# Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/agency%3Aferc%3A479dac448d4af171 ## Record - **Collection:** Agency decision - **Document type:** Agency decision ## Text 1152 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations the consolidated entities or through the payment of dividends or any similar distribution, or an unsecured advance or loan would be made to a stockholder, partner, sole proprietor, limited liability company member, employee or affiliate, such that the withdrawal, advance or loan would cause, on a net basis, a reduction in excess adjusted net capital (or, if the futures commission merchant is qualified to use the filing option available under § 1.10(h), excess net capital as defined in the rules of the Securities and Exchange Commission) of 30 percent or more, notice must be provided at least two business days prior to the withdrawal, advance or loan that would cause the reduction: Provided, however, That the provisions of paragraphs (g)(1) and (g)(2) of this section do not apply to any futures or securities transaction in the ordinary course of business between a futures commission merchant and any affiliate where the futures commission merchant makes payment to or on behalf of such affiliate for such transaction and then receives payment from such affiliate for such transaction within two business days from the date of the transaction. * * * * * ■ 3. Section 1.17 is amended by revising paragraph (d)(1) introductory text; adding paragraph (d)(1)(ii)(D); revising paragraph (e) introductory text; and adding paragraph (g), to read as follows: § 1.17 Minimum financial requirements for futures commission merchants and introducing brokers. mstockstill on PROD1PC61 with RULES * * * * * (d) * * * (1) Equity capital means a satisfactory subordination agreement entered into by a partner or stockholder or limited liability company member which has an initial term of at least 3 years and has a remaining term of not less than 12 months if: * * * * * (ii) * * * (D) In the case of a limited liability company, the sum of its capital accounts of limited liability company members, and unrealized profit and loss. * * * * * (e) No equity capital of the applicant or registrant or a subsidiary’s or affiliate’s equity capital consolidated pursuant to paragraph (f) of this section, whether in the form of capital contributions by partners (including amounts in the commodities, options and securities trading accounts of partners which are treated as equity capital but excluding amounts in such trading accounts which are not equity VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 capital and excluding balances in limited partners’ capital accounts in excess of their stated capital contributions), par or stated value of capital stock, paid-in capital in excess of par or stated value, retained earnings or other capital accounts, may be withdrawn by action of a stockholder or partner or limited liability company member or by redemption or repurchase of shares of stock by any of the consolidated entities or through the payment of dividends or any similar distribution, nor may any unsecured advance or loan be made to a stockholder, partner, sole proprietor, limited liability company member, or employee if, after giving effect thereto and to any other such withdrawals, advances, or loans and any payments of payment obligations (as defined in paragraph (h) of this section) under satisfactory subordination agreements and any payments of liabilities excluded pursuant to paragraph (c)(4)(vi) of this section which are scheduled to occur within six months following such withdrawal, advance or loan: * * * * * (g)(1) The Commission may by order restrict, for a period up to twenty business days, any withdrawal by a futures commission merchant of equity capital, or any unsecured advance or loan to a stockholder, partner, limited liability company member, sole proprietor, employee or affiliate, if: (i) Such withdrawal, advance or loan would cause, when aggregated with all other withdrawals, advances or loans during a 30 calendar day period from the futures commission merchant or a subsidiary or affiliate of the futures commission merchant consolidated pursuant to § 1.17(f) (or 17 CFR 240.15c3–1e), a net reduction in excess adjusted net capital (or, if the futures commission merchant is qualified to use the filing option available under § 1.10(h), excess net capital as defined in the rules of the Securities and Exchange Commission) of 30 percent or more, and (ii) The Commission, based on the facts and information available, concludes that any such withdrawal, advance or loan may be detrimental to the financial integrity of the futures commission merchant, or may unduly jeopardize its ability to meet customer obligations or other liabilities that may cause a significant impact on the markets. (2) The futures commission merchant may file with the Secretary of the Commission a written petition to request rescission of the order issued under paragraph (g)(1) of this section. PO 00000 Frm 00018 Fmt 4700 Sfmt 4700 The petition filed by the futures commission merchant must specify the facts and circumstances supporting its request for rescission. The Commission shall respond in writing to deny the futures commission merchant’s petition for rescission, or, if the Commission determines that the order issued under paragraph (g)(1) of this section should not remain in effect, the order shall be rescinded. * * * * * Issued in Washington, DC, on January 5, 2007 by the Commission. Eileen Donovan, Acting Secretary of the Commission. [FR Doc. E7–173 Filed 1–9–07; 8:45 am] BILLING CODE 6351–01–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM06–4–001; Order No. 679– A] Promoting Transmission Investment Through Pricing Reform Issued December 22, 2006. AGENCY: Federal Energy Regulatory Commission, DOE. ACTION: Final rule; order on rehearing. SUMMARY: In this order on rehearing, the Federal Energy Regulatory Commission (Commission) reaffirms its determinations in part and grants rehearing in part of Promoting Transmission Investment through Pricing Reform, Order No. 679. Order No. 679 amended Commission 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: Effective Date: This final rule and order on rehearing will be effective on February 9, 2007. 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. Andre Goodson (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 E:\FR\FM\10JAR1.SGM 10JAR1 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations 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. SUPPLEMENTARY INFORMATION: 1153 Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff. TABLE OF CONTENTS Paragraph numbers I. Introduction ........................................................................................................................................................................................... II. Background ........................................................................................................................................................................................... III. Discussion ........................................................................................................................................................................................... A. Procedural Matters ....................................................................................................................................................................... B. Statutory Arguments ..................................................................................................................................................................... 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... C. Nexus Requirement ...................................................................................................................................................................... 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... D. Cost-Benefit Analysis ................................................................................................................................................................... 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... E. Rebuttable Presumptions .............................................................................................................................................................. 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... F. ROE Sufficient to Attract Investment .......................................................................................................................................... 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... G. Incentives Available to Transcos ................................................................................................................................................. 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... H. Transmission Organization Incentive ......................................................................................................................................... 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... I. Hypothetical Capital Structure ...................................................................................................................................................... 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... J. Single-Issue Ratemaking ................................................................................................................................................................ 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... K. Public Power ................................................................................................................................................................................. 1. Rehearing Requests ................................................................................................................................................................ 2. Commission Determination ................................................................................................................................................... L. Other Issues ................................................................................................................................................................................... 1. Recovery of Costs of Abandoned Facilities .......................................................................................................................... 2. Prudently Incurred Costs ....................................................................................................................................................... 3. Regional Planning .................................................................................................................................................................. 4. CWIP ....................................................................................................................................................................................... 5. Reporting Requirement: FERC–730 ....................................................................................................................................... 6. Miscellaneous ......................................................................................................................................................................... IV. Information Collection Statement ...................................................................................................................................................... V. Document Availability ........................................................................................................................................................................ VI. Effective Date ...................................................................................................................................................................................... APPENDIX Order on Rehearing mstockstill on PROD1PC61 with RULES I. Introduction 1. On July 20, 2006, the Commission issued a Final Rule in this proceeding.1 In the Final Rule, the Commission amended its regulations to establish incentive-based (including performancebased) rate treatments for the transmission of electric energy in interstate commerce by public utilities. These incentives are intended to benefit 1 Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 FR 43294 (July 31, 2006), FERC Stats. & Regs. ¶ 31,222 (2006) (Order No. 679 or Final Rule). VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 1 9 11 11 13 13 14 16 17 20 28 29 35 41 42 46 51 52 59 71 72 76 79 80 86 91 92 93 94 95 97 100 101 102 103 104 108 110 112 117 121 137 138 141 consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion. We took this action pursuant to section 1241 of the Energy Policy Act of 2005 (EPAct 2005),2 which added a new section 219 to the Federal Power Act (FPA). The Final Rule identified ratemaking treatments available under section 219. The Final Rule did not grant incentives to any particular entity, but rather required each applicant to demonstrate that it could meet the requirements of section 219 and the Final Rule. 2. Many entities sought rehearing of the Final Rule.3 The petitioners representing consumer interests argue that the Final Rule was too permissive in offering rate incentives. We have carefully reviewed these petitions and grant them in part in this order. 3. In doing so, we do not, however, depart from a fundamental commitment to provide incentives to support the development of transmission infrastructure. Section 219 was enacted 2 Energy Policy Act of 2005, Pub. L. No. 109–58, 119 Stat. 594, 315 and 1283 (2005). 