[Federal Register: July 31, 2006 (Volume 71, Number 146)]
[Rules and Regulations]
[Page 43293-43341]
[DOCID:fr31jy06-15]

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Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Promoting Transmission Investment Through Pricing Reform; Final Rule

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM06-4-000; Order No. 679]

Promoting Transmission Investment Through Pricing Reform

Issued July 20, 2006.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: In this Final Rule, pursuant to the requirements of the
Transmission Infrastructure Investment provisions in section 1241 of
the Energy Policy Act of 2005, which adds a new section 219 to the
Federal Power Act, the Federal Energy Regulatory Commission
(Commission) is amending its regulations to establish incentive-based
(including performance-based) rate treatments for the transmission of
electric energy in interstate commerce by public utilities for the
purpose of benefiting consumers by ensuring reliability and reducing
the cost of delivered power by reducing transmission congestion. This
Final Rule is intended to encourage transmission infrastructure
investment.

DATES: Effective Date: This Final Rule will become effective September
29, 2006.

FOR FURTHER INFORMATION CONTACT: Jeffrey Hitchings (Technical
Information), Office of Energy Markets and Reliability, Federal Energy
Regulatory Commission, 888 First Street, NE, Washington, DC 20426, 202-
502-6042.
    Sebastian Tiger (Technical Information), Office of Energy Markets
and Reliability, Federal Energy Regulatory Commission, 888 First
Street, NE, Washington, DC 20426,<PHONE_NUMBER>.
    Andre Goodson (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE, Washington,
DC 20426,<PHONE_NUMBER>.
    Tina Ham (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE, Washington,
DC 20426,<PHONE_NUMBER>.
    Martin Kirkwood (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE, Washington,
DC 20426,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

                                                               Paragraph
                                                                 Nos.

I. Introduction.............................................          1.
II. Background..............................................          1.
III. Overview...............................................         10.
    A. The Need for New Transmission Facilities.............         10.
        1. Background.......................................         10.
        2. Comments.........................................         11.
        3. Commission Determination.........................         14.
    B. The Need for Incentives..............................         15.
        1. Background.......................................         15.
        2. Comments.........................................         16.
        3. Commission Determination.........................         19.
    C. Summary of the Nature and Applicability of Incentives         21.
     Adopted by the Final Rule..............................
    D. Effective Date and Duration of Effectiveness For              30.
     Incentives.............................................
        1. Background.......................................         30.
        2. Comments.........................................         31.
        3. Commission Determination.........................         34.
IV. Discussion..............................................         37.
    A. Standard for Approval of Incentive-Based Rate                 37.
     Treatments.............................................
        1. The Final Rule Applies to the Recovery of Costs           37.
         Incurred to Ensure Reliability or to Reduce
         Transmission Congestion, or Both...................
        2. Other Criteria For Approval of Incentives........         44.
        3. Rebuttable Presumptions..........................         57.
        4. Applicants Seeking Incentive-Based Rates Will Not         59.
         Be Required To File A Cost-Benefit Analysis........
        5. Procedural Requirements for Obtaining Incentive-          66.
         Based Rate Treatments..............................
    B. Incentives Available To All Jurisdictional Public             84.
     Utilities..............................................
        1. ROE Sufficient to Attract Capital................         85.
        2. Construction Work in Progress (CWIP) and Pre-            103.
         Commercial Expenses................................
        3. Hypothetical Capital Structure...................        123.
        4. Accelerated Depreciation.........................        135.
        5. Recovery of Costs of Abandoned Facilities........        155.
        6. Deferred Cost Recovery...........................        168.
        7. Other Incentives--Single-Issue Ratemaking........        179.
    C. Incentives Available to Transcos.....................        194.
        1. Definition of Transco............................        194.
        2. Transco ROE Incentive............................        206.
        3. Accumulated Deferred Income Taxes (ADIT).........        242.
        4. Acquisition Premiums for Transco Formation.......        251.
        5. Merchant Transmission............................        259.
    D. Performance-Based Ratemaking.........................        263.
        1. General Comments.................................        263.
        2. Comments Proposing Performance Tests and                 273.
         Competitive Bidding................................
    E. Advanced Technologies................................        280.
        1. General..........................................        280.
        2. Case-by-Case Review..............................        294.
        3. Whether To Require A Technology Statement........        300.
        4. Risk Sharing.....................................        303.
        5. Other Technology-Related Issues..................        308.
    F. Transmission Organization Incentive..................        312.
        1. Background.......................................        312.
        2. Comments.........................................        314.
        3. Commission Determination.........................        326.
    G. Recovery of Prudently Incurred Costs to Comply with          334.
     Reliability Standards and Recovery of Prudently
     Incurred Costs Associated with Transmission
     Infrastructure Development.............................
        1. Background.......................................        334.
        2. Comments.........................................        336.
        3. Commission Determination.........................        343.
    H. Public Power.........................................        349.
        1. Background.......................................        349.
        2. Comments.........................................        350.
        3. Commission Determination.........................        354.
V. Reporting Requirement....................................        358.
    A. Background...........................................        358.
    B. Comments.............................................        360.
    C. Commission Determination.............................        367.
VI. Other Issues............................................        377.
    A. Rate Related Issues..................................        377.
        1. Rate Related Issues..............................        377.
    B. Section 35.34........................................        395.
        1. The Proposal to Eliminate Section 35.34(e).......        395.
VII. Information Collection Statement.......................        406.
VIII. Environmental Statement...............................        410.
IX. Regulatory Flexibility Act Certification................        411.
X. Document Availability....................................        412.
XI. Effective Date and Congressional Notification...........        415.
Appendices..................................................

Before Commissioners: Joseph T. Kelliher, Chairman; Nora Mead Brownell,
and Suedeen G. Kelly.

I. Introduction

    1. Pursuant to the directives in section 1241 of the Energy Policy
Act of 2005 (EPAct 2005) \1\ which added a new section 219 to the
Federal Power Act (FPA), in this Final Rule the Commission provides
incentives for transmission infrastructure investment that will help
ensure the reliability of the bulk power transmission system in the
United States and reduce the cost of delivered power to customers by
reducing transmission congestion. The Rule does not grant outright any
incentives to any public utility, but rather identifies specific
incentives that the Commission will allow when justified in the context
of individual declaratory orders or section 205 filings by public
utilities under the FPA. A number of these incentives reflect
departures from what the Commission has permitted in the past and a
willingness to consider much greater flexibility with respect to the
nature and timing of rate recovery for needed transmission
infrastructure. While the Commission in recent years has permitted
higher rates of return and deviations from past ratemaking practices in
a few individual transmission infrastructure cases,\2\ we here
determine generically that these types of ratemaking options and others
should be considered on a broader basis for those applicants that can
demonstrate that their infrastructure proposals meet section 219
requirements.
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    \1\ Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat.
594, 315 and 1283 (2005).
    \2\ See Western Area Power, 99 FERC ] 61,306, reh'g denied, 100
FERC ] 61,331 (2002) (Western), aff'd sub nom. Public Utilities
Commission of the State of California v. FERC, 367 F.3d 925 (D.C.
Cir. 2004); Michigan Electric Transmission Co., LLC, 105 FERC ]
61,214 (2003) (METC); American Transmission Company, L.L.C., 105
FERC ] 61,388 (2003) (American Transmission); ITC Holdings Corp.,
102 FERC ] 61,182, reh'g denied, 104 FERC ] 61,033 (2003) (ITC
Holdings).
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    2. In reaching our determinations in this Final Rule, we have
considered comments that reflect widely divergent views with respect to
whether and when utilities should receive incentives and what they must
demonstrate in order to receive particular incentives. As noted, the
Rule does not grant incentives to any public utility but instead
permits an applicant to tailor its proposed incentives to the type of
transmission investments being made and to demonstrate that its
proposal meets the requirements of section 219. Further, under the
Rule, the Commission will permit incentives only if the incentive
package as a whole results in a just and reasonable rate. For example,
an incentive rate of return sought by an applicant must be within a
range of reasonable returns and the rate proposal as a whole must be
within the zone of reasonableness before it will be approved.
    3. An important component of this Rule is the willingness to
provide procedural flexibility, including the use of expedited
declaratory orders on permitted ratemaking treatments, to help with
financing and up-front regulatory certainty for project investments. We
are particularly attuned to the need for flexibility to support long-
distance interstate projects that significantly reduce the cost of
delivered power by reducing transmission congestion on the interstate
grid.
    4. The Final Rule provides incentive-based rate treatments to any
public utility transmitting electric energy in interstate commerce that
meets the requirements of section 219 and this Final Rule. The
Commission will not limit an applicant's ability to seek incentive-
based rate treatments based on corporate structure or ownership. In
addition, the Final Rule provides additional incentives, to the extent
within our jurisdiction,\3\ to any transmitting utility or electric
utility transmitting electric energy in interstate commerce that joins
a Transmission Organization.\4\ Finally, as explained below, to the
extent our jurisdiction allows, we encourage public power entities to
take advantage of the incentive-based rate treatments outlined in the
Final Rule.
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    \3\ With regard to non-public utilities, although the
Commission's regulatory authority is bound by statute, such entities
could be covered by a public utility's incentive rate proposal by a
separate agreement between the public utility and a non-public
utility. See Bonneville Power Administration, et al. v. FERC, 422
F.3d 408 (9th Cir. 2005).
    \4\ Transmission Organization is defined in 18 CFR 35.35(a)(2)
of this Final Rule as ``a Regional Transmission Organization,
Independent System Operator, independent transmission provider, or
other transmission organization finally approved by the Commission
for the operation of transmission facilities.'' Electric Utility is
defined in section 3(22) of the FPA as ``any person or State agency
(including any municipality) which sells electric energy; such term
includes the Tennessee Valley Authority, but does not include any
Federal power marketing agency.'' 16 U.S.C. 796(22). Transmitting
Utility is defined in section 3(23) of the FPA as ``any electric
utility, qualifying cogeneration facility, qualifying small power
production facility, or Federal power marketing agency which owns or
operates electric power transmission facilities which are used for
the sale of electric energy at wholesale.'' 16 U.S.C. 796(23).
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    5. Some commenters have argued that few or no incentives are needed
to encourage new transmission investment. We reject these comments as
fundamentally inconsistent with section 219. Section 219 reflects
Congress' determination that the Commission's traditional ratemaking
policies may not be sufficient to encourage new transmission
infrastructure. Although section 219 does not permit approval of rates
that are inconsistent with section 205 or 206, section 219 nonetheless
constitutes a clear directive that ``the Commission shall establish, by
rule, incentive-based * * * rate treatments * * * for the purpose of
benefiting consumers by ensuring reliability and reducing the cost of
delivered power by reducing transmission congestion'' (emphasis added).
We therefore cannot simply rely on existing ratemaking policy to
faithfully implement section 219. This Final Rule therefore identifies
a non-exclusive list of ratemaking reforms and requires applicants to
tailor their proposals to fit the facts of their particular case.
    6. We do agree, however, with the position of certain wholesale
customers and state commissions that the Commission should not provide
incentives that only serve to increase rates without providing any real
incentives to construct new transmission infrastructure. Section 219(a)
states that transmission incentives should be ``benefiting consumers by
ensuring reliability and reducing the cost of delivered power by
reducing transmission congestion'' (emphasis added). The purpose of our
Rule is to benefit customers by providing real incentives to encourage
new infrastructure, not simply increasing rates in a manner that has no
correlation to encouraging new investment. The Final Rule, therefore,
makes clear that not every incentive identified herein will be
necessary or appropriate for every new transmission investment. To
provide guidance in this regard to potential applicants, we discuss
below why certain incentives may, as a general matter, be better
tailored to certain types of investments than others.

