Promoting Transmission Investment Through Pricing Reform

Note: EPA no longer updates this information, but it may be useful as a reference or resource.

[Federal Register: July 31, 2006 (Volume 71, Number 146)]
[Rules and Regulations]
[Page 43293-43341]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr31jy06-15]
[[Page 43294]]

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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM06-4-000; Order No. 679]

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, 202-502-6079.
Andre Goodson (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE, Washington,
DC 20426, 202-502-8560.
Tina Ham (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE, Washington,
DC 20426, 202-502-6224.
Martin Kirkwood (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE, Washington,
DC 20426, 202-502-8125.

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..................................................

[[Page 43295]]

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:

[[Page 43296]]

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

[[Page 43297]]

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

[[Page 43298]]

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.
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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

[[Page 43299]]

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.
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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.
---------------------------------------------------------------------------

\26\ See also National Grid and EEI.
---------------------------------------------------------------------------

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

[[Page 43300]]

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.
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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

[[Page 43301]]

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.
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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.
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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

[[Page 43302]]

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.
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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.
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\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.
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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.
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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

[[Page 43303]]

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.
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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.
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\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

[[Page 43304]]

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.
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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

[[Page 43305]]

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.
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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.
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\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

[[Page 43306]]

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

[[Page 43307]]

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.
---------------------------------------------------------------------------

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.
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\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

[[Page 43308]]

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.
---------------------------------------------------------------------------

\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.
---------------------------------------------------------------------------

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

[[Page 43309]]

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).
---------------------------------------------------------------------------

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

[[Page 43310]]

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

125. Several parties, including EEI, NSTAR and NU argue in a
similar vein that hypothetical capital structures can aid investments
by companies that are entering a large capital expenditure program or
are emerging from financial distress and may be aiming for a capital
structure they have not yet realized. Semantic suggests a 75 percent
equity and 25 percent debt capital structure be used to reflect the
higher risks of early adoption of advanced technologies.
126. PJM and NSTAR state that hypothetical capital structures are
particularly useful for projects involving consortia. PJM cites its
proposed consortium approach to building transmission, where a capital
structure could be based on the project as a whole rather than
piecemeal based on the individual capital structures of each
participant in individual rate cases.\85\
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\85\ PJM TOs concur that the incentive could be helpful in
project-specific rates.
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127. A number of commenters oppose hypothetical capital
structures.\86\ APPA and CREPC argue hypothetical capital structures
could result in a windfall to public utilities by increasing actual
return far in excess of the Commission's allowed return on equity.
Commenters also express concern that the proposed incentive represents
a departure from Commission precedent and could result in unjust and
unreasonable rates.
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\86\ E.g., California Commission, TDU Systems, APPA, CREPC,
Steel Manufacturers, New Mexico AG, the Oklahoma Commission, PPC,
NECOE, Connecticut AG, and the Delaware Commission.
---------------------------------------------------------------------------

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

[[Page 43311]]

effective for development of consortium projects. This can be
especially important for projects with a diverse set of sponsors, some
of which have different capital structures, (e.g., a power marketing
agency that contributes access but no equity compared to a project
sponsor that brings only equity to a proposed investment). We note the
rise in interest in these types of projects, including such large-
scale, multiple-developer projects as the Frontier Line and TransWest
proposals. Thus, the Commission finds that, in certain contexts, this
incentive is appropriate for consideration under section 219 because it
has been demonstrated to foster the development of transmission
investment, as indicated by the experience of American Transmission and
Trans-Elect.
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\88\ METC, 105 FERC ] 61,214 at P 20.
\89\ Western, supra note 2.
---------------------------------------------------------------------------

132. The Commission continues to believe that an overly rigid
approach to evaluating proposed capital structures may discourage the
development of new transmission projects. Therefore, the Commission
will evaluate each proposal on a case-by-case basis but will not
prescribe specific criteria or set target debt/equity ratios for
evaluating hypothetical capital structures, as requested by some
commenters.\90\
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\90\ We note that many commenters support case-by-case review
and recognize the merits of evaluating the specific circumstances of
hypothetical capital structure proposals.
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133. We will not categorically deny the incentive to vertically-
integrated utilities, as recommended by NECOE. We agree with Ameren
that there may be circumstances in which a hypothetical capital
structure may be appropriate for a transmission investment by a
vertically-integrated utility. However, we are not suggesting that
hypothetical capital structures will become the norm. As with the other
incentives, we will require that the applicant demonstrate a nexus
between its proposed incentive and the facts of its particular case.
134. In this regard, we note that many of the instances in which
hypothetical capital structures are used and can be used reflect unique
circumstances, such as a project or consortium that requires a special
capital structure where the capital structure may change significantly
with new investments. We disagree with TDU Systems that the Commission
has (or should adopt) a general policy on when to use hypothetical
capital structures. Moreover, we do not believe that the Commission's
recent approvals of hypothetical capital structures for electric
transmission companies have resulted in abnormally high equity ratios
or over-compensation for the equity holder at the expense of the ratepayer.
4. Accelerated Depreciation
a. Background
135. In the NOPR (at P 30), the Commission proposed accelerated
depreciation as another way to increase cash flow to utilities, thereby
removing a potential disincentive to investing. The Commission has
determined that in some circumstances allowing accelerated depreciation
is warranted to encourage investment in transmission infrastructure
because it provides improved cash flow and better positions public
utilities for longer-term transmission investments.\91\ The Commission
stated that permitting accelerated depreciation more broadly than just
for emergency conditions or special projects may further the goals of
section 219 by providing incentives to undertake transmission projects
that have the potential to reduce the cost of delivered power and
ensure reliability, and, therefore, proposed to allow transmission
facilities to be depreciated over a period of 15 years, in place of the
typical Commission practice to allow depreciation over the useful life
of the facilities.\92\
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\91\ See Removing Obstacles and Western, supra note 2.
\92\ Removing Obstacles, 94 FERC ] 61,272, at 61,968-69.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

[[Page 43312]]

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

\98\ Depreciation Accounting, Order No. 618, FERC Stats. and
Regs. ] 31,104, at 31,694 (2000) (Order No. 618). According to
International Transmission, in Order No. 618, the Commission
modified its initial proposal to require straight-line depreciation
to permit other methods of depreciation that allocated the cost of
utility property over its useful life in a systematic and rational
manner. The Commission recognized that this approach would ``[allow]
flexibility in a changing business environment.''
---------------------------------------------------------------------------

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

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

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

[[Page 43313]]

