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Transactions Subject to FPA Section 203

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Start Preamble Start Printed Page 1348 Issued December 23, 2005.

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Final rule.

SUMMARY:

Under Subtitle G (Market Transparency, Enforcement, and Consumer Protection), section 1289 (Merger Review Reform), of Title XII (Electricity Modernization Act of 2005), of the Energy Policy Act of 2005 (EPAct 2005), Public Law 109-58, 119 Stat. 594 (2005), the Federal Energy Regulatory Commission (Commission) amends 18 CFR 2.26 and 18 CFR part 33 to implement amended section 203 of the Federal Power Act (FPA).[1]

DATES:

Effective Date: This Final Rule will become effective on February 8, 2006.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Sarah McWane (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-8372.

Phillip Nicholson (Technical Information), Office of Markets, Tariffs and Rates—West, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC, 20426. (202) 502-8240.

Jan Macpherson (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-8921.

James Akers (Technical Information), Office of Markets, Tariffs and Rates—West, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-8101.

End Further Info End Preamble Start Supplemental Information

SUPLEMENTARY INFORMATION:

Table of Contents

Paragraph Nos.
I. Introduction1.
II. Background5.
A. Commission Merger Policy Before Effective Date of Amended FPA Section 2035.
B. Section 203 As Amended By EPAct 200515.
C. Notice of Proposed Rulemaking on Transactions Subject to FPA Section 20325.
III. Discussion27.
A. Amendments to 18 CFR Part 3327.
1. Section 33.1(a)—Applicability28.
2. Section 33.1(b)—Definitions of “Associate Company,” “Holding Company,” “Holding Company System,” “Transmitting Utility,” and “Electric Utility Company”33.
3. Section 33.1(b)—Definition of “Existing Generation Facility”74.
4. Section 33.1(b)—Definition of “Non-Utility Associate Company”88.
5. Section 33.1(b)—Definition of “Value”94.
6. Compliance with Section 203127.
7. Cash Management Arrangements, Intra-Holding Company System Financing, Securities Under Amended Section 203, and Blanket Authorizations133.
8. Section 33.2(j)—General Information Requirements Regarding Cross-Subsidization146.
9. Section 33.11—Commission Procedures for Consideration of Applications under Section 203 of the FPA172.
B. Amendments to 18 CFR 2.26—The Merger Policy Statement195.
1. Comments198.
2. Commission Determination202.
IV. Information Collection Statement203.
V. Environmental Analysis207.
VI. Regulatory Flexibility Act Certification208.
VII. Document Availability210.
VIII. Effective Date and Congressional Notification213.

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

I. Introduction

1. On August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005) [2] was signed into law. Section 1289 (Merger Review Reform) of Title XII, Subtitle G (Market Transparency, Enforcement, and Consumer Protection),[3] of EPAct 2005 amends section 203 of the Federal Power Act (FPA).[4] Amended section 203: (1) Increases (from $50,000 to greater than $10 million) the value threshold for certain transactions being subject to section 203; (2) extends the scope of section 203 to include transactions involving certain transfers of generation facilities and certain holding companies' transactions with a value in excess of $10 million; (3) limits the Federal Energy Regulatory Commission's (Commission) review of a public utility's acquisition of securities of another public utility to transactions greater than $10 million; (4) requires that the Commission, when reviewing proposed section 203 transactions, examine cross-subsidization and pledges or encumbrances of utility assets; and (5) directs the Commission to adopt, by rule, procedures for the expeditious consideration of applications for the approval of dispositions, consolidations, or acquisitions under section 203.

2. As discussed below, on October 3, 2005, the Commission issued a notice of proposed rulemaking (NOPR) in which it proposed certain modifications to 18 CFR 2.26 and 18 CFR part 33 to implement amended section 203.[5] Numerous comments were filed by a variety of entities.

3. In this Final Rule, the Commission adopts some of the proposals in the Start Printed Page 1349NOPR as well as many of the commenters' recommendations. Specifically, this Final Rule:

(1) Implements the new applicability of amended section 203 of the FPA;

(2) Grants blanket authorizations for certain types of transactions, including foreign utility acquisitions by holding companies, intra-holding company system financing and cash management arrangements, certain internal corporate reorganizations, and certain investments in transmitting utilities and electric utility companies;

(3) Adopts many of the NOPR's proposed defined terms, including “electric utility company,” “holding company,” and “non-utility associate company,” but clarifies the application of these terms to certain entities;

(4) Amends the proposed definition of “existing generation facility;'

(5) Adopts a simpler rule than was proposed in the NOPR with respect to the determination of “value” as it applies to various section 203 transactions;

(6) Clarifies and refines the NOPR's proposal with respect to a section 203 applicant's obligation to file evidentiary support to demonstrate that a proposed transaction will not result in cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company; and

(7) Adopts the NOPR's proposal that the Commission provide expeditious consideration of completed applications for the approval of transactions that are not contested, do not involve mergers, and are consistent with Commission precedent.

4. Our goal is to carry out the expanded authorities and requirements contained in the new section 203 amendments to ensure that all jurisdictional transactions subject to section 203 are consistent with the public interest and at the same time ensure that our rules do not impede day-to-day business transactions or stifle timely investment in transmission and generation infrastructure. We believe we have accomplished this result with the rules herein. However, at the technical conference we announced in our final rule implementing the Public Utility Holding Company Act of 2005 (PUHCA 2005),[6] to be held within the next year,[7] we will also address issues raised in this proceeding, including the appropriateness of the blanket authorizations granted herein and whether additional steps are needed to protect against cross-subsidization and pledges or encumbrance of utility assets.

II. Background

A. Commission Merger Policy Before Effective Date of Amended FPA Section 203

5. Section 203 of the FPA [8] currently provides that: No public utility shall sell, lease or otherwise dispose of the whole of its facilities subject to the jurisdiction of the Commission, or any part thereof of a value in excess of $50,000, or by any means whatsoever, directly or indirectly, merge or consolidate such facilities or any part thereof with those of any other person, or purchase, acquire, or take any security of any other public utility, without first having secured an order of the Commission authorizing it to do so.

The Commission shall approve such transactions if they are “consistent with the public interest.”

6. In 1996, the Commission issued the Merger Policy Statement [9] updating and clarifying the Commission's procedures, criteria, and policies concerning public utility mergers. The purpose of the Merger Policy Statement was to ensure that mergers are consistent with the public interest and to provide greater certainty and expedition in the Commission's analysis of merger applications.

7. The Merger Policy Statement sets out three factors the Commission generally considers when analyzing whether a proposed section 203 transaction [10] is consistent with the public interest: Effect on competition; effect on rates; and effect on regulation.

8. With respect to the first factor, the effect on competition, the Merger Policy Statement adopts the Department of Justice (DOJ)/Federal Trade Commission (FTC) 1992 Horizontal Merger Guidelines (Guidelines) [11] as the analytical framework for examining horizontal market power concerns. The Merger Policy Statement also uses an analytical screen (Appendix A analysis) to allow early identification of transactions that clearly do not raise competitive concerns.[12] As part of the screen analysis, applicants must define the relevant products sold by the merging entities, identify the customers and potential suppliers in the geographic markets that are likely to be affected by the proposed transaction, and measure the concentration in those markets. Using the Delivered Price Test to identify alternative competing suppliers, the concentration of potential suppliers included in the defined market is then measured by the Herfindahl-Hirschman Index (HHI) and used as a screen to determine which transactions clearly do not raise market power concerns.

9. The Commission stated in the Merger Policy Statement that it will examine the second factor, the effect on rates, by focusing on customer protections designed to insulate consumers from any harm resulting from the transaction.[13]

10. The Merger Policy Statement set forth a third factor for examination, the effect on regulation. This includes both state regulation and the Commission's regulation, including any potential shift in regulation from the Commission to the Securities and Exchange Commission (SEC) due to a transaction creating a registered public utility holding company under the Public Utility Holding Company Act of 1935 (PUHCA 1935).[14] The Merger Policy Statement explained that, unless applicants commit themselves to abide by this Commission's policies with regard to affiliate transactions involving non-power goods and services, we will set the issue of the effect on regulation for hearing.[15]

Start Printed Page 1350

11. The Commission later issued the Filing Requirements Rule,[16] a final rule updating the filing requirements under 18 CFR part 33 of the Commission's regulations for section 203 applications. The Filing Requirements Rule implements the Merger Policy Statement and provides detailed guidance to applicants for preparing applications. The revised filing requirements also assist the Commission in determining whether section 203 transactions are consistent with the public interest, provide more certainty, and expedite the Commission's handling of such applications.

12. Further, the Filing Requirements Rule codified the Commission's screening approach, provided specific filing requirements consistent with Appendix A of the Commission's Merger Policy Statement, established guidelines for vertical competitive analysis, and set forth filing requirements for mergers that may raise vertical market power concerns.

13. The Filing Requirements Rule also reduced the information burden for transactions that clearly raise no competitive concerns. The Commission explained that for certain transactions, abbreviated filing requirements are appropriate because it is relatively easy to determine that they will not harm competition and, thus, a full-fledged horizontal screen analysis or vertical competitive analysis is not required.[17]

14. The Commission stated in the Filing Requirements Rule that it intended to continue processing section 203 applications expeditiously, with a goal of issuing an initial order for most mergers within 150 days of a completed application.[18] Further, the Commission stated that it intended to continue processing uncontested non-merger applications within 60 days of filing and protested non-merger applications within 90 days of filing.[19]

B. Section 203 as Amended by EPAct 2005

15. EPAct 2005 revises section 203(a) of the FPA as follows:

16. Amended section 203(a)(1) states that no public utility shall, without first having secured an order of the Commission authorizing it to do so: (A) Sell, lease, or otherwise dispose of the whole of its facilities subject to the jurisdiction of the Commission, or any part thereof of a value in excess of $10 million; (B) merge or consolidate, directly or indirectly, such facilities or any part thereof with those of any other person, by any means whatsoever; (C) purchase, acquire, or take any security with a value in excess of $10 million of any other public utility; or (D) purchase, lease, or otherwise acquire an existing generation facility: (i) That has a value in excess of $10 million; and (ii) that is used for interstate wholesale sales and over which the Commission has jurisdiction for ratemaking purposes.

17. Section 203(a)(2) adds the entirely new requirement that no holding company in a holding company system that includes a transmitting utility or an electric utility shall purchase, acquire, or take any security with a value in excess of $10 million of, or, by any means whatsoever, directly or indirectly, merge or consolidate with, a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility, or an electric utility company, with a value in excess of $10 million without prior Commission authorization.

18. Like the existing section 203(a), amended section 203(a)(3) provides that upon receipt of an application for such approval, the Commission shall give reasonable notice in writing to the Governor and state commission of each of the states in which the physical property affected is situated, and to such other persons as it may deem advisable.

19. Amended section 203(a)(4) states that after notice and opportunity for hearing, the Commission shall approve the proposed disposition, consolidation, acquisition, or change in control if it finds that the transaction will be consistent with the public interest. It also specifically provides that the Commission must find that the transaction will not result in cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company, unless that cross-subsidization, pledge, or encumbrance will be consistent with the public interest.

20. Section 203(a)(5) adds the entirely new requirement that the Commission shall: By rule, adopt procedures for the expeditious consideration of applications for the approval of dispositions, consolidations, or acquisitions, under this section. Such rules shall identify classes of transactions, or specify criteria for transactions, that normally meet the standards established in paragraph (4). The Commission shall provide expedited review for such transactions. The Commission shall grant or deny any other application for approval of a transaction not later than 180 days after the application is filed. If the Commission does not act within 180 days, such application shall be deemed granted unless the Commission finds, based on good cause, that further consideration is required to determine whether the proposed transaction meets the standards of paragraph (4) and issues an order tolling the time for acting on the application for not more than 180 days, at the end of which additional period the Commission shall grant or deny the application.

21. Section 203(a)(6), which is also new, provides that for purposes of this subsection, the terms “associate company,” “holding company,” and “holding company system” have the meaning given those terms in PUHCA 2005.

22. Section 1289(b) provides that the amendments made by this section shall take effect six months after the date of enactment of EPAct 2005, or February 8, 2006. This is the same date on which the repeal of PUHCA 1935 and enactment of the PUHCA 2005, are to take effect.[20]

23. Section 1289(c) provides that the amendments made by subsection (a) shall not apply to any section 203 application that was filed on or before the date of enactment of EPAct 2005.

24. Section 203(b) of the FPA remains unchanged.[21]

C. Notice of Proposed Rulemaking on Transactions Subject to FPA Section 203

25. On October 7, 2005, the Commission's NOPR on Transactions Subject to FPA Section 203 was published in the Federal Register.[22] As discussed in more detail below, in the Start Printed Page 1351NOPR the Commission proposed to revise 18 CFR part 33 and 18 CFR 2.26 of its rules to implement amended section 203 of the FPA. Comments were due on or before November 7, 2005.[23]

26. This Final Rule will be effective on the date on which amended section 203 of the FPA takes effect, February 8, 2006.

III. Discussion

A. Amendments to 18 CFR Part 33

27. In the NOPR, the Commission proposed to amend 18 CFR part 33 by: Revising the title to read “Applications Under Federal Power Act Section 203;” amending section 33.1(a) to clarify what transactions are subject to amended section 203 and part 33 as a result of amended sections 203(a)(1)(A)-(D) and (a)(2) of the FPA; adding a new subsection 33.1(b) that defines certain new terms used in amended section 203 that are not defined in EPAct 2005; adding a new subsection 33.2(j) to implement amended section 203(a)(4) regarding cross-subsidization and pledge or encumbrance issues; and adding new sections 33.11(a) and (b) to implement amended section 203(a)(5) regarding the Commission's procedures for the consideration of applications under section 203 of the FPA.

1. Section 33.1(a)—Applicability

28. Proposed section 33.1(a) clarifies what transactions are subject to amended section 203 and part 33 as a result of amended sections 203(a)(1)(A)-(D) and (a)(2) of the FPA.[24]

a. Comments

29. Several commenters raise concerns, described in more detail below, regarding the applicability of amended section 203 to transactions involving foreign utility companies (FUCOs), qualifying facilities (QFs), exempt wholesale generators (EWGs),[25] rural electric cooperatives, local distribution companies, stand-alone generation and retail sales, as well as intrastate transactions, i.e., transactions wholly within the Electric Reliability Council of Texas (ERCOT), Alaska, or Hawaii. They generally argue that Congress did not intend to expand significantly the Commission's jurisdiction under amended section 203 and, therefore, did not convey to the Commission jurisdiction over these types of transactions. Commenters also express concern over any potential overlap between the Commission's scope of review under amended section 203 and the scope of review by state commissions. They state that the Commission should not use its new section 203 authority to preempt state regulatory authority over rates and approvals of utility mergers and acquisitions.

30. Electric Power Supply Association (EPSA) requests that the Commission modify the text of proposed section 33.1(a)(1)(ii) to clarify that any merger or consolidation must exceed the $10 million threshold before section 203 filing approval is required. It states that the Commission should not alter its past practice of applying the statutory dollar threshold to all types of transactions requiring section 203 approval, including mergers and acquisitions. EPSA explains that the mergers and acquisitions clause of the currently effective section 203 and section 203 as amended by EPAct 2005 are substantially the same and do not specify a value amount. EPSA points out, however, that although the currently effective statutory language, like the newly enacted EPAct 2005 language, did not codify the monetary threshold with respect to mergers and consolidations, for decades the Commission's regulations (section 33.1(a)(2)) have required section 203 applications for mergers, consolidations and acquisitions only if they meet the $50,000 threshold (which on February 8, 2006 will become $10 million). EPSA states that the NOPR provides no reason for the Commission to change its interpretation of section 203.

b. Commission Determination

31. Most of the concerns regarding the applicability of amended section 203 involve new section 203(a)(2) and the Commission's proposed definitions of “electric utility company” and “holding company.” Accordingly, these comments are discussed in greater detail in those sections below. Similarly, concerns regarding any potential overlap between the scope of review of the Commission under amended section 203 and that of state commissions are also discussed with the proposed definition of “electric utility company,” below.

32. We reject EPSA's request that we revise proposed section 33.1(a)(1)(ii) to clarify that any merger or consolidation must also exceed a monetary threshold before section 203 filing approval is required. The plain language of amended section 203(a)(1)(B) does not permit such an interpretation. Under amended section 203(a)(1)(B): “No public utility shall * * * merge or consolidate, directly or indirectly, such facilities [facilities subject to the jurisdiction of the Commission] or any part thereof with those of any other person, by any means whatsoever.” This provision, on its face, does not impose a dollar threshold on mergers or consolidations and proposed section 33.1(a)(1)(ii) is consistent with the statutory provision. While Congress included a $10 million threshold for amended subsections 203(a)(1)(A), (C), (D), and 203(a)(2) (dispositions of jurisdictional facilities; acquisitions of securities of public utilities; purchases of existing generation facilities; holding company acquisitions), Congress clearly did not adopt a monetary threshold for mergers and consolidations in amended subsection 203(a)(1)(B). We note that “[w]here Congress includes particular language in one section of a statute but omits it in another section of the same Act, it is generally presumed that Congress acts intentionally and purposely in the disparate inclusion or exclusion.” [26] In light of the unambiguous statutory language, we are not convinced by EPSA's unsupported assertion that the failure to include a monetary threshold as to mergers and consolidations was an “oversight” and that “Congress did not intend to change [the currently effective] statutory and regulatory structure.” [27] While our regulations previously applied a dollar threshold to mergers and consolidations, such an approach is no longer tenable, since it is inconsistent with the plain language of amended section 203. Thus, we will not revise section 33.1(a)(1)(ii) to include a $10 million threshold.

2. Section 33.1(b)—Definitions of “Associate Company,” “Holding Company,” “Holding Company System,” “Transmitting Utility,” and “Electric Utility Company”

33. As noted above, section 203(a)(2) adds an entirely new requirement to the FPA:

No holding company in a holding company system that includes a transmitting utility or an electric utility shall purchase, acquire, or take any security with a value in excess of $10 million of, or, by any means whatsoever, directly or indirectly, merge or consolidate with, a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility, or an electric utility company, with a value in excess of $10 million without first Start Printed Page 1352having secured an order of the Commission authorizing it to do so.

a. Definition of “Electric Utility Company”

34. The scope of amended section 203(a)(2) turns in large part on the Commission's interpretation of the term “electric utility company” which, in turn, affects whether an entity is a holding company subject to section 203(a)(2). The FPA does not include a definition of “electric utility company” and the Commission proposed that the term, as used in amended section 203(a)(2), have the same meaning as in PUHCA 2005, which is “any company that owns or operates facilities used for the generation, transmission, or distribution of electric energy for sale.” [28]

i. Comments

35. The proposed definition of “electric utility company” was one of the most commented-on issues in the NOPR. While certain commenters, including the American Public Power Association and the National Rural Electric Cooperative Association (APPA/NRECA), Indiana Utility Regulatory Commission (Indiana Commission), and Southern Company Services, Inc. (Southern Companies), support the Commission's adoption of the PUHCA 2005 definition of “electric utility company,” several commenters expressed concerns about the scope of the Commission's jurisdiction under the proposed definition. Specifically, they object to the proposed definition of the term “electric utility company” or seek clarification as to what types of entities are considered “electric utility companies,” for purposes of amended section 203(a)(2), to determine whether or not they must seek section 203 approval.