II. Background

    7. Section 219 of the FPA requires the Commission to establish, by
rule, incentive-based (including performance-based) rate treatments for
the transmission of electric energy in interstate commerce by public
utilities for the purpose of benefiting consumers by ensuring
reliability and reducing the cost of delivered power by reducing
transmission congestion. Section 219(b) requires that the rule:

    1. Promote reliable and economically efficient transmission and
generation of electricity by promoting capital investment in the
enlargement, improvement, maintenance, and operation of all facilities
for the transmission of electric energy in interstate commerce,
regardless of the ownership of the facilities;
    2. Provide a return on equity that attracts new investment in
transmission facilities (including related transmission technologies);
    3. Encourage deployment of transmission technologies and other
measures to increase the capacity and efficiency of existing
transmission facilities and improve the operation of the facilities;
and
    4. Allow the recovery of all prudently incurred costs necessary to
comply with mandatory reliability standards issued pursuant to section
215 of the FPA, and all prudently incurred costs related to
transmission infrastructure development, pursuant to section 216 of the
FPA (transmission national interest corridors).
    8. Section 219(c) requires that the Rule provide for incentives to
each transmitting utility or electric utility that joins a Transmission
Organization and to ensure that any recoverable costs associated with
joining may be recovered through transmission rates charged by the
utility or through the transmission rates charged by the Transmission
Organization that provides transmission service to the utility.
Finally, section 219(d) provides that all rates approved under the Rule
are subject to the requirements of sections 205 and 206 of the FPA,\5\
which require that all rates, charges, terms and conditions be just and
reasonable and not unduly discriminatory or preferential.
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    \5\ 16 U.S.C. 824(d) and 824(e) (2000).
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    9. Congress directed the Commission to issue a Final Rule
establishing incentive-based rate treatments for transmission
construction within one year of enactment of EPAct 2005, or by August
8, 2006. The Commission issued a Notice of Proposed Rulemaking (NOPR)
on November 18, 2005 seeking comment on the Commission's proposal to
comply with section 219.\6\ In the NOPR, the Commission proposed to
amend Part 35 of Chapter I, Title 18 of the Code of Federal Regulations
by eliminating paragraph 35.34(e) under Subpart F and adding paragraph
35.35 under Subpart G. The Commission received several hundred pages of
comments. A list of the commenters appears in Appendix B. As explained
below, based on the comments filed, the Commission clarifies and adopts
the proposed regulations in the NOPR.
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    \6\ Promoting Transmission Investment Through Pricing Reform, 70
FR 71409 (Nov. 29, 2005), FERC Stats. & Regs., Proposed Regs. ]
32,593 (2005).
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III. Overview

A. The Need for New Transmission Facilities

1. Background
    10. As indicated in the NOPR, investment in transmission facilities
in real dollar terms declined significantly between 1975 and 1998.
Although the amount of investment has increased somewhat in the past
few years, data for the most recent year available, 2003, shows
investment levels still below the 1975 level in real dollars.\7\ This
decline in transmission investment in real dollars has occurred while
the electric load using the nation's grid more than doubled.\8\
Further, the record shows that the growth rate in transmission mileage
since 1999 is not sufficient to meet the expected 50 percent growth in
consumer demand for electricity over the next two decades.\9\
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    \7\ EEI Survey of Transmission Investment: Historical and
Planned Capital Expenditures (1999-2008) at 3 (2005).
    \8\ Barriers to Transmission Investment, Presentation by Brendan
Kirby (U.S. Department of Energy, Oak Ridge National Laboratory),
April 22, 2005 Technical Conference, Transmission Independence and
Investment, Docket No. AD05-5-000 (April 22, 2005 Technical
Conference).
    \9\ Energy Policy Act of 2005: Hearings before the House
Subcommittee on Energy and Commerce, 109th Congress, First Sess.
(2005) (Prepared statement of Thomas R. Kuhn, President of EEI).
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2. Comments
    11. Many commenters agree that there is a significant need for new
investment in transmission facilities. EEI states that, although
increases in transmission investment are predicted over the 2004 to
2008 period, the industry still has not reached the optimal level of
investment.\10\ International Transmission notes that growth in
transmission capacity has lagged behind the growth in peak demand over
the last three decades and this trend is projected to continue through
at least 2012.\11\ International Transmission cites to studies
estimating the cost of power interruptions and fluctuations to range
from between $29 billion and $135 billion annually,\12\ the cost of the
August 2003 Northeast-Midwest blackout to be between $4 billion and $10
billion,\13\ congestion costs of $4.8 billion in the ISO/RTO markets of
California, New York, New England, the Midwest and PJM for 1999 to
2002,\14\ and increases in PJM congestion costs, from $499 million in
2003 to $808 million in 2004.\15\
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    \10\ 2004 State of the Markets Report, Federal Energy Regulatory
Commission, Staff Report by the Office of Market Oversight and
Investigations, June 2005, at p 27.
    \11\ See Eric Hirst, U.S. Transmission Capacity: Present Status
and Future Prospects, a study prepared for EEI and the U.S.
Department of Energy Office of Electric Transmission and
Distribution, June 2004 (Hirst) and Keeping Energy Flowing: Ensuring
a Strong Transmission System to Support Consumer Needs for Cost-
Effectiveness, Security and Reliability, a report of the Consumer
Energy Council of America, Transmission Infrastructure Forum,
January 2005. See also Affidavit of Jon E. Jipping, Exhibit A to the
Reply Comments of International Transmission (the transmission
system purchased in Michigan was 2.5 to 7 years behind schedule in
maintenance on key transmission facilities).
    \12\ Kristina LaCommare and Joseph Eto, Understanding the Cost
of Power Interruptions to U.S. Electricity Consumers, Lawrence
Berkeley National Laboratory (September 2004) at xiv.
    \13\ See Final Report on the August 14, 2003 Blackout in the
United States and Canada by the U.S.-Canada Power System Outage Task
Force (April 2004) at 1.
    \14\ See Hirst at 8.
    \15\ See 2004 PJM State of the Market Report at 37 (March 8,
2005).
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    12. Many transmission users and state commissions also agree that
there is a need for additional investment in transmission
infrastructure.\16\
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    \16\ E.g., TDU Systems, APPA, and Maryland Commission.
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    13. However, some commenters dispute the need for new transmission
investment. They assert the Commission has overlooked that investment
in transmission has increased in recent years.\17\ They also contend
that investment in transmission by utilities in RTOs and ISOs has been
significant, citing to the approximately $2 billion of approved
spending in PJM since 2000. E.ON U.S. asserts that wide-spread system
shortages have rarely occurred during the past 40 or more years, and
that there does not appear to be any trend line that would suggest that
it is becoming a serious problem now.
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    \17\ E.g., NASUCA and Connecticut DPUC.
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3. Commission Determination
    14. The issue of whether there is a need for new transmission
investment that is sufficient to justify transmission incentives was
put to rest by section 219. Section 219 mandates that the Commission
``establish, by rule, incentive-based (including performance-based)
rate treatments'' and, in doing so, ``promote reliable and economically
efficient transmission and generation of electricity by promoting
capital investment in the enlargement, improvement, maintenance, and
operation of all facilities for the transmission of electric energy in
interstate commerce'' (emphasis added). If this were not enough, the
legislative

mandate of section 219 is supported by abundant evidence, as discussed
above, including the fact that transmission investment in real dollars
terms is lower today than it was in 1975 when the load was
significantly smaller and that, even with the transmission additions of
recent years, the industry still incurs significant congestion costs
due to inadequate transmission.

B. The Need for Incentives

1. Background
    15. In section 219(a) of the FPA, Congress directed the Commission
to establish incentive-based rate treatments to foster investment in
transmission facilities.
2. Comments
    16. Several commenters argue that incentive-based rates are not
necessary to encourage transmission construction or that incentives
will not accomplish the intended goal.\18\ Others assert that reliance
on incentives may increase the price of electricity without any real
benefit.\19\
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    \18\ E.g., APPA, TAPS, NECOE, E.ON U.S., NARUC, and New Jersey
Board.
    \19\ E.g., Connecticut DPUC, NASUCA, NECPUC, Delaware
Commission, Missouri Commission, and New Mexico AG.
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    17. Commenters urge the Commission to limit the scope of any
incentive-based treatments or to adopt mechanisms to ensure that they
have their intended effect. For example, the New Mexico AG and TAPS
assert that the Commission may implement an incentive-based mechanism
by penalizing utilities or RTOs that fail to make investments necessary
to ensure the reliability of the transmission grid. The Delaware
Commission contends that providing incentives without assessing
penalties for failure to meet obligations violates the just and
reasonable standard. NASUCA states that it is unfair to provide
incentives that increase utility profits but do not hold applicants
accountable for performance. The Missouri Commission proposes that the
Commission implement a process that determines performance-based return
on equity. Other commenters recommend that the Commission make approval
of any incentives conditional on the applicant showing a need for the
incentive or that the facility would not have been built absent the
incentive.
    18. In contrast, a number of commenters, including EEI and a large
number of utility and Transco commenters, argue that incentives are
needed to foster investment in transmission facilities. EEI asserts
that incentives are needed to stimulate planning and investment in
national interest electric transmission corridors. NU states that the
many risk factors associated with transmission investments, such as
considerable time delays, negative public opinion of transmission
construction, state siting uncertainties and recovery of project costs,
justify incentives.
3. Commission Determination
    19. Here again, the fundamental issue raised by certain
commenters--whether transmission incentives are necessary to encourage
new infrastructure--was put to rest by the plain language of section
219(a), which requires the Commission issue a rule that adopts
``incentive-based * * * rate treatments.'' Certain commenters urge the
Commission to adopt ``penalties'' in this rulemaking for entities that
do not build sufficient transmission. We decline to do so here.
    20. Other commenters do not oppose incentives outright, but rather
are concerned with the extent to which incentives may increase rates to
consumers. Those concerns are premature. The Final Rule does not grant
incentive-based rate treatments or authorize any entity to recover
incentives in its rates. Rather, it informs potential applicants of
incentives that the Commission is willing to allow when justified.
Before adopting any incentive-based rate treatments for a particular
company, the Commission will need to determine that the applicant has
justified its specific incentive request. In addition, although the
Commission intends to provide flexible procedural mechanisms by which
an applicant may obtain an early determination of which incentives it
may receive (e.g., through an expedited declaratory order proceeding),
before recovering any incentives in its rates, specific rates must be
approved under section 205 of the FPA.

