Rules and Regulations. Correcting amendments

30,052 words·~137 min read·/register/2008/02/04/08-472

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

BILLING CODE 4910-13-M POSTAL REGULATORY COMMISSION 39 CFR Part 3020 [Docket No. RM2007-1; Order No. 43] Administrative Practice and Procedure, Postal Service; Corrections AGENCY: Postal Regulatory Commission. ACTION: Correcting amendments. SUMMARY: The Postal Regulatory Commission published a document in the **Federal Register** on November 9, 2007 (72 FR 63662), adopting new rules. That document inadvertently misidentified, in section 3020.91, the length of time for the Postal Service to file a notice of certain types of corrections to product descriptions in the Mail Classification Schedule and mischaracterized, in section 3020.93, the scope of a product list.

This document corrects the final regulations by revising these sections. DATES: Effective on December 10, 2007. FOR FURTHER INFORMATION CONTACT: Stephen L. Sharfman, General Counsel, 202-789-6820 and *stephen.sharfman@prc.gov* . SUPPLEMENTARY INFORMATION: This document summarizes the Commission's Notice of Errata issued on January 24, 2008, addressing two errors in final regulations. Review of regulations regarding Docket No. RM2007-1 (Order No. 43) indicates a need for revision of two sections to conform to the Commission's Order No. 43, October 29, 2007, which adopted those regulations.

The first affects 39 CFR 3020.91. As published, this section states that the Postal Service is to file a notice of a correction in product lists no later than 30 days prior to the effective date of the proposed change. The correct timeframe for filing such notices is no later than 15 days. The second revision affects 39 CFR 3020.93. As published, this section includes the phrase “market dominant” before “product description”. The phrase “market dominant” should not have been used as a qualifier.

As published, the final regulations contain errors which may prove to be misleading and need to be clarified. List of Subjects in 39 CFR Part 3020 Administrative practice and procedure; Postal Service. Accordingly, 39 CFR part 3020 is corrected by making the following correcting amendments: PART 3020—PRODUCT LISTS 1. The authority citation for part 3020 continues to read as follows: Authority: 39 U.S.C. 503; 3622; 3631; 3642; 3682. 2. Revise § 3020.91 to read as follows: § 3020.91 Modification.

The Postal Service shall submit corrections to product descriptions in the Mail Classification Schedule that do not constitute a proposal to modify the market dominant product list or the competitive product list as defined in § 3020.30 by filing notice of the proposed change with the Commission no later than 15 days prior to the effective date of the proposed change. 3. Revise paragraph

(b)of § 3020.93 to read as follows: § 3020.93 Implementation.

(b)The Commission's finding that changes to the product descriptions are not inconsistent with 39 U.S.C. 3642 is provisional and subject to subsequent review. Steven W. Williams, Secretary. [FR Doc. E8-1890 Filed 2-1-08; 8:45 am] BILLING CODE 7710-FW-P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 52 [EPA-R05-OAR-2007-1085; FRL-8519-1] Final Rule; Ohio; Revised Oxides of Nitrogen (NO X ) Regulation, Phase II, and Revised NO X Trading Rule AGENCY: Environmental Protection Agency (EPA). ACTION: Direct final rule. SUMMARY: EPA is approving a revision to the Ohio oxides of nitrogen (NO X ) State Implementation Plan

(SIP)containing provisions which control emissions of NO X from large internal combustion

(IC)engines, makes corrections to typographical errors in the previously approved Phase I NO X SIP, and expands the definition of NO X budget unit. This approval requires reductions in NO X emissions from large IC engines, based on cost-effective control measures. Large IC engines are defined in the State rule as emitting one ton or more of NO X per day during the ozone season. The Ohio NO X SIP Call IC engine inventory is based on the inventory of IC engines compiled by EPA as part of the NO X SIP Call rule. Including these engines in the Ohio plan reduces NO X to a level at which the State will meet its ozone season NO X budget. EPA is approving the State's revision because it satisfies the Federal requirements for Phase II sources and demonstrates that these rules will meet the Phase II budget for Ohio. DATES: This direct final rule is effective April 4, 2008 without further notice, unless EPA receives adverse comment by March 5, 2008. If EPA receives such comments, it will publish a timely withdrawal of the direct final rule in the **Federal Register** and inform the public that the rule will not take effect. ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R05-OAR-2007-1085, by one of the following methods: I. *http://www.regulations.gov:* Follow the on-line instructions for submitting comments. II. *E-mail:* *mooney.john@epa.gov* . III. *Fax:*

(312)886-5824 IV. *Mail:* Reference EPA-R05-OAR-2007-1085 Docket, Air Programs Branch, U.S. Environmental Protection Agency, (AR-18J), 77 West Jackson Boulevard, Chicago, Illinois 60604. V. *Hand Delivery or Courier:* John Mooney, Chief, Criteria Pollutant Section, Air Programs Branch, U.S. Environmental Protection Agency (AR-18J), 77 West Jackson Boulevard, Chicago, Illinois 60604. Such deliveries are only accepted during the Regional Office's normal hours of operation. The Regional Office's official hours of business are Monday through Friday, 8:30 to 4:30, excluding federal holidays. *Instructions:* Direct your comments to Docket ID No. “EPA-R05-OAR-2007-1085”. EPA's policy is that all comments received will be included in the public docket without change and may be made available online at *www.regulations.gov,* including any personal information provided, unless the comment includes information claimed to be Confidential Business Information

(CBI)or other information whose disclosure is restricted by statute. Do not submit through *www.regulations.gov* or e-mail, information that you consider to be CBI or otherwise protected. The *www.regulations.gov* Web site is an “anonymous access” system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through *www.regulations.gov,* your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters and any form of encryption and should be free of any defects or viruses. For additional information about EPA's public docket visit the EPA Docket Center homepage at *http://www.epa.gov/epahome/dockets.htm* . *Docket:* All documents in the electronic docket are listed in the *www.regulations.gov* index. Although listed in the index, some information is not publicly available, i.e., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically at *www.regulations.gov* or in hard copy at the Environmental Protection Agency, Region 5, Air and Radiation Division, 77 West Jackson Boulevard, Chicago, Illinois 60604. EPA requests that if at all possible, you contact the person listed in the FOR FURTHER INFORMATION CONTACT section to schedule your inspection. The Regional Office's official hours of business are Monday through Friday, 8:30 to 4:30, excluding Federal holidays. FOR FURTHER INFORMATION CONTACT: John Paskevicz, Engineer, Criteria Pollutant Section, Air Programs Branch (AR-18J), Environmental Protection Agency, Region 5, 77 West Jackson Boulevard, Chicago, Illinois 60604. The telephone number is

(312)886-6084. Mr. Paskevicz can also be reached via electronic mail at: *paskevicz.john@epa.gov* . SUPPLEMENTARY INFORMATION: Throughout this document, “we,” “us,” and “our” refer to the U.S. Environmental Protection Agency. Table of Contents I. Does this rule apply to me? II. The State's Submittal A. Why did the State submit this revision and how does it fit in with the State's NO X plan? B. What did Ohio submit? III. EPA's Evaluation and Final Action A. Is the Ohio submittal complete? B. Did the State submit the revision in time to meet EPA requirements? C. Does the Ohio submittal meet the evaluation criteria? IV. What action is EPA taking today? V. Statutory and Executive Order Reviews I. Does this rule apply to me? This rule applies to owners or operators of any large NO X SIP Call stationary internal combustion engines as defined in the State rule and located in the State of Ohio. A “large NO X SIP Call engine” means any engine in the Ohio NO X SIP Call engine inventory emitting more than one ton of NO X emissions per control period day in 1995. Ohio used the EPA 1995 baseline inventory list that contained the NO X emission units for all of the States including Ohio. A search of that list shows that there are 12 large lean burn IC engines, as described by EPA, in Ohio. These engines are located at pipeline pumping stations and are required by State rule to meet the NO X SIP Call Phase II budget. Compliance plans are expected to show that control of these 12 units will bring about reductions of NO X to meet the portion of the NO X budget associated with these units. II. The State's Submittal A. Why did the State submit this revision and how does it fit in with the State's NO X plan? In order to reduce ozone transport in the eastern part of the United States, the EPA issued the NO X SIP Call on October 27, 1998, (63 FR 57356) to reduce emissions of NO X , a precursor of ozone. Subsequent litigation affecting this SIP Call prompted the EPA to divide the SIP Call into two phases. The majority of the SIP Call was upheld by the D.C. Circuit Court of Appeals and these requirements became Phase I of the SIP Call. A second phase of the SIP Call was necessary to address the portions of the October 1998 action which were vacated or remanded to EPA by the Court. EPA published the final Phase II Rule on April 21, 2004 (69 FR 21604). The plans that cover the portion of the rule re-issued after the Court decision are known as “Phase II” SIPs and were due to be submitted to EPA on April 1, 2005, with full compliance by May 1, 2007. The Ohio plan revision was received by EPA on June 16, 2005. Additional information regarding compliance plan approval by Ohio was provided on November 7, 2006. In addition to the Phase II rule, EPA published a draft example rule on September 15, 2004, for States to use as a model for their State rules. A copy of this draft example rule is available at the Web site: *http://www.epa.gov/ttn/oarpg/t1/meta/m25546.html.* Coincidental with the draft example rule EPA provided a list of questions and answers for use by States in response to some common questions expressed by the regulated community. ( *http://www.epa.gov/ttn/oarpg/t1/reports/23814qnaasfin.pdf* ) The EPA Phase II rule identifies the incremental budget for Ohio which the State is expected to comply with in order to fulfill the requirements of the NO X SIP Call. B. What did Ohio submit? Ohio's revision contains rules which add IC engines to the list of affected sources of NO X . The revision also includes some language changes to the original NO X SIP, and also changes in definitions and the addition of specific language for cogeneration units. These changes are located in OAC 3745-14-01, -05, and -12, and Appendix B. OAC 3745-14-01 was changed in the areas of Definitions and Applicability. Ohio made changes in the Definitions section addressing continuous emissions monitoring, linking the language to Ohio rule 3745-14-08, and 40 CFR part 75, and expanded the language in the state's rule pertaining to automated data acquisition and handling system and NO X monitoring. An additional list of definitions was added pertaining to IC engines, clearly defining to which source types this rule applies. In the applicability portion of the rule a separate section addressing (and including) cogeneration units was added. A number of minor wording revisions were made in OAC 3745-14-05, relating to Ohio's incorporation by reference of EPA's technical amendments to the NO X SIP Call Rule and ASTM standard test methods for several pollutants including NO X . This State rule revision includes Appendix B to the chapter, and lists the non-electric generating unit's (non-EGU) annual NO X allowance allocations. This appendix contains corrections to errors on the list made in the point identification portion of the State's Appendix B for non-EGUs. OAC 3745-14-12, Stationary internal combustion engines, is an entirely new rule which applies to large NO X SIP Call engines as defined in OAC 3745-14-01. The rule lists the requirements for a compliance plan, and the requirements for monitoring, recordkeeping and reporting of data. III. EPA's Evaluation and Final Action A. Is the Ohio submittal complete? Yes, Ohio submitted a complete SIP revision. The revision is complete from the point of view of satisfying the Ohio state code for submitting State plans to EPA. And the revision is complete based on the requirements of 40 CFR part 51, Appendix V. This revision augments a number of earlier revisions to the Ohio NO X SIP Call. On August 5, 2003, 68 FR 46089, EPA published a final rule giving conditional approval of the Ohio NO X SIP Call plan, following receipt of a written commitment from Ohio to revise the flow control date. On June 27, 2005, 70 FR 36845, EPA published a final rule approving the Ohio revision which excludes carbon monoxide boilers at fluid catalytic cracking units in oil refineries from Ohio's NO X trading program. B. Did the State submit the revision in time to meet EPA requirement? The State Phase II SIP was required to be submitted one year following the approval by the EPA Administrator establishing the final full NO X budgets for States subject to the NO X SIP Call. The final full NO X budget rule was signed by the administrator on April 1, 2004. (69 FR 21604) The revised State plans were due on April 1, 2005. The Ohio plan was received by EPA on June 16, 2005. C. Does the Ohio submittal meet the evaluation criteria? EPA evaluated the Ohio plan submittal based on the guidance EPA provided to states affected by the NO X SIP Call. We are satisfied that the plan submitted by Ohio meets this guidance. EPA published an example rule (EPA guidance) illustrating a means by which States can meet the NO X SIP Call Phase II requirements. The example rule contained: A set of new definitions associated with stationary internal combustion engines; a description of a compliance plan containing provisions applicable to each owner/operator of a large IC engine; and a detailed list of reporting, monitoring, and recordkeeping requirements with which an owner/operator must comply. We reviewed the Ohio Phase II submittal against our example rule and find the Ohio IC engine rule to be consistent with applicable elements of the EPA example rule. Ohio also included an incorporation by reference (in OAC 3745-14-01) of:

