119. The Commission's current CWIP regulations were developed in an
era of bundled wholesale services and apply to any rate schedule. Since
that time, most wholesale transmission service subject to the
Commission's jurisdiction is provided at unbundled rates under open
access transmission tariffs. EEI points out that the requirement for a
forward looking allocation that estimates the average use a wholesale
customer will make of the utility system over the life of the project
is not necessary with transmission facilities. We agree. The forward
looking allocation ratio was to prevent a customer that was switching
power plant suppliers from having to share in the cost of CWIP of a
particular plant if the customer had no responsibility in the decision
of the utility to build the plant. We believe it highly unlikely that
transmission customers will be faced with such an opportunity.
Accordingly, because we do not view the ``double whammy'' to be a
concern in the transmission context, we grant EEI's request and waive
the requirement in 18 CFR 35.25(c)(4) as it pertains to preventing
double whammy with regard to CWIP associated with new investment in
transmission.\78\ Further, we clarify Sec.  35.35(d)(1)(ii) to state
that other provisions of Sec.  35.25 apply, unless waived by the
Commission on a case-by-case basis. We believe that these
clarifications to the regulatory text will avoid uncertainty expressed
by commenters regarding the procedures for obtaining the CWIP
incentive.
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    \78\ However, this waiver does not relieve transmission owners
from supplying the necessary information required in Sec.
35.25(c)(4) that pertains to CWIP-induced price squeeze. The
Commission will evaluate CWIP-induced price squeeze concerns on a
case-by-case basis.
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    120. In response to comments, we clarify that pre-payments, i.e.,
payments prior to the start of construction, for project costs by
third-parties should not be included in CWIP. If a customer is making
contributions in aid of construction, these amounts should not be
included in rate base. Similarly, in the instance of generator
interconnect, the up-front amount paid by the customer should not be
included in rate base; rather it is included in rate base over time as
the transmission provider provides credits to the customer.
    121. The Commission has previously determined that recovery of CWIP
on a formulary basis is not permitted without prior Commission review
to ensure that the Commission's CWIP standards are met.\79\ The
Commission in Maine Yankee allowed Maine Yankee to propose a method to
limit its filing obligation to once a year so that Maine Yankee did not
have to file each month that it changed the CWIP balances in its
monthly formula charges.\80\ Likewise, we will allow public utilities
to propose a method to limit their filing requirement related to CWIP
to an annual filing. These annual filings may be limited to CWIP and
will not subject

public utilities to a comprehensive rate review.\81\
---------------------------------------------------------------------------

    \79\ Maine Yankee Atomic Power Co., 66 FERC ] 61,375, at 62,252-
53 & n. 10 (1994) (Maine Yankee).
    \80\ Id., at 62,252.
    \81\ We deny the request to limit recovery of these incentives
to the amount originally budgeted. We note that, as a practical
matter, it would be difficult to hold electric transmission projects
to the original budget estimate when it can be 10 to 15 years
between the time the project is proposed and lines are actually
built. Also, if public utilities are held to recovering only
originally estimated budgets, they would either have incentives to
overestimate costs or to avoid the risky projects which the policy
is intended to facilitate.
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    122. With respect to the types of pre-commercial operations costs
that we will allow to be expensed rather than capitalized, we will
allow, on a generic basis, the same types of costs that we approved in
the American Transmission settlement.\82\ Further, we will entertain
proposals by public utilities to expense other types of costs for
consideration on a case-by-case basis.
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    \82\ American Transmission, in its application approved in
American Transmission defined pre-certification costs as preliminary
survey and investigation costs in Account 183. These costs include
all expenditures for, preliminary surveys, plans and investigations,
made for the purpose of determining the feasibility of utility
projects and costs of studies and analyses mandated by regulatory
bodies related to plant in service.
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3. Hypothetical Capital Structure
a. Background
    123. The Commission stated in the NOPR (at P 29) that it has
largely relied on the actual capitalization of a utility in setting its
rate of return, but recognized that an overly rigid approach to
evaluating a proposed capital structure could be a disincentive to
investment in new transmission projects and Transco formation. Each
project or company may have unique financial and cash flow
requirements, and a rigid approach to acceptable capital structures
could threaten the viability of some projects. Accordingly, the
Commission proposed allowing applicants to file an overall rate of
return based on a hypothetical capital structure, and giving them the
flexibility to refinance or employ different capitalizations as may be
needed to maintain the viability of new capacity additions. The
Commission stated that it expected applicants to develop their
proposals based on the specific requirements and circumstances of their
projects, and that the Commission would evaluate proposals for this
incentive on a case-by-case basis. The Commission required public
utilities to provide support in their application for why the
hypothetical capital structure incentive is needed to promote
investment consistent with the goals of section 219. The Commission
required the applicant to provide its transmission investment plan and
explain the specific projects to which the proposed return will apply.
b. Comments
    124. Many commenters support the hypothetical capital structure as
an incentive.\83\ Both American Transmission and Trans-Elect note that
they received approval to use a hypothetical capital structure and that
they had been able to stay on schedule for extensive transmission
construction programs.\84\
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    \83\ American Transmission, EEI, First Energy, KCPL, Nevada
Companies, NSTAR, NU, NYSEG and RGE, PJM, PG&E, Progress, Semantic,
Trans-Elect, United Illuminating and Xcel support the proposal.
    \84\ Trans-Elect cites Western, 99 FERC ] 61,306 at 62,280,
reh'g denied, 100 FERC ] 61,331 at P 7, 9 (stating that rate
treatments including hypothetical capital structure were necessary
for the Path 15 project to be built). See also, METC, 105 FERC ]
61,214 at P 20 (Commission recognized the need to encourage, through
regulatory rate-making policy, the independent business model).
---------------------------------------------------------------------------

    125. Several parties, including EEI, NSTAR and NU argue in a
similar vein that hypothetical capital structures can aid investments
by companies that are entering a large capital expenditure program or
are emerging from financial distress and may be aiming for a capital
structure they have not yet realized. Semantic suggests a 75 percent
equity and 25 percent debt capital structure be used to reflect the
higher risks of early adoption of advanced technologies.
    126. PJM and NSTAR state that hypothetical capital structures are
particularly useful for projects involving consortia. PJM cites its
proposed consortium approach to building transmission, where a capital
structure could be based on the project as a whole rather than
piecemeal based on the individual capital structures of each
participant in individual rate cases.\85\
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    \85\ PJM TOs concur that the incentive could be helpful in
project-specific rates.
---------------------------------------------------------------------------

    127. A number of commenters oppose hypothetical capital
structures.\86\ APPA and CREPC argue hypothetical capital structures
could result in a windfall to public utilities by increasing actual
return far in excess of the Commission's allowed return on equity.
Commenters also express concern that the proposed incentive represents
a departure from Commission precedent and could result in unjust and
unreasonable rates.
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    \86\ E.g., California Commission, TDU Systems, APPA, CREPC,
Steel Manufacturers, New Mexico AG, the Oklahoma Commission, PPC,
NECOE, Connecticut AG, and the Delaware Commission.
---------------------------------------------------------------------------

    128. Other commenters, such as the Kentucky Commission, Dairyland
and MISO States, assert that the Commission should preclude a public
utility from receiving both hypothetical capital structure and the ROE
incentive because combining the incentives could result in adopting a
cost of equity well in excess of the DCF range of reasonableness.
    129. Because of concerns about the criteria to be used in
evaluating proposals for hypothetical capital structures, many parties,
including CREPC, California Commission, NRECA and California Oversight
Board, recommend evaluating the proposal on a case-by-case basis, with
California Oversight Board arguing for standard of proof much higher
than merely having to support the proposal as the NOPR proposes.
    130. NECOE states that the Commission should categorically prohibit
vertically-integrated utilities from using a hypothetical capital
structure. MISO States argues that this incentive is not reasonable,
especially if applied to a company's entire rate base, instead of just
its new transmission. APPA states that if a specific transmission
project is financed separately from other projects within a
transmission network (e.g., merchant transmission line), it may be
appropriate to evaluate its capitalization separately from other
affiliates; however, the evaluation should be based on actual
capitalization instead of hypothetical capitalization. In contrast,
Ameren asserts that hypothetical capital structures beyond project-
financed investments can be supported and should be considered on a
case-by-case basis.\87\
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    \87\ Ameren states that the Commission has approved the use of a
hypothetical capital structure to better reflect the risk profile of
a regulated enterprise. See High Island Offshore Systems, L.L.C.,
110 FERC ] 61,043, at P 143, order on reh'g, 112 FERC ] 61,050
(2005) (High Island).
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c. Commission Determination
    131. The Commission finds that hypothetical capital structures can
be an effective tool available to public utilities to foster
transmission investment in appropriate circumstances. As some
commenters point out, use of a hypothetical capital structure is not
new. For example, the Commission has allowed independent transmission
companies to use a hypothetical capital structure to recognize the
significant benefits of independent ownership and operation of
transmission including, among other things, improved access to capital
markets for transmission investment \88\ and the Commission has allowed
its use for specific projects when shown to be necessary for project
financing, among other things.\89\ Further, as PJM argues in its
comments, hypothetical capital structures may be

effective for development of consortium projects. This can be
especially important for projects with a diverse set of sponsors, some
of which have different capital structures, (e.g., a power marketing
agency that contributes access but no equity compared to a project
sponsor that brings only equity to a proposed investment). We note the
rise in interest in these types of projects, including such large-
scale, multiple-developer projects as the Frontier Line and TransWest
proposals. Thus, the Commission finds that, in certain contexts, this
incentive is appropriate for consideration under section 219 because it
has been demonstrated to foster the development of transmission
investment, as indicated by the experience of American Transmission and
Trans-Elect.
---------------------------------------------------------------------------

    \88\ METC, 105 FERC ] 61,214 at P 20.
    \89\ Western, supra note 2.
---------------------------------------------------------------------------

    132. The Commission continues to believe that an overly rigid
approach to evaluating proposed capital structures may discourage the
development of new transmission projects. Therefore, the Commission
will evaluate each proposal on a case-by-case basis but will not
prescribe specific criteria or set target debt/equity ratios for
evaluating hypothetical capital structures, as requested by some
commenters.\90\
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    \90\ We note that many commenters support case-by-case review
and recognize the merits of evaluating the specific circumstances of
hypothetical capital structure proposals.
---------------------------------------------------------------------------

    133. We will not categorically deny the incentive to vertically-
integrated utilities, as recommended by NECOE. We agree with Ameren
that there may be circumstances in which a hypothetical capital
structure may be appropriate for a transmission investment by a
vertically-integrated utility. However, we are not suggesting that
hypothetical capital structures will become the norm. As with the other
incentives, we will require that the applicant demonstrate a nexus
between its proposed incentive and the facts of its particular case.
    134. In this regard, we note that many of the instances in which
hypothetical capital structures are used and can be used reflect unique
circumstances, such as a project or consortium that requires a special
capital structure where the capital structure may change significantly
with new investments. We disagree with TDU Systems that the Commission
has (or should adopt) a general policy on when to use hypothetical
capital structures. Moreover, we do not believe that the Commission's
recent approvals of hypothetical capital structures for electric
transmission companies have resulted in abnormally high equity ratios
or over-compensation for the equity holder at the expense of the
ratepayer.
4. Accelerated Depreciation
a. Background
    135. In the NOPR (at P 30), the Commission proposed accelerated
depreciation as another way to increase cash flow to utilities, thereby
removing a potential disincentive to investing. The Commission has
determined that in some circumstances allowing accelerated depreciation
is warranted to encourage investment in transmission infrastructure
because it provides improved cash flow and better positions public
utilities for longer-term transmission investments.\91\ The Commission
stated that permitting accelerated depreciation more broadly than just
for emergency conditions or special projects may further the goals of
section 219 by providing incentives to undertake transmission projects
that have the potential to reduce the cost of delivered power and
ensure reliability, and, therefore, proposed to allow transmission
facilities to be depreciated over a period of 15 years, in place of the
typical Commission practice to allow depreciation over the useful life
of the facilities.\92\
---------------------------------------------------------------------------

