alleviate impediments to building new transmission lines for renewable
energy and other system needs to promote a robust competitive market
that will benefit consumers and the environment.
---------------------------------------------------------------------------

    \377\ E.g., Transmission Access Policy Study Group; AWEA;
Northeast Utilities; ITC Companies; Energy Future Coalition Group;
MidAmerican; MISO; NextEra; E.ON Climate Renewables North America;
Exelon; Iberdrola Renewables; WIRES; Western Grid Group; and
Pennsylvania PUC.

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

    489. Many commenters also support aligning transmission planning
and cost allocation more closely.\378\ Transmission Dependent Utility
Systems state that it is virtually impossible to separate transmission
planning from transmission cost allocation. Exelon argues that fair,
efficient, and legal cost allocation should follow the manner in which
its system is planned. Integrys agrees with linking cost allocation
rules with transmission planning, but cautions that the transmission
planning process is not a substitute for the cost allocation process.
---------------------------------------------------------------------------

    \378\ E.g., Atlantic Grid; ITC Companies; Sunflower and Mid-
Kansas; MISO; Pennsylvania PUC; PHI Companies; Colorado Independent
Energy Association; Energy Future Coalition Group; PSC of Wisconsin;
CapX2020; and Wind Coalition.
---------------------------------------------------------------------------

    490. A number of commenters supporting closer alignment between
planning and cost allocation state that existing ISO and RTO
transmission planning and cost allocation processes already may satisfy
the proposal to align transmission planning and cost allocation more
closely.\379\ AEP and SPP believe that their existing transmission
planning and cost allocation processes satisfy many of the Commission's
proposed requirements. Similarly, MISO Transmission Owners state that
cost allocation in MISO is already closely tied to the transmission
planning process. Organization of MISO States points to MISO filings
that address cost allocation issues.
---------------------------------------------------------------------------

    \379\ E.g., SPP; AEP; MISO Transmission Owners; Organization of
MISO States; California PUC; and Pacific Gas & Electric.
---------------------------------------------------------------------------

    491. WIRES asks the Commission to ensure that the planning process
not be unduly influenced by those that seek to redirect potential cost
allocation liability. Illinois Commerce Commission believes it is
unduly discriminatory for a state to be required to bear costs for
transmission expansion projects under a cost sharing arrangement but
have no decisional authority for projects outside their state. Where a
regional state committee exists, Illinois Commerce Commission
recommends that a process be carved out by which the regional state
committee's board of directors has the opportunity to review and decide
on the reasonableness of each of the RTO's proposed transmission
expansion projects for which regional cost allocation would apply.
    492. A number of commenters express concern with the Commission's
proposal to impose generic regional and interregional cost allocation
requirements.\380\ Some commenters argue specifically that there is no
need for the Commission's proposed cost allocation reforms.\381\ For
example, Northern Tier Transmission Group argues that the Proposed Rule
does not present a factual basis for expanding the scope of the cost
allocation requirement to every project contained in a regional
transmission plan. It requests that the Commission confirm that the
Proposed Rule is not intended to apply to existing transmission
projects covered by existing tariff-based and contract-based cost
allocation procedures. If the Proposed Rule is intended to apply to all
new transmission projects in a region's transmission plan, Northern
Tier Transmission Group urges that the Proposed Rule be rejected. It
also is concerned that shifting the burden of cost allocation for every
project onto the regional transmission planning process will create an
unnecessary burden on a region's collective transmission providers.
Westar states that the transmission planning selection process is
critical to ensure that only transmission projects that meet the
various regional requirements are constructed and their costs recovered
as part of tariff rates.
---------------------------------------------------------------------------

    \380\ E.g., Arizona Public Service Company; Bonneville Power;
California Transmission Planning Group; Tucson Electric; Western
Area Power Administration; California Commissions; California ISO;
Eastern Massachusetts Consumer-Owned System; New York PSC; Coalition
for Fair Transmission Policy; Connecticut & Rhode Island
Commissions; Large Public Power Council; National Grid; and Southern
California Edison.
    \381\ E.g., Ad Hoc Coalition; Southern Companies; Salt River
Project; and Nebraska Public Power District.
---------------------------------------------------------------------------

    493. North Carolina Agencies contend that the Commission has not
established that current cost allocation methods are unjust and
unreasonable. Nebraska Public Power District argues that the Proposed
Rule does not contain any record evidence demonstrating the need for
generic rate reform and states that transmission investment has
substantially increased in recent years. Salt River Project argues that
the primary barriers to renewable resource development are delays and
denial of siting and other permits, not transmission funding.
California Municipal Utilities suggest that fewer remote resources are
needed because more local renewable resources are being developed and,
therefore, the need for cost allocation reforms must be re-examined.
Indianapolis Power and Light believes that existing tariff requirements
and ongoing proceedings will achieve the Commission's stated objective
without the uncertainty of a parallel rulemaking process.
    494. MEAG Power responds to Multiparty Commenters' assertion
regarding the cost of transmission expansion by arguing that
investments of the size actually needed to build out the transmission
system, if allocated to load, would raise its native load customers'
transmission costs dramatically. Sacramento Municipal Utility District
states that, even if Multiparty Commenters' assertion were true, it is
irrelevant to the establishment of a just and reasonable transmission
rate whether it comprises a small or large portion of the cost of
delivered power.\382\ Large Public Power Council raises arguments
similar to those raised by both MEAG Power and Sacramento Municipal
Utility District.
---------------------------------------------------------------------------

    \382\ Sacramento Municipal Utility District (citing Farmers
Union Central Exchange v. FERC, 734 F.2d 1486, 1508 (DC Cir. 1984)).
---------------------------------------------------------------------------

3. Commission Determination
    495. The Commission concludes that it is necessary and appropriate
to adopt the cost allocation requirements described in further detail
below for public utility transmission providers. The Commission finds
that, without these minimum requirements in place, cost allocation
methods used by public utility transmission providers may fail to
account for the benefits associated with new transmission facilities
and, thus, result in rates that are not just and reasonable or are
unduly discriminatory or preferential.
    496. 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.\383\ The Commission explained that
knowing how the costs of 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.\384\ In light of that relationship, the Commission directed
public utility transmission providers to identify the cost allocation
method or methods that would apply to transmission facilities that do
not fit under previously existing rate structures.\385\ After several
rounds of compliance filings, the Commission accepted various public
utility transmission providers' proposals as in compliance with Order
No. 890. Particularly in transmission planning regions outside of the
RTO and ISO

footprints, several of the cost allocation methods that the Commission
accepted relied exclusively on a participant funding approach to cost
allocation.\386\ The Commission did not address cost allocation for
interregional transmission facilities in Order No. 890.
---------------------------------------------------------------------------

    \383\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 557.
    \384\ Id.
    \385\ Id. P 558.
    \386\ See, e.g., El Paso Electric Co., 124 FERC ] 61,051 (2008);
Xcel Energy Services, Inc.--Public Service Co. of Colorado, 124 FERC
] 61,052 (2008); South Carolina Electric & Gas Co., 127 FERC ]
61,275 (2009). Entergy Services, Inc., 127 FERC ] 61,272 (2009). See
also Avista Corp., 128 FERC ] 61,065 (2009); Idaho Power Co., 128
FERC ] 61,064 (2009).
---------------------------------------------------------------------------

    497. We conclude that, in light of changes within the industry and
the implementation of other reforms in this Final Rule, the existing
requirements of Order No. 890 are no longer adequate to ensure rates,
terms and conditions of jurisdictional service are just and reasonable
and not unduly discriminatory or preferential. While the existing cost
allocation methods may have sufficed in the past, as we note above, 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. The comments in this proceeding make clear that the pace of
change has accelerated in recent years, such as the expansion of
regional power markets, which has led to a growing need for
transmission facilities that cross several utility, RTO, ISO or other
regions. The industry's continuing transition also has enabled greater
utilization of resources (e.g., reserve sharing) resulting in, among
other effects, broader diffusion of the benefits associated with
transmission facilities. Additionally, the increasing adoption of state
resource policies, such as renewable portfolio standard measures, has
contributed to rapid growth of renewable energy resources that are
frequently remote from load centers, and thus a growing need for
transmission facilities to access remote resources, often traversing
several utility and/or ISO/RTO regions.
    498. The challenges associated with allocating the cost of
transmission appear to have become more acute as the need for
transmission infrastructure has grown. Within RTO or ISO regions,
particularly those that encompass several states, the allocation of
transmission costs is often contentious and prone to litigation because
it is difficult to reach an allocation of costs that is perceived by
all stakeholders as reflecting a fair distribution of benefits. In
other regions, few rate structures are currently in place that reflect
an analysis of the beneficiaries of a transmission facility and for the
corresponding cost allocation of the transmission facility's cost.
Similarly, there are few rate structures in place today that provide
for the allocation of costs of interregional transmission facilities.
    499. We agree with many commenters that the lack of clear ex ante
cost allocation methods that identify beneficiaries of proposed
regional and interregional transmission facilities may be impairing the
ability of public utility transmission providers to implement more
efficient or cost-effective transmission solutions identified during
the transmission planning process. Under the regional transmission
planning and interregional transmission coordination requirements
adopted in this Final Rule,\387\ public utility transmission providers,
in consultation with stakeholders, will identify, evaluate, and
determine the set of transmission facilities that will meet the
combined needs of the region or neighboring pairs of regions,
respectively. This necessarily includes a determination by the region
that the benefits associated with that set of transmission facilities
outweigh the costs. Failing to address the allocation of costs for
these transmission facilities in a way that aligns with the evaluation
of benefits through the transmission planning process could lead to
needed transmission facilities not being built, adversely impacting
ratepayers.
---------------------------------------------------------------------------

    \387\ See discussion supra sections III.A and III.C.
---------------------------------------------------------------------------

