Although they see limited immediate applicability of PBR, both Progress
Energy and Southern Company recommend specific types of PBR--Progress
Energy favors loop flow pricing, and Southern Company favors revenue or
rate caps that would reward utilities for increasing throughput. In
contrast, National Grid emphasizes that it has had success with PBR
mechanisms different from those mentioned in the NOPR outside the U.S.
However, until the U.S. industry is more independent and there is
greater consolidation of ownership and operation, it does not believe
that PBR is an immediate attractive option.
    269. Connecticut DPUC, along with testimony submitted by two of its
witnesses, Thomas P. Lyon and Pete Landrieu, support the view that PBR
is either inappropriate or unlikely to provide important benefits.
Lyon's affidavit emphasizes that critical principles for PBR include
not only incentives to enhance efficiency and performance, but also
should promote an efficient mix of infrastructure investment. He
cautions against the use of price caps because they may induce firms to
degrade quality, and he would favor some type of profit-sharing plan,
perhaps a PBR that links a firm's financial performance to network
congestion.\164\ Landrieu's affidavit emphasizes that PBR is
unnecessary, because system standards and performance are better
managed directly by various regional reliability organizations. He also
is pessimistic that PBR focused only on transmission will be able to
account for important and complex tradeoffs between generation and
transmission. He agrees with other comments that note that establishing
appropriate benchmarks is an extremely complicated task and for that
reason regards benchmark type PBR as unworkable.\165\
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    \164\ Comments of Connecticut DPUC, Affidavit of Thomas P. Lyon
at 16-19.
    \165\ Comments of Connecticut DPUC, Affidavit of Pete Landrieu
at 27-28.
---------------------------------------------------------------------------

c. Commission Determination
    270. We interpret ``incentive-based (including performance-based)
rate treatments'' in section 219 to require the Commission to consider
PBR as an option among incentive ratemaking treatments. To that end,
the NOPR invited comments on how performance-based regulation might be
used to motivate transmission entities to maintain and operate their
systems reliably and efficiently. Consistent with Congress' directive
to encourage PBR, we signaled our intention to reevaluate previous
Commission policies on PBR. We did not intend that the NOPR be viewed
as a rejection of our previous statements or as a comprehensive
overview of all possible approaches to PBR. Our objective was to
consider whether PBR can play a useful role in transmission pricing
reforms in light of the many changes in electric markets that have
occurred since our earlier statements.
    271. The overwhelming view on PBR from all segments of the industry
is ``not at this time'' and ``not given the current industry
structure.'' Although there is general support for our earlier
principles, we acknowledge, as commenters stress, that our voluntary
program has not resulted in any PBR proposals being filed with the
Commission. The consensus appears to be that the current state of the
industry structure--a multitude of transmission-owning entities, many
that do not directly control their transmission assets and operate in
diverse geographical regions with very different customer densities,
system ages and configurations--makes the determination of generally
applicable performance benchmarks unworkable. Some suggest further
study of PBR, express general support for the concept, and urge the
Commission to remain open to considering voluntary proposals on a case-
by-case basis.
    272. We share the view of most commenters that it would be
premature to adopt generic PBR measures at this time. However, the
development of PBR measures may represent a long-term goal for the
industry and the Commission to pursue. Among the goals of section 219
is to promote capital investment ``in the enlargement, improvement,
maintenance, and operation'' of transmission facilities. Accordingly,
we intend to continue to work with the industry to encourage
development of PBR proposals.
2. Comments Proposing Performance Tests and Competitive Bidding
a. Comments
    273. The New Mexico AG asserts that another way to implement an
incentive-based mechanism is to penalize companies or RTOs that do not
perform adequately and do not make the investments necessary to ensure
the reliability of the transmission grid. The Delaware Commission
contends that providing incentives without assessing penalties for
failure to meet obligations violates the just and reasonable standard
because it rewards monopoly power. Furthermore, the Delaware Commission
claims that the plain meaning of incentive requires both rewards and
penalties. NASUCA states that it is one-sided and inherently unfair to
provide incentives that only increase utility profits with no
performance accountability.
    274. The Delaware Commission recommends that the Commission
implement performance penalties by first defining the utility
obligation, then determining whether there are transmission incentive
projects which the transmission owner has failed to carry out, and in
such situations impose a penalty in the form of a prospective reduction
in return on equity or prudence disallowance that can be lifted when
the project is complete.
    275. TAPS argues that transmission providers should have their
returns reduced to the low end of the zone of reasonableness if they
fail to achieve and maintain a robust transmission infrastructure. TAPS
recommends the Commission consider a number of factors in its
determination of system reliability, including congestion, proration of
financial transmission rights (FTRs), lack of available transfer
capacity (American Transmission), failure to meet customer needs and
denial of reasonable access. TAPS also asserts that the capital
requirements of major projects should be put out to bid if a
vertically-integrated transmission owner is unwilling to permit
transmission dependent utility (TDU) participation but refuses to build
without receiving above-cost rate treatments.
    276. The Missouri Commission proposes that the Commission implement
a process that determines performance-based ROEs. The process,
according to the Missouri Commission, would require transmission owners
to bid out projects, thereby providing an incentive for keeping
implementation

costs as low as possible and minimizing the regulatory concern with
cost overruns. Projects based on actual costs would receive an ROE
below the median of ROEs from the proxy group while projects proposing
fixed costs would receive higher ROEs, explains the Missouri
Commission. The Missouri Commission also recommends that the bids
include an assessment and quantification of specific risks associated
with the project. E.ON U.S. would support a competitive bidding process
for transmission additions required to enhance reliability or to meet
native load requirements.
b. Commission Determination
    277. As discussed in the preceding section, the Commission will
continue to support industry in the development of PBR but will not in
the Final Rule impose it. Accordingly, we will not pursue performance
treatments and competitive bidding. Moreover to the extent these
proposals consist of penalties (which would not provide incentives to
expand transmission infrastructure and would likely limit the
investment in infrastructure by reducing the return--and therefore
funds for capital expansions), they do not implement the requirements
of section 219.
    278. We note that the Commission has other regulations to address
concerns over access and discrimination raised by commenters, including
rules promulgated under Order No. 888, the anti-manipulation provisions
of Order No. 672 \166\ and market behavior rules. We believe those
regulations provide adequate protections. Further, all rates that
include incentives will remain in the zone of reasonableness, and,
therefore, we disagree with the Delaware Commission that rates without
penalties are not just and reasonable.
---------------------------------------------------------------------------

    \166\ Rules Concerning Certification of the Electric Reliability
Organization; and Procedures for the Establishment, Approval, and
Enforcement of Electric Reliability Standards, Order No. 672, 71 FR
8662 (Feb. 17, 2006), FERC Stats. & Regs., ] 31,204 (2006), order on
reh'g, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006), FERC Stats. &
Regs. ] 31,212 (2006).
---------------------------------------------------------------------------

    279. While the requirements of section 219 and the Final Rule do
not encompass bidding processes, as recommended by the Missouri
Commission and TAPS, we are sympathetic to the objective of the
Missouri Commission to reduce the costs of expansions to consumers. We
expect that regional planning processes that evaluate and compare the
costs and benefits of expansion proposals, as well as state commission
reviews and requirement that costs be prudently incurred will serve to
provide the screening function desired by the Missouri Commission, and
therefore additional processes are not necessary. We agree with NASUCA
that there is merit in holding utilities receiving incentives
accountable for investing the capital and building the capacity for
which the incentives are provided, as we discuss further in section
IV.A (Standard for Approval) and section III.D (Effective Date and
Duration Of Effectiveness For Incentives). As we discuss further below
in section IV.H (Public Power), we will not make TDU participation in
the project a precondition for receiving incentives.

E. Advanced Technologies

1. General
a. Background
    280. Pursuant to section 219(b)(3) of the FPA, the NOPR proposed to
encourage the use of advanced technology in new transmission projects.
Advanced transmission technologies are defined in section 1223 of EPAct
2005 to be technologies that increase the capacity, efficiency, or
reliability of an existing or new transmission facility.\167\ The
Commission stated that it expected that the NOPR's proposed incentives,
including the ROE-based incentives, will stimulate investment in new
transmission facilities, which will, in turn, provide opportunities for
the deployment of innovative technologies for those new transmission
facilities.
---------------------------------------------------------------------------

    \167\ Section 1223 identifies 18 such technologies and further
provides that advanced transmission technologies include any other
technologies that the Commission considers appropriate.
---------------------------------------------------------------------------

    281. The NOPR also asked for comments on: (1) Whether the
Commission should require that applications for incentive-based
treatment include a technology statement; (2) whether other incentives
could fulfill the goals of section 219(b)(3); and (3) whether
performance-based benchmarks for transmission costs (i.e., a risk-
sharing approach) would provide incentives for the deployment of
advanced technologies.\168\
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    \168\ NOPR at P 64-66.
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b. Comments
    282. NRECA and others support the incentives proposed in the NOPR
and do not support additional separate incentives for advanced
technology. They believe that technologies will be developed when they
are cost effective.
    283. NEMA believes the technology list from section 1223 of EPAct
2005 should be incorporated into the Final Rule to ensure that the
Commission's regulations express the intent of Congress. But, EEI
argues that a predetermined list of advanced technologies would soon
become outdated, which may discourage the use of other worthwhile
technologies. Bonneville states that the list in the NOPR is incomplete
and includes items that range from measures in common use today to very
speculative items. AEP believes that any list of advanced technology
should be illustrative and non-exclusive.
    284. AEP and others want the Commission to encourage additional
measures related to reliability and infrastructure development,
including control center upgrades, national security-related
infrastructure facilities vital to the electric system and operation,
the refurbishment of aging transmission assets, advanced grid control
technologies for real-time measurement, communications and control,
``non-wires'' alternatives to control or dispatch loads and resources
for optimum use of the transmission and distribution infrastructure,
inventories of transformers and other critical equipment, and
substation upgrades.
    285. Some commenters seek incentives for technologies that could
indirectly mitigate congestion and enhance grid reliability. UTC Power
believes the Commission should provide incentives for distributed
generation, such as fuel cells. Sabey believes that advanced technology
usage on the distribution system may provide transmission congestion
relief. FirstEnergy suggests incentives for pumped storage hydro and
compressed air energy storage.
    286. NSTAR and Vectren urge the Commission to recognize the higher
risk caused by accelerated obsolescence of transmission facilities.
Obsolescence may be the result of the changing transmission technology.
Accelerated depreciation could be relevant to a specific facility that
may have a useful life less than its physical life due to obsolescence.
    287. Some commenters, such as International Transmission, state
that it is imperative that new technology installed on the grid be
reliable and durable for decades. They express concern that new
technologies may carry significant risks and may ultimately not be low
cost and reliable.
c. Commission Determination
    288. We agree with comments that new technologies will be adopted
when they are cost effective. Incentives will be considered for
advanced technologies through the same evaluation process as