3 The parties who filed the requests for rehearing and/or clarification are listed in Appendix A. PO 00000 Frm 00019 Fmt 4700 Sfmt 4700 E:\FR\FM\10JAR1.SGM 10JAR1 mstockstill on PROD1PC61 with RULES 1154 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations because of a long decline in transmission investment that is threatening reliability and causing billions of dollars in congestion costs. To reverse this historical trend, section 219 directed the Commission to ‘‘establish, by rule, incentive-based (including performance-based) rate treatments’’ that: ‘‘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; provide a return on equity that attracts new investment in transmission facilities (including related transmission technologies); 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 allow recovery of—(A) all prudently incurred costs necessary to comply with mandatory reliability standards issued pursuant to section 215 and (B) all prudently incurred costs related to transmission infrastructure development pursuant to section 216.’’ 4 The Final Rule fulfilled that command by providing a range of rate treatments that remove impediments to new investment or otherwise attract that investment. 4. This order retains those rate treatments, but modifies the way in which they are applied in three principal respects to address the concerns of petitioners. 5. First, NARUC argues that we erred in rebuttably presuming that certain review processes (e.g., state siting approvals and regional planning processes) satisfy section 219’s requirement that a transmission project ensure reliability or reduce congestion. NARUC contends that these review processes do not, in all cases, establish the need for a particular facility. We grant rehearing in part on this issue. The Commission created the rebuttable presumption because we do not wish to duplicate the work of state siting authorities, regional planning processes, or the U.S. Department of Energy (DOE) under EPAct section 1221. However, we agree with NARUC to the extent that, if review processes do not include a determination of whether a project ensures reliability or reduces congestion, no rebuttable presumption should exist for that project. We will therefore require that each applicant explain whether any process being 4 16 U.S.C.A. 824s(a), (b)(1) (West Supp. 2006). VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 relied upon for a rebuttable presumption includes a determination that the project is necessary to ensure reliability or reduce congestion. Furthermore, we clarify that this rebuttable presumption applies only to whether the project reduces congestion or encourages reliability, not the additional requirements of the Final Rule. As discussed more fully elsewhere in this order, we also grant rehearing with respect to the Final Rule’s rebuttable presumption concerning a National Interest Electric Transmission Corridor (NIETC) designation. 6. Second, the Final Rule required that each applicant demonstrate a nexus between the incentive being sought and the investment being made. Several petitioners argue that the nexus test is not sufficiently rigorous to protect consumers. We grant rehearing in part on this issue. The Final Rule stated that the nexus test is to be applied separately to each incentive, rather than to the package of incentives as a whole. We agree that this approach fails to protect consumers where an applicant both seeks incentives that reduce the risk of the project and seeks an enhanced rate of return on equity (ROE) for increased risk. We will therefore grant in part rehearing and require applicants to demonstrate that the total package of incentives is tailored to address the demonstrable risks or challenges faced by the applicant in undertaking the project.5 If some of the incentives in the package reduce the risks of the project, that fact will be taken into account in any request for an enhanced ROE. 7. Third, several petitioners argue that the Final Rule erred in its treatment of incentive returns on equity. Specifically, they fear the Commission will routinely grant ROEs at the top end of the zone of reasonableness. Although the Commission has broad discretion to establish returns on equity anywhere within the zone of reasonableness, we must be careful in the manner we exercise this discretion. The Commission clarifies below that we do not intend to grant incentive returns ‘‘routinely’’ or that, when granted, they will always be at the ‘‘top’’ of the zone of reasonableness. Rather, each applicant will, first, be required to justify a higher ROE under the required nexus test and, second, to justify where in the zone of reasonableness that return should lie. Furthermore, we recognize that some investors may desire up-front 5 The Commission will apply a rule of reason with respect to what is sufficient to meet the requirement of ‘‘demonstrable’’ risk or challenge. An applicant may provide specific evidence of a risk or challenge or a supported explanation of why it faces a particular risk or challenge. PO 00000 Frm 00020 Fmt 4700 Sfmt 4700 certainty regarding ROE before they invest in a particular project. Because our traditional ratemaking practice typically determines ROE in a hearing only after an investment is made and a facility is constructed, it does not provide such up-front certainty. We therefore clarify that we will entertain requests for a specific ROE determination in a petition for declaratory order. 8. In this order, the Commission denies in part and grants in part the requests for rehearing and/or clarification. II. Background 9. Section 1241 of EPAct 2005 directed the Commission to establish, no later than one year after enactment of section 219, 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.6 To that end, the Commission issued a Notice of Proposed Rulemaking (NOPR) 7 on November 18, 2005 seeking comment on the Commission’s proposal to comply with section 219. In the NOPR, the Commission stated that the purpose of this rulemaking is to promote greater capital investment in new transmission capacity, recognizing that 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.8 10. After considering the comments on the NOPR, the Commission issued its Final Rule on transmission investment incentives to address the need for transmission capacity. In the Final Rule, the Commission provided 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 Final Rule identified specific incentives that the Commission will allow when justified in the context of individual declaratory orders or section 205 filings 6 16 U.S.C.A. 824s(a) (West Supp. 2006). 7 Promoting Transmission Investment Through Pricing Reform, Notice of Proposed Rulemaking, 70 FR 71409 (Nov. 29, 2005), FERC Stats. & Regs., Proposed Regs. ¶ 32,593 (2005). 8 Id. P 2. E:\FR\FM\10JAR1.SGM 10JAR1 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations by public utilities under the FPA.9 The Commission stated that the Final 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, incentives will be permitted only if the incentive package as a whole results in a just and reasonable rate.10 III. Discussion A. Procedural Matters 11. In response to the Final Rule, a number of parties submitted timely requests for rehearing and/or clarification. On August 22, 2006, the Attorney General of the State of Connecticut (Connecticut AG) filed a request for rehearing out of time, seeking to support and join in all aspects the New England Commissions’ request for rehearing. On September 21, 2006, International Transmission Company (International Transmission) filed an answer to SoCal Edison’s request for rehearing. 12. Pursuant to Rule 713(b) of the Commission’s Rules of Practice and Procedure, 18 CFR 385.713(b) (2006), we will deny the request for rehearing of the Connecticut Attorney General because it was filed more than 30 days after issuance of the Final Rule.11 Rule 713(d) of the Commission’s Rules of Practice and Procedure 12 prohibits an answer to a request for rehearing. Therefore, we deny International Transmission’s answer to SoCal Edison’s request for rehearing. 9 Order No. 679, FERC Stats. & Regs ¶ 31,222 at mstockstill on PROD1PC61 with RULES P1. 10 Id. P. 2. Also, in the Final Rule, the Commission agreed with comments that new transmission technologies will be adopted when they are cost effective. The Commission determined that incentives will be considered for advanced technologies through the same evaluation process as other technologies. The Commission declined to make generic determinations regarding the applicability of incentives to particular technologies. Rather, the Final Rule determined that to the extent that applicants seek additional incentives for advanced technologies, the Commission will consider the propriety of such incentives on a case-by-case basis. Id. P 288–93, 298–99. The Final Rule required applicants for incentive rate treatment to provide a technology statement that describes what advanced technologies have been considered and, if those technologies are not to be deployed or have not been deployed, an explanation of why they were not deployed. Id. P 302. No party sought rehearing concerning the Final Rule’s determinations regarding advanced technologies. 11 We note, however, that the Connecticut Attorney General supports New England Commissions’ request for rehearing, which we address in this order. 12 18 CFR 385.713(d) (2006). VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 1155 economically or technologically efficient transmission infrastructure.16 1. Rehearing Requests Section 219 was enacted against the 13. APPA/NRECA argue that the backdrop of a long decline in Commission misinterpreted section 219 transmission investment that is as requiring greater flexibility in imposing substantial costs—in ratemaking practices. According to congestion and service interruptions— APPA/NRECA, ‘‘incentives’’ are not on consumers. If Congress had deemed necessary to attract capital because, our existing practices sufficient to under existing Supreme Court reverse this trend, there would have precedent, ‘‘a public utility’s rate of been little need to enact section 219. return should also be sufficient to attract Section 219 does not simply ‘‘codify’’ investment in new transmission our legal authority; it requires us to take facilities.’’ 13 APPA/NRECA therefore affirmative action to promote new conclude that section 219 merely investment. Although the resulting rates ‘‘codified the longstanding Commission must be just and reasonable, the and judicial interpretations of FPA Commission has significant discretion section 205’s requirement that rates be under section 205 in making that just and reasonable.’’ 14 determination and section 219 provides clear direction that we use that 2. Commission Determination discretion to promote new 14. We agree with APPA/NRECA that infrastructure, not simply maintain the section 219 did not modify the status quo. requirement that rates be just and 15. While section 219 requires us to reasonable under section 205, but do more than maintain the status quo disagree that it did no more than restate for transmission pricing, we recognize that longstanding principle. Section 219 that our traditional ratemaking authority makes very clear that the Commission also requires us to establish a return on ‘‘shall establish, by rule, incentive-based a public utility’s assets that is ‘‘reasonably sufficient to assure (including performance-based) rate confidence in the financial soundness of treatments’’ and that these rate the utility and should be adequate to treatments ‘‘shall * * * promote maintain and support its credit and reliable and economically efficient enable it to raise money necessary for transmission and generation of the proper discharge of its public electricity by promoting capital duties’’ 17 and ‘‘should be sufficient to investment in the enlargement, assure confidence in the financial improvement, maintenance, and integrity of the enterprise, so as to operation of all facilities for the maintain its credit and to attract transmission of electric energy in capital.’’ 18 Thus, a base-level ROE interstate commerce, regardless of the sufficient to promote capital investment ownership of the facilities; provide a in transmission facilities historically has return on equity that attracts new not been considered an ‘‘incentive,’’ but investment in transmission facilities a requirement of establishing a just and (including related transmission technologies); encourage deployment of reasonable rate.19 In this regard, we transmission technologies and other 16 See id. at 824s(a) and (b)(3). measures to increase the capacity and 17 Bluefield Waterworks & Improvement Co. v. efficiency of existing transmission Pub. Serv. Comm’n of W. Va., 262 U.S. 679, 693 facilities and improve the operation of (1923). 18 FPC v. Hope Natural Gas Co., 320 U.S. 591, 603 the facilities and allow recovery of—(A) all prudently incurred costs necessary to (1944). 19 In contrast to a base-level ROE that reflects the comply with mandatory reliability financial and regulatory risks of an investment, an standards issued pursuant to section ‘‘incentive’’ has been more typically associated with 215 and (B) all prudently incurred costs specific basis point additions to a base ROE to satisfy discrete policy objectives. See, e.g., Western related to transmission infrastructure Area Power, 99 FERC ¶ 61,306, reh’g denied, 100 development pursuant to section FERC ¶ 61,331 (2002) (Western), aff’d sub nom. 216.’’ 15 These words do far more than Public Utilities Commission of the State of ‘‘codify’’ the just and reasonable California v. FERC, 367 F.3d 925 (D.C. Cir. 2004); Michigan Electric Transmission Co., LLC, 105 FERC standard; they command the ¶ 61,214 (2003) (METC); American Transmission Commission to use its discretion under Company, L.L.C., 105 FERC ¶ 61,388 (2003) section 205 to promote capital (American Transmission); ITC Holdings Corp., 102 investment. Furthermore, Congress in FERC ¶ 61,182, reh’g denied, 104 FERC ¶ 61,033 (2003) (ITC Holdings); Regional Transmission section 219 even highlighted the Organizations, Order No. 2000, 65 FR 809 (Jan. 6, importance of investment in B. Statutory Arguments 13 APPA/NRECA at 12. 14 Id. at 12–13. 