36. Many commenters argue that Congress did not intend to give the Commission jurisdiction over acquisitions of foreign companies.[29] Certain commenters assert that if Congress had intended the PUHCA 2005 definition to apply to “electric utility company” as used in amended section 203(a)(2), it would have said so as it did for the other terms listed in amended section 203(a)(6). They explain that, while the term “electric utility” is used once in amended section 203(a)(2) and “electric utility company” is used twice, the terms should be read similarly and should not affect the interpretation of the section. Accordingly, commenters assert that it is reasonable to read the term “electric utility company,” not as used in PUHCA 2005, where the term includes foreign utility companies, but rather to have the same meaning as “electric utility,” which is defined in the FPA as “a person or Federal or State agency * * * that sells electric energy.” [30] They argue that the use of the term “electric utility” in the FPA and in the Public Utility Regulatory Policies Act of 1978 (PURPA) [31] makes clear that “electric utilities” are domestic entities (i.e., ones selling electricity in the U.S.), not foreign.[32]

37. Similarly, EEI, Entergy, E.ON, PNM, and Progress Energy maintain that, in order to be consistent with the Commission's FPA jurisdiction, the Commission should define an “electric utility company” as “a person that sells electric energy in interstate commerce.” Suez states that, based on an analysis of and the legislative purpose behind EPAct 2005, the Commission should exempt the acquisition of foreign utility assets by jurisdictional holding companies without captive customers by adding the word “jurisdictional” before “transmitting utility” and “electric utility company” at the end of proposed section 33.1(a)(2).

38. Other commenters add that the Commission did not have jurisdiction over foreign acquisitions before EPAct 2005 and that nothing in EPAct 2005 explicitly gives the Commission jurisdiction over foreign acquisitions. Commenters assert that Commission jurisdiction over foreign acquisitions is contrary to Congressional intent and poor public policy, because Commission review will become an impediment to U.S. investment in foreign entities and may discourage international investment in the U.S. utility industry.[33] They assert that the Commission should not review the numerous and/or routine foreign transactions that are not connected to the Commission's role of overseeing U.S. wholesale electric markets and the public interest. Certain commenters maintain that, at minimum, the Commission should exempt from review a holding company's acquisition of a FUCO where the holding company has no captive U.S. ratepayers.

39. Several commenters argue that if the PUHCA 2005 definition of “electric utility company” is adopted in the Final Rule, the definition should incorporate the exemptions to that definition set forth in the PUHCA 2005, including the exemption for FUCOs.[34]

40. As indicated above, commenters argue that part II of the FPA applies to interstate commerce; therefore, section 203 should not be read to extend to transactions that are not in interstate commerce.[35] Several commenters object to the proposed definition of “electric utility company” if it includes transactions typically reserved for state commission consideration (including transactions involving local distribution companies, stand-alone generation, retail sales and exclusively intrastate transactions), which the commenters maintain are beyond the Commission's jurisdiction.[36]

41. Specifically, Chairman Barton maintains that Congress did not intend to give the Commission jurisdiction over mergers in ERCOT. EEI, as supported by E.ON, PNM, and Progress Energy, maintains that its alternative definition for “electric utility company,” which is “a person that sells electric energy in interstate commerce,” would properly exclude local distribution companies from the Commission's authority under amended section 203.

42. Further, many commenters are concerned that the proposed definition of “electric utility company” applies to QFs.[37] ACC, EPSA, GE EFS, and Independent Sellers ask that the Commission clarify that QFs continue to be exempt from the Commission's section 203 authority. ACC asks the Commission to exclude QFs that are not affiliated with traditional utilities, transmission providers, or other non-QF power producers in order to ensure that the parent companies of such QFs are not subject to amended section 203.

43. Similarly, EPSA, GE EFS, and Independent Sellers request that we exclude a QF's upstream owners from Commission oversight under amended 203. They state that section 210(e) of Start Printed Page 1353PURPA [38] supports this finding. Independent Sellers also maintain that Congressional testimony suggests that amended 203(a)(2) should regulate only transactions of holding companies with public utilities in their holding company systems.[39]

44. Several commenters, including GE EFS and Morgan Stanley Capital Group Inc. (Morgan Stanley), express concern about whether the proposed definition of “electric utility company” includes EWGs. Morgan Stanley agrees with the use of the PUHCA 2005 definition of “electric utility company,” stating that applying the same definition in both statutes accords with traditional principles of statutory construction. However, it asks the Commission to construe that definition consistent with the exemptions set forth in PUHCA 2005; this would exempt EWGs.

45. APPA/NRECA seek clarification that “a State, any political subdivision of a State, or any agency, authority or instrumentality of a State or political subdivision of a State” is not an “electric utility company” under amended section 203(a)(2).

46. Finally, the Energy Program of Public Citizen, Inc. (Public Citizen) asks the Commission to interpret its jurisdiction under amended FPA section 203 more extensively. It argues that certain “suspect” categories of utility owners are not addressed in the NOPR or in current merger policy. These include investment banks, electric equipment suppliers, natural gas system owners, oil companies, and construction and other “service” companies. Public Citizen also states that the Commission must formulate a policy as to how it will protect American ratepayers if foreign holding companies are allowed to acquire, or continue to own, U.S. public utilities. Public Citizen criticizes the SEC's practice of allowing foreign holding companies to declare their own domestic utilities to be FUCOs under section 33 of PUHCA 1935, even though Congress did not intend to provide for this.[40] Public Citizen asks for greater protections for domestic ratepayers given the absence of a requirement for “registration for foreign holding companies and comprehensive PUHCA 1935 regulation of their financial transaction with their U.S. public utilities.” [41] It also states that the Commission should require a strong showing that acquisition by a foreign company without any experience in owning utilities is consistent with the public interest.

ii. Commission Determination

47. A number of commenters make various arguments to support the contention that the term “electric utility company,” as used in amended section 203(a)(2), should not have the same meaning contained in PUHCA 2005. As discussed in greater detail below, we have carefully considered this issue and will retain the NOPR's proposed definition of the term. Additionally, we continue to believe that the most reasonable interpretation of section 203(a)(2) is that it applies to purchases or acquisitions of foreign utility companies. However, consistent with Congressional intent, we do not want to impede foreign investments and we will grant blanket authorizations of foreign utility company acquisitions subject to certain conditions to protect U.S. captive customers. We also offer further clarifications below regarding the application of the definition of “electric utility company” in specific circumstances and provide blanket authorizations for certain transactions.

48. As noted above, new section 203(a)(2) provides:

No holding company in a holding company system that includes a transmitting utility or an electric utility shall purchase, acquire, or take any security with a value in excess of $10,000,000 of, or, by any means whatsoever, directly or indirectly, merger or consolidate with, a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility, or an electric utility company, with a value in excess of $10,000,000 * * *.[42]

Canons of statutory construction require that effect be given to every term used in a statute.[43] In new section 203(a)(2), Congress uses the term “electric utility” (already defined in the FPA) one time, and the term “electric utility company” (undefined in the FPA, but defined in both PUHCA 1935 and PUHCA 2005) two times in the same sentence. We cannot ignore the fact that Congress used two different terms within the same sentence. Had Congress intended “electric utility” to be used in three places instead of one, it would have done so.

49. However, the precise meaning of the term “electric utility company” is not clear. It is not a defined term in the FPA. Amended section 203(a)(6) provides that certain other terms used in amended section 203 (“associate company,” “holding company,” and “holding company system”) are to have the same meanings given those terms in PUHCA 2005, but does not address “electric utility company.” Thus there is Congressional silence as to the meaning of the term. We are therefore left to apply a reasonable meaning to the term in light of the simultaneous amendments to FPA section 203 and enactment of PUHCA 2005.

50. One of the arguments commenters raise in seeking an alternative definition of “electric utility company,” is that “nothing compels” the Commission to use the PUHCA 2005 definition of the term.[44] We agree that such a result is not “compelled,” because the term is ambiguous. However, in determining what Congress might have meant by “electric utility company,” the only reference points the Commission has in the context of federal electric utility regulatory terminology is the meaning of the term as used in PUHCA 1935 and in PUHCA 2005.[45] Further, while certain commenters maintain that Congress intended to use the term “electric utility” instead of “electric utility company” in section 203(a)(2), there is no reliable legislative history to support this conclusion and, moreover, we do not believe that proper statutory construction permits us to simply substitute a term that Congress did not use.[46] Additionally, as discussed below, substitution of the FPA term “electric utility” would not by itself resolve the issue as sought by commenters.

51. We conclude that the most reasonable interpretation of “electric utility company,” as used in section 203(a)(2) of the FPA, particularly in light of the fact that section 203(a)(2) will become effective simultaneous with the repeal of PUHCA 1935 and enactment of PUHCA 2005, is the meaning in PUHCA 2005: “any company that owns or operates facilities used for the generation, transmission, or distribution of electric energy for sale.” We also find that it is reasonable to Start Printed Page 1354interpret section 203(a)(2) as applying to foreign utility acquisitions, in light of the legitimate concern that there be federal oversight to ensure that U.S. captive customers do not cross-subsidize foreign transactions and that U.S. utility assets used to serve captive customers are not encumbered in order to support foreign acquisitions. The legislative history relevant to new section 203(a)(2) evidences this concern.[47] However, the legislative history also makes clear that the provision was not intended to impede foreign investments, particularly where there are no U.S. captive customers that could be affected. Accordingly, we will interpret “electric utility company” to include foreign utility companies, but, as discussed infra, we will grant blanket authorizations for certain foreign acquisitions, with conditions to protect U.S. customers.

52. We reject commenters' specific alternatives to the proposed definition of “electric utility company.” We do not believe that those proposed alternative definitions properly resolve the issue as to whether amended section 203(a)(2) applies to acquisitions of foreign utility companies. As noted above, the term “electric utility company” is defined in PUHCA 2005 as “any company that owns or operates facilities used for the generation, transmission, or distribution of electric energy for sale.” [48] In contrast, “electric utility” (which some commenters would have us substitute) is defined in the FPA, as modified by EPAct 2005, as “a person or Federal or State agency * * * that sells electric energy.” [49] Neither of these terms, on its face, is limited to domestic transactions or even to interstate transactions. “Electric utility,” as defined in the FPA, both pre- and post-EPAct 2005, means persons that sell electric energy. Thus, we reject the argument that the Commission should insert the term “electric utility” into section 203(a)(2) and then re-define it to mean persons that sell electric energy “in interstate commerce.” Not only has the modifier in “interstate commerce” not been included in the FPA definition of “electric utility” either pre- or post-EPAct 2005, but these commenters would require us to write into the statute words that are not there.[50]

53. We also reject the alternative, proposed by Suez, by which the Commission would exclude foreign acquisitions by jurisdictional holding companies without captive customers by adding the word “jurisdictional” before “transmitting utility” and “electric utility company” at the end of proposed section 33.1(a)(2) (which reflects new section 203(a)(2)). Congress in other provisions of the FPA, including section 203, has specifically limited certain authorizations to jurisdictional facilities, but chose not to do so in section 203(a)(2). We do not believe it is appropriate to insert into the statute modifiers that Congress did not include.

54. A number of commenters raised concerns about the definition of “electric utility company” and the applicability of the Commission's authority under amended section 203 to transactions wholly within ERCOT, Alaska, or Hawaii, transactions involving QFs, local distribution companies, stand-alone generation, retail sales and other intrastate transactions. Several of these commenters rely on the argument, as stated above, that Congress did not intend to expand significantly the Commission's jurisdiction and, therefore, did not convey to the Commission jurisdiction over transactions typically reserved for state commission consideration. Others argue for exemptions from the definition of “electric utility company.”

55. While we do not believe it is reasonable to interpret section 203(a)(2) as being limited solely to holding company acquisitions and mergers involving wholesale sales or transmission in interstate commerce, we nevertheless conclude that commenters have raised valid concerns and that there would be no benefit from the Commission's case-by-case evaluation of certain transactions under section 203(a)(2).[51]

56. Our core jurisdiction under part II of the FPA continues to be transmission and sales for resale of electric energy in interstate commerce and we believe that a major impetus behind section 203(a)(2) was to clarify the Commission's jurisdiction over mergers of holding companies that own public utilities as defined in the FPA.[52] However, the fact is that the language in section 203(a)(2) does more than address this issue, and we must implement the provision in a way that recognizes the expansion of authority, yet retains our primary focus on interstate wholesale energy markets and does not interfere unduly with historical state jurisdiction. Accordingly, we conclude that it is consistent with the public interest to grant blanket authorizations in the Final Rule for the following:

(1) Section 203(a)(2) purchases or acquisitions by holding companies of companies that own, operate, or control facilities used solely for transmission or sales of electric energy in intrastate commerce; and

(2) Section 203(a)(2) purchases or acquisitions by holding companies of facilities used solely for local distribution and/or sales at retail regulated by a state commission.

57. We conclude that these blanket authorizations are consistent with the public interest for several reasons. First, the identified categories do not raise concerns with respect to competitive wholesale markets for sales in interstate commerce or protection of wholesale captive customers served by Commission-regulated public utilities—matters within this Commission's core responsibility and expertise. Second, to the extent these categories raise competitive issues in intrastate commerce, i.e., in ERCOT, Hawaii, and Alaska,[53] those issues are within the Start Printed Page 1355expertise of, and more appropriately addressed by, state commissions. Third, to the extent retail competition and retail ratepayer protection issues are raised by a holding company acquisition of local distribution or other retail facilities, these issues also are within the expertise of, and more appropriately addressed by, state commissions. We will thus grant the identified blanket authorizations and not impose any type of filing requirement with respect to such transactions.

58. In response to the request of APPA/NRECA that we clarify that “a State, any political subdivision of a State, or any agency, authority or instrumentality of a State or political subdivision of a State” is not an “electric utility company” under amended section 203(a)(2), and therefore, not subject to amended section 203, we clarify that even if a governmental entity were to meet the definitions of “electric utility company” or “holding company,” section 203(a)(2) would not impose on the governmental entity any filing requirements under section 203. This is discussed in further detail infra. However, if a non-governmental public utility holding company were to seek to acquire a governmental utility (e.g., a municipal utility) that owns interstate transmission facilities or facilities used for wholesale sales in interstate commerce (and thus meets the definitions of “electric utility company”), and turn it into a private company subsidiary, then section 203(a)(2) should apply to the public utility holding company's acquisition. While no section 203 filing requirement would be imposed on the governmental entity, it would be imposed on the private entity.

59. We reject commenters' request that we explicitly exclude QFs and EWGs from the definition of “electric utility company.” Regardless of their status under PUHCA 2005, the exemptions set forth under PUHCA 2005 are not dispositive as to the scope of the Commission's amended FPA section 203 authority. These PUHCA 2005 exemptions are set forth in the context of federal access to books and records and, more importantly, unlike PUHCA 2005, FPA section 203 does not give us any express authority to exempt persons or classes of transactions.[54]

60. Additionally, were the Commission to interpret “electric utility company” for purposes of FPA section 203(a)(2) not to include EWGs or QFs, this could preclude review of certain acquisitions of securities of EWGs or QFs even by holding companies whose systems contain traditional public utilities with transmission facilities and/or captive customers. We do not believe that such transactions should be excluded from review under section 203 and conclude that it is reasonable to interpret the statute not to exclude them.[55] We recognize the arguments of some commenters that we should not apply section 203(a)(2) to holding company acquisitions of securities of EWGs and QFs, or at a minimum should not apply it to such acquisitions by holding companies that are holding companies solely by virtue of owning or controlling one or more EWGs, FUCOs, or QFs, because it would impede investments in QFs and EWGs or result in unnecessary regulation of upstream owners of QFs and EWGs.[56] In response, we believe the blanket authorizations granted herein for certain holding company acquisitions of non-voting securities and up to 9.9 percent of voting securities in electric utility companies will adequately address the concerns raised. To the extent additional blanket authorizations are needed or appropriate, we will consider those on a case-by-case basis.

61. Public Citizen makes broad comments on the scope of the Commission's jurisdiction and the standards articulated in the Commission's existing merger policy. We reject the request that we treat various types of utility owners or transactions as “suspect.” As discussed below, the Commission is adopting the definition of “holding company” as required by amended section 203(a)(6), and is adopting a definition of “electric utility company” that is reasonable, in light of the statutory construction of amended section 203 and Congressional silence. We note that several of the scenarios discussed by Public Citizen in its comments fall under the Commission's amended section 203 authority, as clarified herein. As with all such transactions under its review, the Commission will carefully examine the proposed transaction to ensure it is consistent with the public interest. Moreover, Public Citizen will have an opportunity to present its concerns in these specific cases.

b. Definitions of “Associate Company,” “Holding Company,” “Holding Company System,” and “Transmitting Utility”

62. In the NOPR, the Commission explained that the term “transmitting utility” is already defined in amended section 3 of the FPA [57] as “an entity (including an entity described in section 201(f)) that owns, operates, or controls facilities used for the transmission of electric energy—(A) in interstate commerce; (B) for the sale of electric energy at wholesale.” [58]

63. The Commission also proposed that, consistent with amended section 203(a)(6), the terms “associate company,” “holding company,” and “holding company system” shall have the meaning given those terms in PUHCA 2005.[59]

i. Comments

64. No comments were filed specifically in response to these proposed definitions of “transmitting utility,” “associate company,” or “holding company system.” However, several commenters object to the proposed definition of “holding company” or seek exemption from that definition for purposes of amended section 203(a)(2). They seek to limit the scope of the Commission's definition of “holding company.” [60] Amended section 203(a)(2) provides explicitly, for the first time, that “holding companies” must seek Commission approval prior to certain mergers and acquisitions. Commenters seek clarification as to the types of entities that meet the definition of “holding company” to confirm whether or not they will be subject to this new filing requirement.

65. GE EFS asks the Commission to construe the term “holding company” to include only companies that own traditional utilities and that would have been deemed to be holding companies under PUHCA 1935. This would exclude companies that are holding companies only by virtue of owning QFs, EWGs, or FUCOs. Industrial Start Printed Page 1356Consumers also seek to limit the definition of “holding company,” asking the Commission to clarify that “industrials and other entities whose on-site generation investment meets the statutory definition of EWGs' are not included in the definition.[61] Independent Sellers asks the Commission to confirm that a “holding company,” for purposes of amended section 203(a), does not include entities owning new electric generation facilities that have not yet begun commercial operation.

66. APPA/NRECA seek clarification that “a State, any political subdivision of a State, or any agency, authority or instrumentality of a State or political subdivision of a State,” does not meet the definition of “holding company.” [62] It also seeks clarification that rural electric cooperatives are not “holding companies” under amended section 203(a)(2).

67. HECO seeks clarification that an entity that meets the definition of holding company for purposes of section 203(a)(2) solely because it is the upstream owner of an electric utility company that is not a public utility under FPA, and that is not otherwise subject to Commission jurisdiction under any other provision of part II of the FPA, will not be subject to the Commission's merger authority. HECO explains that this would exclude from the Commission's jurisdiction under section 203(a)(2) acquisitions of holding companies with subsidiaries located only in Hawaii, Alaska, ERCOT, and foreign countries. HECO contends that Commission oversight of holding company acquisitions in this context is not necessary to protect the public interest.

ii. Commission Determination

68. Because the term “transmitting utility” is already defined in amended section 3 of the FPA and amended section 203(a)(6) provides that the terms “associated company” and “holding company system” shall have the meaning provided in PUHCA 2005, the Final Rule adopts them, as set forth in the NOPR.[63] We also note that no commenters oppose these proposed definitions.

69. The Final Rule also adopts the NOPR's proposed definition of the term “holding company.” Amended section 203(a)(6) mandates that the term “holding company” shall have the meaning provided in PUHCA 2005. This statutory directive is unambiguous.

70. The Commission therefore rejects requests for clarification that only companies that own traditional utilities, and not those that own solely FUCOs, EWGs and/or QFs, should be deemed “holding companies” under amended section 203. “Holding Company” in PUHCA 2005, as reflected in the rules adopted herein, means “any company that directly or indirectly owns, controls, or holds, with the power to vote, 10 percent or more of the outstanding voting securities of a public utility company or of a holding company of any public utility company; * * *” [64] There is no limitation within the plain words of this definition that can be read to exclude holding companies that own or control EWGs, FUCOs, or QFs. Additionally, even under PUHCA 2005, persons that own or control only EWGs, FUCOs, or QFs are considered holding companies but are explicitly exempted from PUHCA 2005 by section 1266. There is no similar exemption in amended section 203 and we conclude that it is reasonable to interpret section 203(a)(2) review to include acquisitions of generation or transmission facilities or companies by holding companies owning only FUCOs, QFs, and/or EWGs.

