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Proposed Rule

Promoting Transmission Investment Through Pricing Reform

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Start Preamble Start Printed Page 71409 Issued November 18, 2005.

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Notice of Proposed Rulemaking.

SUMMARY:

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 is proposing to amend 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.

DATES:

Comments are due on or before January 11, 2006.

ADDRESSES:

Comments may be filed electronically via the eFiling link on the Commission's Web site at http://www.ferc.gov. Commenters unable to file comments electronically must send an original and 14 copies of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street, NE., Washington, DC, 20426. Refer to the Comment Procedures section of the preamble for additional information on how to file comments.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Jeffrey Hitchings (Technical Information), Office of Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. 202-502-6042.

Sebastian Tiger (Technical Information), Office of Market Oversight and Investigations, 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.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

Issued November 17, 2005.

I. Introduction

1. On August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005 or the Act)[1] became law. Section 1241 of the Act (Transmission Infrastructure Investment) adds a new section 219 to the Federal Power Act (FPA) which mandates that not later than one year after enactment of section 219, the Commission 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. FPA section 219 was implemented against the backdrop of declining investment in transmission infrastructure and increasing electric load. Transmission investment declined in real dollar terms for 23 years, from 1975 to 1998, before increasing again, although investment for the most recent year available, 2003, is still below 1975 levels.[2] Over the same time period, electric load more than doubled, resulting in a significant decrease in transmission capacity relative to load in every North American Electric Reliability Council region.[3] Edison Electric Institute (EEI) estimates that capital spending must increase by 25 percent, from $4 billion annually to $5 billion annually, to assure system reliability and to accommodate wholesale electric markets, and that the 2.5 percent growth rate in transmission mileage since 1999 is insufficient to meet the expected 50 percent growth in consumer demand for electricity over the next two decades.[4] The Secretary of Energy's Advisory Board at the Department of Energy determined that investment in the transmission grid will only occur when regulatory policy: (a) Provides reasonably certain cost recovery; (b) provides regulatory certainty, in terms of who can operate the system and under what rules; and (c) provides a return that makes investment in transmission a reasonable option, considering other available investment options.[5]

2. The purpose of the proposed rulemaking is to promote greater capital investment in new transmission capacity. As the foregoing analysis indicates, the need for capital investment in energy infrastructure is a national problem that requires a national solution. Inadequate transmission infrastructure results in transmission congestion that impedes competitive wholesale markets and impairs the reliability of the electric grid. To address the need for transmission capacity, the proposed rulemaking provides price reforms applicable to the entire electric grid, in both organized and in other markets and to both vertically-integrated utilities and transcos.[6] We note that the Commission has been active in responding to the need for new transmission capacity for several years prior to the enactment of EPAct 2005, as evidenced by its issuance of a proposed policy statement to promote the efficient operation and expansion of the transmission grid [7] and Start Printed Page 71410a policy statement on transco independence.[8]

3. To address the need for new transmission infrastructure and to encourage necessary investment, the new section 219 specifically charges the Commission with the responsibility to establish, by rule, incentive-based (including performance-based) rate treatments for the transmission of electric energy in interstate commerce that:

a. 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;

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

c. 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

d. Allow the recovery of all prudently incurred costs necessary to comply with mandatory reliability standards established 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).

4. Section 219 also requires the Commission to issue a rule to provide for incentives to each transmitting utility or electric utility that joins a Transmission Organization [9] 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 provides that all rates approved under these rules are subject to the requirements of sections 205 and 206 of the FPA,[10] which provides that all rates, charges, terms and conditions be just and reasonable and not unduly discriminatory or preferential.

5. As discussed in detail below, consistent with the above provisions of FPA section 219, in this proposed rulemaking the Commission seeks to provide incentives and regulatory certainty sufficient to support expanded and improved transmission infrastructure (including advanced technologies) while at the same time ensuring that transmission rates remain just, reasonable, and not unduly discriminatory or preferential. We recognize that there may be other incentives or regulatory steps that could be taken (for example, ensuring that incentive rates, once approved, cannot be reopened for a period of time absent compelling circumstances) to provide greater incentive for needed investment. We seek comments not only on the proposals herein but also on other incentives or regulatory steps that would help fulfill the purposes of FPA section 219.

II. Summary of Proposed Regulations

6. Pursuant to new section 219 of the FPA, the proposed amendments to the existing regulations are intended to promote reliable and economically efficient transmission and generation of electricity by providing incentives for increased capital investment by providing a rate of return that attracts new investment in transmission facilities, and by providing incentives to utilities that join Transmission Organizations. The Commission proposes to amend part 35 of Chapter I, Title18, of the Code of Federal Regulations. First, section 35.34(e) (innovative transmission rate treatments for regional transmission organizations) in subpart F of the Commission's regulations [11] will be removed in its entirety. Second, a new section 35.35 under subpart G, titled Transmission Infrastructure Investment Provisions, will be added and will supersede section 35.34(e).

7. As proposed, new section 35.35 under subpart G would establish the regulation's purpose, definitions, general rules, and incentive-based rate treatments for transmission infrastructure investment.

8. The proposed new paragraph (a) would outline the purpose of the regulation, stating that section 35.35 establishes rules for incentive-based (including performance-based) rate treatments for transmission of electric energy in interstate commerce by public utilities for the purpose of benefiting consumers by ensuring reliability, and reducing the cost of delivered power by reducing transmission congestion.

9. The proposed new paragraph (b) would define the terms, “transco” and “transmission organization,” as used in the regulation:

For purposes of this rulemaking, “transco” means a stand-alone transmission company that has been approved by the Commission. As used herein, “stand-alone transmission company” refers to a company engaged solely in selling transmission at wholesale or on an unbundled retail basis. For purposes of the proposed rule, transcos may be independent or they may have some passive ownership interests by affiliated traditional vertically-integrated public utilities (traditional public utilities).[12] “Transmission Organization,” as defined in new section 3(29) of the FPA, means a regional transmission organization (RTO), independent system operator (ISO), independent transmission provider, or other transmission organization finally approved by the Commission for the operation of transmission facilities.

10. The proposed new paragraph (c) would establish the general rule that all rates approved under the rules of this section 35.35, including any revisions to the rules, are subject to the requirements of sections 205 and 206 of the FPA that all rates, charges, terms and conditions be just and reasonable and not unduly discriminatory or preferential. The proposed new paragraph (d) would describe the incentive-based rate treatments for transmission infrastructure investments that the Commission would authorize. For all jurisdictional public utilities, including transcos, the Commission encourages incentive-based rate proposals, including proposals to: (1) Provide a rate of return on equity (ROE), within the zone of reasonableness, that is sufficient to attract new investment in transmission facilities; (2) recover 100 percent of prudently incurred transmission-related Construction Work in Progress (CWIP) in rate base; (3) recover prudently incurred pre-commercial operations costs by expensing these costs instead of capitalizing them; (4) adopt a hypothetical capital structure; (5) Start Printed Page 71411accelerate the recovery of depreciation expense; (6) recover all prudently-incurred development costs in cases where construction of facilities may subsequently be abandoned as a result of factors beyond the public utility's control; (7) provide deferred cost recovery; and (8) provide any other incentives approved by the Commission that are determined to be just and reasonable and not unduly discriminatory or preferential.