C. Summary of the Nature and Applicability of Incentives Adopted by the
Final Rule

    21. The incentives adopted by this Final Rule are properly
understood only in the context of the traditional regulatory principles
they seek to further. The longstanding rule is that utility rate
regulation must adequately balance both consumer and investor
interests. It is not enough to ensure that investors are properly
compensated, and it is not enough to ensure that consumers are
protected against excessive rates. Our policies must ensure both
outcomes and, in doing so, strike the appropriate balance between these
twin objectives. In striking that balance, the courts have recognized
that there is no single formula for establishing a just and reasonable
rate. Rather, the test is whether the ``end result'' is just and
reasonable.\20\
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    \20\ See FPC v. Hope Natural Gas Co., 320 U.S. 591, 602-03
(1944).
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    22. The traditional policies that we re-examine here reflect both
fundamental precepts: the need to balance investor and consumer
interests and the recognition that there is no single formula for doing
so. For example, in ensuring that rates produce adequate returns for
investors, we do not set a single return on equity for all public
utilities, nor do we presume that there is only one return on equity
that is appropriate for any individual utility. Rather, our precedents
require the establishment of a range of returns and we select an ROE
within that range that reflects the facts and circumstances of a
particular case. Similarly, our policies regarding the recovery of
Construction Work in Progress (CWIP) seek to balance investor and
consumer interests by allowing, in the typical case, 50 percent of CWIP
in rate base. This policy balances investor and consumer interests in
the ordinary case by permitting investors recovery of some construction
costs on a current basis while also protecting consumers against full
rate recovery before a particular facility is placed into service.
    23. Our procedural regulations respecting rate recovery also seek
to balance investor and consumer interests. For example, we allow
public utilities to determine, as a general matter, the timing and
frequency of when to seek a rate increase, which ensures that investors
can file a rate increase when current rates are no longer adequate
(e.g., when the utility is undergoing a large construction program).
However, we also typically require a utility seeking a rate increase to
expose all of its costs to review and therefore do not generally permit
``single issue'' rate filings (selective rate adjustment).
    24. Section 219 requires the Commission to re-examine these and
other policies to determine whether they continue to strike the
appropriate balance in encouraging new transmission investment given
the significant need for new transmission infrastructure in the Nation.
We do so in recognition of the unique and substantial challenges faced
by large new transmission projects. Siting major new transmission lines
is extraordinarily difficult, given the environmental and land use
concerns associated with obtaining and permitting new rights-of-way.
The

experience of American Electric Power Corp. in taking 16 years to
complete construction of a new high-voltage transmission line from
Wyoming County, West Virginia to Jackson Ferry, Virginia represents an
extreme example, but it is illustrative of the significant risks and
challenges associated with siting large new transmission projects.\21\
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    \21\ Although new section 216 of the FPA improves the siting
process for certain new projects, it does not eliminate all risks
faced by such projects nor does it address the risks faced by other
projects that do not reside in a national interest transmission
corridor.
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    25. These challenges and risks are underscored by the fact that, in
many instances, new transmission projects will not be financed and
constructed in the traditional manner. New transmission is needed to
connect new generation sources and to reduce congestion. However,
because there is a competitive market for new generation facilities,
these new generation resources may be constructed anywhere in a region
that is economic with respect to fuel sources or other siting
considerations (e.g., proximity to wind currents), not simply on a
``local'' basis within each utility's service territory. To integrate
this new generation into the regional power grid, new regional high
voltage transmission facilities will often be necessary and,
importantly, no single utility will be ``obligated'' to build such
facilities. Indeed, many of these projects may be too large for a
single load serving entity to finance. Thus, for the Nation to be able
to integrate the next generation of resources, we must encourage
investors to take the risks associated with constructing large new
transmission projects that can integrate new generation and otherwise
reduce congestion and increase reliability. Our policies also must
encourage all other needed transmission investments, whether they are
regional or local, designed to improve reliability or to lower the
delivered cost of power.
    26. To address the substantial challenges and risks in constructing
new transmission, the Final Rule identifies instances where our
regulatory policies may no longer strike the appropriate balance in
encouraging new investment. The Final Rule identifies several policies
that should be adjusted, where appropriate on the facts of a particular
case, to encourage new transmission investment or otherwise remove
impediments to such investment. Although each reform adopted by the
Final Rule constitutes an ``incentive'' as that term is used by section
219, this label has caused some confusion in the comments. It is true
that our reforms adopted in the Final Rule provide ``incentives'' to
construct new transmission, but they do not constitute an ``incentive''
in the sense of a ``bonus'' for good behavior. Rather, as we explain
below, each will be applied in a manner that is rationally tailored to
the risks and challenges faced in constructing new transmission. Not
every incentive will be available for every new investment. Rather,
each applicant must demonstrate that there is a nexus between the
incentive sought and the investment being made. Our reforms therefore
continue to meet the just and reasonable standard by achieving the
proper balance between consumer and investor interests on the facts of
a particular case and considering the fact that our traditional
policies have not adequately encouraged the construction of new
transmission.
    27. A few examples will illustrate this point. The Final Rule
permits higher returns on equity for certain transmission investments.
This may be appropriate in several contexts, such as where the risks of
a particular project exceed the normal risks undertaken by a utility
(and hence are not reflected in a traditional discounted cash flow
(DCF) analysis) and where necessary to encourage creation of a Transco
or participation in a Transmission Organization. However, this does not
mean that every new transmission investment should receive a higher
return than otherwise would be the case. For example, routine
investments to meet existing reliability standards may not always, for
the reasons discussed below, qualify for an incentive-based ROE.
    28. The Final Rule also adopts incentives that are designed to
reduce the risks of new investments. For example, the Final Rule
provides that the Commission will provide assurance of recovery of
abandoned plant costs if the project is abandoned for reasons outside
the control of the public utility. Although this qualifies as an
``incentive'' under section 219, it is perhaps more properly
characterized as reducing a regulatory barrier--the potential lack of
recovery of costs-- to infrastructure development. Moreover, this
reform adequately balances consumer and investor interests because it
is available only when a project is abandoned for reasons beyond the
control of the public utility.
    29. Our Final Rule also adopts certain reforms that affect the
timing of recovery of new transmission investments. Given the long lead
time required to construct new transmission, and the associated cash
flow difficulties faced by many entities wishing to invest in new
transmission, the Final Rule provides that, where appropriate, the
Commission will allow for the recovery of 100 percent of CWIP in rate
base. Here again, we seek to remove an impediment--inadequate cash
flow--that our current regulations can present to those investing in
new transmission. We also will permit, where appropriate, the recovery
of the costs of new transmission through a single issue rate filing
without requiring the public utility to re-open all its transmission
rates to review. We do not, however, suggest that such selective rate
adjustments will be appropriate in all cases, as discussed in more
detail below. Rather, as with each incentive adopted by the Final Rule,
an applicant must show that there is a nexus between its proposal to
make a single issue rate adjustment and the facts of its particular
case.

D. Effective Date and Duration of Effectiveness For Incentives

1. Background
    30. Congress directed the Commission to issue a rule establishing
incentive-based rate treatments no later than one year after enactment
of EPAct 2005, or by August 8, 2006.
2. Comments
    31. Certain commenters urge the Commission to apply the rule to
investments made before August 8, 2005 while others ask the Commission
to apply the rule to investments made after August 8, 2005.\22\ Certain
commenters argue that the Commission should not approve incentives for
facilities that are pending at the time the Final Rule becomes
effective, while others request that the Commission not allow
incentives for investment in facilities that an applicant already has
committed to build or for Transcos that already exist.\23\
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    \22\ E.g., Progress, NEMA, and PG&E.
    \23\ E.g., PG&E, Connecticut DPUC, NASUCA, TDU Systems and TANC.
---------------------------------------------------------------------------

    32. Several commenters argue that, once the incentives have been
granted, the Commission should not eliminate them, or should do so only
under very limited circumstances.\24\ In contrast, others argue that
the Commission should grant incentives for a specific time period or
retain the flexibility to change or review any incentives if it is
found the incentives provide no customer benefit.\25\ The California
Oversight Board requests that any

authorized incentives be subject to refund.
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    \24\ E.g., Progress, NEMA, EEI, Trans-Elect, and National Grid.
    \25\ E.g., TANC, Snohomish, Municipal Commenters, and TDU
Systems.
---------------------------------------------------------------------------

    33. KKR explains that, under certain circumstances, investors in
transmission assets may need favorable rate treatment for a sufficient
period of time to ensure an appropriate return on their capital, i.e.,
for a 15 to 30-year period.\26\ KKR recommends that public utilities
requesting incentive treatment for an extended period into the future
propose criteria that can be used to evaluate that entity's performance
during periodic evaluations. KKR notes that applicants may not always
be able to meet certain proposed metrics due to circumstances beyond
their control. For example, a transmission owner should not lose its
incentive rate treatments if it does not succeed in meeting desired
reductions in congestion because the applicant may not have complete
control of the factors affecting congestion, such as generation
additions, changes in load location and operation of neighboring
systems, and RTO policies. KKR emphasizes that the Commission should
retain the flexibility to assess an applicant's proposal as the facts
and circumstances will vary case-by-case. Finally, KKR recommends that
applicants be required to file a report on their performance every
several years and that the Commission may initiate a proceeding to
review incentives only if the criteria are not met. KKR explains that
frequent reviews run the risk of distorting results due to the
``lumpiness'' of capital investment and the long time periods to make
capital additions and for capital additions to have effects. Further,
KKR states that frequent reviews will make long-term investments more
uncertain and, hence, less likely. In supplemental comments, KKR
asserts that higher ROEs are of material value for Transcos only when
long-term. KKR cites International Transmission as an example, noting
that it is only able to invest in excess of every dollar it earns back
into its system due to the certainty afforded it by its rate compact,
which is long-term, formula-based, and includes a reasonable ROE. The
certainty and long-term horizon of International Transmission's rates
give debt and equity investors in International Transmission comfort
that they will ultimately receive an adequate return on their capital.
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    \26\ See also National Grid and EEI.
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3. Commission Determination
    34. Section 219 of the FPA became effective on August 8, 2005.
Codification of section 219 on that date and the requirement for a rule
authorizing investment incentives provided notice to the industry that
Congress intended that the Commission provide incentive-based rate
treatments promptly. Thus, the Final Rule will become effective 60 days
after publication in the Federal Register. However, we clarify that any
investment made in, or costs incurred for, transmission infrastructure
after August 8, 2005 that ensures reliability or lowers the cost of
delivered power by reducing transmission congestion will be eligible
for incentive-based rate treatments under this Rule. Applicants seeking
incentive-based rate treatments for investments made or costs incurred
after August 8, 2005 will need to satisfy the requirements of this Rule
to obtain and recover any incentives and will need to make an
appropriate filing under section 205.
    35. The fact that a proposed expansion was in a utility's expansion
plan as of August 8, 2005 does not disqualify the project for incentive
treatment. Inclusion of a facility in a plan does not mean that a
project can or will get built. Even where a project already has been
planned or announced, the granting of incentives may help in securing
financing for the project or may bring the project to completion sooner
than originally anticipated. Congress's directive that the Commission
issue a rule within one year of enactment of EPAct 2005 shows that
Congress intended for the Commission to take steps to bring new
transmission on line expeditiously.
    36. With respect to the issue of how long an incentive-based
proposal should remain in effect, the Commission recognizes that it may
be necessary to authorize incentives that may extend over several years
in order to support investment in long-term transmission. It can be
important to investors making long-term investments in long-lived
facilities to be assured that a ratemaking proposal adopted prior to
construction of those facilities will not later be altered in a manner
that undermines the basis for the financing of those facilities. The
Commission will therefore allow applicants to propose specific time
periods by which their incentive-based proposals will not be ``re-
opened'' in a manner incompatible with the nature of the initial
approvals. However, to ensure that ratepayers are also adequately
protected, we will require any applicants seeking such a fixed term for
its plan to explain how ratepayers can be assured that such a plan is
delivering the benefits that formed the basis for the Commission's
initial approval of it. For example, an applicant may propose periodic
progress assessments with appropriate metrics to measure how well the
project is progressing and whether the proposed investment in new
transmission is improving reliability or reducing congestion. Such
metrics would provide the Commission a means to determine whether and
how the applicant is providing the anticipated benefits and thus that
the approved incentives need not be revisited. Because the scope and
size of each project will differ, any applicant seeking incentive-based
rate treatments may propose metrics for its project as well as the
frequency for review of those metrics.\27\ An applicant may include its
proposed metrics and any timetable for review in its section 205 rate
filing seeking recovery of incentives.\28\ Where such metrics are found
to be needed and are approved by the Commission, an applicant would be
required to submit information filings to the Commission consistent
with the approved metrics and timetable. We clarify, however, that the
metrics reviews will not be opportunities to re-argue the issues
addressed in proceedings granting the incentive-based rates; they are
for the purpose of measuring whether the plan is being implemented as
initially approved.
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    \27\ The information may include, as well as supplement,
information provided in FERC-730, discussed in section V below.
    \28\ An applicant has the option to include metrics proposals in
a declaratory order proceeding, but would also need to include them
in the subsequent section 205 rate filing.
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IV. Discussion