15 16 U.S.C.A. 824s(a), (b)(1)–(4) (West Supp. 2006). PO 00000 Frm 00021 Fmt 4700 Sfmt 4700 2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g, Order No. 2000–A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. & Regs. ¶ 31,092 (2000), aff’d sub nom. Pub. Util. Dist. No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001) E:\FR\FM\10JAR1.SGM Continued 10JAR1 1156 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations recognize that our responsibilities under section 205 and our responsibilities under section 219 overlap in significant ways. We recognize that it may be difficult to meaningfully distinguish between an ROE that appropriately reflects a utility’s risk and ability to attract capital and an ‘‘incentive’’ ROE to attract new investment. Notwithstanding this difficult distinction, consistent with Congress’ direction in section 219, we are obligated to establish ROEs for public utilities that both reflect the financial and regulatory risks attendant to a particular project and that are sufficient to actively promote capital investment. We will do so within the zone of reasonableness, including above the midpoint where appropriate, to accomplish these regulatory responsibilities.20 This end-result ROE, whether characterized as an incentive pursuant to section 219 or as a baselevel ROE consistent with the just and reasonable standard of section 205, will take into consideration financial and regulatory risks attendant to the project and thereby satisfy Congress’ direction that the Commission ‘‘provide a return on equity that attracts new investment in transmission facilities * * *.’’ 21 mstockstill on PROD1PC61 with RULES C. Nexus Requirement 16. In the Final Rule, the Commission stated that the applicant must demonstrate that: (1) 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; (2) there is a nexus between the incentive sought and the investment being made; and (3) the resulting rates are just and reasonable.22 The Commission stated that an applicant is not required to show that, but for the incentives, the expansion would not occur because Congress did not require such a showing. Nevertheless, the Commission (Order No. 2000). Section 219 addresses both situations. In addition to requiring the Commission to establish, by rule, incentive rate treatments to promote transmission investment generally, section 219 also requires the Commission to establish incentive-based rates to encourage transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities. Thus, Congress intended for us to establish an ROE sufficient to reflect financial and regulatory risks and also to consider discrete ROE incentives for, among other things, participation in transmission organizations, projects with particular benefits to reliability or reducing congestion, new technologies and efficiency enhancements. 20 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 93. 21 16 U.S.C.A. 824s(b)(2) (West Supp. 2006). 22 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 2, 26. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 maintained that it will 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.23 3. Rehearing Requests 17. Industrial Consumers oppose allowing applicants to request multiple incentives, arguing that the Commission erred by determining that section 219 does not require applicants to demonstrate a relationship between an incentive proposal and transmission investment.24 According to Industrial Consumers, the just and reasonable requirements of section 219(d) require that incentive rates must be based on a showing that there is a relationship between increased rates and the attraction of new capital.25 They assert that customers should not be forced to pay for incentives unless those incentives are actually necessary to deliver additional transmission capacity. Therefore, Industrial Consumers claim that contrary to the Commission’s conclusion, section 219 does not authorize the Commission to depart from judicial precedent on just and reasonable incentive rates.26 Further, to the extent that the Commission relies on non-cost factors in determining just and reasonable incentive rates, the Commission must specify the nature of the relevant noncost factors and offer a reasoned explanation of how the factors justify the resulting rates.27 Industrial Consumers contend that the reasoned explanation must calibrate the relationship between increased rates and the attraction of new capital, ensure that the increase is in fact needed, and is no more than needed to accomplish the objective.28 18. APPA/NRECA also argue that applicants must demonstrate a need for the incentive rate treatments and make a showing sufficient for the Commission to find that a particular incentive rate treatment ‘‘is in fact needed and no more than is needed’’ under the FPA and the Administrative Procedure Act.29 APPA/NRECA consider the nexus requirement to be inadequate because it fails to require applicants to show that a particular rate treatment is actually a lawful incentive under sections 205 and 219 of the FPA.30 They assert that under the nexus requirement, an applicant could show a sufficient rational relationship merely by claiming that granting the incentive rate treatment will make the investment more profitable and thus more attractive to investors.31 TDU Systems repeat these points and claim that the nexus requirement will have no effect on the granting or denying of incentive applications unless the Commission provides concrete examples of categories of asserted relationships between proposed incentives and facilities that will not satisfy the nexus requirement. They also do not consider the nexus requirement to be a reasonable substitute for a cost-benefit analysis.32 19. Likewise, TAPS argues that the nexus requirement is unduly vague because it fails to clearly require a causal connection between the incentive and consumer benefits. TAPS asserts that the nexus requirement should test whether a requested incentive would reasonably be expected to cause either a net decrease in delivered power costs even after considering incentiveincreased transmission costs, or, where the expected net effect on delivered power costs is an increase, reliability gains that make that increase worthwhile.33 To remedy the alleged deficiencies of the nexus requirement, TAPS proposes that the nexus requirement be revised to provide: ‘‘That the incentive sought is designed to result in those facilities being invested in, completed, and placed into service.’’ 34 TAPS also recommends that the rule be amended to explicitly retain a reasonable calculation test, so that the Commission can determine which incentives return net consumer benefits and will be able to verify the accuracy of its prediction that granting incentives will spur increased investment.35 3. Commission Determination 20. Petitioners raise two related objections to the nexus requirement: (i) That it is too vague and therefore will be too easy to satisfy, and (ii) because it is not sufficiently rigorous, a different standard should be adopted. We address each in turn. 21. The required nexus test requires an applicant to demonstrate that the 23 Id. P 26, 48. 24 Industrial Consumers at 3–7. 30 APPA/NRECA at 22. 25 Id. at 4, citing Farmers Union Cent. Exch. v. FERC, 734 F.2d 1486, 1503 (D.C. Cir. 1984) (Farmers Union). 26 Id. at 5. 27 Id. at 6–7 28 Id. 29 5 U.S.C. 556 (2000). PO 00000 Frm 00022 Fmt 4700 Sfmt 4700 31 Id. at 23, citing Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 91, 117, and 133. 32 TDU Systems at 19–20. 33 TAPS at 8–9. 34 Id. at 11. 35 Id. at 16, citing City of Charlottesville v. FERC, 661 F.2d 945, 955 (D.C. Cir. 1981). E:\FR\FM\10JAR1.SGM 10JAR1 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations incentives being requested are ‘‘ tailored to the risks and challenges faced’’ by the project.36 By this we mean that the incentive(s) sought must be tailored to address the demonstrable risks and challenges faced by the applicant in undertaking the project.37 The required nexus test therefore satisfies the Industrial Consumers request that there be a relationship between the rate treatments sought and the attraction of new capital.38 It also satisfies TAPS’ request that ‘‘the incentive sought is designed to result in’’ new facilities being constructed.39 We disagree with TAPS and APPA/NRECA, however, that the test is designed to be lenient or that it will necessarily be satisfied in every case. As we indicated in the Final Rule, ‘‘[n]ot every incentive will be available for every new investment. Rather, each applicant must demonstrate that there is a nexus between the incentive sought and the investment being made.’’ 40 In evaluating whether the applicant has satisfied the required nexus test, the Commission will examine the total package of incentives being sought, the inter-relationship between any incentives, and how any requested incentives address the risks and challenges faced by the project. 22. TDU Systems complain that we did not provide ‘‘concrete examples’’ of showings that would either satisfy or fail the nexus test. Although that was not the purpose of the Final Rule—the purpose was to enunciate the criteria to be applied in individual cases—we did provide certain illustrations. For example, we emphasized the need for incentives for new transmission projects that can integrate new generation and load and thereby improve reliability and reduce congestion: mstockstill on PROD1PC61 with RULES New transmission is needed to connect new generation sources and to reduce congestion. However, because there is a competitive market for new generation facilities, these new generation resources may be constructed anywhere in a region that is economic with respect to fuel sources or other siting considerations (e.g., proximity to wind currents), not simply on a ‘‘local’’ basis 36 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 26. 37 We also note that the Commission retains its discretion to provide policy-based incentives. As the courts have said, even prior to our new authority in section 219, the Commission’s incentive rate determinations ‘‘involve matters of rate design * * * [and] policy judgments [that go to] the core of [the Commission’s] regulatory responsibilities.’’ Maine Public Utilities Commission v. FERC, 454 F.3d 278, 288 (D.C. Cir. 2006). See also Permian Basin Area Rate Cases, 390 U.S. 747 (1968) (Permian). 38 Industrial Consumers at 4. 39 TAPS at 11. 40 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 26. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 within each utility’s service territory. To integrate this new generation into the regional power grid, new regional high voltage transmission facilities will often be necessary and, importantly, no single utility will be ‘‘obligated’’ to build such facilities. Indeed, many of these projects may be too large for a single load serving entity to finance. Thus, for the Nation to be able to integrate the next generation of resources, we must encourage investors to take the risks associated with constructing large new transmission projects that can integrate new generation and otherwise reduce congestion and increase reliability.[41] We also emphasized that ‘‘this does not mean that every new transmission investment should receive a higher return than otherwise would be the case. For example, routine investments to meet existing reliability standards may not always * * *, qualify for an incentive-based ROE.’’ 42 23. The Commission reaffirms that the most compelling case for incentives are new projects that present special risks or challenges, not routine investments made in the ordinary course of expanding the system to provide safe and reliable transmission service. We therefore reject the arguments of EEI and Southern Companies that such routine investments should be treated the same, for purposes of applying the required nexus test, as new projects that present special risks or challenges.43 24. We also believe that the guidance provided in the Final Rule is sufficient. The purpose of the Final Rule was to establish criteria to be applied in individual cases, not to provide an exhaustive list of situations where incentives will be granted or denied. The decision whether to grant or deny incentives to a particular project is appropriately the subject of an individual rate application (or declaratory order) where the Commission can evaluate whether the applicants have fully supported any incentive rate treatments being sought. 25. We now turn to the alternative tests advocated by petitioners, discussing the ‘‘but for’’ test in this section and the ‘‘cost-benefit’’ test in the following section. The Final Rule rejected a ‘‘but for’’ test as inconsistent with Congressional intent in enacting section 219.44 We reaffirm that finding here. In doing so, we emphasize that both the required nexus test and the ‘‘but for’’ test share one thing in common: Their common objective is to ensure that incentives are not provided 41 Id. P 25. 42 Id. P 27. 43 See infra P 52. 44 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 48. PO 00000 Frm 00023 Fmt 4700 Sfmt 4700 1157 in circumstances where they do not materially affect investment decisions. They differ sharply, however, in the means by which they seek to achieve that objective. The ‘‘but for’’ test requires an applicant to show that a facility would not be constructed unless the incentive is granted. We reject that test because it erects an evidentiary hurdle that could only, in very rare cases, be satisfied. There are many impediments to investing in new transmission, including siting concerns, financing challenges, rate recovery concerns, etc. It is therefore unreasonable to expect or require an applicant to show that a facility could not be constructed ‘‘but for’’ the removal of a single impediment—e.g., increased cash flow through 100 percent construction work-in-progress (CWIP) or an enhanced ROE. This test could rarely, if ever, be satisfied, particularly given that incentives are ordinarily sought before investment decisions are made and, hence, before any siting impediments are even confronted. 