other technologies, as discussed in this Final Rule.
    289. We will not provide a unique incentive designed for a specific
technology. To the extent that applicants seek additional incentives
for advanced technologies, the Commission will consider the propriety
of such incentives on a case-by-case basis.
    290. Section 1223 of EPAct 2005 lists 18 advanced transmission
technologies. We interpret this list as being illustrative of the kinds
of technologies that Congress sought to encourage and not exclusive of
advanced technologies that may be employed and considered for incentive
ratemaking treatment. We expect new technologies to continually evolve.
Moreover, as noted above, section 1223 of EPAct 2005 also provides that
advanced transmission technologies include any other advanced
transmission technologies that the Commission considers appropriate.
Thus, we decline to adopt in the regulatory text a specific list of
technologies eligible for incentive ratemaking, and will entertain
proposals for incentives rate treatments for advance technologies on a
case-by-case basis.
    291. This includes technologies that may indirectly mitigate
congestion and enhance grid reliability, if such technologies can be
shown to increase the capacity, efficiency, or reliability of an
existing or new transmission facility.
    292. The Commission does not have sufficient information to make
generic judgments about what barriers exist, if any, to the
introduction of particular technologies based on the record. To the
extent applicants believe additional incentives for advanced
transmission technologies are needed, they must support such requests
in individual cases.
    293. In addition, we note that those applicants that do not want to
use accelerated depreciation for all their facilities may elect to
utilize this incentive for advanced technologies since the useful life
of such technologies may not be sufficiently known. The Commission will
also consider requests to recover the costs of obsolescent plant,
thereby facilitating the addition of new, more technically advanced
transmission infrastructure.
2. Case-by-Case Review
a. Comments
    294. Ameren and others suggest the Commission should determine
whether technology applications are just and reasonable on a case-by
case basis, which would allow applicants flexibility to determine which
technologies are best suited for a particular project.
    295. National Grid believes the Commission should encourage the
development of the best technology for particular needs identified in
transmission owners' planning processes. This avoids putting the
Commission in a position of picking winners and losers, but would allow
transmission owners to make appropriate decisions relative to costs,
benefits and risks associated with advanced technologies.
    296. International Transmission suggests the Commission should
determine what incentives are necessary to overcome barriers to
deployment of the technologies defined in section 1223 of EPAct 2005,
and then authorize those incentives on a case-by-case basis.
    297. As an alternative to the case-by-case consideration of
incentives, AEP recommends establishment of criteria for transmission
investment to receive full incentive treatment. Such criteria might
include: reducing congestion, advancing growth and security of the
interstate grid, and providing an opportunity to site fuel diverse,
newer technology, and environmentally friendly generation.
b. Commission Determination
    298. The Commission will consider incentives for advanced
technologies on a case-by-case basis. As discussed above, we are not
making generic determinations regarding the applicability of incentives
to particular technologies. Consistent with this case-by-case approach,
we will not adopt AEP's suggestion to establish generic criteria for
evaluating which transmission investments will receive full incentives.
As discussed by Ameren and others, case-by-case review also provides
flexibility to transmission providers in identifying the technologies
that are most appropriate for their project applications and business
models. It also avoids putting the Commission in a position of picking
winners and losers, but allows transmission owners to make appropriate
business decisions, as discussed by National Grid. The Commission in
its reviews will provide incentives to technologies that increase the
capacity, efficiency, or reliability of an existing or new transmission
facility.
    299. With regard to International Transmission's concerns, the
Commission is not in a position to make generic judgments about what
barriers exist, if any, to the introduction of particular technologies.
To the extent applicants believe additional incentives for their
advanced technology applications are needed, they can make a case for
advanced technology incentives in their individual proceedings and the
Commission will make a case-by-case determination.
3. Whether To Require A Technology Statement
a. Comments
    300. TAPS and others believe the Commission should not require that
a particular technology or the most advanced technology be used in
order to qualify for incentives. They believe that a technology
statement would add an unnecessary burden to applications and would
likely result in Commission approval of imprudent and routine
transmission investment. They also argue that statements made by an
applicant would tend to be self-serving, and not detailed enough for
proper Commission evaluation. Instead, the Pennsylvania Commission
suggests that the Commission develop in-house technology expertise, or
alternatively establish a peer review board of nationally recognized
independent experts.
    301. UTC Power believes the technology statement should also
include a list of the advanced technologies capable of meeting the
project goals for reducing congestion and increasing reliability, and
reasons they were not employed. Duquesne supports a technology
statement but does not believe that it should have to be specific as to
describe all technologies that were considered and not used.
b. Commission Determination
    302. In as much as EPAct 2005 requires the Commission to encourage
the deployment of transmission technologies, we will require applicants
for incentive rate-treatment to provide a technology statement that
describes what advanced technologies have been considered and, if those
technologies are not to be employed or have not been employed, an
explanation of why they were not deployed.
4. Risk Sharing
a. Comments
    303. CCAS suggests that the Commission offer a framework of cost
sharing among entrepreneurs, ratepayers, utility shareholders and
taxpayers, peer review and competitive solicitation to share and
recover qualified research development and demonstration project costs
through transmission rates. NEMA supports performance-based ratemaking
as a means of enabling advanced technology

implementation for the sharing of benefits and risks between utilities
and customers.
    304. CAISO suggests that the Department of Energy and the
Commission cooperate with the industry and reliability organizations on
programs to identify, test, and disseminate information on new
technology. APPA also suggests a process for the Commission to work
with each region to develop a technology plan and a research and
development budget, with costs to be recovered through regional
transmission rates. Sabey encourages the Commission to provide
incentives for technology demonstrations on small-to-medium scale
projects.
    305. NU and others suggests the Commission consider incentive
ratemaking treatment of research and development dollars spent by
utilities, which benefit the advancement of new technology. The
Kentucky Commission believes in federal funding for research and that
the Department of Energy is an appropriate sponsor for research in new
transmission technology.
    306. EPRI supports efforts to enhance grid infrastructure, and
offers a list of advanced transmission technologies that are near term
or commercially available, those that may be available for
demonstration within four months with commercial availability in three
to five years, and longer-term technologies still in the research and
development stage with possible demonstration in three to five years.
b. Commission Determination
    307. The Department of Energy is a more appropriate federal agency
to promote research and development. Accordingly, research and
development are beyond the scope of this proceeding, and we will not
include incentive ratemaking for research and development costs in the
Final Rule.
5. Other Technology-Related Issues
a. Comments
    308. Semantic states that the Final Rule needs to define
``prudently-incurred'' costs that are to be recoverable and proposes
that ``prudently-incurred'' be defined to include a substitution test
such that expenditures are not made in excess of that which is
required. By way of example, Semantic offer that an open RFP process
for congestion relief should provide for separate pricing for the
avoided cost value of each separable reliability benefit for which the
reliability standards require action. This separate pricing of
strategies for achieving the reliability and congestion goals must be
compared to the summed cost of the advanced technology that can achieve
the goals when determining prudence and just and reasonable rates.
Semantic believes that such an approach results in greater efficiency
in the use of the existing grid and the Final Rule should provide
incentives other than ROE adders to foster such efficiency through the
use of Advanced Transmission Technologies for time of day congested
segments of the grid.
    309. American Superconductor states that the Commission should
revisit and clarify its Seven Factor Test for distinguishing between
transmission and distribution facilities, to reflect technology
advances made since the Commission adopted the Seven Factor Test. For
example, American Superconductor states that it has developed dynamic
VAR technologies that can effectively support transmission grids while
connected to distribution facilities. Classification of such advanced
technologies as transmission facilities would make them eligible for
recovery under Commission-jurisdictional tariffs.
b. Commission Determination
    310. We deny Semantic's request to define ``prudently-incurred'' as
requiring an open RFP process to consider alternative technologies and
to provide additional incentives to address time of day congestion. As
previously stated, we expect that new development programs will
include, or at least consider, advanced technologies, but we will not
mandate it. We agree that improvements in the operation of the grid,
perhaps through advanced technologies addressing time of day
congestion, could result in efficiency benefits and encourage such
proposals on a case-by-case basis.
    311. We also deny American Superconductor's request to revisit our
Seven Factor Test because it is beyond the scope of this
proceeding.\169\
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    \169\ We note that if these technologies truly perform a
transmission function, a more productive approach than modifying the
Seven Factor Test may be to propose modification of the Uniform
System of Accounts to reflect such plant in a new transmission-
related plant account. But that is beyond the scope of this
proceeding.
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F. Transmission Organization Incentive

1. Background
    312. The NOPR (at P 45) proposed that the Commission will continue
to consider requests for ROE-based incentives for utilities that join
an RTO, in recognition of the benefits such organizations bring to
customers, as outlined in detail in Order No. 2000. In addition, it
proposed that the Commission will consider similar requests by
utilities that join an ISO for an incentive ROE that, while still in
the zone of reasonableness, is higher than the ROE the Commission might
otherwise allow if the utility did not join.
    313. The NOPR (at P 46) also sought comment on whether the
Commission should consider incentive-based ROE requests for public
utilities that are not in an RTO but that join a Commission-approved
regional planning organization.
2. Comments
    314. Comments span a wide range of views on proposed incentive for
utilities that join an RTO. Several commenters \170\ support the
proposal to continue to consider requests for ROE-based incentives for
utilities that join a Transmission Organization. Most of these
commenters also request that the incentive apply equally to both new
members and existing members. They contend that denying an incentive to
existing Transmission Organization members while awarding it to new
members who join these organizations unfairly discriminates against
those entities that should be rewarded for taking the initial step of
establishing and joining an independent Transmission Organization and
would therefore be contrary to good public policy, unjust,
unreasonable, and unduly discriminatory. In addition, this
discrimination could create an incentive for a transmission owner to
depart from an existing RTO and to join a new RTO, simply to obtain the
NOPR incentives ``for public utilities that join a Transmission
Organization.'' PEPCO states that an adder should apply generally to
all facilities for utilities in the RTO, not just to new investment
after a new company joins an RTO.
---------------------------------------------------------------------------

    \170\ E.g., Ameren, EEI, Electric Power Supply, FirstEnergy,
KCPL, MidAmerican, National Grid, NYSEG, NorthWestern, New England
TOs, NSTAR, PEPCO, PacifiCorp, PG&E, PJM, PJM TOs, TransCanada,
Trans-Elect, Vectren, and WPS.
---------------------------------------------------------------------------

    315. Other commenters \171\ contend that, if the Commission does
allow an incentive for joining a Transmission Organization, the
incentive should only apply going forward for new members, not for
those who already joined. They argue that incentives should incite or
spur a desired future action, and thus it makes no sense to provide
incentives to transmission owners for past behavior or for actions that
are likely to occur

under other normal business circumstances. Incentives for existing
members would represent an unjustified windfall for utilities, at the
expense of the transmission customers. In addition, the FPA does not
permit the Commission to reward a utility ``in recognition'' of
benefits for actions already taken by the utilities.
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    \171\ E.g., Connecticut DPUC, Dairyland, Delaware Commission,
NRECA, NECOE, NECPUC, New York Commission, SMUD, TANC, MISO States
and TDU Systems.
---------------------------------------------------------------------------

    316. Some of these commenters also assert that the incentive should
not apply where a transmission owner is ordered to join a RTO/ISO by
statute or has agreed to join an RTO/ISO as a condition of receiving
approval for a merger, market-based rates, or because of other
regulatory actions. Also, possible incentives for joining an RTO, and
the procedures for requesting such incentives, are already addressed in
Order No. 2000.
    317. Certain commenters \172\ contend that the Commission should
consider giving ROE incentives only to companies joining a newly
forming Transmission Organization, rather than existing ones, and then
only for a limited period of time; and if a public utility withdraws
from an RTO or ISO for which it obtained an ROE adder for joining, the
Commission should issue an order immediately eliminating such ROE
adders.
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    \172\ E.g., MISO States, NRECA, and TDU Systems.
---------------------------------------------------------------------------

    318. Others request that the Commission make a generic finding that
entities that join an ISO or RTO automatically qualify for the
incentive. For example, Trans-Elect submits that the Commission can and
should use the record developed in this proceeding to find, on a
generic basis, that RTO/ISO membership produces sufficient customer
benefits to qualify for the 50 basis-point ROE adder.
    319. Some commenters \173\ state that this incentive should not be
limited to public utilities. It should apply to all transmitting
utilities and electric utilities, including municipal utilities.
Another view, that of Northwestern's, would have the Commission
consider granting such incentives to transmission owners that are
actively engaged in the development of an RTO or ISO, and permit
transmission owners to recover prudently incurred costs of developing
an RTO or ISO as they are incurred, in regions that do not currently
have such an independent entity. American Wind strongly supports the
objective to regionalize the grid, but believes that it would not serve
the Commission's or Congress' goal to allow incentives to any type of
Transmission Organization that is approved by the Commission for the
operation of facilities. For example, American Wind states that single-
system Transcos do nothing for regional goals.
---------------------------------------------------------------------------

