construction of new transmission facilities because it relies on
willing parties and does not involve parties who are unwilling to bear
costs and who will engage in litigation to oppose transmission project
development. Yet nothing in this Final Rule precludes the use of
participant funding for those transmission projects with the support of
individual market participants. We find that Northern Tier Transmission
Group's argument that other cost allocation methods will impair
construction to be speculative and see no reason to conclude that other
methods in fact will have this result.
---------------------------------------------------------------------------

    \538\ Illinois Commerce Commission, 576 F.3d 470 at 476.
    \539\ We discuss Ad Hoc Coalition of Southeastern Utilities'
claim regarding the consistency of participant funding with judicial
precedent on cost allocation methods below in section IV.F.2.
---------------------------------------------------------------------------

    727. In response to Transmission Agency of Northern California,
Avista, and Puget Sound, we note that a limitation on participant
funding is far from a mandate for broad cost socialization. There is
nothing in our cost allocation reforms that requires broad
socialization or supports improper cost shifting in violation of cost
causation principles. As discussed fully above, our cost allocation
principles require that costs be allocated roughly commensurate with
the benefits received by those that pay those costs.
    728. In any event, nothing in this Final Rule applies to existing
transmission facilities with existing cost allocations or to
transmission projects currently under development.\540\
---------------------------------------------------------------------------

    \540\ See also discussion supra section III.A.3.
---------------------------------------------------------------------------

    729. In response to Entergy's request, we clarify that our cost
allocation reforms in this Final Rule are not intended to modify
existing pro forma OATT transmission service mechanisms for individual
transmission service requests or requests for interconnection service.
3. Whether Regional and Interregional Cost Allocation Methods May
Differ
a. Commission Proposal
    730. In the Proposed Rule, the Commission explained that the method
used for allocating interregional transmission facility costs between
any two transmission planning regions may be different from the method
used by the public utility transmission providers located in either of
those transmission planning regions to allocate the costs of new
regional facilities. Additionally, the Commission proposed that the
cost allocation method used by the public utility transmission
providers located in a transmission planning region to allocate the
costs of new regional facilities could be different from the cost
allocation method by which the public utility transmission providers in
the same transmission planning region further allocate costs to be
borne by that transmission planning region pursuant to an agreed-upon
method for allocating the costs of interregional facilities.\541\
---------------------------------------------------------------------------

    \541\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 176.
---------------------------------------------------------------------------

b. Comments
    731. Several commenters agree with the Commission's proposal that
the method used for allocating interregional transmission facility
costs may differ from the method used to allocate regional costs.\542\
Georgia Transmission Corporation states that if an interregional
coordination obligation would require entities to enter into agreements
with neighboring regions, the Commission should specify that it would
not require the transmission entity to accept the neighboring entity's
cost allocation method. Indianapolis Power & Light states that the cost
allocation provisions of an interregional coordination agreement should
set forth how costs are divided between the regions and leave it up to
the regions to determine how their shares are divided among their
subregions/zones/customers. MISO Transmission Owners state that
transmission providers and their stakeholders should be permitted to
determine whether the cost allocation methods used for regional
projects should apply to the transmission provider's share of
interregional facilities.
---------------------------------------------------------------------------

    \542\ E.g., Georgia Transmission Corporation; Indianapolis Power
& Light; MISO Transmission Owners; NEPOOL; and Northeast Utilities.
---------------------------------------------------------------------------

    732. ISO New England supports the preservation of a voluntary,
flexible approach to interregional cost allocation that recognizes
regional differences. It also states that the Final Rule should either
clarify the manner in which

agreement on a 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.
c. Commission Determination
    733. We find that the method or methods for interregional cost
allocation used by two transmission planning regions may be different
from the method or methods used by either of them for regional cost
allocation. Also, the method or methods for allocating a region's share
of the cost of an interregional transmission facility may differ from
the method or methods for allocating the cost of a regional facility
within that region.
    734. Although the public utility transmission providers in a
transmission planning region may choose to allocate their share of the
costs of an interregional transmission facility using their regional
cost allocation method or methods, we see no reason to require them to
do so. Indeed, for a transmission planning region that shares the cost
of regional transmission facilities broadly, it may be inappropriate to
apply broad cost sharing for an interregional transmission facility
that is found to benefit only part of that transmission planning
region. In addition, an interregional transmission facility may be of
such greater scale than most regional transmission facilities that it
may result in different types of benefits and beneficiaries than for a
regional transmission facility.
    735. In response to Georgia Transmission Corporation, we clarify
that we do not require the public utility transmission providers in a
transmission planning region to accept the regional transmission
planning method or methods of another transmission planning region with
which it participates regarding interregional transmission
coordination. Each transmission planning region would determine for
itself how to allocate the costs of a new interregional transmission
facility consistent with this Final Rule.
4. Recommendations for Additional Commission Guidance on the
Application of the Transmission Cost Allocation Principles
    736. Several comments recommend that the Commission provide
additional guidance on how to apply the cost allocation principles.
a. Comments
    737. A number of commenters provide additional suggestions on cost
allocation methods. Duke states that without clear pricing guidelines
that do more than restate general cost allocation principles, regional
and interregional transmission projects will have trouble getting out
of the starting gate. Pennsylvania PUC asserts that cost allocation
principles and methods should be reasonably clear and explainable to
all stakeholders so that development of a cost allocation paradigm can
be effectively grasped by all participants. East Texas Cooperatives
believe that the costs of all transmission facilities needed to
maintain reliability or to deliver long-term resources to load serving
entities should be rolled into the applicable zonal, regional, or
interregional rate, and that individual cost allocation methods should
clearly set forth a plan for identifying beneficiaries and allocating
costs to them. Washington Utilities and Transportation Commission is
concerned that necessary certainty on cost allocation would not be
achieved if the Final Rule lacks detail on the standards to be applied
when reviewing or approving cost allocations proposals and the
Commission opts to develop more precise cost allocation policies on a
case-by-case basis.
    738. Federal Trade Commission encourages the Commission to consider
providing stronger guidance regarding transmission cost allocation
principles. It expresses its concern that unnecessary variance in
allocation methods will have a disruptive effect on multi-area
transmission proposals, akin to the disruptive effects that unnecessary
diversity in methods for calculating available transmission capacity
had on transmission services spanning multiple areas. Federal Trade
Commission encourages the Commission to consider whether stronger
guidance would promote consensus sooner and avoid creating a patchwork
of transmission cost allocation methods that may not support broad,
efficient regional markets and low-cost compliance with environmental
and energy security policy initiatives.
    739. WIRES states that, as proposed, the principles provide only
the most general outer bounds of acceptable practice and do not specify
the characteristics of cost allocation methods that the Commission is
likely to consider just and reasonable. WIRES states that the use of a
relatively complete set of principles affords the Commission an
opportunity to help short-cut the endless debates about limited merits
of participant funding in a network environment and about the extent to
which the benefits of transmission can be quantified in specific
instances.
    740. Northwestern Corporation (Montana) asserts that new
transmission lines should not be insulated from sharing a portion of
the network costs and/or an allocation of the network revenue
requirement because new transmission lines experience enhanced
reliability by connecting to the network transmission system.
    741. Illinois Commerce Commission urges the Commission to remove
``postage stamp'' cost allocation from the list of acceptable cost
allocation methods.\543\ It maintains that postage stamp cost
allocation is highly unlikely to produce just, reasonable, and
nondiscriminatory rates, and continuing to maintain it as a possible
cost allocation method is paralyzing transmission expansion.
---------------------------------------------------------------------------

    \543\ ``Postage stamp'' here refers to regionwide allocation of
the cost of a transmission facility.
---------------------------------------------------------------------------

    742. Other commenters make suggestions or requests for guidance
that are similar to other commenters' recommendations for additional
cost allocation principles discussed above. For example, some
commenters suggest that cost allocation methods should be periodically
recalculated or reevaluated. Many commenters believe that changes to
transmission system topology and amendments to state policies could
alter disbursement of benefits, so the Final Rule should require cost
allocations to be periodically reviewed and recalculated.\544\ Some of
these commenters believe that permanent cost allocations may inhibit
investing in transmission upgrades and that there should be periodic
reassessments to address any unintended consequences.\545\ For example,
E.ON and East Texas Cooperatives suggest that cost allocation
reevaluation should occur every five years. Pennsylvania PUC states
that a cost allocation method should be designed to evolve and reflect
system changes over time.
---------------------------------------------------------------------------

    \544\ E.g., Sunflower and Mid-Kansas; Electricity Consumers
Resource Council and Associated Industrial Groups; PUC of Ohio; East
Texas Cooperatives; E.ON; and Transmission Dependent Utility
Systems.
    \545\ E.g., Transmission Dependent Utility Systems; Sunflower
and Mid-Kansas; E.ON; East Texas Cooperatives; and Massachusetts
Municipal and New Hampshire Electric.
---------------------------------------------------------------------------

    743. Ohio Consumers Counsel and West Virginia Consumer Advocate
Division suggest that the Commission adopt a process that allows for
expedited resolution of disputes over cost allocation that may arise
during the regional planning process. ISO New

England recommends Commission-sponsored mediation or other alternative
dispute resolution for interregional cost allocation to assist two
regions on reaching agreement if they cannot do so.
    744. Commenters also submitted comments suggesting multiple ways to
allocate costs of public policy driven projects.\546\ FirstEnergy
Service Company believes the Commission should clarify that the cost
causation principle, including the requirement that costs are at least
roughly commensurate with benefits, applies with full force to public
policy driven projects in the regional planning process. First Wind
believes the Commission should seek state input and rely upon state
judgment on cost allocation for projects flowing from state policy.
NEPOOL and New England States Committee on Electricity believe that
each region should have considerable flexibility to develop public
policy cost allocations. Transmission Dependent Utility Systems notes
that not all projects proposed to implement public policy are worthy of
presumptive acceptance and should be rigorously scrutinized in the
stakeholder process.
---------------------------------------------------------------------------

    \546\ E.g., FirstEnergy Service Company; First Wind; NEPOOL; New
England States Committee on Electricity; New England Transmission
Owners; Public Power Council; and Transmission Dependent Utility
Systems.
---------------------------------------------------------------------------

b. Commission Determination
    745. The Commission appreciates interested commenters' views,
suggestions and requests for additional Commission guidance regarding
the development of an acceptable cost allocation method or methods to
comply with the identified cost allocation principles for new regional
and interregional transmission facilities. We believe, however, that
the principles adopted in this Final Rule provide sufficient general
guidance for public utility transmission providers. The principles
establish threshold criteria for a cost allocation method or methods to
facilitate the development of a just and reasonable and not unduly
discriminatory or preferential cost allocation method or methods.
Additionally, the principles afford public utility transmission
providers in individual transmission planning regions the flexibility
necessary to accommodate unique regional characteristics. The
Commission is concerned that providing the additional guidance or
limitations requested by commenters would unduly restrict this
flexibility. As we explained above, the Commission recognizes the need
for regions to retain some level of flexibility to account for specific
regional characteristics, resource types, or policy mandates.
    746. We emphasize, however, that any variations between regions
must be consistent with the six cost allocation principles. For
example, East Texas Cooperatives suggest periodic reevaluation of cost
allocation methods to respond to system changes. We do not view such a
proposal as inconsistent with the cost allocation principles adopted
above and, as such, it could be presented and evaluated at the regional
level and, if agreed upon, proposed to be implemented by that
transmission planning region. However, the Commission declines to
prescribe such a policy for all transmission planning regions
nationwide.
    747. With respect to comments regarding how to allocate costs for
public policy driven transmission projects, as discussed above,\547\ we
are not requiring public utility transmission providers to use the same
cost allocation method for public policy and other types of
transmission facilities. Instead, as discussed for Cost Allocation
Principle 6, we permit different regional and interregional cost
allocation methods for different types of transmission projects. Thus,
whether each region or pair of transmission planning regions has a
separate cost allocation method for public policy driven transmission
projects depends on the consensus within that transmission planning
region or those transmission planning regions, and we will not
prescribe a uniform method for such transmission projects.
---------------------------------------------------------------------------