    500. In general and as discussed elsewhere in this Final Rule, the
Commission requires a public utility transmission provider to
participate in a regional transmission planning process and to
coordinate transmission planning with public utility transmission
providers in neighboring transmission planning regions in a manner that
aligns transmission planning and cost allocation processes.
Additionally, the OATTs of all public utility transmission providers in
a region must include the same cost allocation method or methods
adopted by the region. As some commenters point out, transmission
facilities that are in a transmission plan to achieve a specific
purpose or purposes, such as to avoid an impending violation of a
Reliability Standard, address economic considerations, or enable
compliance with Public Policy Requirements. Because such purposes
involve the identification of expected beneficiaries, either explicitly
or implicitly, establishing a closer link between transmission planning
and cost allocation will ensure that rates for Commission-
jurisdictional service appropriately account for benefits associated
with new transmission facilities.
    501. We recognize that identifying which types of benefits are
relevant for cost allocation purposes, which beneficiaries are
receiving those benefits, and the relative benefits that accrue to
various beneficiaries can be difficult and controversial. We believe
that a transparent transmission planning process is the appropriate
forum to address these issues. By linking transmission planning and
cost allocation through the transmission planning process, we seek to
increase the likelihood that transmission facilities in regional
transmission plans are actually constructed.
    502. Turning to specific comments on this topic, we are not
persuaded to adopt Illinois Commerce Commission's proposal for separate
review and decision by a committee of state regulators on the
reasonableness of proposed transmission expansion projects for which
regional cost allocation would apply. As explained above,\388\ this
Final Rule builds on Order No. 890's requirement that a public utility
transmission provider have open and transparent transmission planning
processes in which we encourage states or state committees to be
involved. Additionally, as required by this Final Rule, through the
transmission planning process, the public utility transmission
providers and other parties, including state regulators, will have
opportunities to participate in the identification of transmission
needs. We decline, however, to mandate veto rights for state
committees, but do not preclude public utility transmission providers
from proposing such mechanisms on compliance if they choose to do
so.\389\
---------------------------------------------------------------------------

    \388\ See discussion supra section III.A.
    \389\ For example, Entergy's OATT allows Entergy's committee of
state regulators to add a project to Entergy's transmission plan
upon unanimous vote of the committee members. See Entergy Arkansas,
Inc., 133 FERC ] 61,211 (2010).
---------------------------------------------------------------------------

    503. In response to Northern Tier Transmission Group's concern that
applying the new cost allocation requirements to existing transmission
projects covered by existing tariff-based and contract-based cost
allocation procedures will shift costs and create unnecessary burdens,
we clarify that the cost allocation requirements of this Final Rule
apply only to new transmission facilities \390\ selected in regional
transmission plans for purposes of cost allocation.
---------------------------------------------------------------------------

    \390\ See discussion supra P 0.

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

B. Legal Authority for Cost Allocation Reforms

1. Commission Proposal
    504. The Commission explained in the Proposed Rule that, to ensure
that transmission rates are just and reasonable, the costs of
jurisdictional transmission facilities must be allocated in a way that
satisfies the ``cost causation'' principle. It noted that the DC
Circuit defined the cost causation principle stating that ``it has been
traditionally required that all approved rates reflect to some degree
the costs actually caused by the customer who must pay them.'' \391\
Moreover, the Commission noted that while the cost causation principle
requires that the costs allocated to a beneficiary be at least roughly
commensurate with the benefits that are expected to accrue to it,\392\
the DC Circuit has explained that cost causation ``does not require
exacting precision in a ratemaking agency's allocation decisions.''
\393\
---------------------------------------------------------------------------

    \391\ K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (DC Cir.
1992) (K N Energy).
    \392\ Illinois Commerce Commission, 576 F.3d 470 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.'').
    \393\ MISO Transmission Owners, 373 F.3d 1361 at 1371.
---------------------------------------------------------------------------

    505. The Commission explained that, while costs generally have been
allocated through voluntary agreements, the cost causation principle is
not limited to such arrangements. If it were, the Commission could not
address free rider problems associated with new transmission investment
and could not ensure that transmission rates are just and reasonable
and not unduly discriminatory. The Commission stated that it may
determine that an entity is a beneficiary of a transmission facility
even if it has not entered a voluntary arrangement with the public
utility transmission provider that is seeking to recover the costs of
that transmission facility.
    506. The Commission noted that it has expressed a willingness to
make such a determination, as when presented with concerns about
parallel path flow.\394\ In such cases, a public utility transmission
provider may propose a transmission service rate that would account for
unauthorized use of its system.\395\ The Commission noted that it has
cautioned against the hasty submittal of such unilateral filings and
prefers resolution of parallel path flow issues on a consensual,
regional basis.\396\ If necessary, however, it would permit recovery of
costs from a beneficiary in the absence of a voluntary arrangement.
---------------------------------------------------------------------------

    \394\ 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).
    \395\ See, e.g., Amer. Elec. Power Svc. Corp., 49 FERC ] 61,377,
at 62,381 (1989) (AEP).
    \396\ Id.; see also Southern California Edison Co., 70 FERC ]
61,087, at 61,241-42 (1995).
---------------------------------------------------------------------------

    507. The Commission also stated that it has affirmatively required
costs of transmission facilities to be allocated to beneficiaries in
the absence of a voluntary arrangement in a series of orders involving
MISO and PJM. Specifically, the Commission explained that it directed
MISO and PJM to develop cost allocation methods for new facilities in
one of their footprints that benefit entities in the other's
footprint.\397\ It subsequently conditionally accepted a proposal by
MISO and PJM on the grounds that it ``more accurately identifies the
beneficiaries and allocates the associated costs.'' \398\
---------------------------------------------------------------------------

    \397\ 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 MISO 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 MISO and
PJM developed to comply with a previous Commission directive. See
Alliance Cos., 100 FERC ] 61,137, at P 48, 53 (2002).
    \398\ 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).
---------------------------------------------------------------------------

    508. The Commission noted that courts have accepted the application
of the cost causation principle in this way. For example, the DC
Circuit addressed this issue in connection with a MISO proposal to
recover administrative costs through a charge that would apply to
transmission loads subject to MISO's OATT rates.\399\ The court found
that the Commission's system-wide benefits analysis met the
requirements of the cost causation principle, that is, to compare ``the
costs assessed against a party to the burdens imposed or benefits drawn
by that party.'' \400\
---------------------------------------------------------------------------

    \399\ MISO Transmission Owners, 373 F.3d 1361. The DC 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.
    \400\ Id. at 1367.
---------------------------------------------------------------------------

2. Comments on Legal Authority
    509. Several entities comment in support of the Commission's legal
authority to allocate costs of new transmission facilities based on a
beneficiary pays approach.\401\ AEP asserts that the Commission's
proposed cost allocation principles comport with the legal requirements
on cost allocation articulated by the U.S. Court of Appeals for the
Seventh Circuit in Illinois Commerce Commission v. FERC.\402\ Further,
AEP states that while the courts have found that the allocation of
transmission expansion costs in rates must follow the ``cost
causation'' principle, the courts have explained that all beneficiaries
``cause'' costs for the purpose of applying this principle. Thus, from
AEP's perspective, the Commission's proposal to require allocation of
costs to beneficiaries is fully consistent with the legal precedent.
Iberdrola Renewables and American Transmission agree. American
Transmission cautions, however, that care be taken in how precisely the
costs of a transmission project are linked to beneficiaries, given that
the benefits and beneficiaries of a particular project may change over
time, particularly in the case of a large project that provides
regional and interregional benefits. Allegheny Energy Companies state
that although the Illinois Commerce Commission decision found that the
Commission did not provide sufficient evidence to justify adoption of
the postage-stamp cost allocation method in PJM, it did not reject the
method outright, instead requiring the Commission only to provide
further justification assuring that this method results in a just and
reasonable rate that satisfies the principle that rates required to be
paid by a customer must have some relationship to the costs caused or
benefits received by that customer.
---------------------------------------------------------------------------

    \401\ E.g., Iberdrola Renewables; 26 Public Interest
Organizations; Exelon; ITC Companies; LS Power; and Multiparty
Commenters.
    \402\ 576 F.3d 470 (7th Cir. 2009) (Illinois Commerce
Commission).
---------------------------------------------------------------------------

    510. LS Power asserts that there is nothing in the FPA that
precludes the Commission from allocating costs incurred by one
transmission provider in a region to entities nominally taking service
under the tariffs of other transmission providers, or to those other
transmission providers themselves for

the benefits they receive with respect to their own uses of the
regional transmission grid. On the contrary, it explains that
allocating costs only to customers located within the corporate
boundaries of the utility that owns the transmission facilities will
over-allocate costs to such customers and allow other beneficiaries to
become free riders. LS Power concludes that the Commission has
exclusive jurisdiction over interstate transmission services, and
therefore, the authority and the responsibility to define interstate
transmission services--here regional transmission services--and to
identify the beneficiaries of those services that are responsible for
costs incurred by regional transmission providers.
    511. Illinois Commerce Commission agrees with the Commission's
decision that, when 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 into a voluntary arrangement with a public
utility that is seeking to recover the costs of that facility. However,
it asserts that the process must take into account the restrictions on
allocation to beneficiaries set forth in Illinois Commerce Commission,
in which cost causers are primary, and beneficiaries may be taken into
account only to the extent that, without the developer's expectation of
receiving revenues from such a party, the project ``might not have been
built, or might have been delayed.'' Illinois Commerce Commission
asserts that an unduly discriminatory socialization of costs based on
speculation that uncertain future costs will offset the discrimination
does not support a finding of just and reasonable rates.\403\
---------------------------------------------------------------------------

    \403\ In reply, PPL Companies assert that Illinois Commerce
Commission overstates Illinois Commerce Commission, arguing that the
court did not interpret the cost causation principle to require that
costs be allocated on a narrow definition of ``cause'' that ignores
benefits received by customers.
---------------------------------------------------------------------------

    512. A number of commenters agree that a free rider problem exists
in transmission development and that the Commission should bring
certainty to cost allocation rules to address this concern.\404\
NextEra states that any project that provides benefits to entities,
other than the sponsoring entity, creates an incentive for an
individual beneficiary to defer investment in hopes that others will
fund the project's development, and this has led to stalemate and
delay. Federal Trade Commission agrees that the lack of rate structures
to allocate the costs of needed transmission, and the free rider
problem that arises when project beneficiaries seek to shift
transmission construction costs onto others, add uncertainty and
conflict to the debate over what transmission to build and how to pay
for it. Sunflower and Mid-Kansas state that the free rider problem can
be an issue regionally, but is likely to prove more intractable for
interregional cost allocation. Boundless Energy and Sea Breeze state
that cost allocation has to deal with the free rider issue when
multiple utilities are involved because then an independent entity with
a proposal that provides system benefits across a larger region may
find that beneficiaries will not contract for their portion of the
benefits.
---------------------------------------------------------------------------

    \404\ E.g., Gaelectric North America; Atlantic Grid; Multiparty
Commenters; Primary Power; Pennsylvania PUC; NextEra; Federal Trade
Commission; Sunflower and Mid-Kansas; Boundless Energy and Sea
Breeze; and LS Power.
---------------------------------------------------------------------------