express concern that the Commission will allow public utilities to
recalibrate the amount of depreciation, or institute a management fee.
Other commenters state the Commission should require certain rules for
sale of the facilities because of complications that will arise from
selling fully depreciated assets. We will not address those issues here
but will address such issues if and when they occur.
151. Commenters raise various accounting issues. With respect to
the effect of this rate treatment on ADIT (accumulated deferred incomes
taxes), we disagree that this proposal will necessarily require that no
provision for deferred incomes taxes be allowed with respect to such
assets (and no deduction from rate base). As stated previously, we are
going to be flexible with respect to the depreciable lives of
qualifying assets; therefore, public utilities may choose 30 years as
Trans-Elect did with Path 15 and as a result deferred income taxes may
still be necessary. Moreover, even if public utilities choose 15 years,
depreciation expense for rate recovery purposes will likely be
calculated using the straight-line method over those 15 years,\100\
while accelerated depreciation for tax purposes may be calculated using
a different method (e.g., double declining balance) over 15 years.
Therefore, despite the use of the same 15 year life, method differences
could continue to create timing differences for which deferred income
taxes would be required.
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\100\ The straight-line method is typically used by utilities
and will likely continue to be used for most utility property.
However, consistent with Order No. 618 we will not require its
universal use, as they may be overly prescriptive. Order No. 618 at 31,694.
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152. With respect to APPA's concern about potential difficulties in
applying SFAS 71,\101\ the Commission and other rate regulatory
authorities often include amounts in allowable costs for ratemaking
purposes in periods other than the period in which those amounts would
ordinarily be charged to expense or included in income for financial
accounting purposes. In those instances, the rate actions of regulators
have economic consequences that must be recognized in financial
statements. Under both SFAS 71 and the Commission's Uniform System of
Accounts, if regulation provides reasonable assurance that incurred
costs will be recovered in future periods, companies must capitalize
the costs. If current recovery is provided for costs that are expected
to be incurred in the future, companies must recognize the current
receipts as a credit amount on the balance sheet. Therefore, because
the accounting requirements for accelerated depreciation are no
different than accounting for the economic consequences of other rate
actions, we do not see an impediment to implementing accelerated rate
recovery of transmission assets.
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\101\ SFAS 71 applies to general-purpose external financial
statements of an enterprise that has regulated operations. The
Commission's Uniform System of Accounts for Public Utilities and
Licensees (18 CFR Part 101) contains provisions similar to SFAS 71
that apply to financial statements public utilities must file with
the Commission.
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153. We are not persuaded that we need to revisit Order No. 618 in
this proceeding as some commenters suggest. In Order No. 618, the
Commission established standards for determining depreciation expense
for book purposes. Here we are establishing a standard for determining
depreciation expense allowable for rate purposes. Although accounting
and cost-based rate setting generally share common standards, there are
instances, and this is one, where different standards should be used by
each discipline and the difference bridged by recognition of regulatory
assets or liabilities as provided for in our Uniform System of
Accounts.\102\ Therefore, companies will continue to depreciate
transmission assets over their economic service life in a systematic
and rational manner for accounting purposes and separately recognize as
a regulatory liability any difference between depreciation expense
recognized for accounting purposes and accelerated depreciation expense
included in the development of rates. In order to clarify this
distinction the Commission shall revise Sec. 35.35(d)(1)(v) of the
regulatory text proposed in the NOPR which read ``(v) accelerated
regulatory book depreciation.'' The revised regulatory text shall read
``(v) accelerated depreciation used for rate recovery.''
---------------------------------------------------------------------------

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

154. We deny International Transmission's request to alter our
section 205 filing requirements for public utilities operating under
formula rates. In Order No. 618, the Commission permitted utilities to
not make a filing to change depreciation rates for accounting purposes
but maintained the filing requirement for changes in depreciation rates
for rate purposes.\103\ The Commission said it would monitor changes in
depreciation rates for accounting purposes when companies filed for
rate changes. We decline in this Final Rule to adopt International
Transmission's requested changes to formula rates. International
Transmission is free to petition the Commission to revise its formula
rate to allow flexibility going forward, but we decline to make such a
generic determination here because to do so would presume that all
formula rates worked in the same manner.
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\103\ Order No. 618 at 31,695.
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5. Recovery of Costs of Abandoned Facilities
a. Background
155. The Commission noted that public utilities, in considering
investments that fulfill the requirements of FPA section 219, may
encounter investment opportunities with significant risk associated
with factors beyond their control, such as generation developers'
decisions to develop or terminate the development of potential
resources or difficulty obtaining state or local siting approvals. In
these circumstances, the Commission stated that it may be appropriate
to consider ways to reduce the risk associated with potential upgrades
or other improvements to the transmission system. To reduce the
uncertainty associated with higher risk projects, thereby facilitating
investment in these projects, the Commission proposed allowing recovery
of 100 percent of the prudently incurred costs of transmission
facilities that are cancelled or abandoned due to factors beyond the
control of the public utility.
156. The Commission's proposal was an extension of a recent
Commission decision to allow Southern California Edison Company \104\
to recover all prudently incurred costs related to certain proposed
transmission facilities if those facilities were later cancelled or
abandoned.\105\ The Commission noted that the company's management did
not control the decision to develop or cancel the wind farm generation
project and that the company's shareholders did not share in the
earnings associated with the generation project. The

[[Page 43314]]

Commission further determined that the company might be at a higher
risk in developing the project because of factors beyond its control.
It also noted that SCE was not a wind farm developer and therefore
would not directly benefit from the facilities. Thus, the Commission
concluded that SCE should not shoulder the risk of the project.\106\
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\104\ SCE, 112 FERC ] 61,014 at P 58-61, reh'g denied, 113 FERC ]
61,143 at P 9-15.
\105\ Prior to SCE, the Commission's policy with respect to
recovery of cancelled plant costs provided that 50 percent of the
prudently incurred costs of a cancelled generating plant should be
amortized as an expense over a period reflecting the life of the
plant if it had been completed and that the remaining 50 percent of
the prudently incurred costs of the cancelled plant should be
written off as a loss. Under this policy, ratepayers are entitled to
the income tax deduction associated with that portion of the loss
for which they are paying. In addition, they are entitled to a rate
base reduction to reflect the accumulated deferred income tax
amounts associated with 50 percent of the abandonment loss. See New
England Power Co., Opinion No. 295, 42 FERC ] 61,016 at 61,068,
61,081-83, order on reh'g, 43 FERC ] 61,285 (1988). See also, Public
Service Company of New Mexico, 75 FERC ] 61,266 at 61,859 (1996)
(PSNew Mexico).
\106\ SCE. at P 61.
---------------------------------------------------------------------------

b. Comments
157. A number of commenters support the 100 percent recovery of
prudently incurred costs of transmission projects that must be
abandoned for reasons beyond the transmission provider's control as a
way to reduce the up-front risk associated with important regional
projects.\107\ Some, like the Kentucky Commission,\108\ advocate that
the Commission should adopt a case-by-case approach to recovery of
costs related to cancelled plant.\109\ Kentucky Commission agrees that
this incentive should be evaluated on a case-by-case basis to ensure
that the decision to abandon the facility was truly beyond the
utility's control. California Commission and CADWR do not oppose the
recovery of 100 percent of the recovery of prudently incurred costs as
long as the determination is made on a case-by-case basis.
International Transmission states that preliminary surveys and
investigations should also be included in the costs that can be recovered.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

[[Page 43315]]

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[Page 43316]]

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

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

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

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

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

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

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

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

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

[[Page 43317]]

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

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

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

C. Incentives Available to Transcos

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

[[Page 43318]]

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

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

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

[[Page 43319]]

Therefore, the Commission stated that it will consider the positive
impact Transcos have on transmission investment and in turn on the
reliable or economically efficient transmission and generation of
electricity when it evaluates ROEs proposed by properly structured
Transcos. (NOPR at P 40, footnote omitted)
ii. Comments
207. Several commenters,\136\ oppose the Commission's proposal to
grant an ROE incentive to Transcos outright. Other commenters\137\
oppose giving Transcos an incentive that is not available to other
business models.
---------------------------------------------------------------------------

\136\ E.g., APPA, Community Power Alliance, Municipal
Commenters, NASUCA, NECPUC, New Mexico AG, NRECA, NU, Pennsylvania
Commission, Snohomish, and TANC.
\137\ E.g., AEP, BG&E, EEI, First Energy, KCPL, MidAmerican and
PacifiCorp, Midwest ISO, NECPUC, Northwestern, PEPCO, PJM, PJM TOs,
PPC, Progress Energy, SCE, Southern Companies, and Vectren.
---------------------------------------------------------------------------

208. Those opposing the outright grant of ROE incentives to
Transcos\138\ contend, among other things, that: There should be no
equity incentive adders without direct demonstration of customer
benefits; such incentives would unfairly divert capital to Transcos;
and that enhanced Transco ROEs do nothing to solve the problem of
building needed transmission.
---------------------------------------------------------------------------

\138\ E.g., Municipal Commenters, NECPUC, Progress Energy,
Snohomish, PPC.
---------------------------------------------------------------------------

209. Commenters opposing\139\ treatment based on corporate form or
business model suggest that the Commission focus on the purpose and
effect of the proposed investments, not the type of entity that
proposes them. They argue that there is a lack of evidence of how
Transcos encourage transmission infrastructure expansion and the track
record for Transcos is incomplete.
---------------------------------------------------------------------------

\139\ E.g., APPA, Community Power Alliance, FirstEnergy,
Pennsylvania Commission and NASUCA.
---------------------------------------------------------------------------