    \91\ See Removing Obstacles and Western, supra note 2.
    \92\ Removing Obstacles, 94 FERC ] 61,272, at 61,968-69.
---------------------------------------------------------------------------

    136. The Commission also sought comment on two issues. The
Commission asked whether 15 years is an appropriate time period for
cost recovery or whether the Commission should establish a presumption
of a shorter or longer depreciable life for new transmission
facilities.\93\ The Commission also requested comment on whether
accelerated depreciation has any longer-term negative impacts that
would undermine the goals of section 219.
---------------------------------------------------------------------------

    \93\ For example, in Removing Obstacles, the Commission
permitted a 10-year depreciable life for facilities that will
increase transmission capacity to relieve existing constraints and
could be in service within a few months.
---------------------------------------------------------------------------

b. Comments
    137. A number of commenters support the proposal to allow
accelerated depreciation of 15 years for the reasons set forth in the
NOPR.\94\ Some of the supporters, such as the Delaware Commission,
KCPL, International Transmission, NYSEG and RGE, Progress, Siemens,
Upper Great Plains, and United Illuminating recommend that the
incentive should be optional.
---------------------------------------------------------------------------

    \94\ E.g., Ameren, EEI, BG&E, FirstEnergy, NSTAR, PG&E, PJM, PJM
TOs, SCE and WPS. Ameren, MidAmerican and Nevada Companies assert
that the Commission should be receptive to a shorter depreciable
life or that a different life may be appropriate, possibly tied to
the term of a service agreement.
---------------------------------------------------------------------------

    138. Other commenters oppose the proposal to allow accelerated
depreciation of transmission facilities.\95\ For example, Connecticut
AG, NECOE and TANC assert the accelerated depreciation incentive will
increase costs and rates and result in gold-plating and over-building
of transmission infrastructure. APPA claims that after new transmission
facilities have been depreciated over the shorter time period proposed
by the Commission, the transmission owners will essentially be
providing transmission service for free. APPA is concerned that when
this happens the transmission owners will propose to ``recalibrate''
(i.e., increase) the transmission rate base to depreciate the same
facilities yet another time at ratepayer expense.
---------------------------------------------------------------------------

    \95\ E.g., TDU Systems, the California Commission, APPA, the
Connecticut AG, NY Association, NECOE, TAPS, the New York Commission
and TANC.
---------------------------------------------------------------------------

    139. Additionally, TAPS opposes accelerated depreciation because
transmitting utilities will no longer earn a return on their
investments after the facility has been depreciated and would
potentially seek to recover a management fee which would deny
ratepayers of the supposed benefits of accelerated depreciation.\96\
TAPS claims that given the likelihood of this management fee, the
Commission cannot refer to accelerated depreciation as a timing
difference. Ameren, on the other hand, states the one drawback to
accelerated depreciation is that once the asset has been fully
depreciated, the public utility can not earn a return.\97\ Ameren
states the Commission should consider generic procedures for the
establishment of compensatory management fees for fully depreciated
transmission assets.
---------------------------------------------------------------------------

    \96\ TAPS cites High Island, 110 FERC ] 61,043, at P 105-115.
    \97\ AEP and International Transmission also note this concern.
---------------------------------------------------------------------------

    140. TAPS also argues that accelerated depreciation would skew
investments towards depreciable plant and away from non-depreciable
land even if acquisition of rights-of-way was the cheaper alternative.
TAPS states that, if the Commission is intent on permitting accelerated
depreciation, the Commission should require the utility to auction off
the fully depreciated facilities at full market value with the proceeds
credited to ratepayers.

    141. California Commission opposes accelerated depreciation because
when a facility is placed into service, the value of the undepreciated
plant is at its highest; therefore, the company earns a high return on
the plant. As a result, the company has immediate cash flow that does
not need to be enhanced. California Commission, TAPS and TDU Systems
express concern that accelerated depreciation may cause generational
inequities between those who pay for the facilities now and those who
do not have to pay later.
    142. EEI states that this incentive should not be dependent on
corporate structure, should not be limited to 15 years when it may be
appropriate to use a shorter depreciable life for certain facilities,
and when 15 years is used by a public utility, the company should be
able to match the tax law depreciation methodology, which weights the
tax depreciation more heavily toward the beginning of the life of the
project rather than spreading it evenly over 15 years.
    143. APPA cites to a number of concerns including the effect of
such accelerated depreciation on book-tax timing differences, and the
associated deferred tax accounts, and complications in calculating
inter-period income tax allocations. APPA also contends that, if the
Commission allows rate recovery over a 15 year life for transmission
assets, then there should be no provision for deferred income taxes
allowed with respect to such assets in any rate case (and no deduction
from rate base), because such book and taxable income with respect to
such assets would then be matched.
    144. International Transmission asserts that in Order No. 618, the
Commission correctly determined that the choice of depreciation method
should be left to industry.\98\ International Transmission argues that
flexibility in determining depreciation methods is particularly
important when new technologies are deployed that may not be proven,
may cost more or have uncertain useful lives, and may be needed to
accommodate ongoing industry restructuring or regulatory innovation.
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    \98\ Depreciation Accounting, Order No. 618, FERC Stats. and
Regs. ] 31,104, at 31,694 (2000) (Order No. 618). According to
International Transmission, in Order No. 618, the Commission
modified its initial proposal to require straight-line depreciation
to permit other methods of depreciation that allocated the cost of
utility property over its useful life in a systematic and rational
manner. The Commission recognized that this approach would ``[allow]
flexibility in a changing business environment.''
---------------------------------------------------------------------------

    145. International Transmission states that accelerated
depreciation does not increase cash flow for companies with formula
rates as it would for companies with stated rates, because the formula
rates reset every year. International Transmission urges the Commission
to clarify that any changes to depreciation rates for a company using a
formula rate will be accepted as a ministerial filing with issues
limited only to estimation of the depreciation life and salvage
parameters; and that an added bonus of this approach would permit
companies with formula rates to remove from their formula rates, in
ministerial filings, accumulated deferred income tax balances from rate
base. International Transmission argues that to do so would increase
cash coverage ratios and the return on equity during the early years of
an asset's life and thereby create a tax-related incentive that
furthers the Congressional intent to encourage transmission
investment.\99\ International Transmission states that if it allows
companies to use accelerated depreciation, the Commission will need to
revisit its Accounting Directive in Order No. 618, in which the
Commission stated that recovery over the useful life generally best
matches benefits with costs. International Transmission offer that
accelerated depreciation could lead to the following problems: (1)
Depreciation would no longer be representative of the useful life of
assets, (2) the representation of net fixed asset value in financial
statements could be distorted; (3) there would be a divergence between
Generally Accepted Accounting Principles and Commission reporting and
(4) efforts by FASB, the Commission and others to clarify financial
reporting could be frustrated.
c. Commission Determination
---------------------------------------------------------------------------

    \99\ International Transmission notes that Congress reduced the
tax depreciable life on transmission investments from 20 years to 15
years to encourage transmission investment. EPAct 2005, section
1308.
---------------------------------------------------------------------------

    146. After considering all comments, we will adopt the NOPR
proposal to allow, as an option, accelerated depreciation for new
transmission facilities that meet the goals of section 219. Accelerated
depreciation increases the cash flow of public utilities thereby
providing an incentive to undertake transmission investment. However,
we are not proposing to grant accelerated depreciation on a generic
basis; rather, as with the other incentives, the applicant must
demonstrate a nexus between its proposal and the facts of its
particular case (e.g., the need for additional cash flow produced by
accelerated depreciation in order to fund new transmission investment).
    147. We do not share the commenters' concerns that this incentive
will result in intergenerational inequity. Most transmission customers
are dependent upon the transmission system serving them and are likely
to continue to receive transmission service over the long-term. Thus,
unlike in power supply situations where there are greater options to
change suppliers, there is little likelihood of intergenerational
impact through the use of accelerated depreciation for transmission
investment. In the event accelerated depreciation results in higher
rates in the near-term, most of the same customers paying the higher
rates will benefit from lower transmission rates in the longer-term. We
clarify that the use of accelerated depreciation may be proposed for
new transmission facilities including additions to capacity on existing
facilities.
    148. Given the long-term under-investment in transmission, we
disagree with the comments of the California Commission that existing
policy is sufficient to encourage transmission investment in all
situations. As the California Commission is aware, Trans-Elect stated
that accelerated depreciation was a necessary component for its
participation in the Path 15 project. In response to the mandate of
section 219, we believe it is appropriate to offer this rate treatment
more broadly to encourage the same successful outcome that was achieved
with Path 15. This does not mean that accelerated depreciation is
necessary or will be granted for every project. Instead, the applicant
will be required to demonstrate that there is a need for the additional
cash flow produced by the accelerated depreciation or that the
incentive is appropriate for other reasons. Likewise, at this juncture,
concerns expressed by some commenters about the potential for
overbuilding of transmission facilities as a result of this rate
treatment are unsupported and highly speculative.
    149. We concur with the comments that suggest the need for
flexibility in the length of the depreciable life. Therefore, public
utilities may propose using accelerated depreciation for rate purposes
over a period of time as short as 15 years. Moreover, we will consider,
on a case-by-case basis, depreciable lives of less than 15 years
because shorter depreciable lives may be appropriate in certain cases,
such as advanced technologies for which the useful life is not
necessarily known.
    150. Based on the comments, we are mindful of the potential
consequences of this rate treatment when the facilities are fully
depreciated. Commenters

express concern that the Commission will allow public utilities to
recalibrate the amount of depreciation, or institute a management fee.
Other commenters state the Commission should require certain rules for
sale of the facilities because of complications that will arise from
selling fully depreciated assets. We will not address those issues here
but will address such issues if and when they occur.
    151. Commenters raise various accounting issues. With respect to
the effect of this rate treatment on ADIT (accumulated deferred incomes
taxes), we disagree that this proposal will necessarily require that no
provision for deferred incomes taxes be allowed with respect to such
assets (and no deduction from rate base). As stated previously, we are
going to be flexible with respect to the depreciable lives of
qualifying assets; therefore, public utilities may choose 30 years as
Trans-Elect did with Path 15 and as a result deferred income taxes may
still be necessary. Moreover, even if public utilities choose 15 years,
depreciation expense for rate recovery purposes will likely be
calculated using the straight-line method over those 15 years,\100\
while accelerated depreciation for tax purposes may be calculated using
a different method (e.g., double declining balance) over 15 years.
Therefore, despite the use of the same 15 year life, method differences
could continue to create timing differences for which deferred income
taxes would be required.
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    \100\ The straight-line method is typically used by utilities
and will likely continue to be used for most utility property.
However, consistent with Order No. 618 we will not require its
universal use, as they may be overly prescriptive. Order No. 618 at
31,694.
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    152. With respect to APPA's concern about potential difficulties in
applying SFAS 71,\101\ the Commission and other rate regulatory
authorities often include amounts in allowable costs for ratemaking
purposes in periods other than the period in which those amounts would
ordinarily be charged to expense or included in income for financial
accounting purposes. In those instances, the rate actions of regulators
have economic consequences that must be recognized in financial
statements. Under both SFAS 71 and the Commission's Uniform System of
Accounts, if regulation provides reasonable assurance that incurred
costs will be recovered in future periods, companies must capitalize
the costs. If current recovery is provided for costs that are expected
to be incurred in the future, companies must recognize the current
receipts as a credit amount on the balance sheet. Therefore, because
the accounting requirements for accelerated depreciation are no
different than accounting for the economic consequences of other rate
actions, we do not see an impediment to implementing accelerated rate
recovery of transmission assets.
---------------------------------------------------------------------------