71. In response to the clarification sought by HECO, as indicated above, amended section 203(a)(6) mandates the adoption of the PUHCA 2005 definition of “holding company.” That definition includes the upstream owners of an electric utility company that is not a public utility under the FPA and that is not otherwise subject to Commission ratemaking jurisdiction under part II of the FPA. As discussed above regarding the definition of “electric utility company,” we have concluded that this definition is not limited to interstate commerce. Therefore, holding companies that own “electric utility companies” whose businesses are solely intrastate technically fall under amended section 203(a)(2). However, we agree that reviewing transactions involving Hawaii, Alaska, and ERCOT would involve matters outside our expertise and the core focus of part II of the FPA, and therefore we have granted blanket authorizations, as discussed above.

72. As requested by Independent Sellers, we clarify that a “holding company,” for purposes of amended section 203(a), does not include entities owning new electric generation that have not yet begun commercial operation.

73. We grant APPA/NRECA's request that the Commission clarify that a state or any political subdivision of a state or agency thereof is not a “holding company” under amended section 203(a)(2). While the definition of holding company possibly could be construed to include governmental entities or electric power cooperatives, we believe a more reasonable interpretation is that Congress did not intend to give the Commission authority over acquisitions by such entities. Section 201(f) of the FPA [65] excludes from most FPA part II provisions governmental entities and electric power cooperatives financed by the Rural Electrification Act of 1936,[66] and there is no indication that Congress intended to impose any section 203 filing requirements on such entities. Accordingly, we will not interpret section 203(a)(2) to apply to governmental entities and electric power cooperatives.

3. Section 33.1(b)—Definition of “Existing Generation Facility”

74. The Commission proposed that subsection 33.1(b) would define “existing generation facility” for section 203 purposes as a generation facility that is operational at the time the transaction is consummated.[67] The Commission stated that, as reflected in proposed section 33.1(a)(1)(iv)(b), if such a generation facility is intended to be used in whole or in part for wholesale sales in interstate commerce by a public utility, it is subject to our jurisdiction for ratemaking purposes and thus is covered under amended section 203(a)(1)(D). The Commission explained that, although the statute refers to a facility that “is” used for wholesale sales (and over which the Commission has jurisdiction for ratemaking purposes), we believed that a reasonable interpretation is that the provision would apply to newly constructed facilities that have already been energized at the time the transaction is consummated and are intended to be used in whole or in part for wholesale sales in interstate commerce by public utilities. The Commission also noted that if it can be demonstrated that a facility is used exclusively for retail sales, then amended section 203(a)(1)(D) does not apply.

Start Printed Page 1357

a. Comments

75. The definition of “existing generation facility” drew extensive comment from state regulatory commissions, traditional public utilities, public/cooperative entities and retail customer and other groups.

76. One comment raised by EEI and Progress Energy is that the Commission should construe the term “existing” to mean only facilities that existed as of the date of enactment of EPAct 2005 (August 8, 2005). They claim that had Congress meant to apply amended section 203 to facilities that become operational after August 8, 2005, it would have used different language. APPA/NRECA takes the decidedly opposite view that applying amended section 203 only to facilities that existed when EPAct 2005 was enacted would eventually mean the demise of section 203 review, without any indication that Congress intended such a result.

77. Most commenters focused on the term “existing” in its operational and temporal context, as reflected in the NOPR's proposal to assert jurisdiction over transfers of facilities that “are operational at the time the transaction is consummated.” Commenters generally focused on whether the facilities are in the construction or development stage, at or near “operation,” or in retired or mothballed status. Contrary to most commenters, Kentucky Public Service Commission (Kentucky Commission) and National Association of State Utility Consumer Advocates (NASUCA) would have the Commission assert jurisdiction over transfers of facilities that are under construction or development. NASUCA argues that section 203 should apply if the facilities have received any kind of federal or state permit or have applied for market-based rate authority or generator interconnection status with an independent system operator (ISO) or regional transmission organization (RTO). It contends that such facilities are already influencing the market, particularly if they are being sold to provide future capacity or ancillary services. By the same token, NASUCA and TAPSG want us to assert jurisdiction over transfers of units that are mothballed or retired, especially if the units can be brought back on line and retain the permits or authorities. FirstEnergy Service Company (FirstEnergy) recommends that the Commission clarify its rules to deal with a mothballed facility that is slated to be refurbished and with a facility that is shut down where the site and equipment has been sold. Neither FirstEnergy nor Progress Energy believe that section 203 should apply to transfers of facilities removed from service and from the Commission's accounting and thus are not physically or otherwise capable of making wholesale sales.

78. Although all commenters agree that section 203 review should encompass facilities that are “operational,” they disagree as to how to define “operational” and “ability to make sales.” They also disagree as to the point in time at which a jurisdictional determination is to be made, particularly for substantially completed plants that are at or near the “operational stage.” APPA/NRECA finds the Commission's proposed approach reasonable, but is concerned that defining a facility on the basis of whether the facility is energized may allow companies to evade section 203 by delaying the interconnection process. NASUCA shares this concern, asserting that whether the plant is producing electricity at the time of the transaction is irrelevant to whether section 203 jurisdiction should apply. NARUC, Progress Energy, and Southern Companies take the view that for a generation facility to be deemed “operational,” it must be interconnected and synchronized with the system so that it is capable of making wholesale sales. Other commenters suggest that a facility actually be in service and making jurisdictional sales. Most commenters agree with the Commission's proposal that the jurisdictional determination should be made on the basis of whether the facility is operational, or is projected to be operational when the transaction is (or is expected) to be consummated. NARUC, however, suggests that the jurisdictional determination should be made on the basis of whether the facility is operational at the time the underlying transaction agreement has been entered into and submitted for Commission approval.

79. Wisconsin Electric Power Company (Wisconsin Electric) expresses concern regarding the application of the term “operational.” It requests that the Commission clarify either that “consummated” refers to when the transaction, as defined by the lease and associated commitments, is executed or that “operational” is restricted to operations in the ordinary course of the business of the non-acquiring party.

80. EEI and Ameren Services Company (Ameren) argue that the “intent” language in proposed section 33.1(a)(1)(iv)(b) exceeds the statutory authority of amended section 203(a)(1)(D)(ii). They also insist that an “intent” standard is unworkable because “intent” would be difficult to ascertain. Southern is also concerned that the “intent” language would introduce confusion as to the jurisdictional status of transfers of facilities that are merely under construction. Chairman Barton questions whether requiring only an intent to use facilities in interstate commerce will unduly burden potential transactions and results in unnecessary review, particularly when, after the facilities are placed in service, the Commission has authority under FPA sections 205 [68] and 206 [69] over the facility and its rates. Although not specifically referring to either the “intent” language or the “exclusive use for retail sales” language, the North Carolina Utilities Commission (North Carolina Commission) emphasizes that nothing in amended section 203(a)(1)(D) expands the Commission's jurisdiction to include generation resource adequacy for retail service; EPAct 2005 expressly reserves authority over generation resource adequacy to the states. It urges that the final rule recognize this limitation.

81. Other commenters, such as Utility Workers Union of America, AFL-CIO (UWUA) and APPA/NRECA, generally support the “intent” language. APPA/NRECA and TAPSG, however, believe that a very high standard should be set for demonstrating that a facility is exclusively used for retail sales. TAPSG points out that utilities do not ordinarily dispatch their units separately for wholesale sales and retail sales. Both commenters also contend that amended section 203 should apply to facilities that received an exemption initially from section 203 on the basis of retail use only but that later are used for wholesale sales. Owners of such facilities should be subject to the Commission's expanded penalty authority. APPA/NRECA and TAPSG argue that the Commission should explicitly state that section 203 approval is required for the acquisition of a QF; they ask us to clarify that QFs may be “existing generation facilities” under amended section 203(a)(1)(D).

b. Commission Determination

82. The Commission will clarify and modify a number of aspects of its proposal for determining whether a generation facility is an existing generation facility for purposes of amended section 203(a)(1)(D). We will also address other questions raised by commenters with regard to the NOPR.

83. Initially, the Commission will reject EEI's and Progress Energy's Start Printed Page 1358argument that “existing generation facility” should be construed to encompass only those generation facilities in existence as of the date of enactment of EPAct 2005 (i.e., August 8, 2005). They submit that any other interpretation would effectively write “existing” out of the statute and that if Congress had intended amended section 203 to apply to generation facilities that come into existence after August 8, 2005, it would have used plainly different language. We do not agree. First, such an interpretation is not, as Progress Energy suggests, required as a textual matter. Congress could have, but chose not to, use the term “existing on the effective date of this Act.” Rather, it simply used the term “existing.” Second, such an interpretation would make little sense. It would eventually write amended section 203(a)(1)(D) out of existence as pre-EPAct 2005 generation facilities are retired and only post-EPAct 2005 generation facilities remain. There is only a brief mention of the term “existing,” without any explanation, in the legislative history of amended section 203. However, the legislative history suggests that Congress intended for the Commission to not only continue, but to expand our review of activities that would affect wholesale competition and ratepayers.[70] Therefore, we reject EEI's and Progress Energy's argument.

84. The Commission adopts the NOPR's proposal that an “existing generation facility” is a generation facility that is operational at or before the time the transaction is consummated. However, we are deleting language in proposed section 33.1(a)(iv)(b) stating that section 203 applies if the generation facility “is intended to be used” in whole or in part for wholesale sales in interstate commerce by a public utility. Below we explain various aspects of this definition.

85. We note first that “the time the transaction is consummated” refers to the point in time when the transaction actually closes and control of the facility changes hands. The Commission will construe “operational” to mean a generation facility for which construction is complete (i.e., it is capable of producing power). An “existing generation facility” would not include generation plants that are only in the development or construction stage. However, an “existing generation facility” would include a mothballed facility, so long as the facility was operational at any time before the transaction is consummated.

86. With regard to the issue of wholesale versus retail sales, the Commission will eliminate the language “intended to be” from proposed section 33.1(a)(1)(iv)(b). We agree with some commenters that “intent” is difficult to discern and could introduce unnecessary confusion about plants that are under construction and clearly not being used for wholesale sales. Rather, the Commission will adopt a rebuttable presumption that amended section 203(a) applies to the transfer of any existing generation facility unless the utility can demonstrate with substantial evidence that the generator is used exclusively for retail sales. In our experience, utilities do not ordinarily separate the dispatch of their plants for retail sales and wholesale sales; rather, they dispatch all their units on an integrated basis to serve all load (retail and wholesale). Therefore a utility proposing an unusual procedure by which it dispatches certain plants “only” for retail load will have the burden to demonstrate that any particular generating facility will never be used to make wholesale sales.

87. Finally, in response to commenters' requests that section 203 approval be required for the acquisition of a QF, we clarify that if a public utility acquires an existing generation facility used for Commission-jurisdictional sales, whether a QF or any other type of generation facility, the transaction is subject to section 203. Although certain QFs themselves are exempted from any filing requirements under section 203 by virtue of our PURPA regulations, this does not mean that public utilities that acquire QFs are exempt. Additionally, there is no limitation in amended section 203(a)(1)(D) on the type of generation facilities that trigger section 203 review, if they are used for interstate wholesale sales and the Commission has jurisdiction over them for ratemaking purposes. Further, even if the Commission had the discretion to exempt QF acquisitions from section 203 review, we do not think it would be necessarily consistent with the public interest to do so in light of EPAct 2005's elimination of QF ownership restrictions.

4. Section 33.1(b)—Definition of “Non-Utility Associate Company”

88. The Commission proposed to interpret the term “non-utility associate company” to mean any associate company in a holding company system other than a public utility or electric utility company that has wholesale or retail customers served under cost-based regulation.[71] Therefore, we proposed that a non-utility associate company would include, for example, a power marketer, a generator that does not have captive customers, a gas marketer, a fuel supply company or other company that provides inputs to power production, or a company that is involved in business activities not related to the generation, transmission, distribution, or sale of electricity.[72] This definition is relevant because of the new section 203(a)(4) requirement that we find that a proposed transaction does not result in inappropriate cross-subsidization or pledge or encumbrance of utility assets. The Commission sought comment on whether it should use a narrower definition, for example, whether we should define a “non-utility associate company” as a company that is in a business not related to the generation, transmission, distribution, or sale of electricity.

a. Comments

89. Many state commissions and other commenters from the industry agree that the Commission's proposed broad definition of “non-utility associate company” should be adopted in order to afford the greatest protection against cross-subsidization, as Congress intended in EPAct 2005.[73] Indiana Commission and NARUC explain that the cross-subsidization of an entity involved in a business unrelated to the electric industry and the cross-subsidization of an entity involved in “unregulated,” electricity-related activities are equally inappropriate. On the other hand, FirstEnergy and Southern Companies urge the Commission to adopt the narrower definition.

90. American Electric Power Service Corporation (AEP) asserts that both the Commission's broader definition proposed in the NOPR and the narrower definition (proposed as an alternative) are unnecessarily broad, ensnaring companies that are providing essentially ancillary services to the regulated utility and that thus present no risk of cross-subsidization. AEP maintains that amended section 203(a)(4) is simply designed to ensure that a transaction does not result in cross-subsidization, Start Printed Page 1359which, by definition, only occurs when a competitive affiliate of the utility is unduly enriched by use of regulated assets. AEP states that the Commission has already defined these energy affiliate companies in the Standards of Conduct,[74] and states that we should define a “non-utility associate company” by adopting the same definition used to describe an “energy affiliate” in 18 CFR 358.3(d).

b. Commission Determination

91. We agree with the majority of the commenters that the NOPR's proposed broader definition of the term “non-utility associate company” is reasonable. Our goal in defining this term is to ensure that public utilities with captive customers do not cross-subsidize “non-regulated” associate companies, i.e., companies that are not subject to traditional cost-based regulation.[75] As it relates to this objective, there is no difference between the propriety of cross-subsidizing associate energy companies that are not subject to traditional cost-based regulation versus an entity that is involved in a business completely unrelated to the energy industry. Since the purpose is to protect customers, whether the company inappropriately subsidized is an associate company in the energy industry or not is irrelevant.

92. We disagree with AEP's contention that cross-subsidization occurs only when using traditionally regulated assets to subsidize a competitive affiliate of the utility company. Congress was concerned with the potential for abuse when a traditionally regulated public utility (i.e., one that is subject to the Commission's traditional cost-based regulation) subsidizes an “unregulated” affiliate company within the same holding company system. Defining a non-utility associate company based on whether or not that “unregulated” affiliate company is a competitor of the utility company is too narrow to prevent abuses; consequently, the Standards of Conduct definition of an “energy affiliate” is not appropriate here.[76]

93. Accordingly, we will adopt the broader definition of a “non-utility associate company,” which is any associate company in a holding company system other than a public utility or electric utility company that has wholesale or retail customers served under cost-based regulation. A non-utility associate company would include, among others, a power marketer, a generator that does not have captive customers, a gas marketer, a fuel supply company or company that provides inputs to power production, or a company that is involved in business activities not related to the generation, transmission, distribution or sale of electricity.

5. Section 33.1(b)—Definition of “Value”

94. In the NOPR, the Commission proposed to generally rely on a “market value” approach for determining whether asset transfers, with the exception of wholesale contracts, meet the value threshold necessary to require approval under amended section 203. This would base value on expected future earnings or profits over the life of the asset. This is in contrast to our current regulations, which define value as original cost undepreciated as defined in the Commission's Uniform System of Accounts; in other words the amount paid for installing an original plant and equipment and additions thereto.[77] As described below, the Commission proposed certain measures of value for each of four types of asset transactions, inviting comment and suggestions for alternative approaches.

95. Specifically, the Commission proposed that section 33.1(b) would define “value,” as applied to jurisdictional facilities and existing generation facilities (addressed by amended subsections 203(a)(1)(A) and (D)), as the market value of such facilities.[78] The Commission recognized that determining the market value of transmission facilities could be difficult in some instances. We proposed that, in the absence of a readily ascertainable market value, original cost undepreciated would be used. For transactions involving transfers of facilities between non-affiliates, the Commission stated that market value will, in most circumstances, be reflected in the transaction price. For transactions between affiliates, the Commission recognized that we cannot assume that market value will be reflected in transaction price. We suggested undepreciated original cost as a possible alternative measure of value.

96. The Commission also proposed that section 33.1(b) would define “value,” with respect to a merger or consolidation with a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility, or an electric utility company, with a value in excess of $10 million, as used in amended section 203(a)(2)) as “market value.” We stated that in most instances market value would be reflected in the transaction price for transactions between non-affiliates.

97. Turning to how to value paper jurisdictional facilities, the Commission proposed that the value of any wholesale contract included in the transaction would be based on total expected contract revenues over the remaining life of the contract.[79] We noted that market value was an alternative approach and that it could be based on the price or consideration paid for the contract.

98. The Commission proposed to define the “value” of a security, as discussed in amended sections 203(a)(1)(C) and (a)(2), as the market price at the time the security is acquired.[80] For transactions between non-affiliated companies, the Commission proposed to rebuttably presume that the market value is the agreed-upon transaction price. We sought comments on how to determine value for security transactions involving affiliates if the securities are not widely traded. Further, the Commission sought comments as to whether it should give particular weight to evidence of non-affiliate transactions involving either non-affiliated buyers or sellers of securities of similarly situated utilities or assets.

a. Comments on Definition of “Value” as Applied to Transmission and Generation Facilities

99. Nearly all commenters support the use of market value. Most commenters support using transaction price to measure market value in most situations.[81]

100. APPA/NRECA and TAPSG contend that market value should be replaced by “fair” market value. They recommend that the Commission measure “fair” market value based on standards to be adopted by the Financial Accounting Standards Board that use both a market approach and an income approach. Because the market value standard could introduce some Start Printed Page 1360uncertainty into the process, FirstEnergy urges the Commission to provide clear guidance to the industry and the investment community explaining how a market value standard would be used in certain situations. It suggests that we create a “safe harbor” that clearly defines methods and components used to assess market value. EEI argues that when a state commission has reviewed or made a determination of value for a particular transaction, a company should be able to rely on that value for purposes of determining value under section 203; the company should not have to pay penalties if the Commission later determines that the value of the transaction exceeds $10 million.

101. Virtually all commenters recognize that a market value standard, particularly one based on transaction price, may need to be modified or even replaced in some circumstances. As explained below, these circumstances involve transactions that include non-jurisdictional facilities in addition to jurisdictional facilities or generation facilities; transactions where market value may not be ascertainable; and transactions not conducted at arms'-length (such as affiliate transactions). Alternative suggested measures of market value or value are the following: (1) Market value as determined by market-based results of an Edgar-type analysis [82] or independent valuation process; (2) original cost undepreciated; (3) the higher of market value or original cost undepreciated; and (4) net book value (original cost depreciated).

102. Focusing first on transactions between non-affiliates, many commenters agree that, in most circumstances, transaction price is the appropriate measure of market value.[83] EEI, Duke Energy Corporation and Cinergy Corp. (Duke/Cinergy), and Progress Energy urge the Commission to rebuttably presume that market value is the agreed-on transaction price. EEI, Duke/Cinergy, Entergy, and FirstEnergy, argue that the market value determination should be based only on the value of jurisdictional transmission assets or generation assets. They state that a single transaction price will not measure the market value for a transaction that also includes assets other than jurisdictional transmission assets or generation assets. EEI proposes determining the transaction price for the jurisdictional transmission facilities or generation facilities based on their relative net book value (original cost depreciated).

