[Federal Register Volume 71, Number 146 (Monday, July 31, 2006)]
[Rules and Regulations]
[Pages 43294-43341]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-6495]



[[Page 43293]]

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Part II





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Part 35



Promoting Transmission Investment Through Pricing Reform; Final Rule

  Federal Register / Vol. 71, No. 146 / Monday, July 31, 2006 / Rules 
and Regulations  

[[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]


Promoting Transmission Investment Through Pricing Reform

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

ACTION: Final rule.

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

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

FOR FURTHER INFORMATION CONTACT: Jeffrey Hitchings (Technical 
Information), Office of Energy Markets and Reliability, Federal Energy 
Regulatory Commission, 888 First Street, NE, Washington, DC 20426, 202-
502-6042.
    Sebastian Tiger (Technical Information), Office of Energy Markets 
and Reliability, Federal Energy Regulatory Commission, 888 First 
Street, NE, Washington, DC 20426, 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..................................................
 


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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.
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3. Commission Determination
    34. Section 219 of the FPA became effective on August 8, 2005. 
Codification of section 219 on that date and the requirement for a rule 
authorizing investment incentives provided notice to the industry that 
Congress intended that the Commission provide incentive-based rate 
treatments promptly. Thus, the Final Rule will become effective 60 days 
after publication in the Federal Register. However, we clarify that any 
investment made in, or costs incurred for, transmission infrastructure 
after August 8, 2005 that ensures reliability or lowers the cost of 
delivered power by reducing transmission congestion will be eligible 
for incentive-based rate treatments under this Rule. Applicants seeking 
incentive-based rate treatments for investments made or costs incurred 
after August 8, 2005 will need to satisfy the requirements of this Rule 
to obtain and recover any incentives and will need to make an 
appropriate filing under section 205.
    35. The fact that a proposed expansion was in a utility's expansion 
plan as of August 8, 2005 does not disqualify the project for incentive 
treatment. Inclusion of a facility in a plan does not mean that a 
project can or will get built. Even where a project already has been 
planned or announced, the granting of incentives may help in securing 
financing for the project or may bring the project to completion sooner 
than originally anticipated. Congress's directive that the Commission 
issue a rule within one year of enactment of EPAct 2005 shows that 
Congress intended for the Commission to take steps to bring new 
transmission on line expeditiously.
    36. With respect to the issue of how long an incentive-based 
proposal should remain in effect, the Commission recognizes that it may 
be necessary to authorize incentives that may extend over several years 
in order to support investment in long-term transmission. It can be 
important to investors making long-term investments in long-lived 
facilities to be assured that a ratemaking proposal adopted prior to 
construction of those facilities will not later be altered in a manner 
that undermines the basis for the financing of those facilities. The 
Commission will therefore allow applicants to propose specific time 
periods by which their incentive-based proposals will not be ``re-
opened'' in a manner incompatible with the nature of the initial 
approvals. However, to ensure that ratepayers are also adequately 
protected, we will require any applicants seeking such a fixed term for 
its plan to explain how ratepayers can be assured that such a plan is 
delivering the benefits that formed the basis for the Commission's 
initial approval of it. For example, an applicant may propose periodic 
progress assessments with appropriate metrics to measure how well the 
project is progressing and whether the proposed investment in new 
transmission is improving reliability or reducing congestion. Such 
metrics would provide the Commission a means to determine whether and 
how the applicant is providing the anticipated benefits and thus that 
the approved incentives need not be revisited. Because the scope and 
size of each project will differ, any applicant seeking incentive-based 
rate treatments may propose metrics for its project as well as the 
frequency for review of those metrics.\27\ An applicant may include its 
proposed metrics and any timetable for review in its section 205 rate 
filing seeking recovery of incentives.\28\ Where such metrics are found 
to be needed and are approved by the Commission, an applicant would be 
required to submit information filings to the Commission consistent 
with the approved metrics and timetable. We clarify, however, that the 
metrics reviews will not be opportunities to re-argue the issues 
addressed in proceedings granting the incentive-based rates; they are 
for the purpose of measuring whether the plan is being implemented as 
initially approved.
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    \27\ The information may include, as well as supplement, 
information provided in FERC-730, discussed in section V below.
    \28\ An applicant has the option to include metrics proposals in 
a declaratory order proceeding, but would also need to include them 
in the subsequent section 205 rate filing.
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IV. Discussion