    \101\ SFAS 71 applies to general-purpose external financial
statements of an enterprise that has regulated operations. The
Commission's Uniform System of Accounts for Public Utilities and
Licensees (18 CFR Part 101) contains provisions similar to SFAS 71
that apply to financial statements public utilities must file with
the Commission.
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    153. We are not persuaded that we need to revisit Order No. 618 in
this proceeding as some commenters suggest. In Order No. 618, the
Commission established standards for determining depreciation expense
for book purposes. Here we are establishing a standard for determining
depreciation expense allowable for rate purposes. Although accounting
and cost-based rate setting generally share common standards, there are
instances, and this is one, where different standards should be used by
each discipline and the difference bridged by recognition of regulatory
assets or liabilities as provided for in our Uniform System of
Accounts.\102\ Therefore, companies will continue to depreciate
transmission assets over their economic service life in a systematic
and rational manner for accounting purposes and separately recognize as
a regulatory liability any difference between depreciation expense
recognized for accounting purposes and accelerated depreciation expense
included in the development of rates. In order to clarify this
distinction the Commission shall revise Sec.  35.35(d)(1)(v) of the
regulatory text proposed in the NOPR which read ``(v) accelerated
regulatory book depreciation.'' The revised regulatory text shall read
``(v) accelerated depreciation used for rate recovery.''
---------------------------------------------------------------------------

    \102\ 18 CFR part 101.
---------------------------------------------------------------------------

    154. We deny International Transmission's request to alter our
section 205 filing requirements for public utilities operating under
formula rates. In Order No. 618, the Commission permitted utilities to
not make a filing to change depreciation rates for accounting purposes
but maintained the filing requirement for changes in depreciation rates
for rate purposes.\103\ The Commission said it would monitor changes in
depreciation rates for accounting purposes when companies filed for
rate changes. We decline in this Final Rule to adopt International
Transmission's requested changes to formula rates. International
Transmission is free to petition the Commission to revise its formula
rate to allow flexibility going forward, but we decline to make such a
generic determination here because to do so would presume that all
formula rates worked in the same manner.
---------------------------------------------------------------------------

    \103\ Order No. 618 at 31,695.
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5. Recovery of Costs of Abandoned Facilities
a. Background
    155. The Commission noted that public utilities, in considering
investments that fulfill the requirements of FPA section 219, may
encounter investment opportunities with significant risk associated
with factors beyond their control, such as generation developers'
decisions to develop or terminate the development of potential
resources or difficulty obtaining state or local siting approvals. In
these circumstances, the Commission stated that it may be appropriate
to consider ways to reduce the risk associated with potential upgrades
or other improvements to the transmission system. To reduce the
uncertainty associated with higher risk projects, thereby facilitating
investment in these projects, the Commission proposed allowing recovery
of 100 percent of the prudently incurred costs of transmission
facilities that are cancelled or abandoned due to factors beyond the
control of the public utility.
    156. The Commission's proposal was an extension of a recent
Commission decision to allow Southern California Edison Company \104\
to recover all prudently incurred costs related to certain proposed
transmission facilities if those facilities were later cancelled or
abandoned.\105\ The Commission noted that the company's management did
not control the decision to develop or cancel the wind farm generation
project and that the company's shareholders did not share in the
earnings associated with the generation project. The

Commission further determined that the company might be at a higher
risk in developing the project because of factors beyond its control.
It also noted that SCE was not a wind farm developer and therefore
would not directly benefit from the facilities. Thus, the Commission
concluded that SCE should not shoulder the risk of the project.\106\
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    \104\ SCE, 112 FERC ] 61,014 at P 58-61, reh'g denied, 113 FERC
] 61,143 at P 9-15.
    \105\ Prior to SCE, the Commission's policy with respect to
recovery of cancelled plant costs provided that 50 percent of the
prudently incurred costs of a cancelled generating plant should be
amortized as an expense over a period reflecting the life of the
plant if it had been completed and that the remaining 50 percent of
the prudently incurred costs of the cancelled plant should be
written off as a loss. Under this policy, ratepayers are entitled to
the income tax deduction associated with that portion of the loss
for which they are paying. In addition, they are entitled to a rate
base reduction to reflect the accumulated deferred income tax
amounts associated with 50 percent of the abandonment loss. See New
England Power Co., Opinion No. 295, 42 FERC ] 61,016 at 61,068,
61,081-83, order on reh'g, 43 FERC ] 61,285 (1988). See also, Public
Service Company of New Mexico, 75 FERC ] 61,266 at 61,859 (1996)
(PSNew Mexico).
    \106\ SCE. at P 61.
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b. Comments
    157. A number of commenters support the 100 percent recovery of
prudently incurred costs of transmission projects that must be
abandoned for reasons beyond the transmission provider's control as a
way to reduce the up-front risk associated with important regional
projects.\107\ Some, like the Kentucky Commission,\108\ advocate that
the Commission should adopt a case-by-case approach to recovery of
costs related to cancelled plant.\109\ Kentucky Commission agrees that
this incentive should be evaluated on a case-by-case basis to ensure
that the decision to abandon the facility was truly beyond the
utility's control. California Commission and CADWR do not oppose the
recovery of 100 percent of the recovery of prudently incurred costs as
long as the determination is made on a case-by-case basis.
International Transmission states that preliminary surveys and
investigations should also be included in the costs that can be
recovered.
---------------------------------------------------------------------------

    \107\ E.g., AWEA, Ameren, AEP, EEI, KCPL, NSTAR, Vectren,
International Transmission, WPS, APPA, NYSEG-RGE, NorthWestern,
National Grid, New York Commission, NY Association, Progress, PNM
and TNMP, SDG&E, and Upper Great Plains.
    \108\ E.g., California Commission and CADWR.
    \109\ Trans-Elect supports the case-by-case approach and cites
San Diego Gas & Elec. Co., 98 FERC ] 61,332 at 62,408, reh'g denied,
100 FERC ] 61,073 (2002) (``claims for full recovery of any
infrastructure projects that are ultimately cancelled will be
addressed by the Commission on a case-specific basis'').
---------------------------------------------------------------------------

    158. SCE supports the recovery of abandoned plant and recommends
specific standards to facilitate the recovery. SCE states that 100
percent of prudently incurred costs should be approved for recovery if
the facility was initially proposed and sited through a process
involving stakeholder input and the subsequent decision to abandon is
not under the control of management. Additionally, SCE states that
utilities should be able to recover the costs of abandoned plant even
when they have some control over the decision to abandon but the
project was cancelled or abandoned due to problems in obtaining
regulatory or other approvals. SCE also supports recovery where
economic circumstances have changed, causing there to be no
demonstrable net benefits.
    159. Others \110\ oppose the incentive. For example, CREPC states
that guaranteeing the cost recovery of cancelled plant allows investors
to ignore risk and places the risk on parties who are unable to manage
the risk. ESAI argues that allowing recovery of 100% of prudently
incurred development costs runs the risk of producing a proliferation
of white elephants.
---------------------------------------------------------------------------

    \110\ E.g., CREPC, the New Mexico AG, Steel Manufacturers and
TANC.
---------------------------------------------------------------------------

    160. TANC argues that the Commission has upheld and enforced its
existing cancelled plant policy and rejected the utility's arguments
that it be allowed full recovery of the cancelled plant because it
could not get state regulatory approvals; and that the Commission
should not adopt a separate policy now.\111\ TANC argues the proposal
violates the intent of Opinion 295-A which is to encourage investors to
make efficient production and consumption decisions.
---------------------------------------------------------------------------

    \111\ TANC cites PSNew Mexico.
---------------------------------------------------------------------------

    161. Commenters \112\ offer numerous instances where they believe
it would be inappropriate to allow a utility to recover abandoned plant
costs. For example, the Commission should not permit recovery: where
the nature of the project was speculative; and where the project was
abandoned for reasons within the control of the utility; or where there
is an unexpected turn in the economy. TAPS questions whether project
abandonment is really beyond a utility's control if a state siting
authority does not outright reject a proposal but instead conditions
its acceptance in a way that the utility finds objectionable.
---------------------------------------------------------------------------

    \112\ E.g., Industrial Consumers, Oklahoma Commission, PPC, MISO
States, and TAPS.
---------------------------------------------------------------------------

    162. Snohomish asserts applicants must make showings of why the
project failed and recoverable costs should be limited to the original
budget. New Mexico AG, TDU Systems and TAPS assert that if utilities
are guaranteed their investment in abandoned facilities they need a
lower ROE to represent the reduced risk of recovery.
c. Commission Determination
    163. We find that an applicant may request 100 percent of
prudently-incurred costs associated with abandoned transmission
projects can be included in transmission rates if such abandonment is
outside the control of management. This incentive will be an effective
means to encourage transmission development by reducing the risk of
non-recovery of costs.
    164. Many commenters request that we evaluate proposals on a case-
by-case basis and we affirm that we intend to do so. The case-by-case
approach and the limitation to prudently-incurred costs should
adequately discipline investment decisions. However, we will not
prescribe specific rules to govern our evaluation but offer limited
guidance below.
    165. We agree with many commenters that when local, state and
federal (as applicable) siting authorities reject an application
outright, we would view those circumstances, generally, as abandonment
beyond the control of management. As TAPS points out, the situation is
less clear when siting authorities do not reject the application
outright but add conditions to the application that make it
uneconomical or otherwise objectionable. In these instances we would
expect the utility to file with the Commission and support the decision
to abandon. The Commission will evaluate, in these instances, the
change in circumstances from those originally planned on a case-by-case
basis.
    166. We see no need to specify unique application procedures for
this incentive. We will require a section 205 filing for recovery of
abandoned plant costs in rates at the time the project is abandoned. We
disagree with CREPC that this incentive shifts risk from those who can
manage the risk to those who cannot because this incentive is limited
by definition to abandonment that is beyond the control of the utility.
We will not by rule limit the recovery of costs associated with
abandoned plant to the costs included in the original budget estimate.
The Commission will evaluate the public utility's cost recovery to
ensure no double recovery of costs. For example, if a utility already
recovered survey costs by expensing these costs as a pre-commercial
cost, it would be unjust and unreasonable for the utility to recover
those costs again if the facility was subsequently abandoned.\113\
---------------------------------------------------------------------------

    \113\ We also clarify that we maintain the timing of recovery as
set forth in Opinion No. 295 which required recovery over the life
of the asset as if it had gone into service.
---------------------------------------------------------------------------

    167. We will not mandate a reduction in ROE for utilities that
receive approval for this rate treatment. As stated in the ROE
incentive discussion, determinations of a just and reasonable ROE
include risk evaluations made in individual rate proceedings and are
based on the facts pertinent to the utility and its proxy group. We
note, however, that a utility that receives approval to recover
abandoned plant in rate base would likely face lower risk and thus may
warrant a lower ROE than would

otherwise be the case without this assurance.\114\ This does not mean
that the Commission would reject an incentive-based ROE for a project
that also receives assurance of abandoned plant costs that are beyond
the utility's control. We would consider any such request on a case-by-
case basis. The risk of a failed project is only one criteria that
would be evaluated in determining whether an incentive-based ROE would
be appropriate in a given case.
---------------------------------------------------------------------------

    \114\ SCE, supra note 104.
---------------------------------------------------------------------------