    \547\ See discussion supra section III.E.7.
---------------------------------------------------------------------------

    748. In response to Illinois Commerce Commission, the Commission
declines to find in advance that a ``postage stamp'' cost allocation
may not be an acceptable cost allocation method. If public utility
transmission providers in a region, in consultation with their
stakeholders, agree to such a method, and it is demonstrated to be
consistent with the cost allocation principles and is supported with an
appropriate assessment of benefits, then such an allocation may be
submitted to the Commission on compliance, and the Commission will
determine then whether the method meets its requirements.
    749. We also clarify that, by establishing the six principles for
regional and interregional cost allocation, the Commission is not
attempting to supersede the cost causation principle. Rather, these six
principles serve as guidelines for public utility transmission
providers to use to create cost allocation methods that are consistent
with the cost causation principle.
    750. With regard to the concerns of Ohio Consumers' Counsel, West
Virginia Consumer Advocate Division, and ISO New England about dispute
resolution, the Commission believes that the dispute resolution
processes in place under Order No. 890, enhanced as may be necessary to
comply with our transmission planning reforms, will be adequate to
address in the first instance, any disagreements that may arise
regarding the allocation of transmission costs. The Commission reviewed
and approved all of the dispute resolution procedures currently in
place during our review of the compliance filings in response to Order
No. 890, requiring enhancements in a number of cases.\548\ We will
review any changes to those dispute resolution procedures in response
to compliance filings submitted in response to this Final Rule.
---------------------------------------------------------------------------

    \548\ See, e.g., Idaho Power Co., 128 FERC ] 61,064 at P 30-40;
Duke Energy Carolinas, LLC, 127 FERC ] 61,281, at P 38-41 (2009);
New York Indep. Sys. Operator, Inc., 125 FERC ] 61,068, at P 61-64
(2008).
---------------------------------------------------------------------------

G. Cost Allocation Matters Related to Other Commission Rules, Joint
Ownership, and Non-Transmission Alternatives

    751. Commenters also raised cost allocation issues related to
generator interconnection costs in Order No. 2003,\549\ pancaked
transmission rates policy in Order No. 2000,\550\ transmission rate
incentives in Order No. 679,\551\ the relationship of this proceeding
to the proceeding on variable energy resources, Docket No. RM10-11-000,
and joint transmission ownership.
---------------------------------------------------------------------------

    \549\ Standardization of Generator Interconnection Agreements
and Procedures, Order No. 2003, 68 FR 49846 (Aug. 18, 2003), FERC
Stats. & Regs. ] 31,146, at P 676 (2003), order on reh'g, Order No.
2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005), FERC
Stats. & Regs. ] 31,171 (2004), order on reh'g, Order No. 2003-C, 70
FR 37661 (Jun. 30, 2005), FERC Stats. & Regs. ] 31,190 (2005), aff'd
sub nom. Nat'l Ass'n of Regulatory Util. Comm'rs v. FERC, 475 F.3d
1277 (DC Cir. 2007), cert. denied, 552 U.S. 1230 (2008).
    \550\ Regional Transmission Organizations, Order No. 2000, 65 FR
809 (Jan. 6, 2000), FERC Stats. & Regs. ] 31,089 (1999), order on
reh'g, Order No. 2000-A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. &
Regs. ] 31,092 (2000), aff'd sub nom. Pub. Util. Dist. No. 1 of
Snohomish County, Washington v. FERC, 272 F.3d 607 (DC Cir. 2001).
    \551\ Order No. 679, 71 FR 43294, FERC Stats. & Regs. ] 31,222,
order on reh'g, Order No. 679-A, 72 FR 1152, FERC Stats. & Regs. ]
31,236, order on reh'g, 119 FERC ] 61,062.

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

1. Whether To Reform Cost Allocation for Generator Interconnections
    752. In the Proposed Rule, the Commission did not propose to alter
the cost recovery provisions of its generator interconnection rules.
a. Comments
    753. Several commenters address the interaction between Order No.
2003 and the cost allocation requirements of this Final Rule. For
example, Duke seeks clarification that impacts on transmission owners
in neighboring regions resulting from a specific generator
interconnection or transmission service request will continue to be
addressed under the existing generation or transmission interconnection
arrangements. East Texas Cooperatives urge the Commission to require
development of an integrated process for studying network and point-to-
point transmission service requests and generator interconnection
requests that affect neighboring regions.
    754. Other commenters address the interaction between Order No.
2003 and the transmission planning requirements. For instance, Solar
Energy Industries and Large-scale Solar state that the Commission
should require transmission providers to coordinate the transmission
planning study process with the generator interconnection study
process. PPL Companies agree stating that this would ensure that
interconnection customers and native load bear their fair share of the
costs of new transmission. On the other hand, NextEra believes that the
costs of transmission projects identified through the transmission
planning process should not be allocated to generators.
    755. Some commenters urge the Commission to reevaluate the cost
responsibilities in Order No. 2003 because they believe these are being
used to circumvent the transmission planning process, creating a
situation where load serving entities are forced to finance projects
without project beneficiaries being identified.\552\ If this continues,
Bay Area Municipal Transmission Group asserts that greater transparency
in the interconnection process is needed to facilitate the
determination of the most cost-effective interconnection alternative.
California Municipal Utilities argue that, if the costs of network
upgrades identified through generator interconnection studies are borne
by load within a region, those upgrades should be examined by the
regional transmission planning process as a necessary precondition to
approval by the relevant transmission provider. Six Cities note that
the California ISO had represented in an Order No. 890 compliance
filing that all interconnection-related network upgrades would be
submitted through the request window open in each planning cycle and
evaluated in the transmission planning process. Northern California
Power Agency asserts that the generator interconnection process
includes a loophole whereby transmission providers can circumvent the
transmission planning process by proposing individual projects that are
constructed by transmission providers, and recommends that the
Commission limit the use of interconnection-related upgrades by
ensuring they are a cost-effective means of grid expansion.
---------------------------------------------------------------------------

    \552\ E.g., Bay Area Municipal Transmission Group; California
Municipal Utilities; and City of Santa Clara.
---------------------------------------------------------------------------

    756. Several commenters discuss cost allocation for generation
interconnection in the context of public policy projects. For example,
Imperial Irrigation District asks the Commission to clarify that
generation interconnection customers and their off-takers can be
allocated the costs of public policy projects under the principles
developed by transmission providers in each region when those
generation project developers and their off-takers cause the need for
or benefit from the public policy projects. In its reply comments, City
of Santa Clara agrees with Imperial Irrigation District. Old Dominion
agrees with PJM that greater clarity is needed regarding the extent to
which the Commission is proposing that cost allocation for public
policy driven projects depart from the existing Order No. 2003
framework. Old Dominion recommends that the Commission require all
transmission providers to describe in their respective transmission
planning and cost allocation tariff filings specific rules governing
cost allocation for such projects.
    757. East Texas Cooperatives state that they support a cost
allocation policy under which the costs of network upgrades required to
serve the native load of a transmission provider's network customers
are rolled into the transmission provider's rates. They recommend that
if a network upgrade is needed to accommodate an interconnection
request for a generating facility that has not been designated as a
network resource or is not otherwise contractually committed to serve
customers within the transmission provider's footprint on a long-term
basis, the interconnecting customer should be required to pay for the
cost of network upgrades that would not have been required but for the
interconnection request. They state that applying this policy would
provide a level of assurance that the cost of such facilities will be
allocated roughly commensurate to the estimated benefits.
    758. Northern Tier Transmission Group asserts that, if a
transmission provider does not execute an interconnection agreement
with a generator, then the transmission provider has no mechanism to
assess costs upon the generator. Northern Tier Transmission Group
states that, to the extent the Commission chooses to address this
practical issue, it should be done in the context of the generator
interconnection procedures and agreements and not in the context of
transmission planning.
    759. In response, California ISO argues that such suggestions are
beyond the scope of this proceeding and, if the Commission wishes to
overhaul Order No. 2003, it should do so in a separate rulemaking so
that parties have adequate notice that the Commission is proposing to
modify its pro forma large generator interconnection procedures.
Replying to Six Cities, California ISO argues that their assertion is
based on a misconception that interconnection-related network upgrades
need to be approved through the transmission planning process.
California ISO states that Order No. 890 did not apply to such network
upgrades.
b. Commission Determination
    760. The Commission agrees with the California ISO and other
commenters that issues related to the generator interconnection process
and to interconnection cost recovery are outside the scope of this
rulemaking. Order No. 2003 sets forth the procedures for the
interconnection of a large generating transmission facility to the bulk
power system. This Final Rule does not set forth any new requirements
with respect to such procedures for interconnecting large, small, or
wind or other generation facilities. Therefore, this Final Rule is not
the proper proceeding for commenters to raise issues about the
interconnection agreements and procedures under Order

Nos. 2003,\553\ 2006 \554\ or 661.\555\ However, in not addressing
these issues here, we are not minimizing the importance of evaluating
the impact of generation interconnection requests during transmission
planning, nor limiting the ability of public utility transmission
providers to use requests for generator interconnections in developing
assumptions to be used in the transmission planning process.
---------------------------------------------------------------------------

    \553\ Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ] 31,146,
order on reh'g, Order No. 2003-A, 69 FR 15932, FERC Stats. & Regs. ]
31,160, order on reh'g, Order No. 2003-B, 70 FR 265, FERC Stats. &
Regs. ] 31,171, order on reh'g, Order No. 2003-C, 70 FR 37661, FERC
Stats. & Regs. ] 31,190, aff'd sub nom. Nat'l Ass'n of Regulatory
Util. Comm'rs v. FERC, 475 F.3d 1277 (DC Cir. 2007), cert. denied,
552 U.S. 1230 (2008).
    \554\ Order No. 2006, 70 FR 34189, FERC Stats. & Regs. ] 31,180,
order on reh'g, Order No. 2006-A, 70 FR 71760, FERC Stats. & Regs. ]
31,196, order granting clarification, Order No. 2006-B, 71 FR 42587,
FERC Stats. & Regs. ] 31,221.
    \555\ Order No. 661, 70 FR 34993 (Jun. 16, 2005), FERC Stats. &
Regs. ] 31,186, order on reh'g, Order No. 661-A, FERC Stats. & Regs.
] 31,198.
---------------------------------------------------------------------------