26. The Commission therefore reaffirms its rejection of the ‘‘but for’’ test as the appropriate test for applying section 219. It would erect a barrier that is nearly impossible to meet and is thereby fundamentally incompatible with Congressional intent in enacting section 219. In enacting EPAct 2005, Congress plainly understood that there are many impediments to new transmission investment. Congress therefore took a variety of actions to address that problem, including giving the Commission backstop siting authority, requiring that entities have long-term transmission rights to support new investment and, in section 219, providing appropriate rate incentives. We decline to render section 219 essentially an empty letter by requiring the demonstration of a negative—that absent an incentive rate treatment, under no circumstance would a transmission project possibly be built. This would be directly contrary to the intent of Congress to encourage the construction of needed transmission. 27. We will grant rehearing, however, in one respect. The Final Rule states that the nexus test is to be applied separately to each incentive, rather than to the package of incentives as a whole. We agree that this approach fails to protect consumers where an applicant seeks incentives that both reduce the risk of the project and offer an enhanced ROE for increased risk. Even though the applicant no longer has to apply the nexus requirement separately to each incentive, the applicant will be required to demonstrate that the total package of incentives is tailored to address the E:\FR\FM\10JAR1.SGM 10JAR1 1158 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations demonstrable risks or challenges faced by the applicant. In presenting a package to the Commission, applicants must provide sufficient explanation and support to allow the Commission to evaluate each element of the package and the interrelationship of all elements of the package. If some of the incentives would reduce the risks of the project, that fact will be taken into account in any request for an enhanced ROE. We are revising § 35.35(d) to reflect this clarification. D. Cost-Benefit Analysis 28. In the Final Rule, the Commission adopted the proposal in the NOPR not to require applicants for incentive-based rate treatments to provide cost-benefit analyses. The Commission noted that courts have recognized that the Commission may consider non-cost factors in its ratemaking decisions.45 Therefore, the Commission stated that it may consider non-cost factors as well as cost factors and that it will consider the justness and reasonableness of any proposal for incentive rate treatment in individual proceedings. mstockstill on PROD1PC61 with RULES 1. Rehearing Requests 29. TDU Systems and APPA/NRECA contend that the Final Rule’s failure to require that incentive rates be justified by a cost-benefit analysis is inconsistent with sections 205 and 219 of the FPA. They assert that the Commission needs the information in the cost-benefit analysis to determine whether a particular incentive rate is just and reasonable, i.e. whether its cost is outweighed by the benefits customers will receive.46 APPA/NRECA also contend that the Commission has no basis for concluding that a particular incentive provides consumers with a net benefit, as required under section 219(a), without a cost-benefit analysis.47 TDU Systems also point out that the Commission and affected customers must have the information necessary to distinguish between proposed projects that would benefit customers a great deal and proposed projects that would benefit customers minimally if at all.48 Further, in considering non-cost factors, these parties argue that the Commission cannot make a reasoned decision about the appropriateness of non-cost factors in approving an incentive rate without first knowing the costs and benefits of 45 Id. P 65, citing Permian, 390 U.S. 747, 815 (1968); Pub. Utils. Comm’n of Cal. v. FERC, 367 F.3d 925, 929 (D.C. Cir. 2004) (CPUC v. FERC); Maine Pub. Utils. Comm’n. v. FERC, 454 F.3d 278, slip op. at 19 (D.C. Cir. 2006) (Maine PUC v. FERC). 46 APPA/NRECA at 26; TDU Systems at 11. 47 APPA/NRECA at 26–27. 48 TDU Systems at 12. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 the incentive rate.49 They assert that intervenors also need this information to evaluate the impact of the rate proposal on them and to understand how much the applicant is relying on non-cost considerations. Moreover, APPA/NRECA contend, if the applicant is not required to present any evidence that consumers obtain net benefits from an increase in their transmission rates, the Commission cannot strike a fair balance between the financial interests of the regulated company and the relevant public interests, both existing and foreseeable.50 Further, TDU Systems and APPA/NRECA state that the plain language of section 219 demonstrates that Congress’ intent is to promote only efficient investment, investment that benefits consumers. They assert that Congress’ unqualified adoption in section 219(d) of the statutory just and reasonable standard demands a cost-benefit analysis. 30. TDU Systems and APPA/NRECA also argue that elimination of the costbenefit analysis will be harmful to customers because of the two-stage application procedure.51 They assert that applicants should be required to provide the Commission and customers with all relevant facts concerning costs and benefits at the petition for declaratory order stage, where the applicant’s right to the incentive will be decided, because the Final Rule precludes relitigation of these issues in the later section 205 proceeding.52 They state that the interested parties must have the information needed to raise specific issues as to whether the likely customer benefits of the project justify the likely costs of the incentives to be awarded. They also argue that without a rigorous cost-benefit analysis at the initial stage, the benefits that formed the Commission’s initial approval would be so amorphous that there would be little objective data for the Commission to assess in its periodic progress assessments. Allowing recipients of incentives to fix the term of their incentive-rate awards in the absence of a rigorous initial cost-benefit analysis would serve only to perpetuate the contravention of the statutory just and 49 Id. at 15; APPA/NRECA at 27. 50 APPA/NRECA at 29, citing Farmers Union, 734 F.2d at 1502. 51 Under the Commission’s two-stage application procedure, an applicant can petition for a declaratory order seeking an incentive-based rate treatment for its project. After the Commission issues the declaratory order, the applicant must seek to put the rates into effect through a separate single-issue or comprehensive section 205 filing. See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 76–78. 52 TDU Systems at 12–14; APPA/NRECA at 29– 30. PO 00000 Frm 00024 Fmt 4700 Sfmt 4700 reasonable standard, according to APPA/NRECA. TDU Systems agree, stating that they can perceive no justification for allowing incentive awardees to define the duration of their own awards in the absence of a rigorous initial cost-benefit analysis. 31. Industrial Consumers argue that the Commission impermissibly departed from Order No. 2000,53 without a reasoned explanation, by eliminating the cost-benefit analysis. They assert that the Commission wrongly concluded that the cost-benefit analysis is not necessary because customers will be protected by the Commission’s review of applications pursuant sections 205, 206, and 219 of the FPA, which require that all rates be just and reasonable and not unduly discriminatory or preferential.54 They state that in Order No. 2000, the Commission required applicants for innovative transmission rate treatments to demonstrate how the investment in the transmission system benefits consumers and to provide a cost-benefit analysis, including rate impacts. Such a disconnect with Commission precedent reflects an absence of reasoned decision making.55 32. Further, Industrial Consumers contend that, to successfully balance the competing interests of providing incentives to encourage transmission investment and its statutory responsibility of protecting customers from excessive rates, the Commission must narrowly tailor incentives that require a close calibration between the increased rates and a corresponding level of benefits. Without such a close calibration between the proposed incentive rates and the anticipated benefit, the Commission risks thwarting the just and reasonable requirements of the FPA. Thus, according to Industrial Consumers, applicants for incentive treatment must be required to demonstrate that incentives will actually yield a positive return in the form of otherwise unachievable reliability improvements and reduced congestion costs.56 33. SMUD contends that the nexus requirement is not sufficient to justify eliminating the cost-benefit analysis required under Order No. 2000. It asserts that there is no connection between the lawfulness of non-cost factors and the elimination of the costbenefit test for incentive rates. SMUD states that, while the Commission recognized the non-cost-based nature of incentive ratemaking in the 1992 Policy 53 Order No. 2000, supra note 19. 54 Industrial Consumers at 7–8. 55 Id. 56 Id. at 10. E:\FR\FM\10JAR1.SGM 10JAR1 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations Statement, the Commission, nonetheless concluded that benefits to consumers must be quantifiable, and SMUD asserts that nothing in section 219 alters the requirement for a cost-benefit test.57 Further, SMUD contends that the nexus test results in a lower burden of proof for applicants without explaining why a cost-benefit test is no longer necessary. SMUD requests the Commission to clarify that the incentives for new construction to reduce congestion will be capped so that the delivered cost of power to the consumer is lower than what it was before the facilities were constructed, thereby ensuring that consumers will not pay incentive rates for congestion-reducing construction unless the result is a lower cost of delivered power. SMUD also requests clarification that incentives for reliability upgrades will not reward the construction of more transmission capacity than is reasonably necessary to meet new reliability standards, thereby ensuring that incentive payments for reliability improvements will not be awarded for more than what is needed to ensure reliability. 34. TAPS asserts that the Commission’s authority to award abovecost incentives has always turned on whether the incentive’s cost is outweighed by the benefits customers will receive.58 TAPS advocates that the Final Rule be amended to explicitly retain a reasonable calculation test that analyzes which incentives spur increased investment, and require the Commission to use this test to replace the cost-benefit requirement. mstockstill on PROD1PC61 with RULES 2. Commission Determination 35. The Commission reaffirms the decision not to adopt a ‘‘cost-benefit’’ analysis for four principal reasons. 36. First, the arguments in favor of a cost-benefit analysis start from the premise that our traditional approach to setting transmission rates is fully sufficient to attract new transmission investment in all cases. This premise cannot be squared with section 219. As discussed above, section 219 was enacted to counteract a long decline in transmission investment. Its provisions are mandatory, not permissive, and they proceed from the premise that the Commission must use its full discretion under section 205 to ‘‘promot[e] capital investment.’’ It did not, as noted above, simply codify the status quo; it required 57 SMUD at 2, citing 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) (1992 Policy Statement). 58 TAPS at 9, citing CPUC v. FERC, 367 F.3d at 929. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 the Commission to pass a new rule adopting incentive-based rate treatments. 37. These facts readily distinguish the Final Rule from prior instances where the Commission required a cost-benefit analysis.59 None of those policies was adopted in response to a Congressional directive to use the Commission’s discretion under section 205 to address a national problem—the decline in transmission investment that is threatening reliability and imposing billions of dollars in congestion costs on consumers. 38. Second, petitioners fail to recognize that applicants will be required to show that all rates are just and reasonable under section 205. For example, any ROE will remain within the range of reasonable returns. Further, many of the incentives described in the Final Rule only change the timing of cost recovery (e.g., 100 percent CWIP), not the level of cost recovery. Others reduce the risks of investment (e.g., abandoned plant recovery), rather than changing the cost levels. We reiterate that each of the incentives adopted by the Final Rule is fully consistent with our responsibility to ensure that rates are just and reasonable under section 205. 39. Third, those advocating a costbenefit analysis fail to recognize that the courts have held that the Commission may consider non-cost factors in setting rates.60 Our authority to consider noncost factors applies equally in the development of incentive ratetreatments.61 40. Finally, although the Commission is rejecting a cost-benefit analysis for the reasons stated above, applicants will nonetheless be required, as discussed above, to demonstrate the required nexus between the incentive being sought and the investment being made. This requirement will ensure that incentives are granted only where the 59 Order No. 2000 required as a condition for any innovative transmission rate treatment that the applicant demonstrate ‘‘a cost-benefit analysis, including rate impacts.’’ 18 CFR 35.34(e)(ii) (2006). The Commission notes that in the 6 years since Order No. 2000 was issued, we have not received a single application seeking any of the innovative rate treatments that were provided for in that order. We believe that the requirement of a cost benefit analysis was perceived as an insurmountable hurdle which inhibited the utilities from seeking innovative rate treatments. Accordingly, in developing incentive rate treatments under section 219, the Commission expressly deleted the requirement for a cost-benefit analysis. 