    513. Several commenters argue that it is unlawful for transmission
developers to recover costs from entities to which they do not provide
service.\405\ Some commenters contend that the Commission ignores that
privity of contract existed between the entities involved in the cases
that it cites to support its proposal \406\ and that the Commission's
authority under the FPA is premised on a utility having a contractual
relationship or a tariff to provide service to its customers.\407\
Nebraska Public Power District asserts that the Mobile-Sierra cases
support this view.\408\
---------------------------------------------------------------------------

    \405\ E.g., Ad Hoc Coalition of Southeastern Utilities; Nebraska
Public Power District; Salt River Project; and Sacramento Municipal
Utility District.
    \406\ E.g., Ad Hoc Coalition of Southeastern Utilities (citing
Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 144); Salt River
Project (citing Proposed Rule, FERC Stats. & Regs. ] 32,660 at P
164).
    \407\ E.g., Ad Hoc Coalition of Southeastern Utilities; Salt
River; and Nebraska Public Power District.
    \408\ Nebraska Public Power District (citing United Gas Pipeline
Co. v. Mobile Gas Corp., 350 U.S. 332 (1955); FPC v. Sierra Pac.
Power Co., 350 U.S. 348 (1956)).
---------------------------------------------------------------------------

    514. Sacramento Municipal Utility District asserts that there is a
distinction between allocating costs among a public utility
transmission provider's customers without their voluntary agreement
(such as the roll-in of the costs of the transmission provider's bulk
transmission system) and allocating them to entities that are not the
transmission provider's customers. It argues that AEP and similar cases
\409\ do not establish a right to assess costs of facilities to non-
customers and that it is a perversion of the statutory scheme to
suggest that an entity could build a transmission facility and then
claim that because power generated or scheduled by non-customers flowed
over the facility, it was entitled to be compensated by them. Southern
Companies note that no complaint was filed in response to AEP, and the
case therefore does not support the idea that allocation of costs to
non-customers is lawful. Northern Tier Transmission Group maintains
that even if the Commission has authority to permit allocation of costs
to an entity that does not take service from the transmission provider
that collects the costs, it has not complied with the common law
requirements necessary to delegate that authority to transmission
providers.
---------------------------------------------------------------------------

    \409\ In addition to AEP, Sacramento Municipal Utility District
cites Sierra Pacific Power Co., 85 FERC ] 61,314 at 62,235 (1998);
Sierra Pacific Power Co., 86 FERC ] 61,198 at 61,698 (1999); Vermont
Elec. Power Co., 44 FERC ] 61,098, at 61,275 (1988).
---------------------------------------------------------------------------

    515. Sacramento Municipal Utility District asserts that the cases
that the Commission cites dealing with the allocation of costs between
RTOs when new facilities in one of their footprints benefits entities
in the other's footprint do not apply here.\410\ It argues that in
those cases, cross-border facility costs were allocated to each RTO as
a whole, after which project costs were recovered by the RTO through
its own intra-RTO cost allocation. Sacramento Municipal Utility
District states that customers in these cases were not being billed for
service taken from entities with which those customers had no contract
or applicable tariff, but rather were being billed by their own
transmission providers.
---------------------------------------------------------------------------

    \410\ Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC
] 61,084; Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC
] 61,168; Midwest Indep. Transmission Sys. Operator, Inc., 113 FERC
] 61,194.
---------------------------------------------------------------------------

    516. Sacramento Municipal Utility District takes issue with the
Commission's reliance on MISO Transmission Owners for the proposition
that the cost causation principle allows allocation of at least some
types of costs to beneficiaries that are not customers of the public
utility that is seeking cost recovery. It states that in that case,
MISO was the public utility seeking cost recovery, and the costs in
question were not levied directly on the entities in question. Instead,
the MISO transmission owners--existing customers under the MISO
tariff--had challenged whether the cost allocation reflected in their
rates was reasonable. Sacramento Municipal Utility District contends
that all the court decided was that the Commission had reasonably
allocated

MISO's operating costs to the transmission owners based on their use of
MISO-controlled transmission facilities to deliver power to entities
that were not subject to the MISO tariff and on the benefits that MISO
Transmission Owners derived from that delivery.\411\
---------------------------------------------------------------------------

    \411\ See also Southern Companies and ColumbiaGrid.
---------------------------------------------------------------------------

    517. Sacramento Municipal Utility District asserts that the
Commission's position on joint rates supports its position that a
contractual customer relationship is a precondition for the allocation
of transmission costs. It states that the Commission's position is
that, absent evidence that two systems were in fact acting as one, the
Commission cannot mandate the use of a single joint rate. Sacramento
Municipal Utility District argues that if the Commission cannot mandate
joint rates when this condition is not met even where a customer takes
service from both utilities, it cannot mandate that an entity pay rates
charged by a utility with which it has no contractual or tariff-based
customer relationship.\412\
---------------------------------------------------------------------------

    \412\ Sacramento Municipal Utility District cites to Ft. Pierce
Utilities Comm'n v. FERC, 730 F.2d 778 (DC Cir. 1984) (Fort Pierce);
Richmond Power & Light v. FERC, 574 F.2d 610 (DC Cir. 1978)
(``purchasers are always free to subscribe to the services of
willing utilities at the separate rates''); Alabama Power Co. v.
FERC, 993 F.2d 1557, 1565 (DC Cir. 1993) (affirming order directing
joint rate between holding company members who the Commission found
were acting as one); see also Illinois Power Co., 95 FERC ] 61,183,
at 61,644 (2002) (approving single joint rate across Alliant and
MISO systems but recognizing that, in the absence of an agreement
between these utilities, there would not be a single rate).
---------------------------------------------------------------------------

    518. ColumbiaGrid argues that the Commission cannot use its
authority to force customers to pay for additional benefits that go
beyond their existing service. It states that a court has held that
under section 5 of the Natural Gas Act, the Commission may reject
unjust and unreasonable rates and prescribe a new just and reasonable
rate, but it may not require distributors to accept or to pay for
additional service.\413\ ColumbiaGrid maintains that this shows that
costs cannot be recovered from entities that are not customers
receiving jurisdictional service. ColumbiaGrid argues that Illinois
Commerce Commission does not support the allocation of costs in the
absence of an approved rate or a contractual relationship between
transmission owners and presumed beneficiaries, and it maintains that
the Commission's reliance on this case to extend the cost causation
principle to cover any entity that may be said to benefit from a
project is misplaced.
---------------------------------------------------------------------------

    \413\ ColumbiaGrid cites to Exxon Mobil Corp. v. FERC, 430 F.3d
1166 (DC Cir. 2005) (Exxon Mobil Corp.).
---------------------------------------------------------------------------

    519. Southern Companies argue that while the Proposed Rule
acknowledges the fundamental role of cost causation, it proceeds to
nullify the ``but for'' element that is intrinsic to any determination
of cost causation. Southern Companies argue that the primary
beneficiary of a transmission improvement is the customer that made the
request that ``causes'' the improvement in question. They argue that
the Proposed Rule seems to attack cost causation by concluding that a
participant funding approach is not permissible.
    520. Several commenters maintain that in their experience, free
rider problems do not exist and that such concerns may be
speculative.\414\ Ad Hoc Coalition of Southeastern Utilities states
that cost socialization is not needed to protect against the inequities
of free ridership. It interprets the Commission's reference to the free
rider problem as referring to the relatively cost-free transmission
that may be provided to entities that take advantage of oversized
investments made by others.
---------------------------------------------------------------------------

    \414\ E.g., Southern Companies; California Municipal Utilities;
Transmission Agency of Northern California; and Columbia Grid.
---------------------------------------------------------------------------

    521. Southern Companies suggest that if any such problems exist,
they are a product of local or regional factors that do not require a
national solution. E.ON argues that free rider problems do not exist in
the context of reliability or public policy transmission projects, and
participant funding of such projects does not exacerbate the free rider
problem.
    522. Some commenters argue that, even if free rider problems exist,
they can either be solved without resort to broad cost allocation or
are beyond the Commission's authority.\415\ Alternatively, Illinois
Commerce Commission states that while a free rider problem does exist,
it is impossible to solve in practice, and the negative consequences of
allocating costs too broadly will be greater than allocating costs more
narrowly to cost causers and direct, quantifiable beneficiaries.
Dominion similarly asserts that while broad cost allocation may
eliminate free ridership, it may result in some entities paying
disproportionate costs.
---------------------------------------------------------------------------

    \415\ E.g., Nebraska Public Power District and Sacramento
Municipal Utility District.
---------------------------------------------------------------------------

    523. Alabama PSC states that it would be improper to require
citizens of Alabama to pay for the costs of transmission facilities in
other areas of the country where there is high congestion and which are
not necessary to provide service in Alabama. It maintains that this
violates the principle of cost causation and the requirement that
facilities be ``used and useful'' before being incorporated into a
consumer's rates. Indianapolis Power & Light argues that it is
inconsistent with cost causation principles to subsidize a state's
generation decisions (e.g., a state's renewable portfolio standard),
and states should not be able to pass the cost of compliance with their
requirements on to other jurisdictions. ELCON agrees and states that a
claim of generalized system benefits, such as an amorphous reliability
improvement, does not justify regionalized charges. Instead, ELCON
asserts that there must be a tangible, nontrivial benefit supported by
substantial evidence. ELCON also maintains that disallowing export
charges or other forms of cost transfer to beneficiaries in other
planning regions will result in unjust and discriminatory rates.
    524. Coalition for Fair Transmission Policy states that the
Commission lacks authority to require consideration of broad public
policy benefits that cannot be measured or projected within a
transmission providers' planning horizon. It maintains that allowing
the allocation of costs that are not required to maintain reliability,
relieve congestion, or to meet mandated public policy requirements is
beyond the Commission's core mission.
    525. Ad Hoc Coalition of Southeastern Utilities states that in the
Southeast, only North Carolina has a renewable portfolio standards
requirement, and there is no suggestion that a regional mechanism for
funding transmission is needed to satisfy this requirement. It thus
sees no reason to discontinue providing cost recovery for regional
transmission projects from the entities that choose to use them.
    526. ColumbiaGrid argues that at least with respect to non-RTO
regions (where there are no regional service tariff rates), directing
public and non-public utilities to adopt a specific cost allocation
method in advance could infringe upon a utility's right to propose
rates under section 205 of the FPA.\416\ The California ISO maintains
that the Commission does not have the authority to compel rate filings
in the first instance, and it can require a filing only if it shows
that the existing rate does not meet the requirements of section
206.\417\

California ISO argues that the Commission cannot fulfill this
requirement with regard to cost allocation for regional and
interregional facilities because there are no existing contracts or
rates for such services. The Commission may at most issue guidance on
whether future filings will meet statutory requirements.
---------------------------------------------------------------------------