6. Deferred Cost Recovery
a. Background
    168. In the NOPR, the Commission stated that public utilities with
a retail rate moratorium may have less incentive to build transmission
facilities that could reduce congestion or ensure reliability because
of concerns about cost recovery for those facilities. Accordingly, the
NOPR proposed to permit such utilities to use a deferred cost recovery
mechanism which allows them to commence recovery of new facility costs
in FERC-jurisdictional rates at the end of a retail rate moratorium. By
providing a mechanism to facilitate cost recovery by public utilities
that build transmission facilities during a retail rate moratorium, the
Commission believed that it would meet the goals of section 219 by
providing certainty to investors that costs can be recovered as quickly
as possible.\115\
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    \115\ The Commission has approved a deferred cost recovery
provision that allowed for the recovery of the cost of new
facilities upon the end of a retail rate moratorium. See Trans
Elect, Inc., 98 FERC ] 61,142, reh'g denied, 98 FERC ] 61,368
(2002).
---------------------------------------------------------------------------

b. Comments
    169. Many commenters support the deferred recovery proposal.\116\
International Transmission states that deferred cost recovery should be
used to facilitate the divestiture of transmission assets to Transcos.
Of those that support the proposal, several urge cooperation between
federal and state regulatory authorities.\117\ In particular, NSTAR and
AEP urge the FERC to collaborate with states and regional state
committees to develop solutions for full and timely cost recovery and/
or be prepared to intervene in state and court proceedings to the
extent state regulators attempt to trap wholesale costs and prevent
recovery of those costs in retail rates. EEI urges the Commission to
ensure that the necessary regulatory mechanisms are in place to allow
cost recovery and should cooperate with the states to develop these
recovery mechanisms including transmission cost recovery tracker
mechanisms.\118\ In EEI's supplemental comments, EEI states that any
utility that constructs new transmission facilities should
automatically be entitled to deferred cost recovery.
---------------------------------------------------------------------------

    \116\ In addition to commenters mentioned below, AEP, Ameren,
KCPL, National Grid, Nevada Companies, NSTAR, NYSEG and RGE, and
Upper Great Plains also support the proposal.
    \117\ E.g., PJM TOs, NSTAR, EEI, and AEP.
    \118\ NU and PEPCO support EEI's comments.
---------------------------------------------------------------------------

    170. Trans-Elect argues that the Commission should allow recovery
of all costs approved for deferred recovery for Michigan Electric
Transmission Company (METC) \119\ and International Transmission.\120\
---------------------------------------------------------------------------

    \119\ See Michigan Electric Transmission Company, 107 FERC ]
61,206 at P12 (2004).
    \120\ See ITC Holdings, 102 FERC ] 61,182 at P 74.
---------------------------------------------------------------------------

    171. TAPS agrees that deferred cost recovery is reasonable in the
case cited in the NOPR in which all connected retail customers pay the
same rates and see the same deferral. However, TAPS asserts that
allowing utilities with stated rates based on old test years to defer
the collection of additional revenues associated with costs related to
new facilities would constitute an unreasonable double-dip and would be
inconsistent with section 219(d). Moreover, because the rates of
bundled retail customers are set elsewhere based on different test
years, this double-dip would be paid only by wholesale customers and
unbundled retail customers and would be unreasonable and unduly
discriminatory.
    172. Several commenters opposing deferred cost recovery cite to
concerns about the effect on state regulation.\121\ Some argue that the
proposal may undermine or impinge on areas exclusively under state
jurisdiction (Pennsylvania Commission cites 16 U.S.C. 824 (a)(b)).
Others allege that the unrestricted ability of a public utility to
defer cost recovery until the end of the rate moratorium may not be
consistent with the spirit of settlements struck as part of rate
freezes.\122\ Pennsylvania Commission adds that all the rate caps in
its state are time-limited and any incremental benefit from a federal
incentive would be more than offset by the legal uncertainty that would
be attached to such incentives and the eventual federal/state conflict
that would ensue.
---------------------------------------------------------------------------

    \121\ E.g., Kentucky Commission, MISO States, Pennsylvania
Commission, and Wyoming Advocate.
    \122\ Similarly, New Mexico AG, California Commission, PPC and
Steel Manufacturers oppose the deferred cost recovery proposal
because of the potential effect on state regulation.
---------------------------------------------------------------------------

    173. MISO States argues that the Commission would do better to work
with state authorities on retail rate recovery issues (e.g., ensure
rate recovery at wholesale and retail) than to adopt a policy
unilaterally.\123\ MISO States comments that Commission statements and
accusations that state-statutory retail rate reviews undermine
incentive ratemaking at the federal level are unwarranted. If the
Commission proceeds with its proposed incentive of allowing deferred
cost recovery, the Commission should consider granting deference to
objections from state-level officials, according to MISO States.
---------------------------------------------------------------------------

    \123\ Steel Manufacturers contends that the Commission should
instead work cooperatively with states on transmission planning
matters, particularly in regional forums, in order to reduce
possible areas for dispute, cost recovery gaps, or duplicative cost
recovery.
---------------------------------------------------------------------------

    174. Other commenters \124\ seek assurance that the Commission will
ensure the company does not over-recover its actual costs; offer that
the Commission should adopt a case-by-case approach to allowing
deferred cost recovery until the end of a moratorium and requiring
agreement by wholesale and retail customers as to the nature, amount
and duration over which the costs are to be deferred and
synchronization of wholesale and retail ratemaking practices to avoid
regulatory price squeeze; \125\ and, argue that the Commission should
place limits on the amount that can be deferred, and initial deferral
period and subsequent recovery period.
---------------------------------------------------------------------------

    \124\ E.g., Municipal Commenters, and APPA.
    \125\ APPA notes that new transmission facility costs that would
be eligible for inclusion as CWIP in rate base should similarly be
eligible for deferred cost recovery to address mismatches in cost
recovery created by retail rate freezes.
---------------------------------------------------------------------------

c. Commission Determination
    175. We find that permitting public utilities under retail rate
freezes to defer recovery of new transmission investment costs
undertaken consistent with section 219 will help facilitate investment.
Increased certainty of cost recovery of new transmission investment
will encourage development of more transmission infrastructure thereby
fulfilling the goals of section 219 of the FPA.
    176. To date, the Commission has approved deferred cost recovery
mechanisms during the formation of Transcos which permitted the new
Transcos to defer recovery of other costs such as the ADIT adjustment
associated with the acquisition of the transmission system and to defer
recovery of the rate differential between the frozen rates and the rate
it would have received. As discussed more fully below, we believe that
Transcos offer significant benefits and the deferred cost recovery

mechanisms that we approved for METC and International Transmission
were helpful to establish those Transcos. We also believe that deferred
cost recovery mechanisms should be available to all public utilities,
not just Transcos and recognize the importance of ensuring that federal
and state ratemaking policies align so that we not only reduce
regulatory lag but facilitate transmission development.
    177. Most of the comments opposing this proposal cite potential
conflicts with state regulation to be a critical issue. We believe that
deferred cost recovery mechanisms generally will not hinder retail
ratemaking. However, if a situation arises where a state regulator
believes that a federal deferred cost mechanism conflicts with a state
goal or undermines a state settlement with the applicant, we will
consider objections by state regulators on a case-by-case basis, and
seek to avoid inconsistencies between state and federal regulation. In
this regard, we note that the approval by the Commission of regional
state committees provides one vehicle for discussing Federal and state
ratemaking issues on a cooperative and regional basis. With respect to
TAPS' concern that the cost of the incentive would be recovered from
only wholesale customers and unbundled retail customers, the Commission
may approve a rate design such that wholesale customers and unbundled
retail customers pick up only a proportionate share of the costs of the
incentive.
    178. With respect to commenters' specific proposals for trackers,
limits, and deferral periods, we decline to adopt such proposals here.
The justness and reasonableness of any deferred cost recovery proposal
will be considered as part of the section 205 filing and there is no
basis to arbitrarily place limits on recovery through this rule. The
intent of the deferred recovery mechanism is to increase the certainty
of cost recovery to encourage more transmission investment. It may also
facilitate the creation of Transcos in states where retail rate freezes
are in place. The deferred recovery mechanism is an option available
for any public utility to propose; a public utility may also propose
the use of a regulatory asset, as suggested by APPA.\126\ We believe
that a public utility must propose a set of incentives that is tailored
to the facts of its particular case and the Commission must review
those proposals to ensure they are just and reasonable.
---------------------------------------------------------------------------

    \126\ Regardless of whether it proposes to use a regulatory
asset, the public utility should explain its proposed accounting for
the deferred recovery mechanism.
---------------------------------------------------------------------------

7. Other Incentives--Single-Issue Ratemaking
a. Background
    179. In the NOPR (at 54), the Commission recognized that
transmission pricing issues are some of the most difficult issues
facing the industry and that the Commission's policy of not allowing
selective adjustments to a cost-of-service may serve as a disincentive
to transmission investment.\127\ Certain applicants may consider the
time requirements and the uncertainties associated with rate
proceedings that encompass their entire transmission systems to be
disincentives to making incentive filings, as specified in the NOPR. To
ensure that the approval process for incentive treatment is as
streamlined as possible, thereby ensuring timely infrastructure
investments, the Commission stated it was willing to consider incentive
filings, applicable to both Transcos and traditional public utilities,
that propose rates applicable only to the new transmission
project.\128\
---------------------------------------------------------------------------

    \127\ See, e.g., City of Westerville, Ohio v. Columbus Southern
Power Co., 111 FERC ] 61,307 at P 18 & n.11 (2005).
    \128\ The NOPR cited Removing Obstacles as an example of one
type of approach utilizing a limited section 205 filing.
---------------------------------------------------------------------------

b. Comments
    180. Numerous commenters\129\ support single issue ratemaking for
the reasons set forth in the NOPR. Additionally, Ameren states that
single-issue ratemaking can be useful in obtaining advance approvals of
specific rate treatments that may be required by investors as a
condition to financing new construction.\130\ Moreover, Kentucky
Commission states that as long as single issue rate cases relate only
to new transmission and comply with the filing requirements set forth
elsewhere in the NOPR, it does not object to this proposal.
---------------------------------------------------------------------------

    \129\ E.g., Ameren, EEI, PJM, Trans-Elect, FirstEnergy,
NorthWestern, MidAmerican, Nevada Companies, AEP, KCP&L, Semantic
and Xcel.
    \130\ See, e.g., Western, supra note 2 (issuing advance
approvals of certain rate treatments for proposed California
transmission Path 15 upgrades).
---------------------------------------------------------------------------

    181. FirstEnergy states this proceeding is analogous to the
Removing Obstacles orders where, in order to facilitate development of
transmission investment the Commission permitted limited section 205
rate applications. FirstEnergy states that in this proceeding, Congress
has realized there is a pressing need for transmission investment and
the Commission should permit limited section 205 rate applications to
facilitate the needed development. FirstEnergy asserts single issue
ratemaking is particularly important for companies using formula rates.
    182. AEP states that the Commission should be flexible with
ratemaking conventions and that single-issue ratemaking could be a
powerful incentive to encourage more transmission investment. AEP also
states that single-issue ratemaking along with transmission cost
trackers at the state level would be productive measures especially
with integrated utilities.
    183. TDU Systems notes that where the Commission has accepted
single issue ratemaking, the Commission required the implementation of
a mechanism that would harmonize the rate increase from that surcharge
with adjustments to rates for existing facilities to reflect the
offsetting decreases in depreciation costs associated with those
existing facilities. EEI agrees that it is important to establish a
crediting mechanism in some cases to harmonize the rate treatment for
new and existing transmission facilities.\131\ PJM, Progress, TAPS and
TDU Systems state that Schedule 12 of the PJM tariff provides an
example of how concerns with single issue ratemaking can be addressed
to implement a $/KW/month adder to network or point-to-point
transmission rates.\132\
---------------------------------------------------------------------------

    \131\ EEI cites Allegheny Power, 111 FERC ] 61,308 at P 54; see
also Request for Rehearing of the PJM Transmission Owners, Docket
No. ER05-513-001, filed on June 30, 2005.
    \132\ PJM and TAPS also cite Allegheny Power (accepting cost
recovery provisions of Schedule 12).
---------------------------------------------------------------------------