210. Other commenters raise concerns about the signals the
Commission is sending regarding RTOs and independence of operations,
planning and expansion that can be ensured through other types of
regional transmission groups or through traditional utilities,
particularly those in a RTO with a regional planning process.\140\ EEI,
for example, opposes the Commission managing business models and argues
the Commission should not (even unintentionally) give the impression
through incentives that it seeks to restructure the transmission sector.
---------------------------------------------------------------------------

\140\ E.g., American Wind, Mid American, PacifiCorp, and EEI.
---------------------------------------------------------------------------

211. Other commenters offer suggestions as to how to distinguish
incentives. For example, NU and PJM suggest targeting incentives at
companies that are investing in transmission and/or involved in
regional planning, regardless of corporate structure. PJM suggests the
Commission proceed on a case-by-case basis.
212. Finally, commenters argue that higher ROEs for only some
transmission owners are discriminatory and not just and reasonable, and
have no basis in section 219. Alternatively, some suggest that Transcos
have lower risk than integrated companies and should receive lower
ROEs. Others argue that incentives should cover only new investments
and behavior,\141\ not existing infrastructure. For example, California
Commission opposes providing higher ROEs to Transcos, arguing that
Transco and traditional integrated utility shareholders bear the same
(and only significant) risk as transmission project owners--during the
initial stage of project permitting and developing. SCE offers that
Transco-specific ROEs might actually provide a disincentive for future
Commission-jurisdictional transmission investments by traditional
utilities if they can earn higher ROEs on state-jurisdictional
facilities. TANC offers that a for-profit Transco has no incentive to
make, and, in fact, is discouraged from making, economically efficient
and/or energy efficient investments. Dairyland points out that American
Transmission's plans for substantial investment were made in the
context of a settlement agreement in which American Transmission agreed
to a lower ROE than that approved for Midwest ISO transmission owners
and that the settlement improved American Transmission's cash flow and
reduced its risk, providing a sufficient financial package to enable
its investments even with the lower ROE. Dairyland states that American
Transmission shows that substantial investment by Transcos is likely to
occur even if ROEs are reduced.
---------------------------------------------------------------------------

\141\ E.g., New Mexico AG, NRECA, Pennsylvania Commission, PG&E,
Vectren, Southern Companies, California Commission, SCE, and TANC.
---------------------------------------------------------------------------

213. Some commenters take issue with the representations in the
NOPR regarding state and federal jurisdiction.\142\ For example,
Community Power Alliance opposes rewarding changes in ownership
structure resulting in transfer of jurisdiction from state to federal
regulators. PEPCO believes the NOPR suggests that traditional utilities
may be treated less well by federal regulators merely because they are
subject to state as well as federal jurisdiction. New Mexico AG states
Transco incentives are nothing more than an attempt by the Commission
to override state regulatory jurisdiction. Nevada Companies state that
the Commission must work with state regulatory authorities to foster
Transco formation.
---------------------------------------------------------------------------

\142\ E.g., Community Power Alliance, PEPCO, NSTAR, and PJMTOs.
TOs.
---------------------------------------------------------------------------

214. TDU Systems opposes incentive rates for new investment by
Transcos after those Transcos form. If any such award is granted, TDU
Systems argues it be done only upon demonstration of need, and apply
only to system expansions, not existing facilities.
215. Other commenters,\143\ generally support incentive-based ROEs
to encourage Transco formation. For example, International Transmission
supports incentives for Transco formation and investment not merely to
reward a particular transmission ownership structure but to encourage a
type of transmission ownership that has produced the results that
Congress sought when it enacted section 219. International Transmission
states that both its own specific experience and the track record of
Transcos generally illustrate the benefits of Transco ownership of
transmission.\144\ International Transmission states that if other
forms of transmission ownership invest in transmission in a manner
comparable to Transcos, those other entities should be eligible for
equal incentives, but that until they do, Transco-specific incentives
are fully appropriate.
---------------------------------------------------------------------------

\143\ E.g., International Transmission, KKR, Nevada Companies,
TDU Systems, Trans-Elect and Upper Great Plains.
\144\ International Transmission states that in the last decade
of Detroit Edison's ownership of the facilities now owned by
International Transmission, Detroit Edison invested about $10
million a year in those transmission facilities that International
Transmission states it invested $41 million on in 2003; $82 million
on in 2004; and over $118 million on in 2005. At the end of 2005,
the net asset value of International Transmission's facilities has
nearly doubled while its CWIP balance remained roughly flat.
International Transmission states that this substantially increased
investment is producing benefits for consumers in enhanced
reliability and increased access to competitively priced generation.
International Transmission states that in the latest Midwest ISO
Transmission System Expansion Plan, the three Transcos in the
Midwest ISO account for 54 percent of the approximately $2.9 billion
in projected investment through 2009. Comparing the level of
projected investment across Transcos and non-Transcos, the average
Transco in the Midwest ISO is investing at over seven times the rate
of the average non-Transco in the Midwest ISO.
---------------------------------------------------------------------------

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

[[Page 43320]]

transmission functions; a singular focus on transmission investment
which allows more rapid and precise response to market signals
indicating when and where transmission investment is needed; a lack of
incentive to maintain congestion in order to protect generation market
share; and an enhanced ability to manage assets and access to capital
markets. As stand-alone entities lacking incentive to favor a
particular market participant's generation, Transcos are likely to
attract a variety of new generators, including solar and wind renewable
generation.
217. KKR states that enhanced ROE can both drive capital investment
and support Transco formation. An enhanced ROE in excess of that
sufficient to support new investment will be factored into the purchase
price of the Transco assets or company and be delivered in whole or in
part to the seller.
218. Additional comments in support of higher ROEs for
Transcos,\145\ note that Transco formation and investment will occur
when actual Transco returns are equal to or greater than returns for
investments with comparable risk and that these returns must be earned
on a consistent basis.
---------------------------------------------------------------------------

\145\ E.g., Nevada Companies and Trans-Elect.
---------------------------------------------------------------------------

219. Trans-Elect offers suggestions on the manner in which the
incentive could be tied specifically (and exclusively) to the acquired
facilities. In addition, Trans-Elect states that whatever methodology
is used to develop a range of equity cost estimates, use of the mid-
point (or average) of that range would be contrary to the notion of
stimulating new transmission investment. Particularly in the context of
the inherently higher-risk Transco business model, Trans-Elect supports
ROEs toward (or at) the high end of the range.
220. Upper Great Plains supports Transco incentives but argues they
be limited to what is necessary to put Transcos on an equal footing
with other transmission developers. According to Upper Great Plains,
leveling the playing field will encourage Transcos to more fully
develop the advantages made possible by their business structure.
iii. Commission Determination
221. After considering all the comments, we adopt in this Final
Rule the proposal from the NOPR to provide to Transcos a ROE that both
encourages Transco formation and is sufficient to attract investment
after the Transco is formed. The incentive ROE does not preclude a
Transco from applying for any other incentive adopted in this rule,
including hypothetical capital structures, ADIT, acquisition premiums,
formula rates or deferred cost recovery. We note that such additional
incentives could aid the formation of Transcos as well as bolster their
ability to add transmission infrastructure. We note, in addition, that
application of the ROE incentive or applicable other incentives will
likely be more efficiently translated into rates for those applicants
that operate under or concurrently propose formula rates.
222. This decision is based on the proven and encouraging track
record of Transco investment in transmission infrastructure. For
example, International Transmission states that its investment was more
than ten times higher in 2005 than the annual investment by DTE during
the last decade of DTE's ownership of the same transmission
system.\146\ Trans-Elect states that it expended $112 million in
capital on its system from May 2002 through 2005.\147\ Since January 1,
2001, American Transmission states that it has invested approximately
$1 billion in strengthening its system, essentially tripling its
investment in transmission infrastructure in five years.
---------------------------------------------------------------------------

\146\ International Transmission comments at 21.
\147\ METC comments at 3.
---------------------------------------------------------------------------