    \416\ ColumbiaGrid bases this claim on Atlantic City Electric
Co. v. FERC, 295 F.3d 1 (DC Cir. 2002) (Atlantic City).
    \417\ Similarly, Northern Tier Transmission Group argues that
the Commission must justify, under section 206, modifying the cost
allocation process that it already accepted for its members.
---------------------------------------------------------------------------

    527. Southern Companies assert that where vertically integrated
transmission providers plan their transmission systems from the bottom
up under state supervision and recover most of their costs for
transmission facilities through bundled rates, the Proposed Rule's
mandates cannot be implemented without preempting or undermining state
law. Southern Companies state that the Commission should revise its
proposed reforms and explain how they can be implemented while
respecting existing processes for bundled retail ratemaking. Southern
Companies assert that they recover only approximately 15 percent of
their transmission revenue requirements under a federal OATT, with the
remaining 85 percent being recovered in state-regulated bundled rates.
They state that the latter cost recovery is not an issue of federal
comparability, and a nonincumbent would, at best, be allowed to recover
only 15 percent of its transmission costs under a federal OATT, with
the rest requiring state approval. Southern Companies maintain that as
a practical matter, a nonincumbent cannot have ``comparable'' cost
recovery without a long-term contract from Southern Companies that has
appropriate state commission approval for purposes of retail rate
recovery.
    528. Transmission Access Policy Study Group urges the Commission to
address allocation of costs of transmission projects that go beyond
existing boundaries of an RTO or individual transmission providers
where the transmission grid is integrated. It recommends that the
Commission recognize that it has the authority to order joint, non-
pancaked rates where transmission systems are integrated. Sacramento
Municipal Utility District argues in response that the Commission
cannot require joint rates unless two adjoining transmission systems
are not just integrated, but effectively operate as a single system.
Large Public Power Council agrees. Ad Hoc Coalition of Southeastern
Utilities argues that the statutory right of utilities to set their
rates may not be easily set aside, and that imposing a joint, non-
pancaked rate structure on utilities would do exactly that.
    529. Florida PSC is concerned that the Commission's proposal may
circumvent its authority over rates for transmission infrastructure
that serves retail load because the Proposed Rule appears to allow
entities seeking to construct merchant transmission projects to recover
project costs from Florida ratepayers through a Commission-approved
cost allocation process. North Carolina Agencies argue that the Final
Rule should recognize the indispensible role of state regulatory
authorities and should apply only to unbundled transmission rates.
Northwestern Corporation (Montana) states that entities seeking to
recover costs without approval from state public utilities commissions
face the risk of cost disallowance.
3. Commission Determination
    530. We conclude that we have the legal authority to adopt the cost
allocation reforms required by this Final Rule. Numerous commenters
challenge our authority to require allocation of transmission costs to
beneficiaries that do not have a contractual or formalized customer
relationship with the entity that is collecting the costs. These
challenges are based primarily on the commenters' analysis of various
Commission and court cases. Some commenters have made arguments that
speak directly to provisions of the FPA, but none of these assertions
reach convincing conclusions. For instance, Ad Hoc Coalition of
Southeastern Utilities states that ``[u]tilities filing for rate
changes under FPA section 205 ask the Commission to approve changes in
rates charged to their customers'' and that ``the Commission's
authority is, in all cases, based on the premise that a utility has a
contractual relationship to provide service to its customers.'' \418\
However, section 205 does not specify any such limitation and no
commenter has shown where it is expressed elsewhere in the FPA.
Instead, commenters generally appear to agree with Ad Hoc Coalition of
Southeastern Utilities that the ``FPA is structured on the assumption
that rates subject to [Commission] approval are supported by a
contractual agreement.'' \419\
---------------------------------------------------------------------------

    \418\ Ad Hoc Coalition of Southeastern Utilities Comments at 60-
61 (emphasis in original).
    \419\ Id. at 60 (emphasis supplied).
---------------------------------------------------------------------------

    531. The merit of this argument depends, of course, on how the FPA
is in fact structured, and an examination of the relevant provisions of
the statute shows that it is not structured in a way that would justify
this argument. On the contrary, the Commission's jurisdiction is
clearly broad enough to allow it to ensure that all beneficiaries of
services provided by specific transmission facilities bear the costs of
those benefits regardless of their contractual relationship with the
owner of those transmission facilities. As discussed further below,
this comports fully with the specific characteristics of transmission
facilities and transmission services, and our actions today are
necessary to fulfill our statutory duty of ensuring rates, terms and
conditions of jurisdictional service are just and reasonable and not
unduly discriminatory or preferential. We thus turn first to the
language of the statute itself.
    532. Section 201(b)(1) of the FPA gives the Commission jurisdiction
over ``the transmission of electric energy in interstate commerce.''
The Commission's jurisdiction therefore extends to the rates, terms and
conditions of transmission service, rather than merely transactions for
such transmission service specified in individual agreements. Moreover,
section 201(b)(1) gives the Commission jurisdiction over ``all
facilities'' for the transmission of electric energy, and this
jurisdiction is not limited to the use of those transmission facilities
within a certain class of transactions. As a result, the Commission has
jurisdiction over the use of these transmission facilities in the
provision of transmission service, which includes consideration of the
benefits that any beneficiaries derive from those transmission
facilities in electric service regardless of the specific contractual
relationship that the beneficiaries may have with the owner or operator
of these transmission facilities.
    533. Neither section 205 nor section 206 of the FPA state or imply
that an agreement is a precondition for any transmission charges. These
statutory provisions speak of rates and charges that are ``made,''
``demanded,'' ``received,'' ``observed,'' ``charged,'' or ``collected''
by a public utility. Any such rates or charges must, of course, be
accepted for filing with the Commission under either section 205 or
206, but nothing in these sections precludes flows of funds to public
utility transmission providers through mechanisms other than agreements
between the service provider and the beneficiaries of those
transmission facilities.
    534. Transmission services create an opportunity for free ridership
because the nature of power flows over an interconnected transmission
system does not permit a public utility

transmission provider to withhold service from those who benefit from
those services but have not agreed to pay for them. The Commission
expressed concern over free ridership in Order No. 890, where it noted
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 benefits from
it.'' \420\
---------------------------------------------------------------------------

    \420\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 561.
---------------------------------------------------------------------------

    535. In Order No. 890, the Commission recognized that 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. We conclude now that this principle cannot be limited to
voluntary arrangements because if it were ``the Commission could not
address free rider problems associated with new transmission
investment, and it could not ensure that rates, terms and conditions of
jurisdictional service are just and reasonable and not unduly
discriminatory. In fact, the courts have recognized this aspect of cost
causation quite independently of an analysis of the scope of our
statutory jurisdiction over transmission.
    536. The courts have acknowledged that cost causation involves
``comparing the costs assessed against a party to the burdens imposed
or benefits drawn by that party.'' \421\ An approach to cost causation
that is limited to voluntary arrangements such as participant funding
has the effect of ``focusing us on the most immediate and proximate
cause of the cost incurred,'' and it precludes looking ``at a host of
contributing causes for the cost incurred (as ascertained by a review
of those who benefit from the incurrence of the cost) and assign[ing]
them liability too.'' \422\ In short, a full cost causation analysis
may involve ``an extension of the chain of causation'' \423\ beyond
those causes captured in voluntary arrangements. In other words, to
identify all causes, we must to some degree begin with their effects,
i.e., the benefits that they engender and then work back to their
sources.
---------------------------------------------------------------------------

    \421\ MISO Transmission Owners, 373 F.3d 1361, at 1368 (internal
citations omitted).
    \422\ KN Energy, 968 F.2d 1295 at 1302.
    \423\ Id.
---------------------------------------------------------------------------

    537. This point was acknowledged in the Seventh Circuit's
characterization of cost causation in Illinois Commerce Commission. The
Seventh Circuit states that:

    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.\424\
---------------------------------------------------------------------------

    \424\ Illinois Commerce Commission, 576 F.3d 470 at 476
(emphasis supplied).

    The court fully recognized that, to identify causes of costs, one
must to some degree begin with benefits. ColumbiaGrid argues that
Illinois Commerce Commission does not support the Commission's position
on cost allocation because the statement just cited is preceded by the
statement that ``[A]ll approved rates [must] reflect to some degree the
costs actually caused by the customer who must pay them.'' \425\
ColumbiaGrid maintains that this demonstrates the Illinois Commerce
Commission ``does not support the [Proposed Rule's] approach of
allocating costs in the absence of an approved rate or a contractual
relationship between transmission owners and presumed beneficiaries.''
\426\ What this argument fails to recognize is that the point
ColumbiaGrid contests was not before the court in Illinois Commerce
Commission, and the Commission's jurisdiction over transmission, as
outlined above, is broad enough to approve rates based on the court's
characterization of cost causation.\427\ In other words, there is
nothing in what the court said that can be viewed as preventing the
Commission from dealing with the free rider problem. Indeed, by
emphasizing the relationship between beneficiaries identified and cost
allocation, the court's ruling supports greater attention to that
issue. Finally, we note that under this Final Rule, transmission
planning regions are not required to analyze the distribution of
benefits on an entity-by-entity basis; nothing in this Final Rule
precludes the regions from doing so, provided that they satisfy the
cost allocation principles adopted herein. We now turn to other
individual comments that involve these issues.
---------------------------------------------------------------------------

    \425\ ColumbiaGrid Comments at 29 (citing Illinois Commerce
Commission, 576 F.3d 470 at 476 (emphasis supplied by
ColumbiaGrid)).
    \426\ Id.
    \427\ This point applies equally to Sacramento Municipal Utility
District's objection that the other Commission and court cases
pertaining to MISO cited in the Proposed Rule are not on point
because they involve instances where a customer relationship of some
type had already been established, and that all that these cases
dealt with was whether an allocation was just and reasonable. When
Sacramento Municipal Utility District states that ``the cost
allocation methods approved by FERC in the MISO cases rested on the
understanding that `the ultimate costs allocated to [MISO] or PJM
for a so-called cross-border allocation project will be recovered by
each RTO pursuant to the applicable provisions of their tariffs,' ''
it is ignoring substance in favor of form. It is focusing on the
formal mechanisms through which costs are collected, not the
underlying substance of the cost allocation itself. See Sacramento
Municipal Utility District Comments at 14 (citing Midwest Indep.
Transmission Sys. Operator, Inc., 113 FERC ] 61,194 at P 4). The
mechanism for recovering a rate does not change the identity of the
provider who is in fact recovering it.
---------------------------------------------------------------------------