    184. TAPS proposes an alternative approach in which the Commission
could harmonize the existing rates and new facility rates, when the
inputs to the existing rate are known (i.e., not hidden in a ``black
box'' settlement), by updating the load divisor and depreciation
reserve, and all other rate components would remain the same (other
than the new facility charge). Where the existing rate was black box, a
load divisor and depreciation reserve would have to be imputed for
these purposes by assuming that the difference between the filed-for
and settled rate represented an adjustment to the rate divisor and
depreciation reserve.
    185. Additionally, if the Commission proceeds with single issue
ratemaking, APPA, TAPS and SCE suggest having the public utility file a
full rate case at some point in the future which would roll-in the
existing rate and the separate

surcharge for the new transmission investment. APPA and TAPS recommend
a full rate case after three years while SCE does not state a specific
deadline for a full rate case.
    186. APPA, NASUCA and TDU Systems oppose single issue ratemaking
for transmission service claiming that public utilities are likely
earning returns on their existing transmission facilities in excess of
previously allowed rates of return (due to load growth, continuing
depreciation of existing transmission facilities, and stale rates).
They argue that single issue ratemaking fails to determine if the
entire transmission rate is just and reasonable. APPA states that to
allow a rate increase for a new facility to be added to the
transmission rates charged for existing facilities improperly mixes
costs from different periods for the same functional class of
facilities. In addition, NASUCA and TDU Systems state that single issue
ratemaking violates section 205 because one rate determinant may often
be accompanied by an associated decrease in other portions of the rate
and failure to consider all rate components together can lead to
overstatements that produce unjust and unreasonable rates.\133\
Further, NASUCA states that waivers of the general rule for a full
blown rate case are found only in limited circumstances, for example
where the utility is merely an accounting conduit for rate changes made
by another utility from which the first utility purchases
services.\134\
---------------------------------------------------------------------------

    \133\ NASUCA cites Arkansas Power & Light Co. v. Missouri Public
Service Commission, 829 F.2d 1444, 1451-52 (8th Cir. 1987) (A state
may determine whether the company has experienced savings in other
areas which might offset the increased price resulting from the
pass-through of the increased wholesale rate).
    \134\ NASUCA cites Panhandle Eastern Pipe Line. v. FERC, 613 F.
2d 1120, 1127 (D.C. Cir. 1979).
---------------------------------------------------------------------------

    187. Municipal Commenters oppose single issue ratemaking because it
represents a departure from cost-of-service ratemaking in that it fails
to demonstrate any nexus between the awarding of proposed incentives
and the owner's overall cost of service, need, financing cost, capital
structure or performance.
    188. TAPS suggests an alternative approach of having companies file
their incentive rate proposals, individually tailored to that utility
where appropriate, but generally applicable to that utility's
qualifying transmission investments. Subsequent facility-specific
filings, as necessary, would merely apply the existing approved plan.
With this approach, single issue ratemaking is unnecessary according to
TAPS.
    189. In the event that the Commission decides to proceed with
allowing single issue ratemaking for new transmission investment
projects, commenters have suggested methodologies for implementing
single issue ratemaking and ways to mitigate any potential problems
with it.
    190. EEI explains that public utilities should be permitted to file
with the Commission to establish a revenue requirement to recover the
costs of constructing a specific new transmission facility pursuant to
section 205. Under this approach, the transmission owner determines
whether to establish a new ROE or use its current Commission-approved
ROE.
c. Commission Determination
    191. We believe that single-issue ratemaking can provide a
significant incentive for achieving the infrastructure investment goals
of section 219 because it can provide assurance that the decision to
construct new infrastructure is evaluated on the basis of the risks and
returns of that decision, rather than the additional uncertainty
associated with re-opening the applicant's entire base rates to review
and litigation. We agree with FirstEnergy that there is a pressing need
for transmission investment and therefore the Commission should allow
for limited section 205 filings as a way to facilitate needed
development, as was approved for the Path 15 project. The Commission's
approval of limited section 205 procedures in Removing Obstacles showed
how useful and appropriate single-issue ratemaking can be for needed
investment in existing facilities, as Trans-Elect attests in their
comments.
    192. We will not require harmonization of rates, roll-in of new and
existing rates or reopening of existing rates in this rule, as
recommended by some commenters. Nor will we specify in this rule the
rate calculations associated with developing a transmission rate for a
particular new facility. Our concern in this rule is to ensure new
investments are not impeded because of existing-system rate issues.
Accordingly, applicants filing for single-issue ratemaking for a
particular project are only required to address cost and rate issues
associated with the new investment in the section 205 proceeding to
approve rates. However, the applicant will be required to fully develop
and support any transmission rate designed to recover the costs of a
particular transmission system facility or upgrade--including cost
allocation and rate design. The Commission will consider the potential
need to combine or reconcile the new rate with any existing
transmission rate when an applicant submits a request for incentives.
In some instances, the Commission may find that single-issue ratemaking
is appropriate without any determination as to when that rate will be
harmonized with existing rates; in other cases, the Commission may, if
appropriate, adopt certain of the mechanisms suggested by the
commenters, such as a requirement to file a full rate case at a date
certain in the future. In each instance, the Commission will balance
the need for new infrastructure, and the importance of permitting
single issue ratemaking in support of that infrastructure, with the
concerns over whether a specific mechanism is required to re-open
existing rates or whether the traditional complaint processes are
sufficient for that purpose.
    193. We find the claims of some commenters that public utilities
are currently earning excessive returns on their existing rates to be
speculative. We have no basis to conclude earned returns are excessive
since these commenters have not submitted section 206 filings alleging
such excessive returns nor do they provide evidence in their pleadings
identifying the companies that are realizing excessive returns.

C. Incentives Available to Transcos

1. Definition of Transco
a. Background
    194. The NOPR (at P 37) proposed to define a Transco as a stand-
alone transmission company, approved by the Commission, which sells
transmission service at wholesale and/or on an unbundled retail basis,
regardless of whether it is affiliated with another public utility. The
Commission invited comments on this proposed definition of Transcos.
b. Comments
    195. AEP and PEPCO support the proposed definition because it
allows a Transco to be affiliated with another public utility. AEP
states that eligible entities should include integrated utility
companies or their affiliates, and PEPCO that the definition of a
Transco should allow for ownership by a single affiliate.
    196. Other commenters support a definition that includes affiliated
Transcos, but only those with passive ownership. Commenters differed on
the level and nature of independence requirements, if any, that should
apply to affiliated Transcos. PJM TOs, for example, argued only for the
same governance requirements otherwise

applicable to Transcos. TAPS, on the other hand, advocates more
specific definitions of affiliated Transcos that would need to meet all
of the standards of the Policy Statement Regarding Evaluation of
Independent Ownership and Operation of Transmission (Policy Statement
Regarding Evaluation of Independent Ownership).\135\ Several
commenters, including APPA and ITC, argue for the benefits of
independence. Vectren opposes the proposed definition of Transco in the
NOPR because by permitting inclusion of transmission owners with
affiliates that own generation and/or distribution, it allows a Transco
to be substantially identical to a vertically-integrated utility.
Vectren questions whether the Commission's policy initiatives would
have more impact on an FPA jurisdictional Transco with generation and
distribution affiliates than on a traditional integrated transmission
owner due to the Transco's parent company's common equity ownership of
transmission and distribution as well as its role in making critical
Transco business decisions. Vectren also argues that holding companies
with Transcos will utilize shared service companies to fulfill common
managerial and administrative functions for Transcos and affiliates.
---------------------------------------------------------------------------

    \135\ ] 111 FERC 61,473 (2005).
---------------------------------------------------------------------------

    197. Commenters differed on whether the level of affiliate
ownership should bear on the definition of a Transco. For example,
Ameren states that utilities exhibiting comparable levels of
independence (and benefits) should be entitled to similar rate
treatments, regardless of organizational structure. Ameren focuses on
the level of functional separation and operational independence of the
Transco--and not the percentage of passive equity ownership. Semantic
requests that the Commission define the maximum permitted traditional
utility ownership allowed in a Transco.
    198. Some commenters, including TransCanada and American
Transmission, advocate flexibility regarding ownership in the proposed
definition. NSTAR, National Grid, and OMS contend that the Commission's
proposed definition of Transco is overly restrictive in applying only
to companies that are solely transmission providers. They argue that
transmission and distribution companies that have taken significant
steps toward independence by divesting of generation and marketing
activities be similarly rewarded.
    199. Due to concerns about competition for capital within Transcos,
TDU Systems states only Transcos with strict limits on investments in
other industries should receive incentive rates. APPA states that
Transcos must have access to sources of equity capital other than their
affiliates, such as through issuance of new equity or through capital
contributions from a diverse base of Load Serving Entity owners.
    200. Semantic states that the definition of Transco should be
broadened to include entities that deliver services using advanced
transmission technologies recognized in section 1223(a) of EPAct 2005,
such that a Transco need not directly participate in the flow of
energy. A Transco could be an ``Advanced Technology Transco'' that
delivers enhanced grid state data processed by analytical software.
c. Commission Determination
    201. We will adopt in the Final Rule the definition from the NOPR
that a Transco is 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. This definition includes the
flexibility advocated by some commenters and allows the Commission to
consider various business models and arrangements.
    202. The definition we adopt here does not exclude affiliated
Transcos with active ownership by market participants, or stand-alone
transmission companies that own transmission and distribution
facilities. However, we expect applicants to demonstrate the value of
their particular affiliated Transco proposal. We will consider the
eligibility of such arrangements based on a showing of how the specific
characteristics of a proposed Transco affect its ability and propensity
to increase transmission investment and lead to increased transmission
investment similar to the Transcos we have already approved. We note
that the three Transcos established thus far--which have all
demonstrated their willingness and ability to invest in new
transmission--are either not affiliated with any market participant
(e.g., International Transmission and METC) or have joint ownership and
board membership by a number of market participants and independent
members (e.g., American Transmission). Concerns regarding affiliated
Transcos, such as those voiced by Vectren, or support for companies
that own transmission and distribution or other business structures,
will be considered in the context of specific applications for
incentive treatment.
    203. In addition, because we do not wish to preclude entities that
may help foster investment in needed transmission infrastructure simply
because they have not yet been proposed or evaluated, we will not
establish specific limits on Transcos regarding, for example, business
investments in other industries, sources of equity, or levels of active
and passive ownership.
    204. We also clarify that an entity's status as a Transco will not
be conditioned on membership in an ISO or RTO. As the Commission
explained in the NOPR, just as the need for investment is a national
need, we believe that the expansion and investment objectives of new
FPA section 219 are best met by a definition of Transcos that does not
restrict the formation of Transcos to only certain organized markets.
Similarly, we clarify that an applicant that receives an incentive
related to its status as a Transco may also request and be eligible for
other generally applicable incentives discussed in the Final Rule, such
as those for joining an RTO or ISO. The Commission will consider the
suitability of multiple incentives at the time of an application.
    205. We will not create a new Transco category that includes
entities that do not own transmission facilities, as requested by
Semantic. Consistent with section 219 the Final Rule applies to rate
treatments for transmission of electric energy in interstate commerce
by public utilities. To the extent Semantic meets this requirement, it
may file an application for incentive treatment and the Commission will
then make its determination of whether the Semantic proposal meets the
requirements of section 219.
2. Transco ROE Incentive
a. ROE Incentive
i. Background
    206. As part of the encouragement of Transco formation, the
Commission stated that it will permit suitably structured Transcos to
receive an ROE that both encourages Transco formation and is sufficient
to attract investment. For example, the Commission approved equity
returns for METC and International Transmission that reflect the
significant benefits that their status as Transcos provide, and these
returns are higher than those approved for integrated entities.
Continuing to allow a higher ROE (that falls within a zone of
reasonableness) in recognition of the benefits Transcos provide is an
appropriate way to ensure the achievement of section 219's objectives.