223. The expansion plans of existing Transcos are also encouraging.
International Transmission notes that in the latest Midwest ISO
Transmission System Expansion Plan, the three Transcos in the Midwest
ISO account for 54 percent of the Plan's approximately $2.9 billion in
projected investment through 2009. It also states that comparing the
level of projected investment across Transcos and non-Transcos, the
average Transco in the Midwest ISO is investing at a rate that is over
seven times that of the average non-Transco in the Midwest ISO.\148\
---------------------------------------------------------------------------

\148\ International Transmission Reply Comments at 6.
---------------------------------------------------------------------------

224. As stated in the NOPR, the Commission believes that this
positive record of Transco investment in transmission facilities is
related to the stand-alone nature of these entities.\149\ In
particular, we agree with the comments submitted by KKR explaining the
benefits of the Transco model. By eliminating competition for capital
between generation and transmission functions and thereby maintaining a
singular focus on transmission investment, the Transco model responds
more rapidly and precisely to market signals indicating when and where
transmission investment is needed. We agree that Transcos have no
incentive to maintain congestion in order to protect their owned
generation. Moreover, Transcos' for-profit nature, combined with a
transmission-only business model, enhances asset management and access
to capital markets and provides greater incentives to develop
innovative services. By virtue of their stand-alone nature, Transcos
also provide non-discriminatory access to all grid users.
---------------------------------------------------------------------------

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

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

[[Page 43321]]

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

\150\ NOPR at P 42.
---------------------------------------------------------------------------

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

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

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

[[Page 43322]]

238. Others, such as APPA, NRECA, and PG&E support the Commission's
proposal that membership in an RTO or ISO should not be a factor in
setting incentive-based ROEs for Transcos. WPS states that the proposed
incentive for Transcos may be appropriate, but also could be
duplicative if the Transco is an RTO member and also receives an
incentive for that membership.
iii. Commission Determination
239. We will not establish a specific methodology to factor the
level of independence into any request for ROE-based incentives for
Transcos. We will also not specify additional incentive levels that
remain within the zone of reasonableness, to correspond to certain
levels of independence. While not quantifying a precise formula or
method, we will consider the level of independence of a Transco as part
of our analysis when we determine the proper ROE for the Transco, and
evaluate the specific attributes of a particular proposal, including
the level of independence, to determine appropriate incentives.
240. Though we are not establishing a range of incentives based on
independence, we note that the three existing Transcos, which have
significantly increased their transmission investment post-formation,
are either totally independent of market participants or can meet the
independence standards in the Policy Statement Regarding Evaluation of
Independent Ownership. Independence is an important component of the
positive contribution of Transcos on investment in needed transmission
infrastructure. A Transco with active ownership by a market participant
or other new business arrangements is also eligible for Transco
incentives to the extent it can show, for example, why active ownership
by an affiliate does not affect the integrity of its investment
planning, capital formation, and investment processes or how its
business structure provides support for transmission investments in a
way similar to the structure of non-affiliated Transcos or Transcos
with only passive ownership by market participants.
241. In addition, while a Transco need not be a member of an RTO,
ISO, or other Transmission Organization, we will also consider such
membership as part of our evaluation process on the level of Transco
incentives that might be appropriate. We also note that a Transco is
eligible for incentives if it is a member in an RTO, ISO, or other
Transmission Organization.
3. Accumulated Deferred Income Taxes (ADIT)
a. Background
242. To remove any disincentives that might prevent the sale or
purchase of transmission assets to form Transcos, such as capital gains
taxes on sales of assets,\152\ the Commission (NOPR at P 43) proposed
to include in the rates of Transcos an adjustment to recover ADIT. This
incentive would provide the assurance of recovery in rate base of
adjustments for taxes associated with asset sales, thereby reducing
uncertainty.
---------------------------------------------------------------------------

\152\ See, e.g., International Transmission Co., 92 FERC ]
61,276 at 61,915-16 (2000) (explaining potential disincentives to
sellers and buyers of transmission assets if the ADIT adjustment is
not granted).
---------------------------------------------------------------------------

b. Comments
243. Several Commenters\153\ submitted comments that generally
support the Commission continuing to consider proposals to include
adjustments for ADIT in rates when a Transco is purchasing transmission
facilities. For example, Trans-Elect states that continuing to allow
adjustments for ADIT will eliminate this tax-related disincentive and,
in the process, demonstrate to potential sellers, purchasers and the
investment community the Commission's commitment to promoting
independent stand-alone transmission businesses. National Grid states
that allowing recovery of ADIT is designed to ensure that there is no
financial or tax penalty associated with undertaking the transactions
necessary to form Transcos and therefore the Commission should allow
such recovery to eliminate an obstacle to Transco formation. OMS states
that allowing the ADIT cost recovery adjustment appears more reasonable
than simply authorizing filings to recover acquisition premiums because
the ADIT adjustment premium would be specifically quantifiable and tied
to a specified purpose. International Transmission and Trans-Elect also
specifically support the Commission's clarification that a stand-alone
transmission company that requests an incentive ROE would not be
precluded from also requesting the ADIT adjustment.
---------------------------------------------------------------------------

\153\ E.g., International Transmission, KKR, National Grid,
NorthWestern, OMS, PJM TOs, TAPS, and Trans-Elect.
---------------------------------------------------------------------------

244. Some commenters raise specific concerns regarding how an ADIT
adjustment will be calculated. TAPS states that after the seller is
held harmless for its book-based gain-on-sale tax consequences (if any)
any remaining tax balance should flow back to ratepayers. TDU Systems
state that the ADIT adjustment should be reduced by the seller's ADIT
and investment tax credits associated with the transferred property.
APPA is concerned about the difficulty a buyer of facilities will have
in correctly calculating the ADIT, which is based on the seller's
capital gains tax liability. NRECA states that the Commission needs to
create sufficient safeguards to prevent double recovery. TAPS and APPA
also cite the American Jobs Creation Act of 2004 as substantially
mitigating, and potentially eliminating the ADIT concern.
245. APPA, PPC and Snohomish state that, in order to get the ADIT
adjustment, buyers of transmission facilities should need to
demonstrate concomitant customer benefits to offset increased
transmission rates resulting from measures to recover capital gains
tax-related acquisition premiums.
246. PPC and Snohomish state that allowing recovery of ADIT goes
beyond the stated goal of promoting investment in new transmission
capacity, and instead would promote the sale of existing transmission
assets. They contend that allowing purchasers to amortize ADIT in rates
will increase ratepayer costs and allow Transcos to benefit from the
time-value of money without offsetting any actual expenditure. The
value of ADIT should be passed through to customers only if the Transco
is actually making tax payments, and then only in an amount equal to
those payments.
c. Commission Determination
247. We find that it is appropriate for the Commission to continue
to consider proposals to make an adjustment to the book value of
transmission assets being sold to a Transco to remove the disincentive
associated with the impact of accelerated depreciation on federal
capital gains tax liabilities. This adjustment is simply intended to
remove a disincentive to Transco formation. As explained in the NOPR,
transmission owners are unlikely to sell transmission assets at book
value if they are not held harmless from capital gains taxes on such
sales by including an adjustment for taxes associated with those sales.
Buyers of transmission assets may be unwilling to pay such an
adjustment without some assurance of recovery of the adjustment in
their rate base, as the Commission has addressed in previous Transco-
related orders. In addition, we find appropriate the clarification
proposed in the NOPR that a Transco requesting an incentive ROE not be
precluded from also requesting the ADIT adjustment.