11. For transcos only, the Commission would authorize the following additional incentives, subject to the requirements of sections 205 and 206 of the FPA that all rates, charges, terms and conditions be just and reasonable and not unduly discriminatory or preferential: (1) A higher ROE which is both sufficient to encourage Transco formation as well as to attract new investment in transmission facilities; and (2) an adjustment to the book value of transmission assets being sold to a Transco to remove the disincentive associated with the impact of accelerated depreciation on Federal capital gains tax liabilities.

12. The proposed new paragraph (e) would describe the incentive-based rate treatment for public utilities that join a Transmission Organization. The Commission will consider authorizing an ROE for a public utility that joins a Transmission Organization that is higher than the return on equity that the Commission might otherwise allow if the public utility did not join a Transmission Organization (but still within the zone of reasonableness). The Commission will also allow public utilities that join a Transmission Organization to recover prudently incurred costs associated with joining the Transmission Organization, either through transmission rates charged by public utilities or through transmission rates charged by the Transmission Organization that provides services to the public utilities.

13. The proposed new paragraph (f) would state that the Commission will approve prudently-incurred costs necessary to comply with the mandatory reliability standards pursuant to section 215 of the FPA.

14. The proposed new paragraph (g) would state that Commission will approve prudently-incurred costs related to transmission infrastructure development pursuant to section 216 of the FPA.

15. The proposed new paragraph (h) would require that jurisdictional public utilities file an annual report with the Commission specifying current and projected transmission investment activity.

16. The Commission does not propose to require applicants for incentive ratemaking treatment under section 35.35 to support their applications with cost-benefit analyses. 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.

III. Proposed Incentives and Issues for Comment

17. Public comments on this notice of proposed rulemaking (NOPR) are due on January 11, 2006. The Commission will carefully weigh and consider all public comments received.

18. The following sections detailing the proposed incentives are organized as follows:

(1) Provisions applicable to all public utilities;

(2) Provisions applicable to transcos; and

(3) Provisions applicable to public utilities that join Transmission Organizations.

These explanations are intended to clarify certain aspects of the proposed regulations in this NOPR in terms of their role in fulfilling the goals of EPAct 2005 and thereby allow for more informed comments. Public utilities would be required to file for approval of any incentives under section 205 of the FPA and include an explanation of the proposed accounting for these incentives.

A. Incentives Available to All Jurisdictional Public Utilities

19. As mentioned earlier, EEI reports that transmission capital spending must increase an estimated 25 percent annually to assure system reliability and accommodate wholesale markets. Undertaking significant new transmission investment can present cash flow, revenue recovery and financing issues, regardless of corporate structure. This section proposes incentives applicable to all public utilities, consistent with section 219 of the FPA, that would foster transmission investment and thereby help to ensure reliability and reduce transmission congestion.

1. Providing an ROE That Attracts New Investment in Transmission Facilities

20. Public utilities investing in transmission capacity will not invest unless they can earn a return they consider to be sufficiently attractive. The Commission's historical approach to developing an allowed rate of return on equity begins with developing a proxy group of similar risk companies. Next, a discounted cash flow (DCF) analysis is performed on the applicant, if possible, and on the companies in the proxy group, and a zone of reasonableness is typically developed based on the proxy group. A DCF return within the zone of reasonableness is then typically specified for the applicant based on a comparison of risk factors between the applicant and the proxy group. While the Commission has typically utilized a DCF analysis, we seek comment on whether the Commission should consider alternatives to the DCF analysis as a way to incent investment in new transmission capacity.

21. As we recognized in Order No. 2000, the risk profile of the transmission business is changing and the historical data typically used to evaluate returns on equity may not be reliable since it reflects a different industry structure from the one that currently exists. A sufficient return that reflects the current industry environment is fundamental to a public utility's decision to invest in new capacity. Therefore, the Commission will continue to consider and approve ROE levels that attract investment for new transmission projects, thereby fulfilling a requirement of section 219.[13] For example, the Commission approved an ROE adder for Pacific Gas and Electric Company, and a 13.5 percent ROE for the recently completed Path 15 project in California.[14] Similarly, Sierra Pacific Power Company received a ROE of 12.5 to 13.5 percent for certain new facilities it proposed that were designed to relieve congestion, increase the transfer capability of electricity to other markets, enhance regional reliability and connect new merchant generation supply throughout the region.[15] We seek comment on whether ROE adders are an appropriate mechanism for requesting and receiving approval for an acceptable ROE.

22. Specifically, the Commission will 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 Start Printed Page 71412reliability and reducing the cost of delivered power by reducing transmission congestion. 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 if 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. We also seek comment on whether the final rule should establish a definition of “independent regional planning process” or if the Commission should consider them on a case-by-case basis.

2. Prudently Incurred Construction Work in Progress and Prudently Incurred Pre-Commercial Operations Costs

23. 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. For example, during the initial phases of a transmission construction project, a utility may have significant expenses associated with planning and siting that typically are not 100 percent recovered in rate base until commercial operation. The Commission believes that there are at least two ways it can further the goals of section 219 by relieving the pressures on utility cash flows associated with transmission investment programs: (1) Including 100 percent of CWIP in rate base; and (2) expensing rather than capitalizing pre-commercial operations costs associated with new transmission investment.

24. The inclusion of CWIP in rate base rather than the accrual of allowance for funds used during construction (AFUDC) on new construction expenditures is one way to increase cash flow. 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.[16] The remaining construction costs (including an 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.

25. The second way to improve utility cash flows, as mentioned above, is to allow utilities to expense pre-commercial operations costs related to new transmission investment rather than capitalize these costs. Expensing the costs provides immediate cash flow that the utility can then use as and where needed, whereas capitalizing the costs would produce cash flow over the life of the asset.[17]

26. 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.[18] 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.

27. The Commission believes that allowing public utilities 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. We propose to evaluate the applicability of these incentives to transmission investment applications on a case-by-case basis.

28. In addition to inviting comment on this provision, we specifically request 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.

3. Hypothetical Capital Structure

29. The Commission has largely relied on the actual capitalization of a utility in setting its rate of return, but we recognize that an overly rigid approach to evaluating a proposed capital structure could be a disincentive to investment in new transmission projects. Each project may have unique financial and cash flow requirements, and a rigid approach to acceptable capital structures could threaten the viability of some projects. Accordingly, we propose that applicants be permitted to propose an overall rate of return based on a hypothetical capital structure, and have the flexibility to refinance or employ different capitalizations as may be needed to maintain the viability of new capacity additions. We expect that applicants will develop their proposals based on the specific requirements and circumstances of their projects, and that the Commission will evaluate proposals for this incentive on a case-by-case basis. In their applications for incentive treatment, public utilities should provide support for why the hypothetical capital structure incentive is needed to promote investment consistent with the goals of section 219. The applicant must also provide its transmission investment plan and explain the specific projects to which the proposed return will apply. We seek comment on this proposal.