Therefore, the Commission stated that it will consider the positive
impact Transcos have on transmission investment and in turn on the
reliable or economically efficient transmission and generation of
electricity when it evaluates ROEs proposed by properly structured
Transcos. (NOPR at P 40, footnote omitted)
ii. Comments
    207. Several commenters,\136\ oppose the Commission's proposal to
grant an ROE incentive to Transcos outright. Other commenters\137\
oppose giving Transcos an incentive that is not available to other
business models.
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    \136\ E.g., APPA, Community Power Alliance, Municipal
Commenters, NASUCA, NECPUC, New Mexico AG, NRECA, NU, Pennsylvania
Commission, Snohomish, and TANC.
    \137\ E.g., AEP, BG&E, EEI, First Energy, KCPL, MidAmerican and
PacifiCorp, Midwest ISO, NECPUC, Northwestern, PEPCO, PJM, PJM TOs,
PPC, Progress Energy, SCE, Southern Companies, and Vectren.
---------------------------------------------------------------------------

    208. Those opposing the outright grant of ROE incentives to
Transcos\138\ contend, among other things, that: There should be no
equity incentive adders without direct demonstration of customer
benefits; such incentives would unfairly divert capital to Transcos;
and that enhanced Transco ROEs do nothing to solve the problem of
building needed transmission.
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    \138\ E.g., Municipal Commenters, NECPUC, Progress Energy,
Snohomish, PPC.
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    209. Commenters opposing\139\ treatment based on corporate form or
business model suggest that the Commission focus on the purpose and
effect of the proposed investments, not the type of entity that
proposes them. They argue that there is a lack of evidence of how
Transcos encourage transmission infrastructure expansion and the track
record for Transcos is incomplete.
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    \139\ E.g., APPA, Community Power Alliance, FirstEnergy,
Pennsylvania Commission and NASUCA.
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    210. Other commenters raise concerns about the signals the
Commission is sending regarding RTOs and independence of operations,
planning and expansion that can be ensured through other types of
regional transmission groups or through traditional utilities,
particularly those in a RTO with a regional planning process.\140\ EEI,
for example, opposes the Commission managing business models and argues
the Commission should not (even unintentionally) give the impression
through incentives that it seeks to restructure the transmission
sector.
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    \140\ E.g., American Wind, Mid American, PacifiCorp, and EEI.
---------------------------------------------------------------------------

    211. Other commenters offer suggestions as to how to distinguish
incentives. For example, NU and PJM suggest targeting incentives at
companies that are investing in transmission and/or involved in
regional planning, regardless of corporate structure. PJM suggests the
Commission proceed on a case-by-case basis.
    212. Finally, commenters argue that higher ROEs for only some
transmission owners are discriminatory and not just and reasonable, and
have no basis in section 219. Alternatively, some suggest that Transcos
have lower risk than integrated companies and should receive lower
ROEs. Others argue that incentives should cover only new investments
and behavior,\141\ not existing infrastructure. For example, California
Commission opposes providing higher ROEs to Transcos, arguing that
Transco and traditional integrated utility shareholders bear the same
(and only significant) risk as transmission project owners--during the
initial stage of project permitting and developing. SCE offers that
Transco-specific ROEs might actually provide a disincentive for future
Commission-jurisdictional transmission investments by traditional
utilities if they can earn higher ROEs on state-jurisdictional
facilities. TANC offers that a for-profit Transco has no incentive to
make, and, in fact, is discouraged from making, economically efficient
and/or energy efficient investments. Dairyland points out that American
Transmission's plans for substantial investment were made in the
context of a settlement agreement in which American Transmission agreed
to a lower ROE than that approved for Midwest ISO transmission owners
and that the settlement improved American Transmission's cash flow and
reduced its risk, providing a sufficient financial package to enable
its investments even with the lower ROE. Dairyland states that American
Transmission shows that substantial investment by Transcos is likely to
occur even if ROEs are reduced.
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    \141\ E.g., New Mexico AG, NRECA, Pennsylvania Commission, PG&E,
Vectren, Southern Companies, California Commission, SCE, and TANC.
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    213. Some commenters take issue with the representations in the
NOPR regarding state and federal jurisdiction.\142\ For example,
Community Power Alliance opposes rewarding changes in ownership
structure resulting in transfer of jurisdiction from state to federal
regulators. PEPCO believes the NOPR suggests that traditional utilities
may be treated less well by federal regulators merely because they are
subject to state as well as federal jurisdiction. New Mexico AG states
Transco incentives are nothing more than an attempt by the Commission
to override state regulatory jurisdiction. Nevada Companies state that
the Commission must work with state regulatory authorities to foster
Transco formation.
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    \142\ E.g., Community Power Alliance, PEPCO, NSTAR, and PJMTOs.
TOs.
---------------------------------------------------------------------------

    214. TDU Systems opposes incentive rates for new investment by
Transcos after those Transcos form. If any such award is granted, TDU
Systems argues it be done only upon demonstration of need, and apply
only to system expansions, not existing facilities.
    215. Other commenters,\143\ generally support incentive-based ROEs
to encourage Transco formation. For example, International Transmission
supports incentives for Transco formation and investment not merely to
reward a particular transmission ownership structure but to encourage a
type of transmission ownership that has produced the results that
Congress sought when it enacted section 219. International Transmission
states that both its own specific experience and the track record of
Transcos generally illustrate the benefits of Transco ownership of
transmission.\144\ International Transmission states that if other
forms of transmission ownership invest in transmission in a manner
comparable to Transcos, those other entities should be eligible for
equal incentives, but that until they do, Transco-specific incentives
are fully appropriate.
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    \143\ E.g., International Transmission, KKR, Nevada Companies,
TDU Systems, Trans-Elect and Upper Great Plains.
    \144\ International Transmission states that in the last decade
of Detroit Edison's ownership of the facilities now owned by
International Transmission, Detroit Edison invested about $10
million a year in those transmission facilities that International
Transmission states it invested $41 million on in 2003; $82 million
on in 2004; and over $118 million on in 2005. At the end of 2005,
the net asset value of International Transmission's facilities has
nearly doubled while its CWIP balance remained roughly flat.
International Transmission states that this substantially increased
investment is producing benefits for consumers in enhanced
reliability and increased access to competitively priced generation.
International Transmission states that in the latest Midwest ISO
Transmission System Expansion Plan, the three Transcos in the
Midwest ISO account for 54 percent of the approximately $2.9 billion
in projected investment through 2009. Comparing the level of
projected investment across Transcos and non-Transcos, the average
Transco in the Midwest ISO is investing at over seven times the rate
of the average non-Transco in the Midwest ISO.
---------------------------------------------------------------------------

    216. KKR offers the following potential investment advantages of
Transcos: elimination of competition for capital between generation and

transmission functions; a singular focus on transmission investment
which allows more rapid and precise response to market signals
indicating when and where transmission investment is needed; a lack of
incentive to maintain congestion in order to protect generation market
share; and an enhanced ability to manage assets and access to capital
markets. As stand-alone entities lacking incentive to favor a
particular market participant's generation, Transcos are likely to
attract a variety of new generators, including solar and wind renewable
generation.
    217. KKR states that enhanced ROE can both drive capital investment
and support Transco formation. An enhanced ROE in excess of that
sufficient to support new investment will be factored into the purchase
price of the Transco assets or company and be delivered in whole or in
part to the seller.
    218. Additional comments in support of higher ROEs for
Transcos,\145\ note that Transco formation and investment will occur
when actual Transco returns are equal to or greater than returns for
investments with comparable risk and that these returns must be earned
on a consistent basis.
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    \145\ E.g., Nevada Companies and Trans-Elect.
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    219. Trans-Elect offers suggestions on the manner in which the
incentive could be tied specifically (and exclusively) to the acquired
facilities. In addition, Trans-Elect states that whatever methodology
is used to develop a range of equity cost estimates, use of the mid-
point (or average) of that range would be contrary to the notion of
stimulating new transmission investment. Particularly in the context of
the inherently higher-risk Transco business model, Trans-Elect supports
ROEs toward (or at) the high end of the range.
    220. Upper Great Plains supports Transco incentives but argues they
be limited to what is necessary to put Transcos on an equal footing
with other transmission developers. According to Upper Great Plains,
leveling the playing field will encourage Transcos to more fully
develop the advantages made possible by their business structure.
iii. Commission Determination
    221. After considering all the comments, we adopt in this Final
Rule the proposal from the NOPR to provide to Transcos a ROE that both
encourages Transco formation and is sufficient to attract investment
after the Transco is formed. The incentive ROE does not preclude a
Transco from applying for any other incentive adopted in this rule,
including hypothetical capital structures, ADIT, acquisition premiums,
formula rates or deferred cost recovery. We note that such additional
incentives could aid the formation of Transcos as well as bolster their
ability to add transmission infrastructure. We note, in addition, that
application of the ROE incentive or applicable other incentives will
likely be more efficiently translated into rates for those applicants
that operate under or concurrently propose formula rates.
    222. This decision is based on the proven and encouraging track
record of Transco investment in transmission infrastructure. For
example, International Transmission states that its investment was more
than ten times higher in 2005 than the annual investment by DTE during
the last decade of DTE's ownership of the same transmission
system.\146\ Trans-Elect states that it expended $112 million in
capital on its system from May 2002 through 2005.\147\ Since January 1,
2001, American Transmission states that it has invested approximately
$1 billion in strengthening its system, essentially tripling its
investment in transmission infrastructure in five years.
---------------------------------------------------------------------------

    \146\ International Transmission comments at 21.
    \147\ METC comments at 3.
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    223. The expansion plans of existing Transcos are also encouraging.
International Transmission notes that in the latest Midwest ISO
Transmission System Expansion Plan, the three Transcos in the Midwest
ISO account for 54 percent of the Plan's approximately $2.9 billion in
projected investment through 2009. It also states that comparing the
level of projected investment across Transcos and non-Transcos, the
average Transco in the Midwest ISO is investing at a rate that is over
seven times that of the average non-Transco in the Midwest ISO.\148\
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    \148\ International Transmission Reply Comments at 6.
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    224. As stated in the NOPR, the Commission believes that this
positive record of Transco investment in transmission facilities is
related to the stand-alone nature of these entities.\149\ In
particular, we agree with the comments submitted by KKR explaining the
benefits of the Transco model. By eliminating competition for capital
between generation and transmission functions and thereby maintaining a
singular focus on transmission investment, the Transco model responds
more rapidly and precisely to market signals indicating when and where
transmission investment is needed. We agree that Transcos have no
incentive to maintain congestion in order to protect their owned
generation. Moreover, Transcos' for-profit nature, combined with a
transmission-only business model, enhances asset management and access
to capital markets and provides greater incentives to develop
innovative services. By virtue of their stand-alone nature, Transcos
also provide non-discriminatory access to all grid users.
---------------------------------------------------------------------------

    \149\ NOPR at P 39.
---------------------------------------------------------------------------