(1)A standard test method for determining NO X concentrations in emissions from natural gas-fired reciprocating engines, combustion turbines, boilers, and process heaters using portable analyzers;

(2)Technical Amendment to the Finding of Significant Contribution and Rulemaking for Certain States for Purposes of Reducing Regional Transport of Ozone, (65 FR 11222, March 2, 2000); and,

(3)Interstate Ozone Transport Response to Court Decisions on the NO X SIP Call, NO X SIP Call Technical Amendments, and Section 126 Rules (69 FR 21603, April 21, 2004.) IV. What action is EPA taking? EPA is approving the revision to the Ohio NO X SIP Call which adds provisions affecting large stationary internal combustion engines. We are also approving a number of changes to the State's plan including the revised budget demonstration for IC engines, rule changes affecting continuous emissions monitoring, and additional language affecting cogeneration units. V. Statutory and Executive Order Reviews Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is not a “significant regulatory action” and therefore is not subject to review by the Office of Management and Budget. For this reason, this action is also not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001). This action merely approves State law as making progress toward meeting Federal requirements and would impose no additional requirements beyond those imposed by State law. Accordingly, the Administrator certifies that this rule would not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 *et seq.* ). Because this action approves pre-existing requirements under State law and would not impose any additional enforceable duty beyond that required by State law, it does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4). This rule also does not have tribal implications because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes, as specified by Executive Order 13175 (65 FR 67249, November 9, 2000). This action also does not have Federalism implications because it would not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132 (64 FR 43255, August 10, 1999). This action approves a State rule making progress toward implementing a Federal standard. It does not alter the relationship or the distribution of power and responsibilities established in the Clean Air Act. This rule also is not subject to Executive Order 13045 “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997), because it would approve a State rule making progress toward implementing a Federal Standard. In reviewing SIP submissions, EPA's role is to approve State choices, provided that they meet the criteria of the Clean Air Act. In this context, in the absence of a prior existing requirement for the State to use voluntary consensus standards (VCS), EPA has no authority to disapprove a SIP submission for failure to use VCS. It would thus be inconsistent with applicable law for EPA, when it reviews a SIP submission, to use VCS in place of a SIP submission that otherwise satisfies the provisions of the Clean Air Act. Thus, the requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) do not apply. This rule would not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 *et seq.* ). The Congressional Review Act, 5 U.S.C. section 801 *et seq.* , as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the **Federal Register** . A major rule cannot take effect until 60 days after it is published in the **Federal Register** . This action is not a “major rule” as defined by 5 U.S.C. 804(2). Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by April 4, 2008. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this rule for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2).) List of Subjects in 40 CFR Part 52 Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Oxides of nitrogen, Reporting and recordkeeping requirements. Dated: January 11, 2008. Gary Gulezian, Acting Regional Administrator, Region 5. For the reasons stated in the preamble, part 52, chapter I, of title 40 of the Code of Federal Regulations is amended as follows: PART 52—[AMENDED] 1. The authority citation for part 52 continues to read as follows: Authority: 42 U.S.C. 7401 *et seq.* Subpart KK—Ohio 2. Section 52.1870 is amended by adding paragraph (c)(141) to read as follows: § 52.1870 Identification of plan.

(c)* * *

(141)Ohio Environmental Protection Agency, on June 16, 2005, submitted amendments to the State Implementation Plan to control nitrogen oxide emissions from internal combustion engines in new rule Ohio Administrative Code

(OAC)3745-14-12. This rule adds stationary internal combustion engines to the list of sources in the Ohio NO X SIP Call emission reduction program. Also, OAC 3745-14-01, General Provisions, is amended. This rule contains definitions used for the nitrogen oxides rules, expands the definition of NO X budget unit, adds definitions for the internal combustion engine rule, amends definition associated with continuous emissions monitoring, and makes corrections to typographical errors. OAC 3745-14-05 Portions of this rule are amended to correctly line up with the changes made in the definitions section of the NO X plan. Typographical errors are also corrected.

(i)*Incorporation by reference.* The following sections of the Ohio Administrative Code

(OAC)are incorporated by reference.

(A)OAC 3745-14-01, General Provisions, effective on May 07, 2005.

(B)OAC 3745-14-05, NO X Allowance Allocations, effective on May 07, 2005.

(C)OAC 3745-14-12, Stationary Internal Combustion Engines, effective on May 7, 2005. [FR Doc. E8-1797 Filed 2-1-08; 8:45 am] BILLING CODE 6560-50-P DEPARTMENT OF THE INTERIOR Bureau of Land Management 43 CFR Part 3130 [WO-310-1310-PP-241A] RIN 1004-AD78 Oil and Gas Leasing; National Petroleum Reserve—Alaska AGENCY: Bureau of Land Management, Interior. ACTION: Final rule. SUMMARY: The Bureau of Land Management

(BLM)is amending its regulations at 43 CFR part 3130 pertaining to oil and gas resources in the National Petroleum Reserve—Alaska (NPR-A). The rule makes oil and gas administrative procedures in NPR-A consistent with Section 347 of the Energy Policy Act of 2005. The rule amends the administrative procedures for the efficient transfer, consolidation, segregation, suspension, and unitization of Federal leases in the NPR-A. The rule also changes the way the BLM processes lease renewals, lease extensions, lease expirations, lease agreements, exploration incentives, lease consolidations, and termination of administration for conveyed lands in the NPR-A. Finally, the rule makes the NPR-A regulation on additional bonding consistent with the regulations that apply outside of the NPR-A. DATES: This rule is effective March 5, 2008. ADDRESSES: Further information or questions regarding this final rule should be addressed in writing to the Director (WO-300), Bureau of Land Management, 1849 C St., NW., Washington DC 20240. FOR FURTHER INFORMATION CONTACT: Greg Noble, Chief, Energy Branch, the BLM's Alaska State Office at

(907)267-1429 or Ian Senio at the BLM's Division of Regulatory Affairs at

(202)452-5049. Persons who use a telecommunications device for the deaf

(TDD)may contact these persons through the Federal Information Relay Service

(FIRS)at 1-800-877-8339, 24 hours a day, 7 days a week, to leave a message or question with the above individuals. You will receive a reply during normal business hours. SUPPLEMENTARY INFORMATION: I. Background II. Discussion of the Final Rule and Responses to Comments on the Proposed Rule III. Procedural Matters I. Background Part 3130 of 43 Code of Federal Regulations

(CFR)contains the regulations that apply to oil and gas leasing in the NPR-A authorized under the Naval Petroleum Reserves Production Act of 1976, as amended (NPRPA), (42 U.S.C. 6501 *et seq.* ). On April 11, 2002 (67 FR 17866), the BLM published a final rule that applies to operations under Federal oil and gas leases in NPR-A and added a new subpart allowing the formation of oil and gas units in the NPR-A. On August 8, 2005, the President signed the Energy Policy Act of 2005 (EPAct of 2005) (Pub. L. 109-58). Section 347 of the EPAct of 2005 amends the NPRPA. These amendments require that the BLM revise our existing regulations on:

(A)Lease extensions and renewals;

(B)Participation in oil and gas units;

(C)Production allocation;

(D)Termination of administration of conveyed mineral estate; and

(E)Waiver, suspension, and reduction of rental or minimum royalty or reduction of the royalty rate. On May 22, 2007, the BLM published a proposed rule to amend existing regulations pertaining to oil and gas resources in the NPR-A (72 FR 28636). This final rule is substantially the same as the proposed rule. However, the final rule differs in some respects from the proposed rule. Some changes are the result of public comment on the proposed rule, and others are to make the rule clearer and more consistent with the EPAct of 2005. II. Discussion of the Final Rule and Responses to Comments on the Proposed Rule Section 3130.0-3 Authority This final rule amends the authority section by adding a reference to the Energy Policy Act of 2005 (Pub. L.109-58) in a new paragraph (d). We received no substantive comment on this section and it remains as proposed. Section 3130.0-5 Definitions The EPAct of 2005 uses three terms that we also use in this final rule. All three terms are used in the provisions having to do with the methodology for allocating production among committed tracts in a unit in the NPR-A (see section 3137.23(g)). If the unit included non-Federal land, the methodology must take into account reservoir heterogeneity and area variation in reservoir producibility. This section of the rule defines the terms “production allocation methodology,” “reservoir heterogeneity,” and “variation in reservoir producibility” in a manner consistent with normal usage in the field. In the final rule we revised the definitions of “production allocation methodology” and “variation in reservoir producibility” based on a commenter's suggestions. The definition of “reservoir heterogeneity” remains as proposed. One commenter suggested modifying the definition of “production allocation methodology” to make it clear that all production from a participating area would be allocated to committed tracts forming the participating area. We agree that the suggested modification provides added clarity and in the final rule revised the definition based on this comment. The commenter also suggested changing the definition for “variation in reservoir producibility” by deleting the sentence, “This can be dependent on where the well penetrates the reservoir”, and replacing it with “These differences can result from variations in the thickness of the reservoir, porosity, and the amount of connected pore space.” We accept the comment and have revised the definition in the final rule. Section 3133.3 Under what circumstances will BLM waive, suspend, or reduce the rental or minimum royalty or reduce the royalty rate on my NPR-A lease? The EPAct of 2005 addresses the circumstances under which the BLM would consider waiving, suspending, or reducing the rental or minimum royalty or reducing the royalty rate on an NPR-A lease. This rule amends the existing regulations by revising paragraphs