103. Commenters differ significantly as to the appropriate measure of value where the transaction is between affiliates. As a first backstop in scenarios involving affiliated transactions, several commenters contend that transaction price is still a reasonable measure of market value, provided that the transaction price is shown to be consistent with the results of an Edgar-type analysis or independent valuation process.[84] However, other commenters, including the New Jersey Board, NASUCA, and APPA/NRECA, would compare a market value or “fair” market value with original cost undepreciated and select the higher of the two. They argue that the Commission must evaluate the widest possible range of transactions to determine the public interest implications of transactions; utilities will attempt to understate value and thereby avoid section 203 review.

104. When a market-based determination of value is not possible or practical, commenters are divided, mainly between original cost undepreciated and net book value. Commenters who advocate the use of net book value urge the Commission to reject any use of original cost undepreciated, particularly for non-affiliate transactions, since it does not reflect the deterioration (wear) of the facility.[85] Rather, they would encourage the use of net book value, since it is the basis of transmission rates.

105. Other commenters suggest a modification of the original cost undepreciated and net book value concepts. Missouri Public Utilities Commission (Missouri Commission) would rely on reproduction cost (the costs of replicating the same plant today with the same assets and same technology). As a proxy for this measure, Missouri Commission suggests that the original cost could be escalated by appropriate wholesale price indices. Scottish Power would adjust net book value by converting it to current dollars.

b. Comments on Definition of “Value” as Applied to Transmitting Utilities, Electric Utility Companies, or Holding Companies

106. Nearly all commenters support the market value approach as measured by the transaction price to determine the value of a transaction involving transmitting utilities, electric utility companies, or holding companies. NASUCA proposes the higher of market value or original cost undepreciated to limit the possibility that a merger of two independent transmission companies would escape review. It also asserts that market value is not necessarily the same as market price. FirstEnergy believes that the transaction price should reflect only the value of the underlying jurisdictional or generation facilities. The Commission should also establish other parameters for determining the market price, such as the point in time at which the determination is to be made, such as the date of the agreement, the date of filing of the application, or the date of consummation of the transaction. To the extent the Commission does not adopt transaction price, FirstEnergy urges the Commission to otherwise specifically define market value and specify safe harbor standards.

c. Comments on Definition of “Value” as Applied to Paper Jurisdictional Facilities

107. Many commenters, including state commissions and consumer groups generally favor total expected revenues over the contract's remaining life as the appropriate measure of value for transfers of wholesale contracts.[86] This is regardless of whether affiliates or non-affiliates are involved. Revenues will be a function of quantities of supply and thus are an indirect measure of the contract's contribution to market supply, in much the same way that the value of generation assets will be related to generator size. These commenters also point out that a revenues approach would be much easier to apply than an expected net profits standard, which can be unpredictable on the basis of varying assumptions and is likely to be measured inaccurately.

108. Constellation adds that the use of nominal revenues avoids confidentiality issues raised by how buyers and sellers value contracts on the basis of transaction price. This is particularly true where it is necessary to determine value for individual contracts that are part of a portfolio of contracts and non-Start Printed Page 1361jurisdictional assets. Some commenters point out that in some instances, for individual contracts, the seller may actually pay the buyer and the buyer may have the option to buy the power at a market price, which may be lower than contract price. Thus, the transaction price would either be negative or much smaller than under a revenues approach. This would increase the likelihood that the transaction would not fall under section 203.

109. On the other hand, many commenters urge the Commission to adopt transaction price as the measure of value.[87] They contend that value is closely tied to expected profits, which considers supply costs, unlike the revenue approach, and thus will be more accurately reflected in transaction price than in revenues. FirstEnergy comments that a revenues approach would be difficult to apply if the contract rates are not fixed. If the Commission decides not to use transaction price, commenters suggest a variety of other measures, including discounted value of future cash flows reduced by obligations, net present value of non-fuel revenues, and expected profits.

110. For affiliate transactions, many of these same commenters generally agree that transaction price is appropriate if it is supported by Edgar-type evidence. However, another measure favored by EEI, Entergy, and Duke/Cinergy would apply “mark to market” pricing [88] to determine the value of a contract between affiliates. Entergy, citing Order No. 627,[89] asserts that the Commission has taken the same approach in requiring utilities to report in Form 1 changes to the fair market value of certain derivative instruments and activities.

d. Comments on Definition of “Value” as Applied to Securities in Excess of $10 Million

111. Generally all of the commenters from the various segments of the industry, including regulatory commissions, public power, and customer groups, support the Commission's proposal to value security transactions between non-affiliates at market value. Nearly all appear to accept our proposal to rebuttably presume that price is the appropriate measure of market value. FirstEnergy requests, however, that the Commission provide more specificity as to which price is relevant, i.e., the agreed-to-price or a publicly traded price, and as to what is meant by time of the transaction—the time of agreement or the time of consummation. FirstEnergy also asks whether the transaction value used should take into consideration the fact that non-regulated assets may be included in the transaction as well. EEI and International Transmission argue that to give regulatory certainty to the transacting parties, the relevant price should be the agreed-to price.

112. EEI suggests that for securities transactions between affiliated parties, market price is reasonable when the securities are widely traded. However, several parties support assessing market value based on an application of Edgar standards, particularly when the securities are not widely traded. On the other hand, FirstEnergy and NASUCA contend that an Edgar approach will not work well because any group of non-affiliate transactions will be vastly different in terms and other factors that affect value or price. When Edgar-type evidence is not available, EEI and Ameren propose certain formulaic measures involving company-specific variables; [90] NARUC suggests that the Commission simply use paid-in capital equity. Indiana Commission suggests that an affiliate transaction be constructed to evade section 203 jurisdiction could be used to subsidize a non-jurisdictional affiliate, but Southern Companies asserts that transaction thresholds are so low there will no meaningful opportunities to evade jurisdiction by such means.

e. Commission Determination

113. The Commission notes the widespread support for using a market value approach (where feasible). After considering the comments of numerous parties, we remain convinced that market value is, in most instances, the most effective and reasonable approach (both for potential section 203 applicants and for the Commission) to determine which asset transfers, particularly those that involve acquisitions of physical facilities or securities, require section 203 approval.

114. As one commenter suggests, however, using market value as the measurement standard is not straightforward in all circumstances. For example, where the transaction involves a single asset subject to section 203 being purchased and sold between non-affiliates, the agreed-upon price for the transaction is a straightforward measure of market value. However, there may be non-affiliate transactions that include a bundle of assets, both assets subject to section 203 and assets not subject to section 203, so that the transaction price does not reflect the market value of only the assets subject to section 203. Another example involves transactions between affiliates where the agreed-upon price for the exchange will not necessarily reflect market value. In both instances, other measures of market value would be required.

115. It is important that the Commission provide as much guidance as possible to those contemplating business transactions regarding how the determination of value should be made and thus deciding whether section 203 review is required. Such guidance will enhance parties' certainty and will also contribute stability to investment decision-making by utilities and non-utilities alike.

116. For transfers of physical facilities (transmission and generation facilities) the Commission will adopt market value as the appropriate measure of value. When a transaction occurs between non-affiliates, the Commission will rebuttably presume that market value is the transaction price. The most obvious complicating factor in applying this test is the need to consider only the value of the facilities subject to section 203; many transactions will include other assets not subject to section 203 as well. However, in such situations, the acquiring entity will probably have made a valuation analysis of the constituent parts of the transaction in order to guide its negotiations and/or properly record the value of those facilities on its balance sheet. Almost certainly included in that analysis will be a valuation of the physical facilities. In transactions involving both facilities subject to section 203 and facilities not subject to section 203, companies should rely on such valuations in Start Printed Page 1362deciding whether to file for section 203 approval.

117. If separate valuations of the physical assets were not performed, companies should rely on original cost undepreciated. Several commenters urge the Commission to reject the use of original cost undepreciated and adopt, instead, net book value. Our current regulations use original cost undepreciated as the appropriate measurement standard and we will continue to use that standard in applying amended section 203. Although net book value is a valuation method commonly used to establish cost-based rates, most generating facilities today sell power at market rates, and their market value is driven primarily by factors unrelated to the book depreciation of the facility. For example, many highly depreciated coal-fired assets have commanded significant premiums in generation divestitures. Hence, we believe that the continued use of original cost undepreciated is preferable to net book value.

118. We also cannot rely on transaction price as a measure of market value when a transaction involving physical facilities occurs between affiliates. Instead, here too we will adopt original cost undepreciated. The alternatives to transaction price most frequently supported by commenters include: (1) Value based on an Edgar-type analysis (market value), (2) original cost undepreciated, (3) the higher of market value or original cost depreciated, and (4) net book value. As discussed above, as between the choices of original cost undepreciated and net book value, the Commission believes that original cost undepreciated is preferable and should continue to be used.

119. The Edgar analysis is applied in section 205 proceedings to determine whether purchases from an affiliate are reasonable in light of other alternatives. The analysis is not intended to provide a bright-line easy-to-apply test of whether jurisdiction to approve a particular transaction exists in the first place. Rather, the analysis is often highly contentious and is used to determine the justness and reasonableness of a particular transaction, not for determining whether jurisdiction exists to review it in the first place. The Commission believes that, for purposes of section 203 applicability, a valuation based on original cost depreciated will be simpler and less ambiguous than one based on Edgar, particularly when most transactions will clearly exceed $10 million by any reasonable measure.

120. With respect to determining value to be applied to transfers of wholesale contracts between non-affiliates, the Commission will rebuttably presume that market value is the transaction price. This is consistent with our use of market value and transaction price for other types of asset transfers. As with transfers of physical facilities, when assets not subject to section 203 are included in the transaction, the acquiring entity should rely on its valuation of the contracts component included in transaction price. The market valuation should be consistent with the value the applicant places on the contract for purposes of its audited financial statements and in keeping with generally accepted accounting principle (GAAP) requirements. One commenter has expressed confidentiality concerns about valuations for individual contracts as part of a portfolio of contracts that could likely arise if a utility's decision not to file for section 203 approval was challenged. We believe that any such concerns can be addressed through our procedures that provide confidential treatment to certain proprietary materials.[91] Furthermore, we note that any measurement standard (such as projected revenue stream) could also raise concerns over confidentiality in certain circumstances.

121. The issue of how to value contract transfers between affiliates is more difficult to resolve, since a transaction price, if it exists at all, will not necessarily reflect market value. For affiliate transfers of contracts, we agree with one commenter that total expected contract revenues are a simple, objective way to assess value and to provide increased certainty as to the need for a section 203 filing. We therefore adopt this standard for valuing jurisdictional contracts between affiliates.

122. Amended sections 203(a)(1)(C) and (a)(2) define the Commission's jurisdiction over certain acquisitions of securities by public utilities and holding companies. With respect to securities transactions between non-affiliates, the Commission will adopt transaction price, as explained more fully herein, for the acquisition of securities by either a public utility or a holding company. The Commission recognizes that the NOPR was not entirely clear as to how to determine the “transaction price.” Although we stated that the value of a security would be defined as the market price at the time the security is acquired, we also stated that the market value would be rebuttably presumed to be the agreed-on transaction price. Thus, FirstEnergy asks how market price should be defined—a publicly traded price or the price ultimately agreed on. It also asked the Commission to clarify the meaning of “at the time the security is acquired.” Specifically, does this language refer to the point in time an agreement is entered into or the actual time of consummation of the transaction?

123. The Commission is mindful of the need to provide parties as much regulatory certainty as possible with respect to decisions as to whether section 203 approval is required for a particular transaction. In this case, the Commission finds that greater regulatory certainty is provided by relying on the agreed-to transaction price at the time the transacting parties enter into an agreement. However, the Commission will reject the argument that the value of securities transactions should be adjusted to reflect the fact that not all of the assets underlying the value of the securities are jurisdictional facilities or generation facilities. Amended section 203 does not permit any such interpretation, as it applies to the purchase of the “security * * * of a * * * public utility,” not to the “securities applicable to the jurisdictional facilities of a public utility.”

124. For securities transactions between affiliates, however, an agreed-on transaction price will not necessarily be consistent with market price. For that reason, if the securities are widely traded, the Commission will require that affiliates value the transaction based on the market price at the time the securities are acquired. If the securities are not widely traded, we will adopt, in a slightly modified manner, EEI's suggestion. For equity securities, we will utilize a three-part determination to determine value: (i) Determining the value of the company that is the issuer of the equity securities based on the total undepreciated book value of the company's assets; (ii) determining the fraction of the securities at issue by dividing the number of equity securities involved in the transaction by the total number of outstanding equity securities for the company; and (iii) multiplying (i) by (ii) (i.e., the value of the company multiplied by the fraction of the equity securities at issue). This method for securities transactions that are not widely traded is consistent with our use of original cost undepreciated to measure value for transactions between affiliates involving physical assets.

125. Amended section 203(a)(2) addresses holding company mergers or consolidations with a transmitting utility, an electric utility company, or a Start Printed Page 1363holding company in a holding company system that includes a transmitting utility, or an electric utility company, with a value in excess of $10 million. Regarding transactions between non-affiliates, market value will be the transaction price or consideration paid, as provided for in the agreement between the transacting entities. As with securities, we note there is no statutory provision or legislative history to suggest that the transaction price should be adjusted to reflect the fact that non-jurisdictional assets are also involved, and so we will not allow for such an adjustment.

126. For mergers or consolidations involving affiliates, transaction price will not be an acceptable basis for establishing value. Several commenters recommend the use of an Edgar-type analysis to arrive at a market value. However, the Edgar approach is not a practical approach to applying the $10 million jurisdictional threshold for the reasons discussed above. Therefore, the Commission will, instead, use the book cost of all of a company's assets to measure the value of mergers or consolidations of affiliated companies.[92]

6. Compliance With Section 203

127. Given the increased significance of valuation of a transaction under amended section 203, the Commission solicited comments on whether our existing recordkeeping and reporting requirements, outside the section 203 context, will allow us and the public to effectively monitor jurisdictional entities' determinations of when a section 203 application is required. For example, the Commission asked “do FERC Form 1s or Order No. 652 [93] market-based rate change in status reports provide sufficient information to monitor compliance with section 203?” [94]

a. Comments

128. Many commenters believe that the Commission's existing record-keeping and reporting requirements will be enough.[95] Some note that parties often seek section 203 authorization out of an abundance of caution, whenever there is a reasonable possibility that section 203 approval is legally required, in order to remove regulatory uncertainty from a transaction, as an entire transaction can be placed at risk if required regulatory approvals are not obtained.

129. However, some commenters suggest that the Commission's current record-keeping and reporting requirements are the minimum necessary for section 203 purposes and should not be reduced. NARUC states that our existing record-keeping and reporting requirements are adequate as they pertain to mergers. However, NARUC suggests that Commission review of merger applications could be enhanced by requiring the applicant to file pro forma consolidated financial reports showing the projected financial position of the merged entity after the proposed transaction.[96]

130. APPA/NRECA assert that the Commission's existing record-keeping and reporting requirements do not provide sufficient information on fair market value for the Commission to ensure that companies are not improperly transacting without filing for approval. They state that the Commission should update our reporting requirements, including requiring applicants to adhere to GAAP principles for valuation determinations and to justify exemption from section 203 under both a cost and market value method of valuation. As for reporting requirements that might enable the Commission and the public to police compliance with section 203, APPA/NRECA suggest that the Commission should consider requiring public utilities to file annual reports of all transactions with a value exceeding, for example, $5 million, to enable the Commission to enforce the $10 million standard.

b. Commission Determination

131. Most commenters state that the Commission's existing record-keeping and reporting requirements are adequate. We agree and we will not adopt any additional compliance requirements at this time. We intend to keep our regulations as straightforward as possible so as not to increase regulatory burden on the industry while at the same time adequately monitoring jurisdictional entities' determinations of when section 203 applies to their transaction. The Commission agrees that parties have often sought section 203 authorization out of an abundance of caution because of a reasonable possibility that section 203 approval was legally required. In this way, parties have sought to remove regulatory uncertainty from a transaction, as an entire transaction can be placed at risk if required regulatory approvals are not obtained. This incentive is even greater now that EPAct 2005 has authorized civil penalties for violating statutory requirements.[97]

132. Although the majority of commenters assert that the current requirements are adequate, a few suggest that these requirements should be considered the minimum necessary for section 203 purposes and should not be reduced. We agree, and note that the NOPR did not propose to reduce our current requirements. We merely asked whether our existing record keeping and reporting requirements, outside the section 203 context, provide an adequate basis for monitoring jurisdictional entities' determinations of when a section 203 application is required. We believe that those requirements, as well as other publicly available information (e.g., financial statements filed with the SEC), will give interested entities enough information to allow them to monitor compliance with section 203. For example, under SEC disclosure requirements, publicly traded entities must disclose material transactions such as mergers or asset acquisitions. Most of these transactions will easily exceed the $10 million threshold, so the public will be on notice of transactions that likely should be submitted to the Commission for approval under section 203. We will therefore not adopt the suggestions of NARUC and APPA/NRECA that we impose new and burdensome disclosure requirements for purposes of monitoring compliance with section 203.

7. Cash Management Arrangements, Intra-Holding Company System Financing, Securities Under Amended Section 203, and Blanket Authorizations

133. The NOPR did not specifically address these issues, but we received comments on them. We note that section 203(a)(2) adds the entirely new requirement that no holding company in a holding company system that includes a transmitting utility or an electric utility shall purchase, acquire, or take any security with a value in excess of $10 million of, or, by any means whatsoever, directly or indirectly, merge or consolidate with, a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting Start Printed Page 1364utility, or an electric utility company, with a value in excess of $10 million without Commission authorization.

a. Comments

134. Many commenters, including EEI, Duke/Cinergy, and Entergy, request that the Commission clarify that it will continue to interpret section 203 to not apply to cash management [98] and other financing arrangements routinely used in utility holding company systems. Thus, they request that the Commission continue to distinguish between the acquisition of voting securities and other instruments that confer control, which is subject to review under section 203, and the acquisition of loans and other financial instruments that do not confer control. They state that the issuance of these should remain subject to section 204 of the FPA [99] and relevant state law, but should not require section 203 approval. EEI, Duke/Cinergy, and Entergy also explain that cash management rules are already in place to monitor any potential cross-subsidization concerns for these types of financial arrangements. Furthermore, they assert that requiring prior approval under section 203 for cash management arrangements would impair the ability of holding companies and their public utility subsidiaries to manage their short-term financing needs efficiently. Applying section 203 to all intra-system financings would be contrary to Congress' intent and would create significant burdens for the Commission and utilities alike. Alternatively, should the Commission determine that section 203 applies to cash management programs, they request that the Commission allow companies to seek pre-approval (similar to the pre-approval process and reporting requirements adopted for cash management agreements) or blanket authorization.

135. MidAmerican Energy Holdings Company (MidAmerican) also urges the Commission to grant a blanket authorization for intra-holding company system financings, contributions, or equity infusions in excess of $10 million undertaken by an upper tier company to fund a lower tier holding company, intermediate holding company, or public utility company within the same holding company system. It states that the purpose of these financial transactions is to fund the capital and operating requirements of the lower tier entities and, thus, that these transactions do not raise any cross-subsidization issues. MidAmerican explains that the utility company would still need to obtain Commission authorization under section 204 for the issuance of its own securities.

136. Further, MidAmerican urges the Commission to grant another blanket authorization for the infusion of capital by a passive investor through the acquisition of holding company or public utility company securities, including debt and equity securities, subject to an aggregate limitation that the passive investor acquire less than ten percent of voting equity securities. It explains that one of the main objectives of repealing PUHCA 1935 was to encourage additional investment in the energy infrastructure by non-traditional, or passive investors (who make significant capital infusions in the utility industry either as lenders or equity investors), because existing investors are not providing sufficient money. There is no need for passive investors to follow the traditional section 203 approval process. It states that passive investments will not have any adverse effects on competition, rates, or regulation, and will not result in cross-subsidization. MidAmerican proposes that, to ensure that a passive investor will not be able to exercise control through ownership of a voting equity security, the passive investor be limited to an ownership interest of less than ten percent of voting securities. Further, MidAmerican states that when an investor acquires the debt or equity securities of an entity that has a de minimis interest in an electric utility company, we should grant the blanket authorization.