    225. Numerous commenters state that the Commission should not favor
one corporate structure (i.e., Transcos) over another. We agree in
part. In the context of the goal to increase investment in needed
transmission infrastructure, it is inappropriate to favor one corporate
structure over another to the extent both business structures have
similar transmission investment records. To date, however, no other
business structure has a transmission investment record similar to that
of a Transco and therefore our incentives that focus on Transcos are
justified. While this rule provides incentives for all public
utilities, the additional incentives for Transcos, in light of their
superior record of adding infrastructure, are neither unduly
discriminatory nor contrary to the goals of section 219.
    226. We believe an incentive ROE for Transcos is justified because
Transcos are spending their additional return on capital spending, as
demonstrated by the negative cash flow profiles of the current Transcos
and their future capital spending plans, as discussed in the comments
of the Transcos and KKR. Though Transcos have demonstrated that they
will build transmission, and plan to build more in the future, we agree
with commenters that state that our focus should be on actual results--
i.e., getting transmission built. Currently, Transcos are spending
capital aggressively, reinvesting any earned returns and spending a
significant amount more than they are earning. However, continuing to
allow a Transco, over the long-term, to receive an incentive ROE for
all its facilities that recognizes its increased transmission
investment only makes sense if the Transco continues to provide the
benefits which we are trying to incentive. Therefore, as discussed
earlier, we encourage Transco applicants to submit proposals to measure
performance and thereby justify continuation of ROEs (as well as other
rate treatments) that were provided for the purpose of attracting and
sustaining transmission investments.
    227. We disagree with AWEA's statement that single-system Transcos
do nothing for regional goals. Even a single-system Transco can build

infrastructure that significantly aids a broad region. Moreover, to the
extent Transcos belong to transmission organizations, their expansion
plans must be approved by transmission organizations and therefore they
support regional planning goals.
    228. We disagree with Municipal Commenters' contention that the
Transco incentive is misguided as transmission prices have increased
dramatically in regions where the transmission systems were spun off
from investor owned utilities. We have no evidence that Transcos have
increased prices, nor did Municipal Commenters provide supporting
evidence. Nor do we agree Transco formation would simply increase
earnings without any direct demonstration of customer benefits from
such formation. The amount of infrastructure likely to be added by
Transcos will directly benefit customers in the region. Responding to
the Pennsylvania Commission, we have no basis to conclude Transcos may
introduce undesirable biases in grid investment and operations.
Furthermore, like any public utility, their rates remain subject to
review to ensure justness and reasonableness. We therefore have no
basis to change our conclusion that Transcos are appropriate structures
for investment in infrastructure and accomplishment of the objectives
of section 219.
    229. In response to concerns of commenters such as NRECA and the
California Commission that the incentive return for Transcos is not
based on a risk evaluation of Transcos, we believe those concerns are
premature. Such an evaluation is more appropriately part of the section
205 process in individual rate applications of assessing representative
proxy companies and the impact of other factors, including risk.
    230. We expect that providing for deferred cost recovery for
Transcos, such as has been approved for Trans-Elect and International
Transmission, will address Nevada Companies' concern that state-level
rate freezes could preclude recovery of costs associated with divesting
transmission assets to Transcos.
    231. We believe PEPCO and the New Mexico AG have misinterpreted our
statements in the NOPR regarding benefits of federal jurisdiction for
Transcos. The NOPR does not state that a state's jurisdiction over some
of the activities and assets of traditional utilities hinders
investment, as PEPCO maintains. Rather, the NOPR indicated that
Transcos would benefit from having incentive approvals determined in a
single jurisdiction, by eliminating delay and uncertainty. The purpose
of our policy of incentives for Transcos is to build much needed
transmission infrastructure. States continue to have jurisdiction over
the siting of new transmission infrastructure and many of the high
voltage interstate projects will require extraordinary cooperation and
collaboration between state and Federal regulators.
b. Transco Level of Independence
i. Background
    232. The Commission proposed to clarify and broaden the definition
of Transcos to be stand-alone transmission companies approved by the
Commission, without a condition of membership in a RTO or ISO, and
requested comment on how to factor the level of independence into any
request for ROE-based incentives for Transcos. The Commission sought
comment on whether it should specify additional incentive levels within
the zone of reasonableness to correspond to certain levels of
independence and if so, what those amounts should be. The Commission
also sought comments concerning whether membership in an RTO or ISO
should be considered in setting incentive-based ROEs approved by the
Commission for a Transco.\150\
---------------------------------------------------------------------------

    \150\ NOPR at P 42.
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ii. Comments
    233. Numerous commenters \151\ generally support tying the level of
incentives to the level of independence of the Transco. For example,
Ameren proposes a tiered approach to ROE incentives, with Transcos that
are members of an RTO or ISO entitled to the highest ROE incentive.
International Transmission states that it is appropriate to award the
highest ROE-based incentives to Transcos that are truly independent.
KKR states that Transcos that have achieved total structural
independence should receive the most generous set of incentives. MISO
States state that the level of Transco independence is an important
consideration and, accordingly, the Commission could apply a graduated
ROE incentive depending upon the degree of independence between the
Transco and market participants, affiliates or generation.
---------------------------------------------------------------------------

    \151\ E.g., Ameren, AWEA, Connecticut DPUC, International
Transmission, KKR, MISO States, and National Grid.
---------------------------------------------------------------------------

    234. National Grid states that the Commission should establish the
level of ROE-based incentives based on a sliding scale keyed to various
levels of independence for all forms of Transmission Organizations,
with one end of the sliding scale being ``total structural
independence,'' which would be entitled to full incentives.
    235. Trans-Elect states that only entities that establish
independence as to operation, planning, construction and investment
decisions should qualify for ROE-based incentives for Transcos. Rather
than recognizing a ``range'' or ``levels'' of independence that would
justify ``additional incentive levels,'' the Commission should confirm
that entities that meet the definition of Transco would qualify for the
full ROE-based incentive, while those that do not would not be eligible
for the incentive. According to Trans-Elect, it is critical that
Transco ownership arrangements that reflect truly passive ownership
qualify for the full ROE-based incentive and that the independence
standard should be deemed satisfied when passive ownership is
structured to ensure that the Transco will ``operate free of market
participant control or influence.''
    236. TDU Systems supports a policy to prevent a Transco with
passive ownership interests from earning Transco incentives. TDU
Systems assert that should the Commission authorize passive ownership
interests by market participants in Transcos, those relationships
should be rigorously scrutinized. Passive ownership interests by market
participants in Transcos should only be authorized upon a showing that
the option of investment in the Transco is open to all LSEs in the
region up to their load ratio shares, according to TDU Systems, with
governance based on equal and/or equally-weighted votes, if any, for
all passive owners. TDU Systems recommend that the Commission commit to
monitor these relationships in order to deter the potential for abuse.
    237. Some commenters also address whether membership in an RTO or
ISO should be considered in setting incentive-based ROEs approved by
the Commission for a Transco. For example, PEPCO states that the
Commission should not provide additional incentive levels for certain
levels of Transco ``independence'' unless it also provides the same
incentive levels for participants in other models, such as RTOs. MISO
States and PJM believe that the Commission should reverse its proposed
policy of not taking into account if the Transco is a member of an RTO
and instead recognize the positive benefits of Transco membership in
RTOs. AWEA states that incentives for regionalizing the grid through
RTO participation should be an additional incentive.

    238. Others, such as APPA, NRECA, and PG&E support the Commission's
proposal that membership in an RTO or ISO should not be a factor in
setting incentive-based ROEs for Transcos. WPS states that the proposed
incentive for Transcos may be appropriate, but also could be
duplicative if the Transco is an RTO member and also receives an
incentive for that membership.
iii. Commission Determination
    239. We will not establish a specific methodology to factor the
level of independence into any request for ROE-based incentives for
Transcos. We will also not specify additional incentive levels that
remain within the zone of reasonableness, to correspond to certain
levels of independence. While not quantifying a precise formula or
method, we will consider the level of independence of a Transco as part
of our analysis when we determine the proper ROE for the Transco, and
evaluate the specific attributes of a particular proposal, including
the level of independence, to determine appropriate incentives.
    240. Though we are not establishing a range of incentives based on
independence, we note that the three existing Transcos, which have
significantly increased their transmission investment post-formation,
are either totally independent of market participants or can meet the
independence standards in the Policy Statement Regarding Evaluation of
Independent Ownership. Independence is an important component of the
positive contribution of Transcos on investment in needed transmission
infrastructure. A Transco with active ownership by a market participant
or other new business arrangements is also eligible for Transco
incentives to the extent it can show, for example, why active ownership
by an affiliate does not affect the integrity of its investment
planning, capital formation, and investment processes or how its
business structure provides support for transmission investments in a
way similar to the structure of non-affiliated Transcos or Transcos
with only passive ownership by market participants.
    241. In addition, while a Transco need not be a member of an RTO,
ISO, or other Transmission Organization, we will also consider such
membership as part of our evaluation process on the level of Transco
incentives that might be appropriate. We also note that a Transco is
eligible for incentives if it is a member in an RTO, ISO, or other
Transmission Organization.
3. Accumulated Deferred Income Taxes (ADIT)
a. Background
    242. To remove any disincentives that might prevent the sale or
purchase of transmission assets to form Transcos, such as capital gains
taxes on sales of assets,\152\ the Commission (NOPR at P 43) proposed
to include in the rates of Transcos an adjustment to recover ADIT. This
incentive would provide the assurance of recovery in rate base of
adjustments for taxes associated with asset sales, thereby reducing
uncertainty.
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    \152\ See, e.g., International Transmission Co., 92 FERC ]
61,276 at 61,915-16 (2000) (explaining potential disincentives to
sellers and buyers of transmission assets if the ADIT adjustment is
not granted).
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b. Comments
    243. Several Commenters\153\ submitted comments that generally
support the Commission continuing to consider proposals to include
adjustments for ADIT in rates when a Transco is purchasing transmission
facilities. For example, Trans-Elect states that continuing to allow
adjustments for ADIT will eliminate this tax-related disincentive and,
in the process, demonstrate to potential sellers, purchasers and the
investment community the Commission's commitment to promoting
independent stand-alone transmission businesses. National Grid states
that allowing recovery of ADIT is designed to ensure that there is no
financial or tax penalty associated with undertaking the transactions
necessary to form Transcos and therefore the Commission should allow
such recovery to eliminate an obstacle to Transco formation. OMS states
that allowing the ADIT cost recovery adjustment appears more reasonable
than simply authorizing filings to recover acquisition premiums because
the ADIT adjustment premium would be specifically quantifiable and tied
to a specified purpose. International Transmission and Trans-Elect also
specifically support the Commission's clarification that a stand-alone
transmission company that requests an incentive ROE would not be
precluded from also requesting the ADIT adjustment.
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    \153\ E.g., International Transmission, KKR, National Grid,
NorthWestern, OMS, PJM TOs, TAPS, and Trans-Elect.
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    244. Some commenters raise specific concerns regarding how an ADIT
adjustment will be calculated. TAPS states that after the seller is
held harmless for its book-based gain-on-sale tax consequences (if any)
any remaining tax balance should flow back to ratepayers. TDU Systems
state that the ADIT adjustment should be reduced by the seller's ADIT
and investment tax credits associated with the transferred property.
APPA is concerned about the difficulty a buyer of facilities will have
in correctly calculating the ADIT, which is based on the seller's
capital gains tax liability. NRECA states that the Commission needs to
create sufficient safeguards to prevent double recovery. TAPS and APPA
also cite the American Jobs Creation Act of 2004 as substantially
mitigating, and potentially eliminating the ADIT concern.
    245. APPA, PPC and Snohomish state that, in order to get the ADIT
adjustment, buyers of transmission facilities should need to
demonstrate concomitant customer benefits to offset increased
transmission rates resulting from measures to recover capital gains
tax-related acquisition premiums.
    246. PPC and Snohomish state that allowing recovery of ADIT goes
beyond the stated goal of promoting investment in new transmission
capacity, and instead would promote the sale of existing transmission
assets. They contend that allowing purchasers to amortize ADIT in rates
will increase ratepayer costs and allow Transcos to benefit from the
time-value of money without offsetting any actual expenditure. The
value of ADIT should be passed through to customers only if the Transco
is actually making tax payments, and then only in an amount equal to
those payments.
c. Commission Determination
    247. We find that it is appropriate for the Commission to continue
to consider proposals to make 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. This adjustment is simply intended to
remove a disincentive to Transco formation. As explained in the NOPR,
transmission owners are unlikely to sell transmission assets at book
value if they are not held harmless from capital gains taxes on such
sales by including an adjustment for taxes associated with those sales.
Buyers of transmission assets may be unwilling to pay such an
adjustment without some assurance of recovery of the adjustment in
their rate base, as the Commission has addressed in previous Transco-
related orders. In addition, we find appropriate the clarification
proposed in the NOPR that a Transco requesting an incentive ROE not be
precluded from also requesting the ADIT adjustment.