4. Accelerated Depreciation

30. Accelerated depreciation is another way to increase cash flow to utilities, thereby removing a potential disincentive to investing. The Commission has determined in some circumstances that allowing accelerated depreciation is warranted as an incentive to encourage investment in transmission infrastructure because it provides improved cash-flow and better positions public utilities for longer-term transmission investments.[19] While the Commission has allowed accelerated depreciation for emergency conditions or special projects,[20] we believe that permitting accelerated depreciation Start Printed Page 71413more broadly may further the goals of section 219 by providing incentives to undertake transmission projects that have the potential to reduce the cost of delivered power and ensure reliability. We therefore propose to allow transmission facilities to be depreciated over a period of 15 years,[21] in place of the typical Commission practice to allow depreciation over the useful life of the facilities, and seek comment on whether 15 years is an appropriate time period for cost recovery or whether the Commission should establish a presumption of a shorter or longer depreciable life for new transmission facilities.[22] We also seek comment on whether accelerated depreciation has any longer-term negative impacts that would undermine the goals of the Act.

5. Recovery of Costs of Abandoned Facilities

31. Public utilities, in considering investments that fulfill the requirements of FPA section 219, may encounter investment opportunities with significant risk associated with factors beyond their control, such as generation developers' decisions to develop or terminate the development of potential resources or state or local siting decision problems. In these circumstances, it may be appropriate to consider ways to reduce the risk associated with potential upgrades or other improvements to the transmission system. By providing for recovery of the costs of facilities that may be later cancelled or abandoned due to factors beyond the control of the public utility, the Commission could reduce the uncertainty associated with higher risk projects, thereby facilitating investment in these projects.

32. Until recently, the Commission's abandoned plant policy was based on a 50/50 sharing.[23] The intent of this policy was to equitably balance the interests of ratepayers and investors. The Commission noted that the competing standards of “used and useful to the ratepayer” and “recovery of prudent investment” were both relevant and determined that 50 percent of the prudently incurred costs of a cancelled generating plant should be amortized as an expense over a period reflecting the life of the plant if it had been completed and that the remaining 50 percent of the prudently incurred costs of the cancelled plant should be written off as a loss.[24] The Commission in Public Service Company of New Mexico,[25] extended its abandoned plant policy to include transmission projects, finding that the policy was not limited to generation facilities only, or to facilities that had no customer support or involvement or to cancellations that were the result of economics.

33. The policy was further expanded in a recent decision by the Commission to allow Southern California Edison Company (SoCal Edison) to recover all prudently incurred costs related to certain proposed transmission facilities if those facilities were later cancelled or abandoned.[26] The Commission noted that the company's management did not control the decision to develop or cancel the wind farm generation project and that the company's shareholders did not share in the earnings associated with the generation project. The Commission further determined that the company might be at a higher risk in developing the project because of factors beyond its control, such as a developer's decision to develop or terminate development of the project. It also noted that SoCal Edison was not a wind farm developer and therefore would not directly benefit from the facilities. Thus, the Commission concluded that SoCal Edison should not shoulder the risk of the project.[27]

34. We believe that extension of the recent precedent on abandoned plant cost recovery is warranted in light of the need to attract new transmission investment. We propose to permit recovery of 100 percent of the prudently incurred costs of transmission facilities that are cancelled or abandoned due to factors beyond the control of the public utility because it will reduce regulatory uncertainty associated with investments in new transmission capacity and therefore meet the objectives of FPA section 219. We seek comment on this proposal.

6. Deferred Cost Recovery

35. Public utilities with a retail rate moratorium may have less incentive to build transmission facilities that could reduce congestion or ensure reliability because of concerns about cost recovery for those facilities. Accordingly, the Commission proposes to permit such utilities to use a deferred cost recovery mechanism which allows them to commence recovery of new facility costs in FERC-jurisdictional rates at the end of a retail rate moratorium. By providing a mechanism to facilitate cost recovery by public utilities that build transmission facilities during a retail rate moratorium, we will meet the goals of FPA section 219 by providing certainty to investors that costs can be recovered as quickly as possible.[28] We seek comment on whether there are other mechanisms that the Commission could institute to provide regulatory certainty of the recovery of the costs of transmission facilities both through retail as well as wholesale rates.

B. Incentives for Transco Formation and Transco Investment

36. While the incentives we are proposing in this rule should facilitate transmission expansion for all jurisdictional entities in furtherance of the goals of section 219, we recognize that for any transmission rate incentive that is approved by the Commission, utilities whose rates are 100 percent FERC jurisdictional may derive more benefit. Consequently, incentives may be more effective in fostering new transmission investment for transcos than for traditional public utilities that are dependent upon retail regulators for some portion of their transmission rate recovery.

37. In this NOPR, the Commission proposes to define a transco as a stand-alone transmission company, approved by the Commission, which sells transmission service at wholesale and/or on an unbundled retail basis, regardless of whether it is affiliated with another public utility. We invite comments on this proposed definition of transcos.

38. We believe that transcos are an important part of the Commission's mandate to support transmission capacity investments that reduce the cost of delivered power by reducing transmission congestion and that ensure reliability. This is because they have demonstrated the capability to invest, on a timely basis, significant amounts of capital in transmission projects and in efforts to reduce congestion. For example, Michigan Electric Transmission Company (METC) is doubling the net book value of its Start Printed Page 71414transmission system over seven years.[29] Similarly, since launching its capital program in 2001, American Transmission has more than doubled the net book value of its system, much of which is in a highly congested area in the Midwest Independent Transmission System Operator (Midwest ISO),[30] and plans to invest $3.4 billion over the next 10 years.[31] In addition, International Transmission Company (International Transmission) made transmission investments of $81 million in 2004 and plans to invest $100 million in 2005.[32]

1. ROE-Based Incentive for Transcos

39. The positive record of transco investment in transmission facilities is, we believe, related to the stand-alone nature of these entities. For instance, transcos may be better situated to meet the transmission infrastructure goals of the FPA section 219 because they eliminate the competition for capital between the generation and transmission functions within corporations. In addition, transcos, unlike some traditional public utilities, do not face a potential decrease in value to their generation assets as a result of additional transmission. Further, by their structure, transcos have incentives to better manage transmission assets, have incentives to develop innovative services, and may have better access to capital markets given a more focused business model.[33] Also, because transcos' sole focus is on the business of transmission, they may be in a better position to respond to market signals that indicate when and where transmission investment is needed, and, therefore, are more likely to yield additional capital investment in transmission. Unlike investments by traditional public utilities subject to company-wide state-level rate case risks that can undermine incentive ratemaking at the Federal level,[34] ratemaking for transcos is entirely subject to Federal jurisdiction. Thus, unlike many traditional public utilities, transcos avoid potential uncertainty associated with the need for additional rate recovery approval by state regulatory agencies.

40. Given the positive contribution to transmission investment made by transcos in the relatively short period since their creation, we believe the formation of additional transcos will promote needed investment in transmission facilities and we therefore want to encourage their formation.[35] As part of this encouragement of transco formation, we will permit properly structured transcos to receive an ROE that both encourages transco formation and is sufficient to attract investment. For example, the Commission approved equity returns for METC and International Transmission that reflect the significant benefits that their status as transcos provide, and are higher than those approved for integrated entities.[36] Continuing to allow a higher ROE (that falls within a zone of reasonableness) in recognition of the benefits transcos provide, we believe, is an appropriate way to ensure that the objectives of new FPA section 219 are achieved. Therefore, the Commission will consider the positive impact transcos have on transmission investment and in turn on the reliable and economically efficient transmission and generation of electricity when it evaluates ROEs proposed by properly structured transcos.

