Promoting Transmission Investment Through Pricing Reform

Federal RegisterJul 31, 2006

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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.

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

II. Background

III. Overview

A. The Need for New Transmission Facilities

1. Background

2. Comments

3. Commission Determination

B. The Need for Incentives

1. Background

2. Comments

3. Commission Determination

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

D. Effective Date and Duration of Effectiveness For Incentives

1. Background

2. Comments

3. Commission Determination

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

2. Other Criteria For Approval of Incentives

3. Rebuttable Presumptions

4. Applicants Seeking Incentive-Based Rates Will Not Be Required To File A Cost-Benefit Analysis

5. Procedural Requirements for Obtaining Incentive-Based Rate Treatments

B. Incentives Available To All Jurisdictional Public Utilities

1. ROE Sufficient to Attract Capital

2. Construction Work in Progress (CWIP) and Pre-Commercial Expenses

103

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 Competitive Bidding

273

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 Reliability Standards and Recovery of Prudently Incurred Costs Associated with Transmission Infrastructure Development

334

1. Background

334

2. Comments

336

3. Commission Determination

343

H. Public Power

349

1. Background

349

2. Comments

350

3. Commission Determination

354

V. Reporting Requirement

358

A. Background

358

B. Comments

360

C. Commission Determination

367

VI. Other Issues

377

A. Rate Related Issues

377

1. Rate Related Issues

377

B. Section 35.34

395

1. The Proposal to Eliminate Section 35.34(e)

395

VII. Information Collection Statement

406

VIII. Environmental Statement

410

IX. Regulatory Flexibility Act Certification

411

X. Document Availability

412

XI. Effective Date and Congressional Notification

415

Appendices

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

I. Introduction

1. Pursuant to the directives in section 1241 of the Energy Policy Act of 2005 (EPAct 2005)

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,

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.

Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594, 315 and 1283 (2005).

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

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

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,

to any transmitting utility or electric utility transmitting electric energy in interstate commerce that joins a Transmission Organization.

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.

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.

FERC,

422 F.3d 408 (9th Cir. 2005).

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).

5. Some commenters have argued that few or no incentives are needed to encourage new transmission investment. We reject these comments as fundamentally inconsistent with section 219. Section 219 reflects Congress' determination that the Commission's traditional ratemaking policies may not be sufficient to encourage new transmission infrastructure. Although section 219 does not permit approval of rates that are inconsistent with section 205 or 206, section 219 nonetheless constitutes a clear directive that “the Commission

shall

establish, by rule, incentive-based * * * rate treatments * * * for the purpose of benefiting consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion” (emphasis added). We therefore cannot simply rely on existing ratemaking policy to faithfully implement section 219. This Final Rule therefore identifies a non-exclusive list of ratemaking reforms and requires applicants to tailor their proposals to fit the facts of their particular case.

6. We do agree, however, with the position of certain wholesale customers and state commissions that the Commission should not provide incentives that only serve to increase rates without providing any real incentives to construct new transmission infrastructure. Section 219(a) states that transmission incentives should be “

benefiting consumers

by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion” (emphasis added). The purpose of our Rule is to benefit customers by providing real incentives to encourage new infrastructure, not simply increasing rates in a manner that has no correlation to encouraging new investment. The Final Rule, therefore, makes clear that not every incentive identified herein will be necessary or appropriate for every new transmission investment. To provide guidance in this regard to potential applicants, we discuss below why certain incentives may, as a general matter, be better tailored to certain types of investments than others.

II. Background

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

1. Promote reliable and economically efficient transmission and generation of electricity by promoting capital investment in the enlargement, improvement, maintenance, and operation of all facilities for the transmission of electric energy in interstate commerce, regardless of the ownership of the facilities;

2. Provide a return on equity that attracts new investment in transmission facilities (including related transmission technologies);

3. Encourage deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve the operation of the facilities; and

4. Allow the recovery of all prudently incurred costs necessary to comply with mandatory reliability standards issued pursuant to section 215 of the FPA, and all prudently incurred costs related to transmission infrastructure development, pursuant to section 216 of the FPA (transmission national interest corridors).