2. Pancaked Rates
a. Comments
    761. A few commenters ask the Commission to address the pancaking
of rates within transmission planning regions. Transmission Dependent
Utility Systems assert that the Proposed Rule should eliminate regional
rate pancaking as it remains a significant financial dilemma for many
transmission customers and is destructive to regional planning.
Transmission Dependent Utility Systems submit that if the Commission is
going to implement a requirement for regional cost allocation, it
should, at a minimum, eliminate pancaked rates unless there is an
existing regional cost allocation method in place.
    762. Sunflower and Mid-Kansas, on the other hand, contend that the
Commission should modify its ``no pancaking'' policies for an RTO or
ISO because the policy is not appropriate for large interregional
projects and will potentially create extremely high rate increases for
customers.
    763. Gaelectric North America explains that merchant transmission
developers are creating new pancaked rates. It asserts that, as public
utilities construct radial merchant lines and allocate their costs
through participant funding, they are creating additional pancaked
rates for new generation owners who may wish to utilize these new
facilities. Gaelectric North America argues that such pancaked rates
inhibit the development and use of renewable resources. Further, it
states that stringing radial transmission over network facilities is
inefficient and pursued only to avoid appropriate cost allocation.
b. Commission Determination
    764. We decline to make new findings with respect to pancaked rates
in this Final Rule as it is beyond the scope of this proceeding. In
particular, we do not make any modifications to the Commission's
pancaked rate provisions for an RTO under Order No. 2000. If rate
pancaking is an issue in a particular transmission planning region,
stakeholders may raise their concerns in the consultations leading to
the compliance proceedings for this Final Rule or make a separate
filing with the Commission under section 205 or 206 of the FPA, as
appropriate.
3. Transmission Rate Incentives
    765. In the Proposed Rule, the Commission did not propose to alter
its transmission rate incentive policies of Order No. 679.
a. Comments
    766. Some commenters suggest that the Commission revisit its policy
on transmission rate incentives, as set forth in Order No. 679. For
example, they relate the Commission's proposals regarding nonincumbent
transmission developers to transmission rate incentives.\556\
Transmission Access Policy Study Group suggests that the Commission
could require an incumbent transmission provider that exercises a
federal right of first refusal to own and build a transmission facility
to forgo any incentives on that facility. It argues that an incumbent
transmission owner that exercises a federal right of first refusal
should not then be given an incentive as necessary to encourage it to
construct needed transmission. Minnesota Public Utilities Commission
and Minnesota Office of Energy Security believe that one reason a
federal right of first refusal may be justified is because there are
instances where an incumbent transmission provider's rate of return is
significantly lower than the incentive rate of return the Commission
has approved for nonincumbent transmission developers. ITC Companies
replies that such instances only demonstrate that different
transmission incentives have been awarded in different cases by
different regulatory bodies, noting that there are a variety of
approved utility ROEs across the industry.
---------------------------------------------------------------------------

    \556\ E.g., New England States Committee on Electricity;
Transmission Access Policy Study Group; and Southern California
Edison.
---------------------------------------------------------------------------

    767. Other commenters tie the Commission's cost allocation
proposals to transmission rate incentives. For example, APPA states
that there is a clear causal connection between thorny cost allocation
concerns and the Commission's incentive policy. APPA argues that when
excessive transmission rate incentives are awarded to project sponsors,
no one benefits from the associated costs except for the sponsors.
Transmission Access Policy Study Group also suggests that the
Commission use this opportunity to reevaluate application of Order No.
679 so that it does not add burdens on the economy or make siting and
cost allocation issues more difficult than they already are.
Transmission Dependent Utility Systems also state that transmission
providers should be able to recover only the costs associated with a
major transmission project through formula rates if that project was a
product of an Order No. 890-compliant planning process that also meets
the requirements of the Final Rule.
    768. Joint Commenters recite cases in which project developers have
been granted rate incentives that they believe substantially exceed the
incentives that would result in just and reasonable rates. Joint
Commenters also assert that the Commission has failed to recognize that
the financial ground has shifted, citing the recent recession,
historically low interest rates, and high unemployment. According to
Joint Commenters, the rate of return needed to attract investment in a
long-lived asset used to provide monopoly service is less than it was a
few years ago. Finally, Joint Commenters recommend that the Commission
revisit two features of its 1992 incentive rate policy statement,\557\
concerning the requirement that incentive rate mechanisms be
symmetrical and the requirement that applicants quantify the benefits
to ratepayers as the incentive payment is awarded, arguing that these
principles are equally important today. In its reply comments, Illinois
Commerce Commission generally agrees with Joint Commenters, as does
Organization of MISO States.
---------------------------------------------------------------------------

    \557\ Incentive Ratemaking for Interstate Natural Gas Pipelines,
Oil Pipelines, and Electric Utilities, 61 FERC ] 61,168 (1992).
---------------------------------------------------------------------------

    769. Pacific Gas & Electric recommends that the Commission clearly
signal in the Final Rule that rate incentives are available for
utilities that dedicate resources to the successful development of
needed regional projects. In particular, Pacific Gas & Electric
suggests that incentives for partnership in the development of major
backbone projects crossing multiple

jurisdictions are appropriate. Pacific Gas & Electric suggests that
incentives should be offered for partnerships to both independent
transmission companies and incumbent utilities, and that the incentives
should be conditioned upon establishment of development arrangements
that ensure consistent design standards are used that are compatible
with the incumbent system, ongoing coordination of maintenance
arrangements by responsible entities, and proper bilateral
interconnection or coordinated operation agreements that will ensure
the continuity and sustained reliability of the system.
    770. However, a number of commenters oppose calls to reopen Order
No. 679 in this proceeding.\558\ Several commenters argue that such
comments are beyond the scope of this rulemaking. They note that Order
No. 679 was implemented in response to the direction of Congress,
codified in section 219 of the FPA, to incent transmission investment.
Some commenters note that Order No. 679 does not undermine transmission
planning and cost allocation processes because the grant of incentives
is conditioned on approval of the project under the relevant regional
transmission planning processes. APPA states that it opposes blanket
statements supporting the applicability of incentives under Order No.
679, and notes that Pacific Gas & Electric's request is illuminating
because it shows how accustomed investor-owned utilities have become to
obtaining such incentives and how they assume the Commission will
simply rubber stamp in advance their requests for more incentives.
---------------------------------------------------------------------------

    \558\ E.g., AEP; Edison Electric Institute; EIF Management; ITC
Companies; National Grid; Pacific Gas & Electric; and PSEG
Companies.
---------------------------------------------------------------------------

b. Commission Determination
    771. We acknowledge commenters concerns regarding the Commission's
policy on transmission rate incentives under Order No. 679. However, we
decline to revisit or modify our policy under Order No. 679 in this
Final Rule, as it is beyond the scope of this proceeding.\559\
---------------------------------------------------------------------------

    \559\ The Commission issued a Notice of Inquiry on May 19, 2011
regarding its policy on transmission incentives under Order No. 679.
See Promoting Transmission Investment Through Pricing Reform, Notice
of Inquiry, 135 FERC ] 61,146 (2011).
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4. Relationship of This Proceeding to the Proceeding on Variable Energy
Resources
a. Comments
    772. APPA argues that, contrary to the Commission's decision not to
address transmission planning and cost allocation issues in its
proceeding on the integration of variable energy resources (VER),
Docket No. RM10-11-000, it believes that the two issues are not easy to
compartmentalize. According to APPA, effective integration of VERs into
regional transmission systems depends in large part on the availability
of transmission facilities to support such integration, which in turn
raises the issue of who will pay for the additional transmission
facilities needed to undertake this integration effort. Thus, APPA
urges the Commission to consider the tariff modification issues raised
by VERs integration together with the need to develop cost allocation
methods to pay for the additional transmission facilities that such
integration requires.\560\
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    \560\ APPA also incorporates by reference the comments it
submitted in Docket No. RM10-11-000.
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    773. In its reply comments, Exelon argues that the Commission
should address in this proceeding the operational issues entailed in
integrating large amounts of VERs onto the grid in tandem with its
rules for transmission planning and cost allocation. It states that
whether or not the Commission issues a single rule in these dockets, it
should rely on the record developed in the VERs rulemaking proceeding
in deciding the Final Rule here, arguing that the record in the VERs
proceeding fully supports the Commission requiring full accounting for
the costs of integrating wind and other variable resources.
b. Commission Determination
    774. This Final Rule establishes minimum requirements to guide the
affected entities in developing their own transmission planning
processes and cost allocation methods, which then will be submitted for
filing with the Commission. The requirements established by this Final
Rule apply to transmission planning and cost allocation for all
resources. The VERs proceeding, however, addresses operational issues.
To the extent that entities consider it necessary or appropriate to
consider such operational issues in this Final Rule, they may do so by
making a separate section 205 filing rather than raise issues on
compliance in this proceeding.
5. Joint Ownership
a. Comments
    775. A number of commenters urge the Commission to consider joint
transmission ownership as a financing and cost allocation tool within
the Proposed Rule. APPA and Six Cities ask the Commission to promulgate
a rule favoring joint transmission ownership and to require that
eligibility for rate incentives depend on an applicant's showing that
it has offered reasonable opportunities for joint transmission
ownership. APPA asserts that joint ownership diversifies financial
risks and reduces the overall costs of the project as well as the need
for transmission incentives. Transmission Access Policy Study Group and
Transmission Agency of Northern California state that joint ownership
leads to a more collaborative process in planning and development for
both pooled systems and load serving entities. Transmission Access
Policy Study Group states that joint ownership results in more diverse
generation scenarios, shorter permitting processes during siting, and
simpler resolutions of cost allocation issues, and points out that
joint ownership spreads the risk of projects and provides a variety of
sources of capital for projects.
b. Commission Determination
    776. Specific financing techniques such as joint ownership are
beyond the scope of this proceeding. Transmission developers are, of
course, free to consider joint ownership when proposing and developing
a transmission project. Just as we are not requiring any specific cost
allocation method, we do not specifically address joint ownership as a
cost allocation tool in this proceeding. However, we reiterate here our
statement in Order No. 890 that we believe there are benefits to joint
ownership of transmission facilities, particularly large backbone
facilities, both in terms of increasing opportunities for investment in
the transmission grid, as well as ensuring nondiscriminatory access to
the transmission grid by transmission customers.\561\
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    \561\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 593.
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6. Cost Recovery for Non-Transmission Alternatives
a. Comment Summary
    777. GridSolar suggests that the Commission require utilities and
RTOs/ISOs to evaluate alternatives to traditional transmission
solutions on the same basis, using the same standards as those used for
traditional transmission solutions, and that this could be done through
a competitive solicitation. GridSolar notes that distributed energy
resources connect at voltages below 69 kV and therefore do not qualify
for cost allocation treatment under the

transmission planning process although they provide the same services
as other transmission resources. Similarly, 26 Public Interest
Organizations argue that transmission and non-transmission solutions
should be treated comparably for cost recovery purposes.
    778. FirstEnergy Service Company argues that while the Proposed
Rule does not address cost recovery for non-transmission projects, only
the costs of facilities that perform a transmission function (including
energy storage projects) should be included in transmission rates.
FirstEnergy Service Company argues that regional transmission planning
processes should not be a vehicle for owners of generation or demand
side management projects that are eligible to earn revenue from sales
of energy, capacity, and ancillary services to earn subsidies from
transmission customers.
b. Commission Determination
    779. As we make clear above in the section on Regional Transmission
Planning, we are maintaining the approach taken in Order No. 890 and
will require that generation, demand resources, and transmission be
treated comparably in the regional transmission planning process.\562\
However, while the consideration of non-transmission alternatives to
transmission facilities may affect whether certain transmission
facilities are in a regional transmission plan, we conclude that the
issue of cost recovery for non-transmission alternatives is beyond the
scope of the transmission cost allocation reforms we are adopting here,
which are limited to allocating the costs of new transmission
facilities.\563\
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    \562\  See discussion supra Section III.A.
    \563\ As we stated in the Proposed Rule, the Commission has
recognized that, in appropriate circumstances, alternative
technologies may be eligible for treatment as transmission for
ratemaking purposes. See Proposed Rule, FERC Stats. & Regs. ] 32,660
at n.58 (citing Western Grid Development, LLC, 130 FERC ] 61,056
(2010)).
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V. Compliance and Reciprocity Requirements