41. We recognize that transcos can be structured with varying degrees of independence, ranging from entities where some measure of control and/or ownership continues to be exercised by market participants [37] to total structural independence, such as International Transmission and METC. The Commission's Transco Independence Policy Statement recognized the range of independence that would be acceptable for Commission approval, including passive ownership subject to the evaluation of factors that affect the independent operation, planning and construction of transmission systems.

42. Furthermore, the Commission believes that the expansion and investment objectives of section 219 are best met by a definition of transcos that does not restrict the formation of transcos to only certain organized markets. Therefore, the Commission proposes to clarify and broaden the definition of transcos to be stand-alone transmission companies approved by the Commission, without a condition of membership in a RTO or ISO. We request comment on how to factor the level of independence into any request for ROE-based incentives for transcos. We seek comment on whether the Commission should specify additional incentive levels, that remain within the zone of reasonableness, to correspond to certain levels of independence and if so, what those amounts should be. We also seek comments concerning whether membership in an RTO or ISO should be considered in setting incentive-based ROEs approved by the Commission for a transco. We also seek comment on whether the Commission should reconsider how it establishes a zone of reasonableness associated with stand-alone transmission companies.

2. Recovery of Accumulated Deferred Income Taxes (ADIT)

43. In order to encourage transco formation, we must also remove disincentives that might prevent the sale or purchase of transmission assets. For example, transmission owners are unlikely to sell transmission assets at book value if they are not held harmless from capital gains taxes on such sales by including an adjustment for taxes associated with those sales. At the same time, buyers of transmission assets may be unwilling to pay such an adjustment without some assurance that they will be able to recover the adjustment in their rate base.[38] The Commission Start Printed Page 71415addressed those concerns in two orders in which it allowed two Transcos (International Transmission and METC) to include in their rates an adjustment to recover ADIT.[39] To remove any disincentive, the Commission will continue to consider proposals to include adjustments for ADIT in rates when a transco is purchasing transmission facilities. In addition, we clarify that a transco that requests an incentive ROE would not be precluded from also requesting the ADIT adjustment

3. Other Potential Incentives for Transcos

44. We seek comments on whether there are other potential rate treatments that would provide incentives to form transcos and promote capital investment or reduce disincentives to the divestiture of transmission facilities. Do any of the incentives we are proposing need to be modified or adapted to recognize the inherent regulatory differences between transcos and traditional public utilities?

C. ROE Incentive for Joining a Transmission Organization

45. FPA section 219 requires that the Commission issue a rule to provide incentives to transmitting or electric utilities that join 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 rates charged by the Transmission Organization. For certain RTOs, such as the Midwest ISO and the Pennsylvania-New Jersey-Maryland Interconnection (PJM), the Commission has considered incentives for public utilities that join an RTO by allowing a public utility that joins an RTO to receive an ROE within the zone of reasonableness that is higher than it would have received had it not joined. We will continue to consider requests for ROE-based incentives for utilities that join an RTO, in recognition of the benefits such organizations bring to customers, as outlined in detail in Order No. 2000.[40] In addition, we will consider similar requests by utilities that join an ISO for an incentive ROE that, while still in the zone of reasonableness, is higher than the ROE the Commission might otherwise allow if the utility did not join. We will require a public utility to make a request for the incentive by making a filing with the Commission under section 205 of the FPA.

46. We also seek comment on whether the Commission should consider incentive-based ROE requests for public utilities that are not in an RTO but that join a Commission-approved regional planning organization.

D. Approval of All Prudently Incurred Costs Associated With Reliability Standards and Transmission Infrastructure Development

47. Under new FPA section 215 (Electric Reliability), an Electric Reliability Organization may propose, and the Commission may approve by rule or order, reliability standards.[41] New FPA section 219(b)(4)(A) requires that the Commission allow recovery of all prudently incurred costs necessary to comply with these mandatory reliability standards. Proposed new section 35.35(f) allows for such recovery.

48. New FPA section 216 (siting of interstate electric transmission facilities) gives the Commission certain backstop siting authority for transmission facilities when the Secretary of Energy designates a geographic area experiencing electric transmission capacity constraints or congestion that adversely affects consumers as a National Interest Electric Transmission Corridor. New FPA section 219(b)(4)(B) requires that the Commission allow recovery of all prudently incurred costs related to infrastructure development pursuant to new section 216. Proposed new section 35.35(g) allows for recovery of such prudently incurred costs.

E. Commission Reporting Requirement

49. To provide a basis for determining the effectiveness of the proposed rules and to provide the Commission with an accurate assessment of the state of the industry with respect to transmission investment, proposed section 35.35(h) would require that jurisdictional public utilities provide information annually on their current and projected transmission investment activity. This information would be reported to the Commission on a proposed new form which would consist of a basic spreadsheet. For purposes of this NOPR, the proposed form is designated as “Form X.” It is an appendix to this NOPR.

F. Proposal To Remove 18 CFR 35.34(e) Concerning Innovative Transmission Rate Treatments for RTOs

50. Section 35.34(e) of the Commission's regulations provides that the Commission will consider authorizing certain innovative transmission rate treatments for an approved RTO, including: A transmission rate moratorium; innovative treatment of rates of return; non-traditional depreciation schedules for new transmission investment; transmission rates based on levelized recovery of capital costs; transmission rates that combine elements of incremental cost pricing for new transmission facilities with an embedded-cost access fee for existing transmission facilities; and performance-based transmission rates.

51. Unless otherwise ordered by the Commission, the authorization for RTOs to include innovative rate treatments in their rates expired after January 1, 2005, with respect to transmission rate moratoriums and rates of return that do not vary with capital structure.[42]

52. In view of section 219's mandate to provide incentives to the entities identified therein and in order to avoid confusion that could arise from potential conflicts between innovative rate treatments available under section 35.34(e) and the proposed incentives discussed in this proposed rule, the Commission proposes to remove section 35.34(e) from the regulations.

G. Other Options

53. To fully meet the requirements of section 219, the Commission must consider all incentives that will encourage capital spending that reduces congestion and ensures reliability, including incentives that have not been fully evaluated by the Commission, or may require additional modifications to past Commission policy. Accordingly, the Commission is proposing that eligible incentives not be limited to the list of proposed incentives, but also include any potential incentives proposed by public utilities and ultimately approved by the Commission that are determined to be just and reasonable, and not unduly discriminatory or preferential. To facilitate comments on the full range of eligible incentives, we identify several potential incentives and their applicability to FPA section 219. We request comments on these potential Start Printed Page 71416incentives and invite commenters to propose any other potential incentives.

1. Single Issue Ratemaking

54. We recognize that transmission pricing issues are some of the most difficult issues facing the industry and that the Commission's policy of not allowing selective adjustments to a cost-of-service may serve as a disincentive to transmission investment.[43] Certain applicants for incentive rate-making treatment will be making investments potentially affecting currently effective transmission rates on file at the Commission. Potential applicants may consider the time requirements and the uncertainties associated with rate proceedings that encompass their entire transmission systems to be disincentives to making incentive filings, as specified in this NOPR. To ensure that the approval process for incentive treatment is as streamlined as possible, thereby ensuring timely infrastructure investments, the Commission is willing to consider incentive filings that propose rates applicable only to the new transmission project.[44] Such an incentive would be applicable to both Transcos and traditional public utilities. We invite comments on this option.