    \173\ E.g., CAISO, APPA, and NRECA.
---------------------------------------------------------------------------

    320. Some commenters raise issues concerning the definition of a
Transmission Organization. For example, Bonneville and PNM believe that
incentives should be available to utilities that enter agreements or
form transmission associations outside the specific models of RTOs or
ISOs. MISO States contend that the Commission should not grant ROE
incentives to utilities joining Transmission Organizations until these
entities are more clearly defined. MISO States assert that the
Commission currently has inadequately specified standards and
requirements for ``independent transmission providers'' and no
established standards or requirements for ``other transmission
organizations.''
    321. Some commenters seek some type of conditions/criteria for
receiving the Transmission Organization incentive, including: Ongoing
participation in an ISO that provides open access on the basis of
competitive bids and that allocates the costs of grid access to users
based on LMP; participation in the relevant ISO or RTO planning process
such that the ISO or RTO will make a determination of need; or tying
the incentives to whether the Transmission Organization has an
effective regional planning process that results in the construction,
not merely the identification, of transmission. Others suggest tying
the level of the incentive to meeting certain criteria, including: A
single sliding scale ROE adder mechanism which is tied to levels of
independence; or a graduated incentive tied to important features of
the Transmission Organization like degree of independence, range of
functions, transparency of operations, openness of stakeholder forums,
and geographic scope of the transmission planning area.\174\
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    \174\ E.g., SDG&E, CAISO, International Transmission, National
Grid, and MISO States.
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    322. Some commenters state that there should be penalties
associated with a lack of participation in Transmission
Organizations.\175\ For example, they contend that: The ROE should be
reflecting that service not provided by an ISO or RTO is less optimal;
there should be a negative 50 basis point penalty on those public
utilities that seek to withdraw from RTOs within the first 5 to 10
years of participation to recognize the costs paid by consumers to fund
the public utility's participation; and there should be penalties for
incumbent transmission owners that continue to frustrate RTO formation.
---------------------------------------------------------------------------

    \175\ E.g., California Oversight Board, TDU Systems, and
TransCanada.
---------------------------------------------------------------------------

    323. Some commenters oppose ROE-based incentives for joining an RTO
or ISO.\176\ Among other reasons, they state that: It has not been
determined whether the benefits of participation in RTOs outweigh the
costs, and, therefore, there is no justification for an incentive to
encourage participation in RTOs; that the incentive is unwarranted
because RTOs and similar organizations have a poor track record for
getting new transmission built; that return incentives for RTO
participation raise the already heavy RTO cost burden and add fuel to
the concerns of state commissions and customers about RTO costs, thus
undermining RTOs; that the risk of joining an RTO/ISO will already be
reflected in the utility's return allowance; that joining an RTO/ISO is
already lucrative, a fact that can be illustrated by the sound business
conditions of the existing transmission owners' businesses in an RTO/
ISO area in which transmission businesses will have guaranteed returns
as a monopoly business; and that the incentive is not tied to actual
new investments, and allowing an increased ROE on all transmission
investment (including existing facilities) would merely drive up
transmission rates.
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    \176\ E.g., APPA, NRECA, and TDU Systems.
---------------------------------------------------------------------------

    324. According to PPC, EPAct 2005 is conspicuously silent regarding
whether Transmission Organizations are desirable, and section 219(c)
cannot fairly be read to authorize the Commission to provide incentives
to the utilities that join such organizations that are greater than
those incentives that are available to other, non-member utilities.
    325. Several commenters support incentives for participation in a
regional planning process that is not necessarily an RTO.\177\ For
example, PJM supports incentives for transmission owners' participation
in robust regional transmission planning processes as an effective,
collaborative and transparent means to ensure the development of
economically efficient transmission projects that truly benefit
customers. MidAmerican states that a strict requirement for public
utility participation in an RTO or ISO could discourage certain
transmission owners, particularly nonjurisdictional transmission
owners, from regional participation under any structure. Bonneville
states that modest financial incentives linked to construction of new
facilities advocated by an independent

regional planning process may be sensible, but incentives must be tied
to implementation of the regional plan, not just for mere participation
in the organization.
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    \177\ E.g., Ameren, Southern Companies, SCE, PJM, and
MidAmerican.
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3. Commission Determination
    326. To the extent within our jurisdiction, we will approve, when
justified, requests for ROE-based incentives for public utilities that
join and/or continue to be a member of an ISO, RTO, or other
Commission-approved Transmission Organization. However, we are not
persuaded that we should create a generic adder for such membership,
but instead will consider the appropriate ROE incentive when public
utilities request this incentive. The decision in this rule to consider
specific incentives on a case-by-case basis fulfills the Congressional
mandate to the Commission.\178\ Thus, issues concerning risk such as
those raised by SMUD are more appropriately addressed in the
proceedings that evaluate proxy companies and set a zone of
reasonableness.
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    \178\ We believe that the Commission's accounting and reporting
procedures for RTOs, as required by Order No. 668, address
commenters' concerns about the management of RTO costs. See
Accounting and Financial Reporting for Public Utilities Including
RTOs, Order No. 668, FERC Stats. & Regs. ] 31,199 (2005).
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    327. We will not make a generic finding on the duration of
incentives that will be permitted for public utilities that join
Transmission Organizations. An entity will be presumed to be eligible
for the incentive if it can demonstrate that it has joined an RTO, ISO,
or other Commission-approved Transmission Organization, and that its
membership is ongoing. Any public utility receiving an incentive ROE
for joining a Transmission Organization but that withdraws from such
organization is no longer eligible for the ROE incentive.
    328. We will not broaden or restrict the definition of Transmission
Organization. For purposes of this Final Rule, and as defined in
section 3(29) of the FPA, a Transmission Organization means a Regional
Transmission Organization, Independent System Operator, independent
transmission provider, or other transmission organization finally
approved by the Commission for the operation of transmission
facilities. We note that all RTOs and ISOs are already covered by this
definition, and we will consider, on a case-by-case basis, applications
for other types of entities to be classified as Transmission
Organizations for purposes of whether membership warrants incentives
under these provisions.
    329. With respect to NorthWestern's argument that the Commission
should consider incentives for the development of a Transmission
Organization and permit recovery of prudently incurred costs of such
development as they are incurred, the Commission will review
applications for incentives in the context of filings for the creation
of Transmission Organizations and determine the appropriate methods for
recovery of costs on a case-by-case basis. With respect to comments
suggesting specific criteria to qualify for the incentive (e.g.,
participation in a planning process) or that the level of the incentive
be tied to meeting certain criteria, we will not specify such criteria
in this Final Rule.
    330. Several comments urge that eligibility for these incentives
not be limited to public utilities. However, the fact is that section
219(a) directs that this rulemaking provide incentives for ``public
utilities'' and public utilities are the only entities whose rates are
jurisdictional under sections 205 and 206 of the FPA. Further, although
section 219(c) refers to incentives for ``transmitting utilities'' and
``electric utilities'' that join Transmission Organizations, it also
contains the provision ``to the extent within its jurisdiction.''
Accordingly, the rule will apply to jurisdictional public
utilities.\179\ We clarify that this does not mean that public
utilities are precluded from proposing incentive plans under section
205 whereby incentives would be given to public utilities as well as
nonpublic utilities. Indeed, we encourage such plans. However, we would
generally not have authority under sections 205 and 206 to enforce such
incentives for the nonpublic utilities.
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    \179\ We note that new section 211A gives the Commission
authority to order transmission services by otherwise
nonjurisdictional transmitting utilities. The Commission has never
exercised authority under the new provision and the new provision
provides limited rate authority. However, we leave open the
possibility that incentives for otherwise nonjurisdictional
transmitting utilities could be permitted in an order under section
211A.
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    331. We also clarify that, as explained earlier, entities that have
already joined, and that remain members of, an RTO, ISO, or other
Commission-approved Transmission Organization, are eligible to receive
this incentive. The basis for the incentive is a recognition of the
benefits that flow from membership in such organizations and the fact
continuing membership is generally voluntary.\180\ Our interpretation
of the statute is that eligibility for this incentive flows to an
entity that ``joins'' a Transmission Organization and is not tied to
when the entity joined. As some commenters note, to do otherwise could
create perverse incentives for an entity to actually leave Transmission
Organizations and then join another one. It would also be unduly
discriminatory for the Commission to consider the benefits of
membership in determining the appropriate ROE for new members but not
for similarly situated entities that are already members.
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    \180\ Our clarification also applies to utilities that joined
RTOs or ISOs because of merger conditions or market-based rate
requirements.
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    332. We will not at this time establish a specific incentive for
joining a Commission-approved regional planning organization. A
regional planning process is very important to meeting regional
transmission needs, and, we believe it will produce benefits for
customers. For this reason, we have initiated a proposed rulemaking to
require transmission providers to coordinate with interconnected
systems when planning transmission system additions.\181\ This
increased coordination in regional planning proposed in the OATT Reform
NOPR would be mandatory, not optional, and therefore we will not offer
at this time an incentive for such coordination. However, if a region
develops a planning processes that is superior to that required by the
OATT reform rulemaking (such as by using an independent entity to
perform system planning), nothing in this final rule would preclude
entities in the region from requesting appropriate incentives under FPA
section 219.
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    \181\  See OATT Reform NOPR at 214.
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    333. As stated earlier in this Final Rule, we will not adopt
performance-based ROEs that reduce ROEs for transmitting utilities that
do not join Transmission Organizations, as recommended by several
commenters. The purpose of this rule is to provide incentives, per the
requirements of section 219.

