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Code · REGISTER · 2008-02-29 · Federal Energy Regulatory Commission, Department of Energy · Rules and Regulations

Rules and Regulations. Final rule

53,760 words·~244 min read·/register/2008/02/29/08-894

A research copy — for the controlling text, always check the official state or federal source. Not legal advice.

BILLING CODE 4910-13-M DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 33 [Docket No. RM07-21-000; Order No. 708] Blanket Authorization Under FPA Section 203 Issued February 21, 2008. AGENCY: Federal Energy Regulatory Commission, Department of Energy. ACTION: Final rule. SUMMARY: The Federal Energy Regulatory Commission (Commission) is amending its regulations pursuant to section 203 of the Federal Power Act
(FPA)to provide for additional blanket authorizations under FPA section 203(a)(1). These blanket authorizations will facilitate investment in the electric utility industry and, at the same time, ensure that public utility customers are adequately protected from any adverse effects of such transactions. DATES: *Effective Date:* This Final Rule will become effective March 31, 2008. FOR FURTHER INFORMATION CONTACT: Carla Urquhart (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-8496 Roshini Thayaparan (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-6857 David Hunger (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-8148 Andrew P. Mosier, Jr. (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-6274 SUPPLEMENTARY INFORMATION: Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff 1. On July 20, 2007, the Commission issued a Notice of Proposed Rulemaking 1 to provide for an additional blanket authorization under section 203(a)(1) of the Federal Power Act (FPA). 2 After receiving comments in response to the Blanket Authorization NOPR, the Commission amends Part 33 of the Commission's regulations to add five blanket authorizations under section 203(a)(1). In addition, this Final Rule provides certain clarifications regarding the existing blanket authorizations under section 203. Further, this Final Rule clarifies the definitions of the terms “affiliate” and “captive customers.” These blanket authorizations and clarifications will facilitate investment in the electric utility industry and, at the same time, ensure that public utility customers are adequately protected from any adverse effects of such transactions. 1 *Blanket Authorization Under FPA Section 203,* Notice of Proposed Rulemaking, 72 FR 41640 (July 31, 2007), FERC Stats. & Regs. ¶ 32,619
(2007)(Blanket Authorization NOPR). 2 16 U.S.C. 824b. I. Background 2. The Energy Policy Act of 2005 3 expanded the scope of the corporate transactions subject to the Commission's review under section 203 of the FPA. Among other things, amended section 203:
(1)Expands the Commission's review authority to include authority over certain holding company mergers and acquisitions, as well as certain public utility acquisitions of generating facilities;
(2)requires that, prior to approving a disposition under section 203, the Commission must determine that the transaction would not result in inappropriate cross-subsidization of non-utility affiliates or the pledge or encumbrance of utility assets; 4 and
(3)imposes statutory deadlines for acting on mergers and other jurisdictional transactions. 3 Energy Policy Act of 2005, Pub. L. 109-58, 1289, 119 Stat. 594, 982-83
(2005)(EPAct 2005). 4 Section 203(a)(4) is not an absolute prohibition on the cross-subsidization of a non-utility associate company or the pledge or encumbrance of utility assets for the benefit of an associate company. If the Commission determines that the cross-subsidization, pledge or encumbrance will be consistent with the public interest, the action may be permitted. 3. Through the Order No. 669 rulemaking proceeding, the Commission promulgated regulations adopting certain modifications to 18 CFR 2.26 and Part 33 to implement amended section 203. 5 The Commission also provided blanket authorizations for certain transactions subject to section 203. These blanket authorizations were crafted to ensure that there is no harm to captive customers of franchised public utilities, but sought to accommodate investments in the electric utility industry and market liquidity. Some commenters in the rulemaking proceeding argued that the Commission should have granted additional blanket authorizations that would benefit the marketplace and not harm customers. Other commenters argued that the Commission should adopt additional generic rules to guard against inappropriate cross-subsidization associated with the mergers. Yet other commenters argued that the Commission should modify its competitive analysis for mergers, which has been in place for 10 years. The Commission stated that it would reevaluate these and other issues at a technical conference on the Commission's section 203 regulations as well as certain issues raised in the Order No. 667 rulemaking proceeding implementing the Public Utility Holding Company Act of 2005 (PUHCA 2005). 6 5 *Transactions Subject to FPA Section 203,* Order No. 669, 71 FR 1348 (Jan. 6, 2006), FERC Stats. & Regs. ¶ 31,200 (2005), *order on reh'g,* Order No. 669-A, 71 FR 28422 (May 16, 2006), FERC Stats. & Regs. ¶ 31,214 (2006), *order on reh'g,* Order No. 669-B, 71 FR 42579 (July 27, 2006), FERC Stats. & Regs. ¶ 31,225 (2006). 6 EPAct 2005, Pub. L. 109-58, 1261, *et seq.* , 119 Stat. 594, 972-78
(2005)(PUHCA 2005). *See also Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005,* Order No. 667, 70 FR 75592 (Dec. 20, 2005), FERC Stats. & Regs. ¶ 31,197 (2005), *order on reh'g,* Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ¶ 31,213, *order on reh'g,* Order No. 667-B, 71 FR 42750 (July 28, 2006), FERC Stats. & Regs. ¶ 31,224 (2006), *order on reh'g,* Order No. 667-C, 72 FR 8277 (Feb. 26, 2007), 118 FERC ¶ 61,133 (2007). These issues included matters related to inappropriate cross-subsidization and pledges or encumbrance of utility assets, whether our current merger policy should be revised, and whether additional exemptions, different reporting requirements, or other regulatory action (under PUHCA 2005 or the FPA or Natural Gas Act (NGA)) needed to be considered. 4. On December 7, 2006, the Commission held a technical conference (December 7 Technical Conference) to discuss several of the issues that arose in the Order No. 667 and Order No. 669 rulemaking proceedings. The December 7 Technical Conference discussed a range of topics. The first panel discussed whether there are additional actions, under the FPA or the NGA, that the Commission should take to supplement the protections against cross-subsidization that were implemented in the Order No. 667 and Order No. 669 rulemaking proceedings. The second panel discussed whether, and if so how, the Commission should modify its Cash Management Rule 7 in light of PUHCA 2005 and whether the Commission should codify specific safeguards that must be adopted for cash management programs and money pool agreements and transactions. The third panel discussed whether modifications to the specific exemptions, waivers and blanket authorizations set forth in the Order No. 667 and Order No. 669 rulemaking proceedings are warranted. Post-technical conference comments were accepted. 7 *Regulation of Cash Management Practices,* Order No. 634, 68 FR 40500 (July 8, 2003), FERC Stats. & Regs. ¶ 31,145, *revised,* Order No. 634-A, 68 FR 61993 (Oct. 31, 2003), FERC Stats. & Regs. ¶ 31,152
(2003)(Cash Management Rule). 5. On March 8, 2007, the Commission held a second technical conference (March 8 Technical Conference) to discuss whether the Commission's section 203 policy should be revised and, in particular, whether the Commission's Appendix A merger analysis is sufficient to identify market power concerns in today's electric industry market environment. The first panel discussed whether the Appendix A analysis is appropriate to analyze a merger's effect on competition, given the changes that have occurred in the industry (e.g., the development of Regional Transmission Organizations) and statutory changes (e.g., as a result of the repeal of the Public Utility Holding Company Act of 1935 8 and new authorities given to the Commission in EPAct 2005 9 ). The second panel assessed the factors the Commission uses in reviewing mergers and the coordination between the Commission and other agencies (including state commissions) with merger review responsibility. 8 16 U.S.C. 79a *et seq.* (PUHCA 1935). EPAct 2005 repealed PUHCA 1935. EPAct 2005, Pub L. No. 109-58, 1263. 9 These include new authorities through amended FPA section 203 as well as PUHCA 2005. 6. On July 20, 2007, the Commission took three actions based on the Commission's experience implementing amended FPA section 203 and PUHCA 2005, as well as the record from the Commission's December 7 and March 8 Technical Conferences regarding section 203 and PUCHA 2005. In this docket, the Commission issued the Blanket Authorization NOPR, proposing an additional blanket authorization for certain dispositions of jurisdictional facilities under FPA section 203(a)(1) and seeking comment on additional blanket authorizations under section 203. In addition, in separate proceedings, the Commission issued a policy statement providing additional guidance regarding the Commission's section 203 authority 10 and a notice of proposed rulemaking proposing to codify restrictions on affiliate transactions between franchised public utilities with captive customers and their market-regulated power sales affiliates or non-utility affiliates. 11 10 *FPA Section 203 Supplemental Policy Statement,* 72 FR 42277 (Aug. 2, 2007), FERC Stats. & Regs. ¶ 31,253
(2007)(Supplemental Policy Statement), *order on clarification and reconsideration,* 122 FERC ¶ 61,157 (2008). 11 *Cross-Subsidization Restrictions on Affiliate Transactions,* 72 FR 41644 (July 31, 2007), FERC Stats. & Regs. ¶ 32,618
(2007)(Affiliate Transactions NOPR); *see Cross-Subsidization Restrictions on Affiliate Transactions,* Order No. 707 122 FERC ¶ 61,155
(2008)(Affiliate Transactions Final Rule). II. Blanket Authorization NOPR 7. In the Blanket Authorization NOPR, based on the record from the technical conferences (including both oral and written comments) and the Commission's experience under amended section 203 to date, the Commission proposed to provide for a limited blanket authorization to public utilities under section 203(a)(1). Under this limited blanket authorization, a public utility would be pre-authorized to dispose of less than 10 percent of its voting securities to a public utility holding company but only if, after the disposition, the holding company and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of that public utility. The proposed limited blanket authorization would work in conjunction with the blanket authorization granted to holding companies under section 203(a)(2) in 18 CFR 33.1(c)(2)(ii). 12 The Commission noted that this proposed blanket authorization would not entirely parallel the section 203(a)(2) authorization since the section 203(a)(2) authorization does not contain the “in aggregate” limitation. However, the Commission stated that this limitation would provide better protection against possible transfer of control of a public utility. The Commission sought comment on this limitation. 12 The section 203(a)(2) blanket authorization states that any holding company in a holding company system that includes a transmitting utility or an electric utility may purchase, acquire, or take “[a]ny voting security 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 if, after the acquisition, the holding company will own less than 10 percent of the outstanding voting securities.” 18 CFR 33.1(c)(2)(ii). Because a “transmitting utility” or “electric utility company” may also be a “public utility” as defined in the FPA, the public utility may need to obtain separate authorization for the same transaction under FPA section 203(a)(1), which requires authorization for public utilities to dispose of jurisdictional facilities. 8. The Commission stated that the disposition of such limited voting interests (less than 10 percent), with the proposed “in aggregate” restriction and the existing reporting requirements applicable to holding companies, 13 will not harm competition or captive customers. Moreover, the Commission stated this 10 percent threshold is consistent with the definition of “holding company” under section 1262(8)(A) of PUHCA 2005. Under that definition, any company that has the power to vote 10 percent or more of the securities of a public utility company (or a holding company of a public utility company) triggers holding company status and thus is presumed to raise sufficient concerns about controlling influence over a subsidiary public utility that regulatory oversight is needed. The Commission also found the 10 percent threshold to be consistent with the blanket authorization granted under section 203(a)(2) in the Order No. 669 rulemaking proceeding, under which holding companies are pre-authorized to acquire up to 9.99 percent of voting securities of a public utility. 13 *See, e.g.* , 18 CFR 33.1(c)(4) (requiring the filing of Securities and Exchange Commission
(SEC)Schedule 13D, Schedule 13G, and Form 13F, if applicable); 18 CFR 35.42(a) (effective September 18, 2007, the effective date of *Market-Based Rates For Wholesale Sales Of Electric Energy, Capacity And Ancillary Services By Public Utilities,* Order No. 697, 72 FR 39903 (July 20, 2007), FERC Stats. & Regs. ¶ 31,252 (2007)) (requiring a notification of any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority); 18 CFR 366.4(a) (requiring Form FERC-65 (notification of holding company status)). 9. The Commission further noted that, as part of the existing “parallel” blanket authorization under section 203(a)(2), the Commission already requires the holding company to provide to the Commission copies of any Schedule 13D, Schedule 13G and Form 13F at the same time and on the same basis, as filed with the SEC in connection with any securities purchased, acquired or taken pursuant to the blanket authorization under section 203(a)(2) provided in § 33.1(c)(2) of the Commission's regulations. 14 Any person is required to file a Schedule 13 notification with the SEC of an acquisition of beneficial ownership of more than five percent of a class of equity securities. 15 Importantly, a Schedule 13G filer must acquire the subject securities “in the ordinary course of his business and not with the purpose nor with the effect of changing or influencing the control of the issuer, nor in connection with or as a participant in any transaction having such purpose or effect” over entities whose securities it holds. 16 Because the Commission already receives these filings from the holding company, the Commission proposed not to require additional reporting on the part of individual public utilities to duplicate the reporting of information we are already getting about the same transaction. However, the Commission sought comment on whether any additional reporting by the public utility should be required. 14 18 CFR 33.1(c)(4). 15 17 CFR 240.13d-1(a). 16 17 CFR 240.13d-1(b)(1)(i). 10. The Commission also sought comment on whether blanket authorizations under section 203(a)(1) should be provided for the transfer of securities by a public utility to a holding company granted a blanket authorization under section 203(a)(2) in 18 CFR 33.1(c)(8), 17 33.1(c)(9), 18 and 33.1(c)(10). 19 In addition, the Commission sought comment on whether it should grant a generic blanket authorization under section 203(a)(1) for the acquisition or disposition of a jurisdictional contract where neither the acquirer nor transferor has captive customers and the contract does not convey control over the operation of a generation or transmission facility. 17 18 CFR 33.1(c)(8) (granting a blanket authorization under section 203(a)(2) to a person that is a holding company solely with respect to one or more exempt wholesale generators (EWGs), foreign utility companies (FUCOs), or qualifying facilities
(QFs)to acquire the securities of additional EWGs, FUCOs, or QFs). 18 18 CFR 33.1(c)(9) (granting a conditional blanket authorization under section 203(a)(2) to a holding company, or a subsidiary of that company, that is regulated by the Board of Governors of the Federal Reserve Bank or by the Office of the Comptroller of the Currency, under the Bank Holding Company Act of 1956 as amended by the Gramm-Leach-Bliley Act of 1999). 19 18 CFR 33.1(c)(10) (granting a limited blanket authorization under section 203(a)(2) to a holding company, or a subsidiary of that company, for the acquisition of securities of a public utility or a holding company that includes a public utility for purposes of underwriting activities or hedging transactions). III. Procedural Matters 11. The Blanket Authorization NOPR invited comments on the proposed regulations. Comments on the Blanket Authorization NOPR were filed by: American Public Power Association and National Rural Electric Cooperative Association (APPA/NRECA); Edison Electric Institute (EEI); Electric Power Supply Association (EPSA); Entergy Services, Inc. (Entergy); Financial Institutions Energy Group (the Financial Group); Mirant Corporation (Mirant); Modesto Irrigation District (Modesto); and Oklahoma Corporation Commission (Oklahoma Commission). IV. Discussion 12. This Final Rule adopts the proposal in the Blanket Authorization NOPR to pre-authorize a public utility to dispose of less than 10 percent of its voting securities to a public utility holding company if, after the disposition, the holding company and any associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of that public utility. Based on comments to the Blanket Authorization NOPR, this Final Rule also provides four additional blanket authorizations under section 203(a)(1). First, a public utility is granted a blanket authorization under section 203(a)(1) to transfer its outstanding voting securities to any holding company granted blanket authorization in § 33.1(c)(8) if, after the transfer, the holding company and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility. Second, a public utility is granted a blanket authorization under section 203(a)(1) to transfer its outstanding voting securities to any holding company granted blanket authorization in § 33.1(c)(9). Third, a public utility is granted a blanket authorization under section 203(a)(1) to transfer its outstanding voting securities to any holding company granted blanket authorization in § 33.1(c)(10). Fourth, a public utility is granted a blanket authorization under section 203(a)(1) for the acquisition or disposition of a jurisdictional contract where neither the acquirer nor transferor has captive customers or owns or provides transmission service over jurisdictional transmission facilities, the contract does not convey control over the operation of a generation or transmission facility, the parties to the transaction are neither affiliates nor associate companies, and the acquirer is a public utility. In addition, this Final Rule provides certain clarifications regarding the existing blanket authorizations under section 203. Finally, this Final Rule clarifies the definitions of the terms “affiliate” and “captive customers.” A. Proposed Blanket Authorizations 1. Scope of the Proposed Blanket Authorization a. Comments 13. APPA/NRECA, Mirant and the Oklahoma Commission support the limited blanket authorization as proposed by the Commission. The Oklahoma Commission states that the rule would allow utilities to expedite business ventures, but warns that the Commission should use terms in their plain and ordinary meanings to reduce any potential ambiguity. It also recommends that the Commission consider language that would allow state commissions to continue to receive notices of any investigations of regulated public utility companies. 14. In the Blanket Authorization NOPR, the Commission asked for comments on the “in aggregate” limitation. APPA/NRECA support the proposed aggregate ownership limitation, stating that it is needed to help prevent the transfer of control of public utilities. They argue that omitting the “in aggregate” limitation would allow a public utility to sell less than 10 percent of its voting securities in successive transfers to each of several affiliates or associate companies (or even the same entity). APPA/NRECA further argues that omitting the “in aggregate” limitation is not in the public interest because, absent a case-by-case review, the Commission has no basis for a finding that an indirect transfer of control of a public utility's generation or transmission facilities to a single entity or to several affiliated entities will not harm competition, captive customers, or transmission customers. 15. Mirant also supports the limited blanket authorization with the “in aggregate” limitation. It states that while this does not completely parallel the blanket authorization granted in Order No. 669, it is comparable enough to remedy the problem that exists when one party must seek Commission review of the transaction. 16. EEI and the Financial Group support the blanket authorization with certain clarifications and recommendations. Specifically, the Financial Group argues that the proposed less than 10 percent blanket authorization under section 203(a)(1) should be expanded to include all acquirers, not just holding companies. It asserts that if a disposition of less than 10 percent of a public utility's voting securities to a holding company raises no concerns with respect to control, markets, or captive customers, then a disposition of less than 10 percent of a public utility's voting securities to an entity that is not a holding company should also raise no concerns. The Financial Group states that, in the case of a disposition of less than 10 percent of the voting securities of a public utility, the interest being disposed of does not convey control and cannot harm markets or captive customers, so the status of the acquirer—as a holding company, public utility, or an entity that is neither—should be irrelevant. It argues that requiring a public utility to seek approval under section 203(a)(1) when disposing of less than 10 percent of its voting securities to a non-holding company would not serve any regulatory purpose, and adds needless costs and delays to transactions that do not raise section 203 concerns. 17. Similarly, EEI argues that the Commission should not limit its proposed section 203(a)(1) blanket authorization to the entities described in 18 CFR 33.1(c)(2)(ii). EEI states that § 33.1(c)(2)(ii) only covers acquisitions by holding companies of securities of a transmitting utility, electric utility company, or holding company in a holding company system with such utilities. This, EEI argues, excludes a broader class of public utilities as well as non-holding company acquirers. It contends that the Commission would reduce the regulatory burden and encourage investment without causing harm “by extending the new blanket authorization to cover jurisdictional transfers of securities from the broader class of ‘public utilities’ to ‘any person’ without the constraints contained in [§] 33.1(c)(2)(ii).” 20 20 EEI Comments at 8. 18. As an additional matter, the Financial Group recommends that the Commission clarify that the aggregate limitation only applies to companies in a holding company system that are 10 percent or more owned by the holding company or its subsidiaries. It argues that this should be clarified by eliminating the reference to “affiliate” altogether in the proposed definition. In the alternative, the Financial Group argues that the Commission clarify that the term does not refer to the PUHCA 2005 definition of affiliate, but rather to an entity that controls, is controlled by, or is under common control with, another entity (where control is rebuttably presumed to mean a voting interest of 10 percent or more). b. Commission Determination 19. We will adopt the proposed blanket authorization without modification. We will retain the “in aggregate” limitation so that, after a disposition of a public utility's securities under the proposed blanket authorization, the acquiring holding company and any associate or affiliate companies “in aggregate” would own less than 10 percent of the outstanding voting interests of that the public utility. As commenters point out, the limitation helps to prevent a public utility from transferring less than 10 percent of its voting securities in successive transfers to each of several affiliate or associate companies (or even the same entity), and thereby transferring control. 20. We deny the Financial Group's and EEI's requests to expand the blanket authorization to cover not only public utility dispositions of securities to holding companies but also public utility dispositions of securities to “any persons.” This request would expand the blanket authorization proposed in the existing NOPR beyond its original intent, which was to ensure that transactions qualifying under the section 203(a)(2) blanket authorization would not have to seek approval under section 203(a)(1). 21 In addition, limiting the blanket authorization to holding companies allows the Commission to monitor these dispositions for possible changes of control even when they fall under the 10 percent threshold because of holding companies' preexisting reporting requirements. 22 If we were to expand the blanket authorization to “any person,” we would need to establish appropriate reporting requirements so that we could monitor transfers to non-holding companies. This is important because, as we explained in the Supplemental Policy Statement, although there is a presumption that less than 10 percent of a utility's shares will not result in a change of control, this presumption is rebuttable. In some instances, the transfer of less than 10 percent of voting shares may constitute a transfer of control. 23 Accordingly, at this time we decline to expand the proposed generic blanket authorization as requested EEI and the Financial Group. However, we recognize that it could reduce regulatory burdens and encourage investment to allow transfers of securities not only to holding companies but to other “persons” and that such transfers will not harm competition or customers as long as there is sufficient ability to monitor possible changes in control of public utilities. Therefore, the Commission is willing to consider such blanket authorizations on a case-by-case basis if applicants can propose sufficient reporting requirements to allow adequate monitoring of possible changes in control and assure us that captive customers are adequately protected. 21 *See* Blanket Authorization NOPR, FERC Stats. & Regs. ¶ 32,619 at P 9-11. 22 *See, e.g.* , 18 CFR 366.4; 18 CFR 366.23; 18 CFR parts 367-68. 23 *See* Supplemental Policy Statement, FERC Stats. & Regs. ¶ 31,253 at n.48. 21. We will also deny the Financial Group's suggestion to eliminate the term “affiliate” from the proposed blanket authorization. However, we clarify that the term affiliate for purposes of the blanket authorization does not refer to the PUHCA 2005 definition of affiliate, but rather, to the definition we adopt in the Affiliate Transactions Final Rule issued concurrently with this Final Rule. As discussed in the Affiliate Transactions Final Rule, we find it appropriate to explicitly incorporate the PUHCA 1935 definition of affiliate for EWGs. 24 We also adopt the PUHCA 1935 definition of affiliate for non-EWGs, but with adjustments to reflect our previously used 10 percent voting interest threshold for non-EWGs and to eliminate certain language not applicable or necessary in the context of the FPA. 25 Accordingly, this definition applies for purposes of the blanket authorizations adopted under section 203. 24 16 U.S.C. 824m. 25 *See, e.g., Morgan Stanley Capital Group, Inc.,* 72 FERC ¶ 61,082, at 61,436-37 (1995). 22. Finally, with regard to the Oklahoma Commission's request for language that would allow state commissions to continue to receive notices of investigations of regulated public utilities, we note that it previously has not been the practice of the Office of Enforcement to inform state commissions of investigations that it is conducting. Section 1b.9 of our regulations requires that all investigative proceedings shall be treated as non-public by the Commission and its staff except to the extent that the Commission authorizes public disclosure, the matter is made a matter of public record during an adjudicatory proceeding, or disclosure is required under the Freedom of Information Act. 26 The Commission concludes that the disclosure of such information could impede the willingness of market participants to self-report and otherwise cooperate in investigations. As such, we decline to grant the Oklahoma Commission's request. 27 26 18 CFR 1b.9. 27 Our determination on this issue is also stated in the concurrently-issued Notice of Proposed Rulemaking in Docket Nos. AD07-7-000 and RM07-19-000 (Wholesale Competition in Regions with Organized Electric Markets) with regard to releasing information to state commissions on referrals by market monitoring units to the Commission for investigation. 2. Reconciling the Proposed Blanket Authorization With the Presumption Provided in the Supplemental Policy Statement a. Comments 23. Both the Financial Group and EEI question whether the blanket authorization is necessary in light of the Supplemental Policy Statement that creates a presumption of no transfer of control for security transfers of under 10 percent of a company's securities. They state that absent such a change in control, the Commission has indicated that a sale of securities is not a transaction subject to section 203(a)(1) jurisdiction. If that is the case, EEI questions why there should be a blanket authorization covering security transfers of up to 10 percent from utility companies to holding companies. 24. EEI also states that it assumes that the proposed blanket authorization is meant to supplement and not modify other blanket authorizations and clarifications so, for example, the new authorization would apply as to securities transfers only in excess of $10 million. 25. Mirant contends that, absent the Blanket Authorization NOPR, no pre-approval would be required from the Commission for a public utility to transfer up to 10 percent of voting securities, though it recognizes the “possibility” that there is a presumption that control could be exercised over the management or policies of the public utility. Accordingly, it states that the Commission should adopt the proposed blanket authorization to remove the presumption that exists in the Supplemental Policy Statement with respect to transfers of voting securities from a public utility to a public utility holding company. It further contends that the proposed blanket authorization will remove the inconsistency in the filing requirements between holding companies and public utilities. b. Commission Determination 26. The Commission provided guidance in the Supplemental Policy Statement that a transfer of less than 10 percent would be rebuttably presumed not to be a transfer of control in order to assist applicants in determining the need for prior authorization under section 203, not to define the scope or limit of our jurisdiction. We agree with commenters that if there is no change in control of a public utility as a result of the transfer of a public utility's securities, then the public utility has not “otherwise disposed” of its jurisdictional facilities under section 203(a)(1)(A) and no Commission authorization is required. However, as the Commission stressed in the Supplemental Policy Statement, we cannot make an *ex ante* determination regarding what is control for purposes of the Commission's section 203 analysis absent facts of a specific case. The circumstances that convey control vary depending on a variety of factors, including the transaction structure, the nature of voting rights and/or contractual rights and obligations conveyed in the transaction. Because of the possibility that transfers of up to 10 percent *could* result in a change in control, the rebuttable presumption in the Supplemental Policy Statement and the blanket authorization should help eliminate uncertainties. Moreover, we view the “in aggregate” limitation in the blanket authorization as important to ensure that companies do not circumvent section 203(a)(1)(A) through multiple dispositions of less than 10 percent. 27. In response to EEI, we clarify that the new blanket authorization in this Final Rule is meant to supplement and not modify other blanket authorizations and clarifications in the Order No. 669 series. We also clarify that, consistent with the statute, it applies only to section 203(a)(1)(A) transfers of securities of a value in excess of $10 million. 3. Reporting Requirement 28. In the Blanket Authorization NOPR, the Commission sought comment on whether, in association with the proposed blanket authorization, additional reporting by the public utility should be required. a. Comments 29. Most commenters, including EEI, the Financial Group, Mirant, and the Oklahoma Commission argue that the Commission should not impose a reporting requirement associated with the proposed blanket authorization. These commenters contend that no additional reporting obligation is required because the relevant information will be submitted by the holding company that is acquiring the securities. 30. EEI argues that if the Commission expands the proposed blanket authorization to cover jurisdictional transfer of securities by public utilities to other entities, the Commission may wish to impose a counterpart to the 18 CFR 33.1(c)(4) holding company reporting requirement on the public utility, but should do so only for those transactions not already covered by § 33.1(c)(4). 31. The Oklahoma Commission also argues that additional reporting is not needed. However, the Oklahoma Commission proposes that the relevant state commission be notified of additional reviews or requests about individual public utilities' current acquisition information. The Oklahoma Commission also urges the Commission to add language that states that section 203 does not preempt applicable state law concerning reporting requirements, which would further protect the interest and authority of state commissions. 32. In contrast, APPA/NRECA argue that the Commission should require a public utility to report on all dispositions of its securities undertaken pursuant to the blanket authorization. APPA/NRECA argue that the reporting burden is minimal and that the Commission should not have to (and, in fact, may not be able to) piece together this information from existing reports. b. Commission Determination 33. We will not require additional reporting requirements at this time. In the Blanket Authorization NOPR, the Commission proposed not to impose additional reporting requirements because existing regulations require the submission of schedules and forms that are also provided to the SEC. 28 While we agree with APPA/NRECA that additional reporting requirements might provide greater efficiency to the Commission, at this time we believe the potential reporting burden on public utilities outweighs the possible efficiency gains. 28 For example, the Commission already requires the holding company to provide to the Commission copies of any Schedule 13D, Schedule 13G and Form 13F, at the same time and on the same basis, as filed with the SEC in connection with securities purchased, acquired or taken pursuant to the blanket authorization under section 203(a)(2) provided in § 33.1(c)(2) of the Commission's regulations. 18 CFR 33.1(c)(4). 34. We clarify, as requested by the Oklahoma Commission, that section 203 does not preempt applicable state law concerning reporting requirements. With regard to the Oklahoma Commission's request that state commissions be notified of additional reviews or requests about individual public utilities' current acquisition information, to the extent that such reviews or requests relate to an investigation, they are subject to the Commission's rules governing investigations as described *supra* . However, if the reviews or requests are made as the result of a public inquiry, such notification may be made. For example, the Commission's Division of Audits in the Office of Enforcement has provided notice of public final audit reports of jurisdictional companies to affected states. We continue to encourage our audits staff to continue this practice. B. Expansion of the Proposed Blanket Authorization 1. Blanket Authorization to “Parallel” Those Granted Under Section 203(a)(2) a. Comments 35. The Blanket Authorization NOPR also requested comments on whether the proposed blanket authorization under section 203(a)(1) should be extended to the transfer of securities by a public utility to a holding company granted a blanket authorization:
(1)§ 33.1(c)(8) for a person that is a holding company solely with respect to owning one or more EWGs, FUCOs, or QFs to acquire the securities of additional EWGs, FUCOs, or QFs;
(2)§ 33.1(c)(9) for a bank holding company or subsidiary that is regulated by the Federal Reserve Board or Comptroller of the Currency to acquire and hold an unlimited amount of the securities of holding companies that include a transmitting utility or an electric utility company if such acquisitions and holdings are in the normal course of business and the securities are held for certain identified purposes 29 ; and