    248. While the Commission will continue to consider proposals to
include adjustments for ADIT in rates when a Transco is purchasing
transmission facilities, we emphasize that we will review such
proposals on a case-by-case basis to ensure that the ADIT adjustment is
just and reasonable and not unduly discriminatory or preferential under
the particular circumstances of the proposal.\154\ Specific concerns
about how the ADIT adjustment is calculated, such as those raised by
TAPS, TDU Systems, APPA and NRECA, can be raised when a proposal is
filed with the Commission. In addition, TAPS' and APPA's concern that
the American Jobs Creation Act of 2004 may eliminate the need for an
ADIT adjustment can be raised as an issue concerning an applicant's
proposed ADIT adjustment in a specific proceeding. We note that, as
there is no sunset date for the incentives, applications could be made
after the potential tax benefits of the American Jobs Creation Act have
lapsed, as the tax law only affects transactions that close by January
1, 2007.
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    \154\ As discussed elsewhere in the Final Rule, an applicant may
propose a number of incentives. Thus, a stand-alone transmission
company is not precluded from requesting ROE and ADIT.
---------------------------------------------------------------------------

    249. We will not require, as requested by APPA, PPC and Snohomish,
that our approval of any ADIT adjustment be conditioned on an analysis
of costs and benefits related to such an adjustment, as discussed
elsewhere in this Rule. We disagree with the implication of PPC that
the Transco purchaser is receiving the benefit for ADIT costs that it
is not really paying. ADIT is part of the purchase price of the
transmission assets sold to the Transco, and hence represents actual
costs to the purchaser.
    250. However, as described more fully in the Performance Test
section, we clarify that continuation of the ADIT adjustment, like
continuation of other incentives, is conditional on the applicant
achieving benchmarks for its own proposed Commission-approved metrics.
4. Acquisition Premiums for Transco Formation
a. Background
    251. The NOPR (at P 55) requested comments on whether the
Commission should make a generic determination that general benefits
would accrue to ratepayers as a result of Transco formation. It also
sought comment on whether any change in the acquisition premium/
ratepayer benefits review at the federal level would risk increased
resistance to such acquisitions at the state level. The NOPR sought
comment on whether there are other mechanisms that the Commission could
institute to provide regulatory certainty of the recovery of the
acquisition premium both through retail as well as wholesale rates. It
also sought comment on what measure the Commission might use in
evaluating the appropriateness of such premiums as measured against,
for example, the size of the premium, the location of the assets, the
level of independence of the Transco, and other relevant factors.
b. Comments
    252. Several Commenters \155\ support a generic Commission
determination that Transco formation benefits consumers and that fair
value paid for transmission assets by a Transco will be recoverable,
even if that fair value exceeds the book value of those assets by a
significant amount. Trans-Elect argues for a case-by-case
consideration, i.e., that a Transco should be entitled to make a
showing that the benefits of a particular transaction justify allowing
a specific acquisition adjustment and that the level of proposed
adjustment is appropriate. KKR supports allowing a Transco Applicant to
recover an acquisition premium in rates for all or a portion of any
premium paid above net book value for purchases of transmission
facilities. PNM encourages the Commission to eliminate its historical
prohibition against recovery of acquisition adjustments for
transmission assets.
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    \155\ E.g., International Transmission, KKR, and Trans-Elect.
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    253. Several commenters \156\ oppose a generic determination
regarding the allowance of acquisition premiums for Transcos, and
generally support the continuation of current Commission policy which,
according to commenters, is case-by-case. They also oppose the
Commission making a general determination that Transco formation
results in general benefits to customers for purposes of determining
whether to allow recovery of an acquisition premium in rates.
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    \156\ E.g., Ameren, APPA, MISO States, Northwestern, NRECA,
Pennsylvania Commission, PEPCO, PJM TOs, Snohomish, TDU Systems, and
WPS.
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    254. In response to our request for comment on what measure to use
to evaluate the appropriateness of such premiums, Pennsylvania
Commission states that if the Commission determines that approval of
acquisition adjustments is necessary to encourage acquisition and
mergers of transmission systems in a business-neutral way, the
Commission should require applicant(s) to demonstrate that such costs
were both reasonable and negotiated at arms' length. According to the
Pennsylvania Commission, the applicant should be required to offer
proof that the purchase price of assets had a reasonable relationship
to the market valuation of the assets transferred, that the buyer and
seller were financially separate and unrelated, and that directors and
officers of, and advisors to, the buyer and seller had a financial and
legal ``arm's-length'' relationship before and after consummation of
the acquisition. International Transmission suggests that recovery of
the difference between book value and fair value, as represented in a
proposed purchase price, be limited to no more than 50 percent of any
amount paid above the book value of the assets, in order to provide
market discipline with respect to the purchase price of the assets.
Snohomish states that there must be a means to independently verify the
purchase price, such as requiring submission of two or more independent
appraisals.
    255. Dairyland supports limiting acquisition adjustments to
situations where the seller of the facilities to a Transco does not
have (or does not simultaneously obtain) an ownership in the Transco.
AEP, PJM TOs and SCE state that if the Commission allows recovery of
acquisition premiums, it should allow all business models to recover
them, including traditional investor-owned utilities.
    256. TAPS and TDU systems argue that entities allowed to recover
acquisition premium for the formation of Transcos should not also be
authorized to receive an enhanced ROE.
    257. Nevada Companies state that the Commission must work with
state regulatory authorities to foster Transco formation since
transmission owners' incentives are reduced if they must give a large
portion of an acquisition premium back to customers.
c. Commission Determination
    258. We will not in this Final Rule change the Commission's policy
of allowing acquisition adjustments in rates only upon a specific
showing of ratepayer benefit.\157\ However, given the positive
contributions of Transcos on transmission investment discussed above,
we find that a Transco may propose an acquisition premium as an
incentive under the Final Rule, as provided under Sec.
35.35(d)(1)(viii). We

will continue to evaluate proposals made by Transcos to recover
acquisition premiums associated with the purchase of transmission
facilities on a case-by-case basis. We appreciate the comments on how
the Commission should evaluate the level of acquisition premiums, such
as those from Pennsylvania Commission, International Transmission, and
Snohomish, and we will take such factors into account in evaluating
whether to allow recovery of particular acquisition premiums. While
this discussion is limited to providing an incentive for Transco
formation, entities other than Transcos can apply for the incentive and
the Commission will evaluate those applications on a case-by-case
basis.
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    \157\ While the proposed ADIT incentive discussed above would
adjust book value and therefore may be considered a premium on net
book value, we note that unlike the acquisition premium discussed
here, the proposed ADIT incentive addresses tax-related issues
outside of the applicant's control.
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5. Merchant Transmission
a. Comments
    259. LIPA states that because of the NOPR's focus on cost-of-
service ratemaking, it has less impact on merchant transmission
developers, whose rates are defined by contract (and thus market
benefit), and not by Commission cost-of-service ratemaking standards.
Merchant transmission developers are generally required to rely on
market rates for transmission service negotiated directly with
purchasers of their capacity, and to assume (along with the purchasers
of their capacity) all of the market risk for their facilities.
Merchant transmission developers will base their decisions on other
factors, particularly their ability to efficiently attain the market
benefits that their investments create.
    260. TransCanada believes that a two-tier subscription process
would provide merchant developers with some initial regulatory and
business certainty by addressing the initial up-front siting and
permitting risk (because of the ability to secure meaningful
commitments from the first tier subscribers). It would also allow for a
full open season for the remainder of the capacity (the second tier)
consistent with current Commission policy.
    261. National Grid states that the key issues raised in this
rulemaking (ensuring adequate returns on equity for investment and
independence, facilitating timely and complete cost recovery, etc.) are
regulated rate issues, which should be of no concern to merchant
transmission developers.
b. Commission Determination
    262. With respect to comments on merchant transmission, we agree
with comments that this issue is beyond the scope of this Final Rule.
Merchant projects are market driven while this final rule deals
fundamentally with regulated transmission rates. True merchant
transmission projects may play an important role in the future of
transmission infrastructure development, but incentives related to, for
example, ROE and cost recovery, do not apply to merchant transmission.

D. Performance-Based Ratemaking

1. General Comments
a. Background
    263. In the NOPR, the Commission sought comments on ways
performance-based ratemaking (PBR) might apply to for-profit Transcos
and traditional public utilities, and not-for-profit Transcos and
public utility ISOs and RTOs. In the case of for-profit entities, the
Commission sought comment on whether there should be mechanisms for
sharing gains with ratepayers and, if so, what those mechanisms should
be. In the case of not-for-profit public utility ISOs and RTOs, the
Commission sought comment on whether and how PBR developed for for-
profit entities might be applied to not-for-profit entities. Finally,
the Commission sought comment on whether performance-based benchmarks
for transmission costs would provide incentives for the deployment of
advanced technologies.\158\
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    \158\ NOPR at P 58.
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b. Comments
    264. Commenters generally support the concept of PBR, especially as
it was defined in the Commission's 1992 Policy Statement on Incentive
Regulation and in Order No. 2000, which emphasize that PBR should be
voluntary, have both an upside and downside, that gains should be
shared with ratepayers, that benefits should be quantifiable, and that
costs to consumers under PBR should not exceed what they would have
been under traditional regulation. They urge the Commission to retain
these principles.\159\
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    \159\ E.g., NASUCA, TDU Systems, Missouri Commission, and SMUD.
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    265. However, citing to current market structure, most commenters
expressed a general lack of enthusiasm for PBR, and none held out any
expectation that PBR would have a significant role to play in providing
consumer benefits. Chief among the obstacles cited to implementing PBR
is a difficulty in determining appropriate performance measures or
benchmarks. For example, KCP&L emphasized that experts, such as EPRI,
are researching appropriate performance measures but have not yet
determined how to account for various factors such as system age and
configuration, geography and customer density, a point of view shared
by many.\160\ Moreover, APPA cautions that poorly designed performance
measures could lead to unintended and undesirable consequences, and it
recommends that the Commission conduct a series of technical
conferences and workshops on PBR before considering any implementation.
The Kentucky Commission states that performance-based benchmarks for
transmission costs are not necessary because any technology that is
beneficial will have an economic reward, thereby providing its own
incentive. The transmission tariff should reflect prudent operation and
maintenance so that, if there is improvement, a greater profit will be
realized. For proven technologies, a sharing of both benefits and the
risks would be appropriate for deployment of new technologies. Thus,
many conclude that the value of PBR seems remote, although voluntary
programs could be worth considering.
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    \160\ E.g., Comments of KCPL, SCE, and EEI.
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    266. Some commenters oppose PBR because they believe it could deter
investment in transmission facilities, contrary to the main objective
of the proposed rulemaking. For example, International Transmission
concludes that PBR might play a limited role in some circumstances, but
warns that some PBR approaches, such as price cap regulation, could
actually discourage investment. Others, such as FirstEnergy and Nevada
Companies are concerned that PBR could increase risk and, thus, reduce
investment. Some commenters believe that PBR might have a limited role
in inducing utilities to adopt certain innovative practices and
advanced technologies,\161\ while other commenters were more concerned
that PBR would discourage reliability and provide unwarranted benefits
to utilities.\162\
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    \161\ E.g., Comments of AEP and UTC Power.
    \162\ E.g., Comments of NSTAR and the New Mexico AG.
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    267. Few commenters see any realistic role for PBR as a means of
inducing cost saving behavior on the part of non-profit entities,
although some, such as Ameren, believe that the Commission's oversight
is inadequate. Industrial Consumers, in particular, express the view
that PBR has no role to play in the non-profit area and, furthermore,
that PBR should not be applied to the profit area unless a proven model
would make pricing under PBR as transparent as pricing under
conventional ratemaking.

Some commenters \163\ stress that safeguards already exist to insure
that ISOs/RTOs are efficient and accountable, and they argue that there
is no urgency to adopt PBR for RTOs/ISOs. Although they could consider
PBR on a limited, case-by-case basis, PJM TOs also emphasize that RTOs
with regional planning processes and requirements outside the
transmission owners' control are poor candidates for PBR.
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    \163\ E.g., NYISO, CAISO, PJM TOs and NECOE.
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    268. Among those commenting most favorably on implementing some
form of PBR were Progress Energy, Southern Company, and National Grid.