G. Recovery of Prudently Incurred Costs To Comply With Reliability
Standards and Recovery of Prudently Incurred Costs Associated With
Transmission Infrastructure Development

1. Background
a. Prudently Incurred Costs To Meet Mandatory Reliability Standards
    334. Under FPA section 215 (Electric Reliability), an Electric
Reliability

Organization may propose, and the Commission may approve by rule or
order, reliability standards.\182\ Pursuant to section 219(b)(4)(A) of
the FPA, the NOPR (at P 47) proposed to allow recovery of all prudently
incurred costs necessary to comply with these mandatory reliability
standards. Proposed new Sec.  35.35(f) would allow for such recovery.
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    \182\ An Electric Reliability Organization is the organization
certified by the Commission to establish and enforce reliability
standards for the bulk power system, subject to Commission review.
See Order Nos. 672 and 672-A.
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b. Prudently Incurred Costs Associated With Transmission Infrastructure
Development
    335. Under FPA section 216 (siting of interstate electric
transmission facilities), the Commission has certain backstop siting
authority for transmission facilities when the Secretary of Energy
designates a geographic area experiencing electric transmission
capacity constraints or congestion that adversely affects consumers as
a National Interest Electric Transmission Corridor. Pursuant to section
219(b)(4)(B) of the FPA, the NOPR (at P 48) proposed to allow recovery
of all prudently incurred costs related to infrastructure development
pursuant to section 216. Proposed new Sec.  35.35(g) would allow for
recovery of such prudently incurred costs.
2. Comments
    336. Several commenters raise issues applicable to both the
mandatory reliability standard-related incentive and the infrastructure
development-related incentive. For example, PJM TOs argue that the
Commission should require that recovery of such prudently incurred
costs be through stand-alone section 205 filings.
    337. FirstEnergy and National Grid seek clarification that the NOPR
is not revising existing policy on the recovery of prudently incurred
costs and that there continues to be a presumption that investment is
prudently made, with the burden of the challenging party to prove
otherwise.
    338. NRECA requests guidance from the Commission on what it
considers to be prudently incurred costs. NRECA suggests the addition
of a test to determine if the costs to comply with mandatory
reliability standards and infrastructure development are just,
reasonable and not unduly discriminatory, and that the Commission
require participation in a regional planning process, with LSE
participation.
    339. Some commenters proffer specific examples they believe should
be considered as prudently incurred reliability or infrastructure
development costs. For example, AEP recommends the cost of control
centers and national security infrastructure, and Semantic recommends
substation tests as reliability costs.
    340. East Texas and others caution the Commission to approve only
the costs that are necessary to comply with mandatory reliability
standards and for transmission infrastructure development. They express
concern about the potential for rising costs to customers that may
result from additional transmission investment.
    341. APPA and others raise issues specific to recovery of prudently
incurred costs to comply with mandatory reliability standards. APPA and
other commenters agree that it is appropriate for the Commission to
allow recovery of all prudently incurred costs to comply with mandatory
reliability standards, and recommend the Commission clarify standards
for determining that such costs are prudently incurred. TDU Systems
suggest the Commission approve only prudently incurred costs to comply
with mandatory reliability standards that are approved by a regional
entity and in the context of a full FPA section 205 rate hearing or
under a formula rate.
    342. East Texas raises an issue specific to recovery of prudently
incurred costs associated with infrastructure development. It requests
that the Commission make explicit provisions in its transmission
incentives rules for any actions that it may undertake under the new
siting authority provided to it under section 216.
3. Commission Determination
    343. The Commission will allow recovery of all prudently incurred
costs necessary to comply with the mandatory reliability standards
under section 215 and all prudently incurred costs associated with
infrastructure development under section 216. In response to
commenters, we further clarify that the Commission will review
applications for the recovery of such prudently incurred costs under
its section 205 procedures.
    344. Some confusion may have been caused because the NOPR is more
broadly related to transmission pricing reform and expresses the
Commission's willingness to consider a variety of transmission pricing
``incentives'' to encourage the construction of new transmission. In
many instances new investment in transmission may both improve
reliability and reduce congestion. However, the NOPR specifically
referred to recovery of ``prudently incurred costs'' in the context of
the section 215 and 216-related expenses and investment. We take this
opportunity to clarify that we are simply codifying our long standing
regulatory policy that allows utilities the opportunity to recover all
prudently incurred costs associated with the provision of transmission
service in interstate commerce.
    345. We deny NRECA's request that the Commission require
participation in a regional planning process as part of the prudence
review. As we have stated earlier in this rule, we will not make
regional planning a precondition of receiving incentive ratemaking
treatment. However, we expect and encourage participation in regional
planning processes for all major transmission additions, including
those within a designated national interest corridor.
    346. In regard to commenters' specific examples of what they
believe should be considered as prudently-incurred reliability or
infrastructure development costs, we find it premature to develop such
a list of pre-approved costs without proper consideration of the
equipment involved and its application to the transmission system. This
type of case-specific justification would be required from the
applicant in its section 205 filing.
    347. Similarly, we deny APPA's request to establish standards for
determining that reliability standards compliance costs are prudently
incurred. The Commission is making no change in the long-standing
regulatory presumption in a section 205 proceeding that costs are
prudently incurred, but parties are free to provide evidence to the
contrary; and, ultimately, the burden is on the applicant to
demonstrate that its proposal is just and reasonable.
    348. We deny the request of East Texas that the Final Rule include
explicit provisions for any actions the Commission may take with
respect to the Commission's backstop siting authority under FPA section
216. This is beyond the scope of this rulemaking, which addresses only
the recovery of prudently-incurred costs related to transmission
infrastructure development pursuant to FPA section 216, not the
Commission's backstop siting authority under that section. This issue
is best addressed in the National Interest Electric Transmission
Corridors proceeding in Docket No. RM06-12-000.

H. Public Power

1. Background
    349. Given the importance of public power participation and the
requirements of section 219, the NOPR (at P 63) requested comments on
what actions the Commission should take in this rulemaking to encourage
public power participation in new transmission projects. The NOPR
asked, for example, whether the consortium approach would help to
promote expansion of the transmission grid, and, if so, what types of
incentives the Commission could provide to encourage such consortia.
2. Comments
    350. Commenters express diverse views. Several commenters \183\
express support for the consortium approach. For example, Connecticut
DPUC states that the approach has appeal especially for very large
transmission projects involving multiple states and that where there is
agreement on the project, a sharing of the benefit incentives might be
applicable. Similarly, Ameren and PJM state that public power
involvement can be valuable and that the Consortium should receive the
same incentives available to public utilities developing such projects.
PJM supports a case-by-case approach for incentive rate treatment for
these types of projects. EEI and MidAmerican offer that regardless of
whether public power is involved, any member of the consortium should
receive the same incentives that public utilities receive for building
new projects. Upper Great Plains states that incentives should be
available to all forms of joint projects, not just those arising from
an RTO-led consortium.
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    \183\ E.g., Connecticut DPUC, PJM, Municipal Commenters,
Semantic, Progress Energy, and Ameren Services.
---------------------------------------------------------------------------

    351. Certain commenters \184\ state that public power participation
should not be mandated. New England TOs warn that requiring that
utilities offer participation in transmission projects to certain pre-
specified parties will be counter-productive. New England TOs state
that there are other entities (e.g., private equity, merchant
transmission) who might have an interest in investing in a particular
project and that the Commission has no basis for discriminating in
favor of public power by giving it special investment rights and that
doing so will create controversy.
---------------------------------------------------------------------------

    \184\ E.g., KCPL, National Grid, International Transmission, New
England TOs, NU, NYSEG, and SMUD.
---------------------------------------------------------------------------

    352. Some of these same commenters that support the consortia \185\
also support the Commission offering to public power entities the same
incentives it is offering to jurisdictional public utilities, including
Transcos. For example, AMP-Ohio states that the Commission should
encourage arrangements that allow public power entities to obtain
direct ownership. Wyoming Infrastructure Authority states that public
power participation has demonstrably aided grid expansion projects to
increase reliability and efficiency of the transmission grid.
---------------------------------------------------------------------------

    \185\ E.g., AMP-Ohio, Ameren, CAISO, Municipal Commenters,
Nevada Companies, Upper Great Plains, Powder River, Wyoming
Infrastructure Authority and Snohomish.
---------------------------------------------------------------------------

    353. Others propose limitations, including limiting incentives to
those applicants offering third-party participation in projects.\186\
Citizens Energy, for example, states that the Commission should require
Transmission Organizations to adopt rules which ensure non-
discrimination against merchant transmission. TransCanada proposes a
specific process for merchant transmission. FirstEnergy states that
public power participation should be permitted only when such entities
have an OATT on file with the Commission. Still other commenters \187\
state public power already enjoys various benefits over investor-owned
utilities (e.g., access to low-cost borrowing funds, ability to set own
rates, tax advantages) and that the Commission should not further the
rate advantages.
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    \186\ E.g., TAPS, TANC, NECOE, Citizens Energy, TDU Systems, and
Municipal Commenters..
    \187\ E.g., KCPL and EEI.
---------------------------------------------------------------------------

3. Commission Determination
    354. We agree with comments that public power participation can
play an important role in the expansion of the transmission system. We
want to encourage public power participation in new transmission
projects, but the ratemaking incentives we discuss in the Final Rule
are generally not directly available to non-jurisdictional entities
such as most public power entities, because they do not file their
rates with the Commission. However, to the extent our jurisdiction
allows, the Commission will entertain appropriate requests for
incentive ratemaking for investment in new transmission projects when
public power participates with jurisdictional entities as part of a
proposal for incentives for a particular joint project.\188\
Encouraging public power participation in such projects is consistent
with the goals of section 219 by encouraging a deep pool of
participants.
    355. We will not specify which incentives might be most appropriate
for encouraging participation by public power entities but instead will
allow the applicants to make proposals that best suit their
circumstances. We also clarify that the Commission's approval of an
incentive plan proposed by a public utility that also pertains to an
entity that is not otherwise jurisdictional under sections 205 and 206
(e.g., public power), does not affect the non-jurisdictional status of
the entity.
---------------------------------------------------------------------------

    \188\ This is not to say that the Commission would not consider
incentive ratemaking treatment for a consortium project that did not
include public power participation. Nothing in this rule prevents
jurisdictional entities from combining their resources on a project.
---------------------------------------------------------------------------

    356. We will not, however, require public power or other joint
participation in a transmission project in order for investment in a
project to be eligible for incentives. While participation by a diverse
group of investors might be the best structure for an individual
project, it is inappropriate to mandate a particular joint-structure be
used in all cases. However, we clarify that, to the extent allowed
under our jurisdiction, a public power entity should have the same
opportunity afforded to jurisdictional entities to recover costs
related to new transmission investment.
    357. We believe a consortium approach that includes public power
and other entities for new investment has value and we encourage
participation by public power in meeting the transmission
infrastructure provisions of section 219. However, we will not require
a consortium approach. We believe it is more appropriate for applicants
to fashion proposals for new transmission infrastructure projects that
are tailored to the specific circumstances and needs of a particular
project. In addition, we believe a consortium-led proposal that is the
result of an open, collaborative, regional process and that includes a
diverse group of participants may face less resistance from parties
when a filing is made here, because competing interests will have
already been addressed before the proposal is filed with the
Commission.

V. Reporting Requirement

A. Background

    358. Section 35.35(h) of the proposed rule would require
jurisdictional public utilities to report annually to the Commission no
later than April 18, 2007, and, in succeeding years, on the date on
which FERC Form No. 1 information is due the following data

and projections: (subsection i) in dollar terms, actual investment for
the most recent calendar year, and planned investments for the next
five years; and (subsection ii) for all current and planned investments
over the next five years, a project by project listing that specifies
for each project the expected completion date, percentage completion as
of the date of filing and reasons for delay. A draft Form X was
provided in the Appendix.
    359. In the NOPR (at P 49), the Commission stated that the purpose
of the reporting requirement is to determine the effectiveness of the
proposed rules and to provide the Commission with an accurate
assessment of the state of the industry with respect to transmission
investment.