[[Page 43323]]

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

\154\ As discussed elsewhere in the Final Rule, an applicant may
propose a number of incentives. Thus, a stand-alone transmission
company is not precluded from requesting ROE and ADIT.
---------------------------------------------------------------------------

249. We will not require, as requested by APPA, PPC and Snohomish,
that our approval of any ADIT adjustment be conditioned on an analysis
of costs and benefits related to such an adjustment, as discussed
elsewhere in this Rule. We disagree with the implication of PPC that
the Transco purchaser is receiving the benefit for ADIT costs that it
is not really paying. ADIT is part of the purchase price of the
transmission assets sold to the Transco, and hence represents actual
costs to the purchaser.
250. However, as described more fully in the Performance Test
section, we clarify that continuation of the ADIT adjustment, like
continuation of other incentives, is conditional on the applicant
achieving benchmarks for its own proposed Commission-approved metrics.
4. Acquisition Premiums for Transco Formation
a. Background
251. The NOPR (at P 55) requested comments on whether the
Commission should make a generic determination that general benefits
would accrue to ratepayers as a result of Transco formation. It also
sought comment on whether any change in the acquisition premium/
ratepayer benefits review at the federal level would risk increased
resistance to such acquisitions at the state level. The NOPR sought
comment on whether there are other mechanisms that the Commission could
institute to provide regulatory certainty of the recovery of the
acquisition premium both through retail as well as wholesale rates. It
also sought comment on what measure the Commission might use in
evaluating the appropriateness of such premiums as measured against,
for example, the size of the premium, the location of the assets, the
level of independence of the Transco, and other relevant factors.
b. Comments
252. Several Commenters \155\ support a generic Commission
determination that Transco formation benefits consumers and that fair
value paid for transmission assets by a Transco will be recoverable,
even if that fair value exceeds the book value of those assets by a
significant amount. Trans-Elect argues for a case-by-case
consideration, i.e., that a Transco should be entitled to make a
showing that the benefits of a particular transaction justify allowing
a specific acquisition adjustment and that the level of proposed
adjustment is appropriate. KKR supports allowing a Transco Applicant to
recover an acquisition premium in rates for all or a portion of any
premium paid above net book value for purchases of transmission
facilities. PNM encourages the Commission to eliminate its historical
prohibition against recovery of acquisition adjustments for
transmission assets.
---------------------------------------------------------------------------

\155\ E.g., International Transmission, KKR, and Trans-Elect.
---------------------------------------------------------------------------

253. Several commenters \156\ oppose a generic determination
regarding the allowance of acquisition premiums for Transcos, and
generally support the continuation of current Commission policy which,
according to commenters, is case-by-case. They also oppose the
Commission making a general determination that Transco formation
results in general benefits to customers for purposes of determining
whether to allow recovery of an acquisition premium in rates.
---------------------------------------------------------------------------

\156\ E.g., Ameren, APPA, MISO States, Northwestern, NRECA,
Pennsylvania Commission, PEPCO, PJM TOs, Snohomish, TDU Systems, and WPS.
---------------------------------------------------------------------------

254. In response to our request for comment on what measure to use
to evaluate the appropriateness of such premiums, Pennsylvania
Commission states that if the Commission determines that approval of
acquisition adjustments is necessary to encourage acquisition and
mergers of transmission systems in a business-neutral way, the
Commission should require applicant(s) to demonstrate that such costs
were both reasonable and negotiated at arms' length. According to the
Pennsylvania Commission, the applicant should be required to offer
proof that the purchase price of assets had a reasonable relationship
to the market valuation of the assets transferred, that the buyer and
seller were financially separate and unrelated, and that directors and
officers of, and advisors to, the buyer and seller had a financial and
legal ``arm's-length'' relationship before and after consummation of
the acquisition. International Transmission suggests that recovery of
the difference between book value and fair value, as represented in a
proposed purchase price, be limited to no more than 50 percent of any
amount paid above the book value of the assets, in order to provide
market discipline with respect to the purchase price of the assets.
Snohomish states that there must be a means to independently verify the
purchase price, such as requiring submission of two or more independent
appraisals.
255. Dairyland supports limiting acquisition adjustments to
situations where the seller of the facilities to a Transco does not
have (or does not simultaneously obtain) an ownership in the Transco.
AEP, PJM TOs and SCE state that if the Commission allows recovery of
acquisition premiums, it should allow all business models to recover
them, including traditional investor-owned utilities.
256. TAPS and TDU systems argue that entities allowed to recover
acquisition premium for the formation of Transcos should not also be
authorized to receive an enhanced ROE.
257. Nevada Companies state that the Commission must work with
state regulatory authorities to foster Transco formation since
transmission owners' incentives are reduced if they must give a large
portion of an acquisition premium back to customers.
c. Commission Determination
258. We will not in this Final Rule change the Commission's policy
of allowing acquisition adjustments in rates only upon a specific
showing of ratepayer benefit.\157\ However, given the positive
contributions of Transcos on transmission investment discussed above,
we find that a Transco may propose an acquisition premium as an
incentive under the Final Rule, as provided under Sec.
35.35(d)(1)(viii). We

[[Page 43324]]

will continue to evaluate proposals made by Transcos to recover
acquisition premiums associated with the purchase of transmission
facilities on a case-by-case basis. We appreciate the comments on how
the Commission should evaluate the level of acquisition premiums, such
as those from Pennsylvania Commission, International Transmission, and
Snohomish, and we will take such factors into account in evaluating
whether to allow recovery of particular acquisition premiums. While
this discussion is limited to providing an incentive for Transco
formation, entities other than Transcos can apply for the incentive and
the Commission will evaluate those applications on a case-by-case basis.
---------------------------------------------------------------------------

\157\ While the proposed ADIT incentive discussed above would
adjust book value and therefore may be considered a premium on net
book value, we note that unlike the acquisition premium discussed
here, the proposed ADIT incentive addresses tax-related issues
outside of the applicant's control.
---------------------------------------------------------------------------

5. Merchant Transmission
a. Comments
259. LIPA states that because of the NOPR's focus on cost-of-
service ratemaking, it has less impact on merchant transmission
developers, whose rates are defined by contract (and thus market
benefit), and not by Commission cost-of-service ratemaking standards.
Merchant transmission developers are generally required to rely on
market rates for transmission service negotiated directly with
purchasers of their capacity, and to assume (along with the purchasers
of their capacity) all of the market risk for their facilities.
Merchant transmission developers will base their decisions on other
factors, particularly their ability to efficiently attain the market
benefits that their investments create.
260. TransCanada believes that a two-tier subscription process
would provide merchant developers with some initial regulatory and
business certainty by addressing the initial up-front siting and
permitting risk (because of the ability to secure meaningful
commitments from the first tier subscribers). It would also allow for a
full open season for the remainder of the capacity (the second tier)
consistent with current Commission policy.
261. National Grid states that the key issues raised in this
rulemaking (ensuring adequate returns on equity for investment and
independence, facilitating timely and complete cost recovery, etc.) are
regulated rate issues, which should be of no concern to merchant
transmission developers.
b. Commission Determination
262. With respect to comments on merchant transmission, we agree
with comments that this issue is beyond the scope of this Final Rule.
Merchant projects are market driven while this final rule deals
fundamentally with regulated transmission rates. True merchant
transmission projects may play an important role in the future of
transmission infrastructure development, but incentives related to, for
example, ROE and cost recovery, do not apply to merchant transmission.

D. Performance-Based Ratemaking

1. General Comments
a. Background
263. In the NOPR, the Commission sought comments on ways
performance-based ratemaking (PBR) might apply to for-profit Transcos
and traditional public utilities, and not-for-profit Transcos and
public utility ISOs and RTOs. In the case of for-profit entities, the
Commission sought comment on whether there should be mechanisms for
sharing gains with ratepayers and, if so, what those mechanisms should
be. In the case of not-for-profit public utility ISOs and RTOs, the
Commission sought comment on whether and how PBR developed for for-
profit entities might be applied to not-for-profit entities. Finally,
the Commission sought comment on whether performance-based benchmarks
for transmission costs would provide incentives for the deployment of
advanced technologies.\158\
---------------------------------------------------------------------------

\158\ NOPR at P 58.
---------------------------------------------------------------------------

b. Comments
264. Commenters generally support the concept of PBR, especially as
it was defined in the Commission's 1992 Policy Statement on Incentive
Regulation and in Order No. 2000, which emphasize that PBR should be
voluntary, have both an upside and downside, that gains should be
shared with ratepayers, that benefits should be quantifiable, and that
costs to consumers under PBR should not exceed what they would have
been under traditional regulation. They urge the Commission to retain
these principles.\159\
---------------------------------------------------------------------------