60 See Permian, 390 U.S. 747 at 791–2; CPUC v. FERC, 367 F.3d 925 at 929. 61 Maine PUC v. FERC, 454 F.3d at 289 (‘‘particularly in view of the [Commission’s] authority to consider non-cost factors in setting rates, the State Commissions’ position on calibration demands too much’’). PO 00000 Frm 00025 Fmt 4700 Sfmt 4700 1159 incentives are tailored to address the demonstrable risks or challenges faced by the applicant. E. Rebuttable Presumptions 41. In the Final Rule, the Commission adopted a set of processes that, if an applicant satisfies them, its project will be afforded a rebuttable presumption that it qualifies for transmission incentives. First, it created a rebuttable presumption that an applicant has met the requirements of section 219 if that project results from a fair and open regional planning process that considers and evaluates projects for reliability and/or congestion and is found to be acceptable to the Commission.62 Second, the Commission stated that regional planning processes can provide an efficient and comprehensive forum for evaluating transmission investments’ qualifications under section 219 by looking at a variety of options across a large geographic footprint. For example, such a process has the ability to determine whether a given project is needed, whether it is the better solution, and whether it is the most cost-effective option among other alternatives.63 The Commission also adopted a rebuttable presumption that an applicant has met the requirements of section 219 if a proposed project is located in a NIETC or has received construction approval from an appropriate state commission, agency or state siting authority.64 The Commission also stated that ‘‘other applicants not meeting these criteria may nonetheless demonstrate that their project is needed to maintain reliability or reduce congestion by presenting [to the Commission] a factual record that would support such a finding.’’ 65 1. Rehearing Requests 42. NARUC and TAPS contend that the Final Rule’s rebuttable presumption is not consistent with the statutory requirements of section 219. They state that there was no showing in the Final Rule that assessments in the regional planning processes satisfy the 62 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 58. 63 Id. The Commission noted that the value of regional planning was expressly recognized 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 the region. See Preventing Undue Discrimination and Preference in Transmission Service, Notice of Proposed Rulemaking, 71 FR 32,536 (June 6, 2006), FERC Stats & Regs., Preambles ¶ 32,603 at P 36 (2006) (OATT Reform NOPR). 64 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 58. 65 Id. P 57. E:\FR\FM\10JAR1.SGM 10JAR1 1160 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations requirements of section 219 and there is no basis to assume that the criteria employed in regional planning processes utilize the criteria set out in section 219.66 Therefore, they argue that it cannot be reasonably presumed that every project that is subject to regional planning will benefit customers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion. NARUC further contends that incentives for using regional planning processes are inappropriate in view of the Commission’s proposal in the OATT Reform NOPR to require all jurisdictional public utilities to engage in regional planning.67 Under such a mandatory requirement, all projects will effectively qualify for the rebuttable presumption because all projects will, presumably, be included in approved regional plans.68 43. APPA/NRECA, NARUC, TDU Systems, and TAPS argue that the rebuttable presumption for state approvals should be deleted because there is no legal or logical basis to presume that projects falling into this category will ensure reliability or reduce the cost of delivered power.69 They assert that the criteria applied by the state may not resemble the criteria that the Commission is required to apply under section 219 of the FPA. They argue that state commissions are mainly concerned with protecting retail customers in their respective states and state authorities apply state laws to construction-permit applications. Accordingly, states are not focused on public utility wholesale customers who may be in other states, or ensuring reliability or reducing transmission congestion. Therefore, APPA/NRECA assert that the Commission cannot delegate its responsibilities under section 219 to state authorities that may of necessity have a very different mission.70 44. NARUC also claims that projects receiving a designation as projects in NIETC should not receive a rebuttable presumption because such a designation, alone, cannot assure that the statutory prerequisites of section 219 have been satisfied when the criteria for NIETC designation do not mirror those set out for incentives under the statute.71 mstockstill on PROD1PC61 with RULES 66 NARUC at 5–6; TAPS at 7–8. 67 See OATT Reform NOPR, FERC Stats & Regs., Preambles ¶ 32,603 at P 36. 68 NARUC at 6. 69 Id. at 7; TAPS at 6; APPA/NRECA at 37–39; TDU Systems at 25–27. 70 APPA/NRECA at 38. 71 NARUC at 7. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 45. Additionally, NARUC, APPA/ NRECA, and TDU Systems claim that the scope of the rebuttable presumption is ambiguous and needs to be clarified. They state that it is not clear to which part of the three-part showing that the rebuttable presumption applies to.72 They state that the rebuttable presumption should only apply to the first part (ensure reliability or reduce the cost of delivered power by reducing transmission congestion) of the threepart showing because the only way an applicant can appropriately satisfy the statutory requirements of FPA section 219 is to demonstrate on the record that the project either ensures reliability or reduces the cost of delivered power and that the rates satisfy sections 205 and 206 of the FPA. Therefore, the applicant must still demonstrate with factual evidence that there is a nexus between the incentive sought and the investment being made and that the resulting rates are just and reasonable.73 APPA/NRECA also request the Commission to clarify that this interpretation applies to both section 205 filings and petitions for declaratory order.74 TAPS contends that the rebuttable presumptions conflict with the Commission’s intended limitations on the receipt of incentives, such as routine investments, which may be included in a regional plan and required to receive state siting approval prior to construction, but may not always qualify for an incentive-based ROE.75 2. Commission Determination 46. We will grant rehearing and clarification in part. The Commission created the rebuttable presumption for the purpose of avoiding duplication in determining whether a project maintains reliability or reduces congestion. We do not wish to repeat the work of state siting authorities, regional planning processes, or the DOE in evaluating these issues. However, we agree with NARUC that if such processes do not in fact include such a determination, a rebuttable presumption would not be appropriate. Accordingly, 72 Under section 35.35(d) of the regulatory text, an applicant for incentive rates is required to make a three-part showing that: (1) 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; (2) there is a nexus between the incentive sought and the investment being made; and (3) resulting rates are just and reasonable. 18 CFR 35.35(d) (2006). 73 APPA/NRECA at 35–36; NARUC at 7–8; TDU Systems at 24–25. 74 APPA/NRECA at 36. 75 TAPS at 8, citing Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 94. PO 00000 Frm 00026 Fmt 4700 Sfmt 4700 we grant rehearing and are modifying § 35.35 in three ways. 47. First, we agree with NARUC that the NIETC process will not necessarily determine that every transmission project within a designated corridor will meet the section 219(a) requirements, nor is DOE required to make such a determination. However, we do not believe it is necessary to retain this particular rebuttable presumption in our regulations because any project which is proposed in a NIETC will of necessity have to go through a state or federal siting process. If an applicant’s proposed project is within a NIETC, we expect that it will be sited in most instances by the appropriate state siting authority and the applicant will be able to rely on the state siting rebuttable presumption for meeting the requirements of section 219(a). In those cases where projects within a NIETC are sited by this Commission pursuant to our new authority in section 216, an applicant may rely on our findings in our siting process for meeting the requirements of section 219(a).76 Thus, applicants with projects in a NIETC have an opportunity to rely upon the appropriate siting processes to meet the requirement that a project ensure reliability or reduce the cost of delivered power by reducing transmission congestion, and we need not include the NIETC process as a rebuttable presumption.77 48. We are amending our regulations to provide that an applicant that obtains Commission authorization under section 216 to site electric transmission facilities in interstate commerce shall be deemed to satisfy the requirements of section 219(a).78 76 As stated in section 216, the Commission may exercise its new siting authority if inter alia it finds that the construction or modification of the facilities ‘‘significantly reduce transmission congestion in interstate commerce and protects or benefits consumers.’’ Since the Commission is required to find that a project reduces transmission congestion before it can authorize the siting of a transmission facility within a NIETC, such facilities necessarily satisfy the requirement of section 219(a) and these regulations. 77 While DOE is not required to determine whether all projects within a NIETC meet the prerequisites of section 219, we anticipate that DOE is likely to consider whether transmission projects within these corridors ensure reliability or reduce the cost of delivered power by reducing transmission congestion. Thus, an applicant that does not rely upon a rebuttable presumption for meeting the pre-requisites of section 219 may nonetheless use the findings made by the DOE. Accordingly, the Commission will give due weight to the DOE’s determinations concerning the ability of transmission projects within a NIETC to ensure reliability or reduce the cost of delivered power by reducing transmission congestion. 78 Section 216(b)(4). See also Regulations for Filing Applications for Permits to Site Interstate Electric Transmission Facilities, Order No. 689, 71 E:\FR\FM\10JAR1.SGM 10JAR1 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations 49. Second, we will modify our regulations to require each applicant seeking to invoke the rebuttable presumption to explain in its filing how the applicable process (regional planning or state approval) in fact considered whether the project ensures reliability or reduce congestion. We continue to believe that, these approval processes will, in all likelihood, examine whether the project maintains reliability or reduces congestion. But in instances where this is not the case the applicant will bear the full burden of demonstrating such facts. 50. Third, we also clarify that the rebuttable presumption applies only to the requirement that an applicant demonstrate, that a project is needed to ensure reliability or to reduce congestion. It does not apply to any other requirement in 18 CFR 35.35, such as the requirement, that the applicant demonstrate the required nexus between the incentive sought and the investment being made 79 and that the resulting rates are just and reasonable in either the petition for declaratory order or section 205 filing. We will modify our regulations accordingly. F. ROE Sufficient To Attract Investment mstockstill on PROD1PC61 with RULES 51. In the Final Rule, the Commission adopted the NOPR’s proposal to 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 congestion.80 By including this provision in the Final Rule, the Commission stated that it satisfied the requirement of section 219 to provide an ROE that attracts new investment in transmission facilities (including related transmission technologies). The Commission stated that it will provide ROEs at the upper end of the zone of reasonableness for transmission investments that meet the requirements of section 219. Further, the Commission clarified that it will continue to use the FR 69,440 at P 41 (Dec. 1, 2006) (‘‘The Commission will review the proposed project and determine if it reduces the transmission congestion identified in DOE’s study and if it will protect or benefit consumers. It will investigate and determine the impact the proposed facility will have on the existing transmission grid and the reliability of the system’’). 79 We note that the Final Rule’s statement regarding routine investment cited by TAPS, applies to the nexus demonstration, and therefore there is no conflict between the rebuttable presumption and that statement. 80 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 91. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 DCF analysis for ROE determinations.81 The Commission also noted that not every investment that increases reliability or reduces congestion will qualify for an incentive-based ROE. For example, routine investments may continue to be assessed under traditional ROE determinations because there is an obligation to construct them and high assurance of recovery of the related costs.82 1. Rehearing Requests 52. EEI and Southern Companies take exception to the statement in the Final Rule that ‘‘routine investments made to comply with existing reliability standards may not always qualify for an incentive-based ROE.’’ 83 They argue that the statement discriminates against projects or upgrades that may be proposed to address reliability concerns, and therefore the statement should be deleted.84 Southern Companies emphasize that the statutory requirement under 219 makes no distinction between routine or nonroutine status; therefore, regardless of status, an investment that promotes reliability should be entitled to incentive rate treatment. In that respect, Southern Companies request the Commission to confirm that all reliability-related investments qualify for incentive-based ROEs.85 Furthermore, Southern Companies request the Commission to clarify that a single incentive-based ROE should apply to all, not just new, transmission investment.86 53. TDU Systems contend that the Commission should reconsider its commitment to grant incentive applicants an ROE at the upper end of the zone of reasonableness. Specifically, TDU Systems claim that the Commission may have difficulty handling all the rate filings that seek extremely high ROEs because of the two-stage process. They contend that 1161 the Commission is placing too much reliance on its ability to protect consumer interests in the second stage, section 205 review, and recommends that the Commission relieve some of the pressures by giving incentive applicants a more specific message that the incentives have limits.87 APPA/NRECA also assert that the Commission has not explained why such an increase in allowed ROEs is, or could be, either necessary to attract capital or otherwise just and reasonable and that the rule does not balance investor and consumer interests in setting incentive ROEs.88 Accordingly, these parties assert that the Commission should permit incentives only if the package as a whole results in a just and reasonable rate. In so doing, they argue, the Commission should disavow any intent to allow ROEs near the top of the zone of reasonableness and ensure that companies in the proxy group with ROEs at the top of the zone of reasonableness do not become the basis for determining the zone, particularly to the extent incentive ROEs become the base case in future DCF analyses. 54. Similarly, TAPS argues that the Commission must be prepared to apply a much stricter scrutiny to the composition of the proxy group that determines the range of the zone of reasonableness to the extent the Commission continues to declare in favor of rates set at the top of a range that has not yet been established.89 Also, TAPS recommends that the Commission modify its methodology for proxy results by first averaging the two results per proxy company so that there is one, average result per proxy company, as it does in gas cases,90 thereby providing a more defensible basis for just and reasonable returns. TAPS requests the Commission to clarify that it will ensure that the top of the range does not become a self87 TDU Systems at 27–29. 81 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. Id. P 92. 82 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 94. 83 Id. 84 EEI at 11; Southern Companies at 3. 85 Southern Companies at 4. 86 86 Southern Companies argue that section 219(b)(2) should be read to require the Commission to re-examine its ratemaking methods and revise it current ROE policies for all transmission investment, and that the base ROE must be sufficient to attract new investment. It contends that Congress did not state that the Commission shall provide a return on equity for new investment in transmission. Instead, section 219(b)(2) states that the Commission shall ‘‘provide a return on equity that attracts new investment in transmission.’’ See Id. at 5 (emphasis provided by commenter). PO 00000 Frm 00027 Fmt 4700 Sfmt 4700 88 APPA/NRECA at 9, 47. 89 TAPS explains that many transmission owners will request rates at the high end of the zone of reasonableness and that the main restraint on transmission rates will be the ceiling that is set by the placement of the top of the zone of reasonableness. The zone has been defined by taking a sample group that includes a large number of proxy companies and calculating two data points per proxy. Each pair of points represents the extreme values for each company. The zone of reasonableness is often characterized as reaching up to the higher data point for the most extreme company in the proxy set. Thus, when the top of the range sets the return, it becomes critical to ensure that every company included in the proxy group very closely resembles the utility whose return is being capped, i.e., its capital structure, business risk, financial risk, and associated capital costs. See TAPS at 18–22. 90 Id. at 21, citing High Island Offshore System, L.L.C., 110 FERC ¶ 61,043, at P 148 (2005). E:\FR\FM\10JAR1.SGM 10JAR1 1162 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations escalating spiral with the highest proxy result reflecting an investor expectation that the proxy itself will garner abovecost incentive profits.91 55. Southern Companies consider the Commission’s continued reliance on DCF analysis in the Final Rule to be contrary to Congressional intent and policy.92 Accordingly, Southern Companies request the Commission to clarify that it will allow the use of additional ROE estimation methodologies 93 because these methodologies will better ensure that an entity is ensured a reasonable rate of return. Southern Companies assert that failure to consider the results of more than one methodology, although there are other sound methods, constitutes arbitrary and capricious decision making.94 Furthermore, Southern Companies consider the Final Rule’s refusal to recognize the flaws in the current DCF analysis to be arbitrary and capricious and its finding that the DCF analysis yields just and reasonable results to be in error, particularly in light of the fact that the DCF analysis drives a utility’s stock price to its book value while market values exceed book values by approximately 2.47 to 1 as of December 31, 2005 and the constantgrowth DCF model often produces divergent and meaningless results.95 56. Southern Companies also argue that ROE adders should be provided to all new transmission construction. They assert that section 219 directs the Commission to promote investment of all facilities and therefore the Commission’s determination in the Final Rule that it will not create specific ROE adders is contrary to EPAct 2005 and requiring applicants to go through a rate case prior to receiving any incentives would unnecessarily impede Congress’ stated goal of encouraging new transmission investment.96 57. The California Commission claims that the Commission did not engage in reasoned decision making in the Final Rule because it failed to consider risk mstockstill on PROD1PC61 with RULES 91 Id. at 22. 92 According to Southern Companies, section 219’s requirement that the Commission provide ROEs that are sufficient to attract new transmission investment is evidence of Congress’ conclusion that the Commission’s current ROE methodology is not producing adequate results. Therefore, the Commission should construe section 219(b)(2) as a mandate from Congress to re-examine its traditional ratemaking policies. Southern Companies at 5–6. 93 Such methodologies include the risk premium approach, the capital asset pricing model and the comparable earnings approach. Id. at 7. 94 They state that using multiple methodologies recognizes that no single approach can accurately predict an appropriate ROE level so as to satisfy the constitutional and statutory requirements. Id. at 8. 95 Id. at 11. 96 Id. at 18. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 assessment and did not address its arguments about the relative low risk of transmission investment.97 It argues that the Commission failed to explain why transmission entities should be eligible for a higher ROE given the low risk associated with transmission investments. The California Commission states that transmission businesses have a low financial risk because they generate a steady revenue stream as a regulated monopoly. Also, among the three functions of an integrated utility’s electricity business, i.e. generation, distribution, and transmission, the transmission business carries the lowest risk.98 Further, the California Commission argues that the Commission did not consider the effect the multiple incentives created by the Final Rule will have on lowering the risk, such as 100 percent recovery of CWIP before a transmission project is used and useful. Accordingly, it contends that above-average ROEs for transmission are not needed to effect new transmission facilities.99 58. New England Commissions argue that the Commission arbitrarily, capriciously, and without a reasonable factual foundation, determined that ROE incentives encourage investment and make transmission projects attractive.100 They state that the New England ROE proceeding in Bangor Hydro-Electric 101 demonstrated that an enhanced ROE will not change transmission owners’ performance in any material respect, but will merely give them an unjust and unreasonable windfall. Accordingly, New England Commissions assert that the Commission’s finding that transmission incentives are necessary is not supported by the record in this rulemaking or in the Bangor HydroElectric proceeding.102 According to the New England Commissions, it is contrary to the directive in section 219(d) that rates be just and reasonable to dispense with any showing of need before awarding ROE incentives.103 New England Commissions requests the Commission to clarify that it will judge the justness and reasonableness of ROE adders in New England based on the record in Bangor Hydro-Electric proceeding and specify in the rule that only a case-by-case evaluation can 97 California Commission at 7–10. 98 Id. at 8. 99 The California Commission states that even without the high ROE incentive, California IOUs have planned and constructed numerous transmission facilities in the last 10 years. Id. at 9. 100 New England Commissions at 5. 101 Bangor Hydro-Electric Co., 106 FERC ¶ 61,280 (2004). 102 New England Commissions at 6–10. 103 Id. at 12. PO 00000 Frm 00028 Fmt 4700 Sfmt 4700 determine whether an ROE incentive will produce justifiable benefits. 2. Commission Determination 59. We will grant rehearing and clarification in part on certain issues and deny rehearing on all other issues. 60. We reject the argument of investor-owned utilities that ROE incentives be applied without regard to the nature of the facility being constructed or the risks associated with it. Specifically, the Commission reaffirms that the most compelling case for incentive ROEs are new projects that present special risks or challenges, not routine investments made in the ordinary course. We therefore reject the arguments of EEI and Southern Companies that such routine investments should be treated the same, for purposes of applying the nexus test, as new projects that present special risks or challenges. Although we will consider applications for ROE incentives for all projects, we reiterate that not all projects will be able to meet the nexus requirement. EEI and Southern Companies have provided no compelling reason why a routine investment made in the ordinary course should, as a general matter, receive an incentive ROE. 61. We also reject the argument that incentive ROEs should apply to existing transmission rate base that has already been built. The purpose of section 219 is to attract investment in transmission. Southern Companies have not provided any evidence that higher ROEs for transmission rate base that has already been built are necessary to ensure reliability or to reduce congestion; nor have they shown why such ROEs are necessary to attract new investment in transmission. 62. We also reject the contentions of certain customer groups that incentive ROEs will ‘‘destabilize’’ the DCF methodology. First, as indicated above, all ROEs approved pursuant to section 219 will be within the range of reasonableness, as determined consistent with our precedents. Second, any incentive ROEs granted under 219 should have a minimal effect, if any, on the overall range of reasonableness derived from the appropriate proxy group. The DCF methodology uses proxy groups of entire companies, not individual transmission projects. In other words, the ‘‘cash flows’’ being measured in the DCF method are the cash flows of entire companies. These cash flows should not be significantly affected by an incentive return for any particular transmission project for one company within the proxy group. Moreover, to the extent there is any E:\FR\FM\10JAR1.SGM 10JAR1 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations mstockstill on PROD1PC61 with RULES small effect on the overall range of reasonableness, it will appropriately reflect the substantial risks associated with constructing new transmission, as discussed above.104 63. We also reject requests to cease our utilization of the DCF method. Inasmuch as the DCF method yields just and reasonable rates, as the Commission has recognized in numerous proceedings, we see no basis to require other methods for the evaluation of incentive applications. As we stated in the Final Rule, the Commission will consider on a case-by-case basis whether the application of the traditional DCF analysis should be modified.105 64. We also do not consider the process for approving incentive ROEs, i.e., setting a zone of reasonableness and a DCF analysis requirement, to be an unnecessary impediment to encouraging transmission investment. Generic adders, as recommended by Southern Companies, would still require the Commission to make a determination that the proposed ROEs are just and reasonable, and its findings would have to be based on reasoned decisionmaking. Therefore, the Commission necessarily would be required to establish a zone of reasonableness and a justification for the approved ROEs. 65. Responding to the California Commission, the Final Rule explained the basis for its decision to provide an incentive ROE, based on the need to attract investment in the context of longterm industry underinvestment and the need to re-evaluate the balance of investor and ratepayer interests, and therefore has provided the reasons for its decisions. The Commission is not, in this rule, setting the incentive ROE, but rather leaves that determination to future proceedings that will authorize a unique ROE appropriate to the facts and circumstances of each applicant. It is in those proceedings that the California Commission can raise its concerns regarding comparative returns within the energy industry and the specific characteristics of California utilities. However, we agree with the California 104 The Commission retains the discretion to adjust ROEs if we find that the results of a DCF analysis do not accurately reflect the risk of the applicant and its ability to attract capital. 