(3)§ 33.1(c)(10) for a holding company or subsidiary to acquire public utility or holding company securities for underwriting or hedging purposes under certain conditions. 30 29 The securities must be held:
(i)As a fiduciary;
(ii)as principal for derivatives hedging purposes incidental to the business of banking and it commits not to vote such securities to the extent they exceed 10 percent of the outstanding shares;
(iii)as collateral for a loan; or
(iv)solely for purposes of liquidation and in connection with a loan previously contracted for and owned beneficially for a period of not more than two years, with the following conditions and reporting requirement: The holding does not confer a right to control, positively or negatively, through debt covenants or any other means, the operation or management of the public utility or public utility holding company, except as to customary creditors' rights or as provided under the United States Bankruptcy Code; and the parent holding company files with the Commission on a public basis and within 45 days of the close of each calendar quarter, both its total holdings and its holdings as principal, each by class, unless the holdings within a class are less than one percent of outstanding shares, irrespective of the capacity in which they were held. 18 CFR 33.1(c)(9). 30 For purposes of conducting underwriting activities, the blanket authorization is subject to the condition that holdings that the holding company or its subsidiary are unable to sell or otherwise dispose of within 45 days are to be treated as holdings as principal and thus subject to a limitation of 10 percent of the stock of any class unless the holding company or its subsidiary has within that period filed an application under FPA section 203 to retain the securities and has undertaken not to vote the securities during the pendency of such application; and the parent holding company files with the Commission on a public basis and within 45 days of the close of each calendar quarter, both its total holdings and its holdings as principal, each by class, unless the holdings within a class are less than one percent of outstanding shares, irrespective of the capacity in which they were held. For purposes of engaging in hedging transactions, the blanket authorization is subject to the condition that if such holdings are 10 percent or more of the voting securities of a given class, the holding company or its subsidiary shall not vote such holdings to the extent that they are 10 percent or more. 18 CFR 33.1(c)(10). 36. EEI, the Financial Group and Mirant support extension of the blanket authorizations. They generally argue that if holding company acquisitions authorized by § 33.1(c)(8), (c)(9) and (c)(10) pose no concern warranting Commission review, counterpart public utility transfers subject to the same constraints should also pose no concern. They also argue that there is no benefit to the acquiring entity under a blanket authorization under section 203(a)(2) unless there is a reciprocal blanket authorization under section 203(a)(1). 37. In addition, the Financial Group recommends that the § 33.1(c)(8) blanket authorization be extended to companies that will become holding companies only after the transaction has been consummated (e.g., special purpose vehicles that are created to acquire and hold the jurisdictional assets of another company) in order for those companies to take advantage of the blanket. The Financial Group also argues that the proposed blanket authorization under section 203(a)(1) should be extended so that a public utility can transfer an unlimited amount of its securities to any entity that will acquire and hold such securities for the four purposes enumerated in § 33.1(c)(9). It asserts that the Commission has previously found in the section 203(a)(2) context that these types of transactions cannot harm competition or captive customers because the securities are being transferred for reasons other than to exercise control over the public utility. Thus, it argues, these transactions do not constitute a change in control over a public utility, which is the core focus of section 203(a)(1). Similarly, with regard to § 33.1(c)(10), the Financial Group argues that the proposed blanket authorization under section 203(a)(1) should be extended to a public utility transferring its securities to any entity. 38. APPA/NRECA argue against granting a parallel blanket authorization under section 203(a)(1) for a public utility to transfer securities of EWGs, FUCOs or QFs (to parallel § 33.1(c)(8)) or to transfer securities to a non-bank holding company or its subsidiary for purposes of engaging in hedging transactions (to parallel § 33.1(c)(10)). They argue that preauthorizing an EWG or QF that is a public utility to transfer all or any part of its securities to a holding company would enable a public utility to transfer control of its generation facilities to a holding company that already controls another public utility without Commission scrutiny of the transaction for competitive harm. 39. Regarding the proposal for a section 203(a)(1) blanket authorization to parallel § 33.1(c)(10), APPA/NRECA state that there is no basis for finding that transactions covered by this blanket are consistent with the public interest even with the 10 percent voting limitation imposed on the holding company. 31 Further, they state that “hedging transactions” are not defined in the regulations or in the NOPR, and there is no requirement that the acquiring company be in some business other than the utility, power or energy business, and thus no assurance that the hedging transaction is only incidental to the holding company's main business. 32 They recommend that, however, if the Commission were to grant a further blanket authorization under section 203(a)(1), it should contain a 10 percent “in aggregate” limitation. 31 Under § 33.1(c)(10)(ii), a holding company or its subsidiaries that acquire 10 percent or more of the voting securities of a public utility or a holding company for hedging transactions are limited to voting less than 10 percent of those securities. 32 APPA/NRECA note that these problems already exist in the context of the blanket authorization under section 203(a)(2) provided in 18 CFR 3.1(c)(10)(ii). b. Commission Determination 40. We will adopt the proposal to extend a blanket authorization under section 203(a)(1) to a public utility in circumstances where a holding company qualifies for, and the exercise of the blanket authorization is for the purpose of facilitating the transactions authorized under the § 33.1(c)(8), 33.1(c)(9) or a 33.1(c)(10) blanket authorization under section 203(a)(2). 41. As to the blanket authorization to parallel § 33.1(c)(8), we will require that the transfer of securities by a public utility to a holding company under that blanket be subject to the 10 percent “in aggregate” limitation as in the proposed limited blanket authorization described above. We recognize that the blanket authorization we adopt in this Final Rule to facilitate transactions undertaken by holding companies under § 33.1(c)(8) does not precisely parallel the section 203(a)(2) authorization since the section 203(a)(2) authorization does not include the “in aggregate” limitation. However, we believe this limitation will provide better protection against possible transfer of control of a public utility and the acquisition of generation market power by the acquiring holding company without Commission approval. 42. The Financial Group's request to extend the proposed section 203(a)(1) blanket to public utilities transferring securities to entities that will become holding companies only after the transaction has been consummated is moot because, as discussed above, the “parallel” 33.1(c)(8) blanket is restricted to cases where, after the transfer, the holding company and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility. Therefore, the scenario presented by the Financial Group would not occur because an entity that was not previously a holding company could not become a holding company as a result of a transaction whereby the acquiring entity is limited to owning less than 10 percent of the shares of the public utility. 33 33 Transfers of securities that result in the acquiring company holding less than 10 percent of the outstanding voting shares of a public utility would have the presumption of not being a change in control and, therefore, not requiring section 203(a)(1) authorization. *See* Supplemental Policy Statement, FERC Stats. & Regs. ¶ 31,253 at P 57. 43. As to the request for a blanket authorization under section 203(a)(1) to parallel that granted under section 203(a)(2) in § 33.1(c)(9), we note that that authorization under section 203(a)(2) applies only to acquisitions by bank holding companies or subsidiaries that are regulated by the Federal Reserve Board or Comptroller of the Currency (banks) of the securities of holding companies that include transmitting utilities and electric utility companies if such acquisitions and holdings are in the normal course of the acquiring bank's business and are held for certain purposes. In some cases the entity whose securities are acquired by the bank would have an obligation under section 203(a)(1) to seek Commission review before disposing of its securities. Typically, these cases would occur when the disposing holding company is a public utility and is also the issuer of the securities being acquired by the bank for those limited circumstances set forth in § 33.1(c)(9). As stated in Order No. 669-A, entities that are subject to the regulatory oversight of the Federal Reserve Bank or the Comptroller of the Currency “are likely to be significantly constrained in their use of those securities so as to not affect regulation, rates or competition under the FPA.” 34 Further, the Commission conditioned the authorization such that the holding of the securities does not confer a right to control the utility operation or management and required a quarterly reporting on the securities so held by the bank. Accordingly, we will adopt the proposal to extend the section 203(a)(1) blanket to a disposing holding company that is also a public utility. Because the entities eligible for the § 33.1(c)(9) blanket authorization are already subject to numerous conditions and reporting requirements, we do not believe additional conditions are required. 34 Order No. 669-A, FERC Stats. & Regs. 31,214 at P 124. 44. With respect to the Financial Group's request that the section 203(a)(1) blanket authorization be extended so that a public utility can transfer an unlimited amount of its securities to any entity that will acquire and hold such securities for the four enumerated purposes in § 33.1(c)(9), we cannot be assured that protections such as those that are in place for entities that are subject to the regulatory oversight of the Federal Reserve Bank or the Comptroller of the Currency would apply to entities that are not subject to such regulatory oversight. Therefore, we will continue to evaluate requests for blanket authorizations for entities that are not subject to regulatory oversight by the Federal Reserve Bank or the Comptroller of the Currency to acquire public utility securities, and for a public utility to transfer securities to such entities, on a case-by-case basis when such authorizations are needed. 35 35 *See Morgan Stanley* , 121 FERC ¶ 61,060 (2007), *clarified by* , 122 FERC ¶61,094 (2008); *The Goldman Sachs Group, Inc.* , 121 FERC ¶ 61,059 (2007), *clarified by* , 122 FERC ¶ 61,005 (2008). 45. As to the request for a blanket authorization under section 203(a)(1) to facilitate the transactions authorized under § 33.1(c)(10), we grant an unlimited authorization for facilitating such transactions under section 203(a)(1). In granting the blanket authorization for the transactions for hedging purposes under section 203(a)(2), the Commission limited the voting ability of the entity acquiring the securities. If the amount held is 10 percent or more of the relevant class, the acquiring entity is limited to voting less than 10 percent of those securities. This existing condition on the party acquiring the securities for hedging purposes should be adequate to ensure that any disposing entity facilitating such transactions and requiring authorization under section 203(a)(1) does not affect a disposition or change in control of the issuer of the public utility securities. 36 36 Order No. 669-A, FERC Stats. & Regs. ¶ 31,214 at P 132. 2. Blanket Authorization as to Certain Jurisdictional Contracts 46. In the Blanket Authorization NOPR, the Commission sought comment as to whether the Commission should grant a blanket authorization under section 203(a)(1) for the acquisition or disposition of a jurisdictional contract where neither the acquirer nor transferor has captive customers and the contract does not convey control over the operation of a generation or transmission facility. a. Comments 47. The Commission received comments from: APPA/NRECA and Modesto (referred to herein as Customers); EEI, EPSA and Mirant (referred to herein as Sellers); and the Financial Group. Customers oppose the blanket authorization, Sellers support it, and the Financial Group not only supports it, but proposes expanding the blanket authorization. 48. Customers argue that the proposal would not protect transmission customers against cross-subsidization in the same way that captive wholesale and retail power customers are protected. They therefore propose narrowing the blanket authorization to cases where “neither the acquirer nor the transferor has captive customers or owns or provides transmission service over Commission-jurisdictional facilities.” 37 They also argue that, even if revised to include the situation where neither the acquirer nor the transferor has captive customers or owns or provides transmission service over jurisdictional transmission facilities, allowing an entity such as a power marketer or independent power producer to transfer its book of jurisdictional power sales contracts at any time and without the purchaser's consent (which may or may not be expressly in the contract) would leave the purchaser with no recourse other than a section 206 complaint and the burden of proof and costs associated therewith. They maintain that purchasers under the jurisdictional contract, even if not “captive” may be a load-serving entity dependent on the contract for a reliable power supply or to meet regulatory or contractual obligations. They also maintain that a purchaser would have no say in the type of entity to whom a seller would transfer contracts, creating the possibility that the entity may not be a suitable counterparty based upon factors such as creditworthiness or other financial criteria, or inexperience in administering the functions contemplated in the subject contract. Some Customers suggest that transfers may result in problems similar to the mortgage-loan business. 37 APPA/NRECA Comments at 13-14. 49. Sellers support the blanket authorization provided that it focuses only on transactions within the Commission's jurisdiction under section 203, and would supplement and not override or otherwise limit the proposed blanket authorization to parallel § 33.1(c)(2)(ii) or existing blanket authorizations. Sellers argue that with the stated constraints, the acquisition or disposition should pose no competitive or rate concerns or impacts on customers that would warrant case-by-case approval because:
(1)The transfer of a wholesale power contract which does not provide for the control of generation or transmission cannot affect horizontal or vertical market power;
(2)the transfer of a wholesale power contract to a party that does not have captive customers cannot affect the rates of captive customers (and therefore has no rate or cross-subsidization impacts); and
(3)the transfer of a wholesale power contract does not affect the Commission's ability to regulate the contract or the parties to the transaction. Sellers assert that there is no regulatory purpose served by requiring section 203 approval for these transactions and states that it is unaware of a single instance where significant issues have been raised with respect to requests for approval of wholesale power contracts of this type. Further, Sellers argue that requiring pre-authorization in this circumstance results in delays and costs. 50. The Financial Group also supports the additional blanket authorization. In addition, it suggests that the blanket authorization not be limited to cases where the transferor also does not have captive customers. The Financial Group argues that where a transferor has captive customers, the issue is whether the transferor would be transferring the contract at a below-market price, thereby depriving its captive customers of the full value of the contract. However, where the transacting parties are not affiliates, it should be assumed that the transferor would seek market price, regardless of whether or not it has captive customers. Accordingly, it proposes the following addition to § 33.1(c): “Any public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to dispose of, transfer, or acquire a contract for the sale of electric energy in interstate commerce where the contract does not convey control over the operation of a generation or transmission facility, the transferor and acquirer are not affiliated, and the acquirer does not have captive customers.” 38 38 Financial Group Comments at 18. b. Commission Determination 51. We adopt the proposed blanket authorization with modifications to address commenters' concerns. We agree with Sellers that the transfer of a wholesale power contract which does not provide for the control of generation or transmission cannot affect horizontal or vertical market power. We also agree that, with the modification proposed by APPA/NRECA, the transfer of a wholesale power contract from one party that does not have captive customers or owns or provides transmission service over jurisdictional transmission facilities to another party that also does not have captive customers or owns or provides transmission service over jurisdictional transmission facilities cannot affect the rates of captive customers or transmission customers (and therefore has no rate or cross-subsidization impacts). However, in at least one case involving a transfer from one affiliated company to another, significant issues were raised with respect to requests for section 203 approval of wholesale power contracts of this type. 39 Such transactions do not have the market discipline that is present in arm's-length negotiations between unaffiliated parties. Finally, Sellers' argument that the transfer of a wholesale power contract would not affect the Commission's ability to regulate the contract or the parties to the transaction ignores the possibility of the contract being transferred to a non-jurisdictional entity, in which case the Commission could lose the ability to regulate the contract or parties to the contract. Therefore, we will adopt the blanket authorization proposed in the Blanket Authorization NOPR, narrowing the blanket to apply in cases where neither the acquirer nor the transferor has captive customers or owns or provides transmission service over jurisdictional transmission facilities, and adding the following language to the end of the proposed blanket authorization: the parties to the transaction are neither associate nor affiliate companies, and the acquirer is a public utility. 39 *Mirant Corp.* , 111 FERC ¶ 61,425 (2005). Pursuant to its bankruptcy reorganization, Mirant transferred power agreements with PEPCO to a newly-formed entity within the corporate family. 52. Customers argue that granting a blanket authorization for the transfer of such jurisdictional contracts without the purchaser's consent (which may or may not be expressly in the contract) would result in the purchaser having no say in the type of entity to whom a seller would transfer contracts, thus leaving the purchaser with no recourse other than a section 206 complaint and the burden of proof and costs associated therewith. We do not find that argument compelling because a section 203 proceeding is unlikely to be the forum for a purchaser to protect its interest under a contractual arrangement. The Commission has stated that contractual provisions are beyond the scope of a section 203 proceeding. 40 Based on our experience, as discussed above, the transfer of such contracts, with the additional conditions on the purchaser and acquirer of the contracts also discussed above, would not adversely affect competition, rates or regulation, and would not result in cross-subsidization, and therefore would be consistent with the public interest. Moreover, whether the contracts were being transferred pursuant to a blanket authorization or an individual section 203 authorization, purchasers would be able to protect their interests by exercising any relevant contractual provisions and, if necessary, by filing a section 206 complaint. Thus, granting the blanket authorization does not adversely affect a purchaser's ability to protect its interests. 40 *See, e.g., American Electric Power Service Corporation* , 107 FERC ¶ 61,209, at P 17 (2004). 53. We decline to adopt the Financial Group's proposal to expand the blanket authorization to cover cases where the transferor does have captive customers but the acquirer does not. We agree with the Financial Group that, presumably, the transferor would seek market price regardless of whether or not it has captive customers. However, captive customers of the transferor would not necessarily receive the benefit from such transactions and could be faced with paying higher rates due to increased costs for replacement power. C. New Requests for Clarification and/or Blanket Authorizations 1. Blanket Authorization Under Section 203(a)(1) for Public Utility Sales of Non-Voting Securities a. Comments 54. EEI argues that the Commission should disclaim jurisdiction under section 203(a)(1) over public utility sales of non-voting securities. EEI argues that such an authorization would parallel the authorization in 18 CFR 33.1(c)(2)(i) for holding companies to acquire non-voting securities, if the acquisition does not transfer control. b. Commission Determination 55. We agree that if a non-voting security does not convey control, its transfer is not jurisdictional under the “or otherwise dispose” provision in section 203(a)(1)(A). 41 As the Commission stated in the Supplemental Policy Statement, and has recently held in case-specific requests for blanket authorizations under section 203(a)(1), 42 transactions that do not transfer control of a public utility or jurisdictional facilities do not fall within the “otherwise dispose” language of section 203(a)(1)(A) and thus do not require approval under section 203(a)(1)(A). 43 If a non-voting security conveys control (e.g., through veto rights or some other means), our requirements regarding transfers of control apply. 41 We note that the situation is different under section 203(a)(2). Jurisdiction over acquisitions of securities under section 203(a)(2) attaches whether or not there is a transfer of control if the acquisition is over $10 million. 42 Supplemental Policy Statement, FERC Stats. & Regs. ¶ 31,253 at P 37; *see, e.g., Legg Mason, Inc.* , 121 FERC ¶ 61,061, at P 18 (2007). 43 This does not affect a public utility's responsibilities under sections 203(a)(1)(C) or 203(a)(1)(D), which apply to public utilities' acquisitions of public utility securities and generating facilities. 2. Clarification Regarding a Public Utility's Transfer of Securities to Its Holding Companies a. Comments 56. EEI argues that the Commission should clarify that a public utility that is a subsidiary of a holding company may transfer its own securities to that holding company without a separate authorization as a counterpart to the 18 CFR 33.1(c)(2)(iii) authorization for holding companies to acquire such securities. EEI argues that because the holding company acquisition of such securities (which is inherently part of what it means to be a holding company) can result in no change of control, the Commission lacks jurisdiction. b. Commission Determination 57. We find that a public utility that is the subsidiary of a single holding company may transfer its own securities to that holding company without a separate authorization under section 203(a)(2) for holding companies to acquire such securities. Where a single holding company system already has control of a subsidiary public utility, the transfer of securities from that public utility to the holding company would not be a change in control. 44 44 Our determination here does not affect any separate requirement that the public utility may have under section 204 of the FPA regarding the issuance of securities. 16 U.S.C. 824c. 3. Clarification Regarding the Internal Corporate Reorganization Blanket Authorization a. Comments 58. EEI asks the Commission to discuss and/or revise the internal corporate reorganization blanket authorization under 18 CFR 33.1(c)(6) 45 to clarify that non-traditional public utilities with market-based rates should not be considered traditional public utilities merely by ownership of incidental transmission facilities. 46 45 This is a blanket authorization under both sections 203(a)(1) and section 203(a)(2) for internal corporation reorganizations that do not result in the reorganization of a traditional public utility that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, and that do not present cross-subsidization issues. 18 CFR 33.1(c)(6). 46 EEI notes that it is not proposing to expand the blanket authorization for internal corporate reorganizations to cover the transfer of assets from one non-traditional public utility subsidiary to another, as such proposal was rejected in the Supplemental Policy Statement. 59. EEI states that while the Commission has clarified that the blanket authorization in 18 CFR 33.1(c)(6) allows “upstream” reorganizations of “non-traditional public utilities,” the blanket authorization does not allow the reorganization of a traditional public utility. EEI states that to qualify as a non-traditional public utility under the language of § 33.1(c)(6), the entity may not “own or provide transmission service over jurisdictional transmission facilities.” 60. According to EEI, because many non-traditional utilities, including EWGs and others with market-based rates, own some incidental jurisdictional transmission facilities (e.g., step-up transformers), the blanket authorization rule for internal corporate reorganizations may unnecessarily restrict the reorganization of what otherwise would clearly be a non-traditional public utility. EEI argues that ownership of step-up transformers or other incidental transmission facilities should not change the fact that case-by-case approval by the Commission is unnecessary for the reorganization of such otherwise non-traditional utilities with no captive customers and whose reorganization would pose no cross-subsidization issues and would not change the ultimate control of the entities. b. Commission Determination 61. We grant EEI's request for clarification. The term “traditional public utility,” as used in the Order No. 669 rulemaking proceeding was taken from prior Commission orders where the term was used to refer to utilities with franchised service territories. 47 In the Notice of Proposed Rulemaking prior to issuance of Order No. 669, the Commission further noted that, “[i]n the context of considering cross-subsidization or affiliate abuse concerns associated with power transactions between public utility affiliates, the Commission has differentiated between utility activities and non-utility activities according to whether they were being conducted by a public utility with captive wholesale or retail customers served under cost-based rates (sometimes described as a `traditional public utility').” 48 In Order No. 669, the Commission continued to implicitly define traditional utility as a public utility with wholesale or retail customers served under cost-based regulation. 49 Thus, EWGs and other utilities that do not have franchised service territories are not considered to be “traditional public utilities” in the first instance, and therefore, their ownership of merely incidental transmission facilities does not make such a utility a traditional public utility by virtue of its ownership of those facilities. 47 *See, e.g., Sierra Pacific Power Co.* , 95 FERC ¶ 61,193, at 61,178-79 (2001). 48 *Transactions Subject to FPA Section 203* , Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,589, at P 43 (2005). In Order No. 669, the Commission continued to define “traditional public utility” as those with wholesale or retail customers served under cost-based regulation. Order No. 669, FERC Stats. & Regs. ¶ 31,200 at P 169. 49 Order No. 669, FERC Stats. & Regs. ¶ 31,200 at P 169. D. Clarification of the Definition of “Captive Customer” 62. In considering the comments in this docket, in response to the Affiliate Transactions NOPR and on rehearing of the Market-Based Rate Final Rule, and in reviewing the use of the definition of captive customers in our other rules, we believe it appropriate to modify the definition of captive customers to make explicit what was only implicit in our earlier rules—that the definition is intended to apply to customers served by a franchised public utility under cost-based regulation. Accordingly, the Commission will revise the definition of captive customers in 18 CFR 33.1(b)(5) to mean any wholesale or retail electric energy customers served by a franchised public utility under cost-based regulation. V. Information Collection Statement 63. The Office of Management and Budget's
(OMB)regulations require that OMB approve certain information collection and data retention requirements imposed by agency rules. 50 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, 51 the reporting requirements in this rulemaking will be submitted to OMB for review. 50 5 CFR 1320. 51 44 U.S.C. 3507(d). 64. The “public protection” provisions of the Paperwork Reduction of 1995 require each agency to display a currently valid control number and inform respondents that a response is not required unless the information collection displays a valid OMB control number on each information collection or provides a justification as to why the information collection control number cannot be displayed. In the case of information collections published in regulations, the control number is to be published in the **Federal Register** . *Public Reporting Burden:* As the Commission stated in the Blanket Authorization NOPR, the regulations should have a minimal impact on the current reporting burden associated with an individual application, as they do not substantially change the filing requirements with which section 203 applicants must currently comply. Further, the Commission does not expect the total number of section 203 applications under amended section 203 to increase, but rather expects the total number of section 203 applications to decrease. This is because the regulations provide categories of jurisdictional transactions for which the Commission would not require applications seeking before-the-fact approval. This would reduce the burden on the electric industry because it will reduce the number of applications that need to be made to the Commission. The Commission received eight comments on the Blanket Authorization NOPR and no entity specifically addressed the Commission's information collection statement. The Commission is submitting a copy of this Final Rule to OMB for review and approval. In their notice of November 28, 2007, OMB took no action on the Blanket Authorization NOPR, instead deferring their approval until review of the Final Rule. *Title:* FERC-519, “Application Under the Federal Power Act, Section 203.” *Action:* Revised Collection. *OMB Control No:* 1902-0082. The applicant will not be penalized for failure to respond to this information collection unless the information collection displays a valid OMB control number or the Commission has provided justification as to why the control number should not be displayed. *Respondents:* Businesses or other for profit. *Frequency of Responses:* N/A. *Necessity of the Information:* This Final Rule codifies limited blanket authorizations under FPA section 203(a)(1), providing for categories of jurisdictional transactions under section 203(a)(1) for which the Commission would not require applications seeking before-the-fact approval. *Internal Review:* The Commission has conducted an internal review of the public reporting burden associated with the collection of information and assured itself, by means of internal review, that there is specific, objective support for its information burden estimate. 65. Interested persons may obtain information on the reporting requirements by contacting: Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC, 20426 [Attention: Michael Miller, Office of the Executive Director, Phone
(202)502-8415, fax
(202)273-0873, e-mail: *michael.miller@ferc.gov* ]. Comments on the requirements of the Final Rule may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission, fax
(202)395-7285, e-mail *oira_submission@omb.eop.gov* ]. VI. Environmental Analysis 66. 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. 52 The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. 53 The Final Rule is categorically excluded as it “do[es] not substantially change the effect of legislation or regulations being amended” and addresses actions under section 203. 54 Accordingly, no environmental assessment is necessary and none has been prepared in this Final Rule. 52 Order No. 486, Regulations Implementing the National Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles 1986-1990 ¶ 30,783 (1987). 53 18 CFR 380.4. 54 *See* 18 CFR 380.4(a)(2)(ii), 380.4(a)(16). VII. Regulatory Flexibility Act 67. The Regulatory Flexibility Act of 1980
(RFA)55 generally requires a description and analysis of Final Rules that will have significant economic impact on a substantial number of small entities. 56 However, the RFA does not define “significant” or “substantial.” Instead, the RFA leaves it up to an agency to determine the effect of its regulations on small entities. 55 5 U.S.C. 601-12. 56 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 year did not exceed 4 million MWh. 13 CFR 121.201. 68. Most filing companies regulated by the Commission do not fall within the RFA's definition of small entity. 57 Moreover, as noted above, this Final Rule codifies blanket authorizations under FPA section 203(a)(1), providing for categories of jurisdictional transactions under section 203(a)(1) for which the Commission would not require before-the-fact approval. Thus, filing requirements are reduced by the rule. Therefore, the Commission certifies that the Final Rule will not have a significant economic impact on a substantial number of small entities. As a result, no regulatory flexibility analysis is required. 57 5 U.S.C. 601(3), citing to section 3 of the Small Business Act, 15 U.S.C. 632. Section 3 of the Small Business Act defines a “small-business concern” as a business which is independently owned and operated and which is not dominant in its field of operation. VIII. Document Availability 69. 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. 70. From FERC's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field. 71. User assistance is available for eLibrary and the FERC's Web site during normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) or e-mail at *ferconlinesupport@ferc.gov* , or the Public Reference Room at
(202)502-8371, TTY
(202)502-8659. E-mail the Public Reference Room at *public.referenceroom@ferc.gov* . IX. Effective Date and Congressional Notification 72. These regulations are effective March 31, 2008. 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” as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996. List of Subjects in 18 CFR Part 33 Electric utilities, Reporting and recordkeeping requirements, Securities. By the Commission. Kimberly D. Bose, Secretary. In consideration of the foregoing, the Commission amends Part 33, Chapter I, Title 18, *Code of Federal Regulations* , to read as follows: PART 33—APPLICATIONS UNDER FEDERAL POWER ACT SECTION 203. 1. The authority citation for part 33 continues to read as follows: Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352; Pub. L. 109-58, 119 Stat. 594. 2. In § 33.1, paragraph (b)(5) is revised to read as follows: § 33.1 Applicability, definitions, and blanket authorizations.
(b)* * *
(5)For purposes of this part, the term captive customers means any wholesale or retail electric energy customers served by a franchised public utility under cost-based regulation. 3. In § 33.1, paragraphs (c)(12) through (c)(15) are added to read as follows: § 33.1 Applicability, definitions, and blanket authorizations.
(c)* * *
(12)A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorizations in paragraph (c)(2)(ii) of this section if, after the transfer, the holding company and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility.
(13)A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorization in paragraph (c)(8) of this section if, after the transfer, the holding company and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility.
(14)A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorization in paragraph (c)(9) of this section.
(15)A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorization in paragraph (c)(10) of this section.