B. Comments

    360. A number of commenters \189\ support the proposed Form X
reporting requirement. For example, International Transmission states
that such reports are important to determine if the investment
incentives adopted by the Commission are actually working to elicit
investment in transmission that benefits consumers. Some of these
commenters make a number of recommendations, including the following:
Define transmission investment for reporting; include separate
categories for new generation interconnection versus other types of
system upgrades; classify investments by voltage level to distinguish
facilities that have little or nothing to do with the interstate
transmission grid; exclude small, miscellaneous upgrades; provide
instructions that Transmission Facilities in the table ``Capital
Spending On Electric Transmission Facilities'' are defined as
transmission assets under the Uniform System of Accounts in accounts
350 through 359; like the report with FERC Form No. 1; provide a list
of categories for the ``Reasons for Delay'' column, such as siting,
delayed completion of a new generator; report the consumer benefits of
the project (e.g., congestion relief, enhanced reliability); require
the posting of the information on RTO, ISO, Transco or public utility
Web sites or OASIS; require that all the reports be aggregated in one
report that is made public, thereby providing manufacturers with a
better basis to plan for industry needs.
---------------------------------------------------------------------------

    \189\ E.g., International Transmission, NRECA, APPA, National
Grid, AEP and TAPS, Siemans, and NEMA.
---------------------------------------------------------------------------

    361. Commenters also contend that the report does not go far
enough. \190\ Some \191\ state that such reports should extend to all
transmission providers, including those subject to new section 211A of
the FPA and government-owned entities. Semantic asserts that the
reporting requirements proposal is incomplete and does not adequately
secure the comprehensive state of the grid information required by the
regulators and market participants. Semantics would require that power
systems state data must be made available in real-time to identify
parallel flows and to avoid under-investment, over-investment or bad
investments; that the report should provide for the filing of data that
enables the Commission to fulfill its oversight responsibility for RTOs
under Sec.  35.34(k)(4) and to promote compliance with Sec.
35.34(k)(1). Semantics further recommends that time of day rate
schedules should be reported into a web-accessible national repository.
Semantic explains that capital investment in advanced technologies will
relieve congestion if this information is made known to technology
vendors and entrepreneurial entities.
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    \190\ E.g., International Transmission, Northwestern, Siemans,
NEMA, and Semantic.
    \191\ E.g., International Transmission, EEI, Northwestern, and
KCP&L.
---------------------------------------------------------------------------

    362. Certain commenters \192\ that support the reporting also
express concerns. For example, National Grid states the Commission
should clarify that the forward-looking projections in Form X, rendered
in good faith and upon a reasonable basis, would not subject the
reporting transmission owners to claims of fraud, detrimental reliance
or other liabilities arising from the fact that actual capital spending
may vary from reported projections.\193\ Ameren requests that the
Commission clarify that the reported information is to be provided for
informational purposes only and should not be allowed to form the basis
of a review by the Commission or other entities regarding the
reasonableness or prudence of the amounts reported. PG&E and the Nevada
Companies assert that a disclaimer should be added to footnote 1
explaining that much of the information reported here may change over
time and may be subject to correction. Trans-Elect asserts that the
reporting requirement, alone, should not be allowed to form a basis for
a section 206 investigation.
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    \192\ E.g., National Grid, Ameren, PG&E, and Nevada Companies.
    \193\ See Section 27A of the Securities Act of 1933, as amended;
Section 21E of the Securities Exchange Act of 1934, as amended; 15
U.S.C. 77z-2 and 78u-5; 17 CFR 240.3b-6.
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    363. Some commenters raise confidentiality concerns.\194\ EEI and
KCP&L urge that the Commission afford Critical Energy Infrastructure
Information (CEII) \195\ status to this information since it clearly
relates to the production, generation, transmission or distribution of
energy, could be useful to a person planning an attack and gives
strategic information beyond the location of critical infrastructure.
EEI encourages the Commission to perform an evaluation as to the need
for confidentiality of selected company information due to the
commercially sensitive nature of the information. Similarly, Ameren and
TransElect request that the Commission clarify that the required
information may be submitted pursuant to the Commission's confidential
filing procedures.\196\
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    \194\ E.g., TransElect, EEI, KCP&L, and Ameren.
    \195\ They cite Critical Infrastructure Information, Order No.
630, 68 FR 9857 (March 3, 2003), FERC Stats. & Regs. ] 31,140
(2003), order on reh'g, Order No. 630-A, 68 FR 46,456 (Aug. 6,
2003), FERC Stats. & Regs. ] 31,147 (2003).
    \196\ See 18 CFR 388.112.
---------------------------------------------------------------------------

    364. A number of commenters oppose the reporting requirement for a
variety of reasons. Several \197\ claim that the Commission has not
provided adequate justification for the Form X data collection, as
required by the Paperwork Reduction Act, given that the Commission
already collects information on utility transmission investment and
planning in existing FERC Form Nos. 1, 714 and 715 and that the
Commission has not demonstrated the need to make the information
collection mandatory. Ameren, AEP and PJM TOs state that the requested
information duplicates information already being compiled by RTOs in
their planning process; and MISO States suggest that the Commission
obtain an aggregate report from the RTO. PJM TOs recommend that Form
No. 1 requirements be modified prospectively, instead of requiring a
new form. EEI is concerned that the Commission, state commissions and
the public may inappropriately rely on the information, expecting the
plans to be implemented without regard to the regulatory approvals and
applicant and market decisions involved. EEI further states that
reporting information on planned future facilities can lead to
unnecessary opposition that might not occur with a proper public siting
process, lead to speculation in land use fees that can harm the
applicant's customers.
---------------------------------------------------------------------------

    \197\ E.g., EEI, Southern, SCE, KCP&L, Nevada Companies,
Progress Energy, Mid-American and PG&E.
---------------------------------------------------------------------------

    365. EEI, arguing that the only accurate measure of the
effectiveness of

the incentives is the number of applications filed for incentives,
encourages the Commission to simply monitor the number of applications
for new transmission facilities, the magnitude of the facilities
involved and the incentives sought and thereby obtain the most accurate
measure of the effectiveness of the proposed incentives. EEI also
encourages the Commission to rely on annual aggregate transmission
investment information that EEI has provided to the Commission and can
continue collecting for the Commission's benefit. Nevada Companies
assert this information should not be required since it is inaccurate
and incomplete.
    366. Southern, SCE and Ameren propose limitations on the
information to be provided as follows: Only aggregate information
should be required, and project-specific information should not be
required since it is extremely burdensome, entails security and
confidentiality issues, and is subject to change; if project-level
information is required, that it be limited to major transmission
projects, i.e., 345 kv and above; and limit project-specific reporting
requirements to only projects costing $20 million or more and that are
subject to a Transmission Organization's or a regional planning
organization's planning and approval process.

C. Commission Determination

    367. To ensure that these rules are successfully meeting the
objectives of section 219, the Commission needs industry data,
projections and related information that detail the level of
investment. The rule's purpose is to both provide new investment as
well as ensure that customers benefit. Thus, information regarding
projected investments as well as information about completed projects
will help the Commission to monitor the success of the ratemaking
reforms announced in this rule. Thus, the Commission will adopt the
proposed reporting requirement Form X and designate it as the FERC-730.
Further, the Commission will make certain modifications to clarify when
reports must be filed and what data must be submitted in FERC-730
reports.\198\ The information required in FERC-730 is not available
from Form Nos. 1, 714 or 715, nor is it available from other federal
agencies. For instance, FERC Form No. 1 requires the reporting of
historical financial data but does not contain forward looking
projections of expected transmission investments.\199\ Thus, the
information sought is not already readily available and will be
required only from public utilities that have been granted incentive
rate treatment for specific transmission projects under the provisions
of Sec.  35.35.
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    \198\ FERC-730 filers are reminded that each FERC-730 filing
must be accompanied by a Subscription consistent with the
requirements of 18 CFR 385.2005(a).
    \199\ See e.g., FERC Form No. 1 schedule pp. 204-7, ``Electric
Plant in Service (Accounts 101, 102, 103 and 106)'' which requires
the reporting of the original cost of electric plant in service and
p. 216, ``Construction Work in Progress--Electric (Account 107)''
which requires the reporting of expenditures for certain
construction projects at December 31 of the reporting year.
---------------------------------------------------------------------------

    368. We agree with commenters that, for some utilities, the
information requested is similar to information submitted to RTOs.
However, the Commission does not receive that information, and the
information provided to RTOs may not be identical to the information
requested here. Therefore, to ease the administrative burden, those
utilities providing information to RTOs can submit the same information
to the Commission. We strongly encourage utilities that submit FERC-730
reports to do so in an electronic format via eFiling.\200\ To rely on
information collected by EEI, as recommended, would not provide the
Commission with the accurate information we need to assess the
effectiveness of our regulations under section 219. The Commission
would not have available to it the survey instruments or the analysis
behind the reported information. Thus, reliance on second-hand gathered
survey information for the purposes of rate setting would not provide
the independent, factual basis to allow the Commission to make a
determination that continuing incentives is appropriate. Likewise, the
summary investment information available in existing reports does not
provide information on projected investment or reasons for delays in
projects, thereby limiting its value for determining the effectiveness
of the rules.
---------------------------------------------------------------------------

    \200\ The Commission will issue a separate notice on how to
submit this data electronically via eFiling.
---------------------------------------------------------------------------

    369. We do not believe a CEII designation is required for this
information since it is expected to only include information on capital
spending and a general designation of the project name, without
requiring data on facility location. With respect to confidential
treatment of FERC-730, as a general matter we do not believe that this
type of general planning information involves commercially sensitive
information. However, while we will require applicants to provide
capital spending projections and other information in their
applications, we also recognize that applicants may have legitimate
reasons to maintain confidentiality of certain information. For this
reason, applicants can request protection of information under Sec.
388.112.
    370. With respect to project-level information, this information is
needed to determine the status of critical projects and reasons for
delay, and will play a role in the Commission's evaluation of
continuing incentives. To facilitate this review, we will require that
filers specify which projects are currently receiving incentives in the
project detail table and that they group together those facilities
receiving the same incentive. We will not limit the information to
projects above a certain voltage, since lower-voltage projects can have
significant impacts on reliability and congestion relief, nor will we
limit the information to projects subject to a Transmission
Organization's or a regional planning organization's planning and
approval process since we are addressing a national problem and
complete coverage is therefore necessary. As discussed earlier in this
rule, projects eligible for incentives--and hence required to submit
data--are not restricted to projects or investments that result from
regional planning processes. We agree with SCE that a minimum dollar
threshold of $20 million is a reasonable level for reporting of
significant projects.
    371. We agree with many of the recommendations for modifications to
the tables as shown in the revised FERC-730 in the Appendix. We will
not require the reporting of consumer benefits of projects. In order
for these projects to have received an incentive, the project must have
met the requirements of this rule, which includes that it benefit
consumers by ensuring reliability and reducing the cost of delivered
power by reducing transmission congestion. We will not require the
addition of operating data to the table since the sole purposes of the
information collection is to determine the level of capital spending,
the status of significant and critical projects and reasons for delay.
We will not require a Proposed Operating Date, as recommended by
Ameren, since our sole concern with this information is that the
planned projects are completed on time; operational start-up issues
such as synchronization with the grid and testing introduce additional
issues not directly relevant to tracking the progress of investments in
new infrastructure.
    372. Further, we will not require year-by-year capital spending
estimates for

the project detail table as recommended by TAPS since the goal of the
rule is not to ensure the achievement of annual capital spending
targets but rather to ensure the overall project is completed, and if
not, the reasons for the delay. We will not require the inclusion of
cost allocation or pricing information as recommended by TAPS since
that information is beyond the scope of our requirements. We do not see
the need for a disclaimer that information is subject to change, since
the required information is clearly labeled ``projected'' and
``expected'' and therefore assumed to be subject to change. Since this
rulemaking applies to public utilities and incentives are being
permitted pursuant to sections 219 and 205, which pertain to public
utilities, we will not require information from entities that are not
jurisdictional under section 205, although such entities are encouraged
to voluntarily provide this information. We clarify that the meaning of
``On Schedule'' in the Project Detail table is the most up-to-date,
expected project completion date.
    373. We clarify that the reported information is to be provided for
informational purposes only, and its purpose is not to establish the
prudence of the amounts spent. As we specified earlier in the rule, we
expect applicants will propose metrics and provide a nexus between the
incentive and the investment, and therefore the information in this
report will not be the sole basis for a section 206 investigation. We
further clarify that the projections in FERC-730, rendered in good
faith and upon a reasonable basis, would not subject the reporting
transmission owners to claims of fraud, detrimental reliance or other
liabilities arising from the fact that actual capital spending may vary
from reported projections.
    374. Rather than requiring all public utilities to submit FERC-730,
we clarify that only those public utilities that have been granted
incentive-based rate treatment for specific transmission projects under
the provisions of Sec.  35.35 must file FERC-730 in the manner
prescribed in Appendix A. A public utility is subject to the FERC-730
reporting requirement beginning with the year the Commission issues an
order in response to a filing made pursuant to section 205 of the
Federal Power Act, or in a petition for a declaratory order that
precedes a filing pursuant to section 205. The initial FERC-730 filing
is due by April 18 of the following calendar year and subsequent
filings are due each April 18 thereafter.
    375. In addition, we will add a new provision to Sec.  35.35(h) and
delegate to the Chief Accountant or the Chief Accountant's designee
authority to act on requests for extension of time to file FERC-730 or
to waive the requirements applicable to any FERC-730 filing.
    376. Finally, we find the data issues raised by Semantic to be
beyond the scope of this rulemaking. While the data requested by
Semantic could provide a useful purpose for the operations and
management of electric facilities and may have applicability to the
Commission's regulations for RTOs, this rulemaking is limited to an
evaluation of incentives for investment in electric transmission
facilities. Therefore, the reporting requirements of the rulemaking are
appropriately limited to data on industry investment.