A. Standard for Approval of Incentive-Based Rate Treatments

1. The Final Rule Applies to the Recovery of Costs Incurred to Ensure
Reliability or to Reduce Transmission Congestion, or Both.
a. Background
    37. Proposed Sec.  35.35(d)(1) specifies that the Commission will
authorize incentive-based rate treatments for investment by public
utilities, including Transcos, in new transmission capacity that
reduces the cost of delivered power by reducing congestion or promotes
reliability, as demonstrated in an application to the Commission.
b. Comments
    38. Many commenters urge the Commission to be flexible in applying
the incentives.\29\ Southern and the Nevada Companies assert the
Commission should not require that facilities both improve regional
reliability and reduce congestion to be eligible for an incentive ROE.
They

argue that the guiding factor should be to provide incentives that
improve regional reliability and/or reduce transmission congestion. AEP
urges the Commission to adopt a functional approach to determine
whether a project qualifies for incentives. For example, AEP suggests
that projects that connect newer technology generation or renewables be
eligible for incentives. Upper Great Plains contends that incentives
should be available for projects that support the development of new
electric generation in recognition of the expected growth in electric
consumption and the need for additional investment to keep pace.
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    \29\ E.g., FirstEnergy, Southern, Nevada Companies, AEP.
---------------------------------------------------------------------------

    39. Several commenters urge the Commission to establish criteria
for transmission projects to demonstrate that they achieve Congress'
goals before projects receive an incentive.\30\ The New York Commission
asks the Commission to convene a technical conference to develop the
criteria.
---------------------------------------------------------------------------

    \30\ E.g., AEP and New York Commission.
---------------------------------------------------------------------------

    40. The Maryland Commission supports incentives that are forward-
looking and targeted to support electric reliability, competitive
markets and diversity in fuel sources, including renewable resources,
in the short and long term.
c. Commission Determination
    41. The purpose of section 219 of the FPA is to benefit consumers
by promoting transmission capital investments that result in reliable
and economically efficient transmission and generation. Congress did
not enact section 219 in isolation. Section 219 is a part of a larger
statutory framework in which Congress directed the Commission to take
steps to address reliability of the bulk power system as well as to
remedy the adverse effects of transmission congestion. For example, in
new section 215 of the FPA Congress enacted a regulatory regime under
which the Commission will, for the first time in its history, approve
and enforce mandatory reliability standards for the nation's power
grid.\31\ In new section 216, Congress directed the Secretary of Energy
to identify areas of the nation in which transmission congestion
adversely affects consumers (national interest electric transmission
corridors) and gave the Commission certain permitting authority to
ensure timely construction of transmission facilities to remedy
transmission congestion in those corridors. In section 1223 of EPAct
2005, Congress directed the Commission to encourage the deployment of
advanced transmission technologies that increase the capacity,
efficiency and reliability of an existing or new transmission facility.
In enacting these provisions of EPAct, Congress made clear that it was
equally concerned with reliability as well as the adverse impacts of
transmission congestion and that the Commission should take steps to
address both issues. New FPA section 219, which is complementary to
these other EPAct provisions, directs the Commission to provide rate
incentives for the purpose of ensuring reliability and reducing
transmission congestion. However, nowhere in section 219 does the
language say that the Commission may provide incentives only to
applicants that propose to both improve reliability and reduce
congestion. In fact, we believe it would be contrary to the intent of
the new provisions, taken together, to limit incentives this way.
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    \31\ See Order No. 672, Rules Concerning Certification of the
Electric Reliability Organization; and Procedures or the
Establishment, Approval, and Enforcement of Electric Reliability
Standards, 71 FR 8662 (Feb. 17, 2006), FERC Stats. & Regs. ] 31,204
(2006).
---------------------------------------------------------------------------

    42. Consistent with the overall goals of Congress in EPAct 2005,
and in particular its focus on reliability improvements and relief of
transmission congestion, we interpret section 219 to promote capital
investment in a wide range of infrastructure investments that can have
either reliability or congestion benefits rather than investments that
have both reliability and congestion benefits. The alternative to this
reading would be to apply section 219 in a manner that would deny
incentive-based rate treatments to a transmission facility that
significantly enhances reliability but does not reduce the cost of
delivered power by reducing transmission congestion. This would be
contrary to a fundamental goal of EPAct 2005 to improve reliability of
the interstate transmission grid. We do not consider such an
interpretation to be reasonable. In any event, we expect there will be
few transmission projects that provide one type of benefit but not the
other.
    43. Commenters seeking a narrow reading of section 219 are
primarily concerned with the impact of any incentive-based rate
treatment on an applicant's rates. These concerns are premature. Before
the Commission will permit any applicant to recover incentives in its
rates, the Commission will evaluate the rate impact under section 205
or 206 of the FPA. Interested parties may raise any rate concerns at
that time. Further, our case-by-case approach ensures that the
incentives granted will be tailored to particular circumstances.
Finally, except for the rebuttable presumptions addressed below, we
will not at this time establish more detailed criteria an applicant
must meet to be eligible for incentive-based rate treatments.
Establishing criteria now would limit the flexibility of the Rule or
improperly pre-judge which projects are acceptable for incentives. The
Commission will, on a case-by-case basis, require each applicant to
justify the incentives it requests. Because these proceedings will
provide ample opportunity for parties to comment on any incentive
proposal, we do not see the need for a technical conference or detailed
criteria now. This notwithstanding, we provide certain guidance, as
described below, regarding the types of projects that may be
particularly well suited to certain incentives and others that may not.
2. Other Criteria For Approval of Incentives
a. Comments
    44. Numerous commenters seek additional conditions to be considered
in the grant of incentives. Some argue that the number of incentives
should be limited while others recommend additional criteria that an
applicant must satisfy \32\ or that the incentives be limited to
certain types of facilities. For example, TDU Systems assert that the
Final Rule should specifically identify other incentives that will be
considered under Sec.  35.35(d)(viii) and specify the parameters for
eligibility for the incentives. EEI, however, contends the Commission
should allow individual companies to propose any incentives on a case-
by-case basis because the individual companies are in a better position
to understand the efficacy of particular incentive mechanisms.
Similarly, National Grid requests clarification that the incentives are
not mutually exclusive and transmission owners should be free to
propose customized rate packages that include one or more of the
incentives in combination.
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    \32\ E.g., East Texas, TANC, and TAPS.
---------------------------------------------------------------------------

    45. With regard to additional conditions, some commenters argue,
for example, that the Commission should authorize incentives only for
proposals that recognize regional differences, that are the product of
an open and inclusive regional transmission planning process, increase
network capacity, or that respond to specific reliability or congestion
concerns. TANC argues that the Commission should limit qualification
for the incentives to those transmission projects that are 200 kV and
above. NECOE argues that incentives should be provided to

utilities that conform to good utility practice and minimize total
costs. Also, NECOE asserts that, when more than one incentive is
requested, the Commission should require the applicant to demonstrate
why a single, appropriately targeted incentive is insufficient. Several
commenters urge the Commission to grant incentives for existing
facilities and for maintenance of existing facilities.\33\ The Southern
Companies state that the Commission should grant incentives to
proposals that resolve a significant inter or intra-regional
constraint, or preclude or mitigate anticipated constraints that may or
may not arise. Progress asserts that incentives should be granted to
encourage installation of new software to better manage flowgates and
calculate Available Transfer Capability values on existing transmission
facilities. The Steel Manufacturers state that a utility does not
deserve special rate treatment to maintain or upgrade its facility to
comply with mandated reliability standards.
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    \33\ E.g., FirstEnergy, PSEG, AEP, EEI, Duquesne and
MidAmerican.
---------------------------------------------------------------------------

    46. Several commenters urge the Commission to condition any
incentive-based rate treatment on the applicant, among other things,
divesting the subject facility to a Transco, demonstrating that the
subject facility solves congestion constraints on a regional basis or
results in significant new transfer capacity, complying with the 1992
and 1994 Policy Statements, showing that the facilities would not have
been built absent the incentives, or showing that the facilities were
not already necessary to meet NERC reliability criteria or normal load
growth.\34\ PJM proposes a tiered procedure to determine whether
incentives are warranted. TDU Systems recommend that incentives should
be denied to public utilities that have refused to provide requested
relief from transmission congestion in the form of transmission
upgrades or otherwise, until such congestion is remedied without the
incentive rates.
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    \34\ E.g., TDU Systems, APPA, TAPS, NRECA, NARUC, NASUCA,
Connecticut DPUC, New Jersey Board, WPS.
---------------------------------------------------------------------------

    47. Several commenters request that the Commission allow states to
play a role in the approval or recovery of incentives because states
may hinder recovery of incentives in bundled rates.\35\ National Grid
asserts that the Commission and states should have an alignment of
interests on transmission investment and, therefore, there is no basis
to believe that the rule will warrant shifts in states' roles.
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    \35\ E.g., CREPC, KCPL, Steel Manufacturers, Montana-Dakota,
MidAmerican, and EEI.
---------------------------------------------------------------------------

b. Commission Determination
    48. Congress has determined that there is a need for incentives,
and has directed the Commission to issue a rule to provide them. Most
of the prerequisites and preconditions raised in the comments reflect a
desire to limit or circumscribe the nature or applicability of
incentives that may be granted under the rule. We have considered these
comments and do not believe that any of them should be adopted at this
time. Some of them are consistent with our overall policy goals (such
as the emphasis on regional planning) and, to that extent, we explain
how we will factor those considerations into an analysis of a proposed
incentive. However, some are inconsistent with the policy goals of
section 219 because they will only serve to discourage transmission
investment. Therefore, unless adopted in other sections of this rule,
we will not require applicants to satisfy the requirements proposed in
the comments. For example, we reject arguments that an applicant must
show that, but for the incentives, the expansion would not occur. Those
arguments are based on commenters' conclusions that the Commission's
prior issuances (i.e., Removing Obstacles order, the 1992 Policy
Statement, or the innovative rate proposal in Order No. 2000) required
an applicant to show need prior to receiving incentives. However, the
Final Rule is based on a clear directive from Congress that does not
require an applicant to show that it would not build the facilities but
for the incentives. This notwithstanding, we do require applicants to
show some nexus between the incentives being requested and the
investment being made, i.e., to demonstrate that the incentives are
rationally related to the investments being proposed.
    49. We also consider our procedures for the approval of incentives
to be comprehensive and, therefore, will not attempt to establish
gradations regarding either approval requirements or the amount of
incentive approved, as recommended by TANC, PJM, Industrial Consumers
and others. Section 219 does not mandate higher returns for projects
that are part of independent regional planning processes, nor does it
require higher standards of review for projects that do not result from
independent planning processes. As long as the project ensures
reliability or reduces the cost of delivered power by reducing
congestion, regardless of where it is located on the nationwide
transmission grid, the project is eligible for incentive ratemaking.
    50. We will not impose size limits on eligible transmission
projects. Projects below 200 kV can have a significant impact on
reliability or reduce congestion, and therefore would qualify for
incentive treatment. We will also not condition approval of incentives
on market power findings. Our regulations and penalties on market power
and market behavior are sufficient inducements to ensure markets are
not manipulated and, therefore, additional provisions are not
necessary.
    51. We will not deny incentives to public utilities that have not
built transmission upgrades requested by transmission customers. The
scope of this Rule is restricted to implementing the requirements of
section 219; the appropriate means to address this issue is to file a
complaint in a separate proceeding.
    52. While the promotion of renewable energy projects supports other
policy and regulatory objectives, we will not adopt separate rate-based
incentives for renewable energy projects. Congress directed the
Commission to issue a rule to ensure reliability or to reduce the cost
of delivered power by reducing transmission congestion regardless of
the nature of the energy carried over the new transmission facilities.
We believe that, by providing incentives applicable to all transmission
facilities, the Final Rule provides incentives for transmission to
serve renewable resources and, therefore, additional incentives are not
necessary.
    53. Because section 219 provides a new directive to the Commission
to permit greater incentives and does not on its face require an
individual showing of need by incentive applicants, we will not require
compliance with the 1992 or 1994 Transmission Policy Statements as a
precondition for approval of incentives.
    54. With regard to state review, the Commission recognizes that
incentives for many utilities are incorporated into rates that must
receive state commission approval and that many decisions on siting and
permitting of new facilities are under the jurisdiction of state and
local government authorities. Because of this, we will carefully
consider the views of any state bodies having jurisdiction over these
matters. We also will, as discussed below, adopt a rebuttable
presumption that projects approved by an appropriate state commission
or siting authority are eligible for incentives under section 219. We
believe that, in these ways, we will appropriately coordinate our
consideration of incentives with the