(16)A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act for the acquisition or disposition of a jurisdictional contract where neither the acquirer nor transferor has captive customers or owns or provides transmission service over jurisdictional transmission facilities, the contract does not convey control over the operation of a generation or transmission facility, the parties to the transaction are neither associate nor affiliate companies, and the acquirer is a public utility. [FR Doc. E8-3812 Filed 2-28-08; 8:45 am] BILLING CODE 6717-01-P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM07-15-000; Order No. 707] Cross-Subsidization Restrictions on Affiliate Transactions Issued February 21, 2008. AGENCY: Federal Energy Regulatory Commission, Department of Energy. ACTION: Final rule. SUMMARY: In this Final Rule, pursuant to sections 205 and 206 of the Federal Power Act, the Federal Energy Regulatory Commission (Commission) is amending its regulations to codify restrictions on affiliate transactions between franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities, and their market-regulated power sales affiliates or non-utility affiliates. These restrictions will supplement other restrictions the Commission has in place to protect captive customers of franchised public utilities or transmission customers of franchised public utilities that own or provide transmission service over jurisdictional transmission facilities from inappropriate cross-subsidization of affiliates. DATES: *Effective Date:* This Final Rule will become effective March 31, 2008. FOR FURTHER INFORMATION CONTACT: Carla Urquhart (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-8496. Roshini Thayaparan (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-6857. David Hunger (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-8148. Stuart Fischer (Technical Information), Office of Enforcement, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426,
(202)502-8517. SUPPLEMENTARY INFORMATION: *Before Commissioners:* Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff. Final Rule 1. On July 20, 2007, the Commission issued a Notice of Proposed Rulemaking to codify affiliate restrictions that would be applicable to all power and non-power goods and services transactions between franchised public utilities with captive customers and their market-regulated power sales and non-utility affiliates. 1 After receiving comments in response to the Affiliate Transactions NOPR, the Commission amends Part 35 of its regulations, pursuant to sections 205 and 206 of the Federal Power Act (FPA), to adopt such restrictions. 2 1 *Cross-Subsidization Restrictions on Affiliate Transactions,* Notice of Proposed Rulemaking, 72 FR 41644 (July 31, 2007), FERC Stats. & Regs. ¶ 32,618
(2007)(Affiliate Transactions NOPR). 2 16 U.S.C. 824d, 824e. 2. Finalization of this rulemaking is one of a number of steps the Commission has taken following the repeal of the Public Utility Holding Company Act of 1935 3 to ensure that customers of franchised public utilities do not inappropriately cross-subsidize the activities of “non-regulated” affiliates, and are not otherwise financially harmed as a result of affiliate transactions and activities. The restrictions in this Final Rule will provide certainty to public utilities and customers with respect to the pricing standard that must be applied to certain affiliate transactions. While the Commission already has in place affiliate rules that apply to public utilities with market-based rates and to public utilities seeking merger approvals, the restrictions in this rule will supplement existing restrictions and will apply to all franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities. Thus, they will strengthen the Commission's ability to ensure that customers are protected against affiliate abuse and that rates remain just and reasonable. 3 16 U.S.C. 79a *et seq.* (PUHCA 1935). I. Background 3. Under sections 205 and 206 of the FPA, the Commission must ensure that the rates, terms and conditions of jurisdictional service are just, reasonable and not unduly discriminatory or preferential. As part of the Commission's obligation in administering this FPA standard, it ensures that wholesale customers' rates do not reflect costs that are the result of undue preferences granted to affiliates or that are imprudent or unreasonable as a result of affiliate transactions. The Commission has a long history of scrutinizing affiliate transactions for potential cross-subsidization and in recent rulemakings and orders it has codified and expanded affiliate restrictions, both under its FPA section 205-206 rate authority (in the context of market-based rates) and under its FPA section 203 merger authority. As discussed *infra,* pursuant to its FPA section 205-206 authority, in this Final Rule the Commission will extend similar restrictions to all franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities. As historical backdrop, however, we first discuss our past and existing practices with respect to affiliate transactions in the context of market-based rates and mergers. A. Affiliate Transactions in the Context of Market-Based Rate Authorizations 1. Historical Approach 4. The Commission began considering proposals for market-based pricing of wholesale power sales and attendant cross-subsidy issues in 1988. The Commission acted on market-based rate proposals filed by various wholesale suppliers on a case-by-case basis. In doing so, the Commission considered, among other things, whether there was evidence of affiliate abuse or reciprocal dealing involving the seller or its affiliates. 4 As the Commission explained, “[t]he Commission's concern with the potential for affiliate abuse is that a utility with a monopoly franchise may have an economic incentive to exercise market power through its affiliate dealings.” 5 The Commission also stated its concern that a franchised public utility and an affiliate may be able to transact in ways that transfer benefits from the captive customers of the franchised public utility to the affiliate and its shareholders. 6 Where a franchised public utility makes a power sale to an affiliate, the Commission is concerned that such a sale could be made at a rate that is too low, in effect, transferring the difference between the market price and the lower rate from captive customers to the market-regulated affiliated entity. Where a power seller with market-based rates makes power sales to an affiliated franchised public utility, the concern is that such sales could be made at a rate that is too high, which would give an undue profit to the affiliated entity at the expense of the franchised public utility's captive customers. 7 In determining whether to allow power sales affiliate transactions, the Commission, over time, has adopted several methods, all of which have focused on ensuring that captive customers are adequately protected against affiliate abuse. 4 *See Heartland Energy Services Inc.,* 68 FERC ¶ 61,223, at 62,062
(1994)( *Heartland* ) (discussing the potential for abuse in the case of affiliated power marketers); *Commonwealth Atlantic Limited Partnership,* 51 FERC ¶ 61,368, at 62,245
(1990)(discussing potential for reciprocal dealing if a buyer agrees to pay more for power from a seller in return for that seller (or its affiliates) paying more for power from that buyer (or its affiliates)). 5 *Boston Edison Company Re: Edgar Electric Energy Co.,* 55 FERC ¶ 61,382, at 62,137 n.56
(1991)( *Edgar* ). *See also TECO Power Services Corp.,* 52 FERC ¶ 61,191, at 61,697 n.41, *order on reh'g,* 53 FERC ¶ 61,202
(1990)(“The Commission has determined that self dealing may arise in transactions between affiliates because affiliates have incentives to offer terms to one another which are more favorable than those available to other market participants.”). 6 *See, e.g., Heartland,* 68 FERC at 62,062. 7 The Commission has found that a transaction between two non-traditional utility affiliates (such as power marketers, exempt wholesale generators (EWGs), or qualifying facilities (QFs)) does not raise the same concern about cross-subsidization because neither has a franchised service territory and therefore has no captive customers. As the Commission has explained, no matter how sales are conducted between non-traditional affiliates, profits or losses ultimately affect only the shareholders. *FirstEnergy Generation Corporation,* 94 FERC ¶ 61,177, at 61,613 (2001); *USGen Power Services, L.P.,* 73 FERC ¶ 61,302, at 61,846 (1995). With respect to affiliate power sales, the Commission has also developed guidelines on how to determine whether a transaction is above suspicion and captive customers are protected, as well as guidelines for competitive solicitation processes. *See Edgar,* 55 FERC at 62,167-69; *Allegheny Energy Supply Company, LLC,* 108 FERC ¶ 61,082, at 61,417 (2004). 5. Just as the Commission has expressed concern about the potential for affiliate abuse in connection with power sales between affiliates, it also has recognized that there may be a potential for affiliate abuse through other means, such as the pricing of non-power goods and services or the sharing of market information between affiliates. 8 The same concerns about giving undue profits to affiliated market-regulated entities and their shareholders, discussed above with respect to power sales, also apply with respect to these interactions. 8 *See, e.g., Potomac Electric Power Company,* 93 FERC ¶ 61,240, at 61,782
(2000)( *Potomac* ); *Heartland,* 68 FERC at 62,062-63. 6. Accordingly, the Commission's policy for many years had been to require that, as a condition of market-based rate authorization, applicants adopt a code of conduct applicable to non-power goods and services transactions and information sharing between regulated and non-regulated (market-regulated) affiliated power sellers. The Commission has also required that applicants include a provision in their market-based rate tariffs prohibiting power sales between regulated and non-regulated affiliated power sellers without first receiving authorization of the transaction under section 205 of the FPA. 9 9 *Aquila, Inc.,* 101 FERC ¶ 61,331, at P 12 (2002). 7. The purpose of the market-based rate code of conduct was to safeguard against affiliate abuse by protecting against the possible diversion of benefits or profits from franchised public utilities (i.e., traditional public utilities with captive ratepayers) to an affiliated entity for the benefit of shareholders. The Commission has waived the market-based rate code of conduct requirement in cases where there are no captive customers, and thus no potential for affiliate abuse, or where the Commission finds that such customers are adequately protected against affiliate abuse. 10 In such cases, however, the Commission directed the utilities to notify the Commission should they acquire captive customers in the future and expressly reserved the right to reimpose the market-based rate code of conduct requirement. 10 *See, e.g., CMS Marketing, Services and Trading Co.,* 95 FERC ¶ 61,308, at 62,051
(2001)(granting request for cancellation of code of conduct where wholesale contracts, as amended, “cannot be used as a vehicle for cross-subsidization of affiliate power sales or sales of non-power goods and services”); *Alcoa Inc.,* 88 FERC ¶ 61,045, at 61,119 (waiving code of conduct requirement where there were no captive customers); *Green Power Partners I LLC,* 88 FERC ¶ 61,005, at 61,010-11
(1999)(waiving code of conduct requirement where there are no captive wholesale customers and retail customers may choose alternative power suppliers under retail access program). 2. The Market-Based Rate Final Rule 8. In the Commission's recent Market-Based Rate Final Rule, 11 among other things, the Commission codified in the regulations at 18 CFR part 35, subpart H, an explicit requirement that any seller with market-based rate authority must comply with the affiliate power sales restrictions and other affiliate restrictions. Compliance on an ongoing basis is a condition of retaining market-based rate authority. The Market-Based Rate Final Rule retains the policy that wholesale sales of power between a franchised public utility and any of its market-regulated power sales affiliates must be pre-approved by the Commission. It also adopts uniform affiliate restrictions governing power sales, sales of non-power goods and services, separation of functions, and information sharing between franchised public utilities with captive customers and their market-regulated power sales affiliates. 12 The power and non-power goods and services restrictions, however, apply only to transactions involving two power sellers. They do not apply to transactions between a franchised public utility and a non-utility affiliate. 11 *Market-Based Rates For Wholesale Sales Of Electric Energy, Capacity and Ancillary Services by Public Utilities,* Order No. 697, 72 FR 39904 (July 20, 2007), FERC Stats. & Regs. ¶ 31,252
(2007)(Market-Based Rate Final Rule). 12 *Id.* P 23. B. Affiliate Transactions Under Section 203 1. Before the Energy Policy Act of 2005 9. The Commission has also addressed cross-subsidization issues in the context of section 203 merger applications. Prior to the Energy Policy Act of 2005, 13 the Commission's policy was to condition its approval of certain section 203 mergers on the applicants' agreement to abide by certain restrictions on non-power goods and services transactions between a merged company's utility and non-utility or market-regulated subsidiaries. The condition was imposed on those mergers involving registered holding companies under PUHCA 1935 14 in order to find that the merger would not adversely affect federal regulation. 15 That requirement grew out of judicial determinations that, when a merger would create or involve a registered holding company, the actions of the Securities and Exchange Commission
(SEC)may preclude the Commission from asserting jurisdiction over the non-power transactions between subsidiaries of that holding company. 16 Under *Ohio Power* , if the SEC approved an affiliate contract involving special purpose subsidiary goods or services at cost, the Commission had to allow pass-through of the costs in jurisdictional rates even if the public utility purchasing the goods or services could have obtained them at a lower market price from a non-affiliate. 17 For over a decade following the *Ohio Power* decision, the Commission required that, to gain section 203 approval of a proposed merger without a hearing, if the transaction would create a registered holding company under the PUHCA 1935, applicants must agree to waive the *Ohio Power* immunity and abide by the Commission's policy on intra-system transactions for non-power goods and services. 18 13 Energy Policy Act of 2005, Pub. L. 109-58, 1289, 119 Stat. 594, 982-83
(2005)(EPAct 2005). 14 EPAct 2005 repealed PUHCA 1935. EPAct 2005, Pub. L. 109-58, 1263. 15 *See, e.g., Niagara Mohawk Holdings, Inc.,* 95 FERC ¶ 61,381, at 62,414, *order on reh'g,* 96 FERC ¶ 61,144 (2001). 16 *See Ohio Power Co.* v. *FERC,* 954 F.2d 779, 782-86 (D.C. Cir.), *cert. denied sub nom., Arcadia* v. *Ohio Power Co.,* 506 U.S. 981
(1992)( *Ohio Power* ). 17 The Commission's policy since the mid-1990s has been that where the regulated public utility has provided non-power goods or services to the non-regulated affiliate, the public utility provides the goods or services at the higher of cost or market. A non-regulated affiliate that sells non-power goods or services to an affiliate with captive customers may not sell at higher than market price. This is often referred to as the “market” standard. These standards were articulated in the Commission's 1996 Merger Policy Statement. *Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement,* Order No. 592, 61 FR 68595 (Dec. 30, 1996), FERC Stats. & Regs. ¶ 31,044, at 30,124-25
(1996)(1996 Merger Policy Statement), *reconsideration denied,* Order No. 592-A, 62 FR 33341 (June 19, 1997), 79 FERC ¶ 61,321 (1997). 18 *Public Service Company of Colorado,* 75 FERC ¶ 61,325, at 62,046
(1996)( *PSC Colorado* ); 1996 Merger Policy Statement, FERC Stats. & Regs. ¶ 31,044 at 30,124-25. 2. After EPAct 2005 10. Because EPAct 2005 repealed PUHCA 1935, certain activities of previously-registered holding companies that were previously subject to SEC regulation, including intra-system affiliate transactions, are no longer exempt from this Commission's full regulatory review. In particular, the Commission's conditions and policies under FPA sections 205 and 206 with respect to non-power goods and services transactions between holding company affiliates may now be applied to all public utilities that are members of holding companies, whether in the context of a section 203 merger proceeding or the context of a section 205-206 rate proceeding. 19 In addition, the Commission has authority to review allocation of service company costs among members of holding companies that have public utilities with captive customers. 19 The provisions of PUHCA 1935 that formed the basis for *Ohio Power* are no longer in effect, thus removing the *Ohio Power* limitation on our oversight of non-power transactions. Further, FPA section 318, which provided for SEC preemption in certain circumstances where there was a conflict between SEC PUHCA 1935 regulation and Commission regulation, was repealed. 11. In the Order No. 669 rulemaking proceedings, 20 which revised the Commission's regulations pursuant to amended section 203, the Commission continued its past approach with respect to affiliate abuse restrictions involving power and non-power goods and services transactions, in the context of section 203 applications. 21 However, the Commission made two additional clarifications. 20 *Transactions Subject to FPA Section 203,* Order No. 669, 71 FR 1348 (Jan. 6, 2006), FERC Stats. & Regs. ¶ 31,200 (2005), *order on reh'g,* Order No. 669-A, 71 FR 28422 (May 16, 2006), FERC Stats. & Regs. ¶ 31,214, *order on reh'g,* Order No. 669-B, 71 FR 42579 (July 27, 2006), FERC Stats. & Regs. ¶ 31,225 (2006). 21 Amended section 203(a)(4) adds to the Commission's merger analysis the explicit requirement that the Commission find that any proposed transaction will not result in cross-subsidization of a non-utility associate company or the 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. 12. First, in its implementation of regulations pursuant to PUHCA 2005, 22 the Commission discussed one exception to the traditional standards articulated in the 1996 Merger Policy Statement. In the Order No. 667 rulemaking proceeding, 23 the Commission explained that there are two circumstances in which the at-cost or market standards may arise in the context of the Commission's jurisdictional responsibilities:
(1)The Commission's review of the costs of non-power goods and services provided by a traditional, centralized service company to public utilities within the holding company system; and
(2)when a service company that is a special-purpose company within a holding company provides non-power goods or services to one or more public utilities in the same holding company system. Under both scenarios, similar concerns regarding affiliate abuse arise: “[W]hether the public utility's costs incurred in purchasing from the affiliate are prudently incurred and just and reasonable, and whether non-regulated affiliates purchasing non-power goods and services from the same special-purpose company are receiving preferential treatment vis-à-vis the public utility.” 24 In Order No. 667, the Commission exempted traditional, centralized service companies, which at that time were using the SEC's “at-cost” standard, from complying with the Commission's market standard for their sales of non-power goods and services to regulated affiliates. 25 In determining that the at-cost standard was appropriate for traditional, centralized service companies, the Commission noted that centralized provision of the services provided by such companies (such as accounting, human resources, legal, tax, and other such services) benefits ratepayers through increased efficiency and economies of scale. Moreover, the Commission recognized that it is frequently difficult to define the market value of the specialized services provided by centralized service companies. On this basis, the Commission stated it would apply a rebuttable presumption that costs incurred under at-cost pricing of such services are reasonable. 26 However, with respect to non-power goods and services transactions between holding company affiliates other than traditional, centralized service companies, i.e., service companies that are non-regulated, special-purpose affiliates, such as a fuel supply company or a construction company, the Commission continued with its prior practice. 27 22 PUHCA 2005 is primarily a books and records access statute and does not give the Commission any new substantive authorities, other than the requirement that the Commission review and authorize certain non-power goods and services cost allocations among holding company members upon request. EPAct 2005, Public Law 109-58, 1275. 23 *Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005,* Order No. 667, 70 FR 75592 (Dec. 20, 2005), FERC Stats. & Regs. ¶ 31,197 (2005), *order on reh'g,* Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ¶ 31,213, *order on reh'g,* Order No. 667-B, 71 FR 42750 (July 28, 2006), FERC Stats. & Regs. ¶ 31,224 (2006), *order on reh'g,* 72 FR 8277 (Feb. 26, 2007), 118 FERC ¶ 61,133 (2007). 24 Order No. 667, FERC Stats. & Regs. ¶ 31,197 at P 168. 25 *Id.* P 169. 26 *Id.* The Commission stated, however, that it would entertain complaints that at-cost pricing for such services exceeds the market price, but complainants would have the burden of demonstrating that that is the case. 27 In Order No. 667, the Commission stated that, with respect to sales from a public utility to a non-regulated, affiliated special-purpose company, the price should be no less than cost, *i.e.,* the higher of cost or market; otherwise, a public utility could attempt to game the system and forego profits it could otherwise obtain by selling to a non-affiliate, to the benefit of its non-regulated affiliate who receives a good or service at a below-market price. The Commission also stated that, when the situation is reversed, *i.e.* , the non-regulated, affiliated special-purpose company is providing non-power goods and services to the public utility affiliate, the Commission will continue to apply its market standard. Accordingly, the non-regulated, affiliated special-purpose company may not sell to its public utility affiliate at a price above the market price. The Commission found that such transactions involving such non-regulated, affiliated special-purpose companies pose a greater risk of inappropriate cross-subsidization and adverse effects on jurisdictional rates. *Id.* P 171. 13. Second, in recent section 203 merger proceedings, the Commission has extended the applicability of the code of conduct restrictions previously applied only to registered holding companies. In *National Grid plc,* 28 the Commission announced that it would require all merging parties to abide by a code of conduct containing specific provisions regarding power and non-power goods and services transactions between the utility subsidiaries and their affiliates: 28 117 FERC ¶ 61,080
(2006)( *National Grid* ). Implementation of the Code of Conduct for all utility subsidiaries of the merged company, as required by our decision here, will address both power and non-power goods and services transactions between the utility subsidiaries and their affiliates. The Code of Conduct to be implemented by the merged company shall
(1)require our approval of all power sales by a utility to an affiliate,
(2)require a utility with captive customers to provide non-power goods or services to a non-utility or “non-regulated utility” affiliate at a price that is the higher of cost or market price,
(3)prohibit a non-utility or non-regulated utility affiliate from providing non-power goods or services to a utility affiliate with captive customers at a price above market price, and
(4)prohibit a centralized service company from providing non-power services to a utility affiliate with captive customers at a price above cost. These requirements protect a utility's captive customers against inappropriate cross-subsidization of non-utility or non-regulated utility affiliates by ensuring that the utility with captive customers neither recovers too little for goods and services that the utility provides to an affiliate nor pays too much for goods and services that the utility receives from an affiliate. Implementation of these requirements provides a prophylactic mechanism to ensure that the merger will not result in cross-subsidization of non-utility or non-regulated utility companies in the same holding company system and therefore meets the requirement of section 203(a)(4) that a merger not result in inappropriate cross-subsidization of a non-utility associate company. 29 29 *Id.* P 66 (internal citations removed). 14. While these affiliate restrictions are broad in terms of transactions covered (covering transactions between power sales affiliates as well as transactions between power sales affiliates and non-utility affiliates) and have been extended within the context of section 203 approvals, they do not apply to public utilities that do not need to seek section 203 merger approval. II. Affiliate Transactions NOPR 15. In the Affiliate Transactions NOPR, the Commission proposed to implement uniform affiliate restrictions that would be applicable to all franchised public utilities with captive customers and their market-regulated and non-utility affiliates and would address both power and non-power goods and services transactions between the utility and its affiliates. 30 The Commission's goal in proposing these prophylactic restrictions is to protect against inappropriate cross-subsidization of market-regulated and unregulated activities by the captive customers of franchised public utilities. The proposed restrictions are based upon those already imposed by the Commission in the context of certain section 203 and 205 approvals, but expand the transactions and entities to which they apply. 30 On July 20, 2007, the Commission took three actions based on the Commission's experience implementing amended FPA section 203 and PUHCA 2005, as well as the record from the Commission's December 7, 2006 and March 8, 2007 technical conferences regarding section 203 and PUCHA 2005. In this docket, the Commission issued the Affiliate Transactions NOPR. In addition, in separate orders, the Commission issued a section 203 Supplemental Policy Statement, and a Notice of Proposed Rulemaking proposing additional blanket authorizations under section 203 of the FPA. *FPA Section 203 Supplemental Policy Statement* , 72 FR 42277 (Aug. 2, 2007), FERC Stats. & Regs. ¶ 31,253
(2007)(Supplemental Policy Statement), *order on clarification and reconsideration* , 122 FERC ¶ 61,157 (2008); *Blanket Authorization Under FPA Section 203* , Notice of Proposed Rulemaking, 72 FR 41640 (July 31, 2007), FERC Stats. & Regs. ¶ 32,619
(2007)(Blanket Authorization NOPR); *see Blanket Authorization Under FPA Section 203* , Order No. 708, 122 FERC ¶ 61,156
(2008)(Blanket Authorization Final Rule). 16. Specifically, the proposed regulations would:
(1)Require the Commission's approval of all wholesale sales between a franchised public utility with captive customers and a market-regulated power sales affiliate;
(2)require a franchised public utility with captive customers to provide non-power goods and services to a market-regulated power sales affiliate or a non-utility affiliate at a price that is the higher of cost or market price;
(3)prohibit a franchised public utility with captive customers from purchasing non-power goods or services from a market-regulated power sales affiliate or a non-utility affiliate at a price above market price (with the exception of (4)); and
(4)prohibit a franchised public utility with captive customers from receiving non-power goods and services from a centralized service company at a price above cost. The Commission stated that these restrictions would help the Commission meet the requirement of amended section 203(a)(4) that a transaction not result in the inappropriate cross-subsidization of a non-utility associate company and, moreover, help the Commission assure just and reasonable rates and the protection of captive customers for all public utilities pursuant to sections 205 and 206 of the FPA, irrespective of whether they need approval of a section 203 transaction. III. Procedural Matters 17. The Affiliate Transactions NOPR invited comments on the proposed regulations. Comments on the Affiliate Transactions NOPR were filed by: American Public Power Association and National Rural Electric Cooperative Association (APPA/NRECA); Edison Electric Institute (EEI); Entergy Services, Inc. (Entergy); Interstate Gas Supply, Inc. (IGS); National Grid USA (National Grid); New York State Public Service Commission (New York Commission); NiSource Inc. (NiSource); Occidental Power Marketing, L.P. (Occidental); Oklahoma Corporation Commission (Oklahoma Commission); Pacific Gas and Electric Company (PG&E); the Pinnacle West Companies (Pinnacle West); 31 and San Diego Gas & Electric Company and Southern California Gas Company (Sempra). 32 31 For purposes of their filing, the Pinnacle West Companies include: Pinnacle West Marketing & Trading Co., LLC; Arizona Public Service Company; and APS Energy Services Company, Inc. 32 Although unnecessary to preserve their rights to participate in a rulemaking proceeding, Allegheny Power and Allegheny Energy Supply Company, LLC filed a motion to intervene without comments. IV. Discussion 18. This Final Rule explains the Commission's authority and jurisdiction under sections 205 and 206 of the FPA to regulate affiliate transactions to ensure that public utility rates are just, reasonable, and not unduly discriminatory or preferential. This Final Rule implements affiliate restrictions applicable to power sales and transactions for non-power goods and services between franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities, and their market-regulated and non-utility affiliates. A. General Matters 1. The Need for the Proposed Regulations a. *Comments* 19. EEI argues that the Commission has not demonstrated a need for the proposed regulations. While EEI agrees that the Commission has been applying affiliate transactions restrictions in the context of section 203 and market-based rates, 33 EEI argues that the Affiliate Transactions NOPR goes too far. EEI argues that the Commission does not provide any examples of the problems that the Commission has discovered in the pricing of utility-affiliate transactions that would warrant the expanded new regulations. EEI also argues that there is sufficient regulatory oversight by the Commission and state commissions, so this extension of policy is not warranted. 33 EEI asserts that the Affiliate Transactions NOPR states that the Commission currently waives market-based rate code of conduct requirements and allows transactions in cases where there are no captive customers or customers are protected against affiliate transactions, but that exception is not reflected in the Market-Based Rate Final Rule. 20. Moreover, EEI argues that the Commission's authority to regulate utility-affiliate transactions under sections 205 and 206 is limited to determining whether jurisdictional rates are just and reasonable. EEI argues that the Commission has not demonstrated why the proposed regulations are necessary to achieve a just and reasonable result. EEI also argues that the Affiliate Transactions NOPR indirectly proposes to regulate entities over which the Commission has no jurisdiction—EWGs, QFs, and non-utilities—by imposing constraints on the prices that utilities may pay these companies for non-power goods and services and the companies in turn must pay the utilities for such goods and services. 34 34 EEI Comments at 6-7 (citing *Sunray Mid-Continental Co.* v. *FPC* , 364 U.S. 137, 142 (1960); *Altamont Gas Transmission Co.* v. *FERC* , 92 F.3d 1239 (D.C. Cir. 1996); *National Fuel Gas Supply Corp.* v. *FERC* , 909 F.2d 1519 (D.C. Cir. 1990)). 21. EEI also argues that the Commission's adoption of the rules as a “prophylactic” measure ignores the wording of the Commission's cross-subsidy authority under section 203 by failing to recognize that certain transactions may be in the public interest. b. *Commission Determination* 22. We disagree with EEI regarding the need for the proposed regulations or the Commission's authority to enact them. Sections 205 and 206 of the FPA require the Commission to ensure that public utility rates are just, reasonable and not unduly discriminatory or preferential. A rate is not just and reasonable if it includes costs which the Commission finds are imprudently incurred or which require a customer to bear costs that are unreasonable. Further, the Commission must ensure that no public utility makes or grants an undue preference with respect to any transmission or sale subject to the Commission's jurisdiction. 35 The Commission has the authority to address these types of rate issues not only in individual cases, but also to set standards by rulemaking with respect to what costs will or will not be considered just and reasonable. The Commission's experience makes clear the need for these types of restrictions and we believe they are particularly warranted in light of the repeal of PUHCA 1935 and our need to be vigilant with respect to holding companies and affiliate transactions. 35 Although section 203 of the FPA requires the Commission to recognize that certain cross-subsidization or pledges or encumbrances of utility assets can be in the public interest, the proposed regulations are set forth pursuant to the Commission's authority under sections 205 and 206 of the FPA. 23. As discussed above, the Commission has a long history of requiring public utilities to comply with affiliate restrictions where an entity seeks market-based rate authorization and in the context of seeking merger authorization under section 203 of the FPA. However, limiting affiliate restrictions to these two contexts leaves a regulatory gap. As the Affiliate Transactions NOPR explained,
(1)restrictions on market-based rate applicants do not cover non-power goods and services transactions between a franchised public utility and non-utilities; they cover only transactions between power sales affiliates and are imposed on only the market-based rate applicants;
(2)restrictions imposed on section 203 applicants only apply to merger applicants;
(3)the pricing policy set forth in Order No. 667 regarding non-power goods and services provided by centralized service companies was not codified in the regulations; and
(4)not all states regulate these types of transactions. 36 The purpose of the proposed regulations therefore is to supplement existing affiliate restrictions to cover transactions between all franchised public utilities with captive customers and their non-utility affiliates. Just as the Commission has adopted regulations designed to prevent captive customers of franchised public utilities from inappropriately cross-subsidizing the activities of market-regulated affiliates (such as affiliated power marketers), so too the Commission wants to ensure that captive customers of franchised public utilities do not inappropriately cross-subsidize the activities of non-utility affiliates (such as an affiliated construction services firm, real estate company, legal services companies, fuel supply companies, or other non-utility affiliates). For example, where a franchised public utility with captive customers transacts with an affiliated non-utility construction services firm, the Commission is concerned that the franchised public utility with captive customers not pay an above-market price for construction services provided by the affiliated construction firm. Otherwise, the public utility's customers would be inappropriately cross-subsidizing the activities of the affiliate. Indeed, non-utility affiliates such as real estate companies, legal services companies, fuel supply companies or other companies selling non-power goods and services could provide similar opportunities for affiliate abuse and improper cross-subsidization. 36 Affiliate Transactions NOPR, FERC Stats. & Regs. ¶ 32,618 at P 15. 24. Finally, we disagree with EEI that the Affiliate Transactions NOPR indirectly proposes to regulate entities over which the Commission “has no jurisdiction”—EWGs, QFs, and non-utilities. As an initial matter, the Commission does, in fact, have certain jurisdiction over QFs, and most EWGs are jurisdictional public utilities. More importantly, however, the pricing rules we adopt here are rooted in our authority to impose pricing rules with respect to certain sales and purchases by public utilities (including EWGs) over whom we have rate jurisdiction under the FPA. These restrictions are tied directly to the reasonableness of public utility rates and the Commission has the statutory responsibility to protect captive customers from unjust and unreasonable rates. 2. The Scope of the Proposed Regulations a. *Comments* 25. Several commenters filed comments concerning the scope of the proposed regulations. APPA/NRECA ask that the Commission clarify that the regulations adopted in this proceeding do not preclude the Commission from imposing additional cross-subsidization restrictions on affiliate transactions as appropriate on a case-by-case basis. 26. The Oklahoma Commission notes that the Commission stated that it would require all merging parties to abide by a code of conduct that has specific provisions regarding power and non-power goods and services transactions between the utility subsidiaries and their affiliates. The Oklahoma Commission urges to the Commission to continue to do so. The Oklahoma Commission also asks that the Commission add language that states that section 203 does not preempt applicable state law concerning reporting requirements, which would further protect the interest and authority of state commissions. 27. IGS agrees with the Commission's proposal to codify affiliate restrictions but suggests that the intent of the code of conduct requirement also includes preventing a utility or its affiliate from gaining unfair advantages in a market, thus impeding the development of a competitive market. IGS agrees that a code of conduct should be codified and expanded to apply to non-power goods and services, and that a code of conduct and related rules should also apply outside the context of merger situations. IGS also agrees that, even outside of the context of a merger, it is important that utility/affiliate code of conduct and related rules apply. IGS further agrees that it is appropriate for the code of conduct and related rules to apply to transactions involving non-power goods and services because, among other things, consumers may not be able to differentiate easily between affiliates and traditional regulated utility and where affiliates are provided preferential access and opportunities, competition is stifled. In addition, IGS argues that the same opportunity for abuse exists in the natural gas industry. It maintains that the same affiliate restriction concepts should be extended to natural gas utilities, and should be considered whenever the utility has an economic interest in the sale of the commodity or non-commodity goods or services. 28. Occidental argues that the proposed regulations permit a utility to circumvent the affiliate transactions restrictions by simply conducting all of its market-based rate activities within its franchised public utility. Occidental asks that the Commission explicitly require that the functional attributes, rather than the arbitrary structure, of a utility be considered in determining compliance with the rule's affiliate abuse restrictions. b. *Commission Determination* 29. We agree with APPA/NRECA that the pricing rules that we adopt in this proceeding do not preclude the Commission from imposing additional cross-subsidization restrictions on affiliate transactions, as appropriate, on a case-by-case basis. 30. Regarding the Oklahoma Commission's request that we continue to require all merging parties to abide by a code of conduct that has specific provisions regarding power and non-power goods and services transactions between the utility subsidiaries and their affiliates, although this rulemaking is not under section 203, as discussed *supra* , as a condition of section 203 authorization for mergers, we have already stated in the context of section 203 proceedings that we will continue to impose affiliate restrictions on entities seeking merger authorization under section 203 of the FPA. Further, we clarify that neither the rules we adopt here, nor the cross-subsidization restrictions imposed under section 203 of the FPA, preempt applicable state law concerning reporting requirements. 31. We deny IGS' request to expand the proposed regulations to include preventing a utility or its affiliate from gaining unfair advantage in a market. The scope of the proposed regulations is to protect against inappropriate cross-subsidization of affiliates by franchised public utilities with captive customers. We note, however, the cross-subsidy protections go a long way to preventing such unfair advantages since market-regulated or non-regulated companies may have an unfair competitive advantage in the marketplace if others bear some of their costs of doing business. 32. We also deny IGS' request to expand the scope of the proposed regulations to include the natural gas industry. As discussed above, the focus of this rulemaking is public utilities—specifically, franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities. We find that there is an insufficient record to warrant including LDCs and interstate pipelines within the scope of the regulations at this time. 33. Finally, we decline to revise the scope of the proposed regulations to address Occidental's concern that the proposed regulations permit a utility to circumvent the affiliate transactions restrictions by simply conducting all of its market-based rate activities within its franchised public utility. We note that Occidental has raised this concern in its request for rehearing of the Market-Based Rate Final Rule. We find that this concern is more appropriately addressed on rehearing of that order. B. Specific Issues 1. Definitions a. *Captive Customers* i. *Comments* 34. Commenters seek a number of clarifications concerning the definition of “captive customers.” 35. EEI and Pinnacle West ask the Commission to clarify that wholesale customers with fixed price contracts are not “captive customers” even if the contracts are cost-based, because there is no risk of harm to such customers from utility-affiliate transactions. 36. Occidental argues that the Commission should revise the definition of “captive customer” to not include wholesale customers. Occidental argues that the Commission clarified in the Market-Based Rate Final Rule that retail customers that have retail choice are not captive customers. Occidental maintains that wholesale customers, whether cost-based or market-based, have alternatives and therefore, are not captive. Accordingly, Occidental argues that the definition of “captive customer” should be limited to retail customers served under cost-based regulation who do not have retail choice available, and should not include wholesale customers which have choices. 37. EEI, National Grid, and Pinnacle West ask the Commission to clarify its definition of “captive customers” consistent with its use of the term in the preamble of the Market-Based Rate Final Rule. In this regard, they ask that the Commission clarify that retail customers in states with retail competition are not “captive customers” for purposes of the affiliate restrictions. Pinnacle West also states that the Commission clarified in Order No. 697 that, for companies the Commission has acknowledged in prior orders as not having captive customers, the affiliate transaction restrictions can be waived. It asks the Commission to provide the same clarification and exemptions in this proceeding. 38. IGS, on the other hand, argues that the restrictions proposed in the Affiliate Transactions NOPR should not be waived for utilities simply because those utilities implement a retail choice program. IGS argues that the ability of a customer to purchase commodities from an alternative power supplier under a retail access program does not mean that these customers are not captive for purposes of receiving their distribution service under cost-based legislation. IGS also states that the restrictions should apply even if the retail customer has a competitive alternative available. It further argues that, as long as a utility is in the business of providing commodity service, there is an opportunity for abuse. 39. EEI and National Grid also ask that the Commission clarify that “captive customers” do not include transmission customers, consistent with the Market-Based Rate Final Rule. By contrast, APPA/NRECA ask that the definition of “captive customers” be expanded to expressly include transmission customers. APPA/NRECA state that the Commission recognized in both the Order No. 669 series and the Order No. 667 series that transmission customers must be protected against cross-subsidization along with captive wholesale and retail customers. They note that the Commission adopted regulatory language in Order No. 669-A “to cover public utilities that own or provide transmission service over Commission-jurisdictional transmission facilities,” and ask that the Commission clarify the regulatory text in the Final Rule to ensure that the new generic cross-subsidization regulation explicitly protects transmission customers. 40. APPA/NRECA also ask that the Commission confirm, consistent with the Market-Based Rate Final Rule, that the affiliate transactions rules do not apply to electric cooperatives. ii. *Commission Determination* 41. The term “captive customers” is used in a number of recently adopted Commission rules, including Order No. 667, Order No. 669, and the Market-Based Rate Final Rule. The Commission for many years had used this term in its orders without definition, but in both the Order No. 669 series and the Market-Based Rate Final Rule, the Commission included in the regulatory text a definition or description of “captive customers” as: “any wholesale or retail electric energy customers served under cost-based regulation.” 37 Based on the comments received, we recognize that there may be some ambiguity as to what types of customers are considered to be under “cost-based regulation” and we provide additional clarifications below. We also modify the definition to make clear that it is intended to refer to customers of franchised public utilities. First, however, we believe it is important to discuss the purpose of our definition and its focus on “cost-based regulation.” 37 Order No. 669-A, FERC Stats. & Regs. ¶ 31,214 at P 147; Market-Based Rate Final Rule, FERC Stats. & Regs. ¶ 31,252 at P 23; *see also* Order No. 667-A, FERC Stats. & Regs. ¶ 31,213 at n.35. 42. The Commission's fundamental goal in categorizing certain customers as “captive” is to protect customers served by franchised public utilities from inappropriately subsidizing the market-regulated or non-utility affiliates of the franchised public utility or otherwise being financially harmed as a result of affiliate transactions and activities. In other words, we are concerned about the potential for the inappropriate transfer of benefits from such customers to the shareholders of the franchised public utility or its holding company. 38 Where customers are served under market-based regulation as opposed to cost-based regulation, it is presumed that the seller has no market power over a customer and that the customer has a choice of suppliers; thus, there is less opportunity for a customer to involuntarily be in a situation in which its rates subsidize or support another entity. 38 For example, if a market-regulated seller sells power to its affiliated franchised public utility at an above market price, the customers of the franchised public utility pay more than they need to for power and the affiliate makes a higher profit for the holding company's shareholders. Similarly, if a franchised public utility sells temporarily excess fuel to its market-regulated power seller affiliate at a price below its cost, the customers of the franchised utility end up subsidizing the affiliate's operating costs, to the benefit of shareholders and the detriment of the customers of the franchised utility. In other contexts, an extreme example would be a holding company that siphons funds from a franchised public utility to support its failing non-regulated affiliate company; again, this results in financial benefit to shareholders at the expense of customers. 43. Under a regime of cost-based regulation, however, we cannot make these same assumptions. If a franchised public utility is selling at a wholesale cost-based rate under the FPA, the franchised utility seller may be in the position of potentially trying to flow through its cost-based rates costs that should instead be borne by its affiliates, *i.e.,* potentially subsidizing the “non-regulated” activities of its market-regulated and non-utility affiliates to the detriment of the franchised public utility's customer(s). While there is some merit to Occidental's assertion that wholesale customers, by definition, have alternatives and that there is no obligation for a wholesale seller to sell to any buyer, nor for a buyer to buy from any particular seller, for the customer protection reasons stated above, we believe it is important to err on the side of a broad definition of captive customers. 44. Although we are erring on the side of a broad definition of captive customers, we recognize that there may well be circumstances in which customers fall within our definition but nevertheless there are sufficient protections in place to protect such customers against any risk of harm from transactions between the franchised public utility and its affiliates. For example, it is possible, as advocated by EEI and Pinnacle West, that wholesale customers with fixed rate contracts would be adequately protected and that the affiliate restrictions of this rule should not apply to utilities whose customers all have fixed rate contracts with no fuel adjustment clause. 39 We are not prepared at this time to generically exclude such customers from the definition of captive customers but instead will allow franchised public utilities, on a case-by-case basis, to seek a waiver of the affiliate restrictions. This will allow the Commission to closely examine the facts related to each franchised public utility. There may be circumstances other than fixed rate contracts in which we may be willing to waive the affiliate restrictions of this rule, but a public utility will need to demonstrate that there is no opportunity for wholesale customers of the franchised public utility to be harmed as a result of affiliate transactions. 39 The Commission would need to be assured that all wholesale customers of a franchised public utility have adequate fixed rate contracts, not just a sub-set of the customers. Further, because such contracts may have different expiration dates, the Commission might need to place temporal conditions on such a waiver. 45. With respect to requested clarifications regarding retail customers in states with retail competition, consistent with our Market-Based Rate Final Rule, we clarify that customers with retail choice are not considered to be customers served under “cost-based regulation” and therefore are not considered captive customers. These customers have retail choice, i.e., by virtue of state law they can purchase at market-based rates from retail suppliers other than a franchised public utility. 40 As the Commission explained in the Market-Based Rate Final Rule, in a regulatory regime in which retail customers have no ability to choose a supplier, they are considered captive because they must purchase from the local utility pursuant to rates set by a state or local regulatory authority. However, retail customers in retail choice states who choose to buy power from their local utility at cost-based rates as part of that utility's provider-of-last resort obligation are not considered captive customers because, although they may choose not to do so, they have the ability to take service from a different supplier whose rates are set by the marketplace. 41 We clarify, however, that if a state regulatory authority in a retail choice state does not believe retail customers are sufficiently protected and that our affiliate restrictions should apply to the local franchised public utility, it may file a petition for declaratory order to deem its retail customers to be captive customers for purposes of applying the affiliate restrictions. 42 40 As further discussed in the Market-Based Rate Final Rule, the role of this Commission is not to evaluate the success or failure of a state's retail choice program including whether sufficient choices are available for customers inclined to choose a different supplier. In this regard the states are best equipped to make such a determination and, if necessary, modify or otherwise revise their retail access programs as they deem appropriate. Further, to the extent a retail customer in a retail choice state elects to be served by its local utility under provider-of-last resort obligations, the state or local rate setting authority, in determining just and reasonable cost-based retail rates, would in most circumstances be able to review the prudence of affiliate purchased power costs and disallow pass-through of costs incurred as a result of an affiliate's undue preference. Market-Based Rate Final Rule, FERC Stats. & Regs. ¶ 31,252 at P 481. Also, we note that some states have chosen to impose their own affiliate restrictions in such circumstances. 41 *Id* . If the retail choice program is not available to all customers in the state, those customers that do not have retail choice would be considered captive customers of the franchised public utility that serves them, and our affiliate restrictions would apply to the franchised public utility. 42 Under the Commission's regulations, states are exempt from filing fees for petitions for declaratory order. 18 CFR 381.108. 46. As a general matter, we also clarify that the definition of captive customers, and our interpretations of the term, are intended to be applied uniformly in implementing all of our rules. In connection with the affiliate restrictions adopted in the Market-Based Rate Final Rule, we clarified that those affiliate restrictions will not apply where a seller demonstrates, and the Commission agrees, that the seller has no captive customers. 43 We also clarified that any sellers that have previously demonstrated and been found not to have captive customers, and therefore have received a waiver of the market-based rate code of conduct requirement in whole or in part, will not be required to request another waiver of the associated affiliate restrictions. 44 We will adopt a similar approach with regard to the cross-subsidization affiliate restrictions that we adopt in this Final Rule. If a utility makes a showing that it has no captive customers, and the Commission agrees, the affiliate cross-subsidization restrictions will not apply. If a public utility has received a finding that it has no captive customers for purposes of meeting the market-based rate affiliate restrictions, such filing will be deemed sufficient here. However, the utility must make an informational filing with the Commission stating that the affiliate restrictions we adopt in this Final Rule do not apply. 43 Market-Based Rate Final Rule, FERC Stats. & Regs. ¶ 31,252 at P 552. 44 *Id.* P 551. 47. Further, in considering the comments in this docket and in the Market-Based Rate Final Rule (pending rehearing), and in reviewing the use of the definition of captive customers in our other rules, we believe it appropriate to modify the definition of captive customers to make explicit what was only implicit in our earlier rules—that the definition is intended to apply to customers served by a franchised public utility under cost-based regulation. Accordingly, we will modify the term to mean: “any wholesale or retail electric energy customers served *by a franchised public utility* under cost-based regulation.” 45 45 We recognize that this amended definition will result in redundancy in certain of our regulations since some regulations refer to “franchised public utilities with captive customers” and other regulations simply refer to “captive customers” without elaboration. However, we believe the amendment will eliminate possible confusion in future interpretations. 48. In response to clarification requests by APPA/NRECA that we modify our proposed regulatory text so that the affiliate restrictions apply not only to franchised public utilities that have captive customers but also to public utilities that own Commission-jurisdictional transmission facilities or provide Commission-jurisdictional transmission service, we will grant the request. Thus, the affiliate restrictions will apply where a franchised public utility has captive customers or owns or provides transmission service over Commission-jurisdictional transmission facilities. While some franchised public utilities have captive customers, others do not, although they own or provide transmission service over Commission-jurisdictional transmission facilities. 46 The customers of these franchised public utilities also should not inappropriately be required to subsidize “non-regulated” activities of the affiliates of such utilities. 47 46 A public utility that has no captive power customers but that owns or provides transmission service over Commission-jurisdictional facilities may seek a waiver of the affiliate restrictions if it can demonstrate that transmission customers are adequately protected against inappropriate cross-subsidization. 47 For example, if a franchised public utility owns transmission facilities and also owns a non-utility construction services firm, the public utility's customers should not pay an above market price for construction services to upgrade transmission facilities. 49. Finally, we clarify that, consistent with the Market-Based Rate Final Rule, we will continue to treat electric cooperatives as not subject to the Commission's affiliate abuse restrictions. 48 48 Market-Based Rate Final Rule, FERC Stats. & Regs. ¶ 31,252 at P 526. b. *Non-Utility Affiliate* i. *Definition of “Affiliate”*
(a)*Comments* 50. PG&E asks the Commission to clarify the definition of “affiliate,” as used in the definition of non-utility affiliate. 49 PG&E states that the Commission should clarify whether the proposed regulations use the definition of affiliate set forth in the PUHCA 2005 regulations or some other definition. 49 As defined in the proposed regulations, “non-utility affiliate” means “any affiliate that is not in the power sales or transmission business.”