VI. Other Issues

A. Rate Related Issues

1. Rate Related Issues
    377. Commenters also raised other rate issues such as formula
rates, rate design, the five-month suspension policy and recovery of
other costs. The Commission addresses these issues below.
a. Comments on Formula Rates
    378. As an alternative to single-issue ratemaking, certain
commenters urge the Commission to require recovery of incentives
through various forms of formula rates.\201\ Certain MISO TOs state
that the Commission should facilitate recovery from wholesale and
retail customers including bundled and unbundled retail load through a
formula rate for new investments. Certain MISO TOs cite section 219 of
the FPA to argue that Congress required the Commission to ensure the
recovery of all prudently incurred costs necessary to comply with
mandatory reliability requirements and related to transmission
infrastructure development.\202\
---------------------------------------------------------------------------

    \201\ E.g., APPA, AWEA, KKR, MDU, PG&E, Certain MISO TOs, and
TAPS.
    \202\ Certain MISO TOs state that all costs of new investment
should include the costs of facilities built by the company as well
as the costs of facilities allocated to the company through a RTO
transmission cost allocation process.
---------------------------------------------------------------------------

    379. EEI argues that the section 205 filing for a public utility
with a formula rate should be limited to including appropriate language
in the formula rate allowing the utility to get the incentives and not
be the basis to challenge any other aspect of the formula rate.
b. Comments on Rate Design
    380. Several commenters urge the Commission to require applicants
to seek rolled-in treatment, rather than participant funding, to
recover any costs incurred under the rule.\203\ Those commenters assert
that participant funding is inequitable because it imposes too much of
a system burden on limited customers and that participant funding may
actually discourage investment.
---------------------------------------------------------------------------

    \203\ E.g., East Texas, TDU Systems, and TAPS.
---------------------------------------------------------------------------

    381. Other commenters support participant funding for
projects.\204\ They argue that socialization unfairly requires others
to pay for facilities that they do not need and may deter new
investment. Xcel requests that the Commission provide clear guidance on
the issue of ``rolled in'' versus ``incremental'' pricing. Xcel states
that the Commission should allow phased roll-in of transmission
facilities as it does for natural gas pipelines because rolled-in
pricing would encourage proper siting of generation.
---------------------------------------------------------------------------

    \204\ E.g., NorthWestern, Progress, Southern Companies, PSEG,
and E.ON US.
---------------------------------------------------------------------------

    382. EEI states that the Commission should be open to proposals
that deviate from the ``higher of'' policy where justified.
    383. Other commenters express support for regional or zonal
rates.\205\ They argue that regional rates would foster new projects
because the rates would match cost recovery to the broad regional
benefits obtained and reduce opposition from local consumers and state
regulators and litigation.
---------------------------------------------------------------------------

    \205\ E.g., TAPS and Upper Great Plains.
---------------------------------------------------------------------------

c. Comments on Five-Month Suspension
    384. EEI, SCE and Xcel argue that the Commission's current
suspension policy hinders transmission investment because delaying the
effective date of rates forces a utility to absorb the costs associated
with the new facilities during the suspension period, thereby
effectively reducing that utility's return on equity. Additionally, EEI
argues that, because any rate increase authorized by the Commission
could be made subject to refund, with interest, customers could be made
whole even without a five-month suspension. SCE suggests that the
Commission should either change the threshold for determining when
rates are excessive or use a sliding scale that would impose a longer
suspension the larger the excessive revenues.
d. Other Comments on Rate Design
    385. Commenters raised a variety of rate design issues. Energy
Capital states that the Commission must modify traditional ratemaking
practices to recognize the risks and structures required to fund a
single line transmission project. SCE states that an

additional disincentive to transmission investment is the imputation of
revenues from grandfathered agreements that are greater than the actual
revenues under the agreements, thereby reducing the earned return for
transmission tariff service. TAPS faults the Commission's policy of
excluding EPRI dues from transmission rates because wholesale customers
may make their own direct contributions. Trans-Elect requests the
Commission to confirm that all financing costs, including prepaid
liquidity reserve and working capital costs required by the lender as a
condition to financing, are recoverable in rates.
e. Commission Determination
    386. We agree with several commenters that formula rates can
provide the certainty of recovery that is conducive to large
transmission expansion programs.\206\ Moreover, formula rates alleviate
the need for other relief sought by commenters. For example, public
utilities with formula rates will generally be able to flow through
increased transmission investment without concern as to the
Commission's five-month suspension policy with the exception of the
suspension period for approval of initial rates. While we continue to
encourage public utilities to explore the benefits of filing
transmission-related formula rates,\207\ we will not require public
utilities to use formula rates to recover incentives.
---------------------------------------------------------------------------

    \206\ We will not rule on PG&E's proposed rate base tracking
mechanism here because we do not have an actual proposal with
supporting documents before us.
    \207\ Allegheny Power System Operating Companies, 111 FERC ]
61,308 at P 51 (2005). See also Allegheny Power System Operating
Companies, 106 FERC ] 61,003 at P 32 (2004) (``The parties may
explore whether adopting formula rates for recovery of the costs of
both the TOs' existing transmission facilities and new transmission
facilities would be best. Specifically, we note that other TOs that
we have approved incentive rates for also have formula rates.'').
---------------------------------------------------------------------------

    387. We disagree with the interpretation that section 219 requires
the Commission to claim jurisdiction over the transmission component of
bundled retail load. While MISO TOs are correct that section 219
requires the Commission to ensure the recovery of all costs prudently
incurred for section 215 reliability compliance and section 216
national interest corridor investments, we do not believe it is
necessary to assert jurisdiction over bundled retail transmission to
fulfill this statutory requirement.\208\
---------------------------------------------------------------------------

    \208\ We will not add the term ``all'' to the regulatory text in
18 CFR 35.35(f) and (g) as recommended by Certain MISO TOs. The text
in those sections reflects the language in section 219 of the FPA
and therefore meets the Commission's compliance requirements.
---------------------------------------------------------------------------

    388. The rate design issues raised in the comments are beyond the
scope of this proceeding.\209\ While rate designs can impact
infrastructure investment, this rule is limited to addressing incentive
treatments that foster infrastructure investment. Interested parties
may raise issues associated with rate design policies in the associated
section 205 filings in which applicants are seeking rate recovery of
transmission incentives.
---------------------------------------------------------------------------

    \209\ We will not retain 18 CFR 35.34(e) in the new regulations
as requested by MISO States. However, the new regulations allow RTOs
to propose alternative incentives in 18 CFR 35.35(d)(1)(iii) and
under these new regulations, RTOs may propose the incremental
pricing provisions previously included in 18 CFR 35.34(e).
---------------------------------------------------------------------------

    389. We will not revise our five-month suspension policy in this
proceeding. To the extent that public utilities are concerned that the
Commission's suspension policy unnecessarily delays recovery of prudent
costs, there are alternative means to ensure such recovery. As
mentioned previously, formula rates enhance cost recovery certainty.
Further, public utilities that are concerned that a particular rate
increase may be deemed ``excessive'' under our suspension policy may
use our pre-filing process for discussing those concerns.
    390. We will not make the determination on Energy Capital's
proposal that the Commission modify its traditional ratemaking
practices to recognize unique aspects of non-traditional transmission
owners because the issues raised are novel and we would be better
informed with an actual proposal before us. Regarding SCE's concern
about imputing the transmission revenues under grandfathered agreements
using the OATT rate, this issue is beyond the scope of this proceeding.
    391. We shall deny TAPS proposal to reconsider our policy on
recovery of EPRI research and development costs when the unbundled
retail load takes service under the same transmission rate as wholesale
customers.\210\ That is beyond the scope of this proceeding.
---------------------------------------------------------------------------

    \210\ The Commission has explained that, when the basis for
calculating the amount of the voluntary contribution to EPRI for
research and development is based on the amount of retail sales,
recovery from wholesale customers is unreasonable. See Public
Service Company of New Mexico, Opinion 133, 17 FERC ] 61,123 at
61,249 (1981), order on rehr'g, Opinion No. 133-A, 18 FERC ] 61,036
(1982).
---------------------------------------------------------------------------

    392. The Commission will remain flexible with respect to rate
treatments proposals that applicants or interested parties can
demonstrate to be just and reasonable.
    393. We will deny the request to confirm in this proceeding that
prepaid liquidity reserve and working capital costs required by project
lenders as a condition to financing are recoverable. Those issues were
the subject of an Administrative Law Judge's Initial Decision in Docket
No. ER05-17-002 and are pending Commission review. Those issues are
better addressed in that proceeding because that proceeding has a
complete litigated record.
    394. We also find that EEI's request that the Commission use this
rule to revisit ``and'' pricing to be beyond the scope of this rule.

B. Section 35.34

1. The Proposal To Eliminate Section 35.34(e)
a. Background
    395. The NOPR proposed that applicants for incentive ratemaking
treatment under section 35.35 would not be required to support their
applications with cost-benefit analyses. The NOPR also proposed to
eliminate Sec.  35.34(e), which requires cost-benefit analyses by RTO
applicants in order to avoid potential conflict between or overlap of
the pre-existing regulations and the new Sec.  35.35.
b. Comments
    396. Several comments specifically addressed the NOPR's proposal to
eliminate Sec.  35.34(e). TDU Systems do not oppose elimination of
Sec.  35.34(e), so long as the consumer protections embodied in that
section are incorporated into a new rule adopted to replace it. TDU
Systems argues that adoption of the conditions and criteria it
recommends (i.e., public power participation in planning, financing and
construction, and rolled-in rate treatment for expansions of network
facilities) would ensure that these protections remain in place. TAPS,
APPA and Industrial Consumers support retention of the cost-benefit
provision for reasons given in their comments on the cost-benefit
issue.
    397. NRECA supports the Commission's proposal. Public utilities
have had the opportunity for five years now to form RTOs and obtain
transmission rate incentives for RTO membership. In light of the fact
that it is yet to be demonstrated that the benefits of RTOs outweigh
their cost, elimination of this provision is appropriate.
    398. MISO supports the elimination of Sec.  35.34(e), because it
will be superfluous and unnecessary if the NOPR is adopted. Moreover,
MISO points out that the authorization for RTOs to