2. Acquisition Premiums for Transco Creation

55. The Commission has historically allowed acquisition adjustments (the premium paid above net book value) in rates only upon a specific showing of ratepayer benefit.[45] However, given the positive contributions of transcos on transmission investment noted above, it may be appropriate to adopt a new policy regarding the recovery in rates of an acquisition premium for purchases of transmission facilities by a transco.[46] We request comments on whether the Commission should make a generic determination that general benefits would accrue to ratepayers as a result of transco formation. We also seek comment on whether any change in the acquisition premium/ratepayer benefits review at the Federal level would risk increased resistance to such acquisitions at the state level. And, we seek comment on whether there are other mechanisms that the Commission could institute to provide regulatory certainty of the recovery of the acquisition premium both through retail as well as wholesale rates. Also, we seek comment on what measure the Commission might use in evaluating the appropriateness of such premiums as measured against, for example, the size of the premium, the location of the assets, the level of independence of the transco, and other relevant factors.

H. Other Issues for Comment

56. In addition to seeking comments on the proposed rules and options contained herein, the Commission seeks comments on the following issues:

1. Performance-Based Ratemaking

57. Because it is difficult to observe directly the level of effort a utility, transmission company, ISO or RTO expends on cutting costs and improving efficiency, performance-based regulation may provide a valuable tool to motivate transmission entities to maintain and operate their systems reliably and efficiently. In addition to incentive regulation proposed in this NOPR to encourage expansion of the electric transmission system generally, performance-based regulation would establish rewards for cost saving measures or specific performance (apart from transmission expansions). Common performance-based models include: (1) Price-cap regulation which places ceilings on the average price that a regulated company can charge, allowing the company rate flexibility;[47] (2) targeted incentives, which give a regulated company incentives to improve specific components of its operation; and (3) benchmark incentives which establish rewards based on the performance of a reference group performing similar activities. The Commission seeks comment on specific methods to incent efficiency in the maintenance and operation of existing transmission facilities, including rate moratoria as well as sophisticated methods of performance based ratemaking based on specific performance metrics.

58. We seek comment on ways performance-based regulation might apply to for-profit transcos and traditional public utilities, and not-for-profit public utility ISOs and RTOs. In the case of for-profit entities, we seek comment on specific transmission performance metrics and other relevant quality-of-service measures that should be subject to a performance standard. The Commission seeks comment on whether there should be mechanisms for sharing gains with ratepayers and, if so, what those mechanisms should be. In the case of not-for-profit public utility ISOs and RTOs, we seek comment on whether and how performance-based regulation developed for for-profit entities might be applied to not-for-profit entities. For example, we are interested in comments on whether and how executive performance measures might be relevant, and whether and how performance might be benchmarked to that of for-profit entities or other not-for-profit entities. Further, in the discussion of advanced technologies, infra, we seek comment on whether performance-based benchmarks for transmission costs would provide incentives for the deployment of advanced technologies.

2. The Role of Public Power

59. Although the transmission infrastructure provisions of section 219 apply only to public utilities, it is important that the Commission encourage needed transmission expansion from all sectors of the industry, including public power.[48] Public power has demonstrated its ability to provide capital and build transmission capacity in some of the most critical transmission projects. For example, public power participates as an equity owner in the American Transmission transco, providing capital to fund transmission construction in a highly congested market. In addition to equity ownership, public power entities have shown that they can participate in, and benefit from, grid expansion opportunities as counterparties to long-term contracts such as the long-term commitment to purchase capacity from transmission projects that are needed to allow such projects to go forward. The Long Island Power Authority's (LIPA) Start Printed Page 71417success in the Cross Sound Cable project's open season resulted in LIPA securing long-term rights to schedule power between nodes in two RTOs. LIPA also obtained rights for 20 years to all 660 megawatts on the Neptune merchant transmission project, a 67-mile-long cable capable of transporting electricity to Long Island, and in conjunction with the Cross Sound Cable between New Haven, Connecticut, and Shoreham, will, according to LIPA, open up an energy corridor from the Mid-Atlantic states through Long Island into New England and Canada.[49]

60. Another option is for public power to participate in specific transmission projects along with developers with other business models. For example, Western Area Power Administration helped the Path 15 project to move forward by serving as project manager, acquiring needed land rights, and owning the transmission line and the land. When public power entities voluntarily participate in grid investments with entities that are under the Commission's rate jurisdiction, those non-jurisdictional public power entities can benefit from the rate policies described in this NOPR that provide for improved certainty and possibly enhanced revenues.

61. New forms of public power entities may also be formed to address infrastructure challenges. For example, the western states spearheading the development of the Frontier transmission line project (Frontier Line) are identifying potential business models to complete the project. Participants in the planning of the Frontier Line are looking to the Commission to, among other things, provide the necessary certainty to attract investment to this type of project,[50] and incentives in this proposed rule may encourage interest in this type of regional partnership, which involve both public and private entities across several states.

62. A consortium approach to building new transmission may also provide an avenue for public power to participate in new transmission projects. Under a consortium approach, as described by PJM,[51] the RTO planning process becomes the platform to facilitate development of transmission business solutions—solutions in which all parties can participate. For example, should public power wish to lend its access to lower cost financing to help fund such a project, the planning process would become the forum for such discussions.

63. Given the importance of public power participation and the requirements of section 219, we request comments on what actions the Commission should take in this rulemaking to encourage public power participation in new transmission projects. For example, would the consortium approach help to promote expansion of the transmission grid? If so, should consortia receive incentives similar to those proposed for Transcos, and what, if any, additional incentives could the Commission provide to encourage such consortia?

3. Advanced Technology

64. We also want to encourage the use of advanced technology in new transmission projects.[52] Advanced transmission technologies are defined in section 1223 of EPAct 2005 to be technologies that increase the capacity, efficiency, or reliability of an existing or new transmission facility, including:

(1) High-temperature lines (including superconducting cables);

(2) Underground cables;

(3) Advanced conductor technology (including advanced composite conductors, high temperature low-sag conductors, and fiber optic temperature sensing conductors);

(4) High-capacity ceramic electric wire, connectors, and insulators;

(5) Optimized transmission line configurations (including multiple phased transmission lines);

(6) Modular equipment;

(7) Wireless power transmission;

(8) Ultra-high voltage lines;

(9) High-voltage DC technology;

(10) Flexible AC transmission systems;

(11) Energy storage devices (including pumped hydro, compressed air, superconducting magnetic energy storage, flywheels, and batteries);

(12) Controllable load;

(13) Distributed generation (including PV, fuel cells, and microturbines);

(14) Enhanced power device monitoring;

(15) Direct system state sensors;

(16) Fiber optic technologies;

(17) Power electronics and related software (including real time monitoring and analytical software);

(18) Mobile transformers and mobile substations; and

(19) Any other technologies the Commission considers appropriate.

65. Generally, we expect that the proposed incentives discussed in this NOPR, including the ROE-based incentives, will stimulate investment in new transmission facilities, which will, in turn, provide opportunities for the deployment of innovative technologies for those new transmission facilities. Consequently, providing the proposed incentives will fulfill the requirement of section 219(b)(3) to encourage deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve the operation of facilities. We ask for comments on whether, in applications for incentive-based treatment, we should require a technology statement. This technology statement could, for example, describe what advanced transmission technologies were considered and, if those technologies were not employed, why not. We also seek comment on any other incentives that the Commission could offer to fulfill the goals of section 219(b)(3) regarding transmission technologies.