8. Section 219(c) requires that the Rule provide for incentives to each transmitting utility or electric utility that joins a Transmission Organization and to ensure that any recoverable costs associated with joining may be recovered through transmission rates charged by the utility or through the transmission rates charged by the Transmission Organization that provides transmission service to the utility. Finally, section 219(d) provides that all rates approved under the Rule are subject to the requirements of sections 205 and 206 of the FPA,

which require that all rates, charges, terms and conditions be just and reasonable and not unduly discriminatory or preferential.

16 U.S.C. 824(d) and 824(e) (2000).

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.

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.

Promoting Transmission Investment Through Pricing Reform,

70 FR 71409 (Nov. 29, 2005), FERC Stats. & Regs., Proposed Regs. ¶ 32,593 (2005).

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.

This decline in transmission investment in real dollars has occurred while the electric load using the nation's grid more than doubled.

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.

EEI Survey of Transmission Investment: Historical and Planned Capital Expenditures (1999-2008) at 3 (2005).

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).

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).

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.

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.

International Transmission cites to studies estimating the cost of power interruptions and fluctuations to range from between $29 billion and $135 billion annually,

the cost of the August 2003 Northeast-Midwest blackout to be between $4 billion and $10 billion,

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,

and increases in PJM congestion costs, from $499 million in 2003 to $808 million in 2004.

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.

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

National Grid and EEI.

3. Commission Determination

34. Section 219 of the FPA became effective on August 8, 2005. Codification of section 219 on that date and the requirement for a rule authorizing investment incentives provided notice to the industry that Congress intended that the Commission provide incentive-based rate treatments promptly. Thus, the Final Rule will become effective 60 days after publication in the

Federal Register

. However, we clarify that any investment made in, or costs incurred for, transmission infrastructure after August 8, 2005 that ensures reliability or lowers the cost of delivered power by reducing transmission congestion will be eligible for incentive-based rate treatments under this Rule. Applicants seeking incentive-based rate treatments for investments made or costs incurred after August 8, 2005 will need to satisfy the requirements of this Rule to obtain and recover any incentives and will need to make an appropriate filing under section 205.

35. The fact that a proposed expansion was in a utility's expansion plan as of August 8, 2005 does not disqualify the project for incentive treatment. Inclusion of a facility in a plan does not mean that a project can or will get built. Even where a project already has been planned or announced, the granting of incentives may help in securing financing for the project or may bring the project to completion sooner than originally anticipated. Congress's directive that the Commission issue a rule within one year of enactment of EPAct 2005 shows that Congress intended for the Commission to take steps to bring new transmission on line expeditiously.

36. With respect to the issue of how long an incentive-based proposal should remain in effect, the Commission recognizes that it may be necessary to authorize incentives that may extend over several years in order to support investment in long-term transmission. It can be important to investors making long-term investments in long-lived facilities to be assured that a ratemaking proposal adopted prior to construction of those facilities will not later be altered in a manner that undermines the basis for the financing of those facilities. The Commission will therefore allow applicants to propose specific time periods by which their incentive-based proposals will not be “re-opened” in a manner incompatible with the nature of the initial approvals. However, to ensure that ratepayers are also adequately protected, we will require any applicants seeking such a fixed term for its plan to explain how ratepayers can be assured that such a plan is delivering the benefits that formed the basis for the Commission's initial approval of it. For example, an applicant may propose periodic progress assessments with appropriate metrics to measure how well the project is progressing and whether the proposed investment in new transmission is improving reliability or reducing congestion. Such metrics would provide the Commission a means to determine whether and how the applicant is providing the anticipated benefits and thus that the approved incentives need not be revisited. Because the scope and size of each project will differ, any applicant seeking incentive-based rate treatments may propose metrics for its project as well as the frequency for review of those metrics.