(b)*Commission Determination* 51. In response to PG&E's request for clarification concerning the definition of affiliate in the proposed regulations, we have considered the use of the term affiliate in the context of the Affiliate Transactions NOPR, the Commission's Standards of Conduct for Transmission Providers, and other precedent. 50 We have also reviewed the affiliate definitions contained in both the PUHCA 1935 and PUHCA 2005 and have considered the fact that, with respect to certain affiliate preferences or advantages involving EWG rates and charges, we are specifically required by FPA section 214 51 to use the definition contained in PUHCA 1935. After taking into account these differing definitions of affiliate (or, in some cases, no definition at all, as in the context raised by PG&E), and recognizing the need to provide greater clarity and consistency in our rules, we believe it is important to try to adopt a more consistent definition in our various rules and also one that is sufficiently broad to allow us to adequately protect customers. 52 50 *See, e.g., Morgan Stanley Capital Group, Inc.* , 72 FERC ¶ 61,082, at 61,436-37
(1995)( *Morgan Stanley* ). 51 16 U.S.C. 824m. 52 For example, we adopt this definition of affiliate for purposes of section 203 of the FPA in the concurrent Blanket Authorization Final Rule. 52. Our goal is to have a more consistent definition of affiliate for purposes of both EWGs and non-EWGs to the extent possible, as well as to strengthen the Commission's ability to ensure that customers are protected against affiliate abuse. Accordingly, having studied the clarity and scope of various definitions, we believe it appropriate to modify the definition proposed in the Affiliate Transactions NOPR to explicitly incorporate the PUHCA 1935 definition of affiliate for EWGs (rather than incorporate it by reference as previously has been done). We will also adopt the PUHCA 1935 definition of affiliate for non-EWGs, but with adjustments to reflect our previously-used 10 percent voting interest threshold for non-EWGs and to eliminate certain language not applicable or necessary in the context of the FPA. This is discussed more fully below. 53. In the case of non-EWG public utilities, our past approach has been that a voting interest of 10 percent creates a rebuttable presumption of control for purposes of determining the existence of an affiliate relationship. 53 For EWGs, on the other hand, section 214 of the FPA specifies that the term affiliate shall have the same meaning as provided in section 2(a) of PUHCA 1935 (which, *inter alia* , contains a five percent voting interest test) for purposes of determining whether an electric utility is an affiliate of an EWG for purposes of evaluating EWG rates. Although PUHCA 2005 also contains a definition of affiliate, which has been incorporated in § 366.1 of our regulations, that definition is not the same as the definition contained in PUHCA 1935. Indeed, it is narrower than the definition contained in PUHCA 1935. 54 53 *See Morgan Stanley* , 72 FERC at 61,436-37; 18 CFR 358.3(b) and (c). 54 It is not clear whether some of the language from PUHCA 1935 was inadvertently omitted from the PUHCA 2005 definition or whether Congress thought a more narrow definition was appropriate with respect to a “books and records” access statute. In either case, the PUHCA 1935 definition provides a more “bright line” approach while still reserving the agency's ability to deem an entity an affiliate based on specific circumstances, thus better ensuring the ability to protect customers. 54. In particular, the PUHCA 2005 definition defines affiliate of a company to mean “any company, 5 percent or more of the outstanding voting securities of which are owned, controlled, or held with power to vote, directly or indirectly, by such company.” The PUHCA 1935 definition, on the other hand, also defines as an affiliate of a specified company “any person that directly or indirectly owns, controls, or holds with power to vote, 5 per centum or more of the outstanding voting securities of such specified company” and “any individual who is an officer or director of such specified company, or of any company which is an affiliate thereof * * *.” In addition, the PUHCA 1935 definition also includes in the definition of affiliate “any person or class of persons that the Commission determines, after appropriate notice and opportunity for hearing, to stand in such relation to such specified company that there is liable to be such an absence of arm's-length bargaining in transactions between them as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that such person * * *” be treated as an affiliate. 55. Because FPA section 214 directs the Commission to use the definition of affiliate that appears in PUHCA 1935 with respect to certain affiliate preferences affecting rates or charges of EWGs, we will revise the definition proposed in the Affiliate Transactions NOPR to be consistent with the PUHCA 1935 definition. 55 55 Section 214 provides that no rate or charge of an EWG shall be lawful if, after notice and opportunity for hearing, the Commission finds that it resulted from any undue preference or advantage received from an electric utility that is an associate or affiliate of the EWG. 56. We also will revise the definition of “affiliate” for purposes of non-EWGs utilities to be consistent with the definition of “affiliate” for EWGs, except to the extent we believe it may leave a gap in coverage or contains language not applicable to the FPA. The definition we adopt for non-EWGs essentially parallels the EWG definition (with certain exceptions that we discuss below), while retaining the 10 percent voting interest threshold contained in the current regulations. Use of the PUHCA 1935 definition for non-EWGs may capture under the definition of “affiliate” entities that otherwise would not have been treated as affiliates under the definition currently in place in the Commission's regulations. We believe it is appropriate to adopt a broader definition, one that is largely consistent with the definition for EWGs, because it will strengthen the Commission's ability to ensure that customers are protected against affiliate abuse. For example, the revised affiliate definition for non-EWGs will give the Commission the ability to treat an entity as an affiliate of a company if, after notice and opportunity for hearing, the Commission finds that “there is liable to be such an absence of arm's-length bargaining in transactions between them as to make it necessary or appropriate in the public interest or for the protection of investors or consumers” that such entity be treated as an affiliate. It also is consistent with other recent orders and rules (e.g., the Supplemental Policy Statement) in which we have provided greater clarity as to what is considered “control” of an entity. 57. While the affiliate definition we adopt for non-EWGs essentially parallels the EWG definition, there are a number of exceptions. One exception is that the non-EWG definition also defines an affiliate of a specified company to include “any person that is under common control with such specified company.” This language is included in the definition of non-EWG affiliate that currently is in the Commission's regulations and identifies an additional instance in which an entity will be deemed to be an affiliate of a specified company. On this basis, we believe it appropriate to include this language as part of the non-EWG definition. Because the “under common control with” language is not part of the PUCHA 1935 definition, however, we cannot also include it as part of the definition of affiliate for purposes of EWGs. We also include as part of the non-EWG affiliate definition a provision making clear that where a person owns, controls, or holds with power to vote less than 10 percent of the outstanding voting securities of a specified company, this creates a rebuttable presumption of lack of control. Although the PUHCA 1935 definition does not contain a parallel provision with regard to the five percent threshold in the case of EWGs, we nevertheless believe that it is appropriate to include this rebuttable presumption as part of the non-EWG definition because it provides greater clarity concerning the circumstances in which an entity will be presumed not to be an affiliate. 58. Another exception concerns the provision in the PUHCA 1935 definition that includes as an affiliate of a specified company “any individual who is an officer or director of such specified company, or of any company which is an affiliate thereof * * *.” We do not believe it necessary to include that language as part of the affiliate definition for non-EWGs because we already are including in the definition, a provision giving the Commission the ability to treat an entity as an affiliate if, after notice and opportunity for hearing, the Commission finds that there is liable to be an absence of arm's-length bargaining in transactions between two entities. 56 56 With respect to this provision, we note that we are omitting language referencing the duties, obligations and liabilities imposed by PUHCA 1935 since those are no longer applicable in light of repeal of PUHCA 1935. 59. In sum, we believe that the definition of affiliate that we adopt in this Final Rule will provide greater clarity to public utilities and customers with respect to identifying which entities are considered to be affiliates for purposes of the regulations that we adopt in this Final Rule. ii. *Definition of “Non-Utility Affiliate”*
(a)*Comments* 60. NiSource argues that the Commission should revise the definition of non-utility affiliate because it could inadvertently include state-regulated local distribution companies
(LDCs)and Commission-regulated interstate pipelines because they are not in the power sales or transmission business. NiSource notes that the regulatory text strongly suggests that the Commission intended the definition of non-utility affiliate to apply only to “unregulated” entities. NiSource argues that this is important because any franchised public utility with captive customers would have to price sales of non-power goods and services to any non-utility affiliate at the higher of cost or market. NiSource argues that imposing this pricing requirement on LDCs and Commission-regulated interstate pipelines (as non-utility affiliates):
(1)Is inconsistent with the intent of the regulations, which is to prevent cross-subsidization of a “non-utility associate company” as derived from PUHCA 1935 and PUHCA 2005,
(2)could conflict with state requirements, and
(3)is unnecessary because the Commission and the states have ample authority to review such transactions.
(b)*Commission Determination* 61. We agree with NiSource and clarify that the definition of non-utility affiliate does not apply to utility affiliates that sell or transport natural gas, such as LDCs, or Commission-regulated interstate pipelines. However, we will not foreclose the expansion of the definition of non-utility affiliate to include LDCs and/or interstate pipelines if circumstances warrant it in the future. 2. Pricing Non-Power Affiliate Transactions 62. In the Affiliate Transactions NOPR, the Commission proposed to implement affiliate restrictions that would be applicable to transactions for non-power goods and services between franchised public utilities with captive customers and their market-regulated and non-utility affiliates. Specifically, the Commission proposed that:
(1)A franchised public utility with captive customers that provides non-power goods and services to a market-regulated power sales affiliate or a non-utility affiliate should charge a price that is the higher of cost or market price;
(2)a franchised public utility with captive customers should be prohibited from purchasing non-power goods and services at a price above market price from market-regulated power sales affiliates and non-utility affiliates, with the exception of centralized service companies; 57 and
(3)a franchised public utility with captive customers should be prohibited from buying non-power goods and services from a centralized service company at a price above cost. 58 The Affiliate Transactions NOPR indicated that each of the proposed restrictions was consistent with restrictions previously imposed in the 203-merger context. 59 57 Order No. 667 defines centralized service companies as performing generally corporate administration functions, such as accounting, human resources, legal and tax services, while special-purpose non-utility affiliates provide generally a single input to utility operations, such as fuel supply, construction or real estate. Order No. 667, FERC Stats. & Regs. ¶ 31,197 at P 171 n.178. 58 Affiliate Transactions NOPR, FERC Stats. & Regs. ¶ 32,618 at P 16. 59 *See, e.g., National Grid* , 117 FERC ¶ 61,080 at P 66. a. *Comments* 63. Several commenters suggest that the Commission's proposal will raise prices within holding company systems by creating inefficiencies. Specifically, EEI, Entergy, NiSource and PG&E argue that the Commission should require at-cost pricing for all transactions within a holding company system regardless of whether the services are provided for or by the franchised public utility. They contend that an at-cost standard creates savings through economies of scale that apply whether the employee providing the non-power good or service is located in a centralized service company, a utility or another affiliate. In addition, they note that it is difficult to find a market price for affiliate transactions for such goods and services. 64. EEI and PG&E further argue that requiring a utility to charge an affiliate the “higher of cost or market” would likely increase costs to both the utility and the affiliate by discouraging the efficient sharing of services. As a substitute for the “higher of cost or market” requirement for sales by a franchised public utility to an affiliate, they state that the Commission should allow the fully loaded cost to be a proxy for the market price for sales of non-power services by a utility to its affiliates. 65. National Grid argues that at-cost pricing for sales of non-power goods and services provided by a franchised public utility to a centralized service company would be consistent with the Commission's rationale for allowing at-cost pricing for sales in the opposite direction. It states that the Commission established at-cost pricing in Order No. 667 to encourage centralization of certain services that provide economies of scale that benefit customers, and that these benefits occur whether a franchised public utility is buying or selling non-power goods or services to or from its centralized service company. It argues that requiring at-cost pricing for transactions from a centralized service company to a franchised public utility on the one hand, while requiring at-the-higher-of-cost-or-market pricing for transactions from a franchised public utility to a centralized service company on the other hand, creates a bifurcated-pricing structure that undermines efficient pricing within a holding company. It further argues that tracking which transactions are “at market” and which transactions are “at cost” adds a level of complexity to the accounting within holding companies, and identifying the market prices for certain non-power goods and services that may be sold by franchised public utilities to centralized service companies is difficult. 66. In contrast, the New York Commission focuses on whether the Commission's proposed pricing standards adequately protect captive customers from cross-subsidization. Specifically, it challenges the Commission's proposal to prohibit a franchised public utility with captive customers from purchasing non-power goods and services at a price above market price from market-regulated power sales affiliates and non-utility affiliates, with the exception of centralized service companies. It asserts that this standard would allow utilities to purchase non-power goods or services from an affiliated entity at market prices and may allow holding companies to structure affiliate transactions so that utilities with captive customers would pay above-cost charges. It states that where an affiliate makes central purchases on behalf of several utilities, the affiliate will likely obtain discounts in the prices it pays due to the combined volume of purchases. The New York Commission contends, however, that the Commission's proposal would allow the central purchasing affiliate to charge each utility up to the prevailing market price which otherwise would be incurred if the utilities made their own separate purchases, and the result would provide a source of affiliate cross-subsidization in an amount equivalent to the incremental purchase quantity discount. 67. As an alternative, the New York Commission proposes that the Commission require utilities to record purchases of covered items from their affiliates at the lower of actual cost or market prices. It contends that this standard would protect captive utility customers against paying affiliates more than the affiliate's actual costs. 68. Commenters also made recommendations on the appropriate relationship between state and Commission affiliate-pricing standards. In particular, EEI, National Grid and Pinnacle West argue that, at the very least, the Commission should avoid unnecessary duplication or conflict with state provisions. In particular, EEI encourages the Commission to adopt deference to states in the cross-subsidy context, unless a state or holding company asks the Commission to apply uniform rules to avoid inconsistent standards that would trap legitimate costs. EEI suggests that the Commission adopt a procedure similar to the one it adopted in Order No. 667, in which a holding company system can apply to the Commission to impose consistent requirements that would eliminate the possibility of trapped costs. National Grid contends that inconsistencies between federal and state rules make implementation of both sets of rules impossible, particularly with respect to the day-to-day press of business within a utility holding company. It argues that deference to the states would minimize disruption of existing holding company accounting and reporting systems, cost-allocation manuals, and interaffiliate-transaction procedures built around state regulation. Pinnacle West states that, because state regulations typically address affiliate transactions, the Commission's regulations could upset states' efforts to ring fence utilities. b. *Commission Determination* 69. The Commission will adopt the pricing restrictions on transactions for non-power goods and services proposed in the Affiliate Transactions NOPR, with the exception of a modification to the restriction applicable to transactions with centralized service companies, to conform those restrictions to the language in our Order No. 667 regulations. These are explained below. 70. First, as proposed, a franchised public utility with captive customers that provides non-power goods and services to a market-regulated power sales affiliate or a non-utility affiliate will be required to sell at a price that is the higher of cost or market price. We will not adopt an at-cost pricing structure for these types of non-power transactions (as suggested by National Grid, EEI, NiSource, Entergy and PG&E) because it would require a franchised public utility to sell to an affiliate at cost even when market prices are higher, thereby foregoing profits that the utility otherwise could have obtained by selling to a non-affiliate at a market price. In such a scenario, the benefit would go to the market-regulated affiliate or non-utility affiliate who receives a good or service at a below-market price. We believe the benefits that captive customers will receive under this “higher of cost or market price” standard outweigh any savings that may (or may not) occur through the use of a uniform at-cost standard. 71. Next, we will adopt the proposal in the Affiliate Transactions NOPR to prohibit a franchised public utility with captive customers from purchasing non-power goods or services from a market-regulated power sales affiliate or a non-utility affiliate at a price above market price (with the exception of transactions from centralized service companies, which are discussed below). In doing so, we deny the New York Commission's request for a “lower of cost or market” standard for these types of transactions. As discussed above, the New York Commission argued that the “at a price above market price” standard would allow holding companies to structure affiliate transactions so that captive customers would pay above-cost charges. But captive customers are not harmed by the franchised public utility paying above-cost charges if those charges are no higher than what they would pay non-affiliates for the same non-power goods and services. Moreover, nothing in the standard requiring that these purchases not be above market prevents the franchised public utility from paying less than the market price. The New York Commission, or any other state commission, can require a stricter standard for these transactions so long as the standards do not result in trapped costs in situations involving multi-state holding companies. If the state commission's pricing standards for a franchised public utility's purchases from an affiliate are stricter than the Commission's (e.g., the state standard is lower of cost or market as opposed to market), then the stricter pricing standard would apply, as long as there is no conflict in complying with both the state's pricing standard and this Commission's pricing standard. 60 60 *See* 18 CFR 366.5. 72. Finally, with regard to centralized service companies, the Affiliate Transactions NOPR proposed that a franchised public utility with captive customers should be prohibited from purchasing or receiving non-power goods and services from a centralized service company at a price above cost. We will conform this standard to the language in Order No. 667, which is to require that such transactions occur “at cost.” While this is a change from the Affiliate Transactions NOPR, which proposed to prohibit such sales from centralized service companies at a price above cost, our intent in the Affiliate Transactions NOPR was to be consistent with Order No. 667, 61 as well as the SEC's at-cost standard used prior to the repeal of PUHCA 1935. As we have previously stated, the at-cost pricing standard for transactions for non-power goods and services from centralized service companies to franchised public utilities with captive customers benefits ratepayers through economies of scale, and eliminates the speculative task of defining a market price in these instances. 62 61 Order No. 667, FERC Stats. & Regs. ¶ 31,197 at P 169. 62 *Id.* 73. We recognize that one of the risks of at-cost pricing is the potential for prices to be imposed that are substantially higher than the market price. As we stated in Order No. 667, the Commission will entertain complaints that at-cost pricing exceeds the market price. Complainants would continue to have the burden of demonstrating the at-cost price exceeded market price and, furthermore, any change in the price as a result of the complaint would be prospective. 74. With regard to comments that the Commission's affiliate-pricing standards may conflict with similar pricing rules at the state level, we are not convinced that the Commission should establish a general policy of deference to existing state rules. For many years, we have required restrictions on certain affiliate transactions for non-power goods and services in the context of both market-base rate authorizations and merger approval under section 203. 63 As stated above, to the extent a state has affiliate-pricing standards that are “stricter” than the Commission's then the stricter standard applies, as long as there is no conflict in complying with both the state's pricing standard and this Commission's pricing standard. 63 *See, e.g., Potomac,* 93 FERC at 61,782; *Heartland,* 68 FERC at 62,062-63; *PSC Colorado,* 75 FERC at 62,046. 3. Reporting Requirements 75. In the Affiliate Transactions NOPR, the Commission asked whether it should adopt any after-the-fact reporting requirements for transactions covered by the proposed regulations. a. *Comments* 76. Most commenters, including EEI, Entergy, PG&E, Pinnacle West and Sempra, argue that the Commission should not require after-the-fact reporting requirements. 77. EEI argues that such reporting would be onerous given the number of transactions at issue, the fact that further reporting could include sensitive information and the Commission already collects large volumes of information from utilities and service companies. EEI also argues that if the Commission does adopt these regulations, it should clarify that utilities no longer need to include language that duplicates the regulations in their code of conduct as part of their individual tariffs. 78. Pinnacle West and Sempra argue that additional reporting is not required because many states already require reporting of affiliate transactions (including the states in which they conduct business) and the Commission already collects affiliate power sales information through EQRs and market-based rate requirements. Sempra states that it does not object to additional reporting requirements provided that the entities subject to the requirements are authorized to submit the same information in the same format and in the same time period as is required under existing state requirements. 79. PG&E encourages the Commission not to require additional reporting requirements for single-state holding companies. PG&E argues that such a requirement would be extraordinarily onerous. PG&E also argues that such a requirement would be duplicative because of Commission reporting requirements (EQRs and Form No. 3-Qs) and state requirements (where there is adequate state regulation of cross-subsidy issues). 80. APPA/NRECA and the state commissions support after-the-fact reporting requirements. APPA/NRECA ask that the Commission adopt additional after-the-fact reporting requirements. APPA/NRECA state that the Commission should require the filing of affiliate agreements governing non-power goods and services and the filing of periodic reports of all affiliate transactions within holding company systems regardless of whether they involve a centralized service company, a single-purpose service company, a market-regulated power sales affiliate or a non-utility affiliate. APPA/NRECA assert that there is no question of the Commission's statutory authority to require such reporting (citing the Commission's analysis in Order No. 667). APPA/NRECA also note that, in Order No. 667, the Commission only requires traditional, centralized service companies in holding company systems to file annual reports containing certain information relating to affiliate transactions, but the Commission does not require any reporting for single-purpose service companies or other associate companies in holding company systems. While APPA/NRECA acknowledge that a one-size-fits-all reporting scheme may not be appropriate, they believe additional reporting is required. As a suggestion, they offer that the Commission require each covered public utility to file a one-time compliance filing which would inform the Commission of its then-existing affiliate relationships and any exemptions from annual reporting requirements. APPA/NRECA admit that that sort of reporting regime is general, and ask that the Commission consider a further technical conference on this question. 81. The Oklahoma Commission also recommends after-the-fact reporting, noting that its rules regarding affiliate information have been effective. The Oklahoma Commission suggests that the Commission allow state commissions the opportunity to review and comment on any post occurrence reporting (suggesting a 90-day review and comment period). 82. The New York Commission also recommends reporting on affiliate transactions. The New York Commission recommends revisions to Form No. 1 and Form No. 2 to require utilities to describe, quantify, and provide the basis used to record each type of transaction with its affiliates. It argues that these reporting requirements are similar to those the Commission included in Form No. 60 for centralized service companies. b. *Commission Determination* 83. We believe that the current reporting regulations are adequate to ensure compliance with the proposed restrictions on affiliate transactions between franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities and their market-regulated power sales affiliates or non-utility affiliates. In addition to the information gathered through Form No. 1, the Commission already collects affiliate power sales information from franchised public utilities through EQRs and market-based requirements. With regard to non-power goods and services, franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities are covered by the existing record retention requirements in Parts 125 and 225 of the Commission's regulations. Accordingly, there is no need to impose additional reporting requirements to ensure compliance with the proposed regulations. However, if the Commission finds that the existing requirements are inadequate, we will consider holding a technical conference to discuss what additional reporting requirements may be warranted. 4. Effective Date a. *Comments* 84. EEI and Entergy recommend that the application of any adopted regulations be prospective in nature and not affect any existing contracts. In its comments, EEI asserts that it would be “unjust and detrimental to the financial integrity” of holding companies for the Commission to retroactively void pricing arrangements to provide energy or non-power goods and services. 64 64 EEI Comments at 13. b. *Commission Determination* 85. In response to EEI's request for clarification, we clarify that the pricing rules adopted herein are prospective and will apply to any contracts, agreements or arrangements entered into on or after the effective date of this Final Rule. To the extent different pricing was in effect for any contract, agreement or arrangement entered into prior to the effective date of this Final Rule, such pricing may remain in effect; however, the Commission on its own motion, or upon complaint, may on a case-by-case basis institute a section 206 proceeding to determine whether the costs incurred by a public utility under such pre-existing contracts, agreements or arrangements are just, reasonable and not unduly discriminatory or preferential. We also note that many public utilities already have the same pricing restrictions in effect as a result of Commission orders approving mergers or market-based rates; these restrictions remain in place. V. Information Collection Statement 86. The Office of Management and Budget's (OMB's) regulations require that OMB approve certain information collection requirements imposed by agency rule. 65 This Final Rule does not impose any additional information collection requirements. Therefore, the information collection regulations do not apply to this Final Rule. The Commission received 12 comments on the Affiliate Transactions NOPR and no entity specifically addressed the Commission's information collection statement. The Commission will submit for informational purposes only a copy of this rulemaking to OMB. 65 5 CFR 1320.12. VI. Environmental Analysis 87. 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. 66 The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. 67 The final rule is categorically excluded as it addresses rate filings submitted under sections 205 and 206 of the FPA. 68 Accordingly, no environmental assessment is necessary and none has been prepared in this final rule. 66 *Regulations Implementing the National Environmental Policy Act,* Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles 1986-1990 ¶ 30,783 (1987). 67 18 CFR 380.4. 68 *See* 18 CFR 380.4(a)(15). VII. Regulatory Flexibility Act 88. The Regulatory Flexibility Act of 1980
(RFA)69 generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. 70 Agencies are not required to make such an analysis if a rule would not have such an effect. 69 5 U.S.C. 601-12. 70 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 year did not exceed 4 million MWh. 13 CFR 121.201. 89. The Final Rule is applicable to franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities. Most such companies regulated by the Commission do not fall within the RFA's definition of small entity. 71 Therefore, the Commission certifies the Final Rule will not have a significant economic impact on a substantial number of small entities. As a result, no regulatory flexibility analysis is required. 71 5 U.S.C. 601(3), citing to section 3 of the Small Business Act, 15 U.S.C. 632. Section 3 of the Small Business Act defines a “small-business concern” as a business which is independently owned and operated and which is not dominant in its field of operation. VIII. Document Availability 90. 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. 91. From FERC's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field. 92. User assistance is available for eLibrary and the FERC's Web site during normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) or e-mail at *ferconlinesupport@ferc.gov,* or the Public Reference Room at
(202)502-8371, TTY
(202)502-8659. E-mail the Public Reference Room at *public.referenceroom@ferc.gov.* IX. Effective Date and Congressional Notification 93. These regulations are effective March 31, 2008. 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” as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996. List of Subjects in 18 CFR Part 35 Electric power rates, Electric utilities, Reporting and recordkeeping requirements. By the Commission. Kimberly D. Bose, Secretary. In consideration of the foregoing, the Commission amends part 35, Chapter I, Title 18, *Code of Federal Regulations* , to read as follows: PART 35—FILING OF RATE SCHEDULES AND TARIFFS 1. The authority citation for part 35 continues to read as follows: Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352. 2. Subpart I is added to read as follows: Subpart I—Cross-Subsidization Restrictions on Affiliate Transactions Sec. 35.43 Generally. 35.44 Protections against affiliate cross-subsidization. § 35.43 Generally.
(a)For purposes of this subpart:
(1)*Affiliate* of a specified company means:
(i)For any person other than an exempt wholesale generator:
(A)Any person that directly or indirectly owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of the specified company;
(B)Any company 10 percent or more of whose outstanding voting securities are owned, controlled, or held with power to vote, directly or indirectly, by the specified company;
(C)Any person or class of persons that the Commission determines, after appropriate notice and opportunity for hearing, to stand in such relation to the specified company that there is liable to be an absence of arm's-length bargaining in transactions between them as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that the person be treated as an affiliate; and
(D)Any person that is under common control with the specified company.
(E)For purposes of paragraph (a)(1)(i) of this section, owning, controlling or holding with power to vote, less than 10 percent of the outstanding voting securities of a specified company creates a rebuttable presumption of lack of control.
(ii)For any exempt wholesale generator (as defined under § 366.1 of this chapter), consistent with section 214 of the Federal Power Act (16 U.S.C. 824m), which provides that “affiliate” will have the same meaning as provided in section 2(a) of the Public Utility Holding Company Act of 1935 (15 U.S.C. 79b(a)(11)):
(A)Any person that directly or indirectly owns, controls, or holds with power to vote, 5 percent or more of the outstanding voting securities of the specified company;
(B)Any company 5 percent or more of whose outstanding voting securities are owned, controlled, or held with power to vote, directly or indirectly, by the specified company;
(C)Any individual who is an officer or director of the specified company, or of any company which is an affiliate thereof under paragraph (a)(1)(ii)(A) of this section; and
(D)Any person or class of persons that the Commission determines, after appropriate notice and opportunity for hearing, to stand in such relation to the specified company that there is liable to be an absence of arm's-length bargaining in transactions between them as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that the person be treated as an affiliate.
(2)*Captive customers* means any wholesale or retail electric energy customers served by a franchised public utility under cost-based regulation.
(3)*Franchised public utility* means a public utility with a franchised service obligation under state law.
(4)*Market-regulated power sales affiliate* means any power seller affiliate other than a franchised public utility, including a power marketer, exempt wholesale generator, qualifying facility or other power seller affiliate, whose power sales are regulated in whole or in part on a market-rate basis.
(5)*Non-utility affiliate* means any affiliate that is not in the power sales or transmission business, other than a local gas distribution company or an interstate natural gas pipeline.
(b)The provisions of this subpart apply to all franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities. § 35.44 Protections against affiliate cross-subsidization.
(a)*Restriction on affiliate sales of electric energy* . No wholesale sale of electric energy may be made between a franchised public utility with captive customers and a market-regulated power sales affiliate without first receiving Commission authorization for the transaction under section 205 of the Federal Power Act.
(b)*Non-power goods or services* .
(1)Unless otherwise permitted by Commission rule or order, sales of any non-power goods or services by a franchised public utility that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, including sales made to or through its affiliated exempt wholesale generators or qualifying facilities, to a market-regulated power sales affiliate or non-utility affiliate must be at the higher of cost or market price.
(2)Unless otherwise permitted by Commission rule or order, and except as permitted by paragraph (b)(3) of this section, a franchised public utility that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, may not purchase or receive non-power goods and services from a market-regulated power sales affiliate or a non-utility affiliate at a price above market.