\159\ E.g., NASUCA, TDU Systems, Missouri Commission, and SMUD.
---------------------------------------------------------------------------

265. However, citing to current market structure, most commenters
expressed a general lack of enthusiasm for PBR, and none held out any
expectation that PBR would have a significant role to play in providing
consumer benefits. Chief among the obstacles cited to implementing PBR
is a difficulty in determining appropriate performance measures or
benchmarks. For example, KCP&L emphasized that experts, such as EPRI,
are researching appropriate performance measures but have not yet
determined how to account for various factors such as system age and
configuration, geography and customer density, a point of view shared
by many.\160\ Moreover, APPA cautions that poorly designed performance
measures could lead to unintended and undesirable consequences, and it
recommends that the Commission conduct a series of technical
conferences and workshops on PBR before considering any implementation.
The Kentucky Commission states that performance-based benchmarks for
transmission costs are not necessary because any technology that is
beneficial will have an economic reward, thereby providing its own
incentive. The transmission tariff should reflect prudent operation and
maintenance so that, if there is improvement, a greater profit will be
realized. For proven technologies, a sharing of both benefits and the
risks would be appropriate for deployment of new technologies. Thus,
many conclude that the value of PBR seems remote, although voluntary
programs could be worth considering.
---------------------------------------------------------------------------

\160\ E.g., Comments of KCPL, SCE, and EEI.
---------------------------------------------------------------------------

266. Some commenters oppose PBR because they believe it could deter
investment in transmission facilities, contrary to the main objective
of the proposed rulemaking. For example, International Transmission
concludes that PBR might play a limited role in some circumstances, but
warns that some PBR approaches, such as price cap regulation, could
actually discourage investment. Others, such as FirstEnergy and Nevada
Companies are concerned that PBR could increase risk and, thus, reduce
investment. Some commenters believe that PBR might have a limited role
in inducing utilities to adopt certain innovative practices and
advanced technologies,\161\ while other commenters were more concerned
that PBR would discourage reliability and provide unwarranted benefits
to utilities.\162\
---------------------------------------------------------------------------

\161\ E.g., Comments of AEP and UTC Power.
\162\ E.g., Comments of NSTAR and the New Mexico AG.
---------------------------------------------------------------------------

267. Few commenters see any realistic role for PBR as a means of
inducing cost saving behavior on the part of non-profit entities,
although some, such as Ameren, believe that the Commission's oversight
is inadequate. Industrial Consumers, in particular, express the view
that PBR has no role to play in the non-profit area and, furthermore,
that PBR should not be applied to the profit area unless a proven model
would make pricing under PBR as transparent as pricing under
conventional ratemaking.

[[Page 43325]]

Some commenters \163\ stress that safeguards already exist to insure
that ISOs/RTOs are efficient and accountable, and they argue that there
is no urgency to adopt PBR for RTOs/ISOs. Although they could consider
PBR on a limited, case-by-case basis, PJM TOs also emphasize that RTOs
with regional planning processes and requirements outside the
transmission owners' control are poor candidates for PBR.
---------------------------------------------------------------------------

\163\ E.g., NYISO, CAISO, PJM TOs and NECOE.
---------------------------------------------------------------------------

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

\164\ Comments of Connecticut DPUC, Affidavit of Thomas P. Lyon
at 16-19.
\165\ Comments of Connecticut DPUC, Affidavit of Pete Landrieu at 27-28.
---------------------------------------------------------------------------

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

[[Page 43326]]

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

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

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

E. Advanced Technologies

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

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

281. The NOPR also asked for comments on: (1) Whether the
Commission should require that applications for incentive-based
treatment include a technology statement; (2) whether other incentives
could fulfill the goals of section 219(b)(3); and (3) whether
performance-based benchmarks for transmission costs (i.e., a risk-
sharing approach) would provide incentives for the deployment of
advanced technologies.\168\
---------------------------------------------------------------------------

\168\ NOPR at P 64-66.
---------------------------------------------------------------------------

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

[[Page 43327]]

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

[[Page 43328]]

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

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

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

[[Page 43329]]

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

316. Some of these commenters also assert that the incentive should
not apply where a transmission owner is ordered to join a RTO/ISO by
statute or has agreed to join an RTO/ISO as a condition of receiving
approval for a merger, market-based rates, or because of other
regulatory actions. Also, possible incentives for joining an RTO, and
the procedures for requesting such incentives, are already addressed in
Order No. 2000.
317. Certain commenters \172\ contend that the Commission should
consider giving ROE incentives only to companies joining a newly
forming Transmission Organization, rather than existing ones, and then
only for a limited period of time; and if a public utility withdraws
from an RTO or ISO for which it obtained an ROE adder for joining, the
Commission should issue an order immediately eliminating such ROE adders.
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\172\ E.g., MISO States, NRECA, and TDU Systems.
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318. Others request that the Commission make a generic finding that
entities that join an ISO or RTO automatically qualify for the
incentive. For example, Trans-Elect submits that the Commission can and
should use the record developed in this proceeding to find, on a
generic basis, that RTO/ISO membership produces sufficient customer
benefits to qualify for the 50 basis-point ROE adder.
319. Some commenters \173\ state that this incentive should not be
limited to public utilities. It should apply to all transmitting
utilities and electric utilities, including municipal utilities.
Another view, that of Northwestern's, would have the Commission
consider granting such incentives to transmission owners that are
actively engaged in the development of an RTO or ISO, and permit
transmission owners to recover prudently incurred costs of developing
an RTO or ISO as they are incurred, in regions that do not currently
have such an independent entity. American Wind strongly supports the
objective to regionalize the grid, but believes that it would not serve
the Commission's or Congress' goal to allow incentives to any type of
Transmission Organization that is approved by the Commission for the
operation of facilities. For example, American Wind states that single-
system Transcos do nothing for regional goals.
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\173\ E.g., CAISO, APPA, and NRECA.
---------------------------------------------------------------------------

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

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

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

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

[[Page 43330]]

regional planning process may be sensible, but incentives must be tied
to implementation of the regional plan, not just for mere participation
in the organization.
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\177\ E.g., Ameren, Southern Companies, SCE, PJM, and MidAmerican.
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3. Commission Determination
326. To the extent within our jurisdiction, we will approve, when
justified, requests for ROE-based incentives for public utilities that
join and/or continue to be a member of an ISO, RTO, or other
Commission-approved Transmission Organization. However, we are not
persuaded that we should create a generic adder for such membership,
but instead will consider the appropriate ROE incentive when public
utilities request this incentive. The decision in this rule to consider
specific incentives on a case-by-case basis fulfills the Congressional
mandate to the Commission.\178\ Thus, issues concerning risk such as
those raised by SMUD are more appropriately addressed in the
proceedings that evaluate proxy companies and set a zone of reasonableness.
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\178\ We believe that the Commission's accounting and reporting
procedures for RTOs, as required by Order No. 668, address
commenters' concerns about the management of RTO costs. See
Accounting and Financial Reporting for Public Utilities Including
RTOs, Order No. 668, FERC Stats. & Regs. ] 31,199 (2005).
---------------------------------------------------------------------------