(a)and (a)(2) to state that the BLM could waive, suspend, or reduce the rental or minimum royalty or reduce the royalty rate on an NPR-A lease if it was necessary to promote development or the BLM determined that the lease could not be successfully operated under the terms of the lease. Also, as a result of changes made to the NPRPA by the EPAct of 2005, this rule changes existing paragraph

(b)by requiring the BLM to consult with the State of Alaska and the North Slope Borough within 10 days of receiving an application for waiver, suspension, or reduction of rental or minimum royalty or reduction of the royalty rate. Under new paragraph (b), the BLM would not approve an application for these benefits (under § 3133.4) until at least 30 days after the consultation is completed. This rule adds a new paragraph

(c)to this section. Under this new paragraph, if a lease included land that was made available for acquisition by a regional corporation (as defined in 43 U.S.C. 1602) under Section 1431(o) of the Alaska National Interest Lands Conservation Act (16 U.S.C. 3101 *et seq.* ), the BLM would only approve a waiver, suspension, or reduction of rental or minimum royalty or a reduction of the royalty rate if the regional corporation concurred. This change is necessary because the EPAct of 2005 requires concurrence from the regional corporation prior to approval of these actions. One commenter expressed support for the changes in section 3133.3 that allow the BLM to waive, suspend, or reduce the rental, royalty, or minimum royalty on an NPR-A lease if the BLM believes it is needed to promote development. The commenter believes that some exploration and development incentives will be necessary for the successful development of the NPR-A. In the final rule we revised sections 3133.3 and 3133.4 to be consistent with the NPRPA and the EPAct of 2005. Both Acts specifically grant the Secretary the authority to waive, suspend, or reduce the rental or minimum royalty, or to reduce the royalty rate on NPR-A leases. Neither Act grants the Secretary authority to waive or suspend the royalty on NPR-A leases, as the current and proposed regulations state, and the final rule makes this clear. Section 3133.4 How do I apply for a waiver, suspension or reduction of rental or minimum royalty or a reduction of the royalty rate for my NPR-A lease? Under this rule, existing paragraphs (a)(6) and (a)(7) have new requirements that an applicant who is applying for a waiver, suspension, or reduction of rental or minimum royalty or a reduction of the royalty rate demonstrate that the waiver, suspension, reduction of the rental or minimum royalty or a reduction of the royalty rate encourages the greatest ultimate recovery of oil or gas or it is in the interest of conservation, and all the facts demonstrate that the applicant cannot successfully operate the lease under its terms. These new requirements are the result of changes that the EPAct of 2005 made to NPRPA. This rule also makes a minor editorial change to existing paragraph (a)(6) (new paragraph (a)(7)) by replacing “can't” with “cannot.” In addition to the revision discussed in section 3133.3, in the final rule we also revised section 3133.4(a)(5) by adding language from previous section 3133.4(a)(7) concerning providing to the BLM, as part of the application, the amount of overriding royalty and payments out of production or other similar interests applicable to the lease. While not specifically listed in the proposed rule, this information would have been required under section (a)(5) or (a)(8) of the proposed rule, but we have included it in the final rule to make it clear that this information is needed in order for BLM to complete an evaluation of the “expenses and costs” of operating the lease. The changes are not significant and do not change the meaning or effect of the regulations. We have also made a grammatical correction to proposed sections 3133.4(a)(6) and (a)(7) by deleting the second “that” in the first sentence of each section. These edits have no substantive effect on the regulation. Section 3134.1-2 Additional Bonds Changes to the existing paragraph

(a)on additional bonding allow the BLM to require additional bonding for all NPR-A leases, not only leases in special areas, using the criteria of section 3104.5(b) of the existing regulations. This rule adds a cross reference to existing section 3104.5(b), which allows the BLM to require an increase in the amount of any NPR-A lease bond if the BLM determined that the operator posed a risk due to factors, including, but not limited to:

(A)A history of previous violations;

(B)A notice from the Minerals Management Service

(MMS)that there are uncollected royalties due; or

(C)The total cost of plugging existing wells and reclaiming lands exceeds the present bond amount based on the estimates determined by the BLM. The previous regulations only allow the BLM to increase the bonding amount in the Special Areas as defined in the NPRPA. This rule allows the BLM to increase the bonding amount on all NPR-A leases and would make the NPR-A oil and gas regulations consistent with the regulations that currently apply to Federal oil and gas leases outside of the NPR-A We received no substantive comment on this section and it remains as proposed. Section 3135.1-4 Effect of Transfer of a Tract This rule revises paragraph

(a)of this section to make the existing provisions clearer. This would not change the meaning or intent of this paragraph. This rule revises the provisions on segregation in paragraph

(b)of this section by changing the standard that the BLM applies when determining if a segregated lease should continue in full force and effect. The existing standard is that a segregated lease remains in full force and effect if the BLM determines that oil and gas is being produced in paying quantities from that segregated portion of the lease area or so long as drilling or well reworking operations, either actual or constructive, are being conducted. The new standard is that a lease continues in full force and effect as long as the activities on the segregated lease support lease extension under the regulations in section 3135.1-5. That section is revised by this rule as well and it is discussed further below. We received no substantive comment on this section and it remains as proposed. Section 3135.1-5 Extension of Lease Existing regulations on lease extensions require that the BLM extend the term of a lease beyond its primary term so long as:

(A)Oil or gas is produced from the lease in paying quantities; or

(B)Drilling or reworking operations, actual or constructive, as approved by the BLM, are being conducted on the lease. This rule adds a new condition to paragraph

(a)of this section under which the BLM would grant a lease extension in cases where the BLM has determined in writing that oil or gas is capable of being produced in paying quantities from the lease. The rule amends existing paragraph

(a)by breaking it into subparagraphs so that it is easier to read. The last sentence of paragraph

(a)is rewritten to make it clear that the BLM approves drilling or reworking operations, actual or constructive, rather than the Secretary. This rule also adds a new paragraph

(b)to this section that explains that NPR-A leases expire on the 30th anniversary of the original issuance date of the lease unless oil or gas is being produced in paying quantities from the lease. The new paragraph further explains that if a lease contains a well that is capable of production, but the lease does not produce the oil or gas due to circumstances beyond the lessee's control, the lessee may apply for a suspension under section 3135.2. If the BLM approved the suspension, the lease would not expire on the 30th anniversary of the original issuance date of the lease. These changes are in response to changes to NPRPA made by the EPAct of 2005. This rule amends what is now paragraph

(c)(paragraph

(b)of the existing regulation) by making it clear that the directional wells discussed in that paragraph are the BLM-approved directional wells. This is a clarification of existing practice. One commenter supported the proposed change to this section that provides for lease extensions based on a well that is capable of producing oil or gas in paying quantities. Another commenter suggested revising section 3135.1-5 to make it clear that leases that are part of a unit can be extended as described in existing subpart 3137. While it is true that leases committed to a unit can be extended under sections 3137.10 and 3137.111, we did not modify final section 3135.1-5 as the commenter suggested. We believe, as the commenter implies, that existing regulations address the issue of extensions of leases committed to a unit. The commenter was also concerned about how leases that are only partially within a unit may be extended. All portions of a lease have the same expiration date and benefit equally from extensions. If a lease is segregated, the segregated portion of the lease would likely have different lease terms than the “parent” lease. The regulations do not address segregation of leases as a result of unitization. If segregation is appropriate it is addressed in the unit agreement. If segregation occurs, sections 3135.1-4 through 3135.1-6 describe how the segregated, non-unit lease may be extended or renewed. Section 3135.1-6 Lease Renewal This rule would add a new section on lease renewals to the existing NPR-A regulations that is based on changes the EPAct of 2005 made to the NPRPA. The EPAct of 2005 and this section address lease renewals in two parts: those leases that have a discovery of hydrocarbons and those leases that do not have a discovery. *With a Discovery* . Under this section, at any time after the fifth year of the primary term of a lease, the BLM could approve a 10-year lease renewal for a lease on which there has been a well drilled and a discovery of hydrocarbons, even if the BLM had determined that the well is not capable of producing oil or gas in paying quantities. Under this section the BLM must receive the lessee's application for lease renewal no later than 60 days prior to the expiration of the primary term of the lease. This section requires that the renewal application provide evidence, and a certification by the lessee, that the lessee has discovered oil or gas on the leased lands in such quantities that a prudent operator would hold the lease for potential future development. Under this section, the BLM approves applications if it determines that a discovery was made and that a prudent operator would hold the lease for future development. The BLM may approve the lease renewal on the condition that the lessee drills one or more additional wells or acquires and analyzes more well data, seismic data, or geochemical survey data prior to the end of the primary term of the lease. Under this section lease renewals are effective on the day following the end of the primary term of the lease. *Without a Discovery* . Under this section, at any time after the fifth year of the primary term of a lease, the BLM could approve an application for a 10-year lease renewal for a lease on which there has not been a discovery of oil or gas. The BLM must receive the lessee's application no later than 60 days prior to the expiration of the primary term of the lease. Under this rule, the renewal application must:

(A)Provide sufficient evidence that the lessee has diligently pursued exploration that warrants continuation of the lease with the intent of continued exploration or future potential development of the leased land. The application must show the lessee has drilled one or more wells or acquired seismic or geochemical data indicating a probability of future success, and the application must include a plan for future exploration; or

(B)Show that all or part of the lease is part of a unit agreement covering a lease that qualifies for renewal without a discovery and that the lease has not been previously contracted out of the unit. Under this section the BLM approves renewal applications if it determines that the application satisfied the requirements of paragraph (b)(2)(A) or

(B)of this section. If the BLM approved the application for lease renewal, the applicant would be required to submit to the BLM a fee of $100 per acre within 5 business days of receiving notification of the renewal approval. Lease renewals are effective on the day following the end of the primary term of the lease. The BLM may approve the lease renewal on the condition that the lessee drills one or more additional wells or acquires and analyzes more well data, seismic data, or geochemical survey data prior to the end of the primary term of the lease. The renewed lease is subject to the terms and conditions applicable to new oil and gas leases issued under the Integrated Activity Plan in effect on the date that the BLM issues the decision to renew the lease. One commenter supported the renewal provisions in section 3135.1-6, but suggested defining the term “discovery” and offered a definition. We did not define the term “discovery” in the final rule based on this comment. We believe section 3135.1-6(a)(2) adequately describes what is necessary for the BLM to consider a request for lease renewal “with a discovery.” We did revise this section to indicate that the discovery well(s) could be drilled by the lessee or the operator. Under this final rule, discovery wells must be drilled on the lease after lease issuance. This makes it clear that the wells can be drilled by the lessee as operator or another operator designated by the lessee. Section 3135.1-7 Consolidation of Leases This rule revises the consolidation provisions in existing regulations having to do with the term of a consolidated lease. Under the existing regulations, the term of a consolidated lease is extended beyond the primary term of the lease only as long as oil or gas is produced in paying quantities or approved constructive or actual drilling or reworking operations are conducted on the lease. Under paragraph

(d)of this rule, the term of consolidated leases are extended or renewed, as appropriate, under the extension or renewal provisions of the regulations. The change recognizes that the new standards in the extension and renewal provisions of this rule apply to consolidated leases. This rule amends paragraph