A. Compliance

1. Commission Proposal
    780. With the exception of the proposed interregional transmission
coordination and interregional cost allocation requirements, the
Proposed Rule would require each public utility transmission provider
to submit a compliance filing within six months of the effective date
of the Final Rule in this proceeding. With regard to the proposed
interregional transmission coordination and interregional cost
allocation requirements, the Proposed Rule would require each public
utility transmission provider to submit a compliance filing within one
year of the effective date of the Final Rule in this proceeding.\564\
The Commission proposed that it would assess whether each compliance
filing satisfies the proposed requirements and principles stated above
and issue additional orders as necessary to ensure that each public
utility transmission provider meets the requirements of the Proposed
Rule.
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    \564\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 179.
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2. Comments
    781. Exelon urges the Commission to adhere to its original time
schedule for compliance filings of six months for intraregional
transmission planning and one year for interregional agreements. In its
reply comments, LS Power argues that the six-month and twelve-month
compliance deadlines are far more generous than the 60-day deadline
that the Commission provided for compliance with Order No. 888 and the
filing of revised power pooling and multilateral coordination
agreements, respectively.
    782. Some commenters suggest that the Commission extend the
compliance deadlines for up to three years.\565\ Indianapolis Power &
Light and SPP state that the proposed six-month and one-year deadlines
do not allow sufficient time for the stakeholder process. Indianapolis
Power & Light states that this is particularly true if the right of
first refusal is removed and recommends that the Commission extend the
deadlines by a minimum of one year. SPP recommends that the Commission
extend the proposed deadline for regional transmission planning by at
least six months and for interregional transmission planning and cost
allocation to three years. MISO Transmission Owners state that the
Commission should extend all compliance deadlines by a minimum of six
months. Arizona Corporation Commission states that the Commission
should recognize that most public utility transmission providers in the
West are not members of an RTO and will need more time, perhaps 24-36
months, to draft regional and interregional transmission plans. Arizona
Public Service Company agrees in is reply comments that the compliance
deadlines are too aggressive, arguing that the Commission is proposing
a vast array of changes that will require utilities to develop
positions, collaborate with neighboring utilities, and reach consensus
with regional groups.
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    \565\ E.g., Indianapolis Power & Light; SPP; MISO Transmission
Owners; Arizona Corporation Commission; and Arizona Public Service
Company.
---------------------------------------------------------------------------

    783. Western Area Power Administration recommends that, in lieu of
compliance filings, the Commission require transmission providers to
file periodic status reports regarding intraregional and interregional
efforts. As an alternative approach, it recommends that the Commission
extend the compliance filing deadline to one year for intraregional
transmission planning and cost allocation issues and two years for
interregional issues. Ad Hoc Coalition of Southeastern Utilities and
Large Public Power Council recommend that in lieu of the proposed one-
year compliance filing requirement, that the Commission call for status
updates on these matters in one year's time, potentially to be followed
by further orders on a regional basis establishing reasonable timeline
targets.
    784. Focusing on the six month regional planning compliance
deadline, some commenters express the view that six months is a
reasonable compliance period.\566\ LS Power notes that many of the
commenters expressing opposition to the six-month compliance deadline
are the same entities that are opposed to removal of the federal right
of first refusal, suggesting that any extension of compliance periods
not apply to the federal right of first refusal from jurisdictional
OATTs and agreements.
---------------------------------------------------------------------------

    \566\ E.g., Northwest & Intermountain Power Procedures Coalition
and LS Power.
---------------------------------------------------------------------------

    785. Other commenters express concern about the ability of
transmission providers to meet the six-month compliance filing
requirement for regional transmission planning requirements.\567\ New
England States Committee on Electricity states that a Final Rule
addressing the rights and obligations of nonincumbent transmission
providers within the regional planning process should provide the
planning regions adequate time to sort through a means of complying.
Xcel urges the Commission to allow entities in the Western
Interconnection sufficient time and latitude to develop mechanisms that
effectively meet the needs of the region; it states that, given the
needs of the western region, six months or even one year is an
unreasonably short period of time to build a structure to comply with
the Commission's regional transmission planning requirements.
Washington Utilities and Transportation Commission states that the
Commission need not proceed with urgency but

should allow existing regional processes to mature, which may lead to a
more expeditious and effective transmission planning process.
---------------------------------------------------------------------------

    \567\ E.g., New England States Committee on Electricity and
Xcel.
---------------------------------------------------------------------------

    786. Focusing on the one year interregional compliance deadline,
East Texas Cooperatives state that, given the urgent need for
interregional transmission planning reform, the Commission should
require filing of interregional transmission planning agreements within
six months of the effective date of the Final Rule. In its reply
comments, East Texas Cooperatives add that shortening this deadline
would motivate transmission providers to improve coordination with
their adjacent regions. Exelon states that for sets of regions that
currently have Commission-approved joint operating agreements, the
Commission should require a six-month compliance filing.
    787. Other commenters contend that the one-year time period for
compliance filings relating to interregional transmission planning
agreements is unworkable. Southern Companies doubt that an
interregional cost allocation agreement could be developed in the
Southeast within the proposed one-year deadline. ISO/RTO Council states
that this proposal is unworkable due to the complexity, limited
resources, the need to involve stakeholders, and potentially the number
of agreements to be reached. NV Energy agrees, stating that significant
additional time is needed to address interregional transmission
agreements and cost allocation issues given the number of parties
involved. Xcel agrees that the proposed one-year deadline is
unattainable and the Commission should allow more time for
interregional planning and cost allocation initiatives to develop
voluntarily.
    788. Duke and Georgia Transmission Corporation state that the
Commission should provide two years to submit interregional
transmission planning agreements, given the number of parties that may
be involved and the difficulties of developing cost allocation methods.
Edison Electric Institute requests that the Commission be flexible
regarding compliance deadlines for interregional agreements and cost
allocation and consider allowing up to two years for compliance.
Pennsylvania PUC states that interregional agreements will require many
actions internal to RTOs and ISOs and planning organizations, therefore
the Commission should consider expanding the compliance period from one
year to 18 or 24 months.
    789. With regard to compliance filings by RTOs and ISOs, New York
ISO argues that the Commission should narrow the scope of the
compliance filings required under the Final Rule so that RTOs and ISOs
are not effectively compelled to demonstrate compliance with
requirements that they have already satisfied in their individual Order
No. 890 planning proceedings. Several commenters also urge the
Commission to consider existing RTO or ISO cost allocation methods as
compliant with the proposed cost allocation principles and to avoid
reopening debates about regional cost allocation methods already
approved by the Commission.\568\ Some of these commenters argue that
existing processes, such as those used in California ISO and ISO New
England, are reasonable \569\ while others disagree.\570\
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    \568\ E.g., California ISO; SoCal Edison; San Diego Gas &
Electric; Eastern Mass. Consumer Owned System; Northeast Utilities;
MISO; New York ISO; NEPOOL; New England States Committee on
Electricity; Kansas Corporation Commission; and Xcel.
    \569\ E.g., California PUC; Pacific Gas & Electric; NEPOOL; and
Connecticut & Rhode Island Commissions.
    \570\ Several commenters, such as the Integrated Transmission
Benefits Model Proponents and Maine Parties argue that ISO New
England's current transmission planning and cost allocation methods
do not comply with this Final Rule. These concerns should be raised
during the stakeholder process used to develop compliance with this
Final Rule. To the extent that a commenter believes that its
concerns have not been resolved in the relevant compliance filing,
it can raise those concerns at that time in a protest to the
compliance filing.
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    790. Several commenters state that the Commission should not
lightly change existing regional cost allocation methods.\571\ For
example, Duke states that parties challenging the appropriateness of an
existing Commission-approved method should bear a heavy burden of
showing why that method is inconsistent with the Final Rule.
Transmission Dependent Utility Systems state that the Commission should
not automatically disrupt current regional cost allocation methods but
instead require compliance filings that demonstrate that the regional
cost allocation method was indeed the product of an open and inclusive
stakeholder process and that the regional cost allocation method either
meets the Commission's proposed cost allocation principles, or that the
existing regional cost allocation method is consistent with or superior
to the requirement of those principles.
---------------------------------------------------------------------------

    \571\ E.g., Duke; New Jersey Board; Northeast Utilities; and
Transmission Dependent Utility Systems.
---------------------------------------------------------------------------

    791. Additionally, MISO Transmission Owners, Indianapolis Power &
Light, and SPP recommend that the Commission clarify that transmission
owners in an RTO or ISO are permitted to participate in the compliance
filing of the RTO or ISO without making a separate compliance filing of
their own. Omaha Public Power District suggests that providers that are
not members of an RTO be allowed to participate in the relevant RTO
planning process to achieve the interregional planning mandate because
this would reduce the cost of coordination and improve its efficiency
and effectiveness.
3. Commission Determination
    792. Given the various comments requesting a longer compliance
period, we extend the compliance filing requirements set forth in the
Proposed Rule. Accordingly, we find that, with the exception of the
requirements with respect to interregional transmission coordination
procedures and an interregional cost allocation method or methods, each
public utility transmission provider must submit a compliance filing
within twelve months of the effective date of this Final Rule revising
its OATT or other document(s) subject to the Commission's jurisdiction
as necessary to demonstrate that it meets the requirements set forth in
this Final Rule.\572\ The Commission also requires each public utility
transmission provider to submit a compliance filing within eighteen
months of the effective date of this Final Rule revising its OATT or
other document(s) subject to the Commission's jurisdiction as necessary
to demonstrate that it meets the requirements set forth herein with
respect to interregional transmission coordination procedures and an
interregional cost allocation method or methods. As explained below, we
expect that the twelve month and eighteen month deadlines provide
sufficient time for each public utility transmission provider to meet
the requirements of this Final Rule.
---------------------------------------------------------------------------

    \572\ See Appendix C for the pro forma Attachment K consistent
with this Final Rule.
---------------------------------------------------------------------------

    793. For those suggesting that current transmission planning and
cost allocation initiatives should be allowed more time to develop, we
find that the need to provide rates, terms and conditions of
jurisdictional service that are just and reasonable and not unduly
discriminatory or preferential, and the need to build new transmission
facilities that more efficiently or cost-effectively support the
reliable development and operation of wholesale electricity markets,
requires that the reforms adopted in this Final Rule are implemented in
a timely

fashion.\573\ The Commission concludes that the time periods provided
for adoption of these reforms--twelve months for regional transmission
planning and cost allocation reforms and eighteen months for
interregional reforms--are reasonable and achievable. These extended
time periods provide additional time for public utility transmission
providers to work with their stakeholders to develop transmission
planning and cost allocation processes that conform with the
requirements adopted herein.
---------------------------------------------------------------------------

    \573\ This finding is supported by our discussion above in
section II.
---------------------------------------------------------------------------