105 We agree with TAPS that averaging each company’s low and high DCF return would result in a single average DCF result for each electric company, making it like the single DCF return for gas and oil pipelines, from which a median return on equity for the group can be calculated. While this is an acceptable method, we will not require use of that method in the Commission’s DCF analysis because that issue is beyond the scope of this proceeding and is more appropriately addressed in the individual application proceedings. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 Commission that utilities should consider the effect that certain incentives (e.g. CWIP in rate base, recovery of abandoned plant) may have on risk and that return on equity in the upper end of the zone of reasonableness may not be appropriate when combined with incentive rate treatments that lower overall risk. 66. We do not address the issues raised by New England Commission with respect to the Bangor HydroElectric proceeding because they have been addressed in a recent Commission order and are now pending on rehearing.106 67. We will, however, grant clarification in part. Several petitioners express the fear that the Commission will routinely grant ROEs at the top end of the zone of reasonableness. Although the Commission has broad discretion to establish returns on equity anywhere within the zone of reasonableness, we must be careful in the manner in which we exercise this discretion. The Commission clarifies that we do not intend to grant incentive returns ‘‘routinely’’ or that, when granted, they will always be at the ‘‘top’’ of the zone of reasonableness. Rather, each applicant will, first, be required to justify a higher ROE under the revised nexus test and, second, to justify where in the zone of reasonableness that return should lie. In some instances, where the risks or challenges faced by a new investment are substantial, we may grant an ROE at the top end of the zone of reasonableness. However, we have no expectation of doing so in all cases or even routinely. 68. We also provide clarification on the timing of an ROE determination. In most instances, an ROE determination occurs in a hearing that considers the justness and reasonableness of the costs of the investment for purposes of setting rates under section 205. In that hearing, the overall range of reasonableness would be established, as well as a determination of where within that range the ROE should be set. If the Commission granted a request for an incentive ROE at the upper end of that range in a petition for declaratory order, the hearing would establish where in the upper end the ROE would fall— whether at the top end or at a different point in the upper end of the range. The Commission would then review any determination by an administrative law judge on that issue. 69. We recognize, however, that our hearing procedures for determining ROE can create uncertainty for investors. 106 Bangor Hydro-Electric Co., Opinion No. 489, 117 FERC ¶ 61,129 (2006). PO 00000 Frm 00029 Fmt 4700 Sfmt 4700 1163 Under traditional ratemaking processes, the rates for a particular project, including the ROE for that project, are determined only after an investment decision is made and the facility is constructed. This may provide a disincentive to new investments that are sensitive to our ROE determinations. Although our processes are designed to provide a just and reasonable return, we recognize that there can be significant uncertainty as to the ultimate return because of the uncertainties associated with administrative determinations (e.g., selection of the proxy group, changes in growth rates, etc.) This can itself constitute a substantial disincentive to new investment. 70. Recognizing this, we will clarify the approach adopted in the Final Rule. We will continue to allow applicants to request, in a petition for declaratory order, an ROE that is at the upper end of the zone of reasonableness and, in such instances, the ultimate ROE will be determined in the hearing process. However, if an applicant desires upfront certainty of the ROE it will receive, we clarify that we also will consider requests for declaratory orders that set the ROE for a particular project, and that include the appropriate support for the ROE, including, for example, a DCF analysis. An applicant seeking to use this process will have to meet the required nexus requirement, such as by showing that an up-front ROE determination is important for its investment decision. An applicant seeking such an up-front ROE determination also may request an ROE at the upper end of the zone of reasonableness; however, the fact that an up-front ROE determination is itself an incentive that tends to reduce risk will be taken into account in considering any such request. G. Incentives Available to Transcos 71. In the Final Rule, the Commission approved incentive-based rate treatments applicable to Transcos to encourage Transco formation and attract investment.107 Specifically, the Commission approved an ROE that encourages Transco formation and is sufficient to attract investment and an adjustment to book value of transmission assets being sold to a Transco to remove the disincentive associated with the impact of accelerated depreciation on federal 107 Section 35.35(b)(1) defines Transcos as standalone transmission companies approved by the Commission that sell transmission services at wholesale and/or on an unbundled retail basis, regardless of whether they are affiliated with another public utility. E:\FR\FM\10JAR1.SGM 10JAR1 1164 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations capital gains tax liabilities.108 The Commission noted that its decision to approve such incentives for Transcos is based on the ‘‘proven and encouraging track record of Transco investment’’ in transmission facilities.109 mstockstill on PROD1PC61 with RULES 1. Rehearing Requests 72. EEI argues that applicants seeking transmission incentives should be treated equally, without regard to their form of business. It argues that the incentives applicable to stand-alone transmission companies should be expanded to apply to all transmitting utilities.110 EEI also urges the Commission to recognize that all forms of transmission business models can effectively provide transmission facilities and to reiterate that it will evaluate each applicant’s proposed incentives, in particular the upper range of reasonable ROEs, without regard to the applicant’s form of business and without bias as between forms of business.111 73. Southern Companies contend that additional incentives for Transcos are not justified on grounds that the Transcos have a good record of transmission investment.112 They state that vertically-integrated utilities like Southern Companies have consistently invested significantly in transmission maintenance and expansion. Southern Companies also claim that special ROE incentives solely for Transcos would be discriminatory by favoring one corporate structure over another to the extent both business structures have similar transmission investment records 113 and the requirements of section 219 to promote investment regardless of the ownership of the facilities. 74. APPA/NRECA assert that because the Commission’s definition of Transcos includes affiliated Transcos under the control of one or more parent public utilities, granting incentive rate treatment greater than that afforded to 108 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 222–224. The incentive ROE does not preclude a Transco from applying for other incentives, including hypothetical capital structure, allowance for deferred income taxes (ADIT), acquisition premiums, formula rates or deferred cost recovery. Id. P 221. 109 See id. P 221–23. 110 EEI at 5, 7–9. 111 Id. at 5. EEI claims that section 219(b) provides that the rule shall promote transmission investment ‘‘regardless of the ownership of facilities’’ and the Commission noted in the Final Rule that it will not limit incentives based on corporate structure or ownership. Id. at 7, citing Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 4, 225. 112 Southern Companies at 16–17. 113 Id. at 17, citing Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 225. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 public utilities would constitute a financial windfall.114 They argue that such affiliated Transcos should not be eligible for special incentive rate treatment because such a payment would neither induce new construction nor provide any new benefit to the customer paying the incentive rate.115 75. Furthermore, TDU Systems oppose passive ownership interests in Transcos and contend that, if authorized, passive ownership interests should only be authorized upon a showing that the option of investment in the Transco is open to all loadserving entities (LSEs) in the region up to their load ratio shares.116 They also argue that the Commission must rigorously scrutinize and monitor relationships among the passive owners to deter the potential for abuse. TDU Systems also contend that the Commission should clarify that Transcos may only receive incentive rates if there are no interests within the Transco competing with transmission for capital. They recommend that the Commission condition the granting of incentives by imposing limits on business investments in other industries to avoid the dilution of capital funding from competing sources within the company.117 They also claim that incentives for new investment in transmission infrastructure should not be necessary because, as the Commission noted in the Final Rule, such incentives are inherent in the corporate business model to encourage investment.118 Therefore, encouraging additional incentives provides no incremental benefit to consumers.119 2. Commission Determination 76. We affirm the finding in the Final Rule that the Commission will not limit an applicant’s ability to seek incentivebased rate treatments based on corporate structure or ownership.120 The Commission will evaluate these 114 APPA/NRECA at 31, 34–35. In the Final Rule, the Commission stated that the definition of Transco does not exclude affiliated Transcos with active ownership by market participants, or standalone transmission companies that own transmission and distribution facilities. The Commission said that it would consider the eligibility of such arrangements based on a showing of how the specific characteristics of a proposed Transco affect its ability and propensity to increase transmission investment and lead to increased transmission investment similar to Transcos the Commission already approved. See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 202. 115 APPA/NRECA at 31. 116 TDU Systems at 39. 117 Id. at 40. 118 See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 204. 119 TDU Systems at 41. 120 See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 4. PO 00000 Frm 00030 Fmt 4700 Sfmt 4700 applications to determine if incentive treatment is justified based on their demonstrations that the projects meet the requirements of section 219 and this rule. Certain types of incentives, such as the ADIT incentive may be more appropriate where transmission is being spun off or otherwise transferred to a new corporate entity, such as a Transco. But we see no basis for the claim that the Transco incentives are unduly discriminatory or contrary to the goals of section 219. 77. The Final Rule described at great length the very significant transmission investment that has been undertaken by Transcos, to date.121 There is no reason to repeat those examples again here, but we disagree with comments that suggest that Transcos do not have a good record of transmission investment. Furthermore, their singular focus on transmission investment by transmission-only companies, the elimination of competition for capital between generation and transmission investments, and the access to capital markets have all been cited in support of the value of the Transco business model for getting new transmission built. For all of these reasons, the Commission adopted incentive-based rate treatments applicable to Transcos that would both encourage Transco formation and attract investment. 78. As we stated in the Final Rule, the Commission will consider concerns regarding affiliated Transcos in specific applications for incentive treatment.122 We believe the Final Rule fulfills the requirements of section 219 by determining eligibility for Transco status and incentive-based rate treatment based on a showing of how the specific characteristics of a proposed Transco affect its ability and propensity to increase transmission investment in individual case proceedings. Therefore, we do not consider this proceeding to be the appropriate forum for adopting preconditions related to other issues, such as affiliation or passive ownership. Inasmuch as Transcos are subject to the Commission’s market behavior rules, their activities will be monitored for any potential market abuse. Therefore, we affirm the availability of ROE incentives to Transcos. As stated in the Final Rule, we expect that the incentive ROE will be used for additional capital spending, and thereby provide consumer benefits, as demonstrated by the negative cash flow profiles of Transcos and their future capital spending plans. 121 Id. P 222–23. 