views of responsible state agencies. We will not, however, adopt any
further requirements regarding state approval, such as the requirement
that an applicant receive state approval of any proposed incentives.
While state approval is desirable it is not required by section 219.
However, if state approval of a particular plan is required, we expect
that any applicant will seek that approval in due course.
    55. Finally, we reiterate that an applicant may request any
combination of the incentives listed in the Final Rule. Applicants also
may request incentives that are not listed in the Final Rule. The
Commission will not use the Final Rule to identify each and every
incentive an applicant may request. However, this in no way relieves
the applicant of fully supporting its rate request and demonstrating
that its request for incentives satisfies section 219 and the
requirements of this Final Rule. If an interested party believes a
particular incentive is not warranted, it may raise its concerns when
an applicant proposes that incentive in a declaratory order or in a
section 205 rate application.
    56. Because section 219 makes clear that the Final Rule should
promote capital investment in the operation and maintenance of all
facilities for the transmission of electric energy in interstate
commerce, new investment in existing facilities will be eligible for
incentive-based rate treatments.\36\ The reliability benefits of
operation and maintenance capital spending are obvious, and we expect
applicants incurring this type of capital spending will be able to
demonstrate reliability benefits and thereby be eligible for incentive
treatment.
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    \36\ In addition, the Final Rule makes available incentives for
joining a Transmission Organization.
---------------------------------------------------------------------------

3. Rebuttable Presumptions
    57. As we discussed above, we will not adopt the variety of
preconditions recommended by the commenters. However, we are
nonetheless required to make findings that a particular investment
falls within the scope of section 219. In making that finding, we have
chosen to rely on existing processes to the extent practicable in
determining whether a particular facility is needed to maintain
reliability or reduce congestion. We describe these processes below and
find that, if an applicant satisfies them, its project will be afforded
a rebuttable presumption that it qualifies for transmission incentives.
Other applicants not meeting these criteria may nonetheless demonstrate
that their project is needed to maintain reliability or reduce
congestion by presenting us a factual record that would support such
findings. Once we determine that the project is eligible for
incentives, we would, as described below, consider whether the
particular incentives being proposed are appropriate for the particular
investments being made.
    58. The first rebuttable presumption we will adopt relates to
regional planning. Although we will not require participation in
regional planning processes as a precondition for obtaining incentives,
as section 219 does not require such a precondition, we believe that
regional planning processes can provide an efficient and comprehensive
forum through which those seeking to make transmission investments can
have their projects evaluated to see if they meet the requirements of
section 219. Regional planning processes can help determine whether a
given project is needed, whether it is the better solution, and whether
it is the most cost-effective option in light of other alternatives
(e.g., generation, transmission and demand response). It does so by
looking at a variety of options across a large geographic footprint;
thus, regional planning can allow for a broad assessment of loop flows
and impacts on neighboring systems. Regional Planning also can serve as
a forum in which states can readily participate.\37\ This benefit of a
regional planning process is difficult to duplicate on a utility-by-
utility basis. It may prove difficult for applicants, on an individual
basis, to timely gain access to all the information that might be
required to make a showing that the project ensures reliability and/or
reduces the cost of delivered power by reducing congestion. The
Commission expressly recognized the value of regional planning when it
proposed to amend the pro forma Open Access Transmission Tariff of
jurisdictional public utilities to require regional planning to ensure
that transmission is planned and constructed on a nondiscriminatory
basis to support reliable and economic service to all eligible
customers in a region.\38\ Consistent with our actions in that NOPR and
our belief that power markets are regional in nature and that the
transmission systems supporting those markets must be supported by
regional planning, we will create a rebuttable presumption for projects
that result from regional planning. Thus, the Commission will
rebuttably presume that transmission projects that result from a fair
and open regional planning process that considers and evaluates
projects for reliability and/or congestion and is found to be
acceptable to the Commission satisfy the requirements of this Rule.\39\
In addition, the Commission will adopt the following other rebuttable
presumptions. We will also attach a rebuttable presumption that an
applicant has met the requirements of section 219 if a proposed project
is located in a National Interest Electric Transmission Corridor or
where a project has received construction approval from an appropriate
state commission or state siting authority.
---------------------------------------------------------------------------

    \37\ State representation in stakeholder committee is a feature
of the Midwest ISO, i.e., the Organization of MISO States (MISO
States or OMS).
    \38\ Preventing Undue Discrimination and Preference in
Transmission Service, Notice of Proposed Rulemaking, 71 FR 32,636
(June 6, 2006), FERC Stats. & Regs., Regs. Preambles ] 32,603 at P
36 (2006) (OATT Reform NOPR):
    We conclude that the inadequacy of the existing obligation to
conduct joint and regional transmission system planning, coupled
with the lack of transparency surrounding system planning generally,
require reform of the pro forma OATT to ensure that transmission
infrastructure is constructed on a nondiscriminatory basis and is
otherwise sufficient to support reliable and economic service to all
eligible customers.
    \39\ An applicant may wish to file a request for incentive
treatment for a project which is undergoing consideration in a
regional planning process. The Commission will consider such
requests, but may make any requested rate treatment contingent upon
the project being approved under the regional planning process. As
discussed elsewhere in this Final Rule, different types of projects
and the circumstances under which they are undertaken may warrant
different rate treatments and incentives.
---------------------------------------------------------------------------

4. Applicants Seeking Incentive-Based Rates Will Not Be Required To
File a Cost-Benefit Analysis
a. Background
    59. The NOPR explained that no cost-benefit analysis would be
required to obtain incentives because customers will be protected by
the Commission's review of applications pursuant to sections 205, 206
and 219 of the FPA, which require that all rates be just and reasonable
and not unduly discriminatory or preferential.\40\
---------------------------------------------------------------------------

    \40\ NOPR at P 16.
---------------------------------------------------------------------------

b. Comments
    60. Certain commenters argue that judicial precedent requires that
incentive rates be supported by a showing of a quantifiable
relationship between the incentive and the result the incentive is
intended to achieve\41\ They also argue that the level of the incentive
must be calibrated to a level that it is no more than needed to achieve
the outcome that the incentive is supposed to produce.\42\ They further
argue that

section 219 does not require significant changes to the Commission's
existing rules and ratemaking policies governing incentive rates, such
as its 1992 Policy Statement \43\ and Order No. 2000,\44\ in which the
Commission required that applications for incentives be supported with
cost-benefit analyses. They contend that the Commission's existing
rules and policies already satisfy the Commission's obligations under
the FPA, even as amended by section 219, and should be retained.\45\
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    \41\ E.g., NECOE, PSE&G, and WPC Companies.
    \42\ E.g., NECOE.
    \43\ Incentive Ratemaking for Interstate Natural Gas Pipelines,
Oil Pipelines, and Electric Utilities: Policy Statement on Incentive
Regulation, 61 FERC ] 61,168 at 61,590 (1992).
    \44\ Regional Transmission Organizations, Order No. 2000, 65 FR
809 (Jan. 6, 2000), FERC Stats. & Regs., Regulations Preambles July
1996-December 2000 ]31,089 (1999), order on reh'g, Order No. 2000-A,
65 FR 12,088 (Mar. 8, 2000), FERC Stats. & Regs., Regulations
Preambles July 1996-December 2000 ]31,092 (2000), aff'd sub nom.
Public Utility District. No. 1 of Snohomish County, Washington v.
FERC, 272 F.3d 607 (D.C. Cir. 2001).
    \45\ E.g., TDU Systems, NRECA, NECOE, and SMUD.
---------------------------------------------------------------------------

    61. Several commenters state that, without a cost-benefit analysis,
the Commission has no basis for concluding that a particular incentive
provides customers with a net benefit or will be just and
reasonable.\46\ The New York Commission suggests that criteria for a
cost-benefit analysis be established through a separate technical
conference or rulemaking.
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    \46\ E.g., NRECA, NARUC, TAPS, East Texas, Connecticut AG,
Industrial Customers, NECPUC, California Oversight Board, MISO
States, DTE Energy, Wyoming Consumer Advocate, and New York
Commission.
---------------------------------------------------------------------------

    62. PJM argues that the Commission should provide incentives for
transmission owners' participation in robust regional transmission
planning that identifies both the costs and economic benefits of a
given project. PJM proposes that such a process should support a
rebuttable presumption that the decision to build is prudent and
warrants an ROE incentive.
    63. East Texas states that utilities engaged in meeting reliability
standards, constructing projects across designated corridors and
joining qualified Transmission Organizations should be allowed the
incentive rates on the simple showing that they seek to recover no more
than their prudently incurred costs. SMUD states that, under section
219, an incentive is appropriate only when it results in lower power
costs to consumers. The Oklahoma Commission states that the Commission
should give direction as to the showing by applicants that is
acceptable in lieu of the cost-benefit analysis.
    64. Other commenters argue that a cost-benefit analysis is
unnecessary.\47\ National Grid states that the Commission already
recognized generically the benefits of using ROE adders as an incentive
for needed transmission investment in the Removing Obstacles order.\48\
FirstEnergy asserts that consumers benefit by strengthening the
transmission grid and by encouraging new investment in transmission and
that the benefits of these factors potentially far exceed the costs.
International Transmission asserts that requiring a cost-benefit
analysis could delay needed transmission upgrades.
---------------------------------------------------------------------------

    \47\ E.g., National Grid.
    \48\ Removing Obstacles to Increased Electric Generation and
Natural Gas Supply in the Western United States, 94 FERC ] 61,272,
reh'g denied, 95 FERC ] 61,225, order on reh'g, 96 FERC ] 61,155,
further order on reh'g, 97 FERC ] 61,024 (2001).
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c. Commission Determination
    65. We reaffirm the NOPR's determination not to require applicants
for incentive-based rate treatments to provide cost-benefit analyses.
The courts have long recognized that a primary purpose of the FPA, and
its counterpart the Natural Gas Act, is to encourage the orderly
development of plentiful supplies of electricity and natural gas at
reasonable prices.\49\ To carry out this purpose, the Commission may
consider non-cost factors as well as cost factors.\50\ Moreover,
Congress's enactment of section 219 reflects its determination that
incentives generally can spur transmission investment which will, in
turn, provide the benefits of a robust transmission system identified
by the commenters. The Commission will consider the justness and
reasonableness of any proposal for incentive rate treatment in
individual proceedings.
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    \49\ See, e.g., Pub. Utilities Comm'n of the State of California
v. FERC, 367 F.3d 925, 929 (D.C. Cir. 2004) (CPUC v. FERC), citing
NAACP v. FPC, 425 U.S. 662, 670 (1976).
    \50\ Id., citing Permian Basin Area Rate Cases, 390 U.S. 747,
791, 815 (1968); Maine Public Utilities Commission v. FERC, No. 05-
1001, slip op. at 19 (D.C. Cir., June 30, 2006).
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5. Procedural Requirements for Obtaining Incentive-Based Rate
Treatments
a. Background
    66. Section 35.35(c) in the NOPR proposed that all rates approved
under the rule would be subject to sections 205 and 206 of the FPA.
Section 35.35(d) in the NOPR proposed certain options by which an
applicant may seek incentive-based rate treatments. The NOPR proposed
that applicants must explain whether the proposed facilities are part
of an independent regional planning process. The Commission also sought
comment on whether the Final Rule should establish a definition of
``independent regional planning process'' or if the Commission should
consider this issue on a case-by-case basis.
b. Comments
    67. Most transmission owners request that the Commission implement
a streamlined process to review and approve incentive-based rate
treatments. For example, some suggest that the Commission adopt a pre-
approval procedure that provides a preliminary determination of a
project's rate treatment, similar to the expedited pre-approval in the
Path 15 upgrade in California,\51\ to promote timely construction of
additional needed transmission facilities.\52\
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    \51\ See Western supra note 2.
    \52\ E.g., Mid-American, Nevada Companies, PacifiCorp, and
Northwestern.
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    68. A number of commenters urge the Commission not to require
transmission owners to make section 205 filings to implement incentive-
based rates. They argue that such proceedings may result in
unreasonable delay and uncertainty and thereby discourage, if not
preclude, incentive-based rate proposals.\53\ Many of these parties
urge the Commission automatically to approve incentives once the
facilities or investment have been shown to ensure reliability or
reduce congestion.\54\ Other commenters suggest that the Commission
create a category of incentives that would not require any review under
section 205 and then hold paper hearings only for those incentives that
do not fall within the designated category of incentives.\55\ Other
commenters request that the Commission establish a rebuttable
presumption that each incentive is just and reasonable or allow
transmission owners to self-certify that they meet the criteria of
section 219.\56\ Others similarly ask that there be a presumption that
facilities included in a regional planning process are eligible for
incentives.\57\ Another group of commenters argue that projects need
not be part of an independent regional planning process to receive an
incentive