(3)A franchised public utility that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, may only purchase or receive non-power goods and services from a centralized service company at cost. [FR Doc. E8-3820 Filed 2-28-08; 8:45 am] BILLING CODE 6717-01-P DEPARTMENT OF HEALTH AND HUMAN SERVICES Food and Drug Administration 21 CFR Parts 520 and 556 New Animal Drugs; Albendazole AGENCY: Food and Drug Administration, HHS. ACTION: Final rule. SUMMARY: The Food and Drug Administration
(FDA)is amending the animal drug regulations to reflect approval of a supplemental new animal drug application
(NADA)filed by Pfizer, Inc. The supplemental NADA provides for use of albendazole oral suspension in nonlactating goats for the treatment of liver flukes. DATES: This rule is effective February 29, 2008. FOR FURTHER INFORMATION CONTACT: Joan C. Gotthardt, Center for Veterinary Medicine (HFV-130), Food and Drug Administration, 7500 Standish Pl., Rockville, MD 20855, 240-276-8342, e-mail: *joan.gotthardt@fda.hhs.gov* . SUPPLEMENTARY INFORMATION: Pfizer, Inc., 235 East 42d St., New York, NY 10017, filed a supplement to NADA 110-048 that provides for the use of VALBAZEN (albendazole) Oral Suspension for the treatment of liver flukes in nonlactating goats. The approval of this supplemental NADA relied on publicly available safety and effectiveness data contained in Public Master File
(PMF)5582, which were compiled under National Research Support Project-7 (NRSP-7), a national agricultural research program for obtaining clearances for use of new drugs in minor animal species and for special uses. The supplemental NADA is approved as of January 24, 2008, and the regulations are amended in 21 CFR 520.45a and 556.34 to reflect the approval. In accordance with the freedom of information provisions of 21 CFR part 20 and 21 CFR 514.11(e)(2)(ii), a summary of the safety and effectiveness data and information submitted to support approval of this application may be seen in the Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, rm. 1061, Rockville, MD 20852, between 9 a.m. and 4 p.m., Monday through Friday. Under section 573(c) of the Federal Food, Drug, and Cosmetic Act (the Act) (21 U.S.C.360ccc-2(c)), this approval qualifies for 7 years of exclusive marketing rights beginning on the date of approval, because the new animal drug has been declared a designated drug by FDA under section 573(a) of the Act. The agency has determined under 21 CFR 25.33(d)(4) that this action is of a type that does not individually or cumulatively have a significant effect on the human environment. Therefore, neither an environmental assessment nor an environmental impact statement is required. This rule does not meet the definition of “rule” in 5 U.S.C. 804(3)(A) because it is a rule of “particular applicability.” Therefore, it is not subject to the congressional review requirements in 5 U.S.C. 801-808. List of Subjects 21 CFR Part 520 Animal drugs. 21 CFR Part 556 Animal drugs, Foods. Therefore, under the Federal Food, Drug, and Cosmetic Act and under authority delegated to the Commissioner of Food and Drugs and redelegated to the Center for Veterinary Medicine, 21 CFR parts 520 and 556 are amended as follows: PART 520—ORAL DOSAGE FORM NEW ANIMAL DRUGS 1. The authority citation for 21 CFR part 520 continues to read as follows: Authority: 21 U.S.C. 360b. 2. Revise § 520.45a to read as follows: § 520.45a Albendazole suspension.
(a)*Specifications* . Each milliliter of suspension contains 45.5 milligrams
(mg)(4.55 percent) or 113.6 mg (11.36 percent) albendazole.
(b)*Sponsor* . See No. 000069 in § 510.600 of this chapter.
(c)*Related tolerances* . See § 556.34 of this chapter.
(d)*Special considerations* . See § 500.25 of this chapter.
(e)*Conditions of use* —(1) *Cattle* . Administer 11.36 percent suspension:
(i)*Amount* . 4.54 mg/pound
(lb)body weight (10 mg/kilogram (kg)) as a single oral dose using dosing gun or dosing syringe.
(ii)*Indications for use* . For removal and control of adult liver flukes ( *Fasciola hepatica* ); heads and segments of tapeworms ( *Moniezia benedeni* and *M. expansa* ); adult and 4th stage larvae of stomach worms (brown stomach worms including 4th stage inhibited larvae ( *Ostertagia ostertagi* ), barberpole worm ( *Haemonchus contortus* and *H. placei* ), small stomach worm ( *Trichostrongylus axei* )); adult and 4th stage larvae of intestinal worms (thread-necked intestinal worm ( *Nematodirus spathiger* and *N. helvetianus* ), small intestinal worm ( *Cooperia punctata* and *C. oncophora* )); adult stages of intestinal worms (hookworm ( *Bunostomum phlebotomum* ), bankrupt worm ( *Trichostrongylus colubriformis* ), nodular worm ( *Oesophagostomum radiatum* )); adult and 4th stage larvae of lungworms ( *Dictyocaulus viviparus* ).
(iii)*Limitations* . Do not slaughter within 27 days of last treatment. Do not use in female dairy cattle of breeding age: Do not administer to female cattle during first 45 days of pregnancy or for 45 days after removal of bulls.
(2)*Sheep* . Administer 4.45 or 11.36 percent suspension:
(i)*Amount* . 3.4 mg/lb body weight (7.5 mg/kg) as a single oral dose using dosing gun or dosing syringe.
(ii)*Indications for use* . For removal and control of adult liver flukes ( *Fasciola hepatica* and *Fascioloides magna* ); heads and segments of common tapeworms ( *Moniezia expansa* ) and fringed tapeworm ( *Thysanosoma actinioides* ); adult and fourth stage larvae of stomach worms (brown stomach worm ( *Ostertagia circumcinta* and *Marshallagia marshalli* ), barberpole worm ( *Haemonchus contortus* ), small stomach worm ( *Trichostrongylus axei* )); adult and fourth stage larvae of intestinal worms (thread-necked intestinal worm ( *Nematodirus spathiger* and *N. filicollis* ), Cooper's worm ( *Cooperia oncophora* ), bankrupt worm ( *Trichostrongylus colubriformis* ), nodular worm ( *Oesophagostomum columbianum* ), and large-mouth bowel worm ( *Chabertia ovina* )); adult and larval stages of lungworms ( *Dictyocaulus filaria* ).
(iii)*Limitations* . Do not slaughter within 7 days of last treatment. Do not administer to ewes during first 30 days of pregnancy or for 30 days after removal of rams.
(3)*Goats* . Administer 11.36 percent suspension:
(i)*Amount* . 4.54 mg/lb body weight (10 mg/kg) as a single oral dose using dosing gun or dosing syringe.
(ii)*Indications for use* . For the treatment of adult liver flukes ( *Fasciola hepatica* ) in nonlactating goats.
(iii)*Limitations* . Do not slaughter within 7 days of last treatment. Do not administer to does during the first 30 days of pregnancy or for 30 days after removal of bucks. PART 556—TOLERANCES FOR RESIDUES OF NEW ANIMAL DRUGS IN FOOD 3. The authority citation for 21 CFR part 556 continues to read as follows: Authority: 21 U.S.C. 342, 360b, 371. 4. In § 556.34, revise paragraph
(b)and add paragraph
(c)to read as follows: § 556.34 Albendazole.
(b)*Tolerances* . The tolerances for albendazole 2-aminosulfone (marker residue) are:
(1)*Cattle* —(i) *Liver (target tissue)* : 0.2 parts per million (ppm).
(ii)*Muscle* : 0.05 ppm.
(2)*Sheep* —(i) *Liver (target tissue)* : 0.25 ppm.
(ii)*Muscle* : 0.05 ppm.
(3)*Goat* —(i) *Liver (target tissue* ): 0.25 ppm.
(ii)[Reserved]
(c)*Related conditions of use* . See § 520.45 of this chapter. Dated: February 19, 2008. Bernadette Dunham, Director, Center for Veterinary Medicine. [FR Doc. E8-3877 Filed 2-28-08; 8:45 am] BILLING CODE 4160-01-S DEPARTMENT OF STATE 22 CFR Part 42 [Public Notice: 6114] Visas: Documentation of immigrants Under the Immigration and Nationality Act, as Amended AGENCY: Department of State. ACTION: Final Rule. SUMMARY: This rule revises the procedure for notifying the beneficiary of an immigrant visa petition of the termination of the immigrant visa registration because of the failure of the beneficiary to pursue the application within a specified time, by providing that such notification will be made by National Visa Center directly to the beneficiary. DATES: This rule is effective February 29, 2008. FOR FURTHER INFORMATION CONTACT: Charles Robertson, Legislation and Regulations Division, Visa Services, Department of State, 2401 E Street, NW., Room L-603D, Washington, DC 20520-0106,
(202)663-1202, e-mail ( *robertsonce@state.gov* ). SUPPLEMENTARY INFORMATION: Why is the Department promulgating this rule? In the past, the consular officer at the post where an alien was registered as a beneficiary of an immigrant visa petition was responsible for notifying the alien of the termination of the immigrant visa registration if the alien failed to pursue the application within one year after being notified that a visa was available. The consular officer based this notification on information received from the National Visa Center (NVC). Now, the NVC will make this notification directly to the alien. How does this change affect the alien? There is no change from the point of view of the alien. The alien still has the ability to apply for reinstatement of the immigrant visa registration. Such application should be sent to the National Visa Center and it will be forwarded to the consular officer at the post where the alien was registered, under the same conditions as before. Regulatory Findings Administrative Procedure Act This regulation involves a foreign affairs function of the United States and, therefore, in accordance with 5 U.S.C. 553(a)(1), is not subject to the rule making procedures set forth at 5 U.S.C. 553. Regulatory Flexibility Act/Executive Order 13272: Small Business Because this final rule is exempt from notice and comment rulemaking under 5 U.S.C. 553, it is exempt from the regulatory flexibility analysis requirements set forth at sections 603 and 604 of the Regulatory Flexibility Act (5 U.S.C. 603 and 604). Nonetheless, consistent with section 605(b) of the Regulatory Flexibility Act (5 U.S.C. 605(b)), the Department certifies that this rule will not have a significant economic impact on a substantial number of small entities. This regulates individual aliens who seek consideration for immigrant visas and does not affect any small entities, as defined in 5 U.S.C. 601(6). The Unfunded Mandates Reform Act of 1995 Section 202 of the Unfunded Mandates Reform Act of 1995 (UFMA), Public Law 104-4, 109 Stat. 48, 2 U.S.C. 1532, generally requires agencies to prepare a statement before proposing any rule that may result in an annual expenditure of $100 million or more by State, local, or tribal governments, or by the private sector. This rule will not result in any such expenditure, nor will it significantly or uniquely affect small governments. The Small Business Regulatory Enforcement Fairness Act of 1996 This rule is not a major rule as defined by 5 U.S.C. 804, for purposes of congressional review of agency rulemaking under the Small Business Regulatory Enforcement Fairness Act of 1996, Public Law 104-121. This rule will not result in an annual effect on the economy of $100 million or more; a major increase in costs or prices; or adverse effects on competition, employment, investment, productivity, innovation, or the ability of United States-based companies to compete with foreign based companies in domestic and import markets. Executive Order 12866 The Department of State has reviewed this final rule to ensure its consistency with the regulatory philosophy and principles set forth in Executive Order 12866 and has determined that the benefits of the final regulation justify its costs. The Department does not consider the final rule to be an economically significant action within the scope of section 3(f)(1) of the Executive Order since it is not likely to have an annual effect on the economy of $100 million or more or to adversely affect in a material way the economy, a sector of the economy, competition, jobs, the environment, public health or safety, or state, local or tribal governments or communities. Executive Orders 12372 and 13132: Federalism This regulation will not have substantial direct effects on the States, on the relationship between the national government and the States, or the distribution of power and responsibilities among the various levels of government. Nor will the rule have federalism implications warranting the application of Executive Orders No. 12372 and No. 13132. Paperwork Reduction Act This rule does not impose information collection requirements under the provisions of the Paperwork Reduction Act, 44 U.S.C., Chapter 35. List of Subjects in 22 CFR Part 42 Aliens, Foreign officials, Immigration, Passports and Visas. Accordingly, for the reasons stated in the preamble, Title 22 Part 42 is amended as follows: PART 42—[AMENDED] 1. The authority citation for part 42 continues to read as follows: Authority: 8 U.S.C. 1104; Pub. L. 105-277, 112 Stat. 2681-795 through 2681-801. Additional authority is derived from Section 104 of the Illegal Immigration Reform and Immigrant Responsibility Act of 1996 (IIRIRA) Pub. L. 104-208, 110 Stat. 3546. 2. Revise § 42.83(c) to read as follows: § 42.83 Termination of registration.
(c)*Notice of termination* . Upon the termination of registration under paragraph
(a)of this section, the National Visa Center
(NVC)shall notify the alien of the termination. The NVC shall also inform the alien of the right to have the registration reinstated if the alien, before the end of the second year after the missed appointment date if paragraph
(a)applies, establishes to the satisfaction of the consular officer at the post where the alien is registered that the failure to apply for an immigrant visa was due to circumstances beyond the alien's control. If paragraph
(b)applies, the consular officer at the post where the alien is registered shall, upon the termination of registration, notify the alien of the termination and the right to have the registration reinstated if the alien, before the end of the second year after the INA 221(g) refusal, establishes to the satisfaction of the consular officer at such post that the failure to present evidence purporting to overcome the ineligibility under INA 221(g) was due to circumstances beyond the alien's control. Dated: February 20, 2008. Maura Harty, Assistant Secretary for Consular Affairs, Department of State. [FR Doc. E8-3941 Filed 2-28-08; 8:45 am] BILLING CODE 4710-06-P DEPARTMENT OF THE INTERIOR Bureau of Indian Affairs 25 CFR Part 171 RIN 1076-AD44 Irrigation Operation and Maintenance AGENCY: Bureau of Indian Affairs, Interior. ACTION: Final rule. SUMMARY: The Department of the Interior, Bureau of Indian Affairs
(BIA)is revising the regulation governing irrigation projects under its jurisdiction. The purpose of the revision is to provide consistent administration; establish the process for updating practices, policies, and procedures for the administration, operation, maintenance, and rehabilitation of irrigation projects; and provide uniform accounting and recordkeeping procedures. This regulation has also been rewritten in plain English as mandated by Executive Order 12866. It also addresses several issues that the prior regulation did not cover. DATES: Effective March 31, 2008. FOR FURTHER INFORMATION CONTACT: John Anevski, Chief, Division of Irrigation, Power and Safety of Dams, Office of Trust Services, Bureau of Indian Affairs, 1849 C Street, NW., Mail Stop 4655-MIB, Washington, DC 20240; Telephone
(202)208-5480. SUPPLEMENTARY INFORMATION: I. Background II. Response to Comments III. Subpart-by-Subpart Analysis IV. Procedural Requirements I. Background This regulation is issued under the Secretary of the Department of the Interior's (Secretary) authority to administer Indian irrigation projects under 25 United States Code (U.S.C.) 381 *et seq.* This revised regulation clarifies prior regulatory language, in keeping with the “plain English” standard required by Executive Order 12866. In revising this regulation, redundant or unnecessary sections of the existing part 171 of Title 25 of the Code of Federal Regulations
(CFR)were identified and deleted. New sections were also added to comply with the Inspector General's
(IG)audit findings and to implement the provisions of the Debt Collection Improvement Act of 1996. For example, several IG audits, the most recent in 1996 (96-I-641), identified a management deficiency concerning full cost rates for operation and maintenance. Also, the Debt Collection Improvement Act established new procedures to manage moneys owed the Federal Government. This regulation addresses both of these issues. The proposed revisions to 25 CFR part 171 were first published on July 5, 1996 (61 FR 35167). Based on the length of time that has passed and changes to the earlier proposed regulation, these proposed revisions were published for public comment on July 17, 2006 (71 FR 40450) with a 120-day public comment period that ended on November 14, 2006. The re-publication provided a fresh start to the rulemaking process for this revision. Consultation meetings with the Indian tribes (Tribes) that may be impacted by this regulation were held on August 24 and 26, 2004, and May 10 and 12, 2005. These consultation meetings were held in accordance with Executive Order 13175. No additional consultation meetings with Tribes were requested or held during the public comment period. II. Response to Comments The Department solicited comments from all interested parties through its publication of the proposed regulation in the **Federal Register** on July 17, 2006 (71 FR 40450). In addition, prior to publication of the proposed regulation, the BIA held four tribal consultation meetings with affected Tribes on August 24 and 26, 2004, and May 10 and 12, 2005. These meetings were well-attended and the BIA received valuable input to help develop the proposed regulation as a result. Transcripts from those consultations were used in the development of the proposed regulation. The Department received written comments from one individual and three tribes. The comments included both general and specific criticisms and suggestions. The comments were carefully reviewed by the regulation drafting team made up of BIA employees from Central Office and attorneys from the Office of the Solicitor. Depending on their merit, the Department accepted, accepted with revision, or rejected comments made on each part of the regulation. Some of the comments included copies of previously submitted comments which were related to earlier versions of the proposed regulation. Because the 2006 proposed regulation was significantly different from earlier versions, those earlier comments are not specifically addressed here; however, those earlier comments were carefully considered in developing the latest version of the regulation. As noted in the part-by-part analysis below, certain sections of the regulation have been clarified in direct response to comments. Additionally, some language has been deleted or added to provide for increased clarity and precision. Substantive comments are summarized below. III. Subpart-by-Subpart Analysis 25 CFR Part 171—Irrigation Operation and Maintenance (O&M) The purpose of this regulation is to provide consistent administration of irrigation projects under the jurisdiction of the BIA; establish uniform accounting and recordkeeping procedures for the assessment of irrigation O&M charges; and establish the process for updating practices, policies, and procedures for the administration, operation, maintenance, and rehabilitation of Indian irrigation projects. The various subparts of part 171 address the applicability of the regulation to individual irrigators; definition of relevant terms; the nature and scope of the irrigation service provided by the BIA; allowable uses of irrigation water; the responsibilities of irrigators and the BIA; assessments, billing, and collections; record-keeping and agreements between BIA and irrigators; and non-assessment status of lands within an irrigation project. General Comments Comment: Adequacy of Consultation Several commenters expressed concern that there was not adequate formal consultation on the proposed regulation. Formal consultations were held on August 24, 2004 and May 12, 2005 in Phoenix, AZ and on August 26, 2004 and May 10, 2005 in Billings, MT. All affected Tribes were invited to attend each of the four formal consultation meetings, and all of the meetings were well-attended. The BIA indicated its willingness to host consultations for individual affected Tribes or additional consultations with groups of Tribes upon request. None of the affected Tribes requested additional consultation meetings. Two of the commenters stated that the Walker River Paiute Tribe was not notified of the consultation meetings and thus could not participate. However, BIA records indicate that the Walker River Paiute Tribe was notified of all four formal consultations meetings, and in fact, three representatives from the Walker River Paiute Tribe attended the May 12, 2005 consultation meeting held in Phoenix, AZ. One commenter noted that a water user meeting held on her reservation two months after publication of the proposed rule did not constitute adequate formal consultation. The meeting this commenter referred to was held on the Walker River Paiute Reservation on September 28, 2006. The purpose of water user meetings is for the local BIA irrigation project to consult with the project stakeholders on project-specific operations, maintenance, budget, rates, and related matters. This meeting was not held for the purpose of consulting with Tribes on the proposed revision to Part 171. One commenter noted that the consultations did not address project-specific operating guidelines and were therefore inadequate. Consultations were held for this proposed regulation. The establishment of operating guidelines specific to the individual irrigation projects is distinct from this rule-making process. The BIA will be consulting with Tribes and water users in the development of individual project operating guidelines. No change was made to the regulation to address these comments. Comment: Timing of Issuance of Final Regulation One commenter stated that the regulation should not be finalized until after the BIA proposes and discusses new project-specific operating guidelines. The commenter stated that studies should be undertaken to determine how the regulation will affect the BIA's ability to protect and manage Indian land and water. The establishment of project-specific operating guidelines is distinct from this rule-making process. This regulation will guide the development of the project-specific guidelines, not the other way around. The regulation will not affect the BIA's ability to protect and manage Indian land and water. These regulations are intended to enhance our ability to protect, manage, and operate irrigation projects by providing new mechanisms for projects to begin addressing long-standing irrigation issues. Additionally, the project-specific operating guidelines are intended to provide additional and more specific guidance for individual projects within the overarching regulations. Thus, it is necessary to finalize this proposed regulation first before developing the more detailed, project-specific operating guidelines. In response to the comment suggesting that BIA study the impact of these regulations prior to finalizing the rule, BIA's irrigation program and the existing proposed regulation have already been the subject of numerous studies, including General Accounting Office
(GAO)reports and IG audits. The overall impact of the revisions to the regulation are relatively minor. Redundant or unnecessary sections were deleted. New sections were added to comply with the Debt Collection Improvement Act, better define what items should be included in project budgets for better rate setting, improve lands within the irrigation projects by using incentive agreements, and grant Annual Assessment Waivers when BIA cannot deliver water to farm units. No change was made to the regulation to address these comments. One commenter noted that the Yakama Nation has a pending lawsuit in federal district court against the United States that questions the scope of BIA's authority to assess irrigation O&M charges. The commenter urged the BIA to delay issuance of the regulation until that litigation is decided. The litigation referenced—Confederated Tribes and Bands of the Yakama Nation v. United States, No. CV-06-3032-LRS (E.D. Wash.)—was dismissed on procedural grounds in December 2006. The Yakama Nation's request for reconsideration was denied in February 2007. The Yakama Nation has served notice of appeal to the Ninth Circuit Court of Appeals purely on the procedural issues, and briefs were filed during the summer of 2007. If the courts were ever to address the substantive issues raised in the litigation it could be years until a judicial resolution would be obtained. Thus, the BIA does not believe it would be prudent to delay issuance of the regulation on that basis. Comments: Plain English Some commenters stated that the change to “plain English” oversimplified technical concepts and made the regulation vague and less precise, and therefore more difficult to understand, than the existing Part 171. While some commenters stated the regulation is too simple, other commenters asserted that the regulation was too complex and used too much “bureaucratic jargon.” The proposed rule was written in “plain English” to comply with Executive Order 12866. Every attempt was made to make the regulation clear and easy to read, while not oversimplifying technical issues. The commenters did not provide any alternate language or suggestions for making this rule easier to understand. No change was made to the regulation to address these comments. Comments: Small Business Regulatory Enforcement Fairness Act (SBREFA) Several commenters expressed concern about the statement in the proposed regulation regarding the Small Business Regulatory Enforcement Fairness Act (SBREFA) and the potential for rate increases. The BIA stated that this regulation will not have an annual effect on the economy of $100 million or more. Although Indian irrigation projects are significant components of reservation economy, this regulation will not significantly change the economy, productivity, or investment opportunities of State, local, or tribal governments or communities on the affected reservations. Nor will this regulation cause a major increase in costs or prices for consumers, individual industries, or governments. This regulation does not increase irrigation O&M assessment rates, and this regulation is not expected to result in major increases in rates in the near future. However, there is a potential that this regulation could result in appreciable rate increases in the long-term. This regulation makes no change to the present method of establishing rates for irrigation projects. The regulation more clearly states the process the BIA has always used to calculate rates. The underlying statutory authority to charge irrigation O&M assessments remains unchanged under the regulation. No change was made to the regulation to address these comments. Comments: BIA Authority To Assess Irrigation O&M Charges Several of the commenters questioned the scope of the BIA's authority to charge irrigation O&M assessments. The comments came in various forms, some more general in nature and others more specific to other parts of the regulation, particularly subpart E—Financial Matters, Billing, and Collections. General and cross-cutting comments are addressed here, while more specific comments are addressed below under the appropriate headings. One commenter seemed to believe that the regulation created new authority for the BIA to fully recover its O&M costs for Indian irrigation projects in a way that it previously could not. Under 25 U.S.C. 381 *et seq.* , the BIA is authorized to recover the full cost of operation and maintenance of its irrigation facilities. This underlying statutory authority to assess irrigation O&M charges remains unchanged under the proposed regulation. No change was made to the regulation to address these comments. Two commenters read 25 U.S.C. 385 and the statutes it codifies to impose a requirement that the BIA first determine an individual's ability to pay irrigation O&M charges before setting rates and assessing charges. One of the commenters also suggested that the parcel of land on which the assessment is based must also have the ability to produce adequate income to pay irrigation O&M assessments. These comments misconstrue the Act of August 14, 1914 and 25 U.S.C. 385. The Secretary's authority to set O&M charges and collect irrigation assessments is not subject to a determination of an individual's ability to pay or the ability of a particular parcel of land to produce adequate income. The ability to pay language in both the 1914 Act and 25 U.S.C. 385 refers only to repayment of construction costs. No change was made to the regulation to address these comments. Comments: Trust Responsibility All of the commenters addressed the United States' trust responsibility to Indian tribes to some degree. Some questioned whether the regulation undermined the trust responsibility in any way, while others asserted a need for the regulation to expressly incorporate more safeguards to protect trust resources. Nothing in this regulation alters the BIA's responsibility regarding irrigation projects and related resources. Instead, this regulation addresses how the BIA administers its irrigation projects. Some commenters also asserted that there is a trust responsibility to provide irrigation service, and one commenter felt that such a trust responsibility required the BIA to charge Indian farmers a different (lower) rate than non-Indian farmers. The BIA does not have a trust obligation to operate and maintain its irrigation projects. See, e.g., *Grey* v. *United States* , 21 Cl. Ct. 285 (1990), aff'd, 935 F.2d 281 (Fed. Cir. 1991), cert. denied, 502 U.S. 1057 (1992). No change was made to the regulation to address these comments. Comment: Protection of Trust Resources One commenter stated that the regulation must incorporate safeguards to protect trust resources. 25 CFR 171.110 describes how the BIA will administer its irrigation facilities. Protection of trust resources is addressed by other statutes or regulations specific to the resource at issue. No change was made to the regulation to address these comments. Comment: Impacts on the Flathead Indian Irrigation Project Turnover One commenter expressed concern that the regulation could impact the transfer of operations and management of the Flathead Indian Irrigation Project. This regulation will have no impact on the transfer process, which is being undertaken pursuant to specific statutory authority. The terms and conditions of the transfer, which are currently being negotiated and developed, will address how the Flathead Indian Irrigation Project will be operated and managed after transfer. After transfer, this regulation will no longer apply to the Flathead Indian Irrigation Project because it will no longer be operated by the BIA. No change was made to the regulation to address these comments. Comment: Impacts on Other Department Bureaus and Offices One commenter stated that the regulation has the potential to impact the operation of the Bureau of Reclamation's Yakima Project. The Bureau of Reclamation has reviewed this regulation. Changes to the BIA irrigation regulation will have no impact on the Yakima Project. No change was made to the regulation to address these comments. Comment: Indian Lands in Probate One commenter recommended that the regulation include an O&M assessment exemption for Indian lands in probate. There is currently a process in place to resolve assessment of O&M on lands in probate outside the scope of this regulation. The process is covered in 25 CFR Part 15, Probate of Indian Estates, and the BIA Irrigation Handbook, Section 12.3.7 Estates/Probates. No change was made to the regulation to address these comments. Comment: Idle Lands on the Yakama Reservation One commenter stated that the regulation must study how the proposed regulation would help alleviate the idle lands problem on the Yakama Reservation. The overall idle agricultural lands issue is a function of the BIA's Real Estate Services program. The regulation at 25 CFR 171.610 provides an avenue by which the BIA, at the project level, may provide incentives to help alleviate some of the idle lands issues. Furthermore, the BIA looks forward to working with Tribes to explore the various options available for addressing the longstanding idle lands issue, such as through the individual project operating guidelines. No change was made to the regulation to address this comment. Subpart A—General Provisions One comment asked that the BIA retain 25 CFR 171.1(b) from the existing version of 25 CFR part 171, which provided authority for the Officer-in-Charge to waive portions of the regulations, particularly for small subsistence units and gardens. This provision was removed in order to avoid conflicts with Departmental Delegations of Authority and to provide consistent application of regulations across all irrigation projects. No change was made to the regulation to address these comments. Three commenters had various suggestions, questions, or concerns with some of the definitions in Section 171.100. Those comments are addressed in the following paragraphs. With regard to the definition of the *annual assessment waiver* and *carriage agreement* , one commenter stated that there was no reference to statutory authority for waiving annual O&M assessments or for *carriage agreements* . In the “authority” portion of the regulation, located just above Subpart A in the **Federal Register** notice, the authorities for all components of the regulation are listed. 25 U.S.C. 381 *et seq.* provide statutory authority for an *annual assessment waiver* and for *carriage agreements* . No change was made to the regulation to address these comments. One commenter asked whether Tribes will have any input into the determination of *farm unit* size, and another commenter asked where the BIA's definition of a *farm unit* is. Additionally, one commenter stated that the regulation fails to state what happens if a *farm unit* is subdivided. If the *farm unit* size is not defined in a project's authorizing legislation, it will be defined in the project-specific operating guidelines, and the BIA will be consulting with Tribes and water users in the development of these operating guidelines. With regard to subdivision of *farm units* , 25 CFR 171.225 describes what must be done to receive irrigation service to a subdivided *farm unit* . No change was made to the regulation to address these comments. One commenter stated that an *incentive agreement* should allow for irrigation water delivery at no or reduced O&M cost for the period of time required to realize the full agricultural potential of the previously idle parcel. The commenter also added that he believed that BIA lacked authority to assess O&M if the parcel is not producing adequate funds to pay O&M. 25 CFR 171.610(a)(4) allows for the delivery of water under an incentive agreement, the terms of which would be described in the agreement. As discussed above, the law does not require the BIA to determine or consider either an individual's ability to pay or the economic viability of the irrigated parcel when setting irrigation O&M assessment rates. No change was made to the regulation to address these comments. One commenter stated that the definition of *incentive agreement* should include a reference to the statutory authority for the concept. In the “authority” portion of the regulation, located just above Subpart A in the **Federal Register** notice, the authorities for all components of the regulation are listed. 25 U.S.C. 381 *et seq.* provide statutory authority for an *incentive agreement* . No change was made to the regulation to address these comments. One commenter thought the definition of *incentive agreement* failed to adequately define “improve idle lands.” In response to that comment, Section 171.610(a)(1) has been amended to include the language “* * * other activities that will improve idle lands to a condition that supports authorized use of delivered water.” One commenter stated that where neither tribal nor individual water rights have been quantified, there can be no such thing as a *supplemental water* . Given that issue, the commenter was concerned with the legality of the concept of *supplemental water* . If a water duty has not been established for an irrigation project, then supplemental water does not apply at that irrigation project. No change was made to the regulation to address these comments. One commenter thought the definition of *total assessable acres* should include special provisions for how O&M charges are assessed on the Toppenish-Simcoe Unit of the Wapato Irrigation Project. The BIA has specifically addressed this issue with the Yakama Nation by letter of June 2, 2006, from Michael Olsen, Principal Deputy Assistant Secretary-Indian Affairs to Honorable Louis Cloud. The BIA intends to include in the revised Project Operations and Maintenance Guidelines a provision substantially similar to the current 25 CFR 171.19(a)(2). Furthermore, project-specific provisions were removed from the regulation as part of the effort to create a consistent set of rules applicable to all BIA irrigation projects. No change was made to the regulation to address these comments. The definition of *wastewater* concerned one commenter. The commenter stated that the regulation should require water users to control return flows. In response to this comment, both the definition of *wastewater* and the regulation at Section 171.230 have been amended accordingly. One commenter stated that the BIA must specifically list each document referenced in Section 171.110. Section 171.110 references a broad array of laws, regulations, and policy documents too numerous to list. Furthermore, many of these items would be specific to individual irrigation project and thus would be inappropriate to reference in a regulation of general applicability. The same commenter also noted that the regulation should state where such documents could be obtained. A listing, along with copies of the pertinent documents, will be made available in the National Irrigation Handbook and the O&M guidelines specific to individual projects. To address this comment, Section 171.110(a) has been amended to reflect that copies of the referenced items can be obtained from the irrigation project serving you. Another commenter stated that his irrigation project is not safely or reliably operated or rehabilitated. The commenter asked when, under the proposed Section 171.110(a), his project would be rehabilitated. The physical state of the BIA's irrigation projects is directly related to BIA's historic inability to recover the full cost of operating and maintaining its irrigation projects. This regulation is intended to improve the BIA's cost recovery. No change was made to the regulation to address these comments. One commenter stated that the consultation referenced in Section 171.110(b) is a mandatory trust responsibility and that consulting only when appropriate or when time allows is insufficient. Consultation with Indian tribes is a government-wide policy, not a trust responsibility per se. As stated in the proposed rule, the BIA will consult with the Tribes and the BIA agrees that consultation is possible and desirable. No change was made to the regulation to address these comments. A number of commenters expressed concern about Section 171.125, which addresses appeals of the BIA's decisions on irrigation projects. The regulation as proposed was unclear and potentially in conflict with the 25 CFR Part 2. Section 171.125(b) has been amended to address these comments, provide clarity, and ensure consistency with the appeals process set forth in 25 CFR Part 2. Subpart B—Irrigation Service One commenter suggested that the regulation provide some authority to enable tiered O&M assessment rates on irrigation facilities to enable the projects to set rates based on quantity of water delivered to farm units. Rates for irrigation O&M are based on the cost of providing irrigation service, not on water quantity. Nothing in these proposed regulations prohibits individual projects from establishing various rates consistent with section 171.110. No change was made to the regulation to address these comments. With regard to Section 171.230, one commenter stated that the BIA should pay for the cost of improvements on Indian lands to make drainage water collection systems adequate. Where adequate funds exist to improve irrigation infrastructure, the BIA will make improvements. No change was made to the regulation in response to this comment. However, Section 171.230 has been amended in response to comments regarding the definition of *wastewater* in Section 171.100. Subpart C—Water Use One commenter expressed concern that allowing the BIA to provide leaching service under Section 171.305 may not be a beneficial use under some water right decrees, tribal water codes, or water use statutes. The commenter expressed a similar concern with regard to the BIA's authority to deliver domestic water and stock water under Section 171.310. Another commenter stated that the BIA was required to deliver domestic and stock water to the Walker River Paiute Tribe pursuant to a court decree. This regulation takes into consideration water rights and related considerations under Section 171.205, which states that “[t]he amount of water you receive will be based on your request, your legal entitlement to water, and the available water supply.” Furthermore, Section 171.110 describes how BIA will administer its irrigation facilities, which is by enforcing the applicable statutes, regulations, water rights decrees, and similar legal requirements, which may mandate “not” delivering leaching water or permitting delivery of domestic or stock water in some cases. No change was made to the regulation to address these comments. One commenter stated that Section 171.305(a)(3) is a departure from the status quo, contrary to practices necessary in some cases to rehabilitate idle land within an irrigation project, and inconsistent with the law. The regulation is not a departure from the status quo. Under former Section 171.17 and now under Sections 171.545 and 171.550, irrigation services are not provided until the annual O&M assessment is paid or there is an approved payment plan in place. The regulation accounts for rehabilitation of idle land. Section 171.610(a)(4) allows for the delivery of water under an incentive agreement, the terms of which could include delivery of water for the purposes of leaching without charge. Section 171.305(a)(3) is consistent with existing law. As discussed elsewhere in these responses to comments, the law does not require the BIA to determine or consider either an individual's ability to pay or the economic viability of the irrigated parcel when setting irrigation O&M assessment rates. The BIA has the authority to deny irrigation service if O&M charges are not paid. No change was made to the regulation to address these comments. Subpart D—Irrigation Facilities One commenter stated that the BIA had no legal authority for Section 171.400(b) because the BIA has a trust responsibility to provide adequate irrigation infrastructure, including necessary private structures to allow access to irrigation water. The commenter added that, at the least, the BIA must engage in consultation before any structures are built. As noted above, the operation and maintenance of irrigation projects is not a trust responsibility. The BIA is committed to engaging in meaningful tribal consultation when appropriate. If the circumstances warrant tribal consultation, the BIA will consult with the affected tribe(s). No change was made to the regulation to address these comments. One commenter objected to Section 171.400(c) to the extent it suggests that the BIA can bill tribal members for costs relating to trust or Indian-owned fee land within an irrigation project. Section 171.400, in its entirety, describes who is responsible for structures on a BIA irrigation project. Section 171.405 describes the process which an individual or group must go through to become responsible for an irrigation project structure “which is under a written agreement between you and us.” No change was made to the regulation to address these comments. One commenter asked that Section 171.405 be removed. The commenter stated that authorizing individuals to take control of irrigation project structures could interfere with the property rights of individuals or tribes owning property underlying the irrigation project facilities and could lead to unequal treatment between water users on a project. The BIA disagrees. One commenter believed that Sections 171.405 and 171.410 contradicted Section 171.415 and, accordingly, suggested that the regulation should be revised to require the BIA to protect the irrigation facilities from encroachment. Section 171.405 provides that authorization to take control of a structure requires a written agreement with the BIA. Revocable encroachment permits do not transfer ownership. The requirement of a written agreement qualifies the ability of an individual to build or assume responsibility of a structure. Such written agreements will ensure that individual property rights are not infringed upon. The BIA has determined that there are no inconsistencies in these sections, especially when examined in concert with the definition of *obstruction* in Section 171.100. No change was made to the regulation to address these comments. Subpart E—Financial Matters One commenter expressed concerns that under Section 171.500, BIA would abuse its authority and add unreasonable costs into the calculation of its irrigation rates because the rates are based on cost estimates rather than actual costs. The commenter was particularly concerned about the potential for fraud, waste, and error. The commenter also asked how the public can obtain irrigation project cost information used to calculate rates. The Secretary of the Interior has previously determined under the existing Section 171.1(f) “that rates will be based on a carefully prepared estimate of the cost of the normal O&M of the project.” Furthermore, because O&M assessment rates are set a year in advance to give adequate notice to irrigators, it is necessary to calculate the proposed rates based on an estimate of the costs for the upcoming year. These figures are typically indexed based on actual costs from previous years. There is opportunity for the public to comment on the proposed rates published annually in the **Federal Register** before they become final. Actual costs of operation and maintenance activities are available from the irrigation facility servicing your farm unit. No change was made to the regulation to address these comments. One commenter thought that Section 171.500(a) included a number of costs that should not be used in calculating rates. The commenter feared that inclusion of items such as depreciation, acquisition costs, and other costs would lead to unreasonably high and unjustifiable rates. The BIA has established rates based on the average per acre cost of all activities involved in delivering irrigation water and maintaining facilities. This regulation does not change that practice; rather, it more specifically identifies those items included in determining the annual costs. Actual costs of O&M activities are available from the irrigation facility servicing your farm unit. No change was made to the regulation to address these comments. Two commenters stated that the BIA should calculate O&M assessments based on an individual farmer's ability to pay under 25 U.S.C. 385, 386a, and 389. Under these statutes, the Secretary's authority to set O&M charges is not subject to a determination of an individual's ability to pay. As stated above in these responses, the “ability to pay” provision included in 25 U.S.C. 385 refers only to repayment of construction costs. 