327. We will not make a generic finding on the duration of
incentives that will be permitted for public utilities that join
Transmission Organizations. An entity will be presumed to be eligible
for the incentive if it can demonstrate that it has joined an RTO, ISO,
or other Commission-approved Transmission Organization, and that its
membership is ongoing. Any public utility receiving an incentive ROE
for joining a Transmission Organization but that withdraws from such
organization is no longer eligible for the ROE incentive.
328. We will not broaden or restrict the definition of Transmission
Organization. For purposes of this Final Rule, and as defined in
section 3(29) of the FPA, a Transmission Organization means a Regional
Transmission Organization, Independent System Operator, independent
transmission provider, or other transmission organization finally
approved by the Commission for the operation of transmission
facilities. We note that all RTOs and ISOs are already covered by this
definition, and we will consider, on a case-by-case basis, applications
for other types of entities to be classified as Transmission
Organizations for purposes of whether membership warrants incentives
under these provisions.
329. With respect to NorthWestern's argument that the Commission
should consider incentives for the development of a Transmission
Organization and permit recovery of prudently incurred costs of such
development as they are incurred, the Commission will review
applications for incentives in the context of filings for the creation
of Transmission Organizations and determine the appropriate methods for
recovery of costs on a case-by-case basis. With respect to comments
suggesting specific criteria to qualify for the incentive (e.g.,
participation in a planning process) or that the level of the incentive
be tied to meeting certain criteria, we will not specify such criteria
in this Final Rule.
330. Several comments urge that eligibility for these incentives
not be limited to public utilities. However, the fact is that section
219(a) directs that this rulemaking provide incentives for ``public
utilities'' and public utilities are the only entities whose rates are
jurisdictional under sections 205 and 206 of the FPA. Further, although
section 219(c) refers to incentives for ``transmitting utilities'' and
``electric utilities'' that join Transmission Organizations, it also
contains the provision ``to the extent within its jurisdiction.''
Accordingly, the rule will apply to jurisdictional public
utilities.\179\ We clarify that this does not mean that public
utilities are precluded from proposing incentive plans under section
205 whereby incentives would be given to public utilities as well as
nonpublic utilities. Indeed, we encourage such plans. However, we would
generally not have authority under sections 205 and 206 to enforce such
incentives for the nonpublic utilities.
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\179\ We note that new section 211A gives the Commission
authority to order transmission services by otherwise
nonjurisdictional transmitting utilities. The Commission has never
exercised authority under the new provision and the new provision
provides limited rate authority. However, we leave open the
possibility that incentives for otherwise nonjurisdictional
transmitting utilities could be permitted in an order under section 211A.
---------------------------------------------------------------------------

331. We also clarify that, as explained earlier, entities that have
already joined, and that remain members of, an RTO, ISO, or other
Commission-approved Transmission Organization, are eligible to receive
this incentive. The basis for the incentive is a recognition of the
benefits that flow from membership in such organizations and the fact
continuing membership is generally voluntary.\180\ Our interpretation
of the statute is that eligibility for this incentive flows to an
entity that ``joins'' a Transmission Organization and is not tied to
when the entity joined. As some commenters note, to do otherwise could
create perverse incentives for an entity to actually leave Transmission
Organizations and then join another one. It would also be unduly
discriminatory for the Commission to consider the benefits of
membership in determining the appropriate ROE for new members but not
for similarly situated entities that are already members.
---------------------------------------------------------------------------

\180\ Our clarification also applies to utilities that joined RTOs or
ISOs because of merger conditions or market-based rate requirements.
---------------------------------------------------------------------------

332. We will not at this time establish a specific incentive for
joining a Commission-approved regional planning organization. A
regional planning process is very important to meeting regional
transmission needs, and, we believe it will produce benefits for
customers. For this reason, we have initiated a proposed rulemaking to
require transmission providers to coordinate with interconnected
systems when planning transmission system additions.\181\ This
increased coordination in regional planning proposed in the OATT Reform
NOPR would be mandatory, not optional, and therefore we will not offer
at this time an incentive for such coordination. However, if a region
develops a planning processes that is superior to that required by the
OATT reform rulemaking (such as by using an independent entity to
perform system planning), nothing in this final rule would preclude
entities in the region from requesting appropriate incentives under FPA
section 219.
---------------------------------------------------------------------------

\181\ See OATT Reform NOPR at 214.
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333. As stated earlier in this Final Rule, we will not adopt
performance-based ROEs that reduce ROEs for transmitting utilities that
do not join Transmission Organizations, as recommended by several
commenters. The purpose of this rule is to provide incentives, per the
requirements of section 219.

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

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

[[Page 43331]]

Organization may propose, and the Commission may approve by rule or
order, reliability standards.\182\ Pursuant to section 219(b)(4)(A) of
the FPA, the NOPR (at P 47) proposed to allow recovery of all prudently
incurred costs necessary to comply with these mandatory reliability
standards. Proposed new Sec. 35.35(f) would allow for such recovery.
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\182\ An Electric Reliability Organization is the organization
certified by the Commission to establish and enforce reliability
standards for the bulk power system, subject to Commission review.
See Order Nos. 672 and 672-A.
---------------------------------------------------------------------------

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

[[Page 43332]]

H. Public Power

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

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

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

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

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

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

\186\ E.g., TAPS, TANC, NECOE, Citizens Energy, TDU Systems, and
Municipal Commenters..
\187\ E.g., KCPL and EEI.
---------------------------------------------------------------------------

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

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

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

V. Reporting Requirement

A. Background

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

[[Page 43333]]

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

B. Comments

360. A number of commenters \189\ support the proposed Form X
reporting requirement. For example, International Transmission states
that such reports are important to determine if the investment
incentives adopted by the Commission are actually working to elicit
investment in transmission that benefits consumers. Some of these
commenters make a number of recommendations, including the following:
Define transmission investment for reporting; include separate
categories for new generation interconnection versus other types of
system upgrades; classify investments by voltage level to distinguish
facilities that have little or nothing to do with the interstate
transmission grid; exclude small, miscellaneous upgrades; provide
instructions that Transmission Facilities in the table ``Capital
Spending On Electric Transmission Facilities'' are defined as
transmission assets under the Uniform System of Accounts in accounts
350 through 359; like the report with FERC Form No. 1; provide a list
of categories for the ``Reasons for Delay'' column, such as siting,
delayed completion of a new generator; report the consumer benefits of
the project (e.g., congestion relief, enhanced reliability); require
the posting of the information on RTO, ISO, Transco or public utility
Web sites or OASIS; require that all the reports be aggregated in one
report that is made public, thereby providing manufacturers with a
better basis to plan for industry needs.
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\189\ E.g., International Transmission, NRECA, APPA, National
Grid, AEP and TAPS, Siemans, and NEMA.
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361. Commenters also contend that the report does not go far
enough. \190\ Some \191\ state that such reports should extend to all
transmission providers, including those subject to new section 211A of
the FPA and government-owned entities. Semantic asserts that the
reporting requirements proposal is incomplete and does not adequately
secure the comprehensive state of the grid information required by the
regulators and market participants. Semantics would require that power
systems state data must be made available in real-time to identify
parallel flows and to avoid under-investment, over-investment or bad
investments; that the report should provide for the filing of data that
enables the Commission to fulfill its oversight responsibility for RTOs
under Sec. 35.34(k)(4) and to promote compliance with Sec.
35.34(k)(1). Semantics further recommends that time of day rate
schedules should be reported into a web-accessible national repository.
Semantic explains that capital investment in advanced technologies will
relieve congestion if this information is made known to technology
vendors and entrepreneurial entities.
---------------------------------------------------------------------------

\190\ E.g., International Transmission, Northwestern, Siemans,
NEMA, and Semantic.
\191\ E.g., International Transmission, EEI, Northwestern, and KCP&L.
---------------------------------------------------------------------------

362. Certain commenters \192\ that support the reporting also
express concerns. For example, National Grid states the Commission
should clarify that the forward-looking projections in Form X, rendered
in good faith and upon a reasonable basis, would not subject the
reporting transmission owners to claims of fraud, detrimental reliance
or other liabilities arising from the fact that actual capital spending
may vary from reported projections.\193\ Ameren requests that the
Commission clarify that the reported information is to be provided for
informational purposes only and should not be allowed to form the basis
of a review by the Commission or other entities regarding the
reasonableness or prudence of the amounts reported. PG&E and the Nevada
Companies assert that a disclaimer should be added to footnote 1
explaining that much of the information reported here may change over
time and may be subject to correction. Trans-Elect asserts that the
reporting requirement, alone, should not be allowed to form a basis for
a section 206 investigation.
---------------------------------------------------------------------------

\192\ E.g., National Grid, Ameren, PG&E, and Nevada Companies.
\193\ See Section 27A of the Securities Act of 1933, as amended;
Section 21E of the Securities Exchange Act of 1934, as amended; 15
U.S.C. 77z-2 and 78u-5; 17 CFR 240.3b-6.
---------------------------------------------------------------------------