(e)of the existing regulation by making it clear that the highest of the royalty or rental rates of any original lease apply to the consolidated lease. This is consistent with existing policy and practice. In the final rule we revised section 3135.1-7(e). The proposed rule stated that “The highest of the royalty or rental rates of any original lease shall apply to the consolidated lease.” The final rule says “The highest royalty and rental rates of the original leases shall apply to the consolidated lease.” The revision makes the final rule clearer, but has no effect on the intent of the proposed rule. Section 3135.1-8 Termination of Administration for Conveyed Lands and Segregation This rule adds a new section concerning the waiver of administration for conveyed lands in a lease. This new section is necessary because of changes that the EPAct of 2005 made to the NPRPA. Under this new section, the BLM is required to terminate administration of any oil and gas lease if all of the mineral estate is conveyed to a regional corporation. The regional corporation would then assume the lessor's obligation to administer any oil and gas lease. This section explains that if a conveyance of the mineral estate does not include all of the land covered by an oil and gas lease, the lease would be segregated into two leases, one of which will cover only the mineral estate conveyed. The regional corporation would assume administration of the lease within the conveyed mineral estate. Under this rule, if the regional corporation assumed administration of a lease under paragraph

(a)or

(b)of this section, all lease terms, the BLM regulations, and the BLM orders in effect on the date of assumption would continue to dictate the lessee's obligations under the lease. All such obligations will be enforceable by the regional corporation as the lessor until the lease terminates. In a case in which a conveyance of a mineral estate described in paragraph

(b)of this section does not include all of the land covered by the oil and gas lease, a person who owns part of the mineral estate covered by the lease is entitled to the revenues associated with its mineral rights, including all royalties resulting from oil and gas produced from or allocated to that part of the mineral estate. We received no substantive comment on this section and with the exception of replacing “Arctic Slope Regional Corporation” and “ASRC” with “regional corporation” (see the discussion of final section 3137.11 for an explanation of this change), it remains as proposed. Section 3137.5 What terms do I need to know to understand this subpart? This rule makes one change to the definition of “participating area” by replacing the word “contain” with the phrase “are proven to be productive by.” Existing regulations imply that every committed tract within a participating area must contain a well that meets the productivity criteria specified in the unit agreement. The rule makes it clear that the participating area consists of tracts that have been proven productive by a well meeting the productivity criteria, but that not every committed tract in the participating area would necessarily contain a well meeting the productivity criteria. We received no substantive comment on this section and it remains as proposed. Section 3137.11 What consultation must BLM perform if lands in the unit area are owned by a regional corporation or the State of Alaska? This rule adds a new section on consultation if lands in a unit are owned by a regional corporation or the State of Alaska. This section is based on changes that the EPAct of 2005 made to the NPRPA. The new section requires that if the BLM administers a unit containing tracts where the mineral estate is owned by a regional corporation or the State of Alaska, or if a proposed unit contains tracts where the mineral estate is owned by a regional corporation or the State of Alaska, the BLM will consult with and provide opportunities for participation with respect to the creation or expansion of the unit by:

(A)A regional corporation, if the unit acreage contains the regional corporation's mineral estate; or

(B)The State of Alaska, if the unit acreage contains the state's mineral estate. The EPAct of 2005 requires that the BLM provide opportunity for participation by the State of Alaska or the regional corporation in the creation and expansion of units if those units include acreage in which the State of Alaska or the regional corporation has an interest in the mineral estate. If a proposed oil and gas unit included lands where one or both of these entities owned an interest in the mineral estate, the BLM will require the unit proponent to allow the State of Alaska and/or the regional corporation to participate in the negotiations of the unit agreement terms and the unit agreement area. This allows the State of Alaska and the regional corporation to protect their interests in the unit agreement before they commit their tracts to the unit. Similarly, if a unit expansion is proposed, and the existing unit or the acreage included in the expansion included lands in which the State of Alaska or a regional corporation owned a mineral interest, the State of Alaska or the regional corporation will participate in the negotiation of the terms of the expanded unit and in the determination of the expanded unit area. “Participation” in this case does not mean sharing of revenues or production. Instead, the term means participation by the regional corporation or the state, as applicable, in the process of government oversight, through consultation, of the unit's creation or expansion. The BLM received two comments addressing proposed section 3137.11. One commenter suggested that the BLM should incorporate language in the regulations that would give the BLM the option to request that the regional corporation and/or the State of Alaska join the unit agreement, as negotiated by the BLM, if the non-federal ownership comprises less than 10% of the surface acreage of the proposed unit. We made no changes to the final rule as a result of this comment. The EPAct of 2005 requires the BLM to provide non-federal entities opportunities for participation in the creation and expansion of units and does not condition this requirement on the percentage of lands involved. Another commenter noted that this “opportunity for participation” has the potential to complicate unit negotiations, but conceded that this would be the case with any unit agreement involving multiple mineral owners. We agree that having more parties participating in negotiating the initial terms of a unit agreement or the modified terms necessary to expand a unit has the potential to complicate negotiations, but we made no changes to the final rule as a result of this comment. The EPAct of 2005 created a statutory requirement for a process that would have been necessary in almost any case. While it is the BLM's responsibility to consult with and provide non-federal mineral owners an opportunity to participate in unit negotiations involving the creation and expansion of units, it will be the responsibility of the proposed unit operator to propose terms in the unit agreement that are acceptable to the mineral interests involved if commitment of those mineral interests is necessary for the unit operator to have effective control of unit operations. The BLM will not approve a unit unless the proposed unit operator has sufficient commitment of mineral interests to demonstrate effective control of the unitized area. At any point after the non-federal mineral owners have had the opportunity to negotiate unit terms, the BLM will review the agreement, if it is submitted by a qualified unit operator. The BLM will approve the unit agreement if the unit operator will have effective control of the unit area, it is in the interest of conservation of the natural resources, it is determined to be necessary or advisable in the public interest, it meets all mandatory terms described in these regulations, and it complies with all special conditions that may be in effect for the NPR-A. The same commenter requested clarification as to who would be the administrator of a unit agreement and suggested that the rule state that the BLM will be the administrator of a unit if a well drilled on a BLM lease leads to the application for a unit. The location of the initial well or well leading to the application for a unit does not determine who will administer the unit and we did not revise this section as a result of this comment. If the BLM approves a unit, the BLM will be the administrator of the unit and subpart 3137 will apply. The BLM can also commit lands to a unit administered by the State and/or regional corporation as provided for in section 3137.15. One commenter suggested that all references to “Arctic Slope Regional Corporation” be changed to “regional corporation” to conform to other references in the regulations. We agree and have made these changes in the final rule. Section 3137.21 What must I include in an NPR-A unit agreement? The rule makes one minor change to section 3137.21(a)(3) by replacing the word “proposed” with the word “anticipated.” Existing regulations assume that in all cases the applicant would be in a position to propose the participating area size and well locations at the application stage. The wording change recognizes that at the early application stage in the process an applicant may not be able to propose the participating area size or anticipated well locations. Using the word “anticipated” instead of “proposed” better reflects on-the-ground circumstances. This rule adds a new paragraph (a)(5) to this section that requires unit agreements that contain the regional corporation's mineral estate or the state's mineral estate to acknowledge that, with respect to those two entities, the BLM consulted with them and provided opportunities for participation in the creation of the unit and that the BLM will consult with them and provide opportunities for participation in the expansion of the unit, as appropriate. Existing regulations do not contain this consultation requirement, which is now necessary due to changes to NPRPA made by the EPAct of 2005. This rule also makes a minor editorial change to existing paragraph (a)(5) (renumbered paragraph (a)(6)) by adding “that” between “subpart” and “you.” We received one comment on section 3137.21. The commenter wanted to confirm that, by approving the unit agreement, the BLM would be simultaneously ratifying the statement required by section 3137.21(a)(5), (i.e., acknowledgement that the BLM consulted with and provided opportunities to the State of Alaska and/or the regional corporation for participation in the creation of the unit and that the BLM will consult with and provide opportunities to the State of Alaska and/or the regional corporation for participation in the expansion of the unit when state and/or regional corporation mineral estate is involved). We did not revise the final rule as a result of this comment, but we agree with the commenter that, by approving the unit agreement, the BLM would be confirming that the requirements of section 3137.21(a)(5) have been met. Section 3137.23 What must I include in my NPR-A unitization application? This rule adds to the existing regulation a provision requiring in the unit application a discussion of the proposed methodology for allocating production among the committed tracts. If the unit includes non-Federal oil and gas mineral estate, new paragraph

(g)requires that the application explain how the methodology would take into account reservoir heterogeneity and area variation in reservoir producibility. These changes are necessary because of changes that the EPAct of 2005 made to the NPRPA. Also, as discussed earlier, the terms “reservoir heterogeneity” and “variation in reservoir producibility” are defined in section 3130.0-5 of this rule. We received no substantive comment on this. We made one grammatical change to this section by revising existing paragraph

(d)to make it grammatically correct. Section 3137.41 What continuing development obligations must I define in a unit agreement? This rule amends the section on continuing development obligations by requiring that a unit agreement provide for the submission of supplemental or additional plans of development which obligate the operator to a program of exploration and development. The existing regulations require that the unit agreement actually obligate the operator to a program of exploration and development. The change recognizes that at the early stages of a unit agreement, an operator would not be able to identify the program of exploration and development and therefore it might not be possible for an operator to commit to one at that time. The rule allows an operator to submit plans of development later in the process, allowing the operator to collect additional data prior to requiring the operator to obligate itself to a program of exploration and development. We received no substantive comment on this section and it remains as proposed. Section 3137.80 What are participating areas and how do they relate to the unit agreement? This rule makes two changes to this section. The first change revises paragraph

(a)of the section by replacing “that contain” with “that are proven to be productive by.” The existing regulations imply that every committed tract within a participating area must contain a well that meets the productivity criteria specified in the unit agreement. The revision makes it clear that a participating area contains committed tracts in a unit area that are proven to be productive by a well meeting the productivity criteria specified in the unit agreement, but that not every committed tract in the participating area would necessarily contain a well meeting the productivity criteria. The second change this rule makes is to paragraph

(b)of this section. Under the new rule, an applicant is required to include “a description of the anticipated participating area(s) size in the unit agreement” rather than merely stating that the unit area “contain” a well meeting the productivity criteria (see existing section 3137.80(a)). This change makes it clear that the application must contain a description of the anticipated participating area size. We received no substantive comment on this section and it remains as proposed. Section 3137.81 What is the function of a participating area? The rule revises paragraph

(a)of this section by changing how the BLM allocates production, for royalty purposes, to each committed tract within the participating area. Under existing regulations, the BLM allocates to each committed tract within the participating area in the same proportion as that tract's surface acreage in the participating area to the total acreage in the participating area. Under this rule, the BLM allocates production for royalty purposes to each committed tract within the participating area using the allocation methodology agreed to in the unit agreement (see section 3137.23(g)). This change allows for variations in the reservoir geology and producibility when calculating allocations for royalty purposes. We received no substantive comment on this section and it remains as proposed. Section 3137.85 What is the effective date of a participating area or modified allocation schedule? This rule revises paragraph