25 U.S.C. 385 codifies several separate provisions taken from the Act of August 1, 1914, Public Law 63-160, 38 Stat. 582, 583 (1914). In addition to authorizing the Secretary to set and assess O&M rates on irrigation projects, the 1914 Act also appropriated a lump sum of money to use for construction of irrigation projects. The second provision of 25 U.S.C. 385, regarding reimbursement of construction costs where Indians have the ability to pay, only applies to the construction money appropriated in the 1914 Act and does not relate to the Secretary's O&M rate-setting authority. 25 U.S.C. 386a refers only to construction charges and is not applicable to this regulation, which only addresses O&M charges. 25 U.S.C. 389 authorizes the Secretary to investigate whether non-Indians have the ability to pay irrigation charges. Based on the outcome of such an investigation, the Secretary has discretion to adjust irrigation charges, but nowhere does the law require that an individual's ability to pay be factored into the irrigation rate-setting process. No change was made to the regulation to address these comments. Two commenters stated that Sections 171.500 and 171.505 violated the BIA's trust responsibility to Indians. As stated above, the operation and maintenance of BIA irrigation projects is not a trust responsibility. See, e.g., *Grey* v. *United States* . With regard to comments about protection of trust resources that might be affected by the operation and maintenance of irrigation projects, the proposed regulation in no way changes the BIA's responsibility regarding irrigation projects and related resources. No change was made to the regulation to address these comments. One commenter suggested that the amount of any rate increase should be limited from year-to-year to no more than the rate of inflation. Because the actual cost of O&M may or may not coincide with inflation, this regulation does not limit O&M rate increases to annual inflation rates. No change was made to the regulation to address these comments. One commenter objected to Section 171.505(d), which provides that some projects may charge a minimum O&M assessment. The commenter objected to owners of small fractionated parcels being charged for irrigation service and recommended, at a minimum, that this section not apply to trust or allotted land. The commenter also claimed there was no legal basis for the minimum charge concept and stated that the BIA cannot charge O&M assessments where the land is not producing adequate funds to pay O&M assessments. This provision only applies to irrigation projects that establish a minimum assessment. The authority to establish a minimum charge is inherent in the Secretary's statutory authority to charge O&M assessments on Indian irrigation projects. See 25 U.S.C. 381 *et seq.* Contrary to the assertion of the commenter, the BIA can charge a minimum O&M assessment regardless of the whether the land produces adequate funds to pay the assessment. No change was made to the regulation to address these comments. One commenter noted that Section 171.510 failed to specify which irrigation projects distribute supplemental water. Such information will be available in the project-specific operating guidelines. This information was purposefully left out of the regulation because it is potentially subject to change at individual projects as water rights are determined and settled. No change was made to the regulation to address these comments. Section 171.515 prompted one commenter to state that the BIA needs to send bills to the water users before the irrigation season starts so that farmers have an adequate amount of time to pay. Because each irrigation project sends out its own bills, this comment is most appropriately directed to the individual irrigation projects. No change was made to the regulation to address these comments. One commenter objected to Section 171.540. No rationale was provided for the objection. To conform to the Debt Collection Improvement Act of 1996, collection of the information specified in the regulation is necessary. No change was made to the regulation to address these comments. One commenter objected to Section 171.545 because it does not account for whether the Indian-owned land produces adequate funds to pay the O&M charges. As discussed above, the BIA can charge a minimum O&M assessment regardless of the whether the land produces adequate funds to pay the assessment. The BIA does not consider an individual's ability to pay or the ability of the land to produce adequate funds when it sets O&M rates and charges assessments. No change was made to the regulation to address these comments. One commenter suggested that water users should be notified individually through the mail of all proposed rate changes instead of through the **Federal Register** as is provided in Section 171.565. It would not be practical for the BIA to notify each of its water users individually, nor is such notice required by law. No change was made to the regulation to address these comments. Several commenters expressed concern about Section 171.575, in which the proposed regulation stated that the BIA could change O&M rates without first notifying irrigators if uncontrolled costs arose. Commenters were concerned that the proposed language was overly broad and should be limited to emergency situations when structural failures threatened property, public safety, or the ability of the BIA to deliver water to a majority of an irrigation project. In response to these concerns, Section 171.575 has been revised to provide for special assessments only when urgencies arise. Rates cannot be changed without notice. Special assessments are now defined in the regulation at Section 171.100. The term “urgency” is defined in Section 171.100 as “a situation that we have determined may adversely impact our irrigation facilities, operation, or other irrigation activities; affect public safety; damage property or equipment.” Subpart F—Records, Agreements, and Other Matters One commenter raised concerns about Section 171.610. The comments are addressed above in the discussion of *incentive agreements* under Section 171.100. No change was made to the regulation to address this comment. Subpart G—Non-Assessment Status One commenter objected to Section 171.705 because it places the burden on the land owner to apply for an annual assessment waiver. The commenter stated that Section 171.705 is unfair because the United States, as trustee, is placing a burden on the trust beneficiary to seek relief from O&M charges. The purpose of Section 171.705 is to help address the problem of areas of an irrigation project within the constructed works where, for whatever reason, water cannot be delivered. The annual assessment waiver provides a mechanism for waiving the O&M assessment, eliminating the need for an expensive and time-consuming process to appeal a bill which has already been issued. It also provides an incentive for an irrigation project to repair or rehabilitate infrastructure to obtain assessment monies. Additionally, it would provide relief to the water user during the time it takes for lands to be re-designated to Temporarily or Permanently Non-Assessable status if so warranted. With regard to the notion of unfairness based on a trust relationship, as stated above, the operation and maintenance of BIA Irrigation Projects is not a trust responsibility. IV. Procedural Requirements A. Review Under Executive Order 12866 This regulation updates an existing regulation and is not a significant rule under Executive Order 12866.
(1)This regulation will not have an effect of $100 million or more on the economy. It will not adversely affect in a material way the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities. This is an existing regulation that is being updated and revised to implement the Inspector General's audit findings and the Debt Collection Improvement Act of 1996.
(2)This regulation will not create a serious inconsistency or otherwise interfere with an action taken or planned by another agency. The irrigation projects impacted by these revisions are solely owned by the BIA and no other agency provides supplemental services or is impacted by the operation of these projects.
(3)This regulation does not alter the budgetary effects of entitlements, grants, user fees, or loan programs or the rights or obligations of their recipients. The user fees or assessments that the BIA establishes at each irrigation project to recover its costs will eventually be impacted as the BIA reviews its rates and strives to implement full cost rates.
(4)This rule does not raise novel legal or policy issues. No new authorities or policies are being established. B. Review Under the Regulatory Flexibility Act The Department of the Interior certifies that this regulation will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 *et seq.* ). An initial Regulatory Flexibility Analysis is not required because Indian tribes are not considered to be small entities for purposes of this Act. C. Review Under the Small Business Regulatory Enforcement Fairness Act (SBREFA) This regulation is not a major regulation under 5 U.S.C. 804(2), the SBREFA. This regulation:
(1)Does not have an annual effect on the economy of $100 million or more. The total revenue stream for the operation and maintenance of all BIA irrigation projects is approximately $25 million annually. This is below the $100 million threshold.
(2)Will not cause a major increase in costs or prices for consumers, individual industries, Federal, state, or local government agencies, or geographic regions. These revisions establish a procedure for identifying full cost rates for BIA irrigation projects. This is not expected to cause major increases in the near future. However, there is a potential that this could result in appreciable rate increases in the long-term for those served by BIA irrigation projects.
(3)Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises. BIA irrigation projects are generally small and have minimal impacts on the economy. The projects are not in competition with other entities since they are located on reservations that are under the purview of the Department of the Interior, Bureau of Indian Affairs. D. Review Under the Unfunded Mandates Reform Act This regulation does not impose an unfunded mandate on state, local, or tribal governments or the private sector of more than $100 million per year. The regulation does not have a significant or unique effect on state, local, or tribal governments or the private sector. The BIA irrigation projects are located on reservations that are under the purview of the Department of the Interior, Bureau of Indian Affairs. A statement containing the information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531 *et seq.* ) is not required. E. Review Under Executive Order 12630 In accordance with Executive Order 12630, the regulation does not have significant takings implications. The regulation revisions do not deprive the public, state, or local governments of rights or property. A takings implication assessment is not required. F. Review Under Executive Order 13211 In accordance with Executive Order 13211, this regulation does not have a significant effect on the nation's energy supply, distribution, or use. The revision to 25 CFR part 171 will have no adverse effects on energy supply, distribution, or use (including a shortfall in supply, price increases, and increase use of foreign supplies). This regulation impacts irrigation projects that have little or no energy supply issues. G. Review Under Executive Order 13132 In accordance with Executive Order 13132, the regulation does not have sufficient federalism implications to warrant the preparation of a Federalism Assessment because they will not interfere with the roles, rights, and responsibilities of states. H. Review Under Executive Order 12988 In accordance with Executive Order 12988, the Office of the Solicitor has determined that this regulation does not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of the Order. I. Review Under the National Environmental Policy Act
(NEPA)This regulation does not constitute a major Federal action significantly affecting the quality of the human environment and no detailed statement is required under the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370(d)). J. Review Under Executive Order 13175 In accordance with the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951), Executive Order 13175, and 512 DM 2, we have identified potential effects on Indian trust resources and they are addressed in this rule. Consultation meetings have been held with the affected Tribes. Accordingly:
(1)We have consulted with the affected Tribes.
(2)We have consulted with Tribes on a government-to-government basis and the consultations have been open and candid so that the affected Tribes could fully evaluate the potential impact of the rule on trust resources.
(3)We have considered tribal views in the final regulation.
(4)We have not consulted with the other bureaus and offices of the Department about the potential effects of this regulation on Indian Tribes. Other Department bureaus and offices are not affected by this rule. The BIA irrigation projects are vital components of the local agricultural economy of the reservations on which they are located. To fulfill its responsibilities to the Tribes, tribal organizations, water user organizations, and the individual water users, the BIA communicates, coordinates, and consults on a continuing basis with these entities on issues of water delivery, water availability, costs of administration, operation, maintenance, and rehabilitation. This is accomplished at the individual irrigation projects by project, agency, and regional representatives, as appropriate, in accordance with local protocol and procedures. The BIA Central Office held four consultation meetings for Tribes and tribal members. Consultation meetings were held on August 24, 2004 and May 12, 2005 in Phoenix, Arizona, and on August 26, 2004 and May 10, 2005 in Billings, Montana. K. Review Under Paperwork Reduction Act of 1995 These regulation revisions affect the collection of information, which has been approved by the Office of Information and Regulatory Affairs, Office of Management and Budget, under the Paperwork Reduction Act of 1995 with the OMB Control Number 1076-0141, expiring August 31, 2009. The Bureau of Indian Affairs operates 15 irrigation projects that provide irrigation services to the end user. The information we collect enables us to properly bill for the services we provide by collecting information that identifies the individual responsible for paying the costs of the services. Some of the information is needed to satisfy the requirements of the Debt Collection Improvement Act of 1996. The table addresses the services available, the number of users, the burden for each, as well as the yearly total and the sections in the rule that apply to the collection items. Service CFR section 171 Hourly burden to respondent per request Number of respondent requests annually Total annual burden hours Salary per hour ($20) × all respondent requests = annual cost burden Requesting irrigation service 200/600 0.5 26,156 13,078 $261,560 Subdividing a farm unit 225 4 1 4 80 Requesting leaching service 305 1 40 40 800 Requesting water for domestic or stock purposes 310 .3 474 142 2,840 Building non-government structures in BIA rights-of-ways 405 3 67 201 4,020 Installing a fence on BIA property or rights-of-ways 410 1.5 52 78 1,560 What information must be provided for billing purposes 530 0.2 500 100 2,000 Requesting payment plans on bills 550 2 126 252 5,040 Establishing a carriage agreement (carrying third party water through our facilities to your lands) 605 1 3 3 60 Negotiating an irrigation incentive lease with the BIA 610/615 6 21 126 2,520 Requesting annual assessment waiver 710/715 1 135 135 2,700 Annual totals 27,575 14,159 $283,180 We estimate that we service 6,539 users who submit information about 27,575 times a year. We estimate the total annual hourly burden to be 14,159 at an estimated cost of $283,180. The users mainly request water to be turned on or turned off. Users are not required to maintain records, but may do so for business purposes. The information they submit is for the purpose of obtaining or retaining a service, namely delivery of irrigation water. While we do require personal information for the purpose of adhering to the controlling laws and regulations, we protect the information under the Privacy Act. Comments on this information collection can be made at any time and sent to the BIA Information Collection Clearance Officer, 625 Herndon Parkway, Herndon, VA 20171. Please note that comments about the burden are separate from comments on the rule. If you wish to withhold personal information, such as your name, you must state this prominently at the beginning of you comments. We will honor your request to the extent that the law allows. List of Subjects in 25 CFR Part 171 Indians—lands, Irrigation. Dated: January 22, 2008. Carl J. Artman, Assistant Secretary—Indian Affairs. For the reasons set out in the preamble, the Department of the Interior, Bureau of Indian Affairs, is revising part 171 of Title 25 of the Code of Federal Regulations to read as follows: PART 171—IRRIGATION OPERATION AND MAINTENANCE Subpart A—General Provisions Sec. 171.100 What are some of the terms I should know for this part? 171.105 Does this part apply to me? 171.110 How does BIA administer its irrigation facilities? 171.115 Can I and other irrigators establish representative organizations? 171.120 What are the authorities and responsibilities of a representative organization? 171.125 Can I appeal BIA decisions? 171.130 Who can I contact if I have any questions about these regulations or my irrigation service? 171.135 Where do I submit written information or requests? 171.140 Information collection. Subpart B—Irrigation Service 171.200 How do I request irrigation service from the BIA? 171.205 How much water will I receive? 171.210 Where will BIA provide my irrigation service? 171.215 What if the elevation of my farm unit is too high to receive irrigation water? 171.220 What must I do to my farm unit to receive irrigation service? 171.225 What must I do to receive irrigation service to my subdivided farm unit? 171.230 What are my responsibilities for wastewater? Subpart C—Water Use 171.300 Does BIA restrict my water use? 171.305 Will BIA provide leaching service to me? 171.310 Can I use water delivered by BIA for livestock purposes? Subpart D—Irrigation Facilities 171.400 Who is responsible for structures on a BIA irrigation project? 171.405 Can I build my own structure or take over responsibility of a BIA structure? 171.410 Can I install a fence on a BIA irrigation project? 171.415 Can I place an obstruction on a BIA irrigation project? 171.420 Can I dispose of sewage, trash or other refuse on a BIA irrigation project? Subpart E—Financial Matters: Assessments, Billing, and Collections 171.500 How does BIA determine the annual operation and maintenance assessment rate for the irrigation facility servicing my farm unit? 171.505 How does BIA calculate my annual operation and maintenance assessment? 171.510 How does BIA calculate my annual operation and maintenance assessment if supplemental water is available on the irrigation facility servicing my farm unit? 171.515 Who will BIA bill? 171.520 How will I receive my bill and when do I pay it? 171.525 How do I pay my bill? 171.530 What information must I provide BIA for billing purposes? 171.535 Why is BIA collecting this information from me? 171.540 What can happen if I do not provide this information? 171.545 What can happen if I don't pay my bill on time? 171.550 Can I arrange a Payment Plan if I cannot pay the full amount due? 171.555 What additional costs will I incur if I am granted a Payment Plan? 171.560 What if I fail to make payments as specified in my Payment Plan? 171.565 How will I know if BIA plans to adjust my annual operation and maintenance assessment rate? 171.570 What is the **Federal Register** and where can I get it? 171.575 Can BIA charge me special assessments? Subpart F—Records, Agreements, and Other Matters 171.600 What information is collected and retained on the irrigation service I receive? 171.605 Can I establish a Carriage Agreement with BIA? 171.610 Can I arrange an Incentive Agreement if I want to farm idle lands? 171.615 Can I request improvements to BIA facilities as part of my Incentive Agreement? Subpart G—Non-Assessment Status 171.700 When do I not have to pay my annual operation and maintenance assessment? 171.705 What criteria must be met for my land to be granted an Annual Assessment Waiver? 171.710 Can I receive irrigation water if I am granted an Annual Assessment Waiver? 171.715 How do I obtain an Annual Assessment Waiver? 171.720 For what period does an Annual Assessment Waiver apply? Authority: 25 U.S.C. 2; 25 U.S.C. 9; 25 U.S.C. 13; 25 U.S.C. 381; Act of April 4, 1910, 36 Stat. 270, as amended (codified at 25 U.S.C. 385); 25 U.S.C. 386a; Act of June 22, 1936, 49 Stat. 1803 (codified at 25 U.S.C. 389 *et seq.* ). Subpart A—General Provisions § 171.100 What are some of the terms I should know for this part? *Annual Assessment Waiver* means a mechanism for us to waive your annual operation and maintenance assessment under certain specified circumstances. *Annual operation and maintenance assessment* means the charges you must pay us for our costs of administration, operation, maintenance, and rehabilitation of the irrigation facility servicing your farm unit. *Annual operation and maintenance assessment rate* means the per acre charge we establish for the irrigation facility servicing your farm unit. *Assessable acres* (see *Total assessable acres* ). *Authorized use* means your use of water delivered by us that supports irrigated agriculture, livestock, Carriage Agreements or other uses defined by laws, regulations, treaty, compact, judicial decree, river regulatory plan, or other authority. *BIA* means the Bureau of Indian Affairs within the United States Department of the Interior. *Bill* means our statement to you of the assessment charges and/or fees you owe the United States for administration, operation, maintenance, rehabilitation, and/or construction of the irrigation facility servicing your farm unit. *Carriage Agreement* means a legally binding contract we enter into:
(1)To convey third-party water through our irrigation facilities; or
(2)To convey our water through third-party facilities. *Construction assessment* means the periodic charge we assess you to repay us the funds we used to construct our irrigation facilities serving your farm unit that are determined to be reimbursable under applicable statutes. *Customer* means any person or entity to whom we provide irrigation service. *Ditch* (see *Farm ditch* or *Service ditch* ). *Due date* means the date printed on your bill, 30 days after which your bill becomes past due. *Facility* (see *Irrigation facility* ). *Farm ditch* means a ditch or canal that you own, operate, maintain, and rehabilitate. *Farm unit* means the smallest parcel of land for which we will establish a delivery point. Farm unit size is defined in the authorizing legislation for each irrigation facility, or in the absence of such legislation, we will define the farm unit size. *I, me, my, you* , and *your* means all interested parties, especially persons or entities to which we provide irrigation service and receive use of our irrigation facilities, such as irrigators, landowners, leasees, irrigator organizations, irrigation districts, or other entities affected by this part and our supporting policies, manuals, and handbooks. *Idle lands* means lands that are not currently farmed because they have characteristics that limit crop production. *Incentive Agreement* means a written agreement between you and us that allows us to waive your annual operation and maintenance assessment, when you agree to improve idle lands and we determine that it is in the best interest of our irrigation facility. *Irrigation bill* (see *Bill* ). *Irrigation district* (see *Representative organization* ). *Irrigation facility* means all structures and appurtenant works for the delivery, diversion, and storage of irrigation water. These facilities may be referred to as projects, systems, or irrigation areas. *Irrigation service* means the full range of services we provide customers, including but not limited to administration, operation, maintenance, and rehabilitation of our irrigation facilities. *Irrigation water* or *water* means water we deliver through our facilities for the general purpose of irrigation and other authorized purposes. *Irrigator* (see *Customer* ). *Landowner* means a person or entity that owns fee, tribal trust, and/or individual allotted trust lands. *Leaching Service* means our delivery of water to you at your request for the purpose of transporting salts below the root zone of a farm unit. *Lessee* means any person or entity that holds a lease approved by us on lands to which we provide irrigation service. *Must* means an imperative or mandatory act or requirement. *My land* and *your land* mean all or part of your farm unit. *Obstruction* means anything permanent or temporary that blocks, hinders, impedes, stops or cuts off our facilities or our ability to perform the services we determine necessary to provide service to our customers. *Organization* (see *Representative organization* ). *Past due bill* means a bill that has not been paid within 30 days of the due date stated on your bill. *Permanently non-assessable acres (PNA)* means lands that the Secretary of the Interior has determined to be permanently non-irrigable pursuant to the standards set out in 25 U.S.C. 389b. *Representative organization* or *organization* means a legally established organization representing your interests that confers with us on how we provide irrigation service at a particular irrigation facility. *Service(s)* (see *Irrigation service* ). *Service area* means lands designated by us to be served by one of our irrigation facilities. *Service ditch* means a ditch or canal which we own, administer, operate, maintain, and rehabilitate that we use to provide irrigation service to your farm unit. *Soil salinity* means soils containing high salt content that limit crop production. *Special assessment* means a charge to cover the uncontrolled cost arising from an urgency on an irrigation facility. *Structures* (see *Irrigation facility* ). *Subdivision* means a farm unit that has been subdivided into smaller parcels. *Supplemental water* means water available for delivery by our irrigation facilities beyond the quantity necessary to provide all project customers requesting water with the per-acre water duty established for that project. *Taxpayer identifying number* means either your Social Security Number or your Employer Identification Number. *Temporarily non-assessable acres (TNA)* means lands that the Secretary of the Interior has determined to be temporarily non-irrigable pursuant to the standards set out in 25 U.S.C. 389a. *Total assessable acres* means the total acres of land served by one of our irrigation facilities to which we assess operation and maintenance charges. The *Total assessable acres* within the service area of an irrigation facility do not include those acres of land that are designated PNA or TNA, nor those acres of land granted an Annual Assessment Waiver. *Trust* or *restricted land* or *land in trust* or restricted status (see definitions in 25 CFR 151.2). *Urgency* means a situation that we have determined may adversely impact our irrigation facilities, operation, or other irrigation activities; affect public safety; or damage property or equipment. *Wastewater* means surface runoff and subsurface drainage from your farm unit from water delivered by us that exceeds irrigation requirements. *Water* (see *Irrigation water* ). *Water delivery* is an activity that is part of the irrigation service we provide to our customers when water is available. *Water duty* means the amount of water, in acre-feet per acre, necessary for full-service irrigation. This value is established by decree, compact, or other legal document, or by specialized engineering studies. *Water user* (see *Customer* ). *We* , *us* , and *our* means the United States Government, the Secretary of the Interior, BIA, and all who are authorized to represent us in matters covered under this part. § 171.105 Does this part apply to me? This part applies to you if you own or lease land within an irrigation project where we assess fees and collect monies to administer, operate, maintain, and rehabilitate project facilities. § 171.110 How does BIA administer its irrigation facilities?
(a)We administer our irrigation facilities by enforcing the applicable statutes, regulations, Executive Orders, directives, Indian Affairs Manual, the Irrigation Handbook, and other written policies, procedures, directives, and practices to ensure the safe, reliable, and efficient administration, operation, maintenance, and rehabilitation of our facilities. Such enforcement can include refusal or termination of irrigation services to you. Copies of the above listed items may be obtained from the irrigation project serving you.
(b)We will cooperate and consult with you, as appropriate, on irrigation activities and policies of the particular irrigation facility serving you. § 171.115 Can I and other irrigators establish representative organizations? Yes. You and other irrigators may establish a representative organization under applicable law to represent your interests for the particular irrigation facilities serving you. § 171.120 What are the authorities and responsibilities of a representative organization?
(a)A legally established organization representing you may make rules, policies, and procedures it may find necessary to administer the activities it is authorized to perform.
(b)An organization must not make rules, policies, or procedures that conflict with our regulations or any of our other written policies, procedures, directives, and manuals.
(c)If this organization collects operation and maintenance assessments and construction assessments on your behalf to be paid to us, it must pay us all your past and current operation and maintenance and construction assessment charges before we will provide irrigation service to you. § 171.125 Can I appeal BIA decisions?
(a)You may appeal our decisions in accordance with procedures set out in 25 CFR Part 2, unless otherwise prohibited by law.
(b)If you appeal an irrigation bill, you must pay the bill in accordance with subpart E before we will provide irrigation service to you. If you prevail on appeal, any overpayment will be refunded to you. § 171.130 Who can I contact if I have any questions about these regulations or my irrigation service? Contact the local irrigation project where you receive service or want to apply for service. If your questions are not addressed to your satisfaction at the local project level, you may contact the appropriate BIA Regional Office. § 171.135 Where do I submit written information or requests? Submit written information to us or make request of us in writing at the irrigation project servicing your farm unit. § 171.140 Information collection. The information collection requirements contained in this part have been approved by the Office of Management and Budget under 44 U.S.C. 3501 *et seq.* and assigned clearance number 1076-0141. This information collection is specifically found in 25 CFR Sections 171.200, 171.225, 171.305, 171.310, 171.405, 171.410, 171.530, 171.550, 171.600, 171.605, 171.610, 171.615, 171.710, 171.715. A Federal agency may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number. Subpart B—Irrigation Service § 171.200 How do I request irrigation service from the BIA?
(a)You must request service from the irrigation facility servicing your farm unit.
(b)Your request must contain at least the following information:
(1)Your full legal name;
(2)Where you want service;
(3)The time and date you want service to start;
(4)How long you want service;
(5)The rate of water flow you want, if available;
(6)How many acres you want to irrigate; and
(7)Any additional information required by the project office responsible for providing your irrigation service.
(c)You must request supplemental water in accordance with the project guidelines established by the specific project providing your irrigation service. § 171.205 How much water will I receive? The amount of water you receive will be based on your request, your legal entitlement to water, and the available water supply. § 171.210 Where will BIA provide my irrigation service?
(a)We will provide service to your farm unit at a single delivery point that we designate.
(b)At our discretion, we may establish additional delivery points when:
(1)We determine it is impractical to deliver water to your farm unit from a single delivery point;
(2)You agree in writing to be responsible for all costs to establish an additional delivery point;
(3)You pay us our costs prior to our establishing an additional delivery point; and
(4)Any work accomplished under this section does not disrupt our service to other customers without their written agreement.
(c)We may establish your delivery point(s) at a well head. § 171.215 What if the elevation of my farm unit is too high to receive irrigation water?
(a)We will not change our service ditch level to provide service to you.
(b)You may install, operate, and maintain your own facilities, at your cost, to provide service to your land:
(1)From a delivery point we designate; and
(2)In accordance with specifications we approve. § 171.220 What must I do to my farm unit to receive irrigation service? You must meet the following requirements for us to provide service:
(a)Put water we deliver to authorized uses;
(b)Make sure your farm ditch has sufficient capacity to carry the water we deliver; and
(c)Properly operate, maintain, and rehabilitate your farm ditch. § 171.225 What must I do to receive irrigation service to my subdivided farm unit? In order to receive irrigation service, you must:
(a)Provide us a copy of the recorded plat or map of the subdivision which shows us how the irrigation water will be delivered to the irrigable acres;
(b)Pay for any extensions or alterations to our facilities that we approve to serve the subdivided units;
(c)Construct, at your cost, any facilities within your subdivided farm unit; and
(d)Operate and maintain, at your cost, any facilities within your subdivided farm unit. § 171.230 What are my responsibilities for wastewater?
(a)You are responsible for your wastewater.
(b)Wastewater may be returned to our facilities, but only at locations we designate, in a manner we approve, and at your cost.
(c)You must not allow your wastewater to flow or collect on our facilities or roads, except at locations we designate and in a manner we approve.
(d)If you fail to comply with this section, we may withhold services to you. Subpart C—Water Use § 171.300 Does BIA restrict my water use?
(a)You must not interfere with or alter our service to you without our prior written authorization; and
(b)You must only use water we deliver for authorized uses. We may withhold services if you use water for any other purpose. § 171.305 Will BIA provide leaching service to me?
(a)We may provide you leaching service if:
(1)You submit a written plan that documents how soil salinity limits your crop production and how leaching service will correct the problem;
(2)We approve your plan in writing; and
(3)Your irrigation bills are not past due.
(b)Leaching service will only be available during the timeframe established by your irrigation facility.
(c)We reserve the right to terminate this service if we determine you are not complying with paragraph
(a)of this section. § 171.310 Can I use water delivered by BIA livestock purposes? Yes, if we determine it will not:
(a)Interfere with the operation, maintenance, or rehabilitation of our facilities;
(b)Be detrimental to or jeopardize our facilities;
(c)Adversely affect the water rights or water supply; or
(d)Cause additional costs to us that we do not agree to in writing. Subpart D—Irrigation Facilities § 171.400 Who is responsible for structures on a BIA irrigation project?
(a)We may build, operate, maintain, rehabilitate or remove structures, including bridges and other crossings, on our irrigation projects.
(b)We may build other structures for your private use during the construction or extension of an irrigation project. We may charge you for structures built for your private use under this section, and we may require you to maintain them.