because other regional processes will also provide the same
benefits.\58\
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    \53\ E.g., United Illuminating, Vectren, NSTAR, and EEI.
    \54\ E.g., Nevada Companies and MidAmerican.
    \55\ E.g., EEI, NU, New England TOs, NYSEG, and RGE.
    \56\ E.g., Southern and FirstEnergy.
    \57\ E.g., BG&E, PEPCO, KCPL, National Grid, PJM, PJM TOs,
United Illuminating and Vectren.
    \58\ E.g., EEI, Progress, Nevada Companies and FirstEnergy.
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    69. EEI argues that public utilities should be permitted to make
limited section 205 filings to specifically address recovery of
incentives in rates, regardless of the form of rate.
    70. National Grid requests clarification that the Commission will
continue to accept incentive and rate reforms that are tailored to the
specific needs of the transmission owner, so that transmission owners
can be allowed more traditional rate treatment, such as accruing the
allowance for funds used during construction, capitalization of pre-
commercial costs and a 30-year depreciation.
    71. BG&E requests clarification that, once the Commission approves
an incentive-based ROE for a particular regional planning process, any
entity within that planning process will be authorized to receive the
approved incentive-based ROE without being required to individually
apply for, or rejustify, the incentive.
    72. Some commenters argue that the Commission must review all
elements of an applicant's cost of service before authorizing any
incentives.\59\ The Steel Manufacturers assert that applicants must
justify each incentive they request under sections 205, 206, and 219
and that those applications seeking more than one incentive must
demonstrate that the overall package results in rates that satisfy the
same criteria.
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    \59\ E.g., Dairyland, TDU Systems, and NASUCA.
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    73. TAPS asserts that, when an applicant files a facility-specific
incentive filing the load divisor and depreciation reserve should be
updated, in the circumstance that existing rate inputs are known; and,
if they are not known because they are part of a ``black box''
settlement, they should be imputed. TAPS suggests ways in which this
can be done.
    74. Snohomish argues that applicants should be required to submit a
schedule of lower-cost alternatives, including potential non-wires
solutions, and to explain why these alternatives were not chosen. The
Oklahoma Commission recommends that state commissions make the
determination as to whether the cost of the project, including the cost
of the incentive, is more beneficial for ratepayers than if a
generation facility were built closer to avoid the cost of
transmission.
    75. Finally, several commenters urge the Commission to adopt a
generic definition of independent regional planning as well as
guidelines and minimum criteria for acceptable independent regional
planning processes.\60\ Other commenters ask the Commission to be
flexible in determining what constitutes a satisfactory ``regional
planning process,'' and to take into consideration any differences
among regions on a case-by-case basis.\61\
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    \60\ E.g., PJM TOs, APPA, International Transmission,
MidAmerican, Pacificorp, National Grid, Kentucky Commission, PJM,
OMS, NRECA and Semantic.
    \61\ E.g., Consumer Energy Council, Ameren, SDG&E, Southern
Companies, NorthWestern and PEPCO, Dairyland, and Vectren.
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c. Commission Determination
    76. Our goal is to provide procedural options that offer applicants
flexibility to address their construction and investment opportunities
while at the same time ensuring that the resulting rates are just and
reasonable and not unduly discriminatory or preferential. The
Commission offers two ways to accomplish this. An applicant may obtain
these rulings: (1) Through a combination of a petition for a
declaratory order and a subsequent section 205 filing or (2) by filing
only a section 205 filing. For both of these options, the applicant
must demonstrate that the facilities for which it seeks incentives
either ensure reliability or reduce the cost of delivered power by
reducing transmission congestion consistent with the requirements of
section 219, that there is a nexus between the incentive sought and the
investment being made, and that the resulting rates are just and
reasonable.
    77. The Commission has found that the first option--petition for
declaratory order followed by a section 205 filing--to be a valuable
tool. In certain instances, it is valuable for an applicant to obtain
an order indicating it qualifies for incentive-based rates prior to
making a formal section 205 filing and prior to commencing siting,
permitting and construction activities because such orders facilitate
financing and investment in new facilities.\62\ To provide applicants
with as much flexibility as possible, the Commission will permit
applicants to seek a declaratory order prior to construction of the
facilities to request a finding that the facilities qualify for
incentive-based rate treatments. The petitioner would have to
demonstrate that its proposal will either ensure reliability or reduce
the cost of delivered power by reducing transmission congestion. The
petitioner may rely on one of the rebuttable presumptions outlined
above or make an independent demonstration. The applicant may also use
the petition to justify which incentives it seeks to implement. We
clarify that any declaratory order will only rule on whether the
applicant's proposal qualifies for incentive-based rate treatment and,
if requested, which incentives the applicant may adopt. The applicant
must seek to put the rates into effect through a separate single-issue
or comprehensive section 205 filing. The Commission's expectation is
that, based on past practice, a declaratory order finding that the
applicant is eligible for incentive-based rate treatments would be
sufficient for the applicant to obtain funding or otherwise acquire
financing for the project. The Commission will seek to process
petitions for declaratory order quickly. While we cannot guarantee
Commission action within 60 days of the request (as is statutorily
required for section 205 filings), we will strive to meet that
standard.
---------------------------------------------------------------------------

    \62\ See Western supra note 2.
---------------------------------------------------------------------------

    78. If an applicant obtains a declaratory order finding that the
proposal qualifies for incentive-based rate treatment, the subsequent
section 205 proceeding would be limited to a review of the applicant's
rates and would not include a review of whether the applicant's
facility qualifies to receive incentive-based rate treatments. If the
petition addresses the applicant's incentives or finds that the
required nexus has been demonstrated, the applicant would not be
required to re-justify those findings in the section 205 filing.
Therefore, if an interested party believes a petitioner's proposal does
not qualify for incentive-based rate treatments or that the incentives
requested are not justified, the party must raise its objections when
the petition is filed and not wait to raise them in the subsequent
section 205 proceeding. If an applicant obtains a declaratory order and
the proposal changes from the facts on which the declaratory order was
issued, the applicant may seek another declaratory order or wait to
seek approval of the changes in the subsequent section 205 filing. In
that event, interested parties may challenge the changes in the section
205 proceeding.
    79. The second option involves filing only a section 205 filing
(either ``single-issue'' or comprehensive) to request all of the
required approvals. Prior to recovering any incentive-based rate
treatments in rates, an applicant must demonstrate that the rates in
which the applicant seeks to recover any incentives are just and
reasonable and not unduly discriminatory. However, the applicant will
have the option of filing a comprehensive section 205 rate case in
which all of the utility's rates

would be reviewed in conjunction with the proposed recovery of the
incentive-based rate treatments or filing a single-issue section 205
rate filing in which only the impact of the incentive-based rate
treatment for the facility granted the incentive will be addressed. As
explained below in section IV.B.7 (the discussion of single-issue
section 205 proceedings), the Commission believes there is a sufficient
need for timely investment in transmission infrastructure to justify,
in certain circumstances, a departure from our past practice by
allowing an applicant to seek to recover any incentive in a single-
issue section 205 rate proceeding. Single issue section 205
proceedings, as well as the declaratory order procedural option
discussed above, can remove obstacles to new investments by allowing
for timely cost recovery. Single issue filings also can support new
investment by allowing applicants to compare the returns of such
investments with the risks of the project itself, as opposed to having
to compare those returns to both the risks of the project being pursued
and the risks associated with re-opening all their rates, which is
ordinarily a time-consuming, expensive, litigious and uncertain
process. Additionally, in further facilitating these goals, the
Commission does not intend to routinely convene trial-type, evidentiary
hearings to review either a comprehensive or a single-issue section 205
filing but will attempt to render a decision based on the paper
submissions whenever possible.
    80. We clarify that no incentives will be granted on a final basis
without a section 205 filing. Therefore, an RTO member will not
automatically receive incentives granted to another RTO member.
However, when evaluating applications for incentive-based rate
treatments filed by an RTO member, the Commission will take into
account incentives granted to other RTO members, particularly in cases
where investments being made by that other RTO member pursuant to a
regional plan also lead to the need for expansions by the applicant in
its own footprint.
    81. We will not specify the rate calculations for section 205
proceedings, as requested by TAPS. These issues are appropriately
addressed in individual section 205 proceedings.
    82. The Commission will require applicants to justify each of the
incentive-based rate treatments it proposes by showing how the proposed
incentive satisfies section 219.\63\ For example, an applicant will be
required to show how the granting of the incentive will promote
reliable and economically efficient transmission and generation of
electricity, attract new investment, or increase capacity and
efficiency of existing transmission facilities or improve their
operation. The Commission, as set forth above, provides several
vehicles for making this showing, including reliance on a Commission
accepted regional planning process. We also will require the applicant
to show that there is a nexus between the incentives being proposed and
the investment being made.
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    \63\ An applicant would not be required to demonstrate that, but
for the incentive, the project would not be completed. Section 219
does not require such a condition.
---------------------------------------------------------------------------

    83. With respect to procedures applicable to joining Transmission
Organizations in Sec.  35.35(e), we clarify that applicants also may
file a petition for declaratory order as to whether the applicant
qualifies for incentives under section 219(c) and then submit a
comprehensive or single-issue section 205 filing to obtain approval of
the rates, or simply file a comprehensive or single-issue section 205
case to obtain all necessary approvals.