An applicant may include its proposed metrics and any timetable for review in its section 205 rate filing seeking recovery of incentives.

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.

The information may include, as well as supplement, information provided in FERC-730, discussed in section V below.

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.

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 § 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.

Southern and the Nevada Companies assert the Commission should not require that facilities both improve regional reliability and reduce congestion to be eligible for an incentive ROE. They

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

E.g.

, FirstEnergy, Southern, Nevada Companies, AEP.

39. Several commenters urge the Commission to establish criteria for transmission projects to demonstrate that they achieve Congress' goals before projects receive an incentive.

The New York Commission asks the Commission to convene a technical conference to develop the criteria.

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.

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.

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

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 § 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.

E.g.

, East Texas, TANC, and TAPS.

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

utilities that conform to good utility practice and minimize total costs. Also, NECOE asserts that, when more than one incentive is requested, the Commission should require the applicant to demonstrate why a single, appropriately targeted incentive is insufficient. Several commenters urge the Commission to grant incentives for existing facilities and for maintenance of existing facilities.

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.

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.

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.

E.g.

, TDU Systems, APPA, TAPS, NRECA, NARUC, NASUCA, Connecticut DPUC, New Jersey Board, WPS.

47. Several commenters request that the Commission allow states to play a role in the approval or recovery of incentives because states may hinder recovery of incentives in bundled rates.

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.

E.g.,

CREPC, KCPL, Steel Manufacturers, Montana-Dakota, MidAmerican, and EEI.

b. Commission Determination

48. Congress has determined that there is a need for incentives, and has directed the Commission to issue a rule to provide them. Most of the prerequisites and preconditions raised in the comments reflect a desire to limit or circumscribe the nature or applicability of incentives that may be granted under the rule. We have considered these comments and do not believe that any of them should be adopted at this time. Some of them are consistent with our overall policy goals (such as the emphasis on regional planning) and, to that extent, we explain how we will factor those considerations into an analysis of a proposed incentive. However, some are inconsistent with the policy goals of section 219 because they will only serve to discourage transmission investment. Therefore, unless adopted in other sections of this rule, we will not require applicants to satisfy the requirements proposed in the comments. For example, we reject arguments that an applicant must show that, but for the incentives, the expansion would not occur. Those arguments are based on commenters' conclusions that the Commission's prior issuances (

i.e., Removing Obstacles

order, the 1992 Policy Statement, or the innovative rate proposal in Order No. 2000) required an applicant to show need prior to receiving incentives. However, the Final Rule is based on a clear directive from Congress that does not require an applicant to show that it would not build the facilities but for the incentives. This notwithstanding, we do require applicants to show some nexus between the incentives being requested and the investment being made,

i.e.

, to demonstrate that the incentives are rationally related to the investments being proposed.

49. We also consider our procedures for the approval of incentives to be comprehensive and, therefore, will not attempt to establish gradations regarding either approval requirements or the amount of incentive approved, as recommended by TANC, PJM, Industrial Consumers and others. Section 219 does not mandate higher returns for projects that are part of independent regional planning processes, nor does it require higher standards of review for projects that do not result from independent planning processes. As long as the project ensures reliability or reduces the cost of delivered power by reducing congestion, regardless of where it is located on the nationwide transmission grid, the project is eligible for incentive ratemaking.

50. We will not impose size limits on eligible transmission projects. Projects below 200 kV can have a significant impact on reliability or reduce congestion, and therefore would qualify for incentive treatment. We will also not condition approval of incentives on market power findings. Our regulations and penalties on market power and market behavior are sufficient inducements to ensure markets are not manipulated and, therefore, additional provisions are not necessary.

51. We will not deny incentives to public utilities that have not built transmission upgrades requested by transmission customers. The scope of this Rule is restricted to implementing the requirements of section 219; the appropriate means to address this issue is to file a complaint in a separate proceeding.