(b)of this section by changing how the BLM determines the effective date of a modified participating area or modified allocation schedule. Under existing regulations, the effective date of a modified participating area or modified allocation schedule is the earlier of the first day of the month in which you:

(1)Complete a new well meeting the productivity criteria; or

(2)Should have known you need to revise the allocation schedule. Under this rule, the effective date of a modified participating area or allocation schedule is the earlier of the first day of the month in which you file a proposal for modification or such other date as may be provided in the unit agreement. It has been common practice with oil and gas units administered by the State of Alaska to allow for an earlier effective date when participating areas or allocation schedules are modified. The rule allows the BLM to approve an earlier effective date of the participating area, if it is warranted, consistent with the approach that the State of Alaska takes. Under this rule, rather than just determining a fair, current allocation of a revised participating area, the BLM is able to approve an effective date back in time. This allows corrections of past, errant allocations rather than just moving forward with a fair allocation from the time new information is acquired. This method of “backward-looking” reallocation creates a greater administrative workload for the BLM and the MMS, but it is the superior approach because it allows for corrections of allocations that were incorrect and helps to ensure that parties to the unit are treated equitably. We received no substantive comment on this section and it remains as proposed. Section 3137.111 When will BLM extend the primary term of all leases committed to a unit agreement or renew all leases committed to the unit? This rule revises this section by adding lease renewals to this section and referencing the rule governing extensions (43 CFR 3135.1-5). The EPAct of 2005 addresses lease renewals and provides for a renewal fee of $100 per acre for each lease in the unit that is renewed without a discovery under 43 CFR 3135.1-6 of this rule. Renewals are addressed under 43 CFR 3135.1-6 of this rule. This section incorporates those changes in this section of the NPR-A unit regulations. As a result of these changes and because the EPAct of 2005 addresses extensions and lease renewals, existing section 3137.111 is superseded by the statutory provisions that this rule implements. We received no substantive comment on this section and it remains as proposed. Section 3137.131 What happens if the unit terminated before the unit operator met the initial development obligations? Section 3137.134 What happens to committed leases if the unit terminates? These two existing sections address what happens to leases in a unit in the event a unit terminates. This rule revises these sections by adding the option of a lessee applying for a renewal upon unit termination and by adding a cross-reference to the lease renewal provisions in these final regulations. We received no substantive comments on these sections, but made minor changes to the final rule to make it clear that it is not enough to qualify for extension or renewal but that the BLM had to have granted the extension or renewal. III. Procedural Matters Executive Order 12866, Regulatory Planning and Review In accordance with the criteria in Executive Order 12866, this rule is not a significant regulatory action. The Office of Management and Budget makes the final determination under Executive Order 12866. a. This rule will not have an annual economic effect of $100 million or adversely affect an economic sector, productivity, jobs, the environment, or other units of government (see below). A cost-benefit and economic analysis is not required. b. This rule will not create inconsistencies with other agencies' actions. These rule changes are administrative in nature and will not effect other agencies' actions. There are provisions in the rule that require the BLM to consult with or request concurrence from the state, North Slope Borough, or the regional corporation before approving certain actions. These provisions are to the benefit of these other agencies because they help ensure that their rights are protected. These provisions will more than likely help ensure that the actions taken under this rule would not create inconsistencies with those agencies' actions. c. This rule will not materially affect entitlements, grants, user fees, loan programs, or the rights and obligations of their recipients. The one fee this rule implements (lease renewals without a discovery) is a per-acre fee mandated by Congress. As stated below, when compared to the scope and cost of operations in NPR-A, this fee is not significant. d. This rule will not raise novel legal or policy issues. All of the NPR-A oil and gas regulation changes that this rule implements are currently addressed similarly in other existing BLM regulations or policies. The following discusses the potential impacts of the rule changes: Waiver, Suspension, or Reduction of the Rental or Minimum Royalty or Reduction of the Royalty Rate The rule adds a provision that allows the BLM to waive, suspend, or reduce the rental or minimum royalty or reduce the royalty rate on an NPR-A lease if it is necessary to promote development or the BLM determines that the lease can not be successfully operated under the terms of the lease. The BLM will not allow for any of these to take place unless it is necessary to promote development or if we determine that the lease can not be successfully operated under the terms of the lease. Operators will benefit from this provision since they will be able to continue to operate their leases. The Federal Government will benefit since producible wells will not be shut in and the Federal Government will continue to receive revenue from wells that might otherwise be shut in, which may result in waste of Federal oil and gas. Furthermore, since this provision may reduce the risk of investment to lessees, it may result in higher bonus bids for new leases. State, local and tribal governments and communities will be positively affected since wells that would under other circumstances be shut in, will continue to produce, providing jobs and revenues to local areas. Any impacts on the economy, productivity, competition or jobs are anticipated to be positive, but they are too speculative to predict. Also, as a result of changes made to the NPRPA by the EPAct of 2005, the rule changes existing regulations by requiring the BLM to consult with the State of Alaska and the North Slope Borough within 10 days of receiving an application for waiver, suspension, or reduction of rental or minimum royalty or reduction of royalty. This provision could increase costs slightly for the BLM, the State of Alaska, and the North Slope Borough because under this rule these parties will be involved in consultation that is currently not required. However, consultation will help ensure that the rights of the state and the North Slope Borough are protected. The rule adds a new provision to the regulations stating that if a lease includes land that is made available for acquisition by a regional corporation under the Alaska National Interest Lands Conservation Act, the BLM will only approve a waiver, suspension, or reduction of rental or minimum royalty or a reduction of the royalty rate if the regional corporation concurs. This change is necessary because the EPAct requires concurrence from the regional corporation prior to approval of these actions. Concurrence by the regional corporation is not currently required. Therefore, this provision could minimally increase administrative costs for the Federal Government and for the regional corporation; however, requiring concurrence would help ensure that the rights of the regional corporation are protected. Additional Bonding Changes to the bonding regulations allow the BLM to require additional bonding under certain circumstances. The existing regulations only allow BLM to increase the bonding amount in the Special Areas as defined in the NPRPA. This rule allows the BLM to require an increase in the amount of an NPR-A lease bond for any NPR-A lease if the BLM determines that the operator poses a risk due to factors, including, but not limited to:

(A)A history of previous violations;

(B)A notice from the MMS that there are uncollected royalties due; or

(C)The total cost of plugging existing wells and reclaiming lands exceeds the present bond amount based on the estimates determined by the BLM. The rule change makes the existing regulations on bonding of NPR-A leases consistent with the Mineral Leasing Act regulations that currently apply to Federal oil and gas leases outside of the NPR-A. The BLM has used this authority on lands leased under the Mineral Leasing Act. The increases have most often been based on the significant liabilities that an operator has under a single bond. Under these circumstances, the average bond increase has been about 200 percent. While it is not possible, at this time, to predict how much any specific bond amount might be increased once this provision is effective, increasing an area-wide NPR-A bond ($300,000) by 200 percent would make the increased bond amount $900,000. This is more consistent with bonding of other agencies on the North Slope than is the area-wide bond amount under existing regulations. For example, the State of Alaska requires bonding of $700,000 for multiple oil wells and the MMS requires bonding of $3,000,000 for offshore development. This provision will economically impact only those operators who have a history of previous violations, those who have uncollected royalties that are due, and those who have leases where the total cost of plugging existing wells and reclaiming lands exceeds the present bond amount based on the estimates determined by the BLM. We expect the economic impact to these operators to be minimal when compared to the value of an oil and gas lease in the NPR-A, and when compared to the additional protection the Federal Government and Federal lands will receive. A typical development in NPR-A is expected to produce approximately 20,000 barrels per day or 7,300,000 barrels per year. With a market price of $60 per barrel 1 in the lower 48 states and approximately $8 in transportation costs per barrel to get the oil from NPR-A to the lower 48 states, the wellhead price would be approximately $52 per barrel. 1 According to the Alaska Department of Revenue, Tax Division, the per-barrel price for oil between January 2005 and April 2006 fluctuated between $41.12 and $67.74 per barrel. We cannot predict price fluctuations in the future; however, $60 represents an estimate of average prices expected. A typical bond amount for a lease in the NPR-A is approximately $300,000. Raising the bonding requirement from $300,000 to $900,000, makes the annual bonding fee the operator will pay go from approximately $3,000 per year to $9,000 per year (the cost of a surety bond is approximately 1% per year), an increase of $6,000 per year. How does that compare to other costs the operator faces? The transportation cost to get the production to the lower 48 states is approximately $58,400,000 per year. Receipts at the wellhead are approximately $379,600,000 per year. The lifting costs are about $33,000,000. Royalties are approximately $47,450,000 per year. We anticipate that a $6,000 increase in costs per year will have minimal impact on the operator. Effect of Transfer of a Tract-Segregation This rule changes the standard that the BLM applies when determining if a segregated lease should continue in full force and effect. The existing standard is that a segregated lease remains in full force and effect if the BLM determines that oil and gas is being produced in paying quantities from that segregated portion of the lease area or so long as drilling or well reworking operations, either actual or constructive, are being conducted. The new standard is that a lease will continue in full force and effect as long as oil or gas is produced or is capable of being produced from the lease in paying quantities or drilling or reworking operations, actual or constructive, as approved by the BLM, are being conducted on the lease. We anticipate that this rule change will have the same economic impact as discussed under the “Lease Extension” and “Lease Renewal” sections since the segregated lease will be able to be extended or renewed based on the same criteria used for all NPR-A leases. Lease Extension Existing regulations on lease extensions require that the BLM extend the term of a lease beyond its primary term so long as:

(A)Oil or gas is produced from the lease in paying quantities; or

(B)Drilling or reworking operations, actual or constructive, as approved by the BLM, are being conducted on the lease. This final rule adds a new condition under which the BLM will grant a lease extension in cases where the BLM has determined that oil or gas is capable of being produced in paying quantities from the lease. This rule also adds a new provision that explains that NPR-A leases expire on the 30th anniversary of the original issuance date of the lease unless oil or gas is being produced from the lease. This provision is required by the EPAct of 2005. Prior to the EPAct of 2005, NPR-A lease terms were fixed at 10 years. Longer lease terms as a result of extensions are preferable since there are harsh climatic conditions and a short “winter only” exploration window in the NPR-A that make it difficult to operate in that region. Extensions of lease terms allow operators additional time to deal with these conditions. Under the existing regulations, the long lead time between exploration and production on the North Slope (6-8 years) reduces the incentive for operators to explore on leases with less than 6-8 years left in their primary term. The new rule provides incentives for operators to continue exploration in the later years of the primary term of the lease. The timeframe for bringing a gas discovery to production is even longer. Without a gas pipeline to the North Slope, operators currently have little incentive to explore in gas-prone areas or to further delineate gas discoveries. The new rule may have the effect of increasing the value of the NPR-A leases, increasing the level of exploration activity, and increasing the likelihood of eventual production from NPR-A leases. The value of these benefits, if any, is too speculative to predict. These changes also have minor administrative savings and economic benefit to operators and to the Federal Government since lessees will not be required to file for lease extensions as frequently and since the Federal Government will not be required to process those lease extensions. Lease Renewal This final rule adds a new section on lease renewals based on changes the EPAct of 2005 made to the NPRPA. The rule addresses lease renewals in two parts: those leases that have a discovery of hydrocarbons and those leases that do not have a discovery. *With a Discovery.* Under this section, the BLM may approve a 10-year lease renewal for a lease on which there has been a well drilled and a discovery of hydrocarbons, even if the BLM had determined that the well is not capable of producing oil or gas in paying quantities. This section requires that the applicant provide evidence that oil or gas has been discovered on the leased lands in such quantities that a prudent operator would hold the lease for potential future development. This regulatory change is required by the EPAct of 2005. The economic impact of this provision will be positive. Existing regulations do not provide for lease renewals, but do provide for lease extensions if there is actual production or as long as drilling and reworking operations are being conducted. This provision allows for lease renewal for a 10-year term if a discovery was made and a prudent operator would hold the lease for future development. This provision provides an incentive for an operator to explore, even if there is not enough time to meet the current conditions for lease extensions. This change allows the lessee another 10 years to explore and develop the lease without having to compete for the lease again in a subsequent lease sale. Leases in the NPR-A typically are either 5,760 or 11,520 acres and the average high bid is approximately $70 per acre. The Federal Government may be foregoing between $400,000 and $800,000 for each of these lease renewals, since lessees who were granted a lease renewal would not be required to compete for a new lease for the same lands. In exchange for this “opportunity cost” the lease has a much greater likelihood of being developed and developed sooner. It is also possible that without the option of renewal, the lease which has been explored without a paying well discovery would have less value and not receive bids in the next sale. In this case, the United States would lose the value of lease rental ($60,000-$150,000 per year). Lease bonuses and lease rentals are both lesser considerations for the United States in realizing the value of leased lands, however. The value of potential production from an NPR-A lease far exceeds either of these revenue streams. A typical North Slope development produces about 20,000 barrels of oil per day. At a $60 per barrel oil price, the United States would collect between $45 and $60 million dollars per year in royalties. If the renewals make the likelihood of development greater, the identified “opportunity costs” are viewed as beneficial to the United States. Furthermore, this could reduce risk of investment to the lessee, which may increase bonus bids on future leases. *Without a Discovery.* Under this section, the BLM could approve an application for a 10-year lease renewal for a lease on which there has not been a discovery of oil or gas. Under this rule, the renewal application must:

(B)Show that all or part of the lease is part of a unit agreement covering a lease that qualifies for renewal without a discovery and that the lease has not been previously contracted out of the unit. If the BLM approves an application for lease renewal, the applicant will be required to submit to the BLM a fee of $100 per acre within 5 working days of receiving notification of the renewal approval. This fee is mandated by the EPAct of 2005. As discussed above, existing regulations do not allow for lease renewals, only lease extensions if there is actual production or as long as drilling and reworking operations are being conducted. This new provision allows for lease renewal without a discovery under certain circumstances and would require that lessees pay a fee of $100 per acre for the renewal. The economic impact of this provision will be minimal. As with lease renewal with a discovery, this provision provides the lessee with incentive to explore, even if there is not sufficient time to take actions to qualify for a lease extension. As discussed above, the cost to obtain the lease in a subsequent sale will likely be around $70 per acre. The new rule allows the lessee to retain the lease without competition or the risk of loss of the lease, for a cost above what it might cost in a competitive lease sale, but it allows the operator to seamlessly pursue exploration. This is likely to have the effect of accelerating the eventuality of bringing the lease into production. It is also possible, as discussed above, that without the option of renewal the lease which has been explored without a discovery would have less value and not receive bids in the next sale. In this case the United States would lose the value of lease rental ($60,000-$150,000 per year). Furthermore, nothing compels a lessee to apply for a lease renewal and pay the per acre fee. If the lessee believes the lease may be valuable, but not worth $100 per acre, he can relinquish the lease and try to obtain it at a lower price in a subsequent competitive lease sale. Operators may still apply for lease extensions under the revised provisions of this rule. Operators may also apply for a renewal under other provisions of this rule and avoid paying the fee by a discovery and a showing that a prudent operator would hold the lease for future development. The new rule has the effect of allowing the government to be compensated for the lease without having the administrative costs of conducting a new lease sale. The new rule also increases the likelihood of production and royalty payments at an earlier date. The value of potential production from an NPR-A lease far exceeds the value of lease bonuses. A typical North Slope development produces about 20,000 barrels of oil per day. At a $60 per barrel oil price, the United States would collect between $45 and $60 million dollars per year in royalties. This provision could lower the risk of investment to the lessee and possibly result in higher bonus bids at future lease sales. Like other changes this rule makes, any benefits of this provision are too speculative to predict. Lease Consolidation This rule revises the consolidation provisions in existing regulations having to do with the term of a consolidated lease. Under existing regulations, the term of a consolidated lease is extended beyond the primary term of the lease only as long as oil or gas is produced in paying quantities or approved constructive or actual drilling or reworking operations are conducted on the lease. Under this rule, the term of a consolidated lease will be extended or renewed, as appropriate, under the extension or renewal provisions of the regulations. The change recognizes that the new standards in the extension and renewal provisions of this rule apply to consolidated leases. We expect that this rule change will have the same economic impacts as discussed under the “Lease Extension” and “Lease Renewal” sections above, i.e., it could have the effect of increasing the value of the NPR-A leases, increasing the level of exploration activity, increasing the likelihood of production from NPR-A leases, and increasing future bonus bids. Termination of Administration for Conveyed Lands and Segregation This rule adds a new section concerning the waiver of administration for conveyed lands in a lease. This new section is necessary because of changes that the EPAct of 2005 made to the NPRPA. Under this new section, the BLM is required to terminate administration of any oil and gas lease if all of the mineral estate is conveyed to a regional corporation. The regional corporation would then assume the lessor's obligation to administer any oil and gas lease. This provision does not provide the authority to convey the mineral estate to the regional corporation, only that once a conveyance is made, the BLM would no longer administer any oil and gas lease. This change will have a minor positive economic impact on the Federal Government because costs for administration of these types of leases would no longer be borne by the BLM. Under this final rule, the regional corporation would be responsible for administration and likewise be responsible for administrative costs. This section explains that if a conveyance of the mineral estate does not include all of the land covered by an oil and gas lease, the lease would be segregated into two leases, one of which will cover only the mineral estate conveyed. The regional corporation would assume administration of the lease within the conveyed mineral estate. The segregation of a lease would not impair the mineral estate owners' rights to royalties for oil and gas produced from, or allocated to, their portions of land covered by the lease. This provision is purely administrative in nature and will have a minimal economic impact. We expect that it will decrease administrative costs for the Federal Government and increase the administrative costs to regional corporations for leases that have been conveyed. Change to the Definition of Participating Area This rule makes one change to the definition of “participating area” by replacing the word “contain” with the phrase “are proven to be productive by.” Existing regulations are not clear that a committed tract does not need to contain a well that meets the productivity criteria specified in the unit agreement. Instead, a unit well meeting the productivity criteria proves that the committed tract is productive. This change has no economic impact since this change merely clarifies existing policy. Consultation If Lands in the Unit Area Are Owned by the Regional Corporation or the State of Alaska This rule adds a new section on consultation if lands in a unit are owned by a regional corporation or the State of Alaska. This section is based on changes that the EPAct of 2005 made to the NPRPA. The new section requires that if the BLM administers a unit containing tracts where the mineral estate is owned by a regional corporation or the State of Alaska, or if a proposed unit contains tracts where the mineral estate is owned by a regional corporation or the State of Alaska, the BLM will consult with and provide opportunities for participation with respect to the creation or expansion of the unit by:

(A)The regional corporation, if the unit acreage contains the regional corporation's mineral estate; or

(B)The State of Alaska, if the unit acreage contains the state's mineral estate. The rule will have minor economic impacts on the BLM, the State of Alaska, and the regional corporation. All parties involved in the consultation could incur minor additional costs; however, consultation will help ensure that the rights of all parties to the unit are protected. NPR-A Unitization Application The final rule requires the unit application to explain the proposed methodology for allocating production among the committed tracts. If a unit includes non-Federal mineral estate, the applicant is required to explain how the methodology would take into account reservoir heterogeneity and area variation in reservoir producibility. These changes are necessary because of changes that the EPAct of 2005 made to the NPRPA. The economic impacts of this provision are expected to be minor, but not measurable, since the change will impact different unit agreements differently. However, the rule will help to ensure fair allocation of production among unit participants and ensure that the Federal Government receives the correct royalty payment. Continuing Development Obligations in a Unit Agreement This final rule amends the provisions on continuing development obligations in existing regulations by requiring that a unit agreement provide for the submission of supplemental or additional plans of development which obligate the operator to a program of exploration and development. The existing regulations require that the unit agreement actually obligate the operator to a program of exploration and development. The change recognizes that at the early stages of a unit agreement, an operator may not be able to identify the program of exploration and development and therefore it might not be possible for an operator to commit to one at that time. The rule allows an operator to submit plans of development later in the process, allowing for the operator to collect additional data prior to requiring the operator to obligate itself to a program of exploration and development. Under the existing process, because the data may be incomplete, the operator may be required to submit information several times as the data becomes available. The new provision will likely have minor positive economic benefits for applicants and the BLM since it allows commitment to a program of exploration and development at a more appropriate time when sufficient data is available. Participating Areas This final rule makes two changes to the provisions on participating areas. The first change makes it clear that a participating area contains committed tracts in a unit area that are proven to be productive by a well meeting the productivity criteria specified in the unit agreement. The second change is that this rule makes it clear that the unit agreement must contain a description of the anticipated participating area size. Neither of these changes will have an economic impact because they merely clarify existing policy. Function of a Participating Area The rule revises the participating area provisions of existing rules by changing how the BLM allocates production, for royalty purposes, to each committed tract within the participating area. Under existing regulations, the BLM allocates to each committed tract within the participating area in the same proportion as that tract's surface acreage in the participating area to the total acreage in the participating area. Under this final rule, the BLM allocates production for royalty purposes to each committed tract within the participating area using the allocation methodology agreed to in the unit agreement. This change allows for variations in the reservoir geology and producibility when calculating allocations for royalty purposes. This change implements changes mandated by Congress in the EPAct of 2005. This rule change will have little economic impact to industry or the Federal Government, but will help ensure proper production allocations on a case-by-case basis. Effective Date of a Participating Area This rule revises how the BLM determines the effective date of a modified participating area or modified allocation schedule. Under existing regulations, the effective date of a modified participating area or modified allocation schedule is the earlier of the first day of the month in which you:

(1)Complete a new well meeting the productivity criteria; or

(EA)and has found that the rule does not constitute a major Federal action significantly affecting the quality of the human environment under Section 102(2)(C) of the National Environmental Policy Act (NEPA), 42 U.S.C. 4332(2)(C). A detailed statement under NEPA is not required. The BLM has placed the EA and the Finding of No Significant Impact on file in the BLM Administrative Record at the address specified in the ADDRESSES section. The action of modifying the existing regulations will have very little impact on the environment. The new regulations create more favorable lease terms for oil and gas companies (e.g., allowing lease extensions and renewals, potential for relief from royalty, rental and minimum royalty) and this may increase the likelihood of exploration and development in the NPR-A. The revised regulations also allow the BLM greater flexibility in granting relief from rentals and royalty which may also have the effect of encouraging development. But while the likelihood of exploration and development may be greater, the character or intensity of exploration and development remains unchanged. The potential impacts from exploration and development have been addressed in three environmental impact statements