B. Incentives Available To All Jurisdictional Public Utilities

    84. In the NOPR, the Commission proposed eight incentive-based rate
treatments for transmission infrastructure investments for all public
utilities, including Transcos. As discussed below, the Commission will
adopt these in the Final Rule.
1. ROE Sufficient To Attract Capital
a. ROE
i. Background
    85. The Commission proposed to consider granting an incentive-based
ROE to all public utilities (i.e., traditional public utilities and
Transcos) that build new transmission facilities that benefit consumers
by ensuring reliability and reducing the cost of delivered power by
reducing transmission congestion thereby fulfilling the requirements of
section 219. As proposed, to receive an incentive-based ROE, a public
utility must submit a request in an application under section 205 of
the FPA and must support the ROE request by demonstrating how the new
facilities will improve regional reliability and reduce transmission
congestion. In addition, the application must explain whether the
facilities are part of an independent regional planning process, such
as that administered by an RTO or ISO or another independent regional
planning process recognized by the Commission and how the proposed ROE
was derived and why it is appropriate to encourage new investment.
(NOPR at P 22) Recognizing that the Commission had approved higher ROEs
(referred to in the NOPR as an ``adder'') for certain projects that
were designed to increase transfer capability or reduce congestion, the
Commission sought comments on the appropriateness of a higher ROE as a
mechanism for increasing investment in new capacity.
ii. Comments
    86. Numerous Commenters \64\ express general support for the
proposal to grant incentive-based ROEs to encourage transmission
investment stating that it is the most direct and effective means of
attracting needed capital to improve the nation's transmission
infrastructure. Southern Companies assert that allowing an incentive
ROE only ``within the zone of reasonableness'' is inconsistent with
Congress's mandate in section 219 that the Commission provide incentive
ROEs for transmission investment. NSTAR and Vectren state that an
incentive need not be cost-based; an incentive is justified under the
statute as just and reasonable if it serves the statutory purpose of
improving reliability or reducing the overall cost of delivered power.
---------------------------------------------------------------------------

    \64\ E.g., National Grid, FirstEnergy, EEI, KCPL, Xcel, Kentucky
Commission, Nevada Companies, Progress, and Southern Companies.
---------------------------------------------------------------------------

    87. Other commenters oppose the Commission's proposal to grant
incentive-based ROEs for investment in new transmission facilities. For
example, APPA states that an ROE adder is basically a bonus payment to
reward transmission providers for doing the job for which they are
already getting paid an adequate ROE under current Commission standards
and relevant FPA requirements. Connecticut DPUC argues ROE adders are
not a useful policy tool for improving transmission and the
Commission's standard rate review process of assessing the firm's risk-
adjusted cost of capital assures a completely adequate ROE without any
adders. TDU Systems and New Mexico AG contend that ROE adders will fail
the judicial mandate that rates be just and reasonable. CREPC maintains
that a blanket ROE increase generally runs counter to the Commission's
goal of encouraging transmission investment because it will either
unnecessarily increase the cost of electricity to end-users or render
an otherwise economic transmission

project uneconomic in comparison to its alternatives. The California
Commission states that the Commission's reliance on incentives granted
to Trans-Elect with respect to financing the critical Path 15 upgrade
in California several years ago is misleading since the special
consideration accorded to Trans-Elect was a direct consequence of the
unique, emergency energy crisis facing California and the Western
United States in 2001.
    88. Some commenters \65\ assert that the Commission must consider
the certainty of rate recovery for investment in new transmission
facilities and associated lower risk--providing the basis for a lower
ROE--before granting incentive-based ROEs. Others, however, such as
MidAmerican and PacifiCorp, state that the Commission should consider
ROE adders or other forms of enhanced returns if a project investment
entails levels of risk to investors and consumers that a traditional
rate of return would not cover or otherwise lacks the economic or
commercial incentives necessary to attract needed capital. PJM
recommends the Commission establish an equity return range based on a
generic analysis of investor expectations concerning transmission
investment as opposed to an analysis of a vertically integrated company
or, as an alternative, recognize the overall risk of each project, such
as the risk of delayed recovery at the state level.
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    \65\ E.g., NRECA, CREPC, AWEA, the Delaware Commission, New
Mexico AG, NY Association, the New York Commission, the California
Commission and SMUD.
---------------------------------------------------------------------------

    89. TAPS states that any incentive-based adjustment to transmission
returns should take the form of an equivalent adjustment to total
return (i.e., return on both debt and equity), rather than making the
value of the adjustment vary with the transmitter's capital structure.
TDU Systems state that if the Commission allows ROE adders, it should
consider applying the adders to the overall rate of return as an
alternative to estimating equity returns using public utility returns
as a proxy.
    90. MISO States argues that the Commission should make clear that
proposed ROE incentives are on investments in new transmission, as
contrasted with all of a public utility's transmission investment. TAPS
claims that increasing the ROE for existing facilities does nothing to
encourage investment in new transmission facilities. TDU Systems
recommends limiting ROE adders to the portion of rate base related to
the new investment.
iii. Commission Determination
    91. Consistent with the proposal in the NOPR, the Commission will
allow, when justified, an incentive-based ROE to all public utilities
(i.e., traditional public utilities and Transcos) for new investments
in transmission facilities that benefit consumers by ensuring
reliability or reducing the cost of delivered power by reducing
transmission congestion. By including this provision in the Final Rule,
we meet the requirement of section 219 to provide an ROE that attracts
new investment in transmission facilities (including related
transmission technologies). Public utilities making investments in
transmission infrastructure have made clear, both in their applications
for new projects and in their comments on this Rule, that the ROE
incentives encourage investment. We expect that an incentive ROE will
make transmission projects more attractive, and therefore more likely,
when transmission projects must compete for capital in vertically-
integrated utilities as well as in transmission and delivery utilities.
Accordingly, the Commission will approve an ROE at the upper end of the
zone of reasonableness for new infrastructure investments that meet the
requirements of section 219 as discussed elsewhere in this Final Rule.
    92. Concerns of blanket ROE increases and ROEs that exceed the DCF
determined ROE are misplaced. The NOPR's use of the term ``adder'' may
have contributed some confusion regarding the Commission's proposal.
The Commission, as discussed later in this section, will continue to
use the DCF analysis for ROE determinations. That analysis can result
in a range of returns (e.g., 9 percent to 13 percent), any of which
falling within the range are just and reasonable. This analysis,
undertaken in individual rate applications, assesses representative
proxy companies and the impact of other factors, including risk, on the
zone of reasonableness for ROE. Thus, contrary to certain comments, our
justification for a higher ROE is not based on a risk assessment; the
risk assessment is part of the traditional DCF analysis.
    93. Under the Rule adopted herein, the Commission will provide ROEs
at the upper end of the zone of reasonableness for transmission
investments that meet the requirements of section 219 as discussed
elsewhere in this Final Rule. Incentive-based ROEs, like other
incentives offered in this Rule, are to be filed with the Commission
for approval before rates that reflect such incentives can be charged.
Accordingly, because the approved ROE, including the impact of an
incentive, will be within the zone of reasonableness, we consider this
provision consistent with section 205 of the FPA. We will not create
specific ROE adders (e.g., 100 basis points); the Commission has always
considered a range of returns in determining the appropriate ROE and we
see no reason to depart from this practice. Though some commenters
assert that the incentive need not be cost-based and therefore can
justifiably be above the upper-end of the zone of reasonableness, we
believe a return within the zone will be adequate to attract new
investment and consistent with the intent of Congress in section 219.
The Commission will determine the level of the ROE on a case-by-case
basis when an application for an incentive-based ROE is filed with the
Commission. This is consistent with the approach the Commission has
employed to date, which has been found to be just and reasonable.\66\
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    \66\ Public Utilities Commission of the State of California v.
FERC, 367 F.3d 925 (D.C. Cir. 2004).
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    94. The foregoing does not mean, however, that we will grant
incentive-based ROEs to every new investment that increases reliability
or reduces congestion. The purpose of section 219 was, as described
above, to require the Commission to re-examine whether its current
policies are adequate to encourage new investment and strike the
appropriate balance between the investor and consumer interests. In
many instances, an incentive-based ROE is appropriate because our
traditional policies are not sufficient to encourage new investment.
For example, a large new interstate transmission project that reduces
congestion or increases reliability can face substantial risks that the
ordinary transmission investment does not. Further, such projects will
often be undertaken only at the election of investors, given that no
single entity is ``required'' to undertake them, and thus an incentive-
based ROE is appropriate to encourage proactive behavior. Other
projects also may present special risks or considerations that merit an
incentive-based ROE. By contrast, there are certain projects that may
not merit such an incentive. For example, routine investments made to
comply with existing reliability standards may not always qualify for
an incentive-based ROE. These are the types of investments that have,
as a general matter, been adequately addressed through traditional
ratemaking because there is an

obligation to construct them and high assurance of recovery of the
related costs. For these and other reasons, traditional ROE
determinations may continue to be appropriate for these investments.
This does not mean that other incentives may not be appropriate for
such investments (such as 100 percent CWIP recovery) or that other
reliability investments (e.g., substantial new investments to meet new
standards) would not qualify for incentive-based ROE determinations.
    95. We decline to apply incentives to total return, including debt,
as requested by TAPS. Section 219 directs the Commission to focus on
ROE, not total return; and this focus is proper. In a competitive
market for debt financing, any incentives added to the actual costs of
debt will flow to equity investors without actually increasing the
returns of debt capital providers. Unlike debt investors who do not
propose new investment or make direct investment decisions, equity
investors make investment decisions directly or by giving management
their proxy. Thus the opportunity for a higher ROE will directly and
more transparently influence the actions of those in the position to
make initial investment decisions.
    96. With regard to questions about whether the opportunity to earn
an incentive-based ROE applies to all of a public utility's
transmission investment, we clarify that it applies to new transmission
investment including investment that results in the enlargement of or
improved operation and maintenance of all facilities, consistent with
section 219 as discussed elsewhere in this Final Rule.
b. Alternatives to DCF Analysis
i. Background
    97. While the Commission has typically utilized a DCF analysis, the
NOPR (at P 20) sought comment on whether it should consider
alternatives to the DCF analysis as a way to provide incentives for
investment in new transmission capacity.
ii. Comments
    98. A number of commenters \67\ do not support a departure from the
DCF method that the Commission currently uses to determine allowed ROE.
APPA, for example, states that the DCF approach is generally
analytically sound and has produced consistent, predictable results
over time, eliminating some of the subjectivity and randomness in
equity forecasts that might occur if the Commission were to change
methods on a case-by-case basis. The New York Commission supports the
use of a DCF analysis as an appropriate means to determine an ROE that
reflects commensurate risks and thus would attract new investments.
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    \67\ E.g., APPA, the Kentucky Commission, New Mexico AG, NY
Association, New York Commission, TDU Systems and TAPS.
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    99. A number of commenters,\68\ request that the Commission adopt
additional methodologies, such as risk premium, comparable earnings,
Fama-French, and/or capital asset pricing, to use along with the
current DCF analysis because a multiple model approach will result in a
more representative ROE range. These commenters contend that the
Commission should make clear that it will consider and use alternative
methods of calculating ROEs. They argue that the Commission's final
determination of a just and reasonable ROE should be based on a
combination of the results from those alternative methods of
calculating ROEs, not on the result from any single method, because
each method has its own set of theoretical deficiencies and a range of
methods ensures all applicable variables are considered.
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    \68\ E.g., AEP, Ameren, EEI, California Commission, KCPL,
PacifiCorp, PEPCO, PJM TOs, Progress Energy, NSTAR, SDG&E, SCE,
Southern Companies, Trans-Elect, Vectren and WPS.
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    100. Other Commenters \69\ ask that the Commission consider changes
to how it determines proxy groups in the DCF analysis, by permitting
adjustments for leveraging effects, or adopting modified or expanded
proxy groups, as appropriate on a case-by-case basis, and by looking
more to companies in the primary or sole business of providing electric
delivery service or by isolating those activities from the other
activities of public utilities included in proxy groups. EEI recommends
that the Commission should use after-tax weighted average cost of
capital to adjust for leverage differences among sample companies and
recommends applying DCF results to the market value of equity rather
than to the book value of equity.
---------------------------------------------------------------------------

    \69\ E.g., PEPCO, APPA, PJM, AEP, FirstEnergy, and Ameren.
---------------------------------------------------------------------------