    794. We find that the compliance time periods established in this
Final Rule strike an appropriate balance between implementing needed
reforms to transmission planning and cost allocation processes in a
timely fashion and providing time for those involved in these processes
to work with stakeholders to develop transmission planning and cost
allocation processes that conform with the requirements adopted herein.
Moreover, we believe these compliance filing deadlines are compatible
with the interests of those that intend to develop transmission
planning processes that take into account the lessons learned through
the ARRA-funded transmission planning initiatives, discussed above in
section I.C and III.C.I, under which the participants of each
interconnection are currently collaborating on transmission planning to
produce an initial long-term plan in mid-2012 and a final plan in 2013.
For this same reason, we are not persuaded by those commenters that
recommend that the Commission require periodic status reports in lieu
of compliance filings.
    795. In response to commenters' requests, we clarify that an RTO or
ISO and its public utility transmission provider members may make a
compliance filing that demonstrates that some or all of its existing
RTO and ISO transmission planning processes are already in compliance
with this Final Rule, and we will consider this demonstration and any
contrary views on compliance. We require every public utility
transmission provider, including an RTO or ISO transmission provider,
to file its existing or proposed OATT provisions with an explanation of
how these provisions meet the requirements of this Final Rule. While
many of the existing transmission planning and cost allocation
processes and methods may be similar to what this Final Rule requires,
others may differ because this Final Rule's requirements expand on the
Order No. 890 requirements. Whether an existing process was approved
previously by the Commission is not dispositive of whether that process
complies with this Final Rule.
    796. We recognize that it is possible that some existing RTO and
ISO transmission planning and cost allocation processes may already
satisfy the Commission's proposal in whole or in part. However, we
decline to rule generically, in the absence of a record based on a
comparison of existing practices with the provisions of this Final
Rule, on the degree to which a particular RTO or ISO may already be in
compliance.
    797. Furthermore, public utility transmission owners that are part
of Commission-jurisdictional RTOs and ISOs may demonstrate compliance
through that RTO's or ISO's compliance filing and are not required to
make a separate compliance filing. This includes, in response to SPP,
compliance with the interregional transmission coordination
requirements to the extent an RTO or ISO has negotiated the necessary
arrangements on behalf of its members. In response to Omaha Public
Power District, we encourage both RTO and ISO members and those not in
an RTO or ISO to work together regarding regional transmission
planning. We neither prohibit non-RTO/ISO members that are
geographically adjacent to and/or contiguous with an RTO/ISO from
participating in the RTO/ISO's regional transmission planning process
nor do we require an RTO/ISO to admit nonmembers to its regional
transmission planning process. The decision on whether to combine their
transmission planning efforts in this way to comply with the regional
transmission planning and regional cost allocation requirements and the
interregional transmission coordination requirements and interregional
cost allocation requirements of this Final Rule is a decision that is
best left to the individual entities as well as to the two regions in
question. In addition, the OATT for the RTO or the ISO of which a
public utility transmission provider is a part should include commonly
agreed-to language describing that RTO/ISO's interregional transmission
coordination with each neighboring transmission planning region.
    798. In addition, in non-RTO/ISO regions, if public utility
transmission providers in those regions decide to make combined
compliance filings, they are free to do so. However, each public
utility transmission providers' OATT must include the reforms required
in this Final Rule.

B. Reciprocity

1. Commission Proposal
    799. The Commission proposed that transmission providers that are
not public utilities (i.e., non-public utility transmission providers)
would have to adopt the requirements of the Proposed Rule as a
condition of maintaining the status of their safe harbor tariff or
otherwise satisfying the reciprocity requirement of Order No. 888.\574\
The Commission also stated that if it finds on the appropriate record
that a non-public utility transmission provider is not participating in
the proposed regional transmission planning and cost allocation
processes set forth in this Final Rule, the Commission may exercise its
authority under FPA section 211A \575\ on a case-by-case basis.\576\
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    \574\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 181
(citing Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63).
Under the pro forma OATT, a non-public utility transmission provider
may satisfy the reciprocity condition in one of three ways. First,
it may provide service under a tariff that has been approved by the
Commission under the voluntary ``safe harbor'' provision of the pro
forma OATT. A non-public utility transmission provider using this
alternative submits a reciprocity tariff to the Commission seeking a
declaratory order that the proposed reciprocity tariff substantially
conforms to, or is superior to, the pro forma OATT. The non-public
utility transmission provider then must offer service under its
reciprocity tariff to any public utility transmission provider whose
transmission service the non-public utility transmission provider
seeks to use. Second, the non-public utility transmission provider
may provide service to a public utility transmission provider under
a bilateral agreement that satisfies its reciprocity obligation.
Finally, the non-public utility transmission provider may seek a
waiver of the reciprocity condition from the public utility
transmission provider. See Order No. 890, FERC Stats. & Regs. ]
31,241 at P 163.
    \575\ FPA section 211A(b) provides, in pertinent part, that
``the Commission may, by rule or order, require an unregulated
transmitting utility to provide transmission services--(1) at rates
that are comparable to those that the unregulated transmitting
utility charges itself; and (2) on terms and conditions (not
relating to rates) that are comparable to those under which the
unregulated transmitting utility provides transmission services to
itself and that are not unduly discriminatory or preferential.'' The
non-public utility transmission providers referred to in this Final
Rule include unregulated transmitting utilities that are subject to
FPA section 211A.
    \576\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 43.
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2. Comments
    800. Some commenters question whether non-jurisdictional entities
can legally be required to participate in regional and interregional
transmission planning and cost allocation processes. Several non-
jurisdictional entities suggest that they cannot. For example,
Bonneville Power asserts that the proposed mandatory cost allocation
reforms could conflict with its statutory obligations. Bonneville Power
states that

it is required by statute to have Congressional approval before it can
build facilities outside the Pacific Northwest or build major
transmission facilities within the Pacific Northwest. Bonneville Power
states that it is obligated to determine the appropriateness of its
transmission expenditures, and those expenditures are subject to
specific directives or limitations that Congress may include in its
appropriation acts. As a result of these statutory obligations,
Bonneville Power contends that it must retain the right to review each
proposal and agree to any proposed allocation of costs from another
party.
    801. Western Area Power Administration states that it is a federal
power marketing administration and must comply with statutory
requirements that apply to such entities, such as the Anti-Deficiency
Act, the Reclamation Project Act of 1939, and the Flood Control Act of
1944. Western Area Power Administration argues that these statutory
requirements preclude involuntary cost allocation of third-party
transmission facilities to it. Western Area Power Administration also
argues that requiring it to incorporate a mandatory cost allocation
share into its rates is inconsistent with the jurisdiction over, and
power to review, Western Area Power Administration's rates that the
Department of Energy delegated to the Commission.
    802. Bonneville Power requests that the Commission explain the
effect of reciprocity in the context of transmission planning and cost
allocation. Bonneville Power states that if the Commission conditions
reciprocity on adherence to the Proposed Rule, it requests that the
Commission state in the Final Rule that it will accommodate deviations
in compliance filings that are necessary to allow non-public utilities
to participate. Bonneville Power contends that if the Commission does
not accept regional deviations, coordinated regional planning and cost
allocation will likely be unworkable for both public and non-public
utilities in the Pacific Northwest.
    803. Public Power Council asserts that the Commission's proposed
cost allocation method will drive non-public utilities out of the
voluntary planning process. Public Power Council states that
governmentally-owned utilities are subject to state statutes that may
limit their ability to enter into contracts involving unknown future
costs and that bind future district commissions or city councils.
Public Power Council thus argues that the Commission should either
abandon its proposal to require binding cost allocation agreements for
non-RTO areas or withdraw its proposal that voluntary participant
funding cannot be the sole method of cost allocation when the
transmission provider is not a participant in an RTO. Omaha Public
Power District states that it is committed to voluntary participation
in the transmission planning process. However, it also states that as a
state political subdivision it is not subject to the Commission's
general jurisdiction under the FPA and that the Commission has no
authority to set rates for it without its consent.
    804. Four G&T Cooperatives argues that the Commission does not have
jurisdiction under the FPA to require non-public utilities to
participate in regional transmission planning processes or to agree to
regional cost allocation methods. It also argues that the reciprocity
provisions under Order Nos. 888 and 890 and the pro forma OATT do not
provide a basis for requiring non-public utilities to participate in
regional transmission planning and cost allocation. National Rural
Electric Coops state that the Commission has consistently refused to
expand the reach of the reciprocity provision to include transmission
customers other than those from which the non-public utility is taking
service and those who are transmission-owning members of an RTO or ISO.
G&T Cooperatives and National Rural Electric Coops request
clarification that the Commission is not modifying the scope of the
reciprocity requirement as established in Order Nos. 888, 890, and 890-
A.
    805. Western Grid Group, on the other hand, recommends that to
engage non-jurisdictional utilities in regional planning groups, the
Commission should make it clear that such participation is a
requirement for Commission recognition of reciprocity tariffs and that
all entities that share the grid have an obligation in the public
interest to help plan its expansion and modernization.
    806. SPP states that, consistent with the approach set forth in
Order No. 890, the Commission should continue to encourage
participation by non-jurisdictional entities in regional transmission
planning processes. SPP also states that the Commission should consider
requiring non-jurisdictional entities that have reciprocity tariffs on
file with the Commission to modify those tariffs specifically to
address the obligation to participate in the regional transmission
planning process and cost allocation mechanism development. Similarly,
San Diego Gas & Electric suggests that Order No. 888's reciprocity
requirements be enforced, as necessary. Anbaric and PowerBridge also
believe that the Final Rule should apply to all transmission providers,
including to those subject to the Commission's reciprocity
requirements.
    807. A number of commenters also address the Commission's authority
under FPA section 211A. National Rural Electric Coops argue that the
Commission's jurisdiction under FPA section 211A is limited to
requiring a subset of unregulated transmitting utilities to provide
transmission services to others on terms and conditions (not relating
to rates) that are comparable to those under which the unregulated
transmitting utility provides transmission services to itself and that
are not unduly discriminatory or preferential. National Rural Electric
Coops asserts that it is concerned that the Commission may be
interpreting FPA section 211A to mean that it could invoke the
provision in circumstances other than those in which it makes a finding
that an unregulated transmitting utility is not treating its
transmission customers in a way that is comparable to the way it treats
itself. National Rural Electric Coops request that the Commission
clarify that it will address questions of non-comparable treatment on a
case-by-case basis as necessary. National Rural Electric Coops state
that such a clarification could help avoid unnecessary litigation.
    808. Imperial Irrigation District questions the Commission's legal
authority to allocate costs to non-public utilities via either the
reciprocity principle or FPA section 211A. It states that cost
allocation is a rate issue, and Congress has not authorized the
Commission to set rates for non-public utilities. It argues that under
the Commission's reciprocity principle, the Commission does not set
rates of non-public utilities.
    809. Large Public Power Council and Nebraska Public Power District
state that the proposed reciprocity requirement would dramatically
expand the commitment that non-public utilities were asked to make
under Order No. 888 and ensuing orders and would greatly exceed the
Commission's authority. They state that FPA section 211A does not
permit the Commission to compel a non-public utility to contribute
funding for regional or interregional transmission projects, nor would
it enable the Commission to exercise any authority over the
transmission planning or construction plans of a non-public utility.
Sacramento Municipal Utility District urges the Commission to
reconsider its proposal to invoke FPA section 211A