363. Some commenters raise confidentiality concerns.\194\ EEI and
KCP&L urge that the Commission afford Critical Energy Infrastructure
Information (CEII) \195\ status to this information since it clearly
relates to the production, generation, transmission or distribution of
energy, could be useful to a person planning an attack and gives
strategic information beyond the location of critical infrastructure.
EEI encourages the Commission to perform an evaluation as to the need
for confidentiality of selected company information due to the
commercially sensitive nature of the information. Similarly, Ameren and
TransElect request that the Commission clarify that the required
information may be submitted pursuant to the Commission's confidential
filing procedures.\196\
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\194\ E.g., TransElect, EEI, KCP&L, and Ameren.
\195\ They cite Critical Infrastructure Information, Order No.
630, 68 FR 9857 (March 3, 2003), FERC Stats. & Regs. ] 31,140
(2003), order on reh'g, Order No. 630-A, 68 FR 46,456 (Aug. 6,
2003), FERC Stats. & Regs. ] 31,147 (2003).
\196\ See 18 CFR 388.112.
---------------------------------------------------------------------------

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

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

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

[[Page 43334]]

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

C. Commission Determination

367. To ensure that these rules are successfully meeting the
objectives of section 219, the Commission needs industry data,
projections and related information that detail the level of
investment. The rule's purpose is to both provide new investment as
well as ensure that customers benefit. Thus, information regarding
projected investments as well as information about completed projects
will help the Commission to monitor the success of the ratemaking
reforms announced in this rule. Thus, the Commission will adopt the
proposed reporting requirement Form X and designate it as the FERC-730.
Further, the Commission will make certain modifications to clarify when
reports must be filed and what data must be submitted in FERC-730
reports.\198\ The information required in FERC-730 is not available
from Form Nos. 1, 714 or 715, nor is it available from other federal
agencies. For instance, FERC Form No. 1 requires the reporting of
historical financial data but does not contain forward looking
projections of expected transmission investments.\199\ Thus, the
information sought is not already readily available and will be
required only from public utilities that have been granted incentive
rate treatment for specific transmission projects under the provisions
of Sec. 35.35.
---------------------------------------------------------------------------

\198\ FERC-730 filers are reminded that each FERC-730 filing
must be accompanied by a Subscription consistent with the
requirements of 18 CFR 385.2005(a).
\199\ See e.g., FERC Form No. 1 schedule pp. 204-7, ``Electric
Plant in Service (Accounts 101, 102, 103 and 106)'' which requires
the reporting of the original cost of electric plant in service and
p. 216, ``Construction Work in Progress--Electric (Account 107)''
which requires the reporting of expenditures for certain
construction projects at December 31 of the reporting year.
---------------------------------------------------------------------------

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

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

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

[[Page 43335]]

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

VI. Other Issues

A. Rate Related Issues

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

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

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

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

\205\ E.g., TAPS and Upper Great Plains.
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c. Comments on Five-Month Suspension
384. EEI, SCE and Xcel argue that the Commission's current
suspension policy hinders transmission investment because delaying the
effective date of rates forces a utility to absorb the costs associated
with the new facilities during the suspension period, thereby
effectively reducing that utility's return on equity. Additionally, EEI
argues that, because any rate increase authorized by the Commission
could be made subject to refund, with interest, customers could be made
whole even without a five-month suspension. SCE suggests that the
Commission should either change the threshold for determining when
rates are excessive or use a sliding scale that would impose a longer
suspension the larger the excessive revenues.
d. Other Comments on Rate Design
385. Commenters raised a variety of rate design issues. Energy
Capital states that the Commission must modify traditional ratemaking
practices to recognize the risks and structures required to fund a
single line transmission project. SCE states that an

[[Page 43336]]

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

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

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

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

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

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

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

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

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

B. Section 35.34

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

[[Page 43337]]

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

VII. Information Collection Statement

406. The Office of Management and Budget (OMB) regulations require
approval of certain information collection requirements imposed by
agency rules.\211\ The Commission is submitting these reporting
requirements to OMB for its review and approval under section 3507(d)
of the Paperwork Reduction Act.\212\ Upon approval of a collection(s)
of information, OMB will assign an OMB control number and an expiration
date. Respondents subject to the filing requirements of this rule will
not be penalized for failing to respond to these collections of
information unless the collections of information display a valid OMB
control number. Interested persons may obtain information on the
reporting requirements by contacting: Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426 [Attention:
Michael Miller, Office of the Executive Director, Phone: (202) 502-
8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov].
---------------------------------------------------------------------------

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

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

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

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

[[Page 43338]]

Frequency of Responses: On occasion for applicants and annually for
transmission investment report.
Necessity of the Information: The Final Rule amends the
Commission's regulations to implement the statutory provisions of
section 1241 of EPAct 2005. The Act directs the Commission to establish
incentive-based (including performance-based) rate treatments for the
transmission of electric energy in interstate commerce by public
utilities in order to benefit consumers by ensuring reliability and
reducing the cost of delivered power by relieving transmission
congestion. This mandate addresses an identified need to encourage
construction of transmission infrastructure and encourage investment.
Sufficient supplies of energy and a reliable way to transport those
supplies are necessary to assure reliable energy availability and to
enable competitive markets. Without sufficient delivery infrastructure,
some suppliers will not be able to enter the market, customer choices
will be limited, and prices may be needlessly higher or volatile. The
implementation of incentive and performance-based rate treatments
supports the Commission's mandate to support investments in transmission
capacity to reduce the cost of delivered power by reducing congestion.
408. Entities seeking incentives to build new transmission
facilities must file under Part 35 of the Commission's regulations, an
application describing how the entity will bring benefits to the grid.
The information provided for under Part 35 is identified as FERC-516.
The information for actual and planned investments as proposed in an
annual report is identified as FERC-730 and the information is provided
for under Sec. 35.35(h) of the Commission's regulations.
409. Comments on the final rule may also be sent to the Office of
Management and Budget. For information on the requirements, submitting
comments on the collection of information and the associated burden
estimates including suggestions for reducing this burden, please send
your comments to the Federal Energy Regulatory Commission, 888 First
Street, NE., Washington, DC 20426 (Attention: Michael Miller, Office of
the Executive Director, (202-502-8415) or send comment to the Office of
Management and Budget (Attention: Desk Officer for the Federal Energy
Regulatory Commission, fax: 202-395-7285, e-mail:
oria_submission@omb.eop.gov., and please reference this rulemaking docket
no. in your submission.

VIII. Environmental Statement

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

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

IX. Regulatory Flexibility Act Certification

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

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

X. Document Availability

412. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A,
Washington, DC 20426.
413. From the Commission's Home Page on the Internet, this
information is available in the eLibrary. The full text of this
document is available on eLibrary both in PDF and Microsoft Word format
for viewing, printing, and/or downloading. To access this document in
eLibrary, type the docket number excluding the last three digits of
this document in the docket number field.
414. User assistance is available for eLibrary and the Commission's
Web site during normal business hours. For assistance, please contact
Online Support at 1-866-208-3676 (toll free) or 202-502-6652 (e-mail at
FERCOnlineSupport@FERC.gov), or the Public Reference Room at 202-502-
8371, TTY 202-502-8659 (e-mail at public.referenceroom@ferc.gov).

XI. Effective Date and Congressional Notification

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

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

List of Subjects in 18 CFR Part 35

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

By the Commission.
Magalie R. Salas,
Secretary.

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

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.

Subpart F--Procedures and Requirements Regarding Regional
Transmission Organizations

Sec. 35.34 [Amended]

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

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

[[Page 43339]]

Subpart G--Transmission Infrastructure Investment Provisions

Sec. 35.35 Transmission infrastructure investment.

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

[[Page 43340]]

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

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

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

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

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

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

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

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

Appendix B--Commenters on the NOPR

Public Utilities and Trade Associations

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

Public Power Entities and Associations

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

[[Page 43341]]

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

State Commissions and Other State Entities

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

Others

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

Reply and Supplemental Comments

EEI
International Transmission
KKR
National Grid

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