    101. NSTAR and New England TOs assert that any changes to the
Commission's ROE methodology should not be considered an incentive
because updating the ROE methodology including appropriate recognition
of risk is not an incentive, but rather is necessary to assure that the
ROEs received by transmission-owning utilities are compensatory and
fair under current market conditions and recover their cost of capital.
iii. Commission Determination
    102. While commenters note that every alternative method has a
theoretical deficiency and there is a benefit to introducing more
information into the analysis process, we do not see any basis to
conclude that the alternative methods would encourage more transmission
investment than continued reliance on the DCF analysis. Our past
practice of using the DCF approach has yielded just and reasonable
results and is consistent with long-standing ratemaking principles.
Therefore, at this time, we will not make broadly applicable changes to
how the Commission has traditionally performed its DCF analysis on
companies in the electric industry. However, we will consider on a
case-by-case basis whether the application of the traditional DCF
analysis should be modified and entertain proposals to use different
proxy groups as a way of capturing different business models.
2. Construction Work in Progress (CWIP) and Pre-Commercial Expenses
a. Background
    103. In the NOPR, the Commission noted that the long lead times
required to plan and construct new transmission can impact utility cash
flow, in turn affecting the overall financial health of a company and
its ability to attract capital at reasonable prices. The Commission
proposed including 100 percent of CWIP in rate base; \70\ and expensing
rather than capitalizing pre-commercial operations costs associated
with new transmission investment in order to relieve the pressures on
utility cash flows associated with transmission investment programs.
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    \70\ CWIP is a return on capital. Since 1987, the Commission's
general policy has been to allow only 50 percent of the non-
pollution control/fuel conversion construction costs as CWIP in rate
base. The remaining construction costs, including an allowance for
funds used during construction (AFUDC) which provides a return on
those expenditures, generally would have been capitalized and
included in rate base only when the plant went into commercial
operation, i.e., when the plant became used and useful. Allowing
some portion of the costs in rate base prior to commercial operation
provides utilities with additional cash flow in the form of an
immediate earned return. See 18 CFR 35.25(c)(3).
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    104. In 2004, the Commission accepted a proposal by American
Transmission Company (American Transmission) to include 100 percent of
CWIP in the calculation of transmission rates and to expense pre-
commercial operations costs for new transmission investment, instead of
capitalizing those costs and earning a return.\71\ American

Transmission stated that these incentives would help maintain adequate
cash flow during the construction process and that without these
incentives it could face a downgrade of its fixed income rating over
the next several years due to inadequate cash flow, thereby increasing
its capital costs by $176 million over a twenty-year horizon.
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    \71\ See American Transmission, supra note 2.
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    105. The Commission stated in the NOPR that allowing public
utilities, on a case-by-case basis, to include up to 100 percent of
prudently incurred transmission-related CWIP in rate base and
permitting them to expense prudently incurred pre-commercial operations
costs will further the goals of section 219 by relieving the pressures
on utility cash flows associated with their transmission investment
programs and providing up-front regulatory certainty. The Commission
specifically requested comment on (1) the types of costs that should be
considered ``pre-commercial'' operation costs; and (2) whether there
should be a presumption that these incentives meet the requirements of
FPA section 219 that investments ensure reliability and reduce the cost
of delivered power.
b. Comments
    106. Most of the commenters,\72\ support including 100 percent of
prudently-incurred CWIP in rate base and expensing all pre-commercial
operation costs, stating that these incentives will encourage
transmission investment through improved cash flow, greater rate
stability and lower rates to future customers. Additionally, SDG&E
notes that this incentive will balance short-term rates and long-term
rates by increasing the rates during construction but lowering the
rates during operation of a facility.
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    \72\ E.g., EEI, American Transmission, AWEA, PG&E, AEP, NSTAR,
WPS and TDU Systems.
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    107. Opponents, such as the New Mexico AG and California
Commission, state that maintaining the status quo would be in keeping
with the long-standing ratemaking doctrine that recovery of utility
plant costs should be based on utility plant that is ``used and
useful.'' They also oppose expensing pre-commercial costs instead of
capitalizing such costs because there will be no opportunity for a
comprehensive review of project costs before those costs are passed on
to ratepayers.
    108. Snohomish argues that the Commission must implement a
procedure to handle refunds where the project is never ultimately
completed, and must condition inclusion of CWIP and other pre-operation
costs in rates on adherence to the construction schedule submitted with
the application.
    109. In its supplemental comments, EEI recommends the Commission
waive the requirement that a utility requesting CWIP must provide a
forward-looking allocation that estimates the average use a wholesale
customer will make of the utility system over the life of a project, as
currently required by 18 CFR 35.25(c)(4). EEI states the purpose of the
required forward-looking allocation is to protect wholesale customers
against a double whammy (i.e., being required to pay for the
construction of new generation facilities if the customer switched
supplier). EEI states that the double whammy concern is not present
with transmission facilities because the customer will almost certainly
not switch transmission suppliers.
    110. TDU Systems assert that CWIP should not be allowed for
projects for which the public utility receives upfront interconnection
payments, nor for any project for which the funds have been provided by
a third party, except in tandem with crediting-back of such prepayments
or investments on a schedule to which the transmission customer agrees.
TDU Systems assert that if formula rates are in place for the public
utility seeking to expense the cost of capital assets, inter-
generational inequity is even more egregious since the public utility
may well receive a one-year amortization of that expense although
future rate payers will benefit from the use of those facilities for
years to come.
    111. Other commenters state that pre-commercial costs should be
defined and the Commission should provide guidance.\73\ Commenters'
proposals for pre-commercial costs definitions include all costs
associated with pre-construction activities, such as planning, related
studies, and siting costs, including (1) costs of routing studies for
placement of transmission lines, (2) costs of certification associated
with regulatory approvals including legal and consulting costs, (3)
costs of public hearings and informational hearings, (4) costs for
design, planning, drafting, surveying services, material procurement
and labor in support of project construction, and (5) costs associated
with development and implementation of interim measures to maintain
adequate reliability level due to the delayed completion of the
proposed project.
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    \73\ E.g., EEI, SCE, AEP, NSTAR, WPS, NU, FirstEnergy, the
Nevada Companies, KCPL, NRECA and Ameren.
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    112. Additionally, EEI argues the Commission should also include as
pre-commercial costs other costs that have been traditionally expensed
such as costs of resetting relays, using a mobile transformer, making
payments to other transmission owners for upgrades to their lines, and
the write-offs of the undepreciated cost of facilities that are being
replaced with new transmission investment.
    113. NRECA states that these costs should be limited to prudently
incurred direct transmission investment costs. TDU Systems states that
in no event should the Commission allow public utilities to expense
costs associated with transmission facilities such as land, towers,
transformers, lines, and substations.
    114. PJM recommends that costs of developing a transmission
proposal through a planning process should be considered a pre-
commercial cost.
c. Commission Determination
    115. After considering all the comments, we adopt in this Final
Rule the proposal from the NOPR to give public utilities, where
appropriate, the ability to include 100 percent of prudently incurred
transmission-related CWIP in rate base and to expense prudently
incurred ``pre-commercial'' costs. These rate treatments will further
the goals of section 219 by providing up-front regulatory certainty,
rate stability and improved cash flow for applicants thereby easing the
pressures on their finances caused by transmission development
programs. As noted by many commenters, these proved effective for
American Transmission by easing the pressures on American
Transmission's finances caused by its transmission development program
allowing American Transmission to, among other things, stay on schedule
with its development program. For American Transmission, this also
meant a higher credit rating and lower cost of capital, thus benefiting
customers. Similar results can be expected for other transmission
developers availing themselves of such opportunities.
    116. We appreciate the concerns, as expressed by the California
Commission and others, that the proposal is a departure from existing
ratemaking doctrine that rates should be based on plant that is ``used
and useful.'' However, as times and circumstances warrant, the
Commission has revised its ratemaking policies. In fact in Order No.
298,\74\ the Commission did just that

when it decided to allow any public utility engaged in the sale of
electric power for resale to file to include in rate base up to 50
percent of CWIP, subject to limitations. Thus, the Commission already
allows inclusion of some CWIP in rate base. The Commission also
departed from existing principles in the American Transmission and
Southern California Edison cases.\75\ The nation has suffered a decline
in transmission investment and it is time that the Commission revisit
ratemaking policies that may serve as a barrier to investment and
revise them accordingly while ensuring that customers are protected and
rates remain just and reasonable. Finally, we note that 100 percent
recovery of CWIP costs is already provided for pollution control
facilities of public utilities.\76\
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    \74\ Construction Work in Progress for Public Utilities;
Inclusion of Costs in Rate Base, Order No. 298, FERC Stats. & Regs.
] 30,455 (1983), order on reh'g, 25 FERC ] 61,023 (1983).
    \75\ See American Transmission, supra note 2; Southern
California Edison Co., 112 FERC ] 61,014, at P 61, reh'g denied, 113
FERC ] 61,143 (2005) (SCE).
    \76\ See 18 CFR 35.25(c)(1).
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    117. Allowing public utilities the opportunity, in appropriate
situations, to include 100 percent of CWIP in the calculation of
transmission rates and to expense pre-commercial operations costs for
new transmission investment (instead of capitalizing these costs and
earning a return) removes a disincentive to construction of
transmission, which can involve very long lead times and considerable
risk to the utility that the project may not go forward. The fact that
public utilities have the opportunity to recover these costs in rates
in a different manner than in the past does not mean that the rates are
not subject to review under FPA sections 205 and 206. Even for rates
that are formulaic, it may be necessary for the utility to revise the
rate formula under section 205 to capture the recovery of these types
of costs to the extent that they are not provided for in the formula.
Moreover, as the D.C. Circuit has found, the Commission can depart from
the norm as long as it reasonably balances consumers' interest in fair
rates against investors' interest in ``maintaining financial integrity
and access to capital markets.'' \77\ Finally, if the transmission
facility never enters service (i.e., is never used or useful), the
transmission owner may still seek recovery of the expenses associated
with the construction work in progress (i.e., the return on capital)
under our abandoned plant incentive, as discussed below. Accordingly,
we find that the ``used and useful'' ratemaking principle is not a
sufficient basis to deny adoption of the NOPR's proposal. However, as
explained above, we will require each applicant to demonstrate that
there is a nexus between its request for 100 percent CWIP recovery and
the investments being made. Ordinarily, such an incentive would be
appropriate for large new investments or in situations, as occurred
with ATC, where denying such an incentive would adversely affect the
utility's ratings. There may be other situations as well where such an
incentive is appropriate and we will consider each proposal on the
basis of the particular facts of the case.
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    \77\ Jersey Central Power & Light Co. v. FERC, 810 F.2d 1168,
1178 (D.C. Cir. 1987) (Jersey Central). ``Although a utility's rate
base normally consists only of items presently `used and useful'
(see New England Power Co. Mun. Rate Comm. v. FERC, 668 F.2d 1327,
1333 (D.C. Cir. 1981), cert. denied, 457 U.S. 1117 (1982)), a
utility may include `prudent but canceled investments' in its rate
base as long as the Commission reasonably balances consumers'
interest in fair rates against investors' interest in `maintaining
financial integrity and access to capital markets.' '' Jersey
Central, 810 F.2d 1168, 1178 (D.C. Cir. 1987).
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    118. With regard to requests that the Commission condition
inclusion of CWIP and pre-operation costs on adherence to the
construction schedule submitted with the application and that we
implement a procedure to handle refunds in the event the facility is
not put into service, we find them to be unnecessary and/or
inconsistent with the other measures we adopt in this Final Rule. As
discussed further below, the Commission is proposing to provide a
public utility with the opportunity to file for abandoned plant costs.
Thus, requiring a refund procedure that raises perceived risks of
proposing new transmission at this time would be inconsistent. We also
do not see the need to condition inclusion of CWIP on adherence to a
construction schedule. Because the actual recovery of CWIP will occur
either under a rate on file or a rate to be filed under FPA section
205, parties will have an opportunity to raise any concerns with regard
to actual expenditures vis-a-vis construction progress at that time.
Accordingly, we see no reason to condition inclusion of CWIP on
adherence to a construction schedule.