    538. Southern Companies' argument that the primary beneficiary of a
transmission facility is the customer that made the request that causes
the improvements to be planned and constructed tends to blur the
distinction between benefits and burdens. As discussed above, the
courts have acknowledged that distinction as relevant to cost
allocation and the requirements in this Final Rule are consistent with
that distinction. To the extent that commenters are supporting
participant funding as a regional cost allocation method, we address
those comments below.\428\
---------------------------------------------------------------------------

    \428\ See discussion infra section IV.F.2.
---------------------------------------------------------------------------

    539. We disagree with Sacramento Municipal Utility District and
Southern Companies that AEP applies only in exceptional circumstances
and does not support our position here. In that case, the Commission
expressed a preference for a voluntary resolution of the problem that
loop flow represented, a position that is consistent with our findings
here. The Commission's authority is not limited in principle by cases
where the Commission expresses a preference not to exercise that
authority. We also disagree with Sacramento Municipal Utility District
that our reforms represent a perversion of the statutory scheme in
which an entity could build a transmission facility and then simply
claim a right to payment for benefits from beneficiaries with which it
has no contractual or tariff relationship. As we state above, the
Commission's jurisdiction is broad enough to allow it to ensure that
beneficiaries of service provided by specific transmission facilities
bear the costs of those benefits regardless of their contractual
relationship with the owner of those transmission facilities. Our cost
allocation reforms are tied to our transmission planning reforms, which
require that, to be eligible for regional cost allocation, a proposed
new transmission facility first must be selected in a regional
transmission plan for purposes of cost allocation, which depends on a
full assessment by a broad range of regional stakeholders of the
benefits accruing from transmission facilities planned according to the
reformed transmission planning processes. As such, the public utility
transmission providers in the regional

transmission planning process identify the beneficiaries who will pay
for the costs of the new transmission facility selected in a regional
plan for purposes of cost allocation.
    540. The fact that the Commission has supported parts of its
argument through reference to cases in which privity of contract
existed between public utilities and the entities from which costs were
recovered does not affect this conclusion.\429\ This issue was not
before the court in any of these cases, and therefore the mere
existence of privity of contract does not demonstrate the necessity of
privity. In response to Nebraska Public Power District, we do not agree
that the Mobile-Sierra doctrine has applicability here. We are dealing
here with conditions under which costs can be recovered in rates, not
conditions under which existing contracts rates can be altered.
---------------------------------------------------------------------------

    \429\ See Midwest Indep. Transmission Sys. Operator, Inc., 109
FERC ] 61,168; Alliance Cos., 100 FERC ] 61,137.
---------------------------------------------------------------------------

    541. Contrary to ColumbiaGrid's position, Exxon Mobil Corp. does
not apply here. As ColumbiaGrid states, in Exxon Mobil Corp. the court
held that the Commission may not require distributors to accept or pay
for additional service.\430\ Unlike the situation addressed in Exxon
Mobil Corp., the requirements of this Final Rule with respect to cost
allocation do not ``impose'' any new service on beneficiaries.
---------------------------------------------------------------------------

    \430\ See Exxon Mobil Corp., 430 F.3d 1166, 1176-77 (DC Cir.
2005).
---------------------------------------------------------------------------

    542. We also note that our position on joint rates does not have
any relevance here. The fact that the Commission cannot require two
public utilities to charge a joint rate without evidence that their two
systems are in fact acting as one does not preclude the Commission from
permitting a single public utility to recover its costs from
beneficiaries of the transmission facilities identified in the
transmission planning process regardless of the formal customer
relationships that exist prior to the time that cost allocation is
authorized. We do not see how the conditions under which a joint rate
can be imposed has any implications for the range of beneficiaries from
which a single public utility can recover the costs of its transmission
services, even when combined with recovery by other public utilities of
related transmission facilities.
    543. We disagree with Northern Tier Transmission Group that we are
delegating any authority to transmission providers. All proposed cost
allocation methods will be subject to Commission approval, and all
specific allocations will be incorporated in rates that must be filed
with and accepted by the Commission.
    544. We agree with the Alabama PSC that citizens of Alabama should
not be responsible for costs of transmission facilities from which they
derive no benefits. Indeed, the Commission specified in the Proposed
Rule as a principle of regional cost allocation that ``[t]hose 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.'' \431\ With respect to interregional
transmission coordination, the Commission specified that 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.'' \432\ In
addition, ``[c]osts cannot be assigned involuntarily under this rule to
a transmission planning region in which that facility is not located.''
\433\ These cost allocation principles are adopted in this Final Rule,
and its requirements thus conform fully with the position taken by the
Alabama PSC.
---------------------------------------------------------------------------

    \431\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 164.
    \432\ Id. P 174.
    \433\ Id.
---------------------------------------------------------------------------

    545. Contrary to the claims of Indianapolis Power & Light, the
reforms instituted in this Final Rule neither authorize nor will lead
to subsidization of generation decisions by different states.
Beneficiaries in one state are not subsidizing anyone in another state
when they are allocated costs that are commensurate with the benefits
that accrue to them, even if the transmission facility in question was
built in whole or part as a result of the other state's transmission
needs driven by Public Policy Requirements. If no benefits accrue, the
cost allocation principles we adopt below would prohibit the allocation
of costs to the non-beneficiaries. If benefits do accrue, however,
there are no less benefits because Public Policy Requirements played a
role in the decision to construct the transmission facility. We agree
with ELCON that estimations of benefits require adequate support. We
note, however, that benefits are not ``amorphous'' simply because costs
are to be allocated ``in a manner that is roughly commensurate with
estimated benefits.'' \434\ The courts have acknowledged the natural
limits that accompany estimations made in the cost-allocation
process.\435\
---------------------------------------------------------------------------

    \434\ The Commission discusses in detail the application of this
cost allocation principle below.
    \435\ Illinois Commerce Commission, 576 F.3d 470 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 MISO 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.
---------------------------------------------------------------------------

    546. We disagree with Coalition for Fair Transmission Policy that
the Proposed Rule can be read to imply that the Commission may require
consideration of broad policy goals that are far afield from the
Commission's core mission. This Final Rule requires that public utility
transmission providers establish a process for identifying those
transmission needs driven by Public Policy Requirements that are to be
considered in the transmission planning process.\436\ In doing this, we
are simply acknowledging that such Public Policy Requirements are facts
that may have consequences in the form of increasing or decreasing the
demand for additional transmission facilities. We are not straying from
our core mission when we acknowledge that these facts will affect
matters that are central to that mission and accordingly require that
they be considered in the transmission planning process, nor are we
promoting any particular public policy by requiring a process to
determine what, if any, transmission needs are driven by a Public
Policy Requirement.\437\
---------------------------------------------------------------------------

    \436\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 4.
    \437\ See discussion supra section III.A.4.
---------------------------------------------------------------------------

    547. Directing a public utility transmission provider to adopt a
specific cost allocation method or methods in advance does not infringe
upon a utility's right to propose rates under section 205 of the FPA.
It simply requires that rate filings meet certain standards.
ColumbiaGrid cites Atlantic City as supporting the contrary position.
In that case, the court held that the Commission could not require that
the PJM Transmission Owners Agreement be modified to eliminate a
provision that allowed a public utility transmission owner to make a
unilateral filing to make changes in rate design or terms and
conditions of jurisdictional services. The court held that public
utilities have an express right under section 205 to make such filings,
and the Commission could not require them to relinquish it.\438\
Nothing in this Final Rule has the effect of disenfranchising any
individual or entity of rights under

section 205 to make filings. The Commission regularly establishes
standards for filings under section 205, and doing so does not negate
any rights under that section.
---------------------------------------------------------------------------

    \438\ Atlantic City, 295 F.3d 16, at 21 (DC Cir. 2002).
---------------------------------------------------------------------------

    548. In response to those commenters that argue that our cost
allocation reforms will affect existing state jurisdiction over utility
rates, it is not clear why cost allocations consistent with this Final
Rule would affect state jurisdiction differently from existing cost
allocations. In any event, we find that such arguments are premature.
It is inappropriate for the Commission to decide such issues
generically in a rulemaking, as such issues should be decided based on
specific facts and circumstances, none of which are presented here.
    549. In response to Transmission Access Policy Study Group, we note
that the issue of joint rates is beyond the scope of this proceeding.
This Final Rule requires the development of cost allocation methods for
regional and interregional transmission facilities in connection with
its planning reforms. As described in the cases that commenters cite in
their responses to Transmission Access Policy Study Group, the issue of
joint, non-pancaked rates involves matters that are considerably
broader than our transmission planning-based cost allocation reforms.
The Commission will consider any calls for joint, non-pancaked rates on
a case-by-case basis and in accordance with the principles established
in these cases.

C. Cost Allocation Method for Regional Transmission Facilities

1. Commission Proposal
    550. The Proposed Rule would require that every public utility
transmission provider develop 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 would be required to
set forth in its tariff the method or methods for cost allocation used
in its transmission planning region. This method or methods would have
to satisfy six regional cost allocation principles, discussed below.
    551. These regional cost allocation principles would apply only to
the cost allocation method or methods for new transmission facilities
selected in the regional transmission plan produced by the transmission
planning process in which the public utility transmission provider
participates. The Commission also stated that it did not intend to
require a uniform cost allocation method that every region must adopt
to allocate the costs of new regional transmission facilities that are
eligible for cost allocation, but instead recognized that regional
differences may warrant distinctions in cost allocation methods among
transmission planning regions.\439\
---------------------------------------------------------------------------

    \439\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 165.
---------------------------------------------------------------------------

    552. The Commission stated in the Proposed Rule that 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 regional cost allocation method or methods
would be permitted.\440\
---------------------------------------------------------------------------

    \440\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 169.
---------------------------------------------------------------------------

2. Comments on Cost Allocation Method in Regional Transmission Planning
    553. A number of commenters generally support the Commission's
proposal.\441\ For example, ITC Companies support the promulgation of a
comprehensive, holistic cost allocation method generally applicable to
new transmission facilities, citing SPP's highway/byway mechanism as a
model.\442\
---------------------------------------------------------------------------

    \441\ E.g., MidAmerican; American Transmission; Clean Line;
Dominion; East Texas Cooperatives; MISO; National Grid; NEPOOL; New
York ISO; Multiparty Commenters; and WIRES.
    \442\ The arguments in support of this proposal are implicit in
the comment summaries under the discussion of other cost allocation
proposals below. See discussion infra section 0. The term ``highway/
byway'' refers to regionwide allocation of the cost of a new high
voltage transmission facility and the allocation of the cost of a
new lower voltage transmission facility to a defined portion of the
region. See Southwest Power Pool, Inc., 131 FERC ] 61,252 (2010).
---------------------------------------------------------------------------