authority on a case-by-case basis. It states that this is unnecessary,
beyond the limited reciprocity requirements of Order Nos. 888 and 890,
and it is beyond the Commission's authority. Western Area Power
Administration states that FPA section 211A does not authorize the
Commission to require unregulated transmitting utilities to engage in
regional transmission planning and cost allocation.
    810. Western Area Power Administration and National Rural Electric
Coops request clarification that the Commission did not intend its
statements in the Proposed Rule regarding FPA section 211A and the
reciprocity provisions of Order Nos. 888 and 890 to expand its
authority over non-public utilities. Georgia Transmission Cooperative
argues that the Commission has not provided evidence to support
application of FPA section 211A and that applying it would be
inconsistent with prior Commission statements that non-public utilities
are not subject to the same cost allocation rules as public utilities.
    811. Transmission Access Policy Study Group and Colorado
Independent Energy Association support the Commission's proposal to
invoke reciprocity for non-jurisdictional transmission providers as
needed to achieve its goals, and they agree with the Commission's
decision not to invoke its authority under FPA section 211A. Colorado
Independent Energy Association also recommends that to avoid the use of
FPA section 211A, the Commission should provide a pro forma OATT and a
date certain for non-jurisdictional entities to report their progress
to the Commission regarding incorporation of the principles set forth
in the Proposed Rule into their OATTs and practices. Transmission
Agency of Northern California believes that the demonstrated
willingness of non-public utility transmission providers to comply
voluntarily with Commission directives shows that an explicit
requirement that they comply with the Proposed Rule is unnecessary.
    812. Other commenters, including MidAmerican and NextEra, suggest
that the Commission should apply reciprocity or exercise its authority
under FPA section 211A to require non-public utilities to participate
in regional and interregional transmission planning and cost allocation
processes. MidAmerican states that the Commission has the authority to
require all non-jurisdictional utilities to comply with, and remain
subject to, the proposed transmission planning and cost allocation
requirements and that the Commission should use this authority if it
intends to achieve its stated objectives on a non-discriminatory basis.
MidAmerican believes that failure to include all transmission providers
will result in an inequitable burden for jurisdictional utilities and
their customers, and it will create additional investment uncertainty
for projects included in the regional plan. NextEra supports the use of
FPA section 211A to extend the requirements of the Final Rule to
unregulated transmitting utilities. It believes that invoking FPA
section 211A on a case-by-case basis is risky and may not ensure
maximum participation by unregulated utilities. AWEA states that the
Commission should make clear its intention to invoke FPA section 211A
as necessary to ensure needed participation in regional transmission
efforts and cost allocation requirements.
    813. Bonneville Power asserts in its response that neither the
Proposed Rule, nor any of the initial comments, provide evidence that
supports invoking FPA section 211A, either on a case-by-case basis or
generically. Bonneville Power disagrees with MidAmerican that public
utility transmission providers would be subject to undue discrimination
if non-public utilities do not participate in transmission planning and
cost allocation. It argues that any differences in treatment would
result from adopting the Proposed Rule, not from discrimination by non-
public utilities. Large Public Power Council disagrees that the
Commission has authority under FPA section 211A to compel non-public
utilities to participate fully in whatever planning and cost allocation
rules are adopted in this proceeding. It also states that the
Commission cannot accomplish indirectly through its reciprocity
provisions what it cannot accomplish directly under the statute.
    814. MidAmerican also suggests that the Commission use its
conditioning authority to require non-jurisdictional utilities to
participate in the regional transmission planning and cost allocation
processes, stating that the Commission has already taken this approach
under FPA section 215. However, in reply, Large Public Power Council
disagrees, noting that section 215 explicitly extends Commission
jurisdiction for reliability purposes over a wide range of entities,
thereby confirming that express direction from Congress is required
before the Commission can exercise jurisdiction over otherwise non-
jurisdictional entities.
3. Commission Determination
    815. To maintain a safe harbor tariff, a non-public utility
transmission provider must ensure that the provisions of that tariff
substantially conform, or are superior, to the pro forma OATT as it has
been revised by this Final Rule. As noted in the Proposed Rule, we are
encouraged, based on the efforts that followed Order No. 890, that both
public utility and non-public utility transmission providers
collaborate in a number of regional transmission planning processes. We
therefore do not believe it is necessary at this time to invoke our
authority under FPA section 211A, which gives us authority to require
non-public utility transmission providers to provide transmission
services on a comparable and not unduly discriminatory or preferential
basis. However, if the Commission finds on the appropriate record that
non-public utility transmission providers are not participating in the
transmission planning and transmission cost allocation process required
by this Final Rule, the Commission may exercise its authority under FPA
section 211A on a case-by-case basis.
    816. Given our decision above, we decline to adopt SPP's suggestion
that the Commission require non-public utility transmission providers
that have safe harbor tariffs on file to modify those tariffs
specifically to address the transmission planning and cost allocation
processes required by this Final Rule. Rather, it remains up to each
non-public utility transmission provider whether it wants to maintain
its safe harbor status by meeting the transmission planning and cost
allocation requirements of this Final Rule.\577\ We also note in
response to National Rural Electric Coops and others that the
Commission is not proposing any changes to the reciprocity provision of
the pro forma OATT or any other document. The Commission is not
modifying the scope of the reciprocity provision.
---------------------------------------------------------------------------

    \577\ For this same reason, we find that it is not necessary to
address Anbaric and PowerBridge's suggestion that this Final Rule
should apply to all transmission providers, including those subject
to the Commission's reciprocity provisions and enforced as
necessary. However, we reiterate our determination in section
IV.E.2. that an entity participating in the regional transmission
planning process can be identified as the beneficiary of a regional
transmission facility and allocated associated costs, irrespective
of its status as a public utility under the FPA.
---------------------------------------------------------------------------

    817. We disagree with Colorado Independent Energy Association that
the Commission should impose any requirements on non-public utility
transmission providers for the purpose of avoiding recourse to section
211A, as we do not see any necessity, at this time, to invoke our
authority under that

section. In addition, we disagree with MidAmerican, NextEra, and SPP
that we should establish requirements regarding participation by non-
public utility transmission providers in regional and interregional
transmission planning and cost allocation processes beyond those
required by reciprocity. We likewise disagree with Western Grid Group
that we need to clarify for non-public utility transmission providers
the importance of their participation in the processes established by
this Final Rule.
    818. The Commission recognizes that many of the existing regional
transmission planning processes are comprised of both public and non-
public utility transmission providers. In the Proposed Rule, the
Commission described the significance of its proposal for non-public
utility transmission providers in terms of the principle of
reciprocity.\578\ None of the commenters has provided a persuasive
reason for departing from the position taken in the Proposed Rule.
Thus, as noted above, and consistent with the approach taken in Order
No. 890, the Commission expects all public utility and non-public
utility transmission providers to participate in the transmission
planning and cost allocation processes set forth in this Final Rule.
The success of the reforms implemented here will be enhanced if all
transmission owners participate. Further, we believe that non-public
utility transmission providers will benefit greatly from the improved
transmission planning and cost allocation processes required for public
utility transmission providers because a well-planned grid is more
reliable and provides more available, less congested paths for the
transmission of electric power in interstate commerce. Those that take
advantage of open access, including improved transmission planning and
cost allocation, should be expected to follow the same requirements as
public utility transmission providers.
---------------------------------------------------------------------------

    \578\ Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 43.
---------------------------------------------------------------------------

    819. In response to G&T Cooperatives and others, we note that the
Commission is not acting here under the FPA to require non-public
utility transmission providers to participate in regional transmission
planning processes or to agree to a method or methods for allocating
the costs of their transmission facilities. Under the reciprocity
provision, if a public utility transmission provider seeks transmission
service from a non-public utility transmission provider to which it
provides open access transmission service, the non-public utility
transmission provider that owns, controls or operates transmission
facilities must provide comparable transmission service that it is
capable of providing on its own system.\579\ A non-public utility
transmission provider that elects to receive such service, therefore,
must do so on terms that satisfy the reciprocity condition. We disagree
that we are using the principle of reciprocity to expand our
jurisdiction over non-public utility transmission providers. Non-public
utility transmission providers are free to decide whether they will
seek transmission service that is subject to the Commission's
jurisdiction, and we do not exercise jurisdiction over them when we
determine the terms under which public utility transmission providers
must provide that transmission service.
---------------------------------------------------------------------------

    \579\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 163.
---------------------------------------------------------------------------

    820. While a number of commenters argue that this Final Rule's
reforms could conflict with their statutory obligations, no specific
conflict has been presented for us to act on in this Final Rule.
Concerns about possible conflicts should be raised in transmission cost
allocation discussions and any subsequent Commission proceedings on
proposed transmission cost allocation methods.
    821. We disagree with National Rural Electric Coops that our
discussion of FPA section 211A in the Proposed Rule is unclear or
ambiguous. However, in response to National Rural Electric Coops we
note that our intent is to invoke section 211A only on a case-by-case
basis. We see no reason to reconsider our position on section 211A as
Sacramento Municipal Utility District requests, nor a need to address
additional arguments concerning the scope of our authority under
section 211A given that we are not acting under section 211A in issuing
this Final Rule. Likewise, in response to Georgia Transmission
Cooperative, we do not need to provide evidence in this proceeding to
support the application of FPA section 211A because we are not applying
it here.
    822. With regard to Transmission Agency of Northern California's
suggestion that an explicit requirement that non-public utility
transmission providers comply with the Proposed Rule is unnecessary
because they are already complying, we note that this Final Rule does
not include any such explicit requirement and instead only notes an
expectation that non-public utility transmission providers will
participate voluntarily.

VI. Information Collection Statement

    823. The Office of Management and Budget (OMB) requires that OMB
approve certain information collection and data retention requirements
imposed by agency rules.\580\ Upon approval of a collection(s) of
information, OMB will assign an OMB control number and an expiration
date. Respondents subject to the filing requirements of a rule will not
be penalized for failing to respond to these collections of information
unless the collections of information display a valid OMB control
number.
---------------------------------------------------------------------------

    \580\ 5 CFR 1320.11(b).
---------------------------------------------------------------------------

    824. The Commission is submitting the proposed modifications to its
information collections to OMB for review and approval in accordance
with section 3507(d) of the Paperwork Reduction Act of 1995.\581\ In
the Proposed Rule, the Commission solicited comments on the need for
this information, whether the information will have practical utility,
the accuracy of provided burden estimates, ways to enhance the quality,
utility, and clarity of the information to be collected or retained,
and any suggested methods for minimizing the respondent's burden,
including the use of automated information techniques. The Commission
also included a chart that listed the estimated public reporting
burdens for the proposed reporting requirements, as well as a
projection of the costs of compliance for the reporting requirements.
The Commission received one comment from Arizona Public Service Company
specifically addressing the Commission burden estimate in the Proposed
Rule.
---------------------------------------------------------------------------

    \581\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    825. Arizona Public Service Company states that while it supports
the need for a robust regional transmission planning process, it
contends that the burden estimate in the Proposed Rule understated the
number of hours and the average rates of the employees working on these
processes. As an example, Arizona Public Service Company states that it
participates in WestConnect, which in the past twelve months has
involved over two dozen regional or subregional transmission planning
meetings. According to Arizona Public Service Company, many of these
meetings last an entire day, and require a significant amount of
preparation work prior to the meeting. It further contends that the
Commission should have included calculation of travel expenses of
participants in the regional transmission planning

processes, including transportation, lodging, and meal expenses.
    826. In the Proposed Rule, the Commission estimated the number of
hours required for the average public utility transmission provider to
comply with the minimum requirements included in the Proposed Rule. The
burden estimates in this Final Rule represent the incremental burden
changes related only to the requirements set forth in this Final
Rule.\582\ It should also be noted that the burden estimates are
averages for all of the filers. Furthermore, we acknowledge that some
regional transmission planning processes have been developed to date
that may require more time to participate than the estimate that the
Commission provided in the Proposed Rule. However, the fact that such
processes have been developed reflects the choice of the participants
in those regional transmission planning processes on how to comply with
the Commission's rules, it does not mean that the Commission's rules
necessarily required such processes. For example, we note that public
utility transmission providers may decide, in a particular region or
between regions, to develop a regional transmission planning process
that includes more objectives and procedures than the minimum set forth
in this Final Rule, which may increase the number of hours necessary to
participate. In any event, Arizona Public Service Company did not
provide any estimates of the number of hours that it has taken to
participate in its regional transmission planning processes, nor
suggested alternative estimates. Thus, for the most part, the
Commission adopts the burden estimates that it set out in the Proposed
Rule.
---------------------------------------------------------------------------

    \582\ 5 CFR 1320.3(b)(1)-(2).
---------------------------------------------------------------------------

    827. As for the hourly rates of the employees, the Commission
relies on average national salaries to develop hourly rates of the
employees necessary to comply with the requirements adopted in this
Final Rule. Again, we note that this is an average rate, and that rates
may be higher or lower depending on the area of the country where the
public utility transmission provider is located. Therefore, we find
that the averages in the Proposed Rule are reasonable estimates of the
average national rates for the employees described below.
    828. Finally, the Commission has included, in its burden estimate,
the number of hours that a public utility transmission provider may
need to travel to participate in a regional transmission planning
process and interregional transmission coordination procedures.
    Burden Estimate and Information Collection Costs: The estimated
Public Reporting burden and cost for the requirements contained in this
Final Rule follow.