(c)If we require you to maintain a structure and you do not do so to our satisfaction, we may remove it or perform the necessary maintenance, and we will bill you for our costs. § 171.405 Can I build my own structure or take over responsibility of a BIA structure? You may build a structure on our irrigation facility for your private use or take responsibility of one of our structures, but only under a written agreement between you and us which:
(a)Relieves us from any future liability or responsibility for the structure;
(b)Relieves us from any future costs incurred for maintaining the structure;
(c)Describes what is granted by us and accepted by you; and
(d)Provides that if you do not regularly use a structure for a period of time that we have determined, or you do not properly maintain and rehabilitate the structure, we will notify you in writing that:
(1)You must either remove it or correct any unsafe condition;
(2)If you do not comply with our notice, we may remove the structure and you must reimburse us our costs; and
(3)We may modify, close, or remove your structure without notice due to an urgency we have identified. § 171.410 Can I install a fence on a BIA irrigation project? Yes. Fences are considered structures and may be installed in compliance with § 171.405. § 171.415 Can I place an obstruction on a BIA irrigation project? No. You may not place obstructions on BIA irrigation projects.
(a)If you do so, we will notify you in writing that you must remove it.
(b)If you do not remove your obstruction in compliance with our notice, we will remove it and we will bill you for our costs.
(c)We can remove your obstruction without notice because of an urgency we have identified. § 171.420 Can I dispose of sewage, trash, or other refuse on a BIA irrigation project? No. Sewage, trash, or other refuse are considered obstructions and must be removed in accordance with § 171.415. Subpart E—Financial Matters: Assessments, Billing, and Collections § 171.500 How does BIA determine the annual operation and maintenance assessment rate for the irrigation facility servicing my farm unit?
(a)We calculate the annual operation and maintenance assessment rate by estimating the following annual costs and then dividing by the total assessable acres for your irrigation facility:
(1)Personnel salary and benefits for the facility engineer/manager and employees under their management or control;
(2)Materials and supplies;
(3)Vehicle and equipment repairs;
(4)Equipment costs, including lease fees;
(5)Depreciation;
(6)Acquisition costs;
(7)Maintenance of a reserve fund available for contingencies or emergency costs needed for the reliable operation of the irrigation facility infrastructure;
(8)Maintenance of a vehicle and heavy equipment replacement fund;
(9)Systematic rehabilitation and replacement of project facilities;
(10)Contingencies for unknown costs and omitted budget items; and
(11)Other costs we determine necessary to properly perform the activities and functions characteristic of an irrigation facility.
(b)Annual operation and maintenance assessment rates may be lowered through the exercise of our discretion when items listed in
(a)of this section are adjusted pursuant to our authority under 25 U.S.C. 385, 386a and 389.
(c)If you subdivide your farm unit, you may be subject to a higher annual operation and maintenance assessment rate, which we publish annually in the **Federal Register** .
(d)At projects where supplemental water is available, the calculation of your annual operation and maintenance assessment rate may take into consideration the total estimated annual amount to be collected for supplemental water deliveries. § 171.505 How does BIA calculate my annual operation and maintenance assessment?
(a)We calculate your annual operation and maintenance assessment by multiplying the total assessable acres of your land within the service area of our irrigation facility by the annual operation and maintenance assessment rate we establish for that facility.
(b)We will not assess lands that have been re-classified as either permanently non-assessable
(PNA)or temporarily non-assessable
(TNA)or lands that have been granted an Annual Assessment Waiver.
(c)If your lands are under an approved Incentive Agreement, we may waive your assessment as described in the Incentive Agreement (See § 171.610).
(d)Some irrigation facilities may charge a minimum operation and maintenance assessment. If the irrigation facility serving your farm unit charges a minimum operation and maintenance assessment that is more than your assessment calculated by the method described in subpart
(a)of this section, you will be charged the minimum operation and maintenance assessment. We provide public notice of any minimum operation and maintenance assessments annually in the **Federal Register** (See § 171.565). § 171.510 How does BIA calculate my annual operation and maintenance assessment if supplemental water is available on the irrigation facility servicing my farm unit?
(a)For projects where supplemental water is available, and you request and receive supplemental water, your assessment will include two components: a base rate, which is for your per-acre water duty delivered to your farm unit; and a supplemental water rate, which is for water delivered to your farm unit in addition to your per-acre water duty.
(b)We publish base and supplemental water rates annually in the **Federal Register** . The base and supplemental water rates are established to recover the costs identified in Section 171.500(a) of this Subpart.
(c)If your project has established a supplemental water rate, and you request and receive supplemental water, we will calculate your total annual operation and maintenance assessment by adding the following two totals:
(1)The total assessable acres of your land within the service area of our irrigation facility multiplied by the annual operation and maintenance assessment rate we establish for that facility; and
(2)the actual quantity of supplemental water you request and we agree to deliver (in acre-feet) times the supplemental water rate established for that facility. § 171.515 Who will BIA bill?
(a)We will bill the landowner, unless:
(1)The land is leased under a lease approved by us, in which case we will bill the lessee, or
(2)The landowner(s) is represented by a representative organization that collects annual operation and maintenance assessments on behalf of its members and the representative organization makes a direct payment to us on your behalf.
(b)If you own or lease assessable lands within a BIA irrigation facility, you will be billed for annual operation and maintenance assessments, whether you request water or not, unless otherwise specified in § 171.505(b). § 171.520 How will I receive my bill and when do I pay it?
(a)You will receive your bill in the mail at the address of record you provide us.
(b)You should pay your bill no later than the due date stated on your bill.
(c)You will not receive a bill for supplemental water. You must pay us in advance at the supplemental water rate established for you project published annually in the **Federal Register** . § 171.525 How do I pay my bill?
(a)You can pay your bill by:
(1)Personally going to the local office of the irrigation facility authorized to receive your payment during normal business hours;
(2)Depositing your payment in an authorized drop box, if available, at the local office of the irrigation facility; or
(3)Mailing your payment to the address indicated on your bill.
(b)Your payment must be in the form of:
(1)Check or money order in the mail or authorized drop box; or
(2)Cash, check, or money order if you pay in person. § 171.530 What information must I provide BIA for billing purposes? We must obtain certain information from you to ensure we can properly bill, collect, deposit, and account for money you owe the United States. At a minimum, this information is:
(a)Your full legal name;
(b)Your correct mailing address; and
(c)Your taxpayer identifying number. § 171.535 Why is BIA collecting this information from me?
(a)As part of doing business with you, we must collect enough information from you to properly bill and service your account.
(b)We are required to collect your taxpayer identifying number under the authority of, and as prescribed in, the Debt Collection Improvement Act of 1996, Public Law 104-134 (110 Stat. 1321-364). § 171.540 What can happen if I do not provide this information? We will not provide you irrigation service. § 171.545 What can happen if I don't pay my bill on time?
(a)We will not provide you irrigation service until:
(1)Your bill is paid; or
(2)You make arrangement for payment pursuant to § 171.550 of this part.
(b)If you do not pay your bill prior to the close of business on the 30th day after the due date, we consider your bill past due, send you a notice, and assess you the following:
(1)Interest, as required by 31 U.S.C. 3717. Interest will accrue from the original due date stated on your bill.
(2)An administrative fee, as required by 31 CFR 901.9.
(c)If you do not pay your bill prior to the close of business of the 90th day after the due date, we will assess you a penalty, as required by 31 CFR 901.9(d). Penalties will accrue from the original due date stated on your bill.
(d)We will forward your past due bill to the United States Treasury no later than 180 days after the original due date, as required by 31 CFR 901.1, “Aggressive agency collection activity.” § 171.550 Can I arrange a Payment Plan if I cannot pay the full amount due? We may approve a Payment Plan if:
(a)You are a landowner and your land is not leased;
(b)You certify that you are financially unable to make a lump sum payment;
(c)You provide additional information we request, which may include information identified in 31 CFR 901.8, “Collection in installments”; and
(d)You sign our Payment Plan containing terms and conditions we specify. § 171.555 What additional costs will I incur if I am granted a Payment Plan? You will incur the following costs:
(a)An administrative fee to process your Payment Plan, as required by 31 CFR 901.9.
(b)Interest, accrued on your unpaid balance, in accordance with § 171.545. § 171.560 What if I fail to make payments as specified in my Payment Plan?
(a)We will discontinue irrigation service until your bill is paid in full;
(b)You will be in default, you will be assessed an administrative fee, and your debt will be immediately forwarded to the United States Treasury in accordance with the Debt Collection Improvement Act of 1996 (Pub. L. 104-134).
(c)You will be ineligible for Payment Plans for the next 6 years. § 171.565 How will I know if BIA plans to adjust my annual operation and maintenance assessment rate?
(a)We provide public notice of our proposed rates annually in the **Federal Register** .
(b)You may contact the irrigation facility servicing your farm unit. § 171.570 What is the Federal Register and where can I get it?
(a)The **Federal Register** is the official daily publication for Rules, Proposed Rules, and Notices of official actions by Federal agencies and organizations, as well as Executive Orders and other Presidential Documents, and is produced by the United States Government Printing Office (GPO).
(b)You can get publications of the **Federal Register** :
(1)By going on the World Wide Web at *http://www.gpo.gov* ;
(2)By writing to the GPO, Superintendent of Documents, P.O. Box 371954, Pittsburgh, Pennsylvania 15250-7954; or
(3)By calling GPO at
(202)512-1530. § 171.575 Can BIA charge me a special assessment? Yes. We will make every reasonable effort to avoid charging special assessments. However, if we determine that we have a significant uncontrolled cost due to an urgency, we may charge you a special assessment. We will only charge special assessments when there are inadequate project funds available, including any emergency reserve funds held by the project. The special assessment rate will be calculated by dividing the total uncontrolled cost, or some portion of that cost, by the total number of assessable acres. Your individual special assessment will be equal to the special assessment rate multiplied by the number of assessable acres in your farm unit. Subpart F—Records, Agreements, and Other Matters § 171.600 What information is collected and retained on the irrigation service I receive? We will collect and retain at least the following information as part of our record of the irrigation service we have provided you:
(a)Your name;
(b)Delivery point(s) where service was provided;
(c)Beginning date and time of your irrigation service;
(d)Ending date and time of your irrigation service; and
(e)Amount of water we delivered to your farm unit. § 171.605 Can I establish a Carriage Agreement with BIA?
(a)We may agree in writing to carry third-party water through our facilities to your lands not served by our facilities if we have determined that our facilities have adequate capacity to do so.
(b)If we determine that carrying water in accordance with paragraph
(a)of this section is jeopardizing our ability to provide irrigation service to the lands we are required to serve, we will terminate the Agreement.
(c)We may enter into an agreement with a third party to provide service through their facilities to your isolated assessable lands.
(d)You must pay us all administrative, operating, maintenance, and rehabilitation costs associated with any agreement established under this section before we will convey water.
(e)We will notify you in writing no less than five days before terminating a Carriage Agreement established under this section.
(f)We may terminate a Carriage Agreement without notice due to an urgency we have identified. § 171.610 Can I arrange an Incentive Agreement if I want to farm idle lands? We may approve an Incentive Agreement if:
(a)You request one in writing at least 90 days prior to the beginning of the irrigation season that includes a detailed plan to improve the idle lands, which contains at least the following:
(1)A description of specific improvements you will make, such as clearing, leveling, or other activities that will improve idle lands to a condition that supports authorized use of delivered water;
(2)The estimated cost of the improvements you will make;
(3)The time schedule for your proposed improvements;
(4)Your proposed schedule for water delivery, if necessary; and
(5)Justification for use of irrigation water during the improvement period.
(b)You sign our Incentive Agreement containing terms and conditions we specify. § 171.615 Can I request improvements to BIA facilities as part of my Incentive Agreement? Yes. You may request and we may agree to make improvements as part of your Incentive Agreement that we determine are in the best interest of the irrigation facility servicing your farm unit. Subpart G—Non-Assessment Status § 171.700 When do I not have to pay my annual operation and maintenance assessment? You do not have to pay your annual operation and maintenance assessment for your land(s) within the service area of your irrigation facility when:
(a)We grant you an Annual Assessment Waiver; or
(b)We grant you an Incentive Agreement which may include waiving your annual operation and maintenance assessment; or
(c)Your land is re-designated as permanently non-assessable or temporarily non-assessable. § 171.705 What criteria must be met for my land to be granted an Annual Assessment Waiver? For your land to be granted an Annual Assessment Waiver, we must determine that our irrigation facilities are not capable of delivering adequate irrigation water to your farm unit. Inadequate water supply due to natural conditions or climate is not justification for us to grant an Annual Assessment Waiver. § 171.710 Can I receive irrigation water if I am granted an Annual Assessment Waiver? No. Water will not be delivered in any quantity to your farm unit if you have been granted an Annual Assessment Waiver. § 171.715 How do I obtain an Annual Assessment Waiver? For your land to be granted an Annual Assessment Waiver, you must:
(a)Send us a request in writing to have your land granted an Annual Assessment Waiver;
(b)Submit your request prior to the bill due date for the year for which you are requesting the Annual Assessment Waiver; and
(c)Receive our approval in writing. § 171.720 For what period does an Annual Assessment Waiver apply? Annual Assessment Waivers are only valid for the year in which they are granted. To obtain an Annual Assessment Waiver for a subsequent year, you must reapply. [FR Doc. E8-3698 Filed 2-28-08; 8:45 am] BILLING CODE 4310-W7-P DEPARTMENT OF HOMELAND SECURITY Coast Guard 33 CFR Part 117 [USCG-2008-0104] RIN 1625-AA-09 Drawbridge Operation Regulations; Atlantic Intracoastal Waterway (AIWW); Wrightsville Beach, NC AGENCY: Coast Guard, DHS. ACTION: Notice of temporary deviation from regulations. SUMMARY: The Commander, Fifth Coast Guard District, has issued a temporary deviation from the regulation governing the operation of the S.R. 74 Bridge, across the AIWW mile 283.1 at Wrightsville Beach, NC, to accommodate the annual race. DATES: This deviation is effective from 8 a.m. to 9:30 a.m. on March 15, 2008. ADDRESSES: Materials referred to in this document are available for inspection or copying at Commander (dpb), Fifth Coast Guard District, Federal Building, 1st Floor, 431 Crawford Street, Portsmouth, VA 23704-5004 between 8 a.m. and 4 p.m., Monday through Friday, except Federal holidays. The telephone number is
(757)398-6222. Commander (dpb), Fifth Coast Guard District maintains the public docket for this temporary deviation. FOR FURTHER INFORMATION CONTACT: Mr. Gary S. Heyer, Bridge Management Specialist, Fifth Coast Guard District, at
(757)398-6629. SUPPLEMENTARY INFORMATION: The S.R. 74 Bridge, a lift drawbridge, has a vertical clearance in the closed position to vessels of 20 feet, above mean high water. The North Carolina Department of Transportation (the bridge owner) requested a temporary deviation from the current operating regulation set out in 33 CFR 117.821(a)(5) to accommodate the Knights of Columbus Shamrock Fun Run and Walk scheduled for Saturday, March 15, 2008. The Coast Guard will inform the users of the waterway through our Local and Broadcast Notices to Mariners of the closure period for the bridge so that vessels can arrange their transits to minimize any impact caused by the temporary deviation. To facilitate the race, the S.R. 74 Bridge will be maintained in the closed-to-navigation position from 8 a.m. to 9:30 a.m. on March 15, 2008. In accordance with 33 CFR 117.35(e), the drawbridge must return to its regular operating schedule immediately at the end of the designated time period. This deviation from the operating regulations is authorized under 33 CFR 117.35. We analyzed this temporary deviation under Commandant Instruction M16475.lD and Department of Homeland Security Management Directive 5100.1, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969
(NEPA)(42 U.S.C. 4321-4370f). The environmental impact that this temporary deviation will have is minimal because the drawbridge being closed to vessels for a period of an hour and a half will not result in a change in functional use, or an impact on a historically significant element or setting. Dated: February 20, 2008. Waverly W. Gregory, Jr., Chief, Bridge Administration Branch, Fifth Coast Guard District. [FR Doc. E8-3834 Filed 2-28-08; 8:45 am] BILLING CODE 4910-15-P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 52 [EPA-R05-OAR-2007-0183; FRL-8535-1] Approval and Promulgation of Air Quality Implementation Plans; Illinois; Revisions to Emission Reduction Market System AGENCY: Environmental Protection Agency (EPA). ACTION: Withdrawal of direct final rule. SUMMARY: EPA is withdrawing the January 30, 2008 (73 FR 5435), direct final rule approving revisions to the State of Illinois' rules for its Emission Reduction Market System (ERMS). In the direct final rule, EPA commented on statements in and implications of a memorandum from Robert Meyers, Principal Deputy Assistant Administrator for Air and Radiation, to EPA's Regional Administrators dated October 3, 2007. (The rule gave an incorrect date of October 7, 2007.) The memorandum addresses the status of new source review criteria for ozone nonattainment areas based on a decision by the Court of Appeals for the DC Circuit in the case of South Coast *Air Quality Management Dist.* v. *EPA,* 472 F.3d 882 (DC Cir. 2006). In commenting upon the memorandum of Robert Meyers in the direct final rule of January 30, 2008, Region 5 unintentionally addressed an issue of national policy. As the issue is one of national policy, the implications of the Court ruling should only be addressed in national guidance and rulemaking. Notwithstanding our observations regarding the implications of the Robert Meyers memorandum, the rationale for proposing to approve the ERMS rule revisions did not rely on these observations, and so the soundness of EPA's proposal is not affected. Therefore, EPA is withdrawing the January 30, 2008, direct final rule, but announcing today that the associated proposed rule will stand as a proposed rule. (See 73 FR 5471). Comments on the proposed rule continue to be due on February 29, 2008. EPA will publish a revised final rule after considering any comments that it may receive. EPA will not institute a second comment period on this action. DATES: The direct final rule published at 73 FR 5435 on January 30, 2008, is withdrawn as of February 29, 2008. Comments on the proposed rule published at 73 FR 5471 on January 30, 2008, remain due on February 29, 2008. FOR FURTHER INFORMATION CONTACT: John Summerhays, Environmental Scientist, Criteria Pollutant Section, Air Programs Branch (AR-18J), Environmental Protection Agency, Region 5, 77 West Jackson Boulevard, Chicago, Illinois 60604,
(312)886-6067, *summerhays.john@epa.gov.* List of Subjects in 40 CFR Part 52 Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds. Authority: 42 U.S.C. 7401 *et seq.* Dated: February 21, 2008. Bharat Mathur, Acting Regional Administrator, Region 5. Accordingly, the amendments to 40 CFR 52.720 which published in the **Federal Register** on January 30, 2008 (72 FR 5435) on page 5439 are withdrawn as of February 29, 2008. [FR Doc. E8-3800 Filed 2-28-08; 8:45 am] BILLING CODE 6560-50-P DEPARTMENT OF HEALTH AND HUMAN SERVICES Centers for Medicare & Medicaid Services 42 CFR Parts 401 and 405 [CMS-4064-RCN] RIN 0938-AM73 Medicare Program; Changes to the Medicare Claims Appeal Procedures; Continuation of Effectiveness and Extension of Timeline for Publication of Final Rule AGENCY: Centers for Medicare & Medicaid Services (CMS), HHS. ACTION: Interim final rule; continuation of effectiveness and extension of timeline for publication of final rule. SUMMARY: This notice announces the continuation of effectiveness of a Medicare interim final and the extension of the timeline for publication of the final rule. This notice is issued in accordance with section 1871(a)(3)(C) of the Social Security Act (the Act), which allows an interim final rule to remain in effect after the expiration of the timeline specified in section 1871(a)(3)(B) of the Act if prior to the expiration of the timeline, the Secretary publishes in the **Federal Register** a notice of continuation and explains the exceptional circumstances justifying the extension of the timeline for publishing a final rule. DATES: *Effective Date:* February 29, 2008. FOR FURTHER INFORMATION CONTACT: David Danek,
(617)565-2682, or Arrah Tabe-Bedward,
(410)786-7129. SUPPLEMENTARY INFORMATION: I. Background Section 1871(a)(3)(A) of the Social Security Act (the Act) requires the Secretary, in consultation with the Director of the Office of Management and Budget (OMB), to establish and publish a regular timeline for the publication of a final rule based on the previous publication of a proposed rule or an interim final rule. In accordance with section 1871(a)(3)(B) of the Act, such regular timeline may vary among different regulations, based on the complexity of the rule, the number and scope of the comments received, and other relevant factors. The timeline for publishing the final regulation; however, cannot exceed 3 years from the date of publication of the proposed or interim final rule, unless there are exceptional circumstances. After consultation with the Director of OMB, we published a notice in the **Federal Register** on December 30, 2004 (69 FR 78442) establishing a general 3-year timeline for finalizing a Medicare proposed and an interim final rule. Section 1871(a)(3)(C) of the Act states that a Medicare interim final rule shall not continue in effect if the final rule is not published before the expiration of the regular timeline, unless the Secretary publishes at the end of the regular timeline a notice of continuation that includes an explanation of why the regular timeline was not met. Upon publication of such a notice, the timeline for publishing the final rule is extended for 1 year. II. Notice of Continuation Section 521 of the Medicare, Medicaid, and State Children's Health Insurance Program (SCHIP) Benefits Improvement and Protection Act of 2000 (BIPA), amended section 1869 of the Act to provide for significant changes to the Medicare claims appeal procedures. On November 15, 2002, we published in the **Federal Register** a proposed rule (67 FR 69312) consistent with Section 521 of BIPA. An interim final rule with comment implementing the BIPA provisions as well as further changes to the claim appeals procedures enacted in Title IX of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003
(MMA)appeared in the **Federal Register** in March 2005 (70 FR 11420). Under the previously established regular timeline for publication of a final rule, we must publish a final rule responding to public comments on the interim final rule with comment period no later than March 1, 2008. This notice announces an extension of the timeline for publication of the final rule and the continuation of effectiveness of the interim final rule with comment period. We are not able to meet the 3-year timeline for publication of the final rule due to the complexity of the rule and the need to ensure coordination with other government agencies. Specifically, the development of the final rule requires collaboration among other HHS agencies (that is, the Office of Medicare Hearings and Appeals (OMHA), and the Departmental Appeals Board (DAB), as well as extensive involvement from the HHS Office of the General Counsel). Although OMHA was not in existence when the interim final rule with comment period was published, OMHA is now a key component of the Medicare claims appeal process. We note that extensive coordination is needed to ensure that there is a mutual understanding of these provisions among all three affected administrative agencies. In addition, the development of the final rule requires significant coordination with other HHS policy related regulations (that is, the Provider Reimbursement Determinations and Appeals final rule and the Medicare Prescription Drug Appeals Process proposed rule (Part D proposed rule,)) which are currently under development. We believe that an extension of the publication timeline is necessary and appropriate to ensure that we are able to address all of the issues raised in response to the interim final. Therefore, this notice extends the timeline for publication of the final rule until March 1, 2009. In accordance with section 1871(a)(3)(C) of the Act, interim final rule shall remain in effect through March 1, 2009 (unless the final rule is published and becomes effective before March 1, 2009). (Catalog of Federal Domestic Assistance Program No. 93.773 Medicare—Hospital Insurance Program; and No. 93.774, Medicare—Supplementary Medical Insurance Program) Dated: February 25, 2008. Ann Agnew, Executive Secretary to the Department. [FR Doc. E8-3861 Filed 2-28-08; 8:45 am] BILLING CODE 4120-01-P DEPARTMENT OF HEALTH AND HUMAN SERVICES Centers for Medicare & Medicaid Services 42 CFR Part 488 [CMS-2278-IFC4] RIN 0938-AP22 Revisit User Fee Program for Medicare Survey and Certification Activities AGENCY: Centers for Medicare & Medicaid Services (CMS), HHS. ACTION: Interim final rule with comment period. SUMMARY: This interim final rule with comment period implements the continuation of the revisit user fee program for Medicare Survey and Certification activities, in accordance with the statutory authority in the Continuing Appropriations Resolution entitled, “Making further continuing appropriations for the fiscal year 2008, and for all other purposes,” Public Law 110-149 (“Continuing Resolution”) signed into law on December 21, 2007. On September 19, 2007, we published a final rule that established a system of revisit user fees applicable to health care facilities that have been cited for deficiencies during initial certification, recertification or substantiated complaint surveys and require a revisit to confirm that previously-identified deficiencies have been corrected. DATES: *Effective date:* These regulations are effective February 29, 2008, and applicable beginning December 21, 2007. *Comment date:* To be assured consideration, comments must be received at one of the addresses provided below, no later than 5 p.m. on April 29, 2008. ADDRESSES: In commenting, please refer to file code CMS-2278-IFC4. Because of staff and resource limitations, we cannot accept comments by facsimile
(FAX)transmission. You may submit comments in one of four ways (no duplicates, please): 1. *Electronically.* You may submit electronic comments on specific issues in this regulation to *http://www.cms.hhs.gov/eRulemaking.* Click on the link “Submit electronic comments on CMS regulations with an open comment period.” (Attachments should be in Microsoft Word, WordPerfect, or Excel; however, we prefer Microsoft Word.) 2. *By regular mail.* You may mail written comments (one original and two copies) to the following address ONLY: Centers for Medicare & Medicaid Services, Department of Health and Human Services, Attention: CMS-2278-IFC3, P.O. Box 8010, Baltimore, MD 21244-8016. Please allow sufficient time for mailed comments to be received before the close of the comment period. 3. *By express or overnight mail.* You may send written comments (one original and two copies) to the following address only: Centers for Medicare & Medicaid Services, Department of Health and Human Services, Attention: CMS-2278-IFC4, Mail Stop C4-26-05, 7500 Security Boulevard, Baltimore, MD 21244-1850. 4. *By hand or courier.* If you prefer, you may deliver (by hand or courier) your written comments (one original and two copies) before the close of the comment period to one of the following addresses. If you intend to deliver your comments to the Baltimore address, please call telephone number
(410)786-7195 in advance to schedule your arrival with one of our staff members: Room 445-G, Hubert H. Humphrey Building, 200 Independence Avenue, SW., Washington, DC 20201; or 7500 Security Boulevard, Baltimore, MD 21244-1850. (Because access to the interior of the HHH Building is not readily available to persons without Federal Government identification, commenters are encouraged to leave their comments in the CMS drop slots located in the main lobby of the building. A stamp-in clock is available for persons wishing to retain a proof of filing by stamping in and retaining an extra copy of the comments being filed.) Comments mailed to the addresses indicated as appropriate for hand or courier delivery may be delayed and received after the comment period. For information on viewing public comments, see the beginning of the SUPPLEMENTARY INFORMATION section. FOR FURTHER INFORMATION CONTACT: Kelley Tinsley,
(410)786-6664. SUPPLEMENTARY INFORMATION: *Submitting Comments:* As the public was provided an opportunity to comment on the substance of the rule during the comment period prior to the publication of the September 19, 2007 final rule, and as the substance of the rule is not changed by this interim final rule with comment period, we are accepting comments only to the extent that they pertain to the applicability of the new authority for the rule. You can assist us by referencing the file code CMS-2278-IFC3. *Inspection of Public Comments:* All comments received before the close of the comment period are available for viewing by the public, including any personally identifiable or confidential business information that is included in a comment. We post all comments received before the close of the comment period on the following Web site as soon as possible after they have been received: *http://www.cms.hhs.gov/eRulemaking.* Click on the link “Electronic Comments on CMS Regulations” on that Web site to view public comments. Comments received timely will be available for public inspection as they are received, generally beginning approximately three weeks after publication of a document, at the headquarters of the Centers for Medicare & Medicaid Services, 7500 Security Boulevard, Baltimore, Maryland 21244, Monday through Friday of each week from 8:30 a.m. to 4 p.m. To schedule an appointment to view public comments, phone 1-800-743-3951. SUPPLEMENTARY INFORMATION: I. Background In the June 29, 2007 **Federal Register** (72 FR 35673), we published the proposed rule entitled, “Establishment of Revisit User Fee Program for Medicare Survey and Certification Activities” and provided for a 60-day comment period. In the September 19, 2007 **Federal Register** (72 FR 53628) we published the Revisit User Fee Program final rule. That final rule set forth final requirements and a final fee schedule for providers and suppliers who require a revisit survey as a result of deficiencies cited during an initial certification, recertification, or substantiated complaint survey. The Centers for Medicare & Medicaid Services
(CMS)has in place an outcome-oriented survey process that is designed to ensure that existing Medicare-certified providers and suppliers or providers and suppliers seeking initial Medicare certification, meet statutory and regulatory requirements, conditions of participation, or conditions for coverage. These health and safety requirements apply to the environments of care and the delivery of services to residents or patients served by these facilities and agencies. The Secretary of the Department of Health and Human Services
(HHS)has designated CMS to enforce the conditions of participation/coverage and other requirements of the Medicare program. The revisit user fee will be assessed for revisits conducted in order to determine whether deficiencies cited as a result of failing to satisfy federal quality of care requirements have been corrected. Pursuant to the requirements of the Continuing Appropriations Resolution budget bill for fiscal year
(FY)2007, the Secretary directed CMS to implement the revisit user fees for FY 2007 for certain providers and suppliers for which a revisit was required to confirm that previously-identified failures to meet federal quality of care requirements had been remedied. The fees recover the costs associated with the Medicare Survey and Certification program's revisit surveys. The primary purpose for implementing the revisit user fees is to ensure the continuance of CMS Survey and Certification quality assurance activities that improve patient care and safety. The fees became effective upon publication September 19, 2007, when the final rule was published. II. Provisions of the Interim Final Rule The current Continuing Resolution Public Law 110-149, amends Public Law 110-92 Division B by striking the date specified in section 106(3) and inserting ‘December 31, 2007’. The current Continuing Resolution authorizes HHS to continue to impose revisit user fees until December 31, 2007, as follows: Sec. 101. Such amounts as may be necessary, at a rate for operations as provided in the applicable appropriations Acts for fiscal year 2007 and under the authority and conditions provided in such Acts, for continuing projects or activities (including the costs of direct loans and loan guarantees) that are not otherwise specifically provided for in this joint resolution, that were conducted in fiscal year 2007, and for which appropriations, funds, or other authority were made available in the following appropriations Acts:
(3)The Continuing Appropriations Resolution, 2007 (division B of Public Law 109-289, as amended by Public Law 110-5). *(H.J. Res. 20, § 101 (2007)).* Sec. 106. Unless otherwise provided for in this joint resolution or in the applicable appropriations Act for fiscal year 2008, appropriations and funds made available and authority granted pursuant to this joint resolution shall be available until whichever of the following first occurs:
(3)December 31, 2007. As directed by the Secretary, in the September 19, 2007 **Federal Register** (72 FR 53628), we established the revisit user fee program for revisit surveys. We put forth in regulation the relevant definitions, criteria for determining the fees, the fee schedule, procedures for the collection of fees, the reconsideration process, enforcement and regulatory language addressing enrollment and billing privileges, and provider agreements. In the September 19, 2007 final rule, cost projections were based on FY 2006 actual data and were expected to amount to $37.3 million for FY 2007. These calculations were included in section IV of the final rule (72 FR 53642). We stated in the final rule that, “if authority for the revisit user fee is continued, we will use the current fee schedule in [the final rule] for the assessment of such fees until such time as a new fee schedule notice is proposed and published in final form.” (72 FR 53628). The current Continuing Resolution continues the authority of the FY 2007 Continuing Resolution from December 21, 2007 through December 31, 2007. Due to the enactment of the Consolidated Appropriations Act, 2008, on December 26, 2007, the current Continuing Resolution will cease to be effective on December 26, 2007. The authority of the Consolidated Appropriations Act supersedes that of the current Continuing Resolution, therefore ending its effective date the day on which the Appropriations Act was signed. Accordingly, the revisit fees will continue to be assessed for the 5-day time period authorized by the current Continuing Resolution to begin December 21, 2007, and ending on the day the Consolidated Appropriations Act was signed by the President, December 26, 2007. III. Response to Comments Because of the large number of public comments we normally receive on **Federal Register** documents, we are not always able to acknowledge or respond to all of them individually. We will consider all comments we receive by the date and time specified in the DATES section of this preamble, and, when we proceed with a subsequent document, we will respond to the comments in the preamble to that document. IV. Waiver of Proposed Rulemaking and Delay in Effective Date We ordinarily publish a notice of proposed rulemaking in the **Federal Register** and invite public comment on the proposed rule in accordance with *5 U.S.C. 553*