include innovative rate treatments in their rates found in Sec.
35.34(e) expired after January 1, 2005, with respect to transmission
rate moratoriums and rates of return that do not vary with capital
structure.
    399. Ameren Services does not oppose the Commission's proposal to
remove existing section 18 CFR 35.34(e) from its regulation. This is
consistent with the mandate of new FPA section 219 to provide
incentives for qualifying entities. Ameren Services contends that
removal of Sec.  35.34(e) will avoid confusion that could arise from
potential conflicts between innovative rate treatments available under
existing Sec.  35.34(e) and the additional incentives proposed to be
adopted in new Sec.  35.35.
    400. MISO States generally support the elimination of Sec.
35.34(e). However, MISO States point out that Sec.  35.34(e) appears to
contain a provision that permits RTOs to apply for incremental pricing
for new transmission facilities in association with an embedded-cost
access fee for existing transmission facilities. Such a provision does
not appear to be encompassed in the language of the Commission's
proposed new Sec.  35.35 rule. MISO States believe that such a
provision could prove useful in certain circumstances and urges the
Commission not to drop this provision in the transition process of
deleting the elements in Sec.  35.34(e) and replacing them with the new
elements in Sec.  35.35.
    401. NorthWestern opposes preferential treatment based on corporate
structure. It argues that if the Commission does remove Sec.  35.34(e)
as proposed, it should make certain that its resulting policies provide
the appropriate non-preferential treatment.
c. Commission Determination
    402. Comments opposing the elimination of the cost-benefit analysis
requirement are addressed above in our determination to affirm the NOPR
on the cost-benefit issue.
    403. MISO States expresses concern that the proposed new Sec.
35.35 does not appear to encompass the provision in pre-existing Sec.
35.34(e)(v) allowing RTOs to apply for incremental pricing for new
transmission facilities in association with an embedded-cost access fee
for existing transmission facilities. The deletion of Sec.  35.34(e) is
intended to eliminate potentially conflicting or overlapping
regulations concerning requests for incentive rate treatment. Thus, for
example, the deletion of Sec.  35.34(e) eliminates potential confusion
over whether a proposal would be an ``innovative'' rate treatment (and
require a cost-benefit analysis) under the pre-existing rules or be an
incentive rate treatment requirement (with no cost-benefit analysis)
under the new rules.
    404. In Section IV.D. of this preamble in our determination
segment, we find that we do not have a sufficient basis to adopt rules
for PBR in this rule. Notwithstanding that determination not to
enumerate PBR in the list of incentive rate treatments, we also state
that we remain open to consider PBR proposals as an incentive rate
treatment pursuant to section 219. Given that determination, and to
avoid potential conflict or overlap with the rules adopted herein, we
believe that removal of the pre-existing PBR provisions--Sec. Sec.
35.34(e)(2)(v) and 35.34(e)(3)--is appropriate.
    405. We address NorthWestern's comment that the Commission should
not favor any particular corporate structure in the discussion of the
Transco incentives, supra Section IV.

VII. Information Collection Statement

    406. The Office of Management and Budget (OMB) regulations require
approval of certain information collection requirements imposed by
agency rules.\211\ The Commission is submitting these reporting
requirements to OMB for its review and approval under section 3507(d)
of the Paperwork Reduction Act.\212\ 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 this 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. Interested persons may obtain information on the
reporting requirements by contacting: Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426 [Attention:
Michael Miller, Office of the Executive Director, Phone: (202) 502-
8415, fax:<PHONE_NUMBER>, e-mail<EMAIL_ADDRESS>---------------------------------------------------------------------------

    \211\ 5 CFR 1320.13 (2005).
    \212\ 44 U.S.C. 3507(d) (2000).
---------------------------------------------------------------------------

    407. Public Reporting Burden: The Commission did not receive
specific comments concerning its burden estimates and uses the same
estimate here. Comments on the proposed reporting requirement (proposed
in the NOPR as Form X) are addressed above in Section V, Reporting
Requirements, where we adopt the FERC-730 information collection
requirement. The comments received and our adoption of FERC-730 do not
lead us to revise the NOPR's estimates of the public reporting burden.

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
FERC-516:
    Transcos....................................              30               1             296           8,880
    Traditional Public Utilities................             200               1             181          36,200
    FERC-730....................................             200               1              30           6,000
                                                 ---------------------------------------------------------------
        Totals..................................             230               1             222          51,080
----------------------------------------------------------------------------------------------------------------

    Total Annual Hours for Collection: (Reporting + Recordkeeping, (if
appropriate)) = 51,080 hours.
    Information Collection Costs: The Commission sought comments about
the time and corresponding costs needed to comply with these
requirements. No comments were received. Costs for FERC-516 and FERC-
730 = $6,129,600 (51,080 hours at $120 an hour). (The hourly rate was
determined by taking the median annual salary from Bureau of Labor
Statistics, Department of Labor Occupational Outlook Handbook. The
figures reported by BLS are for 2002 and added to them was an inflation
factor of 4.73 percent for the period January 2003 through December
2004.)
    Title: FERC-516 ``Electric Rate Schedule Filings'', FERC-730
``Report of Transmission Investment Activity''.
    Action: Proposed Collections.
    OMB Control No.: 1902-0096; and to be determined.
    Respondents: Business or other for profit.

    Frequency of Responses: On occasion for applicants and annually for
transmission investment report.
    Necessity of the Information: The Final Rule amends the
Commission's regulations to implement the statutory provisions of
section 1241 of EPAct 2005. The Act directs the Commission to establish
incentive-based (including performance-based) rate treatments for the
transmission of electric energy in interstate commerce by public
utilities in order to benefit consumers by ensuring reliability and
reducing the cost of delivered power by relieving transmission
congestion. This mandate addresses an identified need to encourage
construction of transmission infrastructure and encourage investment.
Sufficient supplies of energy and a reliable way to transport those
supplies are necessary to assure reliable energy availability and to
enable competitive markets. Without sufficient delivery infrastructure,
some suppliers will not be able to enter the market, customer choices
will be limited, and prices may be needlessly higher or volatile. The
implementation of incentive and performance-based rate treatments
supports the Commission's mandate to support investments in
transmission capacity to reduce the cost of delivered power by reducing
congestion.
    408. Entities seeking incentives to build new transmission
facilities must file under Part 35 of the Commission's regulations, an
application describing how the entity will bring benefits to the grid.
The information provided for under Part 35 is identified as FERC-516.
The information for actual and planned investments as proposed in an
annual report is identified as FERC-730 and the information is provided
for under Sec.  35.35(h) of the Commission's regulations.
    409. Comments on the final rule may also be sent to the Office of
Management and Budget. For information on the requirements, submitting
comments on the collection of information and the associated burden
estimates including suggestions for reducing this burden, please send
your comments to the Federal Energy Regulatory Commission, 888 First
Street, NE., Washington, DC 20426 (Attention: Michael Miller, Office of
the Executive Director,<PHONE_NUMBER>) or send comment to the Office of
Management and Budget (Attention: Desk Officer for the Federal Energy
Regulatory Commission, fax:<PHONE_NUMBER>, e-mail:
<EMAIL_ADDRESS>and please reference this rulemaking docket

no. in your submission.

VIII. Environmental Statement

    410. 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.\213\ The
Commission has categorically excluded certain actions from this
requirement as not having a significant effect on the human
environment. Included in the exclusion are rules that are clarifying,
corrective, or procedural or that do not substantially change the
effect of the regulations being amended.\214\ Thus, we affirm the
finding we made in the NOPR that this Final Rule is procedural in
nature and therefore falls under this exception; consequently, no
environmental consideration would be necessary.
---------------------------------------------------------------------------

    \213\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (1987), FERC Stats. & Regs. ] 30,783
(1987).
    \214\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

IX. Regulatory Flexibility Act Certification

    411. The Regulatory Flexibility Act (RFA) \215\ requires that a
rulemaking contain either a description and analysis of the effect that
the Final Rule will have on small entities or a certification that the
rule will not have a significant economic impact on a substantial
number of small entities. However, the RFA does not define
``significant'' or ``substantial'' instead leaving it up to any agency
to determine the impacts of its regulations on small entities. The
Final Rule will not have a significant adverse impact on a substantial
number of small entities. The Final Rule applies only to entities that
own, control, or operate facilities for transmitting electric energy in
interstate commerce and not to electric utilities per se. Small
entities that believe this Final Rule will have a significant impact on
them may apply to the Commission for waivers.
---------------------------------------------------------------------------

    \215\ 5 U.S.C. 601-612 (2000).
---------------------------------------------------------------------------

X. Document Availability

    412. 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 p.m. Eastern time) at 888 First Street, NE., Room 2A,
Washington, DC 20426.
    413. From the Commission's Home Page on the Internet, this
information is available in the eLibrary. The full text of this
document is available on eLibrary both 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.
    414. User assistance is available for eLibrary and the Commission's
Web site during normal business hours. For assistance, please contact
Online Support at 1-866-208-3676 (toll free) or<PHONE_NUMBER> (e-mail at
FERCOnlineSupport@FERC.gov), or the Public Reference Room at 202-502-

8371, TTY<PHONE_NUMBER> (e-mail at public.referenceroom@ferc.gov).

XI. Effective Date and Congressional Notification

    415. This Final Rule will take effect September 29, 2006. The
Commission has determined, with the concurrence of the Administrator of
the Office of Information and Regulatory Affairs of the Office of
Management and Budget, that this rule is not a major rule within the
meaning of section 251 of the Small Business Regulatory Enforcement
Fairness Act of 1996.\216\ The Commission will submit the Final Rule to
both houses of Congress and the Government Accountability Office.\217\
---------------------------------------------------------------------------

    \216\ 5 U.S.C. 804(2) (2000).
    \217\ 5 U.S.C. 801(a)(1)(A) (2000).
---------------------------------------------------------------------------

List of Subjects in 18 CFR Part 35

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

    By the Commission.
Magalie R. Salas,
Secretary.

0
In consideration of the foregoing, the Commission amends part 35 of
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. 7101-7352.

Subpart F--Procedures and Requirements Regarding Regional
Transmission Organizations

Sec.  35.34  [Amended]

0
2. In Sec.  35.34, remove and reserve paragraph (e).

0
3. A new subpart G is added to read as follows:

Subpart G--Transmission Infrastructure Investment Provisions

Sec.  35.35  Transmission infrastructure investment.