137. MidAmerican suggests that the Commission require those who receive these types of blanket authorizations to report their transactions within 45 days of the closing of the transactions.

138. Many commenters, including EPSA and Independent Sellers, request that the Commission clarify that the term “securities,” as used in amended section 203(a), means only “voting securities,” as that term is defined in section 1262(17) of PUHCA 2005, and does not apply, for example, to debt or other nonvoting securities. Alternatively, if the Commission is unable or unwilling to so clarify, the Commission should request a conforming amendment from Congress.

139. Transmission Agency of Northern California (TANC) urges the Commission to modify its Cash Management Rule to apply to public utility holding companies, which would add an additional layer of protection to utilities and their customers.

b. Commission Determination

140. As noted above, amended section 203(a)(2) expands the Commission's authority to include mergers, acquisitions, and purchases of securities [100] of over $10 million involving holding companies within certain holding company systems. A major part of the Commission's past practice in reviewing section 203 transactions has been to determine whether a particular merger or acquisition results in a single entity having control over transmission or generation resources that would allow it exercise market power. This would also be a concern under the new section 203(a)(2) provision.

141. However, as several commenters suggest, there are several classes of transactions covered by amended section 203(a)(2) that will not harm competition or captive customers. These include: (1) Routine cash management transactions and intra-holding company system financing transactions; (2) acquisition of non-voting securities (in any amount); [101] and (3) acquisition of voting securities that would give the acquiring entity not more than 9.9 percent ownership of the outstanding voting securities. For these transactions, the Commission finds that it is consistent with the public interest to issue a blanket authorization in this Final Rule, for the reasons discussed below.

Start Printed Page 1365

i. Cash Management Programs and Intra-Holding Company Financing Arrangements

142. As several commenters note, cash management programs, money pools, and other intra-holding company financing arrangements are a routine and important tool used by many large companies to lower the cost of capital for their regulated subsidiaries and to improve the rate of return the holding company and its subsidiaries can get on their money.[102] The Commission does not intend to make it more difficult for companies to take advantage of these types of transactions. Since the companies participating in a cash management-type agreement are already affiliated, allowing the transfer of funds between such companies does not generally present competitive problems. Thus, we find that it is consistent with the public interest to grant a blanket authorization to allow holding companies and their subsidiaries to take part in intra-system cash management-type programs, subject to the discussion below.

143. TANC suggests that the Commission modify its Cash Management Rule to cover holding companies themselves. Currently, the Cash Management Rule only covers the cash management practices of a holding company's public utility subsidiaries.[103] We disagree with TANC that additional generic cash management rules governing holding companies are necessary at this time to safeguard consumers. The focus of amended section 203 is partly to prevent inappropriate cross-subsidization, or encumbrances or pledges of utility assets by public utility subsidiaries. Applicants must adopt sufficient safeguards, including any necessary cash management controls (such as restrictions on upstream transfers of funds, ring fencing, etc.), to prevent any cross-subsidization between holding companies and their new subsidiaries prior to receiving section 203 approval. Such safeguards ensure that consumers are protected, while permitting companies the flexibility to competitively manage their cost of capital via a cash management program. On balance, the Commission believes that the flexibility provided by this approach, combined with our existing cash management policies,[104] is superior to the one-size-fits-all approach advocated by TANC.

ii. Purchases of Non-Voting Securities by a Qualifying Holding Company

144. We agree with the majority of commenters that there is no need for case-by-case examination of the purchase by a holding company of non-voting securities of a public utility or of another holding company under amended section 203. The purchase of such securities generally does not convey control and hence does not grant the purchasing holding company additional market power, harm competitive markets, or otherwise disadvantage captive customers.[105] This is consistent with the intent of Congress that EPAct 2005 increase outside investment in the utility sector while protecting customers.[106] As MidAmerican notes, the issuance of securities by a jurisdictional company is also governed by section 204 of the FPA. Thus, for the purposes of amended section 203, we find that it is consistent with the public interest to grant a blanket authorization for the purchase by a holding company of any amount of non-voting securities of a public utility or of another holding company. We will grant this blanket authorization and will not impose any type of filing requirement with respect to such transactions.

iii. Purchases of Voting Securities Amounting to 9.9 Percent or Less of Outstanding Voting Securities

145. As commenters note, a number of investors would like to invest in the utility sector, but have been prevented from doing so by the fear that they would become subject to regulation by the SEC as well as this Commission. To remedy this problem, a number of commenters suggest giving a blanket section 203 approval to institutional investors within holding company systems purchasing less than 10 percent of the outstanding voting securities. Commenters note that the SEC has traditionally given blanket approval to a holding company in a holding company system purchasing up to 9.9 percent of outstanding voting securities of a public utility or a holding company covered by the statute. We agree that this approach makes sense and that it is consistent with the public interest and Congressional intent in repealing the restrictions of PUHCA 1935 and encouraging incentives for additional investment. We will, however, condition the blanket authorization by requiring the purchaser of such securities to provide the Commission, not more than 45 days after the purchase, with the same information on the same basis that the holding company now provides to the SEC.[107] We will issue notices of these filings for informational purposes only.

8. Section 33.2(j)—General Information Requirements Regarding Cross-Subsidization

146. In the NOPR, the Commission proposed that new section 33.2(j) would implement section 203(a)(4) by requiring applicants to explain how they are providing assurance that the proposed transaction will not result in a cross-subsidization of a non-utility associate company or a pledge or encumbrance of utility assets for the benefit of an associate company. We proposed to require appropriate evidentiary support for that explanation. We proposed that if no such assurance can be provided, applicants must explain how such cross-subsidization, pledge, or encumbrance will be consistent with the public interest.[108] This explanation would be Exhibit M to the applicant's section 203 application. The Commission sought comment on what evidence parties should be required to submit to support any explanation offered under this subsection.

147. The Commission noted that it has sought to guard against potential Start Printed Page 1366cross-subsidization and affiliate abuse when it reviews applications for cost-based or market-based rate authority under section 205 of the FPA [109] or dispositions of jurisdictional facilities under section 203 involving public utilities (or their affiliates) with captive customers.[110] We also noted that the Commission has cash management rules to monitor proprietary capital ratios and money lending or other financial arrangements that can harm regulated companies.[111] We stated that our primary focus has been on preventing a transfer of benefits from a traditional public utility's captive customers to shareholders of the public utility's holding company due to an intra-system transaction that involves power or energy, generation facilities, or non-power goods and services. Thus, in light of the Congress' clear directive in EPAct 2005 that the Commission make findings regarding cross-subsidization and the pledge or encumbrance of utility assets in a section 203 order, we sought comments on what additional safeguards or conditions may need to be placed on section 203 transactions. Specifically, the Commission solicited comments on the adequacy of its present policies preventing affiliate abuse and cross-subsidization, and whether conditions such as those imposed by state commissions may need to be imposed on section 203 transactions. The Commission also sought comment on whether additional conditions should be placed on section 203 approvals to ensure that there is no pledge or encumbrance that harms utility customers.

a. Comments

148. Many commenters generally support the Commission's proposal but recommend additional conditions or safeguards. They agree that the Commission should impose specific conditions or safeguards to protect against unfair competitive practices, cross-subsidization, and affiliate abuse.[112] Some recommend that the Commission consider such protections on a case-by-case basis in consultation with affected state commissions. Proposed conditions include, for example: Utility company subsidiaries shall not loan any funds (or advance any credit or indemnity) to the holding company without appropriate regulatory approvals; a utility shall not incur any additional indebtedness, issue any additional securities, or pledge any assets to finance any part of a merger of holding companies without prior regulatory approvals; all debt at the holding company level shall be non-recourse to the utility; and the Commission should develop a process for periodic audits of inter-company transactions to be conducted in appropriate instances, as well as procedures for compliance monitoring, investigation, and complaints of cross-subsidization and affiliate abuse.

149. The Oklahoma Corporation Commission (Oklahoma Commission) proposes that applicants provide: A report of the nature of affiliates' operations; description of the business intended to be done by subsidiaries; and an explanation and detailed rationale of any plans to make any material change in investment policy, business, corporate structure, or management.

150. New Jersey Board states that it is not clear that proposed section 33.2(j) requires applicants to provide evidentiary support when claiming that a cross-subsidization, pledge, or encumbrance is consistent with the public interest. Therefore, it proposes that the text be revised to state “An explanation , with appropriate evidentiary support for such explanation (to be identified as Exhibit M to this application):”.[113]

151. To mitigate cross-subsidization risks to ratepayers, other commenters propose structural conditions on mergers of entities that include both public utility and non-utility businesses, as the facts require. This could include the separation of public utility business within companies that also engage in non-utility business and the separation of a public utility's books and records from those of non-utility affiliates.

152. Finally, Southern Companies request that when a public utility predominately serves customers at retail but has some jurisdictional facilities, the Commission accept as sufficient a showing that the public utility applicant is subject to general supervision by a state commission that has authority to review the transaction, and that such state commission approval is predicated upon a finding that the transaction will not impair the performance of public service obligations or result in cross-subsidy burdening utility assets or service.

153. Other commenters generally state that there is no need to impose additional conditions or a new evidentiary requirement to ensure that transactions are consistent with the public interest.[114] They assert that the Commission already has in ways to guard against cross-subsidization or pledging or encumbering of utility assets, including: (1) Cash management rules; (2) code of conduct restrictions; (3) prior approval for certain power transactions; (4) access to, and auditing of, books and records; (5) expanded jurisdiction under EPAct 2005 with regard to books, accounts, and records; (6) standards of conduct; and (7) the application of Edgar standards to ensure that the sale price is not higher than would have been paid to a non-affiliate.

154. Duke/Cinergy, EEI, PNM, and Entergy assert that the Commission should allow applicants to avoid a detailed examination of cross-subsidization and encumbrance concerns by making four verifications on a case-by-case basis that address those issues. These verifications would enable the Commission to quickly determine whether a transaction is consistent with the public interest. The verifications would be that the transaction results in: (1) No transfers of facilities between a traditional utility associate company with wholesale or retail customers served under cost-based rates and an associate company; (2) no new issuance of securities by traditional utility associate companies with wholesale or retail customers served under cost-based rates for the benefit of an associate company; (3) no new pledge or encumbrance of assets of a traditional utility associate company with wholesale or retail customers served under cost-based regulation for the benefit of an associate company; (4) no new affiliate contracts between non-utility associate companies and traditional utility associate companies with wholesale or retail customers served under cost-based rates, other than system allocation agreements subject to review under EPAct 2005 section 1275(b).[115] In cases where an applicant is unable to make one or more of the accepted verifications, these commenters state that the applicant should bear the burden of submitting sufficient information in Exhibit M to demonstrate that there is no cross-subsidization issue or, if there is, that the transaction is consistent with the public interest.

Start Printed Page 1367

155. Some commenters generally oppose imposing additional conditions or safeguards beyond or that would conflict with those imposed by state commissions. Many commenters believe that the Commission's current policies are more than adequate to address state commission conditions and that the Commission already imposes most of these conditions directly.[116]

156. Oklahoma Commission suggests that the Commission allow state commissions to continue to exercise their autonomous authority in addressing possible affiliate abuse and cross-subsidization. Kentucky Commission states that any additional conditions imposed by the Commission should complement, not nullify or preempt, those imposed by state commissions.

157. International Transmission states that because independent transmission companies, by definition, are not affiliated with market participants, concerns regarding transmission-specific cross-subsidization that distort energy markets are minimized. National Grid states that the Commission should impose a merger condition only when it finds a proposed transaction, taken as a whole, is inconsistent with the public interest. Scottish Power states that the Commission should allow applicants to provide their own ways to demonstrate that there is no potential for cross-subsidization, on a case-by-case basis.

158. FirstEnergy contends that a requirement that applications demonstrate that each company within a holding company system is unaffected by cross-subsidization would inundate the Commission with information that has no real import. If the Commission requires such an evidentiary showing, it must clearly define the types of evidentiary support that would be necessary and provide guidance on the types of activities that typically would result in a pledge or encumbrance and those that will be consistent with the public interest. FirstEnergy states that conditions should be placed on section 203 approvals only when the Commission finds that a pledge or encumbrance is not consistent with the public interest.

159. Finally, Independent Sellers request that the Commission adopt a rebuttable presumption that no opportunity for cross-subsidization exists when a transaction involves only entities that are not affiliated with traditional public utilities with captive ratepayers.

160. In addition, Kentucky Commission, APPA/NRECA, and TAPSG comment that the Commission should require as part of a section 203 application the disclosure of all existing and/or future pledges and future encumbrances of utility assets. They state that applicants should have to explain how these existing pledges or encumbrances do not harm utility customers. However, International Transmission and FirstEnergy do not believe that all existing pledges and encumbrances should be disclosed in section 203 applications because this would be inconsistent with section 33.11(b)(3) of the regulations, which assumes that corporate reorganizations can occur that do not present cross-subsidization issues.

161. Missouri Commission states that the Commission should require, as a condition of approving mergers, the application of a “lower of” or “higher of” “cost or market value” standard. TANC states that requiring associate and affiliated companies to file cost allocation agreements with the Commission will help prevent excessive costs for non-power goods and services from being charged to utility companies and their customers. With regard to cost allocations for non-power goods and services, TANC asserts that the dual approach of a “lower of cost or market” standard has the advantage of ensuring that utilities and customers will not be harmed by an affiliate company relationship, regardless of whether market price exceeds costs for the non-power goods or services, or vice versa.

162. AEP encourages the Commission to retain the “at cost” standard for intra-system non-power goods and services transactions due to the added cost, burden, and inconsistencies that would be created otherwise. It explains that the expense and effort of implementing a “lower of cost or market” standard to the wide range of routine service company administrative and professional services would be immense, would result in lost efficiencies and, ultimately, would produce higher rates for regulated ratepayers. AEP states that the at-cost standard is a fair, verifiable, and workable.[117]

163. National Grid states that the Commission should continue to allow the use of the SEC's “at no more than cost” standard for pricing of intra-company transactions involving service companies. It explains that such companies were created to allow efficiently centralized support services for utility and non-utility associate companies within a holding company; therefore, a pricing system based on market prices would not be appropriate.

b. Commission Determination

164. The Commission will adopt, with the modification explained below, our proposal to require section 203 applicants to include an explanation of either: (1) How they are providing assurances that the proposed transaction will not result in cross-subsidization or improper pledges or encumbrances of utility assets; or (2) if such results would occur, how those results are consistent with the public interest. We believe that this approach meets Congress' concern regarding cross-subsidization in section 203 transactions. As we explained in the NOPR, the Commission has previously adopted a number of policies to address affiliate abuse and cross-subsidization activities as it carries out its section 203 and 205 responsibilities. Amended section 203, however, clearly shows that Congress intended that cross-subsidization and related concerns should be a focal point of the Commission's section 203 analysis.

165. We also agree with commenters that certain protections may be necessary, on a case-by-case basis, in order to protect against cross-subsidization, pledge or encumbrance of utility assets, and affiliate abuse. We note that commenters who generally support the Commission's proposal, as well as some who generally do not support the proposal, advocate a case-by-case approach. Commenters suggest many valid conditions that applicants might propose or that the Commission might impose under revised FPA section 203(a)(4). However, many of these conditions may not be appropriate to every section 203 transaction.

166. In our Merger Policy Statement, the Commission explained that, in determining whether a merger is consistent with the public interest, one of the factors we consider is the effect the proposed merger will have on rates. The Commission's main objective in applying this factor is to protect captive customers who are served under cost-based rates that could be adversely affected by a section 203 transaction.[118] Start Printed Page 1368The new provision in amended section 203(a)(4) concerning cross-subsidization is rooted in similar concerns. In our Merger Policy Statement, we held that an applicant that wishes to avoid a hearing on rate issues should submit a commitment that adequately protects captive customers, such as a hold harmless commitment or an open season. Also, as part of our policy authorizing market-based rates for traditional public utilities or their affiliates, we have required that these utilities adopt a code of conduct that addresses both power and non-power transactions between them.[119] We believe that these types of commitments also can, in appropriate circumstances, address concerns regarding the potential that a merger may permit cross-subsidization. We will therefore require applicants to offer protections to their captive customers that address the potential for cross-subsidization. We also note that, in addition to any such commitments, we have continuing jurisdiction over the rates of public utilities under section 205 by which to further protect captive customers.

167. In sum, the concern about cross-subsidization is principally a concern over the effect of a transaction on rates. Accordingly, applicants proposing transactions under section 203 should proffer ratepayer protection mechanisms to assure that captive customers are protected from the effects of cross-subsidization. The applicant bears the burden of proof to demonstrate that customers will be protected.[120] Applicants should attempt to resolve the matter with customers before filing. Among the types of protection mechanisms that could be proposed by applicants are: A general hold harmless provision, which must be enforceable and administratively manageable, where the applicant commits that it will protect wholesale customers from any adverse rate effects resulting from the transaction for a significant period of time following the transaction; or a moratorium on increases in base rates (rate freeze), where the applicant commits to freezing its rates for wholesale customers under a certain tariff for a significant period of time.[121] The Commission will address the adequacy of the proposed mechanisms on a case-by-case basis. Furthermore, we agree that any additional conditions imposed by the Commission would complement, not nullify, those imposed by state commissions.

168. What constitutes adequate ratepayer protection will depend on the particular circumstances of the transaction. Should parties be unable to reach an agreement on ratepayer protection, the Commission may still be able to approve the transaction on the basis of the parties' filings if we determine that the proposal protects ratepayers from harm, or after imposing conditions specific to the particular circumstances.

169. We also agree with commenters that certain verifications in an application under amended section 203 could streamline the approval process by avoiding a detailed examination of cross-subsidization and encumbrance concerns. Such verifications, considered on a case-by-case basis in light of the given transaction, and explanations relating to those verifications, as well as other explanations of how the transaction will not result in cross-subsidization, pledge, or encumbrance of utility assets for the benefit of an associate company “ or if it does result in such, an explanation of how such cross-subsidization, pledge, or encumbrance will be consistent with the public interest “ is to be included as Exhibit M to the application. Accordingly, along with any protection mechanisms as discussed above, we may accept on a case-by-case basis, in lieu of or in addition to any other explanation, the following four verifications. The application may verify that the proposed transaction does not result in, at the time of the transaction or in the future: (1) Transfers of facilities between a traditional utility associate company with wholesale or retail customers served under cost-based regulation and an associate company; (2) new issuances of securities by traditional utility associate companies with wholesale or retail customers served under cost-based regulation for the benefit of an associate company; (3) new pledges or encumbrances of assets of a traditional utility associate company with wholesale or retail customers served under cost-based regulation for the benefit of an associate company; (4) new affiliate contracts between non-utility associate companies and traditional utility associate companies with wholesale or retail customers served under cost-based regulation, other than non-power goods and services agreements subject to review under sections 205 and 206 of the FPA.

170. We also agree with New Jersey Board that proposed section 33.2(j) does not clearly require appropriate evidentiary support for the explanation in Exhibit M. We will therefore revise the text to read: “An explanation, with appropriate evidentiary support for such explanation (to be identified as Exhibit M to this application): * * *” Further, the Commission will monitor and periodically audit, where appropriate, to ensure that applicants abide by their commitments in Exhibit M and any requirements contained in Commission orders.