(b)of the Administrative Procedure Act (APA). The notice of proposed rulemaking includes a reference to the legal authority under which the rule is proposed, and the terms and substance of the proposed rule or a description of the subjects and issues involved. This procedure can be waived, however, if an agency finds good cause that a notice-and-comment procedure is impracticable, unnecessary, or contrary to the public interest and incorporates a statement of the finding and its reasons in the rule issued. We find that the notice-and-comment procedure is unnecessary in this circumstance because providers and suppliers have already been provided notice and an opportunity to comment on the substance of this rule. This interim final rule with comment merely updates the Congressional authority under which the rule operates. Therefore, we find good cause to waive the notice of proposed rulemaking and to issue this final rule on an interim basis. We are providing a 60-day public comment period. We ordinarily provide a 30-day delay in the effective date of the provisions of a rule in accordance with the Administrative Procedure Act (APA), 5 U.S.C. 553(d). However, the delay in the effective date may be waived as, in pertinent part, “provided by the agency for good cause found and published with the rule.” 5 U.S.C. 553(d)(3). The Secretary finds that good cause exists to waive the 30-day effective date delay. The good cause exception to the 30-day effective date delay provision of section 553(d) of the APA is read to be broader than the good cause exception to the notice and comment provision of section 553(b) of the APA. The legislative history of the APA indicates that the purpose for deferring the effectiveness of a rule under section 553(d) was to “afford persons affected a reasonable time to prepare for the effective date of a rule or rules or to take other action which the issuance may prompt.” S. Rep. No. 752, 79th Cong., 1st Sess. 15 (1946); H.R. Rep. No. 1980, 79th Cong. 2d Sess. 25 (1946). In this case, affected parties do not need time to adjust their behavior before this rule takes effect. This rule merely updates the authority under which the revisit fee is assessed and does not provide any additional requirements for the affected parties. Moreover, with or without a revisit fee, a provider or supplier must be found to have corrected significant deficiencies in order to avoid termination. Additionally, the application of a fee for the revisit does not place appreciable administrative burdens on the affected providers or suppliers. We do not expect appreciable cost to State survey agencies because we are undertaking the billing and collection of the revisit user fee. We identified in the September 19, 2007 final rule the immediacy of this revisit user fee program and the specific statutory requirement contained limited in the Continuing Resolution that required us to implement the revisit user fee program in FY 2007. Accordingly, providers and suppliers have been on notice for some time that these fees will be imposed, and do not need additional time to be prepared to comply with the requirements of this regulation. We believe that given the short timeframe that we have to collect fees before the statutory authority of the current Continuing Resolution expires, there is good cause to waive the 30-day effective date. V. Collection of Information Requirements This document does not impose information collection and recordkeeping requirements. Consequently, it need not be reviewed by the Office of Management and Budget under the authority of the Paperwork Reduction Act of 1995. VI. Regulatory Impact Analysis A. Overall Impact We have examined the impacts of this rule as required by Executive Order 12866 (September 1993, Regulatory Planning and Review), the Regulatory Flexibility Act
(RFA)(September 19, 1980, Pub. L. 96-354), section 1102(b) of the Social Security Act, the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4), and Executive Order 13132. Executive Order 12866 (as amended by Executive Order 13258, which merely reassigns responsibility of duties) directs agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). A regulatory impact analysis
(RIA)must be prepared for major rules with economically significant effects ($100 million or more in any one year). This rule is not a major rule. The aggregate costs will total approximately $37.3 million in any 1 year. The RFA requires agencies to analyze options for regulatory relief of small businesses. For purposes of the RFA, small entities include small businesses, nonprofit organizations, and small governmental jurisdictions. Individuals and States are not included in the definition of a small entity. Small businesses are small entities, either by nonprofit status or by having revenues of $6.5 million to $31.9 million or less in any one year for purposes of the RFA. The September 19, 2007 final rule provided an analysis on the impact of small entities (72 FR 53642-3). The analysis published in the final rule remains valid. Since this interim final rule with comment merely updates the Congressional authority under which the rule operates, we have determined that this rule will not have a significant impact on small entities based on the overall effect on revenues. Section 1102(b) of the Act requires us to prepare a regulatory impact analysis if a rule may have a significant impact on the operations of a substantial number of small rural hospitals. This analysis must conform to the provisions of section 604 of the RFA. For purposes of section 1102(b) of the Act, we define a small rural hospital as a hospital that is located outside of a Metropolitan Statistical Area (superseded by Core Based Statistical Areas) and has fewer than 100 beds. This rule affects those small rural hospitals that have been cited for a deficiency based on noncompliance with required conditions of participation and for which a revisit is needed to ensure that the deficiency has been corrected. We identified in the September 19, 2007 final rule that for the effective period of that rule that less than 3 percent of all hospitals may be assessed a revisit user fee and that less than 1 percent of those hospitals would be rural hospitals (72 FR 53643). The analysis published in the final rule remains valid. Since this interim final rule with comment merely updates the Congressional authority under which the rule operates, we maintain that this rule will not have a significant impact on small rural hospitals. Section 202 of the Unfunded Mandates Reform Act of 1995 also requires that agencies assess anticipated costs and benefits before issuing any rule whose mandates require spending in any one year of $100 million in 1995 dollars, updated annually for inflation. That threshold level is currently approximately $120 million. This interim final rule with comment will have no mandated effect on State, local, or tribal governments and the impact on the private sector is estimated to be less than $120 million and will only affect those Medicare providers or suppliers for which a revisit user fee is assessed based on the need to conduct a revisit survey to ensure deficient practices that were cited have been corrected. Executive Order 13132 establishes certain requirements that an agency must meet when it promulgates a proposed rule (and subsequent final rule) that imposes substantial direct requirement costs on State and local governments, preempts State law, or otherwise has Federalism implications. This interim final rule with comment will not substantially affect State or local governments. This rule establishes user fees for providers and suppliers for which CMS has identified deficient practices and requires a revisit to assure that corrections have been made. Therefore, we have determined that this interim final rule with comment will not have a significant effect on the rights, roles, and responsibilities of State or local governments. B. Impact on Providers/Suppliers There is no change on the impact on providers and suppliers with the publication of this interim final rule with comment. The impact remains as discussed in the final rule (72 FR 53643). Final Fee Schedule for Onsite and Offsite Revisit Surveys The FY 2007 fee schedule published on September 19, 2007 (72 FR 53647) in the final rule will be retained. As noted in the final rule, the published fee schedule will be used by CMS for the assessment of fees until a new fee schedule is proposed and published in final form. The calculations used to determine the fee as identified in the final rule will be the same (72 FR 53645-6). We will continue to assess a flat fee based on provider or supplier type and type of revisit survey conducted. Table A below identifies the final fee schedule. Table A.—Final Fee Schedule Facility Fee assessed per offsite revisit survey Fee assessed per onsite revisit survey SNF & NF $168 $2,072 Hospitals 168 2,554 HHA 168 1,613 Hospice 168 1,736 ASC 168 1,669 RHC 168 851 ESRD 168 1,490 Costs for All Revisit User Fees Assessed We anticipated that the combined costs for all providers and suppliers for all revisit surveys in FY 2007 would total approximately $37.3 million on an annual basis, with onsite revisit surveys amounting to approximately $34.6 million and offsite revisit surveys totaling approximately $2.7 million. (72 FR 53645). However, actual fees assessed in FY 2007 were much less than this amount, since CMS did not charge for revisits that occurred prior to publication of the final regulation. Since we continue to operate under this same estimate for FY 07, we provide below monthly estimates of the impact for the period of the current Continuing Resolution in Tables B and C. For the period of the current Continuing Resolution, we will use the FY 2007 fee schedule established in the final rule for the assessment of fees until a new fee schedule notice is proposed and published as final. In Table B below, we provide the projected costs for the period of this current Continuing Resolution based on the fee schedule of the final rule. We expect the combined costs for all providers and suppliers for all onsite revisit surveys for the period of this current Continuing Resolution to total approximately $473,503 thousand. We first multiplied the total number of onsite revisit surveys in one year by the expected revisit user fees assessed per revisits as finalized in Table A above, estimated by provider or supplier, to obtain the annual cost of revisit surveys. We then divided this number by 365 to obtain the daily cost per provider or supplier of onsite revisit surveys. To obtain the total costs for onsite revisit surveys for the effective period of the current Continuing Resolution (5 days), we then took the daily cost and multiplied it by 5. Finally, to achieve the total costs for all onsite revisit surveys for the period of this current Continuing Resolution, we totaled all providers and suppliers. Table B.—Onsite Revisit Surveys—Estimated 5 Day Costs Facility Number of onsite revisit surveys (FY 2006) Fee assessed per onsite revisit surveys (hrs × $112) Number of onsite revisit surveys est. for 5 days* 5 day costs for onsite revisit surveys** SNF & NF 14,288 $2,072 198 $ 405,544 Hospitals 575 2,554 8 20,117 HHA 1,068 1,613 15 23,598 Hospice 256 1,736 4 6,087 ASC 95 1,669 1 2,171 RHC 149 851 2 1,737 ESRD 698 1,490 10 14,246 Total 17,129 238 473,500 * Estimated total numbers of onsite revisit surveys for 5 days were rounded up after dividing yearly survey totals from FY 2006 actual data by 365 and multiplying that number by 5. ** 5 day costs may differ from the multiple of 5 day revisits and fee per revisit due to rounding. We expect the combined costs for all providers and suppliers for all offsite revisit surveys to total $37,684 for the period of the current Continuing Resolution. In Table C below, we first estimated by provider or supplier the number of offsite revisit surveys expected for an entire fiscal year, and multiplied this number by the expected revisit user fee of $168 per offsite revisit survey to obtain the annual cost of surveys. We then divided this number by 365 to obtain the daily cost of offsite revisit surveys. To obtain the total costs for offsite revisit surveys for the period of the current Continuing Resolution (5 days), we then took the daily cost and multiplied it by 5. Finally, to achieve the total costs for all offsite revisit surveys for the period of this current Continuing Resolution, we totaled all providers and suppliers. Table C.—Offsite Revisit Surveys—Estimated 5 Day Costs Facility Number of offsite revisit surveys (FY 2006) Fee assessed per offsite revisit survey ($112 × 1.5 hrs) Number of offsite revisit surveys est. for 5 days* 5 day costs for offsite revisit surveys** SNF & NF 15,138 $168 207 $34,838 Hospitals 278 168 4 640 HHA 517 168 1 1,190 Hospice 51 168 1 117 ASC 93 168 1 214 RHC 67 168 1 154 ESRD 231 168 3 531 Total 16,375 224 37,684 * Estimated total numbers of offsite revisit surveys for 5 days were rounded up after dividing yearly survey totals from FY 2006 actual data by 365 and multiplying that number by 5. ** 5 day costs may differ from the multiple of 5 day revisits and fee per revisit due to rounding. As shown in Table D below, we provide the aggregate costs expected as projected for the entire FY 2007, as well as the costs we would expect to offset for the period of the current Continuing Resolution. Table D.—Total Costs Combined for All Revisits Surveys per Fiscal Year & Period of CR FY 2007 Period of CR* Onsite Revisit Surveys $34,565,760 $473,503 Offsite Revisit Surveys 2,751,000 37,684 Total Costs All Revisits 37,316,760 511,187 * CR period's costs are based on CR period revisit surveys rounded up to the nearest whole number as shown in Tables B & C. E. Alternatives Considered We considered a number of alternatives to the revisit user fee program. Such alternatives were discussed in the final rule published on September 19, 2007 (72 FR 53647). We affirm the continuing validity of that analysis. The current Continuing Resolution provides CMS with the authority to continue projects or activities as was otherwise provided for in FY 2007, and as such CMS is required to publish an interim final rule with comment. This interim final rule with comment merely updates the Congressional authority under which the rule operates. In accordance with Executive Order 12866, this rule was not reviewed by the Office of Management and Budget. List of Subjects in 42 CFR Part 488 Administrative practice and procedure, Health facilities, Medicare, Reporting and recording requirements. For the reasons set forth in the preamble, the Centers for Medicare & Medicaid Services amends 42 CFR chapter IV, part 488 as set forth below: PART 488—SURVEY, CERTIFICATION, AND ENFORCEMENT PROCEDURES 1. The authority citation for part 488 is revised to read as follows: Authority: Secs. 1102 and 1871 of the Social Security Act, unless otherwise noted (42 U.S.C. 1302 and 1395(hh)); Continuing Resolution Pub. L. 110-149 H.J. Res. 72. (Catalog of Federal Domestic Assistance Program No. 93.778, Medical Assistance Program) (Catalog of Federal Domestic Assistance Program No. 93.773, Medicare—Hospital Insurance; and Program No. 93.774, Medicare—Supplementary Medical Insurance Program) Dated: January 30, 2008. Kerry Weems, Acting Administrator, Centers for Medicare & Medicaid Services. Approved: February 14, 2008. Michael O. Leavitt, Secretary. [FR Doc. E8-3830 Filed 2-28-08; 8:45 am] BILLING CODE 4120-01-P FEDERAL COMMUNICATIONS COMMISSION 47 CFR Part 76 [MM Docket No. 92-264; FCC 07-219] The Commission's Cable Horizontal and Vertical Ownership Limits AGENCY: Federal Communications Commission. ACTION: Final rule. SUMMARY: This document adopts a rule prohibiting cable operators from owning or having an attributable interest in cable systems serving more than 30 percent of multichannel video programming subscribers nationwide. It also eliminates the overbuilder exception, which allowed cable operators to count against its horizontal limit only those cable subscribers served by its “incumbent cable franchises” and excluding new subscribers gained through overbuilding “non-incumbent cable systems. Elimination of the exception prevents a cable operator near the horizontal limit from using the exception to exceed the 30 percent limit and thereby reduce the open field below the 70 percent necessary to ensure that no single operator can, by simply refusing to carry a video network, cause it to fail. The revised rule balances the need to ensure that cable operators cannot use their dominant position in the multichannel video programming distribution
(MVPD)market to impede unfairly the flow of video programming to consumers with consideration of the efficiencies and other benefits that might be gained through increased ownership or control. DATES: Effective March 31, 2008. FOR FURTHER INFORMATION CONTACT: Elvis Stumbergs,
(202)418-7878; Mania Baghdadi,
(202)418-2330. SUPPLEMENTARY INFORMATION: This is a summary of the Federal Communications Commission's *Fourth Report and Order* in MB Docket No. 92-264, FCC 07-219, adopted December 18, 2007, and released February 11, 2008. The full text of this document is available for public inspection and copying during regular business hours in the FCC Reference Center, Federal Communications Commission, 445 12th Street, SW., CY-A257, Washington, DC 20554. These documents will also be available via ECFS ( *http://www.fcc.gov/cgb/ecfs* ). The complete text may be purchased from the Commission's copy contractor, 445 12th Street, SW., Room CY-B402, Washington, DC 20554. To request this document in accessible formats (computer diskettes, large print, audio recording and Braille), send an e-mail to *fcc504@fcc.gov* or call the FCC's Consumer and Governmental Affairs Bureau at
(202)418-0530 (voice)
(202)418-0432 (TTY). Summary of the Report and Order 1. This *Order* was adopted pursuant to Section 613(f)(1)(A) of the Telecommunications Act of 1996 (“1996 Act”), which requires the Commission to prescribe rules and regulations establishing reasonable limits on the number of cable subscribers a person is authorized to reach through cable systems owned by such person, or in which such person has an attributable interest, and to respond to the concerns of the United States Court of Appeals for the District of Columbia Circuit in *Time Warner Entertainment Co.* v. *FCC* (“ *Time Warner II* ”) that the Commission had failed adequately to justify the 30 percent limit. 2. The court in *Time Warner II* held that Section 613(f) authorizes the Commission to set a limit to ensure that no single company could be in a position single-handedly to deal a programmer a death blow but does not authorize the agency to regulate the legitimate, independent editorial choices of multiple MSOs and further found that the Commission lacked evidence that cable operators would collude and that the Commission could not simply assume that cable operators would coordinate their behavior in an anticompetitive manner. 3. The *Report and Order* establishes a 30% cable horizontal ownership limit by relying on a modified “open field” approach to ensure that no single cable operator becomes so large that a programming network can survive only if that operator carries it and eliminates the overbuilder exception to the calculation of the limit. 4. The Commission considered comments it had received relative to three possible approaches to use in fashioning a horizontal ownership limit:
(1)The open field approach, which examines whether one or more cable operators are large enough to effectively limit the viability of a programming network if they denied it carriage;
(2)monopsony theory, which considers whether a cable operator has sufficient market power to restrict the price it pays for programming by purchasing less of it and thereby restrict the flow of programming to subscribers; and
(3)bargaining theory, which examines the negotiations between the programming network and the cable operator in order to determine the point at which programmers will curtail their activities and thereby limit the quality and diversity of programming. 5. We determine that the open field approach, suitably modified, represents the best method of determining an appropriate horizontal limit. We determine that monopsony theory does not apply to this market because of the lack of a single market price in the market for programming. Although we find that bargaining theory is useful in establishing the need for a limit, the record is insufficient to derive a specific limit using this theory. 6. The open field approach determines whether a programming network would have access to alternative MVPDs of sufficient size to allow it to successfully enter the market, if it were denied carriage by one or more of the largest cable operators. 7. To calculate a horizontal limit that meets this test, we first determine the minimum number of subscribers a network needs in order to survive in the marketplace and then estimate the percentage of subscribers a network is likely to serve once it secures a carriage contract. The resulting calculation indicates that an open field of 70 percent and an ownership limit of 30 percent are necessary to ensure that no single cable operator is able to impede unfairly the flow of programming to consumers. 8. The Commission eliminated the overbuilder exception, which allowed counting against a cable operator's horizontal limit only those cable subscribers served by its “incumbent cable franchises,” excluding new subscribers gained through overbuilding “non-incumbent cable systems and concluded that elimination of the exception was necessary to prevent a cable operator near the horizontal limit to use the exception to exceed the 30 percent limit, which would have the effect of reducing the open field below the 70 percent that is necessary to ensure that no single operator can, by simply refusing to carry a video network, cause it to fail. 9. The revised rule balances the need to ensure that cable operators cannot use their dominant position in the multichannel video programming distribution
(MVPD)market to impede unfairly the flow of video programming to consumers with consideration of the efficiencies and other benefits that might be gained through increased ownership or control. 10. The Commission further clarifies 76.503(g) of its rules which requires any cable operator serving 20 percent or more of nationwide MVPD subscribers to certify prior to acquiring additional MVPDs that no violation of the horizontal ownership limit will occur as a result of its acquisition, but does not prescribe a particular form of certification. We clarify in the *Report and Order* that certifications must be executed by an officer of the corporation and must state that the number of attributable subscribers served by the applicant is reported accurately in the certification. If this number varies from subscriber counts the cable operator has provided to other government agencies, financial institutions, or third-party publishers of industry-wide subscriber data, the certification shall disclose and explain the nature of such discrepancies. The Commission will consider specific allegations of misrepresentation on a case-by-case basis. Fourth Report and Order Paperwork Reduction Act Analysis 11. This document does not contain new or modified information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA), Public Law 104-13. In addition, therefore, it does not contain any new or modified “information collection burden for small business concerns with fewer than 25 employees,” pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107-198, *see* 44 U.S.C. 3506(c)(4). 12. *Congressional Review Act.* The Commission will send a copy of this Fourth Report and Order in a report to be sent to Congress and the Government Accountability Office, pursuant to the Congressional Review Act. 13. *Final Regulatory Flexibility Analysis.* As required by the Regulatory Flexibility Act of 1980, as amended (RFA), an Initial Regulatory Flexibility Analysis
(IRFA)was incorporated in the *2005 Second FNPRM* in MB Docket No. 92-264, FCC 05-96. The Commission sought written public comment on the proposals in the *2005 Second FNPRM* including comment on the IRFA. This present Final Regulatory Flexibility Analysis
(FRFA)conforms to the RFA. A. Need for, and Objectives of, This Fourth Report and Order 14. In this Fourth Report and Order, we set the Commission's cable horizontal ownership limit to bar cable operators from having an attributable interest in cable systems serving more than 30 percent of multichannel video programming subscribers nationwide. Our action here responds to the court's decision in *Time Warner Entertainment Co.* v. *FCC* (“ *Time Warner II* ”), which remanded the Commission's 30 percent limit. Our decision implements the statutory directive that we impose a limit designed to ensure that no single cable operator or group of operators, because of their size, unfairly impede the flow of programming to consumers. 15. In establishing the 30 percent cable horizontal ownership limit, we rely on a modified “open field” approach to ensure that no single cable operator becomes so large that a programming network can survive only if that largest operator carries it. To calculate a horizontal limit that meets this test, we first determine the minimum number of subscribers a network needs in order to survive in the marketplace, and then estimate the percentage of subscribers a network is likely to serve once it secures a carriage contract. The resulting calculation indicates that an open field of 70 percent and an ownership limit of 30 percent are necessary to ensure that no single cable operator is able to impede unfairly the flow of programming to consumers. B. Summary of Significant Issues Raised by Public Comments in Response to the IRFA 16. None of the parties in this proceeding filed comments on how issues raised in the 2001 FNPRM or the 2005 Second FNPRM would impact small entities. C. Description and Estimate of the Number of Small Entities to Which the Rule Will Apply 17. The RFA directs agencies to provide a description of, and, where feasible, an estimate of, the number of small entities that may be affected by the rules adopted herein. The RFA generally defines the term “small entity” as having the same meaning as the terms “small business,” “small organization,” and “small governmental jurisdiction.” In addition, the term “small business” has the same meaning as the term “small business concern” under the Small Business Act. A “small business concern” is one which:
(1)Is independently owned and operated;
(2)is not dominant in its field of operation; and
(3)satisfies any additional criteria established by the Small Business Administration (SBA). 18. *Cable and Other Program Distribution* . The Census Bureau recently updated the NAICS so that these firms are included in the Wired Telecommunications Carriers category which is described as follows: “This industry comprises establishments primarily engaged in operating and/or providing access to transmission facilities and infrastructure that they own and/or lease for the transmission of voice, data, text, sound, and video using wired telecommunications networks. Transmission facilities may be based on a single technology or a combination of technologies. Establishments in this industry use the wired telecommunications network facilities that they operate to provide a variety of services, such as wired telephony services, including VoIP services; wired (cable) audio and video programming distribution; and wired broadband Internet services. By exception, establishments providing satellite television distribution services using facilities and infrastructure that they operate are included in this industry.” The SBA has updated the small business size standards to accord with the revised NAICS. The size standard for Wired Telecommunications Carriers is all firms having an average of 1,500 or fewer employees. The Census Bureau has not collected information on the size distribution of firms in the revised classification of Wired Telecommunications Carriers. Accordingly we will apply the new size standard to Census Bureau data for 2002 regarding the size distribution of Cable and Other Program Distribution. There were a total of 1,191 firms in this category that operated for the entire year. Of this total, 1,178 firms had fewer than 1,000 employees. Thus, under this size standard, the majority of firms can be considered small. 19. *Cable System Operators* . The Communications Act of 1934, as amended, also contains a size standard for small cable system operators, which is “a cable operator that, directly or through an affiliate, serves in the aggregate fewer than 1 percent of all subscribers in the United States and is not affiliated with any entity or entities whose gross annual revenues in the aggregate exceed $250,000,000.” The Commission has determined that an operator serving fewer than 653,000 subscribers shall be deemed a small operator, if its annual revenues, when combined with the total annual revenues of all its affiliates, do not exceed $250 million in the aggregate. Industry data indicate that, of 994 cable operators nationwide, all but thirteen are small under this size standard. We note that the Commission neither requests nor collects information on whether cable system operators are affiliated with entities whose gross annual revenues exceed $250 million, and therefore we are unable to estimate more accurately the number of cable system operators that would qualify as small under this size standard. 20. *Private Cable Operators
(PCOs)also known as Satellite Master Antenna Television (SMATV) Systems* . PCOs, also known as SMATV systems or private communication operators, are video distribution facilities that use closed transmission paths without using any public right-of-way. PCOs acquire video programming and distribute it via terrestrial wiring in urban and suburban multiple dwelling units such as apartments and condominiums, and commercial multiple tenant units such as hotels and office buildings. The SBA definition of small entities for Wired Telecommunications Carriers includes PCOs or SMATV systems and, thus, small entities are defined as all such companies with 1,500 or fewer employees. Currently, there are approximately 76 members in the Independent Multi-Family Communications Council (IMCC), the trade association that represents PCOs. Individual PCOs often serve approximately 3,000-4,000 subscribers, but the larger operations serve as many as 15,000-55,000 subscribers. In total, PCOs currently serve approximately 900,000 subscribers. Because these operators are not rate regulated, they are not required to file employment data with the Commission. Furthermore, we are not aware of any privately published employment information regarding these operators. Based on the estimated number of operators and the estimated number of units served by the largest ten PCOs, we believe that a substantial number of PCO may qualify as small entities. D. Description of Projected Reporting, Recordkeeping, and Other Compliance Requirements 21. The new rule imposes a 30 percent limit on the number of MVPD subscribers nationwide that one person or entity may serve. No new reporting, recordkeeping or other compliance requirements are adopted. E. Steps Taken To Minimize Significant Economic Impact on Small Entities, and Significant Alternatives Considered 22. The RFA requires an agency to describe any significant alternatives that it has considered in developing its approach, which may include the following four alternatives (among others): “(1) The establishment of differing compliance or reporting requirements or timetables that take into account the resources available to small entities;
(2)the clarification, consolidation, or simplification of compliance and reporting requirements under the rule for such small entities;
(3)the use of performance rather than design standards; and
(4)an exemption from coverage of the rule, or any part thereof, for such small entities.” 23. In this *Fourth Report and Order* , based on its calculations using an open field approach, the Commission sets a 30 percent horizontal ownership limit. This rule limits the size of large MSOs and does not prevent small cable operators from growing larger. We also continue to base the limit on the number of actual MVPD subscribers, a figure used by cable operators when they negotiate with and purchase programming from video programmers. *See Id* . Finally, the horizontal cap would not change pursuant to the *Order* . Accordingly, we do not find that the *Order* will impose new burdens on small cable operators. 24. The Commission considered other alternatives, with respect to the horizontal limit, but the *Order* adopted a 30 percent horizontal ownership limit based on evidence that this is the level necessary to preserve programmer viability. The Commission believes that the decisions it adopts in the Order serve our public interest goals and comport with the evidence. F. Report to Congress 25. The Commission will send a copy of the *Fourth Report and Order* , including this Supplemental FRFA, in a report to be sent to Congress pursuant to the Congressional Review Act. In addition, the Commission will send a copy of the *Fourth Report and Order* , including this Supplemental FRFA, to the Chief Counsel for the advocacy of the SBA. A copy of the *Fourth Report and Order* and the Supplemental FRFA (or summaries thereof) will also be published in the **Federal Register** . List of Subjects in 47 CFR Part 76 Multichannel video and Cable television service. Federal Communications Commission. Marlene H. Dortch, Secretary. Rule Changes For the reasons discussed in the preamble, the Federal Communications Commission amends 47 CFR part 76 as follows: PART 76—MULTICHANNEL VIDEO AND CABLE TELEVISION SERVICE 1. The authority citations for part 76 continue to read as follows: Authority: 47 U.S.C. 152(a), 154(i), 303, 307, 309, 310, 533. 2. Amend § 76.503 by revising paragraph
(a)and by removing and reserving paragraphs (b),
(c)and
(d)as follows: § 76.503 National subscriber limits.
(a)No cable operator shall serve more than 30 percent of all multichannel-video programming subscribers nationwide through multichannel video programming distributors owned by such operator or in which such cable operator holds an attributable interest. [FR Doc. E8-3700 Filed 2-28-08; 8:45 am BILLING CODE 6712-01-P DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration 50 CFR Part 622 [Docket No. 0612243157-7799-07] RIN 0648-AT87 Fisheries of the Caribbean, Gulf of Mexico, and South Atlantic; Reef Fish Fishery and Shrimp Fishery of the Gulf of Mexico; Amendment 27/14; Correction AGENCY: National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce. ACTION: Final rule; correction. SUMMARY: This document contains a correction to the final rule to implement joint Amendment 27 to the Fishery Management Plan for the Reef Fish Resources of the Gulf of Mexico and Amendment 14 to the Fishery Management Plan for the Shrimp Fishery of the Gulf of Mexico (Amendment 27/14) that was published in the **Federal Register** Tuesday, January 29, 2008. DATES: This correction is effective February 28, 2008. FOR FURTHER INFORMATION CONTACT: Anik Clemens, 727-824-5305; fax: 727-824-5308; e-mail: *Anik.Clemens@noaa.gov* . SUPPLEMENTARY INFORMATION: The final rule that is the subject of this correction was published Tuesday, January 29, 2008 (73 FR 5117). That final rule contains an error in the regulatory text. In § 622.37, paragraph (d)(1)(iv), the conversion of 13 inches to 38.1 cm is incorrect. The correct conversion is 33.0 cm. All other information remains unchanged and will not be repeated in this correction. Correction On page 5128, in the first column, in § 622.37(d)(1)(iv), “13 inches (38.1 cm)” should read “13 inches (33.0 cm)”. Authority: 16 U.S.C. 1801 *et seq.* Dated: February 22, 2008. John Oliver, Deputy Assistant Administrator for Operations, National Marine Fisheries Service. [FR Doc. E8-3840 Filed 2-28-08; 8:45 am] BILLING CODE 3510-22-S DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration 50 CFR Part 679 [Docket No. 070213032-7032-01] RIN 0648-XF93 Fisheries of the Exclusive Economic Zone Off Alaska; Pacific Cod by Non-American Fisheries Act Crab Vessels Catching Pacific Cod for Processing by the Offshore Component in the Central Regulatory Area of the Gulf of Alaska AGENCY: National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce. ACTION: Temporary rule; closure. SUMMARY: NMFS is prohibiting directed fishing for the A season allowance of the 2008 Pacific cod sideboard limits apportioned to non-American Fisheries Act
(AFA)crab vessels catching Pacific cod for processing by the offshore component in the Central Regulatory Area of the Gulf of Alaska (GOA). This action is necessary to prevent exceeding the A season allowance of the 2008 Pacific cod sideboard limits apportioned to non-AFA crab vessels catching Pacific cod for processing by the offshore component in the Central Regulatory Area of the GOA. DATES: Effective 1200 hrs, Alaska local time (A.l.t.), February 26, 2008, until 1200 hrs, A.l.t., September 1, 2008. FOR FURTHER INFORMATION CONTACT: Jennifer Hogan, 907-586-7228. SUPPLEMENTARY INFORMATION: NMFS manages the groundfish fishery in the GOA exclusive economic zone according to the Fishery Management Plan for Groundfish of the Gulf of Alaska
(FMP)prepared by the North Pacific Fishery Management Council under authority of the Magnuson-Stevens Fishery Conservation and Management Act. Regulations governing fishing by U.S. vessels in accordance with the FMP appear at subpart H of 50 CFR part 600 and 50 CFR part 679. Regulations governing sideboard protections for GOA groundfish fisheries appear at subpart B of 50 CFR part 680. The A season allowance of 2008 Pacific cod sideboard limits apportioned to non-AFA crab vessels catching Pacific cod for processing by the offshore component in the Central Regulatory Area of the GOA is 354 metric tons
(mt)for the GOA, as established by the 2008 and 2009 harvest specifications for groundfish of the GOA published on February 27, 2008. In accordance with § 680.22(e)(2)(i), the Administrator, Alaska Region, NMFS (Regional Administrator), has determined that the A season allowance of the 2008 Pacific cod sideboard limits apportioned to non-AFA crab vessels catching Pacific cod for processing by the offshore component in the Central Regulatory Area of the GOA will soon be reached. Therefore, the Regional Administrator is establishing a sideboard directed fishing allowance for Pacific cod as 344 mt in the offshore component in the Central Regulatory Area of the GOA. The remaining 10 mt in the offshore component in the Central Regulatory Area of the GOA will be set aside as bycatch to support other anticipated groundfish fisheries. In accordance with § 680.22(e)(3), the Regional Administrator finds that this sideboard directed fishing allowance has been reached. Consequently, NMFS is prohibiting directed fishing for Pacific cod by non-AFA crab vessels catching Pacific cod for processing by the offshore component in the Central Regulatory Area of the GOA. After the effective date of this closure the maximum retainable amounts at § 679.20(e) and
(f)apply at any time during a trip. Classification This action responds to the best available information recently obtained from the fishery. The Assistant Administrator for Fisheries, NOAA (AA), finds good cause to waive the requirement to provide prior notice and opportunity for public comment pursuant to the authority set forth at 5 U.S.C. 553(b)(B) as such requirement is impracticable and contrary to the public interest. This requirement is impracticable and contrary to the public interest as it would prevent NMFS from responding to the most recent fisheries data in a timely fashion and would delay the sideboard directed fishing closure of Pacific cod apportioned to non-AFA crab vessels catching Pacific cod for processing by the offshore component in the Central Regulatory Area of the GOA. NMFS was unable to publish a notice providing time for public comment because the most recent, relevant data only became available as of February 25, 2008. The AA also finds good cause to waive the 30-day delay in the effective date of this action under 5 U.S.C. 553(d)(3). This finding is based upon the reasons provided above for waiver of prior notice and opportunity for public comment. This action is required by § 680.22 and is exempt from review under Executive Order 12866. Authority: 16 U.S.C. 1801 *et seq.* Dated: February 25, 2008. James P. Burgess, Acting Director, Office of Sustainable Fisheries, National Marine Fisheries Service. [FR Doc. 08-894 Filed 2-26-08; 3:12 pm]
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  • 18 CFR 33
  • Pub. L. 109-58
  • 119 Stat. 594
  • 17 CFR 240.13
  • 18 CFR 1
  • 18 CFR 3.1(c)(10)(ii)
  • 5 CFR 1320
  • 5 USC 601-12
  • 16 USC 791a-825r
  • 42 USC 7101-7352
  • 18 CFR 35
  • 954 F.2d 779
  • 506 U.S. 981
  • 364 U.S. 137
  • 92 F.3d 1239
  • 909 F.2d 1519
  • 5 CFR 1320.12
  • 15 USC 79b(a)(11)
  • 21 CFR 520.45
  • 21 CFR 20
  • 5 USC 801-808
  • 21 CFR 520
  • 21 CFR 556
  • 22 CFR 42
  • Pub. L. 104-4
  • 109 Stat. 48
  • Pub. L. 104-121
  • Pub. L. 105-277
  • Pub. L. 104-208
  • 110 Stat. 3546
  • 25 CFR 171
  • 935 F.2d 281
  • 502 U.S. 1057
  • 25 CFR 15
  • 25 CFR 171.1(b)
  • 25 CFR 171.19(a)(2)
  • 25 CFR 2
  • Pub. L. 63-160
  • 42 USC 4321-4370(d)
  • 36 Stat. 270
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U.S.C.§ 824b
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C.F.R.§ 33.1
C.F.R.§ 35.42
C.F.R.§ 366.4
C.F.R.§ 366.23
U.S.C.§ 824m
U.S.C.§ 824c
F. App'x954 F.2d 779
SCOTUS506 U.S. 981
SCOTUS364 U.S. 137
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