66. We seek comment on whether performance-based benchmarks for transmission costs would provide incentives for the deployment of advanced technologies. In this risk-sharing approach, the project sponsor would be allowed to recover costs up to a benchmark level and ratepayers would be protected from costs above the benchmark level. If the new technology is adopted and fails to live up to expectations, how are those costs shared with ratepayers? And, if the new technology is successful, how are the gains shared with ratepayers?

67. In addition to the comments invited above, the Commission welcomes comments on additional provisions that commenters believe would accomplish the transmission infrastructure objectives of the Act.

IV. Information Collection Statement

68. The Office of Management and Budget (OMB) regulations require approval of certain information collection requirements imposed by agency rules.[53] Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to Start Printed Page 71418the filing requirements of this rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number. The NOPR amends the Commission's regulations to implement the statutory provisions of section 1241 of EPAct 2005. The Act directs the Commission to establish incentive-based (including performance-based) rate treatments for the transmission of electric energy in interstate commerce by public utilities in order to benefit consumers by ensuring reliability and reducing the cost of delivered power by relieving transmission congestion. Entities seeking to build new transmission facilities must file under part 35 of the Commission's regulations, an application describing how the entity will bring benefits to the grid. The information provided for under part 35 is identified as FERC-516.

69. The Commission is submitting these reporting requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act.54 Comments are solicited on the Commission's need for this information, whether the information will have practical utility, the accuracy of provided burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected, and any suggested methods for minimizing the respondent's burden, including the use of automated information techniques.

Burden Estimate: The Public Reporting burden for the requirements contained in the NOPR is as follows:

Data collectionNumber of respondentsNumber of responsesHours per responseTotal annual hours
 FERC-516
Transco3012968,880
Traditional Public Utilities200121142,200
Totals230122251,080

Total Annual Hours for Collection: (Reporting + recordkeeping, (if appropriate)= 51,080 hours.

Information Collection Costs: The Commission seeks comments on the costs to comply with these requirements. It has projected the average annualized cost to be the total annual hours of 51,080 times $120 = $6,129,600. (The hourly rate was determined by taking the median annual salary from Bureau of Labor Statistics, Department of Labor Occupational Outlook Handbook. The figures reported by BLS are for 2002 and added to them was an inflation factor of 4.73 percent for the period January 2003 through December 2004.)

Title: FERC-516 “Electric Rate Schedule Filings.”

Action: Proposed Collections.

OMB Control No: 1902-0096.

Respondents: Business or other for profit.

Frequency of Responses: On occasion for applicants and annually for transmission investment report.

Necessity of the Information: This proposed rule, if adopted, would implement the Congressional mandate of the Energy Policy Act of 2005 to establish incentive-based (including performance-based) rate treatments for the transmission of electric energy in interstate commerce. This mandate addresses an identified need to encourage construction of transmission infrastructure and encourage investment. Sufficient supplies of energy and a reliable way to transport those supplies are necessary to assure reliable energy availability and to enable competitive markets. Without sufficient delivery infrastructure, some suppliers will not be able to enter the market, customer choices will be limited, and prices may be needlessly higher or volatile. The implementation of incentive and performance-based rate treatments support the Commission's mandate to support investments in transmission capacity to reduce the cost of delivered power by reducing congestion.

Internal review: The Commission has reviewed the requirements pertaining to public utilities and transmission companies and determined the proposed requirements are necessary to meet the statutory provisions of the Energy Policy Act of 2005.

70. These requirements conform to the Commission's plan for efficient information collection, communication and management within the energy industry. The Commission has assured itself, by means of internal review, that there is specific, objective support for the burden estimates associated with the information requirements.

71. Interested persons may obtain information on the reporting requirements by contacting: Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426 [Attention: Michael Miller, Office of the Executive Director, Phone: (202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov]. Comments on the requirements of the proposed rule may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission].

V. Environmental Analysis

72. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.[55] The Commission has categorically excluded certain actions from these requirements as not having a significant effect on the human environment.[56] The actions proposed here fall within categorical exclusions in the Commission's regulations for promulgation of rules that are clarifying, corrective, or procedural, and for electric rate filings submitted by public utilities, the establishment of just and reasonable rates, and confirmation, approval and disapproval of rate filings submitted by Federal power marketing agencies.[57] Therefore, an environmental assessment is unnecessary and has not been prepared for this NOPR.

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VI. Regulatory Flexibility Act Certification

73. The Regulatory Flexibility Act (RFA) [58] requires that a rulemaking contain either a description and analysis of the effect that the proposed rule will have on small entities or a certification that the rule will not have a significant economic impact on a substantial number of small entities. However, the RFA does not define “significant” or “substantial” instead leaving it up to any agency to determine the impacts of its regulations on small entities. The proposed regulations would not have a significant adverse impact on a substantial number of small entities. The proposed rule applies only to entities that own, control, or operate facilities for transmitting electric energy in interstate commerce and not to electric utilities per se. Small entities that believe this proposed rule will have a significant impact on them may apply to the Commission for waivers.

VII. Comment Procedures

74. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due on or before January 11, 2006. Comments must refer to Docket No. RM06-4-000, and must include the commenter's name, the organization they represent, if applicable, and their address in their comments. Comments may be filed either in electronic or paper format.

75. Comments may be filed electronically via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing formats and commenters may attach additional files with supporting information in certain other file formats. Commenters filing electronically do not need to make a paper filing. Commenters that are not able to file comments electronically must send an original and 14 copies of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street NE., Washington, DC 20426.

76. All comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters.

VIII. Document Availability

77. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.

78. From FERC's Home Page on the Internet, this information is available in the Commission's document management system, eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

79. User assistance is available for eLibrary and the FERC's website during normal business hours. For assistance, please contact the Commission's Online Support at 1-866-208-3676 (toll free) or TTY (202) 502-8659, or e-mail at FERCOnlineSupport@ferc.gov. You may also contact the Public Reference Room at (202) 502-8371 or e-mail at public.referenceroom@ferc.gov.

Start List of Subjects

List of Subjects in 18 CFR Part 35

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By direction of the Commission.

Magalie R. Salas,

Secretary.

End Signature

In consideration of the foregoing, the Commission proposes to amend part 35 of Chapter I, Title 18, Code of Federal Regulations, as follows:

Start Part

PART 35—FILING OF RATE SCHEDULES AND TARIFFS

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

Start Authority

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

End Authority

Subpart F—Procedures and Requirements Regarding Regional Transmission Organizations

[Amended]

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

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

Subpart G—Transmission Infrastructure Investment Provisions

Transmission infrastructure investment.

(a) Purpose. This section establishes rules for incentive-based (including performance-based) rate treatments for transmission of electric energy in interstate commerce by public utilities for the purpose of benefiting consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion.

(b) Definitions.

(1) Transco means a stand-alone transmission company that has been approved by the Commission and that sells transmission services at wholesale and/or on an unbundled retail basis, regardless of whether it is affiliated with another public utility.