52. While the promotion of renewable energy projects supports other policy and regulatory objectives, we will not adopt separate rate-based incentives for renewable energy projects. Congress directed the Commission to issue a rule to ensure reliability or to reduce the cost of delivered power by reducing transmission congestion regardless of the nature of the energy carried over the new transmission facilities. We believe that, by providing incentives applicable to all transmission facilities, the Final Rule provides incentives for transmission to serve renewable resources and, therefore, additional incentives are not necessary.

53. Because section 219 provides a new directive to the Commission to permit greater incentives and does not on its face require an individual showing of need by incentive applicants, we will not require compliance with the 1992 or 1994 Transmission Policy Statements as a precondition for approval of incentives.

54. With regard to state review, the Commission recognizes that incentives for many utilities are incorporated into rates that must receive state commission approval and that many decisions on siting and permitting of new facilities are under the jurisdiction of state and local government authorities. Because of this, we will carefully consider the views of any state bodies having jurisdiction over these matters. We also will, as discussed below, adopt a rebuttable presumption that projects approved by an appropriate state commission or siting authority are eligible for incentives under section 219. We believe that, in these ways, we will appropriately coordinate our consideration of incentives with the

views of responsible state agencies. We will not, however, adopt any further requirements regarding state approval, such as the requirement that an applicant receive state approval of any proposed incentives. While state approval is desirable it is not required by section 219. However, if state approval of a particular plan is required, we expect that any applicant will seek that approval in due course.

55. Finally, we reiterate that an applicant may request any combination of the incentives listed in the Final Rule. Applicants also may request incentives that are not listed in the Final Rule. The Commission will not use the Final Rule to identify each and every incentive an applicant may request. However, this in no way relieves the applicant of fully supporting its rate request and demonstrating that its request for incentives satisfies section 219 and the requirements of this Final Rule. If an interested party believes a particular incentive is not warranted, it may raise its concerns when an applicant proposes that incentive in a declaratory order or in a section 205 rate application.

56. Because section 219 makes clear that the Final Rule should promote capital investment in the operation and maintenance of all facilities for the transmission of electric energy in interstate commerce, new investment in existing facilities will be eligible for incentive-based rate treatments.

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.

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.

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.

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.

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.

State representation in stakeholder committee is a feature of the Midwest ISO,

i.e.

, the Organization of MISO States (MISO States or OMS).

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.

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.

NOPR at P 16.

b. Comments

60. Certain commenters argue that judicial precedent requires that incentive rates be supported by a showing of a quantifiable relationship between the incentive and the result the incentive is intended to achieve

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.

They further argue that

section 219 does not require significant changes to the Commission's existing rules and ratemaking policies governing incentive rates, such as its 1992 Policy Statement

and Order No. 2000,

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.

E.g.,

NECOE, PSE&G, and WPC Companies.

E.g.,

NECOE.

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).

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).

E.g.,

TDU Systems, NRECA, NECOE, and SMUD.

61. Several commenters state that, without a cost-benefit analysis, the Commission has no basis for concluding that a particular incentive provides customers with a net benefit or will be just and reasonable.

The New York Commission suggests that criteria for a cost-benefit analysis be established through a separate technical conference or rulemaking.

E.g.,

NRECA, NARUC, TAPS, East Texas, Connecticut AG, Industrial Customers, NECPUC, California Oversight Board, MISO States, DTE Energy, Wyoming Consumer Advocate, and New York Commission.

62. PJM argues that the Commission should provide incentives for transmission owners' participation in robust regional transmission planning that identifies both the costs and economic benefits of a given project. PJM proposes that such a process should support a rebuttable presumption that the decision to build is prudent and warrants an ROE incentive.