171. With regard to comments on the “at cost” standard versus the “market” standard for transactions involving non-power goods and services, we note that the Commission addressed this issue in the PUHCA 2005 rulemaking.[122]

9. Section 33.11—Commission Procedures for Consideration of Applications Under Section 203 of the FPA

172. In the NOPR, the Commission proposed new subsections 33.11(a) and (b) to implement amended section 203(a)(5). Specifically, subsection 33.11(a) provides that the Commission will act on a completed application for approval of a transaction (i.e., an application that meets the requirements of Part 33), not later than 180 days after the completed application is filed.[123] If the Commission does not act within 180 days, such application shall be deemed granted unless the Commission finds, based on good cause, that further consideration is required and issues an Start Printed Page 1369order tolling the time for acting on the application for not more than 180 days, at the end of which additional period the Commission shall grant or deny the application, as required by amended section 203 of the FPA.[124]

173. Proposed subsection 33.11(b) would provide for the expeditious consideration of completed section 203 applications that are not contested, are not mergers, and are consistent with Commission precedent, because they should typically meet the standards established in section 203(a)(4).[125]

174. The Commission also stated that it could not provide a comprehensive description of all the classes or types of transactions that will receive the expedited review. However, the Commission proposed that transactions that would generally warrant expedited review include: (1) A disposition of only transmission facilities, particularly those that both before and after the transaction remain under the functional control of a Commission-approved RTO or independent system operator; (2) transfers involving generation facilities of a size that do not require an Appendix A analysis; (3) internal corporate reorganizations that do not present cross-subsidization issues; and (4) the acquisition of a foreign utility company by a holding company with no captive customers in the United States.[126]

175. With respect to the latter category, the Commission recognized that amended section 203's requirement for regulatory approval could have a chilling effect on investment—particularly if the transaction were subjected to a lengthy regulatory review. The Commission noted that such a transaction would not cause competitive concerns in the United States and, further, that there would be no concerns about cross-subsidization that harms captive customers in the United States. In addition, the Commission stated that even with respect to the acquisition of a foreign utility company by a holding company with captive customers in the United States, there may be safeguards that allow expedited approval of such transactions. Thus, the Commission sought comment on procedures the Commission might adopt, or safeguards it might require, to pre-approve or expedite such transactions while at the same time protecting U.S. captive customers.

176. Further, the Commission stated that it expects to have a 60-day notice period for section 203 applications that involve, contain, or require a competitive analysis per the part 33 and a 21-day notice period for all other section 203 applications, except for certain applications that may raise cross-subsidization concerns. The Commission stated that it expects to have a 60-day notice period for applications that seek authorization to transfer ownership of a generation plant from one affiliate or associate company to another company within the same corporate structure and for other applications that may raise cross-subsidization or pledge or encumbrance issues.[127]

a. Comments

177. Many commenters, including TAPSG and UWUA, support the Commission's proposal regarding the criteria for expedited consideration (applications that are not contested, are not mergers, and are consistent with Commission precedent). APPA/NRECA and TANC, however, caution that uncontested section 203 applications should still be reviewed to ensure they are consistent with Commission precedent. International Transmission notes that limiting expedited review to non-merger transactions is inconsistent with the Commission's recognition in the NOPR that not all merger transactions require the same level of analysis. Oklahoma Commission suggests that state commissions take over initial transaction review and that the Commission adopt a role of appellate review where there are disagreements between state commissions and the applicant.

178. TAPSG and UWUA agree with the Commission's proposal not to provide a comprehensive description of the classes or types of transactions that generally fall into the expedited review category. However, TANC suggests that the Commission adopt an exhaustive list of section 203 transactions that are eligible for expedited review to provide customers with the utmost protection and certainty. International Transmission recommends that, in order to encourage investment in independent transmission, dispositions, consolidations, or acquisitions by independent transmission companies should receive expedited review, even if all of the criteria in section 33.11(b) of the proposed regulations are not met. Many commenters recommend that, for all four of the categories, the Commission automatically approve the application upon filing an informational report where the applicants make certain verifications.[128]

179. With respect to proposed section 33.11(b)(4), commenters had a variety of responses on the procedures that the Commission might adopt, or safeguards it might require, to expedite or pre-approve transactions involving the acquisition of a FUCO by a holding company with no captive customers in the U.S. Many commenters request that the Commission not adopt any rules or policies that would impose undue regulatory burdens on holding companies that seek to invest in foreign utility companies.

180. Many traditional public utility commenters and others generally support a 30-day expedited review or pre-approval for transactions involving acquisitions of FUCOs.[129] Commenters suggest that the Commission automatically approve the application when the applicant provides certain cross-subsidization verifications (similar to those listed in EEI's comments), as well as assurances that the transaction will have no adverse effect on competition, rates, and regulation, if the filing is verified by a duly authorized corporate official of the holding company.[130] The transaction should be deemed approved upon making such informational filing.

181. State commission commenters, including NARUC, Ohio Commission, and New Jersey Board, generally suggest that, in order to protect domestic customers while expediting or pre-approving foreign utility transactions, the Commission should consider reviewing the financial condition and credit ratings of the acquiring utility holding company and its operating utility companies, or require applicants to submit service agreements, codes of Start Printed Page 1370conduct, and affiliate rules.[131] They recommend that the Commission also conduct a cursory “due diligence” review of historical information from annual FERC Form 1 filings by the holding company's operating utility companies to examine trends in the holding company's investment in its domestic operating utilities and in their quality of service. The Commission could get this information from state regulatory commissions.

182. Some commenters are cautious of the Commission's proposed expedited procedures for approving the acquisition of FUCOs. TAPSG states that the Commission should not decide in the abstract how reviews of such transactions can be expedited. Public Citizen urges the Commission to protect domestic ratepayers by requiring that a strong showing be made that such a transaction is consistent with the public interest and by evaluating whether attempts by off-shore companies to acquire or hold controlling shares in U.S. public utilities can be found to be consistent with the public interest.

183. With respect to proposed section 33.11(b)(1) and expedited procedures for a disposition of transmission facilities only (particularly those that both before and after the transaction remain under the functional control of a Commission-approved RTO or ISO), TANC comments that expedited review should be used only where the facilities will remain under the functional control of the same Commission-approved RTO or ISO after the transaction is completed. TANC also states that transmission-only dispositions should receive expedited review only when they involve entities that are non-dominant market participants. APPA/NRECA argues that dispositions of transmission-only facilities should not generally receive expedited review.

184. With respect to proposed section 33.11(b)(2) and expedited procedures for transfers involving generation facilities of a size that do not require an Appendix A analysis, many traditional public utility commenters suggest that such expedited review be extended to include all transactions that do not require an Appendix A analysis. They recommend revising the proposed regulations to state: “transactions that do not require an Appendix A analysis.” [132] They also state that, even in cases where an Appendix A analysis is required for a generation facility acquisition, the Commission should act expeditiously in certain circumstances, setting a 30-day comment period and issuing an order no later than 30 days thereafter. Southern Companies requests that the Commission provide guidance regarding when an Appendix A analysis is required.

185. With regard to proposed section 33.11(b)(3), EEI, Entergy, and Duke/Cinergy support expedited procedures or pre-approval for internal corporate reorganizations that do not present cross-subsidization issues. National Grid, however, requests expedited procedures or pre-approval for internal reorganizations that do involve mergers.[133] It requests that the Commission facilitate all internal corporate reorganizations that do not either introduce new third-party interests or cross-subsidization issues, which are routine aspects of a company's financial operations, and do not need to be disrupted by formal proceedings, however expedited, under section 203.

186. EEI, Entergy, and Duke/Cinergy, state that the Commission could streamline the process further by granting blanket authorizations, for FUCO acquisitions involving holding companies that do not have captive customers in the U.S. and for internal corporate reorganizations involving public utility and holding company systems that do not involve traditional utility companies with captive customers.[134]

187. Several commenters also made suggestions regarding notice periods and complete applications. Many commenters support the Commission's expected notice periods. However, some commenters recommend that, except in simple cases, the Commission provide for a 60-day notice period. They suggest that the applicant bear the burden of demonstrating that a shorter notice period is appropriate. TAPSG and UWUA recommend that, where applications are not complete, the Commission should issue deficiency letters. TAPSG also suggests that the Commission not deem an application complete until after it has reviewed any interventions or protests, since they may identify deficiencies in the application. UWUA recommends that the 180-day clock on section 203 applications should not begin to run until a complete application has been submitted. It states that merger applicants should have an increased responsibility to submit complete applications that are supported with full explanations of the details of the proposed transaction, including testimony.

b. Commission Determination

188. The Commission adopts the proposed criteria for expedited consideration in section 33.11(b). Expedited consideration will be available for applications that are not contested, are not mergers, and are consistent with Commission precedent. With respect to APPA/NRECA and TANC's concerns that the Commission should review even uncontested section 203 applications to ensure that they are consistent with Commission precedent, we note that the Commission has always reviewed section 203 applications, regardless of whether they are contested.

189. Further, while some commenters recommend that the regulations contain an exhaustive list of the types of transactions that would generally warrant expedited review, we continue to believe that doing so could exclude transactions that may warrant expedited review, but that are not listed. Thus, as discussed below, we will not adopt an exhaustive list of such transactions. The Commission will not expressly provide expedited review for mergers or acquisitions involving independent transmission companies, as suggested by International Transmission, as review of such cases would be more appropriately addressed on an individual basis.[135]

190. Commenters have raised many valid arguments regarding the Commission's four proposed categories of transactions generally warranting expedited review. We will adopt the NOPR's proposal in section 33.11(b)(1) and will generally provide expedited review for a disposition of only transmission facilities, particularly those that both before and after the transaction remain under the functional control of a Commission-approved RTO or ISO. We note APPA/NRECA's concern that the consolidation of control of jurisdictional facilities should be carefully evaluated under section 203 and TANC's argument that expedited review should be limited to those facilities that will remain under the functional control of the same Commission-approved RTO or ISO after the transaction is completed. However, Start Printed Page 1371we believe that ISOs and RTOs are pro-competitive and are effective at preventing market power abuse because they have Commission-approved market-monitoring and mitigation measures in place. Further, we continue to believe that, as stated in the Filing Requirements Rule, “the standards set forth in Order No. 2000 [136] require extensive information from RTO applicants that we believe will demonstrate whether the proposal is in the public interest. It also has been our experience that anticompetitive effects are unlikely to arise with regard to internal corporate reorganizations or transactions that only involve the disposition of transmission facilities.” [137] For these reasons, we adopt section 33.11(b)(1) as proposed in the NOPR.

191. With respect to proposed section 33.11(b)(2), the Commission will adopt commenters' proposal and expand that section to generally provide expedited review for “transactions that do not require an Appendix A analysis.” On further consideration, the Commission finds that it is not necessary to limit the transactions that will receive expedited review based on the amount of generation that is being transferred in the transaction. First, we note that the amount as well as the type of generation involved can have different market power consequences, depending on the situation, in different markets. Second, our current regulations, which allow applicants to file an abbreviated competitive analysis (e.g., an analysis that does not include an Appendix A analysis) in certain circumstances, permit us to seek additional information if it is needed to allow us to evaluate the effects of the transaction. Therefore, although in the first instance the applicant must decide whether to perform a full-fledged analysis, it is the Commission that ultimately decides whether such analysis is necessary and thus whether the filing qualifies for expedited review.

192. With respect to proposed section 33.11(b)(3), we agree with commenters that internal corporate reorganizations that do not present cross-subsidization issues are unlikely to cause anticompetitive effects. Thus, instead of providing expedited review for this category, the Commission is granting a blanket authorization for internal corporate reorganizations that do not present cross-subsidization issues and that do not involve a traditional public utility with captive customers.

193. With respect to the last category, proposed section 33.11(b)(4), we will not adopt the NOPR's proposal to expedite review for transactions involving the acquisition of a FUCO by a holding company with no captive customers in the U.S. Instead, we will grant a blanket authorization for any holding company in a holding company system that includes a transmitting utility or an electric utility company to acquire a foreign utility company. However, if such holding company or any of its affiliates, its subsidiaries, or associate companies within the holding company system have captive customers in the United States, the authorization is conditioned on the holding company verifying by a duly authorized corporate official of the holding company that the proposed transaction will not have any adverse effect on competition, rates, or regulation, and will not result in, at the time of the transaction or in the future: (1) Any transfer of facilities between a traditional utility associate company with wholesale or retail customers served under cost-based regulation and an associate company; (2) any new issuance of securities by traditional utility associate companies with wholesale or retail customers served under cost-based regulation for the benefit of an associate company; (3) any new pledge or encumbrance of assets of a traditional utility associate company with wholesale or retail customers served under cost-based regulation for the benefit of an associate company; or (4) any new affiliate contracts between non-utility associate companies and traditional utility associate companies with wholesale or retail customers served under cost-based regulation, other than non-power goods and services agreements subject to review under sections 205 and 206 of the FPA. Such transactions will be deemed approved only upon making a filing of these verifications.

194. Regarding notice periods, the Final Rule adopts the NOPR approach. Some commenters recommend that the Commission's default rule for all section 203 applications should be to provide the public 60 days to submit comments, and that the applicants should bear the burden or demonstrating that a shorter notice is appropriate. However, the Commission finds that the NOPR notice periods will allow us to continue processing section 203 applications quickly to allow reasonable business goals to be met. Accordingly, we expect to have a 60-day notice period for section 203 applications that involve, contain, or require a competitive analysis per the revised filing requirements, and a 21-day notice period for all other section 203 applications, except those that may raise cross-subsidization concerns. We will not formalize this policy by rule, so that we can be flexible to deal with varying circumstances. This will allow us to protect against some commenters' concerns that the public notice period would be “unnecessarily short-circuited,” and ensure that it will only be streamlined as appropriate.

B. Amendments to 18 CFR 2.26—The Merger Policy Statement

195. When the Commission considers a proposed transaction's effect on federal regulation, section 2.26(e)(1) states that “[w]here the merged entity would be part of a registered public utility holding company, if applicants do not commit in their application to abide by this Commission's policies with regard to affiliate transactions, the Commission will set the issue for a trial-type hearing.”

196. However, in the NOPR, the Commission explained that because EPAct 2005 repeals PUHCA 1935,[138] activities of registered holding companies that were previously subject to SEC regulation, including inter-company transactions, will no longer be exempt from this Commission's regulation once PUHCA 1935 repeal takes effect on February 8, 2006.[139] Thus, the Commission stated that there is no longer a concern about any potential shift in regulation from this Commission to the SEC under the effect of regulation factor, and proposed to delete section 2.26(e)(1).[140]

197. Proposed new subsection 2.26(f) would state that the Commission will not approve a transaction that will result in cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company unless that cross-subsidization, pledge, or encumbrance will be consistent with the public interest.

1. Comments

198. Commenters did not specifically address the Commission's proposed section 2.26(e) and (f) amendments. However, some recommend that the Commission rethink its current merger policy and make important decisions as Start Printed Page 1372to what “consistent with the public interest” means in light of amended section 203 and the repeal of PUHCA 1935. Some comment that the Commission should broaden its public interest inquiry to consider ratepayer benefits on an application-specific basis; namely, applicants could propose an open season guarantee under which their existing wholesale requirements customers could terminate their contracts if the applicants request a rate increase affecting those customers for the first five years after the merger is consummated.

199. Ohio Commission comments that the Commission should consider factors in addition to those listed in section 2.26(b). It recommends that the Commission require that a holding company secure a letter of endorsement, or order, from any affected state regulatory commission in which the holding company has utility operations. It states that a similar endorsement requirement is used by the SEC to implement Rule 53 [141] regarding authority for registered holding company financings in connection with the acquisition of exempt wholesale generators.

200. Commenters also explain that, in light of amended section 203, the Commission should expect numerous section 203 applications seeking approval of “cross-country” (or interstate) mergers. They state that the Commission's current method for evaluating the effect of a proposed electric utility merger on competition, the Appendix A analysis, was developed when cross-country electric utility mergers were not common, because of PUHCA 1935. The “impact on competition” horizontal screen analysis looks primarily at whether competition will be lessened in the “common” markets where the merger applicants operate. They state that continued use of the Appendix A analysis alone may result in substantial industry consolidation.

201. TAPSG asserts that the Commission almost exclusively relies on the HHI aspect of the Appendix A analysis and fails to examine the other competitive effects of a transaction. It comments that the Commission should require applicants to submit documents and data, beyond those needed to perform the Appendix A analysis, including the kinds of information submitted to the antitrust agencies as part of the initial Hart-Scott-Rodino [142] notification, and should require applicants to submit supply curve analyses for each relevant market.

2. Commission Determination

202. With respect to commenters' specific concerns regarding the Commission's merger policy, we are not persuaded at this time to change our current policies. Our standard of review is flexible enough to consider any changes in market structure that ultimately result from the EPAct 2005 and the repeal of PUHCA 1935. However, once the Commission has gained more experience in evaluating section 203 applications under the new statute, we may consider reevaluating our merger policy in general. Accordingly, we adopt the proposal set forth in the NOPR with respect to amended sections 2.26(e) and (f).

IV. Information Collection Statement

203. Office of Management and Budget (OMB) regulations require that OMB approve certain reporting and recordkeeping requirements (collections of information) imposed by an agency.[143] The information collection requirements in this Final Rule are identified under the Commission's data collection, FERC-519, “Applications Under Federal Power Act Section 203.” Under section 3507(d) of the Paperwork Reduction Act of 1995,[144] the reporting requirements in this rulemaking will be submitted to OMB for review.

204. Respondents subject to the filing requirements of this Final Rule will not be penalized for failing to respond to this collection of information unless the collection of information displays a valid OMB control number. “Display” is defined as publishing the OMB control number in regulations, guidelines, forms or other issuances in the Federal Register (for example, in the preamble or regulatory text for the Final Rule containing the information collection).[145]

Public Reporting Burden: In the NOPR, the Commission stated that the regulations that it proposed should have a minimal impact on the current reporting burden associated with an individual application, as they would not substantially change the filing requirements with which section 203 applicants must currently comply. Further, the Commission stated that it did not expect the total number of section 203 applications to increase substantially under amended section 203. The Commission received 42 comments on its NOPR and only GE EFS specifically addressed its estimates. GE EFS notes that the “Information Collection Statement” in the NOPR states that “the Commission does not expect the total number of section 203 applications under amended section 203 to increase substantially.” [146] GE EFS comments that, unless the Commission limits the overly broad scope of its proposed rules, the Commission will be burdened with applications for acquisitions of securities of QFs, which heretofore were exempted from section 203.[147] As noted above, we believe that the blanket authorizations granted herein for certain holding company acquisitions of non-voting securities and up to 9.9 percent of voting securities in electric utility companies will adequately address GE EFS' concerns. To the extent additional blanket authorizations are needed or appropriate, we will consider those on a case-by-case basis. Thus, we believe that we have lessened the burden on applicants subject to the requirements of amended section 203, including for applicants seeking to acquire securities of QFs. Therefore, the Commission will retain its initial estimates.

The Commission is submitting a copy of this Final Rule to OMB for review and approval. In their notice of December 9, 2005, OMB took no action on the NOPR, instead deferring their approval until review of the Final Rule.

Title: FERC-519, Applications Under Federal Power Act Section 203.

Action: Proposed Information Collection.

OMB Control No: 1902-0082.

Respondents: Businesses or other for profit.

Necessity of the Information: The information collected under the requirements of FERC-519 is used by the Commission to implement section 203 of the Federal Power Act and the Code of Federal Regulations under 18 CFR part 33 and 18 CFR 2.26. This Final Rule is limited to implementing amended section 203 of the FPA, which directs the Commission to adopt a rule to do so. Further, this Final Rule does not substantially change the current filing requirements or regulations that applicants must comply with for transactions subject to FPA section 203.

205. Interested persons may obtain information on this information collection by contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC Start Printed Page 137320426, Attention: Michael Miller, Officer of the Executive Director, phone: (202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov.

206. Comments concerning this information collection can be sent to the Office of Management and Budget, Office of Information and Regulatory Affairs, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-4650, fax: (202) 395-7285].