    (a) Purpose. This section establishes rules for incentive-based
(including performance-based) rate treatments for transmission of
electric energy in interstate commerce by public utilities for the
purpose of benefiting consumers by ensuring reliability and reducing
the cost of delivered power by reducing transmission congestion.
    (b) Definitions. (1) Transco means a stand-alone transmission
company that has been approved by the Commission and that sells
transmission services at wholesale and/or on an unbundled retail basis,
regardless of whether it is affiliated with another public utility.
    (2) Transmission Organization means a Regional Transmission
Organization, Independent System Operator, independent transmission
provider, or other transmission organization finally approved by the
Commission for the operation of transmission facilities.
    (c) General rule. All rates approved under the rules of this
section, including any revisions to the rules, are subject to the
filing requirements of sections 205 and 206 of the Federal Power Act
and to the substantive requirements of sections 205 and 206 of the
Federal Power Act that all rates, charges, terms and conditions be just
and reasonable and not unduly discriminatory or preferential.
    (d) Incentive-based rate treatments for transmission infrastructure
investment. The Commission will authorize any incentive-based rate
treatment, as discussed in this paragraph (d), for transmission
infrastructure investment, provided that the proposed incentive-based
rate treatment is just and reasonable and not unduly discriminatory or
preferential. A public utility's request for one or more incentive-
based rate treatments, to be made in a filing pursuant to section 205
of the Federal Power Act, or in a petition for a declaratory order that
precedes a filing pursuant to section 205, must include a detailed
explanation of how the proposed rate treatment complies with the
requirements of section 219 of the Federal Power Act and a
demonstration that the proposed rate treatment is just, reasonable, and
not unduly discriminatory or preferential. The applicant must
demonstrate that the facilities for which it seeks incentives either
ensure reliability or reduce the cost of delivered power by reducing
transmission congestion consistent with the requirements of section
219, that there is a nexus between the incentive sought and the
investment being made, and that resulting rates are just and
reasonable. For purposes of this paragraph (d), incentive-based rate
treatment means any of the following:
    (1) The Commission will authorize the following incentive-based
rate treatments for investment by public utilities, including Transcos,
in new transmission capacity that reduces the cost of delivered power
by reducing transmission congestion or ensures reliability, and is
otherwise just, reasonable and not unduly discriminatory or
preferential, as demonstrated in an application to the Commission:
    (i) A rate of return on equity sufficient to attract new investment
in transmission facilities;
    (ii) 100 percent of prudently incurred Construction Work in
Progress (CWIP) in rate base;
    (iii) Recovery of prudently incurred pre-commercial operations
costs;
    (iv) Hypothetical capital structure;
    (v) Accelerated depreciation used for rate recovery;
    (vi) Recovery of 100 percent of prudently incurred costs of
transmission facilities that are cancelled or abandoned due to factors
beyond the control of the public utility;
    (vii) Deferred cost recovery; and
    (viii) Any other incentives approved by the Commission, pursuant to
the requirements of this paragraph, that are determined to be just and
reasonable and not unduly discriminatory or preferential.
    (2) In addition to the incentives in Sec.  35.35(d)(1), the
Commission will authorize the following incentive-based rate treatments
for Transcos, provided that the proposed incentive-based rate treatment
is just and reasonable and not unduly discriminatory or preferential:
    (i) A return on equity that both encourages Transco formation and
is sufficient to attract investment; and
    (ii) An adjustment to the book value of transmission assets being
sold to a Transco to remove the disincentive associated with the impact
of accelerated depreciation on federal capital gains tax liabilities.
    (e) Incentives for joining a Transmission Organization. The
Commission will authorize an incentive-based rate treatment, as
discussed in this paragraph (e), for public utilities that join a
Transmission Organization, if the applicant demonstrates that the
proposed incentive-based rate treatment is just and reasonable and not
unduly discriminatory or preferential. Applicants for the incentive-
based rate treatment must make a filing with the Commission under
section 205 of the Federal Power Act. For purposes of this paragraph
(e), an incentive-based rate treatment means a return on equity that is
higher than the return on equity the Commission might otherwise allow
if the public utility did not join a Transmission Organization. The
Commission will also permit transmitting utilities or electric
utilities that join a Transmission Organization the ability to recover
prudently incurred costs associated with joining the Transmission
Organization, either through transmission rates charged by transmitting
utilities or electric utilities or through transmission rates charged
by the Transmission Organization that provides services to such
utilities.
    (f) Approval of prudently-incurred costs. The Commission will
approve recovery of prudently-incurred costs necessary to comply with
the mandatory reliability standards pursuant to section 215 of the
Federal Power Act, provided that the proposed rates are just and
reasonable and not unduly discriminatory or preferential.
    (g) Approval of prudently incurred costs related to transmission
infrastructure development. The Commission will approve recovery of
prudently-incurred costs related to transmission infrastructure
development pursuant to section 216 of the Federal Power Act, provided
that the proposed rates are just and reasonable and not unduly
discriminatory or preferential.
    (h) FERC-730, Report of transmission investment activity. Public
utilities that have been granted incentive rate treatment for specific
transmission projects must file FERC-730 on an annual basis beginning
with the calendar year incentive rate treatment is granted by the
Commission. Such filings are due by April 18 of the following calendar
year and are due April 18 each year thereafter. The following
information must be filed:
    (1) In dollar terms, actual transmission investment for the most
recent calendar year, and projected, incremental investments for the
next five calendar years;
    (2) For all current and projected investments over the next five
calendar years, a project by project listing that specifies for each
project the most up-to-date, expected completion date, percentage
completion as of the date of filing, and reasons for delays. Exclude
from this listing projects with projected costs less than $20 million;
and
    (3) For good cause shown, the Commission may extend the time within
which any FERC-730 filing is to

be filed or waive the requirements applicable to any such filing. The
authority to act on motions for extensions of time to file FERC-730 or
to waive the requirements applicable to any FERC-730 filing, including
granting or denying such motions, in whole or in part, is delegated to
the Chief Accountant or the Chief Accountant's designee.
    (i) Rebuttable presumption. The Commission will apply a rebuttable
presumption that an applicant has met the requirements of section 219
for:
    (1) A transmission project that results from a fair and open
regional planning process that considers and evaluates projects for
reliability and/or congestion and is found to be acceptable to the
Commission;
    (2) A project that has received construction approval from an
appropriate state commission or state siting authority; or
    (3) A proposed project that is located in a National Interest
Electric Transmission Corridor pursuant to section 216 of the Federal
Power Act.

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

Appendix A--FERC-730, Report of Transmission Investment Activity

Company Name: ----------

                      Table 1.--Actual and Projected Electric Transmission Capital Spending
----------------------------------------------------------------------------------------------------------------
                                     Actual at    Projected investment (incremental investment by year for each
   Capital spending on electric       December                of the succeeding five calendar years)
   transmission facilities 1  ($        31,     ----------------------------------------------------------------
            thousands)             -------------
                                        20--         20--         20--         20--         20--         20--
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
 \1\ Transmission facilities are defined to be transmission assets as specified in the Uniform System of
  Accounts in account numbers 350 through 359 (see, 18 CFR Part 101).

                                                              Table 2.--Project Detail \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                Expected project                                                     If project not on
      Project description \2\           Project type \3\    completion date  (month/ Completion status \4\      Is project on        schedule, indicate
                                                                     year)                                     schedule?  (Y/N)    reasons for delay \5\
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
 \1\ Respondents must list all projects included in the actual and projected electric transmission capital spending table, excluding those projects with
  projected costs less than $20 million.
\2\ Project description should include voltage level.
\3\ Project types are New Build, Upgrade of Existing, Refurbishment/Replacement, or Generator Direct Connection.
\4\ Completion status designations are Complete, Under Construction, Pre-Engineering, Planned, Proposed, and Conceptual.
\5\ Reasons for delay designations are Siting, Permitting, Construction, Delayed Completion of New Generator, or Other (specify).

Appendix B--Commenters on the NOPR

Public Utilities and Trade Associations

Ameren Service Company (Ameren)
American Electric Power System Corporation (AEP)
American Transmission Companies (American Transmission)
WestConnect Public Utilities (WestConnect)
Baltimore Gas and Electric Company (BG&E)
California Independent System Operator Corporation (California ISO)
Certain Midwest ISO Transmission Owners (Certain MISO TOs)
Citizens Energy Corporation (Citizens Energy)
Consumers Energy Company (Consumers Energy)
DTE Energy Company (DTE Energy)
Duquesne Light Company (Duquesne)
E.ON U.S. LLC (E.ON US)
Edison Electric Institute (EEI)
Electric Power Supply Association (EPSA)
FirstEnergy Service Company (FirstEnergy)
Gridwise Alliance (Gridwise)
International Transmission Company (International Transmission)
ISO New England (ISO-NE)
Kansas City Power & Light Company (KCPL)
MidAmerican Energy Company (MidAmerican)
Midwest Independent Transmission System Operator, Inc. (Midwest ISO)
Montana-Dakota Utilities (Montana-Dakota)
National Grid USA (National Grid)
Nevada Power Company and Sierra Pacific Power Company (Nevada
Companies)
New England Transmission Owners (New England TOs)
New York Independent System Operator, Inc. (New York ISO)
New York Electric & Gas Corporation and Rochester Gas & Electric
Corporation (NYSEG and RGE)
Northeast Utilities (NU)
NorthWestern Corporation (NorthWestern)
NSTAR Electric & Gas Corporation (NSTAR)
Pacific Gas and Electric Company (PG&E)
PacifiCorp
Pepco Holdings, Inc., et al. (Pepco)
PJM Interconnection, LLC (PJM)
PJM Transmission Owners (PJM TOs)
Progress Energy, Inc. (Progress Energy)
PSEG Companies (PSEG)
Public Service Company of New Mexico and Texas-New Mexico Power
Company (PNM and TNMP)
San Diego Gas & Electric Company (SDG&E)
Southern California Edison Company (SCE)
Southern Company Services, Inc. (Southern Companies)
Trans-Elect, Inc. (Trans-Elect)
United Illuminating Company (United Illuminating)
WPC Companies (WPS)
Xcel Energy Services, Inc. (Xcel)

Public Power Entities and Associations

American Municipal Power-Ohio, Inc. (AMP-Ohio)
American Public Power Association (APPA)
Bonneville Power Administration (Bonneville)
California Department of Water Resources State Water Project (CADWR)
CAPX Utilities (CAPX Utilities)
Community Power Alliance
Dairyland Power Cooperative (Dairyland)
East Texas Cooperatives (East Texas)
Hamilton, Ohio, et al. (Municipal Commenters)
Imperial Irrigation District (Imperial)
Los Angeles Department of Water and Power (LADWP)
National Rural Electric Cooperative Association (NRECA)
New England Consumer-Owned Entities (NECOE)
New York Association of Public Power (NY Association)
Public Power Council (PPC)
Public Utility District No. 1 of Snohomish County, Washington
(Snohomish)
Sacramento Municipal Utility District (SMUD)
Transmission Access Policy Study Group (TAPS)
Transmission Agency of Northern California (TANC)

Transmission Dependent Utility Systems (TDU Systems)
Upper Great Plains Transmission Coalition (Upper Great Plains)
Wyoming Infrastructure Authority

State Commissions and Other State Entities

California Electricity Oversight Board (California Oversight Board)
Public Utilities Commission of the State of California (California
Commission)
Committee on Regional Electric Power Cooperation (CREPC)
Connecticut Attorney General (Connecticut AG)
Connecticut Department of Public Utility Control (Connecticut DPUC)
Delaware Public Service Commission (Delaware Commission)
Kentucky Public Service Commission (Kentucky Commission)
Long Island Power Authority and Long Island Lighting Company (LIPA)
Maryland Public Service Commission (Maryland Commission)
Missouri Public Service Commission (Missouri Commission)
National Association of Regulatory Commissioners (NARUC)
National Association of State Regulatory Consumer Advocates (NASUCA)
New England Conference of Public Utility Commissioners (NECPUC)
New Jersey Board of Public Utilities (New Jersey Board)
New Mexico Attorney General (New Mexico AG)
New York Public Service Commission (New York Commission)
North Dakota Industrial Commission (North Dakota Commission)
Oklahoma Corporation Commission (Oklahoma Commission)
Organization of MISO States (MISO States or OMS)
Pennsylvania Public Utility Commission (Pennsylvania Commission)
Wyoming Office of Consumer Advocate (Wyoming Consumer Advocate)

Others

American Superconductor Corporation (American Superconductor)
American Wind Energy Association (AWEA)
Babcock & Brown, L.P. (Babcock & Brown)
Coalition for the Commercial Application of Superconductors (CCAS)
Consumer Energy Policy of America (CECA)
Electric Power Research Institute (EPRI)
Energy Capital
Energy Financing, Inc. (Energy Financing)
Industrial Consumers [ELCON, et al.] (Industrial Consumers)
JH2 Risk Advisors (JH2)
Kohlberg Kravis Roberts & Co. (KKR)
National Electrical Manufacturers Association (NEMA)
Norton Energy Storage (Norton)
Powder River Energy Corporation (Powder River)
Sabey Corporation (Sabey)
Semantic Applications, Inc. (Semantic)
Siemens Power Transmission & Distribution (Siemens)
Steel Manufacturers Association (Steel Manufacturers)
TransCanada Pipelines Limited (TransCanada)
UTC Power
Vectren Corporation (Vectren)

Reply and Supplemental Comments

EEI
International Transmission
KKR
National Grid

[FR Doc. 06-6495 Filed 7-28-06; 8:45 am]

BILLING CODE 6717-01-P