(2) Transmission Organization means a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other transmission organization finally approved by the Commission for the operation of transmission facilities.

(c) General rule. All rates approved under the rules of this section, including any revisions to the rules, are subject to the filing requirements of sections 205 and 206 of the Federal Power Act and to the substantive requirements of sections 205 and 206 of the Federal Power Act that all rates, charges, terms and conditions be just and reasonable and not unduly discriminatory or preferential.

(d) Incentive-based rate treatments for transmission infrastructure investment. The Commission will authorize any incentive-based rate treatment, as discussed in this paragraph (d), for transmission infrastructure investment, provided that the proposed incentive-based rate treatment is just and reasonable and not unduly discriminatory or preferential. An applicant's request, to be made in a filing pursuant to section 205 of the Federal Power Act, or in a petition for a declaratory order that precedes a filing pursuant to section 205, must include a detailed explanation of how the proposed rate treatment justifies incentive-based (or performance-based) treatment based on the purposes and requirements of this section. For purposes of this paragraph (d), incentive-based rate treatment means any of the following:

(1) The Commission will authorize the following incentive-based rate treatments for investment by public utilities, including Transcos, in new transmission capacity that reduces the cost of delivered power by reducing Start Printed Page 71420transmission congestion and ensures reliability, as demonstrated in an application to the Commission:

(i) A rate of return on equity sufficient to attract new investment in transmission facilities;

(ii) 100 percent of prudently incurred Construction Work in Progress (CWIP) in rate base;

(iii) Recovery of prudently incurred pre-commercial operations costs;

(iv) Hypothetical capital structure;

(v) Accelerated regulatory book depreciation;

(vi) Recovery of 100 percent of prudently incurred costs of transmission facilities that are cancelled or abandoned due to factors beyond the control of the public utility;

(vii) Deferred cost recovery; and

(viii) Any other incentives approved by the Commission, pursuant to the requirements of this paragraph, that are determined to be just and reasonable and not unduly discriminatory or preferential.

(2) In addition to the incentives in paragraph (d)(1) of this section, the Commission will authorize the following incentive-based rate treatments for Transcos, provided that the proposed incentive-based rate treatment is just and reasonable and not unduly discriminatory or preferential:

(i) A return on equity that both encourages Transco formation and is sufficient to attract investment; and

(ii) An adjustment to the book value of transmission assets being sold to a transco to remove the disincentive associated with the impact of accelerated depreciation on federal capital gains tax liabilities.

(e) Incentives for joining a Transmission Organization. The Commission will authorize an incentive-based rate treatment, as discussed in this paragraph (e), for public utilities that join a Transmission Organization, provided that the proposed incentive-based rate treatment is just and reasonable and not unduly discriminatory or preferential. Applicants for the incentive-based rate treatment must make a filing with the Commission under section 205 of the Federal Power Act. For purposes of this paragraph (e), an incentive-based rate treatment means a return on equity that is higher than the return on equity the Commission might otherwise allow if the public utility did not join a Transmission Organization. The Commission will also permit public utilities that join a Transmission Organization the ability to recover prudently incurred costs associated with joining the Transmission Organization, either through transmission rates charged by public utilities or through transmission rates charged by the Transmission Organization that provides services to the public utilities.

(f) Approval of prudently-incurred costs. The Commission will approve recovery of prudently-incurred costs necessary to comply with the mandatory reliability standards pursuant to section 215 of the Federal Power Act, provided that the proposed rates are just and reasonable and not unduly discriminatory or preferential.

(g) Approval of prudently incurred costs related to transmission infrastructure development. The Commission will approve recovery of prudently-incurred costs related to transmission infrastructure development pursuant to section 216 of the Federal Power Act, provided that the proposed rates are just and reasonable and not unduly discriminatory or preferential.

(h) Reporting transmission investment activity to the Commission. Jurisdictional public utilities are required to report annually to the Commission no later than April 18, 2007 and, in succeeding years, on the date on which Form 1 information is due, the following information on Form X:

(i) In dollar terms, actual transmission investment for the most recent calendar year, and planned investments for the next five years.

(ii) For all current and planned investments over the next five years, a project by project listing that specifies for each project the expected completion date, percentage completion as of the date of filing, and reasons for delays.

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End Part End Supplemental Information

Footnotes

1.  Public Law No. 109-58, 119 Stat. 594 (2005).

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

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3.  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).

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4.  Energy Policy Act of 2005: Hearings before the House Subcommittee on Energy and Commerce, 109th Congress, First Sess. (2005) (Prepared statement of Thomas R. Kuhn, President of EEI).

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5.  Comprehensive National Energy Policy: Hearings before the House Subcommittee on Energy and Commerce, 108th Congress, First Sess. (Prepared statement of Glenn English, Chief Executive Officer of National Rural Electric Cooperatives Association).

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6.  Transcos are stand-alone transmission companies that have been approved by the Commission.

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7.  Proposed Pricing Policy for Efficient Operation and Expansion of Transmission Grid, 102 FERC ¶ 61,032 (2003). That proposed policy statement, which was issued in Docket No. PL03-1-000, has been superseded by this proposed rulemaking. Accordingly, the Commission will take no further action in Docket No. PL03-1-000.

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8.  Policy Statement Regarding Evaluation of Independent Ownership and Operation of Transmission, 111 FERC ¶ 61,473 (2005) (Transco Independence Policy Statement).

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9.  Section 3(29) of the FPA (as added by section 1291(b)(29) of EPAct 2005) defines a Transmission Organization 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.

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10.  16 U.S.C. 824(d) and 824(e) (2000).

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11.  Subpart F of the Commission's regulations consists of § 35.34 (procedures and requirements regarding regional transmission organizations).

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12.  A transco is also a public utility under the FPA unless it is wholly owned and operated by entities that fall within section 201(f) of the FPA (e.g., governmental and certain electric cooperative entities). So, in order to distinguish traditional vertically-integrated public utilities from transcos for purposes of this notice of proposed rulemaking, we refer to traditional vertically-integrated public utilities as “traditional public utilities.”

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13.  FPA section 219(b)(2).

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14.  See Western Area Power Administration, 99 FERC ¶ 61,306 (2002), reh'g denied, 100 FERC ¶ 61,331 (2002), aff'd sub nom. Public Utilities Commission of the State of California v. FERC, 367 F.3d 925 (D.C. Cir. 2004) (Western Area Power Administration). The District of Columbia Circuit held that “using price incentives to increase the supply of energy available to customers is a valid, non-cost consideration in setting rates.”

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15.  Sierra Pacific Resources Operating Companies, 105 FERC ¶ 61,178 (2003), order on reh'g, 106 FERC ¶ 61,096 (2004).

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17.  The Commission recognizes that not all corporate models ascribe to the philosophy of early cash returns; some prefer the stable long-term returns resulting from the higher rate base.

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18.  The Commission conditionally accepted the proposal for filing, set it for hearing, subject to refund. Subsequently, the Commission accepted a settlement that allowed American Transmission to recover transmission-related CWIP and pre-certification costs in rate base. See American Transmission Company, LLC, 105 FERC ¶ 61,388 (2003), order approving settlement, 107 FERC ¶ 61,117 (2004).