V. Environmental Analysis

207. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.[148] The Commission concludes that neither an Environmental Assessment or an Environmental Impact Statement is required for this Final Rule under section 380.4(a)(2)(ii) of the Commission regulations, which provides a “categorical exclusion for rules that do not substantively change the effect of legislation.”[149]

VI. Regulatory Flexibility Act Certification

208. The Regulatory Flexibility Act of 1980 (RFA)[150] generally requires a description and analysis of final rules that will have a significant economic impact on a substantial number of small entities.[151] The Commission is not required to make such analyses if a rule would not have such an effect.

209. The Commission adheres to its certification in the NOPR that this rulemaking will not have a significant economic impact upon a substantial number of small entities. As stated in the NOPR, EPAct 2005 directs the Commission to issue a rule adopting procedures for the expeditious consideration of applications for the approval of dispositions, consolidations, or acquisition, under this section. In accordance with this directive, this rule implements section 203 of the FPA. In particular, the rule increases the value threshold for filing a section 203 application with the Commission from transactions in excess of $50,000 to transactions in excess of $10 million (under amended section 203 of the FPA). Further, the RFA directs agencies to consider four regulatory alternatives to be considered in a rulemaking to lessen the impact on small entities: Tiering or establishment of different compliance or reporting requirements for small entities, classification, consolidation, clarification or simplification of compliance and reporting requirements, performance rather than design standards, and exemptions. In this Final Rule, the Commission has adopted tiering, and classification and simplification by classifying the types of holding acquisitions that qualify for a grant of blanket approval under section 203(a)(2). Further, the rule does not substantially change the current requirements and regulations that applicants must comply with for transactions subject to FPA section 203. Therefore, the Commission certifies that this rule will not have a significant impact on a substantial number of small entities.

VII. Document Availability

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

211. From the Commission's Home Page on the Internet, this information is available in the Commission's document management system, eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type “RM05-34” in the docket number field.

212. User assistance is available for eLibrary and the FERC's Web site during normal business hours. For assistance, please contact FERC Online Support at 1-866-208-3676 (toll free) or 202-502-6652 (e-mail at FERCOnlineSupport@FERC.gov), or the Public Reference Room at 202-502-8371, TTY 202-502-8659 (e-mail at public.referenceroom@ferc.gov).

VIII. Effective Date and Congressional Notification

213. This Final Rule will take effect on February 8, 2006. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is not a major rule within the meaning of section 251 of the Small Business Regulatory Enforcement Fairness Act of 1996.[152] The Commission will submit this Final Rule to both houses of Congress and the General Accountability Office.[153]

Start List of Subjects

List of Subjects

End List of Subjects Start Signature

By Order of the Commission.

Magalie R. Salas,

Secretary.

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In consideration of the foregoing, the Commission amends Chapter I, Title 18,

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PART 2—GENERAL POLICY AND INTERPRETATIONS

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1. The authority citation for part 2 is revised to read as follows:

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Authority: 5 U.S.C. 601; 15 U.S.C. 717-717w, 3301-3432; 16 U.S.C. 792-825y, 2601-2645; 42 U.S.C. 4321-4361, 7101-7352; Pub. L. No. 109-58, 119 Stat. 594.2.

End Authority Start Amendment Part

2. Section 2.26 is amended by revising paragraph (e) and by adding paragraph (f) to read as follows:

End Amendment Part
Policies concerning review of applications under section 203.
* * * * *

(e) Effect on regulation. (1) Where the affected state commissions have authority to act on the transaction, the Commission will not set for hearing whether the transaction would impair effective regulation by the state commissions. The application should state whether the state commissions have this authority.

(2) Where the affected state commissions do not have authority to act on the transaction, the Commission may set for hearing the issue of whether the transaction would impair effective state regulation.

(f) Under section 203(a)(4) of the Federal Power Act (16 U.S.C. 824b), in Start Printed Page 1374reviewing a proposed transaction subject to section 203, the Commission will also consider whether the proposed transaction will result in cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company, unless that cross-subsidization, pledge, or encumbrance will be consistent with the public interest.

Start Part

PART 33—APPLICATIONS UNDER FEDERAL POWER ACT SECTION 203

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3. The authority citation for part 33 is revised to read as follows:

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Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352; Pub. L. No. 109-58, 119 Stat. 594.

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4. The heading of part 33 is revised to read as set forth above.

End Amendment Part Start Amendment Part

5. Section 33.1 is revised to read as follows:

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Applicability, definitions, and blanket authorizations.

(a) Applicability. (1) The requirements of this part will apply to any public utility seeking authorization under section 203 of the Federal Power Act to:

(i) Sell, lease, or otherwise dispose of the whole of its facilities subject to the jurisdiction of the Commission, or any part thereof of a value in excess of $10 million;

(ii) Merge or consolidate, directly or indirectly, such facilities or any part thereof with those of any other person, by any means whatsoever;

(iii) Purchase, acquire, or take any security with a value in excess of $10 million of any other public utility; or

(iv) Purchase, lease, or otherwise acquire an existing generation facility:

(A) That has a value in excess of $10 million; and

(B) That is used in whole or in part for wholesale sales in interstate commerce by a public utility.

(2) The requirements of this part shall also apply to any holding company in a holding company system that includes a transmitting utility or an electric utility if such holding company seeks to purchase, acquire, or take any security with a value in excess of $10 million of, or, by any means whatsoever, directly or indirectly, merge or consolidate with, a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility, or an electric utility company, with a value in excess of $10 million.

(b) Definitions. For the purposes of this part, as used in section 203 of the Federal Power Act (16 U.S.C. 824b)

(1) Existing generation facility means a generation facility that is operational at or before the time the section 203 transaction is consummated. “The time the transaction is consummated” means the point in time when the transaction actually closes and control of the facility changes hands. “Operational” means a generation facility for which construction is complete (i.e., it is capable of producing power). The Commission will rebuttably presume that section 203(a) applies to the transfer of any existing generation facility unless the utility can demonstrate with substantial evidence that the generator is used exclusively for retail sales.

(2) Non-utility associate company means any associate company in a holding company system other than a public utility or electric utility company that has wholesale or retail customers served under cost-based regulation.

(3) Value when applied to:

(i) Transmission facilities, generation facilities, transmitting utilities, electric utility companies, and holding companies, means the market value of the facilities or companies for transactions between non-affiliated companies; the Commission will rebuttably presume that the market value is the transaction price. For transactions between affiliated companies, value means original cost undepreciated, as defined in the Commission's Uniform System of Accounts prescribed for public utilities and licensees in part 101 of this chapter, or original book cost, as applicable;

(ii) Wholesale contracts, means the market value for transactions between non-affiliated companies; the Commission will rebuttably presume that the market value is the transaction price. For transactions between affiliated companies, value means total expected nominal contract revenues over the remaining life of the contract; and

(iii) Securities, means market value for transactions between non-affiliated companies; the Commission will rebuttably presume that the market value is the agreed-upon transaction price. For transactions between affiliated companies, value means market value if the securities are widely traded, in which case the Commission will rebuttably presume that market value is the market price at which the securities are being traded at the time the transaction occurs; if the securities are not widely traded, market value is determined by:

(A) Determining the value of the company that is the issuer of the equity securities based on the total undepreciated book value of the company's assets;

(B) Determining the fraction of the securities at issue by dividing the number of equity securities involved in the transaction by the total number of outstanding equity securities for the company; and

(C) Multiplying the value determined in paragraph (b)(3)(iii)(A) of this section by the value determined in paragraph (b)(3)(iii)(B) of this section (i.e., the value of the company multiplied by the fraction of the equity securities at issue).

(4) The terms associate company, electric utility company, foreign utility company, holding company, and holding company system have the meaning given those terms in the Public Utility Holding Company Act of 2005. The term holding company does not include: A State, any political subdivision of a State, or any agency, authority or instrumentality of a State or political subdivision of a State; or an electric power cooperative.

(c) Blanket Authorizations. (1) Any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to purchase, acquire, or take any security of:

(i) A transmitting utility or company that owns, operates, or controls only facilities used solely for transmission in intrastate commerce and/or sales of electric energy in intrastate commerce;

(ii) A transmitting utility or company that owns, operates, or controls only facilities used solely for local distribution and/or sales of electric energy at retail regulated by a state commission; or

(iii) A transmitting utility or company if the transaction involves an internal corporate reorganization that does not present cross-subsidization issues and does not involve a traditional public utility with captive customers.

(2) Any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to purchase, acquire, or take:

(i) Any non-voting security (that does not convey sufficient veto rights over management actions so as to convey control) in a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility or an electric utility company; or

(ii) Any voting security in a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a Start Printed Page 1375transmitting utility or an electric utility company if, after the acquisition, the holding company will own less than 10 percent of the outstanding voting securities; or

(iii) Any security of a subsidiary company within the holding company system.

(3) The blanket authorizations granted under paragraph (c)(2) of this section are subject to the conditions that the holding company shall not:

(i) Borrow from any electric utility company subsidiary in connection with such acquisition; or

(ii) Pledge or encumber the assets of any electric utility company subsidiary in connection with such acquisition;

(4) A holding company granted blanket authorizations in section (c)(2) shall provide the Commission with the same information, on the same basis, that the holding company provides to the Securities and Exchange Commission in connection with any securities purchased, acquired or taken pursuant to this section.

(5) Any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to acquire a foreign utility company. However, if such holding company or any of its affiliates, its subsidiaries, or associate companies within the holding company system have captive customers in the United States, the authorization is conditioned on the holding company verifying by a duly authorized corporate official of the holding company that the proposed transaction:

(i) Will not have any adverse effect on competition, rates, or regulation; and

(ii) Will not result in, at the time of the transaction or in the future:

(A) Any transfer of facilities between a traditional utility associate company with wholesale or retail customers served under cost-based regulation and an associate company;

(B) Any new issuance of securities by traditional utility associate companies with wholesale or retail customers served under cost-based regulation for the benefit of an associate company;

(C) Any new pledge or encumbrance of assets of a traditional utility associate company with wholesale or retail customers served under cost-based regulation for the benefit of an associate company; or

(D) Any new affiliate contracts between non-utility associate companies and traditional utility associate companies with wholesale or retail customers served under cost-based regulation, other than non-power goods and services agreements subject to review under sections 205 and 206 of the Federal Power Act.

(iii) A transaction by a holding company subject to the conditions in paragraphs (c)(5)(i) and (ii) of this section will be deemed approved only upon filing the information required in paragraphs (c)(5)(i) and (ii) of this section.

Start Amendment Part

6. Section 33.2 is amended to add paragraph (j) to read as follows:

End Amendment Part
Contents of application—general information requirements.
* * * * *

(j) An explanation, with appropriate evidentiary support for such explanation (to be identified as Exhibit M to the application):

(1) Of how applicants are providing assurance that the proposed transaction will not result in cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company; or

(2) If no such assurance can be provided, an explanation of how such cross-subsidization, pledge, or encumbrance will be consistent with the public interest.

Start Amendment Part

7. Section 33.11 is added to read as follows:

End Amendment Part
Commission procedures for the consideration of applications under section 203 of the FPA.

(a) The Commission will act on a completed application for approval of a transaction (i.e., one that is consistent with the requirements of this part) not later than 180 days after the completed application is filed. If the Commission does not act within 180 days, such application shall be deemed granted unless the Commission finds, based on good cause, that further consideration is required to determine whether the proposed transaction meets the standards of section 203(a)(4) of the FPA and issues, by the 180th day, an order tolling the time for acting on the application for not more than 180 days, at the end of which additional period the Commission shall grant or deny the application.

(b) The Commission will provide for the expeditious consideration of completed applications for the approval of transactions that are not contested, do not involve mergers, and are consistent with Commission precedent. The transactions that would generally warrant expedited review include:

(1) A disposition of only transmission facilities, particularly those that both before and after the transaction remain under the functional control of a Commission-approved regional transmission organization or independent system operator; and

(2) Transactions that do not require an Appendix A analysis.[1]

Note:

The following appendix will not appear in the Code of Federal Regulations.

Appendix List of Intervenors and Commenters

Intervenors

California Public Utilities Commission.

Edison Mission Energy, Edison Mission Marketing & Trading, Inc., and Midwest Generation EME, LLC.

Public Service Commission of Wisconsin.

Public Utilities Commission of Ohio.

Southern California Edison Company.

Commenters

AcronymName
ACCAmerican Chemistry Counsel.
AEPAmerican Electric Power Service Corporation.
AESThe AES Corporation.
AmerenAmeren Services Company.
APPA/NRECAAmerican Public Power Association and the National Rural Electric Cooperative Association.
Chairman BartonCongressman Joe Barton.
ConstellationConstellation Energy Group Inc.
Duke/CinergyDuke Energy Corporation and Cinergy Corporation.
EEIEdison Electric Institute.
Start Printed Page 1376
EntergyEntergy Services, Inc.
E.ONE.ON AG.
EPSAElectric Power Supply Association.
FirstEnergyFirstEnergy Service Company.
GE EFSGE Energy Financial Services.
HECOHawaiian Electric Company, Inc.
Independent SellersCogentrix Energy, Inc. and The Goldman Sachs Group, Inc.
Indiana CommissionIndiana Utility Regulatory Commission.
Industrial ConsumersElectricity Consumers Resource Council, the American Iron and Steel Institute, the American Chemistry Council, and the PJM Industrial Customer Coalition.
International TransmissionInternational Transmission Company.
Kentucky CommissionKentucky Public Service Commission.
MidAmericanMidAmerican Energy Holdings Company.
Missouri CommissionMissouri Public Utilities Commission.
Morgan StanleyMorgan Stanley Capital Group Inc.
NAFCNational Alliance for Fair Competition.
NARUCNational Association of Regulatory Utility Commissioners.
NASUCANational Association of State Utility Consumer Advocates.
National GridNational Grid USA.
New Jersey BoardNew Jersey Board of Public Utilities.
North Carolina CommissionNorth Carolina Utilities Commission.
Ohio CommissionPublic Utilities Commission of Ohio.
Oklahoma CommissionOklahoma Corporation Commission.
PNMPNM Resources, Inc.
Progress EnergyProgress Energy, Inc.
Public CitizenEnergy Program of Public Citizen, Inc.
Scottish PowerScottish Power plc.
Southern CompaniesSouthern Company Services, Inc.
SuezSUEZ Energy North America.
TANCTransmission Agency of Northern California.
TAPSGTransmission Access Policy Study Group.
UWUAUtility Workers Union of America, AFL-CIO.
Wisconsin ElectricWisconsin Electric Power Company.
XcelXcel Energy Services, Inc.
End Supplemental Information

Footnotes

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

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3.  EPAct 2005 §§ 1281 et seq.

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5.  Transactions Subject to FPA Section 203, 70 FR 58,636 (October 7, 2005), FERC Stats. & Regs. ¶ 32,589 (2005).

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6.  EPAct 2005 sections 1261 et seq. Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005, Order No. 667, FERC Stats. & Regs. ¶ 31,197 (2005) (PUHCA 2005 Final Rule).

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7.  PUHCA 2005 Final Rule at P 17. Specifically, in the PUHCA Final Rule, the Commission stated that we intend to hold a technical conference no later than one year after PUHCA 2005 becomes effective to evaluate whether additional exemptions, different reporting requirements, or other regulatory actions need to be considered. The Commission's regulations implementing PUHCA 2005 take effect on February 8, 2006.

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8.  EPAct 2005's amendments to FPA section 203 take effect on February 8, 2006. We will generally refer to EPAct 2005's amended section 203 of the FPA as “amended” or “new” section 203. All other references to FPA section 203 are as it exists now.

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9.  Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, 61 FR 68,595 (Dec. 30, 1996), FERC Stats. & Regs. ¶ 31,044 (1996), reconsideration denied, Order No. 592-A, 62 FR 33,340 (June 19, 1997), 79 FERC ¶ 61,321 (1997) (Merger Policy Statement).

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10.  Although the Commission applies these factors to all section 203 transactions, not just mergers, the filing requirements and the level of detail required may differ. Id. at 30,113 n.7. See also 18 CFR 2.26 (2005) (codifying the Merger Policy Statement).

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11.  U.S. Department of Justice and Federal Trade Commission, Horizontal Merger Guidelines, 57 FR 41,552 (1992), revised, 4 Trade Reg. Rep. (CCH) ¶ 13,104 (Apr. 8, 1997).

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12.  Merger Policy Statement at 30,119-20.

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13.  See id. at 30,121-24.

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14.  15 U.S.C. 79a et seq. (2000).

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15.  Merger Policy Statement at 30,125; see also Atlantic City Electric Co. and Delmarva Power & Light Co., 80 FERC ¶ 61,126 at 61,412, order denying reh'g, 81 FERC ¶ 61,173 (1997). With respect to a transaction's effect on state regulation, where the state commissions have authority to act on the transaction, the Commission stated that it intends to rely on them to exercise their authority to protect state interests.

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16.  Revised Filing Requirements Under Part 33 of the Commission's Regulations, Order No. 642, 65 FR 70,983 (Nov. 28, 2000), FERC Stats. & Regs., July 1996-Dec. 2000 ¶ 31,111 (2000), order on reh'g, Order No. 642-A, 66 FR 16,121 (Mar. 23, 2001), 94 FERC ¶ 61,289 (2001) (codified at 18 CFR Part 33 (2005)) (Filing Requirements Rule).

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17.  Filing Requirements Rule at 31,902 & 31,907. The Commission clarified that, if it later determined that a filing raised competitive issues, the Commission would evaluate those issues and direct the applicant to submit any data needed to satisfy the Commission's concerns. Id. at n.79.

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18.  Id. at 31,873.

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19.  Id. at 31,876.

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20.  Id. §§ 1261, 1274. PUHCA 2005 Final Rule at P 1.

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21.  Section 203(b) states:

The Commission may grant any application for an order under this section in whole or in part and upon such terms and conditions as it finds necessary or appropriate to secure the maintenance of adequate service and the coordination in the public interest of facilities subject to the jurisdiction of the Commission. The Commission may from time to time for good cause shown make such orders supplemental to any order made under this section as it may find necessary or appropriate.

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22.  70 FR 58,636 (October 7, 2005). On October 19, 2005, an errata notice was published in the Federal Register (70 FR 60,748), correcting Paragraph 1, footnote 4 of the NOPR to refer to February 8, 2006, as opposed to February 3, 2006.

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23.  The commenters are listed in an appendix to this order.

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24.  Because proposed section 33.1(a) is almost identical, with minor exceptions, to amended sections 203(a)(1)(A)-(D) and (a)(2), which are summarized in section II.B. above and set forth in the regulatory text, we will not recite that text here.

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25.  PUHCA 2005 § 1266(a).

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26.  Russello v. United States, 464 U.S. 16, 23 (1983) (internal citations omitted).

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27.  EPSA Comments at 5.

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28.  EPAct 2005 § 1262(5).

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29.  E.g., Congressman Joe Barton (Chairman Barton), The AES Corporation (AES), Edison Electric Institute (EEI), Entergy Services, Inc. (Entergy), E.ON AG (E.ON), EPSA, GE Energy Financial Services (GE EFS), Cogentrix Energy, Inc. and The Goldman Sachs Group, Inc. (Independent Sellers), National Grid USA (National Grid), PNM Resources, Inc. (PNM), Progress Energy, Inc. (Progress Energy), Scottish Power plc (Scottish Power), and SUEZ Energy North America (Suez).

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30.  EPAct 2005 1291(b)(22).

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32.  See, e.g., AES Comments at 5. For example, AES states that, unless “electric utility” is implicitly defined only to include domestic entities, the provisions of sections 111-117 of PURPA, which relate in part to the actions of state commissions as they affect “electric utilities,” become a complete non sequitur.

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33.  E.g., E.ON, Chairman Barton, and Suez.

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34.  E.g., EEI, Entergy, E.ON, Independent Sellers, National Grid, Progress Energy, and Scottish Power (citing, e.g., PUHCA 2005 §§ 1264 & 1266).