63. East Texas states that utilities engaged in meeting reliability standards, constructing projects across designated corridors and joining qualified Transmission Organizations should be allowed the incentive rates on the simple showing that they seek to recover no more than their prudently incurred costs. SMUD states that, under section 219, an incentive is appropriate only when it results in lower power costs to consumers. The Oklahoma Commission states that the Commission should give direction as to the showing by applicants that is acceptable in lieu of the cost-benefit analysis.

64. Other commenters argue that a cost-benefit analysis is unnecessary.

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.

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.

E.g.,

National Grid.

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).

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.

To carry out this purpose, the Commission may consider non-cost factors as well as cost factors.

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.

See, e.g., Pub. Utilities Comm'n of the State of California

FERC,

367 F.3d 925, 929 (D.C. Cir. 2004) (

CPUC

FERC

citing NAACP

FPC,

425 U.S. 662, 670 (1976).

Id., citing Permian Basin Area Rate Cases,

390 U.S. 747, 791, 815 (1968);

Maine Public Utilities Commission

FERC,

No. 05-1001, slip op. at 19 (D.C. Cir., June 30, 2006).

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,

to promote timely construction of additional needed transmission facilities.

See Western supra

note 2.

E.g.

, Mid-American, Nevada Companies, PacifiCorp, and Northwestern.

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.

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.

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.

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.

Others similarly ask that there be a presumption that facilities included in a regional planning process are eligible for incentives.

Another group of commenters argue that projects need not be part of an independent regional planning process to receive an incentive

because other regional processes will also provide the same benefits.

E.g.

, United Illuminating, Vectren, NSTAR, and EEI.

E.g.

, Nevada Companies and MidAmerican.

E.g.

, EEI, NU, New England TOs, NYSEG, and RGE.

E.g.

, Southern and FirstEnergy.

E.g.

, BG&E, PEPCO, KCPL, National Grid, PJM, PJM TOs, United Illuminating and Vectren.

E.g.

, EEI, Progress, Nevada Companies and FirstEnergy.

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.

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.

E.g.

, Dairyland, TDU Systems, and NASUCA.

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.

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.

E.g.

, PJM TOs, APPA, International Transmission, MidAmerican, Pacificorp, National Grid, Kentucky Commission, PJM, OMS, NRECA and Semantic.

E.g.

, Consumer Energy Council, Ameren, SDG&E, Southern Companies, NorthWestern and PEPCO, Dairyland, and Vectren.

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.

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.

See Western supra

note 2.

78. If an applicant obtains a declaratory order finding that the proposal qualifies for incentive-based rate treatment, the subsequent section 205 proceeding would be limited to a review of the applicant's rates and would not include a review of whether the applicant's facility qualifies to receive incentive-based rate treatments. If the petition addresses the applicant's incentives or finds that the required nexus has been demonstrated, the applicant would not be required to re-justify those findings in the section 205 filing. Therefore, if an interested party believes a petitioner's proposal does not qualify for incentive-based rate treatments or that the incentives requested are not justified, the party must raise its objections when the petition is filed and not wait to raise them in the subsequent section 205 proceeding. If an applicant obtains a declaratory order and the proposal changes from the facts on which the declaratory order was issued, the applicant may seek another declaratory order or wait to seek approval of the changes in the subsequent section 205 filing. In that event, interested parties may challenge the changes in the section 205 proceeding.

79. The second option involves filing only a section 205 filing (either “single-issue” or comprehensive) to request all of the required approvals. Prior to recovering any incentive-based rate treatments in rates, an applicant must demonstrate that the rates in which the applicant seeks to recover any incentives are just and reasonable and not unduly discriminatory. However, the applicant will have the option of filing a comprehensive section 205 rate case in which all of the utility's rates