(EIS)written for the Integrated Activity Plans for the Northeast and Northwest NPR-A, seven EAs written for individual exploration proposals, and the Alpine Satellites Development EIS. To the extent that recent Court decisions may require further NEPA analysis with respect to the environmental impacts of proposed leasing in the NPR-A, the BLM would address such analysis within the context of its consideration of land use planning and any proposed leasing. However, these regulations do not invoke any significant environmental impact requiring additional NEPA analysis beyond the environmental assessment. The revised regulations may also have the effect of allowing the oil and gas operators to pursue exploration and development at a more measured pace since terms of the lease can be extended beyond what was previously available. The change to bonding levels will provide the BLM more certainty that environmental obligations, such as reclamation and well plugging, are honored. We expect that this will lessen the likelihood of adverse environmental impacts to the NPR-A. Changes in the regulations that require:

(1)The BLM to allow participation from the regional corporation and the State of Alaska in the creation and expansion of oil and gas units;

(2)Consultation with the regional corporation, State of Alaska, and the North Slope Borough when considering relief from royalty, rentals, or minimum royalty;

(3)Allocation of production based on reservoir characteristics; and

(4)The BLM to give the regional corporation administration of leases conveyed to the regional corporation, are strictly administrative in nature and will have no effect on the environment. This view as to the minimal environmental effects of the changes in the regulations is consistent with the Department's previously expressed policies as indicated by provisions of the Departmental Manual

(DM)which establish categorical exclusions under NEPA for actions by the BLM of the type addressed by these regulations. The categorical exclusions include “(3) Approval of unitization [ *sic* ] agreements * * *

(4)Approval of suspensions of operations, *force majeure* suspensions, and suspensions of operations and production.” See 516 DM Chapter 11.9B(3) and

(4)(72 FR 45504, 45539 (August 14, 2007)). Regulatory Flexibility Act Congress enacted the Regulatory Flexibility Act

(RFA)of 1980, as amended, 5 U.S.C. 601-612, to ensure that Government regulations do not unnecessarily or disproportionately burden small entities. The RFA requires a regulatory flexibility analysis if a rule would have a significant economic impact, either detrimental or beneficial, on a substantial number of small entities. This rule will not have a significant economic effect on a substantial number of small entities as defined under the RFA. An initial or final Regulatory Flexibility Analysis is not required. Accordingly, a Small Entity Compliance Guide is not required. The BLM cannot determine how many lessees may qualify as small businesses or how many will be adversely affected by this rule because the BLM does not track this type of information and it is not readily available. The BLM believes that several of the types of businesses identified in the North American Industrial Classification System (NAICS) (codified in the Small Business Administration regulations at 13 CFR 121.201) may do business in the NPR-A. These businesses, NAICS codes, and size standards in millions of dollars in receipts annually or number of employees are listed in the following table: NAICS code NAICS U.S. industry title Size standard in millions of dollars Size standard in number of employees 211111 Crude Petroleum and Natural Gas Extraction 500 211112 Natural Gas Liquid Extraction 500 213111 Drilling Oil and Gas Wells 500 213112 Support Activities for Oil and Gas Operations 6.5 237120 Oil and Gas Pipeline and Related Structures Construction 31 As stated above, the businesses in the table represent ones that may operate in NPR-A. However, we do not believe that businesses with the NAICS codes 213111, 213112, or 237120 will be impacted by the changes this rule makes to the current regulations. Of the businesses listed in the table, businesses with NAICS codes 211111 and 211112 may be impacted by the changes this rule makes because the regulatory changes primarily affect lessees, and lessees may fall into one or both of these two categories. Due to the scale and cost of operations on the North Slope (see the discussion under Executive Order 12866 above), it is not likely that operators in NPR-A will be small businesses. Furthermore, the BLM is unaware of any small businesses operating on lands in NPR-A under existing regulations, and because of the large scale and high cost of operations in NPR-A, we do not anticipate that small businesses will enter the market in the future. Even if a small business did begin doing business in NPR-A, when compared to the costs of operating in the NPR-A and the potential receipts involved if production were to take place (see the discussion under Executive Order 12866 above), the impact of this rule will be minimal. Therefore, the changes will likely not have a significant economic effect on a substantial number of small entities. Small Business Regulatory Enforcement Fairness Act This rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule: a. Does not have an annual effect on the economy of $100 million or more. Please see the discussion under Executive Order 12866 above. b. Will not cause a major increase in costs or prices for consumers, individual industries, Federal, state, or local government agencies, or geographic regions. Please see the discussion under Executive Order 12866. c. 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. These rule changes should have no adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises because their impact, economic and otherwise, will be minimal. Unfunded Mandates Reform Act In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501, *et seq.* ): a. This rule will not “significantly or uniquely” affect small governments. A Small Government Agency Plan is not required. b. This rule will not produce a Federal mandate of $100 million or greater in any year, i.e., it is not a “significant regulatory action” under the Unfunded Mandates Reform Act. This final rule will not mandate additional expenditures by any state or local government, any Federal agency, or any other entity. The State of Alaska and the regional corporation may incur minor additional expenses under the consultation provisions of this rule, but the consultations are for the benefit of those parties. Executive Order 12630, Governmental Actions and Interference With Constitutionally Protected Property Rights (Takings) The final rule does not represent a government action capable of interfering with constitutionally protected property rights. The rule primarily extends benefits to leaseholders. The cost of additional bonding is too minor to constitute a taking. Therefore, the Department of the Interior has determined that the rule will not cause a taking of private property or require further discussion of takings implications under this Executive Order. Executive Order 13132, Federalism The final rule will not have a substantial direct effect on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. In accordance with Executive Order 13132, the rule does not have significant Federalism implications. A Federalism assessment is not required. The rule has the potential for a minimal effect on the states, on the relationship between the national government and the states, and on the distribution of power and responsibilities among the various levels of government. There are certain consultation provisions in the rule where the state would be invited to participate in the discussion of the creation or expansion of Federal unit agreements in NPR-A which contain state lands. The consultation burden is minimal and it is in the interest of the state to participate to help ensure that allocations to the state were fair. Executive Order 12988, Civil Justice Reform Under Executive Order 12988, the Office of the Solicitor has determined that this rule does not unduly burden the judicial system and that it meets the requirements of sections 3(a) and 3(b)(2) of the Order. The BLM has worked closely with the Office of the Solicitor to help ensure that the rule is written clearly and to help eliminate drafting errors. Executive Order 13175, Consultation and Coordination With Indian Tribal Governments Executive Order 13175 (E.O. 13175) provides that Federal agencies must consult with Indian Tribal Governments before formal promulgation of regulations “that have Tribal implications.” E.O. 13175 defines “Indian Tribes” for purposes of government-to-government consultation as those “that the Secretary of the Interior acknowledges to exist as an Indian tribe pursuant to the Federally Recognized Indian Tribe List Act of 1994, 25 U.S.C. 479a” (E.O. 13175 at section 1(b)). In accordance with this mandate, the Bureau of Indian Affairs recently published a list of recognized tribes, including a large number of Native Alaskan entities including villages, communities, and tribes (see 72 FR 13648 (March 22, 2007)). If there were a duty of government-to-government consultation, prior to promulgation of these regulations, it would be owed to those listed tribal governments. None of the recognized tribal governments have significant oil and gas interests within NPR-A or within the vicinity of NPR-A. Therefore, nothing in these final regulations has “substantial direct effects on one or more Indian tribes, on the relationship between the Federal government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes” (see section 1(a) of E.O. 13175). Accordingly, the final regulations do not have tribal implications and there is no government-to-government consultation obligation in this case. Additionally, we are aware that a number of Alaska regional corporations organized under the Alaska Native Claims Settlement Act (43 U.S.C. 1601 *et seq.* ) (ANCSA) may own an interest in the mineral estate. The rule provides for consultation with the regional corporation in accordance with the requirements of the EPAct of 2005 if a unit or a proposed unit contains tracts where the mineral estate is owned by a regional corporation. Also, the rule provides for concurrence by the regional corporation before the BLM approves a waiver, suspension, or reduction of rental or minimum royalty or a reduction of royalty under section 3133.3 if the lease includes land that was made available for acquisition by the regional corporation under Section 1431(o) of the Alaska National Interest Lands Conservation Act (ANILCA) (Pub. L. 96-487). Additionally, these corporations could potentially become participants in units that include Federal NPR-A leases. If so, they would be eligible to participate in those unit agreements in the same manner as any other participants. However, no special consultation beyond that required by the EPAct of 2005 or by these rules with such corporations is required as a matter of law. The Bureau of Indian Affairs has recently declined to include such corporations on the list of recognized tribes eligible for government-to-government consultation (see 72 FR 13648 (March 22, 2007)). The Bureau of Indian Affairs previously indicated that ANCSA corporations are formally state-chartered corporations rather than tribes in the conventional legal or “political sense” and that Alaskan Native Villages were Indian tribes. See “Indian Entities Recognized and Eligible to Receive Services From the United States Bureau of Indian Affairs,” (60 FR 9250 (February 16, 1995)). The BLM provided opportunity for the tribal governments, along with the public generally, to comment during the comment period, in accordance with the notice and comment requirements of the Administrative Procedure Act. We received no comments from tribes on the proposed rule. Therefore, in accordance with E.O. 13175, we have found that this rule does not include policies that have tribal implications. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use In accordance with Executive Order 13211, the BLM has determined that the final rule will not have significant adverse effects on the energy supply, distribution or use, including a shortfall in supply or price increase. For the most part, this rule does not represent the exercise of agency discretion inasmuch as a substantial portion of this rule is mandated by the EPAct of 2005. Congress' mandate to amend the BLM's existing NPR-A oil and gas regulations may result in an increase in oil and gas production of unknown amounts. Executive Order 13352, Facilitation of Cooperative Conservation In accordance with Executive Order 13352, the BLM has determined that this rule does not impede facilitating cooperative conservation; takes appropriate account of and considers the interests of persons with ownership or other legally recognized interests in land or other natural resources; properly accommodates local participation in the Federal decision-making process; and provides that the programs, projects, and activities are consistent with protecting public health and safety. The rule may positively affect the facilitation of cooperative conservation because the rule seeks to add provisions to the existing NPR-A oil and gas regulations requiring that the BLM consult with the regional corporation and the state in certain circumstances where consultation is not currently required. Paperwork Reduction Act The BLM has determined that this rulemaking does not contain any new information collection requirements that the Office of Management and Budget must approve under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 *et seq.* ). Data Quality Act When the BLM developed this rule, it did not conduct or use a study, experiment, or survey requiring peer review under the Data Quality Act (Pub. L. 106-554, Appendix C, § 515, 114 Stat. 2763, 2763A-153-154). Authors The principal authors of this rule are Greg Noble, Chief, Energy Branch, Bureau of Land Management, Alaska State Office, and Erick Kaarlela, Special Assistant to the Assistant Director, Minerals, Realty and Resource Protection, assisted by the Department of the Interior Office of the Solicitor and BLM's Division of Regulatory Affairs, Washington, DC. List of Subjects in 43 CFR Part 3130 Alaska, Government contracts, Mineral royalties, Oil and gas exploration, Oil and gas reserves, Public lands—mineral resources, Reporting and recordkeeping requirements, Surety bonds. Dated: January 18, 2008. C. Stephen Allred, Assistant Secretary, Land and Minerals Management. For the reasons stated in the preamble, the BLM amends 43 CFR part 3130 as set forth below: PART 3130—OIL AND GAS LEASING: NATIONAL PETROLEUM RESERVE, ALASKA 1. The authority citation for part 3130 is revised to read as follows: Authority: 42 U.S.C. 6508, 43 U.S.C. 1733 and 1740. § 3130.0-3 [Amended] 2. Amend § 3130.0-3 by adding a new paragraph

(d)to read as follows:

(d)The Energy Policy Act of 2005 (42 U.S.C. 6506a(o)). 3. Amend § 3130.0-5 by adding three new paragraphs (g), (h), and

(i)to read as follows: § 3130.0-5 Definitions.