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35.  See, e.g., Chairman Barton Comments at 3.

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36.  E.g., Chairman Barton, EEI, Hawaiian Electric Company, Inc. (HECO), National Association of Regulatory Utility Commissioners (NARUC), National Grid, PNM, and Progress Energy.

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37.  E.g., American Chemistry Counsel (ACC), APPA/NRECA, EPSA, GE EFS, Independent Sellers, and Transmission Access Policy Study Group (TAPSG).

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38.  16 U.S.C. 824a-3 (2000). Section 210(e) provides certain exemptions for cogeneration and small power producers.

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39.  Independent Sellers Comments at 9.

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40.  Public Citizen Comments at 10.

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41.  Id. at 10-11.

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42.  EPAct 2005 1289(a).

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43.  See Reiter v. Sonotone Corp., 442 U.S. 330, 339 (1979) (finding that settled principles of statutory construction require giving “effect, if possible, to every word Congress used”); see also 2A Statutes and Statutory Construction § 46.06 (N. Singer 6th Ed. 2000 Revision) (a statute must be construed so that no part will be void or insignificant).

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44.  Commenters' alternative proposed definitions are also discussed below in the specific context of the requested exemptions of foreign transactions.

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45.  While both the FPA and PURPA contain definitions of “electric utility,” neither contains a definition of “electric utility company.”

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46.  See, e.g., Indiana Michigan Power Co. v. Dept. of Energy, 88 F.3d 1272, 1276 (DC Cir. 1996) (vacating an agency's decision where the agency's “treatment of [a] statute is not an interpretation but a rewrite”); United States v. Plaza Health Laboratories, Inc., 3 F.3d 643, 655 (2nd Cir. 1993), cert. denied sub nom. United States v. Villegas, 512 U.S. 1245 (1994) (“neither agencies nor courts should rewrite the statute to be more ‘reasonable’ * * * than Congress intended”).

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47.  The only legislative history on this issue is a colloquy between Senators Bingaman and Domenici, Ranking Member and Chairman, respectively, of the Senate Committee on Energy and Natural Resources. See Senate Floor Statements by Senators Bingaman (D-NM) and Domenici (R-NM), H.R. 6, Energy Policy Act of 2005, 151 Cong. Rec. S9359 (July 29, 2005) (discussing concerns regarding Commission approval of certain foreign transactions outside of the United States).

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48.  EPAct 2005 § 1262(5).

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49.  Id. § 1291(b)(22).

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50.  In fact, the key FPA provisions in which the term “electric utility” is used are sections 210 and 211. Section 210, both pre- and post-EPAct 2005, permits the Commission to order an interconnection with the facilities of persons that sell energy in interstate or intrastate commerce. The current interconnection between ERCOT and the interstate grid was pursuant to a Commission order under sections 210 and 211 of the FPA. See Central Power & Light Co., 17 FERC ¶ 61,078 (1981), order on reh'g, 18 FERC ¶ 61,100 (1982). Although commenters are correct that most of part II of the FPA is limited to interstate commerce, Congress has made specific exceptions in certain FPA provisions, and that includes the definition of “electric utility.” Cf. Indiana Michigan Power Co. v. Dept. of Energy, 88 F.3d 1272, 1276 (DC Cir. 1996) (“The [agency's] treatment of this statute is not an interpretation but a rewrite.”); United States v. Plaza Health Laboratories, Inc., 3 F.3d 643, 655 (2nd Cir. 1993) (stating “neither agencies nor courts should rewrite the statute to be more ‘reasonable’ * * * than Congress intended”); Newman v. Love, 962 F.2d 1008, 1013 (Fed. Cir. 1992) (rejecting an agency's “attempt to rewrite” a statute to contain costs or to avoid what it views as an inappropriate allocation of benefits).

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51.  An acquisition or merger involving “any company that owns or operates facilities used for the generation, transmission, or distribution of electric energy for sale” is not on its face limited to interstate facilities.

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52.  Illinois Power Co., 67 FERC ¶ 61,136 (1994) (noting that the Commission does not have jurisdiction over public holding company mergers or consolidations, but concluding that, ordinarily, when public utility holding companies merge, an indirect merger involving their public utility subsidiaries also takes place, and that Commission approval under section 203 would be required).

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53.  Similarly, although not raised by commenters, the blanket authorization would apply to any organized Territory of the United States.

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54.  While QFs themselves currently are exempt from section 203's filing requirements by virtue of the Commission's PURPA regulations, PURPA does not give us authority to exempt holding companies that own QFs.

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55.  We note that a holding company acquisition of securities of an EWG would in some circumstances trigger section 203 review in any event by virtue of section 203(a)(1). This is because the EWG could well be a public utility and, to the extent the holding company acquired “control” of the EWG, we would construe the EWG to be “disposing” of its jurisdictional facilities and thus required to file for approval under section 203(a). A similar situation involving acquisition of securities of a QF would not trigger section 203 review, since QFs currently are exempted from FPA section 203 filing requirements by the Commission's PURPA regulations.

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56.  See, e.g., GE EFS and Independent Sellers.

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58.  NOPR at P 38 (citing EPAct 2005 1291(b)(1)(B)(23)).

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59.  Id. at P 39 (citing EPAct 2005 1262(2), (8), & (9)).

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60.  E.g., GE EFS, HECO, Independent Sellers, and the Electricity Consumers Resource Council, the American Iron and Steel Institute, the American Chemistry Council, and the PJM Industrial Customer Coalition (collectively, Industrial Consumers).

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61.  Industrial Consumers Comments at 6.

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62.  APPA/NRECA Comments at 18.

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63.  We note that, prior to EPAct 2005, the FPA term “transmitting utility” was not limited to entities that own or operate transmission facilities used “in interstate commerce.” EPAct 2005, however, modified the definition to, among other things, limit it to facilities used in interstate commerce.

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64.  EPAct 2005 1262(8).

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67.  NOPR at P 37.

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70.  See, e.g., Senate Floor Statement by Senator Bingaman (D-NM), H.R. 6, Energy Policy Act of 2005, Congressional Record at S9258 (July 28, 2005) (stating that “in the area of electric utility mergers, we have expanded the jurisdiction of [the Commission] over mergers involving existing generation plants; that is, plants that are in existence at the time the merger takes place.”).

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71.  NOPR at P 44.

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72.  These are examples only. This list is not intended to be exhaustive.

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73.  E.g., APPA/NRECA, Indiana Commission, Kentucky Commission, NARUC, NASUCA, and New Jersey Board of Public Utilities (New Jersey Board).

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75.  NOPR at P 42.

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78.  NOPR at P 30.

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79.  Id. at P 32.

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80.  Id. at P 33.

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81.  Chairman Barton does not take a position on the appropriate measure of value, but believes that the Commission should consider whether the use of market value, by bringing more transactions under section 203, will unnecessarily increase regulatory burden because of the potential for disputes concerning the market value of transactions. He also suggests that some utilities will make section 203 filings needlessly to show the Commission that section 203 does not apply. He notes that undepreciated original cost value is a simple way to value transactions. Chairman Barton Comments at 6.

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82.  Boston Edison Co. Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 (1991) (Edgar). The Edgar standard of review is designed to prevent affiliate abuse and to ensure prices that are consistent with competitive outcomes.

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83.  E.g., Indiana Commission, Kentucky Commission, New Jersey Board, International Transmission Company (International Transmission), EPSA, Scottish Power, TAPSG, and UWUA.

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84.  E.g., EEI, Duke/Cinergy, TAPSO, Indiana Commission, Kentucky Commission, Progress Energy, and Scottish Power.

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85.  E.g., EEI, Ameren, Progress Energy, Southern Companies, and Duke/Cinergy.

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86.  NARUC, Missouri Commission, the Public Utilities Commission of Ohio (Ohio Commission), APPA/NRECA, NASUCA, and Constellation Energy Group Inc. (Constellation).

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87.  E.g., EEI, First Energy, Ameren, Duke/Cinergy, Entergy, International Transmission, EPSA, Independent Sellers, Scottish Power, Morgan Stanley, Indiana Commission, and Missouri Commission.

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88.  In this context, “mark to market” refers to the process whereby the book value or collateral value of an asset such as a multiyear contract or power purchase agreement is adjusted to reflect current market value for the applicable period.

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89.  Accounting and Reporting of Financial Instruments, Comprehensive Income, Derivatives and Hedging Activities, Order No. 627, 67 FR 67,691 (Oct. 10, 2002), FERC Stats. & Regs. ¶ 32,558 (2002).

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90.  For example, EEI proposes that, for securities that are not widely traded, the Commission should allow companies to utilize the Edgar guidelines. If the Edgar guidelines are not applicable to a particular case, EEI suggests the following: For equity securities, a three part determination should be utilized to determine value: (i) Determining the value of the company that is the issuer of the equity securities based on the depreciated net book value of the company's assets; (ii) determining the fraction of the securities at issue by dividing the number of equity securities involved in the transaction by the total number of outstanding equity securities for the company; and (iii) multiplying (i) by (ii) (i.e., the value of the company multiplied by the fraction of the equity securities at issue). EEI Comments at 11.

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92.  Book cost, as used here, refers to original book cost.

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93.  Reporting Requirement for Changes in Status for Public Utilities with Market-Based Rate Authority, Order No. 652, 70 FR 8,253 (Feb. 18, 2005), FERC Stats. & Regs. ¶ 31,175, order on reh'g, 111 FERC ¶ 61,413 (2005).

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94.  NOPR at P 35.

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95.  E.g., Kentucky Commission, NARUC, Oklahoma Commission, Ameren, Constellation, EEI, FirstEnergy, Progress Energy, and Southern Companies. Some commenters argue that the Commission's existing record-keeping and reporting requirements, including the information supplied under the FERC Form 1, Order No. 652, and Change in Status reports, are more than adequate.

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96.  NARUC Comments at 7-8.

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97.  See 16 U.S.C. 825o-1 (2000), as amended by EPAct 2005 1284(e).

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98.  While there are several different types of cash management programs, a cash management program generally involves pooling the cash resources of several affiliated companies into a “money pool.” Affiliates can then borrow against the funds in the pool, often at below market rates. Additionally, the parent company is often able to achieve a higher rate of return on its money pool investments than any single affiliate could on its own. For a more detailed discussion of cash management programs. See Regulation of Cash Management Practices, Order No. 634, 68 FR 40,500 (July 8, 2003), III FERC Stats. & Regs. ¶ 31,145 (June 26, 2003), Order No. 634-A, 68 FR 61,993 (Oct. 31, 2003), FERC Stats. & Regs. ¶ 31,152 (Oct. 23, 2003) (Cash Management Rule).

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100.  The term “security” is defined in FPA section 3(16) as “any note, stock, treasury stock, bond, debenture, or other evidence of indebtedness of a corporation * * *.”

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101.  We note, however, that it is possible, in some circumstances, for non-voting securities to convey sufficient “veto” rights over management actions as to convey “control” that triggers section 203. The Commission has addressed similar issues for purposes of evaluating independence of entities that ask for RTO status, and the SEC considered similar issues through its “no action” letter process in applying PUHCA 1935. We anticipate that our treatment of such issues under amended section 203 will generally be consistent with these precedents. If uncertainty exists as to whether significant veto rights could convey control, entities should seek a ruling from the Commission to determine whether section 203 approval is required.

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102.  See, e.g., EEI Comments at 27-31.

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103.  See Cash Management Rule at P 29.

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104.  We also note that under our existing Cash Management Rule, changes to existing or new cash management agreements (including money pool arrangements and other internal corporate financing arrangements) must be filed with the Commission.

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105.  See Cash Management Rule at P 29 (discussing exception for non-voting interests that convey significant veto rights).

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106.  See, e.g., Senate Floor Statement by Senators Domenici (R-NM), H.R. 6, Energy Policy Act of 2005, 151 Cong. Rec. S9256 (July 28, 2005) (stating that “this should bring much more capital investment into the utility companies that make up this powerful institution, this entity called the grid of the United States.”).

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107.  Accordingly, the Commission directs that the purchaser of such securities file with the Commission copies of SEC schedules 13D, 13G, and 13F. SEC schedule 13D is required to be filed by any entity acquiring beneficial ownership of more than 5 percent of a class of a company's securities. The schedule 13D filing requires, among other things, a statement of the purpose(s) of the acquisition of the securities of the issuer and a description of any plans or proposals the reporting person may have that relate to or would result in the acquisition of additional securities of the issuer; any extraordinary corporate transactions, such as a merger, reorganization or liquidation of the issuer or its affiliates; and any changes in the board of directors or management of the issuer. Schedule 13G is the same form, but is used when the person or entity is making the purchase for investment only. Institutional investment managers who exercise investment discretion over $100 million or more must report their holdings on SEC schedule 13F. We note that these schedules required for a grant of blanket authorization under section 203(a)(2) should impose only a de minimis burden on the holding company, since we are requiring merely the same information that is filed with the SEC. Should the SEC change its reporting requirements, this information must continue to be filed with the Commission.

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108.  NOPR at P 45.

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110.  See, e.g., Sierra Pacific, 95 FERC ¶ 61,193; Boston Edison Co., 80 FERC ¶ 61,274 (1997).

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111.  NOPR at P 46.

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112.  E.g., NARUC, New Jersey Board, Ohio Commission, Oklahoma Commission, Indiana Commission, APPA/NRECA, TANC, TAPSG, NASUCA, and UWUA.

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113.  New Jersey Board Comments at 6 (emphasis in original).

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114.  E.g., Duke/Cinergy, Entergy, EEI, AEP, Ameren, FirstEnergy, Progress Energy, International Transmission, National Grid, and Scottish Power.

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115.  See, e.g., EEI Comments at 20-21; Entergy Comments at 8; Duke/Cinergy Comments at 7.

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116.  E.g., Duke/Cinergy, EEI, Entergy, AEP, Ameren, Progress Energy, PNM, FirstEnergy, International Transmission, National Grid, and Scottish Power (citing NOPR at P 52.).

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117.  AEP Comments at 6-7.

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118.  Customers charged under market-based rates escape the potentially deleterious effects of cross-subsidization, or pledge or encumbrance of utility assets, because the prices are constrained by competition, regardless of the seller's costs. In contrast, captive customers (who pay cost-based rates) require protection. See, e.g., Alpena Power Generation, L.L.C., 110 FERC ¶ 61,199, at P 17 (2005) (finding affiliate abuse concerns were addressed with respect to market-based rate authority because, among other factors, there were no captive customers); Pinnacle West Capital Corp., 95 FERC ¶ 61,300, at 62,024 (2001) (“The focus of the Commission's affiliate abuse concerns in cases involving sales between affiliates at market-based rates thus is protection of captive customers.”); Connectiv Energy Supply, Inc., 91 FERC ¶ 61,076, at 61,268 (2000) (“As the Commission has explained in previous cases, there is a concern whenever a public utility can transact with an affiliated power marketer in such a way as to transfer benefits from a power sale from captive ratepayers to its shareholders.”); The Detroit Edison Co., 84 FERC ¶ 61,197 (1998) (the Commission places no restrictions on power marketer transactions with affiliates that do not have captive customers).

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119.  NOPR at P 48 and 49.

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120.  See Central Vermont Pub. Serv. Corp., 39 FERC ¶ 61,295, at 61,960 (1987) (stating that in cases where the Commission finds sufficient potential for abuse, the Commission may disapprove the transaction or place appropriate conditions on it).

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121.  These protection mechanisms are offered only as examples. Whether these types of protection mechanisms are appropriate in a particular case will depend on the circumstances and the details of the transaction in question. See, e.g., Merger Policy Statement at 30,121-24.

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122.  PUHCA 2005 Final Rule at P 166-73.

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123.  As explained in the Merger Policy Statement, a complete application is one that describes the merger being proposed and that contains all the information necessary to explain how the merger is consistent with the public interest, including an evaluation of the merger's effect on competition, rates, and regulation. Merger Policy Statement at 30,127. The Commission's review process will begin when the application is deemed to be complete.

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124.  NOPR at P 56.

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125.  Id. at P 57.

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126.  NOPR at P 59. The Commission noted that PUHCA 1935 exempted from its requirements certain acquisitions of foreign utility companies by a holding company with operations in the United States. 15 U.S.C. 33 (2000); 17 CFR 250.57 (2005). However, amended section 203 appears to provide no such exemption.

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127.  NOPR at P 64-64. The Commission explained that not included in this category are transactions that merely change upstream ownership interests held by parent companies of public utilities or transactions that do not alter the terms of power supply or power supply costs for captive customers.

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128.  See EEI Comments at 22-23. For example, one verification that EEI proposes is that the proposed transaction results in no transfers of facilities between a traditional utility associate company with wholesale or retail customers served under cost-based regulation and an associate company. Thus, a transaction that results in a transfer of facilities into or out of a traditional utility with captive customers could not qualify for automatic approval.

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129.  E.g., EEI, Duke/Cinergy, Entergy, AEP, Progress Energy, Ameren, AES, EPSA, Scottish Power, and E.ON.

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130.  E.g., EEI Comments at 22-23, 25-26; National Grid Comments at 20-22; AES Comments at 15-19; EPSA Comments at 8-9.

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131.  See, e.g., NARUC Comments at 15-16; Ohio Commission Comments at 8-9; New Jersey Board Comments at 9-10.

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132.  See, e.g., EEI Comments at 24-26; Duke/Cinergy Comments at 10-11; Entergy Comments at 9-11.

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133.  National Grid Comments at 33.

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134.  See, e.g., EEI Comments at 26-27.

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135.  We note that although the Filing Requirements Rule provided that applicants for a transaction involving only transmission facilities need not provide a competitive analysis under §§ 33.3 or 33.4 of the Commission's regulations, it also states that if the Commission determines that a filing nonetheless raises competitive issues, the Commission will evaluate those issues. Filing Requirements Rule at 31,902.

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136.  Regional Transmission Organizations, Order No. 2000, 65 FR 809 (Jan. 6, 2000), FERC Stats. & Regs. ¶ 31,089, at 31,108 (1999), order on reh'g, Order No. 2000-A, 65 FR 12,088 (Mar. 8, 2000), FERC Stats. & Regs. ¶ 31,092 (2000), aff'd sub nom. Public Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (DC Cir. 2001).

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137.  Filing Requirements Rule at 31,902.

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138.  EPAct 2005 § 1263.

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140.  NOPR at P 67. However, the Commission reiterated that applicants are still required to address whether the transaction will have any other effect on the Commission's regulation.

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142.  TAPSG explains that the Hart-Scott-Rodino notification is a far more limited submission required of all utilities subject to the Hart-Scott-Rodino filing requirements and described in 16 CFR part 803 (2005).

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146.  NOPR at P 70.

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147.  GE EFS Comments at 2.

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148.  Order No. 486, Regulations Implementing the National Environmental Policy Act, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987).

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149.  18 CFR 380.4(a)(2)(ii) (2005).

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151.  The RFA definition of “small entity” refers to the definition provided in the Small Business Act, which defines a “small business concern” as a business that is independently owned and operated and that is not dominant in its field of operation. 15 U.S.C. 632. The Small Business Size Standards component of the North American Industry Classification System defines a small electric utility as one that, including its affiliates, is primarily engaged in the generation, transmission, and/or distribution of electric energy for sale and whose total electric output for the preceding fiscal years did not exceed 4 million MWh. 13 CFR 121.201 (2005).

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153.  See 5 U.S.C. 801(a)(1)(A).

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1.  Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, 61 FR 68,595 (Dec. 30, 1996), FERC Stats. & Regs. ¶ 31,044 (1996), reconsideration denied, Order No. 592-A, 62 FR 33,340 (June 19, 1997), 79 FERC ¶ 61,321 (1997) (Merger Policy Statement).

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[FR Doc. 06-77 Filed 1-5-06; 8:45 am]

BILLING CODE 6717-01-P