would be reviewed in conjunction with the proposed recovery of the incentive-based rate treatments or filing a single-issue section 205 rate filing in which only the impact of the incentive-based rate treatment for the facility granted the incentive will be addressed. As explained below in section IV.B.7 (the discussion of single-issue section 205 proceedings), the Commission believes there is a sufficient need for timely investment in transmission infrastructure to justify, in certain circumstances, a departure from our past practice by allowing an applicant to seek to recover any incentive in a single-issue section 205 rate proceeding. Single issue section 205 proceedings, as well as the declaratory order procedural option discussed above, can remove obstacles to new investments by allowing for timely cost recovery. Single issue filings also can support new investment by allowing applicants to compare the returns of such investments with the risks of the project itself, as opposed to having to compare those returns to both the risks of the project being pursued and the risks associated with re-opening all their rates, which is ordinarily a time-consuming, expensive, litigious and uncertain process. Additionally, in further facilitating these goals, the Commission does not intend to routinely convene trial-type, evidentiary hearings to review either a comprehensive or a single-issue section 205 filing but will attempt to render a decision based on the paper submissions whenever possible.

80. We clarify that no incentives will be granted on a final basis without a section 205 filing. Therefore, an RTO member will not automatically receive incentives granted to another RTO member. However, when evaluating applications for incentive-based rate treatments filed by an RTO member, the Commission will take into account incentives granted to other RTO members, particularly in cases where investments being made by that other RTO member pursuant to a regional plan also lead to the need for expansions by the applicant in its own footprint.

81. We will not specify the rate calculations for section 205 proceedings, as requested by TAPS. These issues are appropriately addressed in individual section 205 proceedings.

82. The Commission will require applicants to justify each of the incentive-based rate treatments it proposes by showing how the proposed incentive satisfies section 219.

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.

An applicant would not be required to demonstrate that, but for the incentive, the project would not be completed. Section 219 does not require such a condition.

83. With respect to procedures applicable to joining Transmission Organizations in § 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

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.

E.g.

, National Grid, FirstEnergy, EEI, KCPL, Xcel, Kentucky Commission, Nevada Companies, Progress, and Southern Companies.

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

project uneconomic in comparison to its alternatives. The California Commission states that the Commission's reliance on incentives granted to Trans-Elect with respect to financing the critical Path 15 upgrade in California several years ago is misleading since the special consideration accorded to Trans-Elect was a direct consequence of the unique, emergency energy crisis facing California and the Western United States in 2001.

88. Some commenters

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.

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.

Public Utilities Commission of the State of California

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

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

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.

E.g.

, APPA, the Kentucky Commission, New Mexico AG, NY Association, New York Commission, TDU Systems and TAPS.

99. A number of commenters,

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.

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

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.

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;

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.

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.

American

Transmission stated that these incentives would help maintain adequate cash flow during the construction process and that without these incentives it could face a downgrade of its fixed income rating over the next several years due to inadequate cash flow, thereby increasing its capital costs by $176 million over a twenty-year horizon.

See American Transmission, supra

note 2.

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,

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.

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.

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.

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,

the Commission did just that

when it decided to allow any public utility engaged in the sale of electric power for resale to file to include in rate base up to 50 percent of CWIP, subject to limitations. Thus, the Commission already allows inclusion of some CWIP in rate base. The Commission also departed from existing principles in the

American Transmission

and

Southern California Edison

cases.

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.

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).

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).

See

18 CFR 35.25(c)(1).

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.”

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.

Jersey Central Power & Light Co.

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.

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.

Further, we clarify § 35.35(d)(1)(ii) to state that other provisions of § 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.

However, this waiver does not relieve transmission owners from supplying the necessary information required in § 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.

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.

Likewise, we will allow public utilities to propose a method to limit their filing requirement related to CWIP to an annual filing. These annual filings may be limited to CWIP and will not subject

public utilities to a comprehensive rate review.

Maine Yankee Atomic Power Co.

, 66 FERC ¶ 61,375, at 62,252-53 & n. 10 (1994) (

Maine Yankee

Id.

, at 62,252.

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.

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.

Further, we will entertain proposals by public utilities to expense other types of costs for consideration on a case-by-case basis.

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.

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.

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.

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.

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).