    554. Other commenters express concern with the Commission's
proposal to require the development of a cost allocation method for
transmission facilities included in a regional transmission plan.\443\
Bonneville Power asserts that mandatory regional cost allocation is not
necessary to build new transmission in the Pacific Northwest, and such
a requirement will lead to extended disputes and greater uncertainty.
Bonneville Power contends that instead, voluntary participation,
including participation in open seasons, is the best way to encourage
the development of new transmission for renewables in the Pacific
Northwest. California Commissions echo the sentiment that cost
allocation has generally not been a major barrier to entry for new
transmission in the West. California Commissions are concerned that the
Commission may do more harm than good by moving aggressively and
prescriptively on regional cost allocation methods that are not
necessarily needed to support transmission development.
---------------------------------------------------------------------------

    \443\ E.g., Bonneville Power Administration; California
Commissions; Eastern Massachusetts Consumer-Owned System; Xcel; and
Western Area Power Administration.
---------------------------------------------------------------------------

    555. Some commenters, such as Bonneville Power, California ISO, and
Western Area Power Administration, express a preference for voluntary
coordination and cost allocation of transmission facilities rather than
mandatory cost allocation rules. Coalition for Fair Transmission Policy
urges the Commission to consider whether it is prudent in all cases to
require the filing of regional cost allocation methods by transmission
providers in advance of projects being proposed, as not every project
will fit into a particular model, and adherence to strict rules may
deter rather than encourage the construction of needed new transmission
facilities.
    556. New York PSC indicates that it is uncertain as to whether the
Commission intends to utilize a pre-established cost allocation
methodology as an automatic right of cost recovery. Therefore, New York
PSC requests that the Commission clearly indicate when a project would
be entitled to cost recovery relative to receiving a cost allocation.
Western Grid Group shares the view that the distinction between cost
allocation and cost recovery is a pertinent issue. Arizona Public
Service Company raises concerns about cost recovery in regions where no
regional tariff mechanisms exist. In the absence of such a cost
recovery solution, Arizona Public Service Company states that the
Commission should not place the burden of recovery for third party
developers on incumbent utilities that may be required to seek such
recovery

through state commissions for facilities that the incumbent utilities
have not built and for which the incumbent utilities may be unable to
show benefit for their ratepayers.
    557. MISO Transmission Owners agree that a transmission provider
should not be able to invoke the regional cost allocation method
unilaterally for a facility located entirely within its own service
territory. However, they state that in the RTO context, facilities
located solely within one transmission owner's service territory should
be allocated in accordance with the Commission-accepted cost allocation
method. MISO Transmission Owners state that the Proposed Rule should
not be interpreted to indicate that single-zone facilities are no
longer eligible for regional cost allocation if such allocation is
permitted under an RTO or ISO tariff. Additionally, MISO Transmission
Owners argue that the Commission should not permit this requirement to
allow attempts to relitigate existing cost allocation method that apply
to intra-zonal transmission facilities.
3. Commission Determination
    558. We require that a public utility transmission provider have in
place a method, or set of methods, for allocating the costs of new
transmission facilities selected in the regional transmission plan for
purposes of cost allocation. If the public utility transmission
provider is an RTO or ISO, then the cost allocation method or methods
must be set forth in the RTO or ISO OATT. In a non-RTO/ISO transmission
planning region, each public utility transmission provider located
within the region must set forth in its OATT the same language
regarding the cost allocation method or methods used in its
transmission planning region. In either instance, such cost allocation
method or methods must be consistent with the regional cost allocation
principles adopted below.
    559. We conclude that these regional transmission cost allocation
requirements are necessary to ensure that rates, terms and conditions
of jurisdictional service are just and reasonable and not unduly
discriminatory or preferential. In the absence of clear cost allocation
rules for regional transmission facilities, there is a greater
potential that public utility transmission providers and nonincumbent
transmission developers may be unable to develop transmission
facilities that are determined by the region to meet their needs.
Conversely, greater certainty as to the cost allocation implications of
a potential transmission project will enhance the ability of
stakeholders in the regional transmission planning process to evaluate
the merits of the transmission project. Moreover, as we have
established above, there is a fundamental link between cost allocation
and planning, as it is through the planning process that benefits,
which are central to cost allocation, can be assessed.
    560. We do not specify here how the costs of an individual regional
transmission facility should be allocated. However, while each
transmission planning region may develop a method or methods for
different types of transmission projects, such method or methods should
apply to all transmission facilities of the type in question. Although
we allow a different method or methods for different types of
transmission facilities, as discussed below regarding regional Cost
Allocation Principle 6, if public utility transmission providers choose
to propose a different cost allocation method or methods for different
types of transmission facilities, each method would have to be
determined in advance for each type of facility.
    561. We disagree with California Commissions that our actions here
are too aggressive and prescriptive and with Bonneville Power that
adopting a mandatory cost allocation method will lead to extended
disputes and greater uncertainty. We have stressed throughout this
proceeding that we intend to be flexible and are open to a variety of
approaches to compliance. By imposing the cost allocation requirements
adopted here, the Commission seeks to enhance certainty for developers
of potential transmission facilities by identifying, up front, the cost
allocation implications of selecting a transmission facility in the
regional transmission plan for purposes of cost allocation. This does
not undermine the ability of market participants to negotiate
alternative cost sharing arrangements voluntarily and separately from
the regional cost allocation method or methods. Indeed, market
participants may be in a better position to undertake such negotiations
as a result of the public utility transmission providers in the region
having evaluated a transmission project. The results of that
evaluation, including the identification of potential beneficiaries of
the transmission project, could facilitate negotiations among
potentially interested parties.
    562. In response to Coalition for Fair Transmission Policy, we
require the development of a cost allocation method or a set of methods
in advance of particular transmission facilities being proposed so that
developers have greater certainty about cost allocation and other
stakeholders will understand the cost impacts of the transmission
facilities proposed for cost allocation in transmission planning. The
appropriate place for this consideration is the regional transmission
planning process because addressing these issues through the regional
transmission planning process will increase the likelihood that
transmission facilities selected in regional transmission plans for
purposes of cost allocation are actually constructed, rather than later
encountering cost allocation disputes that prevent their construction.
    563. With regard to comments regarding matters of cost recovery, we
acknowledge that cost allocation and cost recovery are distinct. This
Final Rule sets forth the Commission's requirements regarding the
development of regional and interregional cost allocation methods and
does not address matters of cost recovery. We disagree with Arizona
Public Service Company, however that incumbent utilities may be
unreasonably burdened by the potential of cost allocation for
transmission facilities developed by third party developers. For any
proponent of a transmission facility, whether an incumbent or a
nonincumbent, to have the costs of a transmission facility allocated
through the regional cost allocation method or methods, its
transmission facility first must be selected in the regional
transmission plan for purposes of cost allocation. This in turn
requires a determination that the transmission project is an efficient
or cost-effective solution pursuant to the processes the transmission
providers in the region have put in place, including consultation with
stakeholders. Therefore, the benefits of any such transmission project
should have been clearly identified prior to the allocation of any
related costs.
    564. With respect to cost allocation for a proposed transmission
facility located entirely within one public utility transmission
owner's service territory, we find that a public utility transmission
owner may not unilaterally apply the regional cost allocation method or
methods developed pursuant to this Final Rule. However, a proposed
transmission facility located entirely within a public utility
transmission owner's service territory could be determined by public
utility transmission providers in the region to provide benefits to
others in the region and thus the cost of that transmission facility
could be allocated according to

that region's regional cost allocation method or methods.
    565. In response to MISO Transmission Owners' concerns regarding
relitigation of existing Commission-approved transmission cost
allocation methods, the Commission declines here to prejudge whether
any such existing cost allocation methods comply with the requirements
of this Final Rule. To the extent MISO Transmission Owners believe that
to be the case with their region, they may take such positions during
the development of compliance proposals and during Commission review of
compliance filings. However, we reiterate here that our cost allocation
reforms apply only to new transmission facilities that are selected in
a regional transmission plan for purposes of cost allocation and,
therefore, do not provide grounds for relitigation of cost allocation
decisions for existing transmission facilities.

D. Cost Allocation Method for Interregional Transmission Facilities

1. Commission Proposal
    566. The Proposed Rule would 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. This common method would
have to satisfy six interregional cost allocation principles, discussed
below.
    567. The Commission stated in the Proposed Rule that it would not
apply the interregional cost allocation principles so as to require
every pair of regions to adopt the same uniform approach to cost
allocation for new interregional transmission facilities, but instead
recognized that there may be legitimate reasons for the public utility
transmission providers located in different pairs of neighboring
transmission planning regions to adopt different cost allocation
methods.\444\
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    \444\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 175.
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2. Comments on Interregional Cost Allocation Reforms
    568. A number of commenters generally support the proposal that
each transmission provider have an interregional cost allocation method
for facilities located in more than one region.\445\ NEPOOL states that
it generally supports the proposal to require formal agreements between
neighboring control areas that contain cost allocation methods for
interregional projects, with such methods being subject to the
principles specified in the Proposed Rule. East Texas Cooperatives
support the application of the six proposed principles to interregional
cost allocation methods. AEP states that getting these ground rules in
place is essential to move forward on major interregional projects and
to break down decades old barriers to these types of projects.
Likewise, MidAmerican states that there is little if any coordination
of transmission cost allocation between MISO and SPP regions and the
MISO and MAPP regions and, as such, supports the Commission's efforts
to create a more coordinated and effective way to allocate costs of new
transmission facilities both within these planning regions and those
linking adjacent planning regions.
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    \445\ E.g., AEP; Clean Line; MidAmerican; MISO; MISO
Transmission Owners; NEPOOL; New England States Committee on
Electricity; Northeast Utilities; Pennsylvania PUC; PSEG Companies;
and Energy Consulting Group.
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    569. Vermont Electric states that it welcomes the proposed
requirement for interregional coordination and the Commission's
attention to what it views as deficiencies in the ISO New England
transmission planning process. Vermont Electric states that the
Commission's proposed requirement for a standard cost allocation method
applicable to interregional projects would prevent delays, reduce costs
for project developers, and facilitate development of potentially
valuable interregional projects.
    570. A number of commenters question or express concern about the
appropriateness of requiring the development of interregional cost
allocation methods for future interregional transmission facilities in
advance of a proposal for a specific interregional facility.\446\ For
example, SoCal Edison notes that voluntary coordination efforts are
underway, and it argues that there is no reason to impose additional
mandatory interregional coordination criteria or requirements. ISO New
England supports the preservation of a voluntary, flexible approach to
interregional cost allocation that recognizes regional differences. ISO
New England also states that the Final Rule should either clarify the
manner in which agreement on cost allocation would be signified by each
of the two regions or provide for flexibility in recognition of the
mechanisms that may be most appropriate in light of the internal
transmission planning processes of the paired regions.
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    \446\ E.g., New York ISO; Coalition for Fair Transmission
Policy; California ISO; and National Grid.
---------------------------------------------------------------------------