----------------------------------------------------------------------------------------------------------------
                                                                                Total
                                         Annual       Annual                               Total        annual
    FERC-917--Proposed reporting       number of    number of     Hours per  response      annual      hours in
       requirements in RM10-23        respondents   responses                             hours in    subsequent
                                        (filers)                                           year 1       years
----------------------------------------------------------------------------------------------------------------
Participation in a transparent and            132          132  110 hrs in Year 1; 52         14520         6864
 open regional transmission planning                             hrs in subsequent
 process that meets regional                                     years.
 transmission planning principles,
 includes consideration of
 transmission needs driven by Public
 Policy Requirements, identifies and
 evaluates transmission facilities
 to meet needs, develops cost
 allocation method(s), and produces
 a regional transmission plan that
 describes and incorporates a cost
 allocation method(s) that meets the
 Commission's principles.
Development of interregional                  132          132  133 hrs in Year 1; 43         17556         5676
 transmission coordination                                       hrs in subsequent
 procedures that meet the                                        years.
 Commission's requirements,
 including the ongoing requirement
 to provide or post certain
 transmission planning information
 and provide annual data exchange,
 as well as the development of a
 cost allocation method for
 interregional transmission
 facilities that meets the
 Commission's principles.
Conforming tariff changes for local           132          132  57 hrs in Year 1; 25           7524        33000
 transmission planning, including                                hrs in subsequent
 those related to consideration of                               years.
 transmission needs driven by Public
 Policy Requirements; and conforming
 tariff changes for regional
 transmission planning and
 interregional transmission
 coordination.
                                                                                -------------------------
    Total Estimated Additional        ...........  ...........  ......................        39600        15840
     Burden Hours, Proposed for FERC-
     917 in NOPR in RM10-23.
----------------------------------------------------------------------------------------------------------------

Cost to Comply

    Year 1: $4,514,400 or [39,600 hours x $114 per hour \583\]
---------------------------------------------------------------------------

    \583\ The estimated cost of $114 an hour is the average of the
hourly costs of: attorney ($200), consultant ($150), technical
($80), and administrative support ($25).
---------------------------------------------------------------------------

    Subsequent Years: $1,805,760 or [15,840 hours x $114 per hour]
    Title: FERC-917.
    Action: Proposed Collections.
    OMB Control No: 1902-0233.
    Respondents: Public Utility Transmission Providers. An RTO or ISO
also may file some materials on behalf of its members.
    Frequency of Responses: Initial filing and subsequent filings.

Necessity of the Information

    829. Building on the reforms in Order No. 890, the Federal Energy
Regulatory Commission adopts these amendments to the pro forma OATT to
correct certain deficiencies in the transmission planning and cost
allocation requirements for public utility transmission providers. The
purpose of this Final Rule is to strengthen the pro forma OATT, so that
the transmission grid can better support wholesale power markets and
ensure that Commission-jurisdictional services are provided at rates,
terms, and conditions that are just

and reasonable and not unduly discriminatory or preferential. We expect
to achieve this goal through this Final Rule by reforming electric
transmission planning requirements and establishing a closer link
between cost allocation and regional transmission planning processes.
    830. Interested persons may obtain information on reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director, e-mail:
<EMAIL_ADDRESS>Phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>.
Comments concerning the collection of information and the associated
burden estimate(s), may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street,
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal
Energy Regulatory Commission, phone:<PHONE_NUMBER>, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically
to the following e-mail address<EMAIL_ADDRESS>Comments
submitted to OMB should include OMB Control No. 1902-0233 and Docket
No. RM10-23-000.

VII. Environmental Analysis

    831. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\584\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact Statement is required for this Proposed Rule
because section 380.4(a)(15) of the Commission's regulations provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to rates and charges for the transmission or
sale of electric energy subject to the Commission's jurisdiction, plus
the classification, practices, contracts and regulations that affect
rates, charges, classifications, and services.\585\ The reforms herein
do not require transmission or other facilities to be built, but rather
establish transmission planning mechanisms that will result in a more
appropriate allocation of costs and thus better ensure just and
reasonable and not unduly discriminatory or preferential rates.
---------------------------------------------------------------------------

    \584\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs.
] 30,783 (1987).
    \585\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VIII. Regulatory Flexibility Act Analysis

    832. The Regulatory Flexibility Act of 1980 (RFA) \586\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
This Final Rule applies to public utilities that own, control or
operate interstate transmission facilities other than those that have
received waiver of the obligation to comply with Order Nos. 888, 889,
and 890. The total number of public utility transmission providers
that, absent waiver, must modify their current OATTs by filing the
revised pro forma OATT is 132. Of these public utility transmission
providers, only 9 filers, or 6.8 percent, have output of four million
MWh or less per year.\587\ The Commission does not consider this a
substantial number and, in any event, each of these entities retains
its rights to request waiver of these requirements. The criteria for
waiver that would be applied under this rulemaking for small entities
is unchanged from that used to evaluate requests for waiver under Order
Nos. 888, 889, and 890. Accordingly, the Commission certifies that this
Final Rule will not have a significant economic impact on a substantial
number of small entities.
---------------------------------------------------------------------------

    \586\ 5 U.S.C. 601-612.
    \587\ A firm is ``small'' if, including its affiliates, it is
primarily engaged in the generation, transmission, and/or
distribution of electric energy for sale and its total electric
output for the preceding fiscal year did not exceed 4 million
megawatt-hours. Based on the filers of the annual FERC Form 1 and
Form 1-F, as well as the number of companies that have obtained
waivers, we estimate that 6.8 percent of the filers are ``small.''
---------------------------------------------------------------------------

IX. Document Availability

    833. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE., Room
2A, Washington, DC 20426.
    834. From the Commission's Home Page on the Internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
    835. User assistance is available for eLibrary and the Commission's
Web site during normal business hours from FERC Online Support at (202)
502-6652 (toll free at 1-866-208-3676) or e-mail at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
<EMAIL_ADDRESS>
X. Effective Date and Congressional Notification

    836. These regulations are effective October 11, 2011. The
Commission has determined, with the concurrence of the Administrator of
the Office of Information and Regulatory Affairs of OMB, that this rule
is not a ``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996. The Commission will submit
this Final Rule to both houses of Congress and the Government
Accountability Office.

List of Subjects in 18 CFR Part 35

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

    By the Commission. Commissioner Moeller is dissenting, in part,
with a separate statement attached.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission amends part 35,
Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

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

0
2. Amend Sec.  35.28 as follows:
0
a. Paragraphs (c)(1) through (c)(1)(iii) are revised.
0
b. Paragraph (c)(1)(vi) is revised.
0
c. Paragraphs (c)(3), (c)(3)(i), and (c)(3)(ii) are revised.
0
d. Paragraphs (c)(4) through (c)(4)(ii) are revised.
0
e. Paragraph (d)(1) is revised.
0
f. Paragraph (e)(1) is revised.

Sec.  35.28   Non-discriminatory open access transmission tariff.

* * * * *
    (c) Non-discriminatory open access transmission tariffs.
    (1) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce must have on file with the Commission a tariff of general
applicability for transmission services,

including ancillary services, over such facilities. Such tariff must be
the open access pro forma tariff contained in Order No. 888, FERC
Stats. & Regs. ] 31,036 (Final Rule on Open Access and Stranded Costs),
as revised by the open access pro forma tariff contained in Order No.
890, FERC Stats. & Regs. ] 31,241 (Final Rule on Open Access Reforms)
and further revised in Order No. 1000, FERC Stats. & Regs. ] 31,323
(Final Rule on Transmission Planning and Cost Allocation by
Transmission Owning and Operating Public Utilities), or such other open
access tariff as may be approved by the Commission consistent with
Order No. 888, FERC Stats. & Regs ] 31,306, Order No. 890, FERC Stats.
& Regs. ] 32,241, and Order No. 1000, FERC Stats. & Regs. ] 31,323.
    (i) Subject to the exceptions in paragraphs (c)(1)(ii),
(c)(1)(iii), (c)(1)(iv) and (c)(1)(v) of this section, the pro forma
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as
revised by the open access pro forma tariff contained in Order No. 890,
FERC Stats. & Regs. ] 31,241 and further revised in Order No. 1000,
FERC Stats. & Regs. ] 31,323, and accompanying rates, must be filed no
later than 60 days prior to the date on which a public utility would
engage in a sale of electric energy at wholesale in interstate commerce
or in the transmission of electric energy in interstate commerce.
    (ii) If a public utility owns, controls, or operates facilities
used for the transmission of electric energy in interstate commerce as
of October 11, 2011, it must file the revisions to the pro forma tariff
contained in Order No. 890, FERC Stats. & Regs. ] 31,241, as amended by
Order No. 1000, FERC Stats. & Regs. ] 31,323, pursuant to section 206
of the FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Order No. 890, FERC Stats.
& Regs. ] 31,241 and Order No. 1000, FERC Stats. & Regs ] 31,323.
    (iii) If a public utility owns, controls, or operates transmission
facilities used for the transmission of electric energy in interstate
commerce as of October 11, 2011, such facilities are jointly owned with
a non-public utility, and the joint ownership contract prohibits
transmission service over the facilities to third parties, the public
utility with respect to access over the public utility's share of the
jointly owned facilities must file the revisions to the pro forma
tariff contained in Order No. 890, FERC Stats. & Regs. ] 31,241 as
amended by Order No. 1000, FERC Stats. & Regs. ] 31,323, pursuant to
section 206 of the FPA and accompanying rates pursuant to section 205
of the FPA.
* * * * *
    (vi) Any public utility that seeks a deviation from the pro forma
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as
revised in Order No. 890, FERC Stats. & Regs. ] 31,241 and Order No.
1000, FERC Stats. & Regs. ] 31,323, must demonstrate that the deviation
is consistent with the principles of Order No. 888, FERC Stats. & Regs
] 31,036, Order No. 890, FERC Stats. & Regs. ] 31,241, and Order No.
1000, FERC Stats. & Regs. ] 31,323.
* * * * *
    (3) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce, and that is a member of a power pool, public utility holding
company, or other multi-lateral trading arrangement or agreement that
contains transmission rates, terms or conditions, must have on file a
joint pool-wide or system-wide open access transmission tariff, which
tariff must be the pro forma tariff contained in Order No. 888, FERC
Stats. & Regs. ] 31,036, as revised by the pro forma tariff contained
in Order No. 890, FERC Stats. & Regs. ] 31,241 and further revised in
Order No. 1000, FERC Stats. & Regs. ] 31,323, or such other open access
tariff as may be approved by the Commission consistent with Order No.
888, FERC Stats. & Regs. ] 31,036, Order No. 890, FERC Stats. & Regs. ]
31,241, and Order No. 1000, FERC Stats. & Regs. ] 31,323.
    (i) For any power pool, public utility holding company or other
multi-lateral arrangement or agreement that contains transmission
rates, terms or conditions and that is executed after October 11, 2011,
this requirement is effective on the date that transactions begin under
the arrangement or agreement.
    (ii) For any power pool, public utility holding company or other
multi-lateral arrangement or agreement that contains transmission
rates, terms or conditions and that is executed on or before October
11, 2011, a public utility member of such power pool, public utility
holding company or other multi-lateral arrangement or agreement that
owns, controls, or operates facilities used for the transmission of
electric energy in interstate commerce must file the revisions to its
joint pool-wide or system-wide open access transmission tariff
consistent with Order No. 890, FERC Stats. & Regs. ] 31,241 as amended
by Order No. 1000, FERC Stats. & Regs. ] 31,323, pursuant to section
206 of the FPA and accompanying rates pursuant to section 205 of the
FPA in accordance with the procedures set forth in Order No. 890, FERC
Stats. & Regs. ] 31,241 and Order No. 1000, FERC Stats. & Regs ]
31,323.
* * * * *
    (4) Consistent with paragraph (c)(1) of this section, every
Commission-approved ISO or RTO must have on file with the Commission a
tariff of general applicability for transmission services, including
ancillary services, over such facilities. Such tariff must be the pro
forma tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036,
as revised by the pro forma tariff contained in Order No. 890, FERC
Stats. & Regs. ] 31,241 and further revised in Order No. 1000, FERC
Stats. & Regs. ] 31,323, or such other open access tariff as may be
approved by the Commission consistent with Order No. 888, FERC Stats. &
Reg. ] 31,036, Order No. 890, FERC Stats. & Regs. ] 31,241, and Order
No. 1000, FERC Stats. & Regs. ] 31,323.
    (i) Subject to paragraph (c)(4)(ii) of this section, a Commission-
approved ISO or RTO must file the revisions to the pro forma tariff
contained in Order No. 890, FERC Stats. & Regs. ] 31,241 as amended by
Order No. 1000, FERC Stats. & Regs. ] 31,323, pursuant to section 206
of the FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Order No. 890, FERC Stats.
& Regs. ] 31,241 and Order No. 1000, FERC Stats. & Regs ] 31,323.
    (ii) If a Commission-approved ISO or RTO can demonstrate that its
existing open access tariff is consistent with or superior to the
revisions to the pro forma tariff contained in Order No. 888, FERC
Stats. & Regs. ] 31,036, as revised by the pro forma tariff in Order
No. 890, FERC Stats. & Regs. ] 31,241 and further revised in Order No.
1000, FERC Stats. & Regs. ] 31,323, or any portions thereof, the
Commission-approved ISO or RTO may instead set forth such demonstration
in its filing pursuant to section 206 in accordance with the procedures
set forth in Order No. 1000, FERC Stats. & Regs ] 31,323.
    (d) * * *
    (1) No later than October 11, 2011, or
* * * * *
    (e) * * *
    (1) A non-public utility may submit a transmission tariff and a
request for declaratory order that its voluntary transmission tariff
meets the requirements of Order No. 888, FERC Stats. & Regs. ] 31,036,
Order No. 890, FERC Stats. & Regs. ] 31,241, and Order No. 1000, FERC
Stats. & Regs. ] 31,323.
* * * * *