A. Standard for Approval of Incentive-Based Rate Treatments

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

    \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).
---------------------------------------------------------------------------

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

    \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).
---------------------------------------------------------------------------

    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.
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    \71\ See American Transmission, supra note 2.
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    105. The Commission stated in the NOPR that allowing public 
utilities, on a case-by-case basis, to include up to 100 percent of 
prudently incurred transmission-related CWIP in rate base and 
permitting them to expense prudently incurred pre-commercial operations 
costs will further the goals of section 219 by relieving the pressures 
on utility cash flows associated with their transmission investment 
programs and providing up-front regulatory certainty. The Commission 
specifically requested comment on (1) the types of costs that should be 
considered ``pre-commercial'' operation costs; and (2) whether there 
should be a presumption that these incentives meet the requirements of 
FPA section 219 that investments ensure reliability and reduce the cost 
of delivered power.
b. Comments
    106. Most of the commenters,\72\ support including 100 percent of 
prudently-incurred CWIP in rate base and expensing all pre-commercial 
operation costs, stating that these incentives will encourage 
transmission investment through improved cash flow, greater rate 
stability and lower rates to future customers. Additionally, SDG&E 
notes that this incentive will balance short-term rates and long-term 
rates by increasing the rates during construction but lowering the 
rates during operation of a facility.
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    \72\ E.g., EEI, American Transmission, AWEA, PG&E, AEP, NSTAR, 
WPS and TDU Systems.
---------------------------------------------------------------------------

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

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

    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\
---------------------------------------------------------------------------

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

    \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\
---------------------------------------------------------------------------

    \85\ PJM TOs concur that the incentive could be helpful in 
project-specific rates.
---------------------------------------------------------------------------

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

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

[[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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \90\ We note that many commenters support case-by-case review 
and recognize the merits of evaluating the specific circumstances of 
hypothetical capital structure proposals.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[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\
---------------------------------------------------------------------------

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

[[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.
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    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.
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    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.
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    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.
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    \175\ E.g., California Oversight Board, TDU Systems, and 
TransCanada.
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    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.
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    331. We also clarify that, as explained earlier, entities that have 
already joined, and that remain members of, an RTO, ISO, or other 
Commission-approved Transmission Organization, are eligible to receive 
this incentive. The basis for the incentive is a recognition of the 
benefits that flow from membership in such organizations and the fact 
continuing membership is generally voluntary.\180\ Our interpretation 
of the statute is that eligibility for this incentive flows to an 
entity that ``joins'' a Transmission Organization and is not tied to 
when the entity joined. As some commenters note, to do otherwise could 
create perverse incentives for an entity to actually leave Transmission 
Organizations and then join another one. It would also be unduly 
discriminatory for the Commission to consider the benefits of 
membership in determining the appropriate ROE for new members but not 
for similarly situated entities that are already members.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

V. Reporting Requirement

A. Background

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

[[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.
---------------------------------------------------------------------------

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

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

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

    \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: [email protected]., 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 
[email protected]), or the Public Reference Room at 202-502-
8371, TTY 202-502-8659 (e-mail at [email protected]).

XI. Effective Date and Congressional Notification

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

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

List of Subjects in 18 CFR Part 35

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

    By the Commission.
Magalie R. Salas,
Secretary.

0
In consideration of the foregoing, the Commission amends part 35 of 
Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

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

Subpart F--Procedures and Requirements Regarding Regional 
Transmission Organizations


Sec.  35.34  [Amended]

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

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

[[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]
BILLING CODE 6717-01-P