    571. National Grid believes that interregional coordination
agreements should include general cost allocation principles that will
apply to interregional projects, but that it would not be beneficial to
prescribe an interregional cost allocation method in advance of a
specific interregional project. Similarly, New England Transmission
Owners and New York Transmission Owners contend that, in light of the
limited number of projects that are likely to be identified through
interregional coordination, the Commission should allow cost allocation
issues to be decided in connection with individual projects instead of
dictating a generic cost allocation method in advance.
    572. Vermont Electric agrees, suggesting that the Commission impose
an interregional requirement only to the extent regional planning
organizations do not respond promptly and effectively to cost
allocation issues applicable to interregional projects on a case-by-
case basis. New York ISO recommends that the Commission require
neighboring regions to include language in their tariffs setting forth
their obligation to negotiate cost allocation rules for any
interregional projects that are approved in their respective planning
processes and that such rules must comply with the cost allocation
principles established in the Final Rule.
    573. Similarly, Transmission Agency of Northern California cautions
against requiring the development of cost allocation principles between
planning regions prior to the need for such coordination. California
ISO and Indianapolis Power & Light also argue that the requirement for
a mandatory advanced agreement on cost allocation before knowing the
specific facts and circumstances of an interregional project is neither
appropriate nor effective. Indianapolis Power & Light also states that
it would be better to postpone development of such agreements until a
specific interregional project has been proposed.
    574. California ISO states that the Commission should not mandate
an interregional cost allocation method or methods because the existing
case-by-case determination of cost allocation for interregional
transmission facilities has worked well in the West. California ISO
states that different parties will bring different interests to the
table, and different circumstances may warrant different approaches to
interregional cost allocation. However, California ISO states that
regardless of what the

Commission concludes on this issue, it should retain in the Final Rule
the concept that inclusion of an interregional transmission project in
each of the relevant regional transmission plans would be a
prerequisite to applying an interregional cost allocation
principle.\447\ California ISO argues that this is necessary to ensure
equitable cost allocation.
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    \447\ See also, e.g., Connecticut & Rhode Island Commissions.
---------------------------------------------------------------------------

    575. Edison Electric Institute states that flexibility is
especially important for multistate projects with a large number of
likely beneficiaries. It states that flexibility also is important for
different regions in developing interregional cost allocation methods,
including methods that provide for a case-by-case evaluation of
projects in lieu of using prescribed cost allocation formulas. Edison
Electric Institute states that the Commission should allow a region to
propose the evaluation of alternative cost-effective projects that
would result in lower costs to the region's consumers.
    576. Edison Electric Institute also asks the Commission to be clear
in the Final Rule about whether and how existing interregional cost
allocation mechanisms and those under development in various regions
will be affected, if at all. Transmission Dependent Utility Systems and
Xcel support the proposed requirement, but request that the Commission
not disrupt or disturb the methods already in place. New England
Transmission Owners state that the Commission should permit New England
and New York to move forward to develop coordinated interregional
coordination based on the principles in their current agreement.
    577. SPP seeks clarification, consistent with Order No. 890, that
transmission owning members of RTOs and ISOs can comply with the
proposed interregional cost allocation mandates through their
participation in the RTO or ISO and the interregional agreements
executed by the RTO or ISO, rather than requiring them to negotiate
with their neighbors to develop separate arrangements.
3. Commission Determination
    578. We require a public utility transmission provider in a
transmission planning region to have, together with the public utility
transmission providers in its own transmission planning region and a
neighboring transmission planning region, a common method or methods
for allocating the costs of a new interregional transmission facility
among the beneficiaries of that transmission facility in the two
neighboring transmission planning regions in which the transmission
facility is located.\448\ As we discuss further below, the cost
allocation method or methods used by the pair of neighboring
transmission regions can differ from the cost allocation method or
methods used by each region to allocate the cost of a new interregional
transmission facility within that region. For example, region A and
region B could have a cost allocation method for the allocation of the
costs of an interregional transmission facility between regions A and B
(the interregional cost allocation method) that could differ from the
respective regional cost allocation method that either region A or
region B uses to further allocate its share of the costs of an
interregional transmission facility. In an RTO or ISO region, the
method must be filed in the OATT. In a non-RTO/ISO transmission
planning region, the common cost allocation method or methods must be
filed in the OATT of each public utility transmission provider in the
transmission planning region. In either instance, such cost allocation
method or methods must be consistent with the interregional cost
allocation principles adopted below.
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    \448\ 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 or methods for allocating the costs of a new interregional
transmission facility. However, the Commission does not require such
multiregional provisions among more than two neighboring
transmission planning regions.
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    579. As with our regional cost allocation requirements above, we
are requiring interregional cost allocation requirements to remove
impediments to the development of transmission facilities that are
identified as needed by the relevant regions. We conclude that the
absence of clear cost allocation rules for interregional transmission
facilities can impede the development of such transmission facilities
due to the uncertainty regarding the allocation of responsibility for
associated costs. This may, in turn, adversely affect rates for
jurisdictional services, causing them to become unjust and unreasonable
or unduly discriminatory or preferential.
    580. As in the case of regional cost allocation, we do not require
a single nationwide approach to interregional cost allocation but
instead allow each pair of neighboring regions the flexibility to
develop its own cost allocation method or methods consistent with the
interregional cost allocation principles adopted in this Final Rule. We
also clarify that we do not require each transmission planning region
to have the same interregional cost allocation method or methods with
each of its neighbors. Each pair of transmission planning regions may
develop its own approach to interregional cost allocation that
satisfies both transmission planning regions' needs and concerns, as
long as that approach satisfies the interregional cost allocation
principles. Our intention is to preserve the ability of each pair of
transmission planning regions to plan for future development of
interregional transmission projects that will be beneficial to both
transmission planning regions.
    581. We do not specify here how the costs for an individual
interregional transmission facility should be allocated. However, while
transmission planning regions can develop a different cost allocation
method or methods for different types of transmission projects, such a
cost allocation method or methods should apply to all transmission
facilities of the type in question. Although we allow a different cost
allocation method or methods for different types of transmission
facilities, as discussed below regarding Interregional Cost Allocation
Principle 6, if public utility transmission providers choose to propose
a different cost allocation method or methods for different types of
transmission facilities, each cost allocation method would have to be
determined in advance for each type of transmission facility. Also, we
adopt the requirement that an interregional transmission facility must
be in the relevant regional transmission plans to be eligible for
interregional cost allocation pursuant to the interregional cost
allocation method or methods.
    582. Additionally, a central underpinning to our reforms in this
Final Rule is the closer alignment of transmission planning and cost
allocation. As we discuss above in the section on interregional
transmission coordination,\449\ an interregional transmission facility
must be selected in both of the relevant regional transmission planning
processes for purposes of cost allocation in order to be eligible for
interregional cost allocation pursuant to a cost allocation method
required under this Final Rule. This is designed, among other things,
to allow for adequate stakeholder review of the interregional
transmission facility before the relevant portion of the facility is in
a regional transmission plan.\450\ This process could be undermined if
a transmission facility that is located and

reviewed only within one regional transmission planning process, could
nevertheless have its costs allocated to potential beneficiaries in
another region that may not have had an adequate opportunity to review
the need for the transmission facility and make the resulting
beneficiary determinations. As we make clear in our discussion of Cost
Allocation Principle 4,\451\ costs may be assigned on a voluntary basis
under this Final Rule to a transmission planning region in which an
interregional transmission facility is not located. Given this option,
regions are free to negotiate interregional transmission arrangements
that allow for the allocation of costs to beneficiaries that are not
located in the same transmission planning region as any given
interregional transmission facility.
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    \449\ See discussion supra section III.C.
    \450\ See discussion supra section III.C.
    \451\ See discussion infra section IV.E.5.
---------------------------------------------------------------------------

    583. With respect to existing interregional transmission
coordination and cost allocation agreements, we do not opine here on
whether such agreements satisfy the interregional transmission
coordination requirements and cost allocation principles of this Final
Rule.\452\ To the extent that a public utility transmission provider
believes such an agreement satisfies these requirements in whole or in
part, that public utility transmission provider should describe in its
compliance filing how the relevant requirements are satisfied by
reference to tariff sheets on file with the Commission.
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    \452\ Public utility transmission providers may continue to
enter into such agreements as a means of complying with this Final
Rule, but any such agreements that are incorporated into the public
utility transmission provider's OATT by reference must be consistent
with or superior to this Final Rule.
---------------------------------------------------------------------------

    584. We also clarify in response to commenters that the requirement
to coordinate with neighboring regions applies to public utility
transmission providers within a region as a group, not members within
an RTO or ISO acting individually. Therefore, within an RTO or ISO, the
RTO or ISO would develop an interregional cost allocation method or
methods with its neighbors on behalf of its public utility transmission
owning members.

E. Principles for Regional and Interregional Cost Allocation

1. Use of a Principles-Based Approach
a. Commission Proposal
    585. For the cost allocation method or methods to be just and
reasonable and not unduly discriminatory or preferential, the Proposed
Rule would require that each cost allocation method satisfy six general
cost allocation principles, as set out in the following subsections.
The Commission proposed six regional cost allocation principles for
each cost allocation method for regional transmission facilities
included in the regional transmission plan for purposes of cost
allocation and six analogous interregional cost allocation principles
for each cost allocation method for a new transmission facility that is
located in two neighboring transmission planning regions and is
accounted for in the interregional transmission coordination process.
    586. Specifically, the Proposed Rule would require that each RTO or
ISO (on behalf of its transmission owning members) or the individual
public utility transmission providers in a non-RTO/ISO transmission
planning region to demonstrate through a compliance filing that its
cost allocation method or methods for new transmission facilities
satisfy the following regional cost allocation 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.\453\ 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.\454\
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    \453\ See Illinois Commerce Commission, 576 F.3d 470 at 476-77
(stating that ``[w]e 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 MISO Transmission Owners, 373 F.3d 1361 at 1369 (stating that
``we have never required a ratemaking agency to allocate costs with
exacting precision''); Sithe, 285 F.3d 1 at 5.
    \454\ As discussed above, the Commission proposed 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 drive
transmission needs. As discussed above, we adopt this requirement in
this Final Rule.
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    (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 a regional 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.\455\ 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.
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    \455\ In addition, the Commission preliminarily found that this
principle does not affect the cross-border cost allocation methods
developed by PJM and MISO in response to Commission directives
related to their intertwined configuration. Midwest Indep.
Transmission Sys. Operator, Inc., 113 FERC ] 61,194, at P 10;
Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ] 61,084;
Midwest Indep. Transmission Sys. Operator, Inc., 129 FERC ] 61,102.
As noted above, we adopt this finding in this Final Rule.
---------------------------------------------------------------------------

    (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 Final
Rule.\456\
---------------------------------------------------------------------------

    \456\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 164.