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

                              Appendix A--Summary of Compliance Filing Requirements
----------------------------------------------------------------------------------------------------------------
  Deadline (months after the effective
        date of the final rule)                  Compliance action                Section of the final rule
----------------------------------------------------------------------------------------------------------------
12 months..............................  Submit revised Attachment K of     Section III.A.
                                          the pro forma OATT and any other
                                          Commission jurisdictional
                                          documents to include local and
                                          regional transmission planning
                                          processes that are consistent
                                          with the requirements of this
                                          Final Rule.
12 months..............................  Submit revised Attachment K of     Section III.C.
                                          the pro forma OATT and other
                                          Commission jurisdictional
                                          documents to include a cost
                                          allocation method or methods for
                                          regional cost allocation
                                          consistent with principles of
                                          this Final Rule.
18 months..............................  Submit revised Attachment K of     Section IV.C.
                                          the pro forma OATT and any other
                                          Commission jurisdictional
                                          documents to include an
                                          interregional transmission
                                          coordination procedure or
                                          procedures consistent with the
                                          requirements of this Final Rule.
18 months..............................  Submit revised Attachment K of     Section IV.D.
                                          the pro forma OATT and any other
                                          Commission jurisdictional
                                          documents to include a cost
                                          allocation method or methods for
                                          interregional cost allocation
                                          consistent with the principles
                                          of this Final Rule.
----------------------------------------------------------------------------------------------------------------

Appendix B: Abbreviated Names of Commenters

    The following two tables contain the abbreviated names of
initial and reply commenters that are used in this Final Rule.

                           Initial Commenters
------------------------------------------------------------------------
           Abbreviation                     Initial commenter(s)
------------------------------------------------------------------------
26 Public Interest Organizations..  Alliance for Clean Energy New York;
                                     Citizens Utility Board of
                                     Wisconsin; Climate and Energy
                                     Project; Conservation Law
                                     Foundation; Earthjustice;
                                     Environment Northeast;
                                     Environmental Defense Fund;
                                     Environmental Law & Policy Center;
                                     Fresh Energy; Great Plains
                                     Institute; Institute for Market
                                     Transformation; Iowa Environmental
                                     Council; Land Trust Alliance;
                                     National Audubon Society; Natural
                                     Resources Defense Council;
                                     Pennsylvania Land Trust Alliance;
                                     Nevada Wilderness Project; NW
                                     Energy Coalition; Pace Energy and
                                     Climate Center; Piedmont
                                     Environmental Council; Project for
                                     Sustainable FERC Energy Policy;
                                     Sierra Club; Southern Alliance for
                                     Clean Energy; The Wilderness
                                     Society; Union of Concerned
                                     Scientists; and Western Grid Group.
Ad Hoc Coalition of Southeastern    Central Electric Power Cooperative,
 Utilities.                          Inc.; Dalton Utilities; Georgia
                                     Transmission Corporation; JEA; MEAG
                                     Power; Orlando Utilities
                                     Commission; Progress Energy Service
                                     Company, LLC (on behalf of Progress
                                     Energy Carolinas, Inc. and Progress
                                     Energy Florida, Inc.); South
                                     Carolina Electric & Gas Company;
                                     South Carolina Public Service
                                     Authority (Santee Cooper); and
                                     Southern Company Services, Inc. (on
                                     behalf of Alabama Power Company,
                                     Georgia Power Company, Gulf Power
                                     Company, Mississippi Power Company,
                                     and Southern Power Company).
AEP...............................  American Electric Power Service
                                     Corporation.
Alabama PSC.......................  Alabama Public Service Commission.
Allegheny Energy Companies........  Monongahela Power Company; The
                                     Potomac Edison Company; West Penn
                                     Power Company; Trans-Allegheny
                                     Interstate Line Company; and
                                     Allegheny Energy Supply Company,
                                     LLC.
ALLETE............................  ALLETE, Inc.
Alliant Energy....................  Alliant Energy Corporate Services,
                                     Inc.
American Antitrust Institute......  American Antitrust Institute.
American Forest & Paper...........  American Forest & Paper Association.
American Transmission.............  American Transmission Company LLC.
Anbaric and PowerBridge...........  Anbaric Holding, LLC; PowerBridge,
                                     LLC.
APPA..............................  American Public Power Association.
Arizona Corporation Commission....  Arizona Corporation Commission.
Arizona Public Service Company....  Arizona Public Service Company.
Atlantic Grid.....................  Atlantic Grid Development, LLC on
                                     behalf of Atlantic Wind Connection.
Avista and Puget Sound............  Avista Corporation and Puget Sound
                                     Energy, Inc.
AWEA..............................  American Wind Energy Association;
                                     Wind on the Wires; Renewable
                                     Northwest Project; Mid-Atlantic
                                     Renewable Energy Coalition;
                                     Alliance for Clean Energy, Inc.;
                                     Interwest Energy Alliance; RENEW;
                                     the Wind Coalition; and Center for
                                     Energy Efficiency and Renewable
                                     Technologies.
Baltimore Gas & Electric..........  Baltimore Gas & Electric Company.
Bay Area Municipal Transmission     City of Santa Clara, California; the
 Group.                              City of Palo Alto, California; and
                                     the City of Alameda, California.
Bonneville Power..................  Bonneville Power Administration.
Boundless Energy and Sea Breeze...  Boundless Energy, LLC and Sea Breeze
                                     Pacific Regional Transmission
                                     System.
Brattle Group (The)...............  Peter Fox-Penner; Johannes
                                     Pfeifenberger; and Delphine Hou.
California Commissions............  California Public Utilities
                                     Commission and the Energy Resources
                                     Conservation and Development
                                     Commission of the State of
                                     California.
California ISO....................  California Independent System
                                     Operator Corporation.

California Municipal Utilities....  California Municipal Utilities
                                     Association (Cities of Alameda;
                                     Anaheim; Azusa; Banning; Burbank;
                                     Cerritos; Colton; Corona; Glendale;
                                     Gridley; Healdsburg; Hercules;
                                     Lodi; Lompoc; Moreno Valley;
                                     Needles; Palo Alto; Pasadena;
                                     Pittsburg; Rancho Cucamonga;
                                     Redding; Riverside; Roseville;
                                     Santa Clara; Shasta Lake; Ukiah;
                                     and Vernon; the Imperial; Merced;
                                     Modesto; Turlock Irrigation
                                     Districts; the Northern California
                                     Power Agency; Southern California
                                     Public Power Authority;
                                     Transmission Agency of Northern
                                     California; Lassen Municipal
                                     Utility District; Power and Water
                                     Resources Pooling Authority;
                                     Sacramento Municipal Utility
                                     District; the Trinity and Truckee
                                     Donner Public Utility Districts;
                                     the Metropolitan Water District of
                                     Southern California; and the City
                                     and County of San Francisco, and
                                     Hetch-Hetchy).
California Transmission Planning    Sacramento Municipal Utility
 Group.                              District; the Imperial Irrigation
                                     District; the Los Angeles
                                     Department of Water and Power; the
                                     Southern California Public Power
                                     Authority; the Transmission Agency
                                     of Northern California; the Turlock
                                     Irrigation District; the Southern
                                     California Edison Company; the
                                     Pacific Gas & Electric Company and
                                     the San Diego Gas & Electric
                                     Company.
California State Water Project....  California Department of Water
                                     Resources State Water Project.
CapX2020 Utilities................  Central Minnesota Municipal Power
                                     Agency; Dairyland Power
                                     Cooperative; Great River Energy;
                                     Minnesota Power; Minnkota Power
                                     Cooperative; Missouri River Energy
                                     Services; Otter Tail Power Company;
                                     Rochester Public Utilities;
                                     Southern Minnesota Municipal Power
                                     Agency; WPPI Energy; and Xcel
                                     Energy Inc.
Champlain Hudson..................  Champlain Hudson Power Express, Inc.
City and County of San Francisco..  City and County of San Francisco.
City of Los Angeles Department of   City of Los Angeles Department of
 Water and Power.                    Water and Power.
City of Santa Clara...............  City of Santa Clara, California.
Clean Energy Group................  Clean Energy Group.