122 See id. P 202. E:\FR\FM\10JAR1.SGM 10JAR1 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations H. Transmission Organization Incentive 79. In the Final Rule, the Commission stated that it will authorize, when justified, an incentive-based rate treatment for public utilities that join and/or continue to be a member of an ISO, RTO, or other Commissionapproved Transmission Organization.123 Applicants for the incentive-based rate treatment must make a filing with the Commission under section 205 of the FPA. For purposes of section 35.35(e), an incentive-based rate treatment means an ROE that is higher than the ROE the Commission might otherwise allow if the public utility were not a member of a Commission-approved Transmission Organization. The Commission stated that it will not create a generic adder for such membership, but instead will consider appropriate ROE incentives on a case-by-case basis. The Commission also stated that transmitting utilities or electric utilities that join a Transmission Organization would be eligible to apply to recover prudently-incurred costs associated with joining the Transmission Organization, either through rates charged by transmitting utilities or electric utilities or through transmission rates charged by the Transmission Organization that provides services to such utilities.124 Furthermore, the Commission stated that based on its interpretation of section 219, eligibility for this incentive flows to an entity that ‘‘joins’’ a Transmission Organization and is not tied to when the entity joined. Therefore, the Commission clarified that entities that have already joined, and that remain members of, an RTO, ISO, or other Commission-approved Transmission Organization, are eligible to receive this incentive.125 However, as the Commission noted, any public utility receiving an incentive ROE for joining a Transmission Organization but withdraws from such organization is no longer eligible for the ROE incentive. 1. Rehearing Requests mstockstill on PROD1PC61 with RULES 80. Petitioners contend that public utilities should not be eligible for the Transmission Organization incentive if the public utilities are already members because the payment would neither induce new construction nor provide any new benefit to the customer paying 123 Id. P 326. Transmission Organization is defined 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.’’ Id. P 328. 124 Id. P 329. 125 Id. P 331. VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 the incentive rate.126 They argue that the Final Rule’s determination that incentives may go to entities that are already members of a Transmission Organization is contrary to court and Commission precedent interpreting incentive rates as forward-looking inducements, not a reward for past behavior.127 The California Commission claims that the Final Rule’s interpretation of section 219 exceeds the Commission’s authority by creating an incentive that is broader than specified in the FPA.128 Furthermore, TDU Systems assert that many public utilities have already joined ISO or RTOs without ROE incentives and have benefited from such membership. Those public utilities that have not joined have chosen not to do so because their business interests would not be advanced by a reduction in transmission barriers and constraints. Therefore, they argue that ‘‘recalcitrant utilities’’ should not be awarded windfall profits for holding out on participating in Transmission Organizations because such action would only amount to rewarding the exercise of market power.129 81. Furthermore, the California Commission states that an incentive for utilities that have already joined a Transmission Organization and are planning to build transmission facilities provides no balancing of the consumer interests and represents an unjust windfall.130 By continuing its membership in an ISO/RTO, a transmission company will not incur any additional risks and will still remain a monopoly. The California Commission and TDU Systems argue that the Commission did not provide any evidence that current RTO/ISO members may leave a Transmission Organization without the incentive of higher ROEs and therefore such a conclusion constitutes unreasonable, unlawful decision making.131 APPA/ 126 TDU Systems at 43; APPA/NRECA at 31–32, citing Southern California Edison Company, 114 FERC ¶ 61,018, at P 16 (2005) (‘‘The rationale for this incentive is to encourage transmission owners to turn over the operational control of their transmission facilities to a regional transmission organization; therefore, it does not apply to transmission owners who have already done so, as they need no inducement to take such action’’) (Southern California Edison). 127 E.g., APPA/NRECA at 32; SMUD at 3–7; TDU Systems at 43. The California Commission argues that the courts have not permitted ROE adders for past conduct. California Commission at 18–19, citing Maine PUC v. FERC, 454 F.3d 278 (2006) and Allegheny Power Systems Operating Co., 111 FERC ¶ 61,308 (2005). 128 California Commission at 14–15. 129 TDU Systems at 42. 130 California Commission at 16. 131 Id. P 17–18; TDU Systems at 43. PO 00000 Frm 00031 Fmt 4700 Sfmt 4700 1165 NRECA assert that if a member leaves the Transmission Organization, the Commission can simply deny that utility a rate incentive.132 Further, SMUD notes that there is no assurance that members will be permitted to leave since such a decision is subject to Commission review, and expresses concern that extending incentives to existing members of a Transmission Organization for not leaving may discourage parties legitimately dissatisfied with the Transmission Organization’s performance and thereby make these organizations less accountable.133 Finally, APPA/NRECA argue that the Commission’s statement that it would be unduly discriminatory not to award all members of a Transmission Organization an incentive ROE has no basis because nothing in the FPA forbids different rates if these arrangements are necessary to carry out the provisions of the FPA and to serve the regulatory purposes contemplated by Congress.134 82. TDU Systems request clarification that the Commission will not consider single company entities as Transmission Organizations. They state that to ensure new transmission investment serves regional markets, a ‘‘collaborative [and] open regional planning process’’ is necessary. Therefore, TDU Systems claim that only entities that provide for, or participate in, regional planning that spans a number of public utility transmission systems should be eligible for incentives.135 83. TDU Systems recommend a reduction, i.e. negative 50 basis point penalty, in the authorized ROE for public utilities that withdraw from Transmission Organizations within the first five to ten years of participation to recognize the costs paid by consumers in anticipation of long-term savings. TDU Systems also argue that the incentive should not be allowed for public utilities ordered to join Transmission Organizations by statute, merger conditions or other regulatory requirements because there is no nexus between the incentive rates and demonstrated consumer benefits.136 Finally, SMUD argues that the Final Rule offered no explanation for providing an incentive for utilities that are required to join Transmission Organizations as a merger condition.137 132 APPA/NRECA assert that the Commission rejected such a remedy without a reasoned explanation in the Final Rule. APPA/NRECA at 32. 133 SMUD at 3–7. 134 APPA/NRECA at 33. 135 TDU Systems at 41–42. 136 Id. at 42–43. 137 SMUD at 7. E:\FR\FM\10JAR1.SGM 10JAR1 1166 Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations 84. MISO TOs state that the Final Rule was unclear on the mechanics of requesting incentives by RTO members and request clarification that transmission owners may seek this incentive without opening up a Commission-accepted ROE or additional rates or formulas.138 Specifically, they state that the Commission did not clarify that such a single-issue filing will not open up the already Commission-accepted ROE. 85. Finally, APPA/NRECA argues that the Final Rule does not comply with section 219(c) to provide incentives to each transmitting utility or electric utility that joins a Transmission Organization because it disregards incentives to non-jurisdictional utilities.139 The Commission reasoning that it does not have jurisdiction to provide incentives for non-public utilities joining Transmission Organizations is unjustified when it has asserted jurisdiction in other proceedings.140 APPA/NRECA recommend the Commission to consider incentives for non-public utilities such as assurances that these entities will fully recover all their costs of joining and participating in the Transmission Organization. 2. Commission Determination 86. We affirm the finding in the Final Rule that the incentive applies to all utilities joining transmission organizations, irrespective of the date they join, based on a reading of section 219 in its entirety. Section 219 specifically provides that ‘‘the Commission shall * * * provide for incentives to each transmitting utility or electric utility that joins a Transmission Organization.’’ The stated purpose of section 219 is to provide incentivebased rate treatments that benefit consumers by ensuring reliability and reducing the cost of delivered power. We consider an inducement for utilities to join, and remain in, Transmission Organizations to be entirely consistent with those purposes. The consumer benefits, including reliability and cost benefits, provided by Transmission Organizations are well documented,141 138 MISO TOs at 2–3. mstockstill on PROD1PC61 with RULES 139 APPA/NRECA at 53–54. 140 Id. P 54, citing City of Vernon, California and CAISO, Opinion No. 479, 111 FERC ¶ 61,092, reh’g granted in part and denied in part, 112 FERC ¶ 61,207 (2005), reh’g denied, 115 FERC ¶ 61,297 (2006). 141 In Order No. 2000, in which the Commission’s goal was to promote efficiency in wholesale electricity markets and to ensure that electricity consumers pay the lowest price possible for reliable service, the Commission stated that: These benefits [of RTOs] will include: Increased efficiency through regional transmission pricing VerDate Aug<31>2005 14:45 Jan 09, 2007 Jkt 211001 and the best way to ensure those benefits are spread to as many consumers as possible is to provide an incentive that is widely available to member utilities of Transmission Organizations and is effective for the entire duration of a utility’s membership in the Transmission Organization. To limit the incentive to only utilities yet to join Transmission Organizations offers no inducement to stay in these organizations for members with the option to withdraw, and hence risks reducing Transmission Organization membership and its attendant benefits to consumers. Because the incentive is applicable to utilities that join Transmission Organizations and is consistent with the requirements of section 219 of the FPA, the incentive complies with EPAct 2005 and the FPA.142 87. We consider the claim of APPA/ NRECA that the incentive is inappropriate because it does not induce construction to be misplaced. Section 219(c), applicable to the Transmission Organization incentive, is separate from the construction incentives in subsection (b), and therefore was not intended to directly encourage construction.143 However, we note that regional transmission organizations provide a platform for regional planning and cost allocation associated with transmission expansion and planning 144 and therefore can help and the elimination of rate pancaking; improved congestion management; more accurate estimates of ATC; more effective management of parallel path flows; more efficient planning for transmission and generation investments; increased coordination among state regulatory agencies; reduced transaction costs; facilitation of the success of state retail access programs; facilitation of the development of environmentally preferred generation in states with retail access programs; improved grid reliability; and fewer opportunities for discriminatory transmission practices. All of these improvements to the efficiencies in the transmission grid will help improve power market performance, which will ultimately result in lower prices to the Nation’s electricity consumers. Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,024. 142 In light of our determination here, we reverse the policy adopted in our decision in Southern California Edison. Our decision in Southern California Edison failed to recognize that incentives are equally important in inducing utilities to join and remain in Transmission Organizations. Southern California Edison Co., 114 FERC ¶ 61,018, at P 16 (2005). 143 We note that a more accurate interpretation of section 219(c) must recognize that an important component of section 219(c) is ensuring cost recovery, and therefore this section differs from the rest of section 219 that only address incentive-based rate treatments. We note that the Midwest ISO tariff provisions governing pass-through of transmission costs are consistent with this section, and this section would provide the basis for approval of pass-through of costs in other ISOs. 144 PJM Interconnection, L.L.C., 117 FERC ¶ 61,218 (2006); Midwest Independent PO 00000 Frm 00032 Fmt 4700 Sfmt 4700 support the identification and construction of transmission needed to ensure reliability and to reduce congestion. 88. We will not specify a particular method for establishing the appropriate ROE for entities that join and/or continue to be a member of an ISO, RTO, or other Commission-approved Transmission Organization in this generic proceeding. For example, the mechanics of setting an incentive ROE is an issue best addressed in a proceeding evaluating the Transmission Organization incentive for transmission owners that belong to the particular Transmission Organization. We recognize that the issue was remanded to the Commission with respect to Midwest ISO.145 In t [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/agency%3Aferc%3A479dac448d4af171. Public record. Not legal advice.