    587. The Proposed Rule required each cost allocation method to
---------------------------------------------------------------------------
comply with the following interregional cost allocation 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.
    (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.\457\
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    \457\ 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.
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    (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.

    588. The Proposed Rule also states that public utility transmission
providers will have the first opportunity to develop cost allocation
methods for regional and interregional transmission facilities in
consultation with 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 its proposed requirements.
b. Comments on Use of Principles-Based Approach
    589. Many commenters generally support the use of cost allocation
principles although this support is often expressed as part of general
support for the Proposed Rule's six proposed cost allocation principles
as a package.\458\ For example, Dominion believes that by providing
cost allocation principles linked to planning, the Commission has taken
the correct approach without being overly prescriptive. Dayton Power
and Light states that these principles help to reduce uncertainty and
provide guidance to interested stakeholders. Energy Future Coalition
Group states that the proposed principles follow the direction laid out
by the court in the Illinois Commerce Commission case, and address
legitimate concerns that have been raised by some opponents of broad
cost allocation policy over the past two years. On the other hand, as
discussed above,\459\ some comments oppose any generic action on
regional and interregional cost allocation and therefore do not support
the use of cost allocation principles to support such action.
---------------------------------------------------------------------------

    \458\ E.g., DC Energy; WIRES; Dominion; and Dayton Power and
Light.
    \459\ See discussion supra section II.
---------------------------------------------------------------------------

    590. Almost all commenters urge the Commission not to adopt a
``one-size-fits-all'' approach to cost allocation and to retain
regional and interregional flexibility.\460\ For example, APPA and
Transmission Agency of Northern California state that the Commission
should not prescribe a uniform approach to interregional transmission
cost allocation, and should allow for regional and interregional
differences. Transmission Agency of Northern California states that
this issue is being addressed at a level where local and regional
differences can be addressed more fully, and that it supports the
Proposed Rule's assumption that this ongoing process should not be
disrupted by this rulemaking.
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    \460\ E.g., Large Public Power Council; Kansas Corporation
Commission; and Nebraska Public Power District.
---------------------------------------------------------------------------

    591. Several commenters ask the Commission to address the Proposed
Rule's provision regarding ``in the event that no agreement can be
reached.'' \461\ They contend that if the Commission adopts a rule
providing that it would select a backstop cost allocation method in the
event that stakeholders within a region cannot agree to a regional cost
allocation method or if regions cannot agree on a cost allocation
method for interregional projects, the Commission should provide
additional guidance that would help stakeholders to reach agreement.
For example, Multiparty Commenters request that the Commission clarify:
The level of stakeholder agreement that is acceptable; what would be
evidence of an impasse; whether the Commission will defer to the
majority; and whether the Commission will extend the time in which to
make compliance filings to afford more time to obtain an agreement.
Similarly, for interregional cost allocation, Anbaric and PowerBridge
recommend that the Commission stipulate a reasonable period of time for
regions to reach agreement on a proposed interregional cost allocation
method.
---------------------------------------------------------------------------

    \461\ E.g., Anbaric and PowerBridge; AWEA; MidAmerican;
Multiparty Commenters; and Southern Companies.
---------------------------------------------------------------------------

    592. Some commenters recommend that the Commission adopt an
interregional default cost allocation method if regions cannot agree to
such a method themselves, although they note that specific projects
will involve unique facts and circumstances. Anbaric and PowerBridge
believe that, if regions cannot agree on an interregional cost
allocation method, the Commission could impose an agreement based on
the facts and circumstances of the project. Massachusetts Municipal and
New Hampshire Electric state that, even if an interregional default
method is implemented, whether by mutual agreement or by Commission
directive, disputes will arise about the application of that method to
a given set of facts. Massachusetts Municipal and New Hampshire
Electric suggest that the Commission can address these concerns by
adopting expedited hearing procedures to be applied in such cases.
    593. Other commenters suggest a variation on or alternative to the
idea that the Commission adopt a default cost allocation method for
regional and interregional cost allocation if stakeholders or regions
cannot come to a consensus themselves.\462\ Wind Coalition states that
having a default cost allocation method would allow construction to
commence while an alternative cost allocation method is being
developed, if needed. It states that this would be particularly needed
for cross-border cost allocation because there are currently few
interregional agreements on cost allocation. Wind Coalition also states
that matching cost

allocation with a proactive regional or interregional plan is important
for justifying regional cost sharing.
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    \462\ E.g., American Transmission; AWEA; NextEra; and Wind
Coalition.
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    594. Some commenters argue that, if a region or regions fail to
agree on a method, the Commission should not select a default cost
allocation method and also should not select a cost allocation method
based on the record here.\463\ APPA contends that adoption of a default
cost allocation method or particular cost allocation principles or
guidelines would influence the prospects for successful regional and
interregional negotiation because stakeholders that support the default
method will be unwilling to negotiate, knowing that if no agreement is
reached, their preferred method will be adopted as the default. PSEG
Companies argue that adoption of a single default cost allocation
method would be inconsistent with the Proposed Rule's ``beneficiary
pays'' approach. PSEG Companies believe that the ``roughly
commensurate'' standard that the Illinois Commerce Commission decision
requires will be satisfied only by happenstance under a default cost
allocation method. PSEG Companies also disagree with comments by
National Grid, AEP, and others that the Commission should institute a
default cost allocation method for transmission planning regions that
would apply regardless of the nature of the facilities planned (i.e.,
reliability or economic). PSEG Companies suggest that the Commission
clarify how interregional cost allocation will be handled in the
absence of an interregional agreement, and it should make clear that
the existence of such an agreement is a prerequisite to the assignment
of costs to another transmission planning region and its customers.
PSEG Companies also state that, if certain regions decline to enter
into interregional agreements, the Commission should adopt a ``do not
harm'' standard applicable to such regions as a corollary principle,
that is, no region may plan its system in a way that would impose costs
on other regions.
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    \463\ E.g., APPA and PSEG Companies.
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    595. Some commenters suggest a particular default method that the
Commission should adopt if it decides to have a default cost allocation
method, such as the SPP highway/byway mechanism.\464\ However, other
commenters express concern with establishing a ``one-size-fits-all''
default allocation method.\465\ In particular, New England States
Committee on Electricity and Identified New England Transmission Owners
urge the Commission to reject recommendations to adopt the highway/
byway mechanism as a default cost allocation method, instead asking the
Commission to respect regional differences. Sunflower and Mid-Kansas
submit that the Final Rule should provide for two-third regional (or
interregional) allocation of costs and one-third to the ultimate sink
zone for all network upgrades approved through an interregional plan
that are needed for variable energy resource integration.
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    \464\ Several commenters suggested this method including AWEA,
Multiparty Commenters, and NextEra.
    \465\ E.g., Connecticut & Rhode Island Commissions; Kansas
Corporation Commission; Salt River Project; WIRES; and Wisconsin
Electric.
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    596. With respect to the question of whether the Commission should
establish an interim cost allocation method until stakeholders have
time to reach consensus, AWEA states that the current market structure
and the mechanisms used to allocate costs between transmission
providers outside organized market regions needs to mature further
before transmission providers in many of these market regions will be
able to fully comply with the Proposed Rule. It states that if
transmission providers outside organized market regions cannot
demonstrate a binding cost allocation method as envisioned by the
Proposed Rule, it would be appropriate for the Commission to consider
an interim method to address cost allocation in those regions, such as
using an ``intertie open season'' to create a record about the
appropriate allocation of costs.
    597. NextEra suggests that, for non-RTO regions, regional cost
recovery should be promoted by an adder on the transmission rates of
public utility transmission providers (and extended to non-
jurisdictional utilities via reciprocity). Southern Companies respond
that this approach is not feasible because it does not address the fact
that their OATT recovers only the share of the cost attributable to
their provision of wholesale transmission service. Southern Companies
state that even with an adder, third parties would be limited to
recovering approximately 15 percent of their transmission costs, which
is comparable to Southern Companies' cost recovery.
    598. Massachusetts Departments and MidAmerican state that the
Commission should narrowly apply any authority it has to develop a cost
allocation method only for specific projects rather than requiring an
established mechanism for all projects. For instance, MidAmerican
proposes that the Commission adopt a default cost allocation method
that would be used only if the stakeholders fail to agree regarding a
500 kV or higher alternative current facility (except high voltage
direct current projects) that is identified by the planning process as
providing widespread benefits. In this limited case, MidAmerican
suggests that the Commission adopt a streamlined dispute resolution
mechanism with a rebuttable presumption in favor of specified regional
and interregional cost allocation methods. MidAmerican states that the
record in the proceeding before the Commission on remand from the
Seventh Circuit Illinois Commerce Commission opinion, demonstrates the
reliability, economic, and societal benefits of 500 kV and above
transmission, and it also documents that these benefits are realized
regionwide whenever extra-high voltage transmission is deployed.
    599. Wisconsin Electric states that it may be useful to consider
the extent to which statewide stakeholder collaboratives could be
effective in helping to resolve interstate cost allocation and cost
recovery controversies. It points to California's Renewable Energy
Transmission Initiative, which distinguishes stakeholders who are
willing to work in good faith to resolve a project from those who only
oppose transmission for self-interested reasons. Northwestern
Corporation (Montana) is concerned that the proposal could have
uneconomic consequences in that a high-cost allocation solution could
be involuntarily allocated to an unwilling entity that has a lower-cost
solution. Northern Tier Transmission Group is also worried about the
difficulties that would arise in the context of allocating costs to
entities that are unwilling to incur them.
    600. Some commenters state that the Commission should not close the
door on existing or evolving processes.\466\ Salt River Project states
that requiring involuntary cost sharing would risk foreclosure of
promising alternatives and superior options for reliable and least-cost
service for customers. Salt River Project is also concerned that
arbitrary solutions could result that fail to honor local and regional
interests.
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    \466\ In addition, WIRES also notes that a default method where
regional parties reach an impasse may look more attractive if the
Commission's principles provide only generalized guidance. However,
WIRES states that greater reliance on principled, up-front guidance