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19.  See Removing Obstacles to Increased Electric Generation and Natural Gas Supply in the Western United States, 94 FERC ¶ 61,272, further order on removing obstacles to increased energy supply and reduced demand in the Western United States and dismissing reh'g, 95 FERC ¶ 61,225, order on reh'g, 96 FERC ¶ 61,155, order on reh'g, 97 FERC ¶ 61,024 (2001) (Removing Obstacles). See also Western Area Power Administration, supra note 14.

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21.  Removing Obstacles, 94 FERC at 61,968-69.

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

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23.  See New England Power Co., Opinion No. 295, 42 FERC ¶ 61,016 at 61,068, 61,081-83, order on reh'g, 43 FERC ¶ 61,285 (1988).

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24.  Under this policy, ratepayers are entitled to the income tax deduction associated with that portion of the loss for which they are paying. In addition, they are entitled to a rate base reduction to reflect the accumulated deferred income tax amounts associated with 50 percent of the abandonment loss

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25.  75 FERC ¶ 61,266 at 61,859 (1996).

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26.  Southern California Edison Co., 112 FERC ¶ 61,014 at P 58-61, reh'g denied, 113 FERC ¶ 61,143 at P 9-15 (2005) (SoCal Edison).

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27.  Id. at P 61.

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28.  The Commission has approved for Trans-Elect, Inc. (Trans-Elect) a proposal for a deferred cost recovery provision that allowed Trans-Elect to commence recovery of the cost of new facilities upon the end of the retail rate moratorium. See Trans Elect, Inc., 98 FERC ¶ 61,142, reh'g denied, 98 FERC ¶ 61,368 (2002).

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29.  April 22, 2005 Technical Conference, Tr. 187 (statement of Paul McCoy, Trans-Elect, Inc.).

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30.  April 22, 2005 Technical Conference, Tr. 192 (statement of Dan Langren, American Transmission).

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31.  See American Transmission's 10-Year Transmission System Assessment Summary Report 2005 at p. 12, which is available on ATC's Web site at http://www.atc10yearplan.com.

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32.  April 22, 2005 Technical Conference, Tr. 79 (statement of Joe Welch, International Transmission).

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33.  See, e.g., ITC Holdings Corp., 102 FERC ¶ 61,182 at P 62, reh'g denied, 104 FERC ¶ 61,033 (2003) (ITC Holdings Corp.) (“Moreover, we believe that International Transmission's for-profit, stand-alone transmission business will bring significant benefits through, among other things, improved asset management, development of innovative services, and improved access to capital markets given a more focused business model than that of vertically-integrated utilities.”); TRANSLink Transmission Co., L.L.C., 99 FERC ¶ 61,106 at 61,455 (2002), order on reh'g, 101 FERC ¶ 61,140 (2003) (“We have recognized that the ITC business model can bring significant benefits to the industry. Their for-profit nature with a focus on the transmission business is ideally suited to bring about: (1) Improved asset management including increased investment; (2) improved access to capital markets given a more focused business model than that of vertically-integrated utilities; (3) development of innovative services; and (4) additional independence from market participants.”).

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34.  See April 22, 2005 Technical Conference, Tr. 44 (statement of Jon Larson, Trimaran Capital Partners).

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35.  We also note that, as entities that do not own or control generation assets, transcos further ensure non-discriminatory transmission service.

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36.  Michigan Electric Transmission Co., LLC, 105 FERC ¶ 61,214 (2003); ITC Holdings Corp., supra note 33.

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37.  Section 35.34(b)(2) of the Commission's RTO regulations defines a market participant as:

(i) Any entity that, either directly or through an affiliate, sells or brokers electric energy, or provides ancillary services to the [RTO], unless the Commission finds that the entity does not have economic or commercial interests that would be significantly affected by the [RTO's] actions or decisions; and

(ii) Any other entity that the Commission finds has economic or commercial interests that would be significantly affected by the [RTO's] actions or decisions.

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

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39.  See ITC Holdings Corp., 102 FERC ¶ 61,182 at P 62 (with regard to International Transmission Company); Trans-Elect, Inc., 98 FERC ¶ 61,368 at 62,590 (2002) (with regard to METC).

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40.  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 12088 (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).

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41.  An Electric Reliability Organization is the organization certified by the Commission to establish and enforce reliability standards for the bulk power system, subject to Commission review.

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42.  See 18 CFR 35.34(e)(4) (2005).

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43.  See, e.g., City of Westerville, Ohio v. Columbus Southern Power Co., 111 FERC ¶ 61,307 at P 18 & n.11 (2005).

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44.  See Removing Obstacles, supra note 20, for one type of approach utilizing a limited section 205 filing.

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45.  See, e.g., UtiliCorp United Inc. and Centel Corp., 56 FERC ¶ 61,031 at 61,120 & nn. 26-28, reh'g denied, 56 FERC ¶ 61,427 at 62,528-29 (1991); Minnesota Power & Light Co., 43 FERC ¶ 61,104 at 61,341-42, reh'g denied, 43 FERC ¶ 61,502 (1989), appeal dismissed, No. 88-2234 (8th Cir. Sept. 14, 1989). While the proposed ADIT incentive discussed above would adjust book value and therefore may be considered a premium on net book value, we note that the acquisition premium discussed here is separate and distinct from the proposed ADIT incentive.

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46.  See April 22, 2005 Technical Conference, Docket No. AD05-5-000, Tr. 44-45 (statement of Jon Larsen, Trimaran Capital Partners); Tr. 215 (statement of Christopher Leslie, MacQuarie Securities (USA), Inc.).

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47.  The Commission has approved performance-based rates for oil pipelines based on this model. See Revisions To Oil Pipeline Regulation Pursuant to the Energy Policy Act of 1992, Order No. 561, FERC Stats. & Regs. ¶ 30,985 (1993), 58 FR 58753 (Nov. 4, 1993), order on reh'g, Order No. 561-A, FERC Stats. & Regs. ¶ 31,000 (1994), 59 FR 40243 (Aug. 8, 1994), aff'd, Association of Oil Pipelines v. FERC, 83 F.3d 1424 (D.C. Cir. 1996).

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48.  The term “public power” as used in this NOPR refers to such traditional entities as municipal and cooperatively owned utilities, state power authorities, Federal power marketing administrations and power authorities, and others that do not fall within the Commission's FPA sections 205 and 206 ratemaking jurisdiction as public utilities.

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50.  See April 22, 2005 Technical Conference, Tr. 166 (statement of Joe Desmond, Deputy Secretary of Energy for the State of California).

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51.  See April 22, 2005 Technical Conference, Tr. 75-76, Tr. 123-124 (statement of Audrey Zibelman, PJM Interconnection); Supplemental Comments of PJM Interconnection at p. 4 (submitted May 2, 2005, Docket No. PL03-1-000).

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52.  New FPA section 219(b)(3), added by EPAct 2005, requires that the rule established pursuant to section 219 “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.”

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55.  Order No. 486, Regulations Implementing the National Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preamble 1986-1990 ¶ 30,783 (1987).

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57.  18 CFR 380.4(a)(2)(ii) and 380.4(a)(15).

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58.  5 U.S.C. 601-612 (2000).

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BILLING CODE 6717-01-P

[FR Doc. 05-23404 Filed 11-28-05; 8:45 am]

BILLING CODE 6717-01-C