(g)*Production allocation methodology* means a way of attributing the production of oil and gas produced from a unit well or wells to individual tracts committed to the unit and forming a participating area.

(h)*Reservoir heterogeneity* means spatial differences in the oil and gas reservoir properties. This can include, but is not limited to, the thickness of the reservoir, the amount of pore space in the reservoir rock that contains oil, gas, or water, and the amount of water contained in the reservoir rock. This information may be used to allocate production.

(i)*Variation in reservoir producibility* means differences in the rates oil and gas wells produce from the reservoir. These differences can result from variations in the thickness of the reservoir, porosity, and the amount of connected pore space. 4. Amend § 3133.3 by revising paragraphs

(a)introductory text, (a)(2), and

(b)and by adding a new paragraph

(c)to read as follows: § 3133.3 Under what circumstances will BLM waive, suspend, or reduce the rental, or minimum royalty, or reduce the royalty rate on my NPR-A lease?

(a)BLM will waive, suspend, or reduce the rental or minimum royalty or reduce the royalty rate on your lease if BLM finds that—

(1)* * *

(2)It is necessary to promote development or the BLM determines the lease cannot be successfully operated under the terms of the lease.

(b)The BLM will consult with the State of Alaska and the North Slope Borough within 10 days of receiving an application for waiver, suspension, or reduction of rental or minimum royalty, or reduction of the royalty rate and will not approve an application under § 3133.4 of this subpart until at least 30 days after the consultation.

(c)If your lease includes land that was made available for acquisition by a regional corporation (as defined in 43 U.S.C. 1602) under the provision of Section 1431(o) of the Alaska National Interest Lands Conservation Act (ANILCA) (16 U.S.C. 3101 *et seq.* ), the BLM will only approve a waiver, suspension, or reduction of rental or minimum royalty, or reduction of the royalty rate if the regional corporation concurs. 5. Amend § 3133.4 by revising paragraphs (a)(5), (a)(6), and (a)(7) to read as follows: § 3133.4 How do I apply for a waiver, suspension or reduction of rental or minimum royalty or a reduction of the royalty rate for my NPR-A lease?

(a)* * *

(5)A detailed statement of expenses and costs of operating the entire lease, including the amount of any overriding royalty and payments out of production or similar interests applicable to your lease;

(6)All facts that demonstrate the waiver, suspension, or reduction of the rental or minimum royalty, or the reduction of the royalty rate encourages the greatest ultimate recovery of oil or gas or it is in the interest of conservation; and

(7)All facts that demonstrate you cannot successfully operate the lease under the terms of the lease; 6. Amend § 3134.1-2 by revising paragraph

(a)to read as follows: § 3134.1-2 Additional bonds.

(a)The authorized officer may require the bonded party to supply additional bonding in accordance with § 3104.5(b) of this chapter. 7. Revise § 3135.1-4 to read as follows: § 3135.1-4 Effect of transfer of a tract.

(a)When a transfer is made of all the record title to a portion of the acreage in a lease, the transferred and retained portions are divided into separate and distinct leases. The BLM will not approve transfers of a tract of land:

(1)Of less than 640 acres that is not compact; or

(2)That would leave a retained tract of less than 640 acres.

(b)Each segregated lease shall continue in full force and effect for the primary term of the original lease and so long thereafter as the activities on the segregated lease support extension in accordance with § 3135.1-5. 8. Revise § 3135.1-5 to read as follows: § 3135.1-5 Extension of lease.

(a)The term of a lease shall be extended beyond its primary term:

(1)So long as oil or gas is produced from the lease in paying quantities;

(2)If the BLM has determined in writing that oil or gas is capable of being produced in paying quantities from the lease; or

(3)So long as drilling or reworking operations, actual or constructive, as approved by the BLM, are conducted thereon.

(b)Your lease will expire on the 30th anniversary of the original issuance date of the lease unless oil or gas is being produced in paying quantities. If your lease contains a well that is capable of production, but you fail to produce the oil or gas due to circumstances beyond your control, you may apply for a suspension under § 3135.2. If the BLM approves the suspension, the lease will not expire on the 30th anniversary of the original issuance date of the lease.

(c)A lease may be maintained in force by the BLM-approved directional wells drilled under the leased area from surface locations on adjacent or adjoining lands not covered by the lease. In such circumstances, drilling shall be considered to have commenced on the lease area when drilling is commenced on the adjacent or adjoining lands for the purpose of directional drilling under the leased area through any directional well surfaced on adjacent or adjoining lands. Production, drilling or reworking of any such directional well shall be considered production or drilling or reworking operations on the lease area for all purposes of the lease. 9. Redesignate § 3135.1-6 as § 3135.1-7 and add a new § 3135.1-6 to read as follows: § 3135.1-6 Lease Renewal.

(a)*With a discovery* —(1) At any time after the fifth year of the primary term of a lease, the BLM may approve a 10-year lease renewal for a lease on which there has been a well drilled and a discovery of hydrocarbons even if the BLM has determined that the well is not capable of producing oil or gas in paying quantities. The BLM must receive the lessee's application for lease renewal no later than 60 days prior to the expiration of the primary term of the lease.

(2)The renewal application must provide evidence, and a certification by the lessee, that the lessee or its operator has drilled one or more wells and discovered producible hydrocarbons on the leased lands in such quantities that a prudent operator would hold the lease for potential future development.

(3)The BLM will approve the renewal application if it determines that a discovery was made and that a prudent operator would hold the lease for future development.

(4)The lease renewal will be effective on the day following the end of the primary term of the lease.

(5)The lease renewal may be approved on the condition that the lessee drills one or more additional wells or acquires and analyzes more well data, seismic data, or geochemical survey data prior to the end of the primary term.

(b)*Without a discovery* —(1) At any time after the fifth year of the primary term of a lease, the BLM may approve an application for a 10-year lease renewal for a lease on which there has not been a discovery of oil or gas. The BLM must receive the lessee's application no later than 60 days prior to the expiration of the primary term of the lease.

(2)The renewal application must:

(i)Provide sufficient evidence that the lessee has diligently pursued exploration that warrants continuation of the lease with the intent of continued exploration or future potential development of the leased land. The application must show the:

(A)Lessee or its operator has drilled one or more wells or has acquired and analyzed seismic data, or geochemical survey data on a significant portion of the leased land since the lease was issued;

(B)Data collected indicates a reasonable probability of future success; and

(C)Lessee's plans for future exploration; or

(ii)Show that all or part of the lease is part of a unit agreement covering a lease that qualifies for renewal without a discovery and that the lease has not been previously contracted out of the unit.

(3)The BLM will approve the renewal application if it determines that the application satisfies the requirements of paragraph (b)(2)(i) or

(ii)of this section. If the BLM approves the application for lease renewal, the applicant must submit to the BLM a fee of $100 per acre within 5 business days of receiving notification of approval.

(4)The lease renewal will be effective on the day following the end of the primary term of the lease.

(5)The lease renewal may be approved on the condition that the lessee drills one or more additional wells or acquires and analyzes more well data, seismic data or geochemical survey data prior to the end of the primary term.

(c)*Renewed lease.* The renewed lease will be subject to the terms and conditions applicable to new oil and gas leases issued under the Integrated Activity Plan in effect on the date that the BLM issues the decision to renew the lease. 10. Amend newly designated § 3135.1-7 by revising paragraph

(d)and by adding a new sentence to the end of paragraph

(e)to read as follows: § 3135.1-7 Consolidation of leases.

(d)The effective date, the anniversary date, and the primary term of the consolidated lease will be those of the oldest original lease involved in the consolidation. The term of a consolidated lease may be extended, or renewed, as appropriate, beyond the primary lease term under § 3135.1-5 or 3135.1-6.

(e)* * * The highest royalty and rental rates of the original leases shall apply to the consolidated lease. 11. Add a new § 3135.1-8 to read as follows: § 3135.1-8 Termination of administration for conveyed lands and segregation.

(a)If all of the mineral estate is conveyed to a regional corporation, the regional corporation will assume the lessor's obligation to administer any oil and gas lease.

(b)If a conveyance of the mineral estate does not include all of the land covered by an oil and gas lease, the lease will be segregated into two leases, one of which will cover only the mineral estate conveyed. The regional corporation will assume administration of the lease covering the conveyed mineral estate.

(c)If the regional corporation assumes administration of a lease under paragraph

(a)or

(b)of this section, all lease terms, BLM regulations, and BLM orders in effect on the date of assumption continue to apply to the lessee under the lease. All such obligations will be enforceable by the regional corporation as the lessor until the lease terminates.

(d)In a case in which a conveyance of a mineral estate described in paragraph

(b)of this section does not include all of the land covered by the oil and gas lease, the owner of the mineral estate in any particular portion of the land covered by the lease is entitled to all of the revenues reserved under the lease as to that portion including all of the royalty payable with respect to oil or gas produced from or allocated to that portion. 12. Amend § 3137.5 by revising the definition of “Participating area” to read as follows: § 3137.5 What terms do I need to know to understand this subpart? *Participating area* means those committed tracts or portions of those committed tracts within the unit area that are proven to be productive by a well meeting the productivity criteria specified in the unit agreement. 13. Add a new § 3137.11 to read as follows: § 3137.11 What consultation must the BLM perform if lands in the unit area are owned by a regional corporation or the State of Alaska? If the BLM administers a unit containing tracts where the mineral estate is owned by a regional corporation or the State of Alaska, or if a proposed unit contains tracts where the mineral estate is owned by a regional corporation or the State of Alaska, the BLM will consult with and provide opportunities for participation in negotiations with respect to the creation or expansion of the unit by—

(a)The regional corporation, if the unit acreage contains the regional corporation's mineral estate; or

(b)The State of Alaska, if the unit acreage contains the state's mineral estate. 14. Amend § 3137.21 by revising paragraph (a)(3), redesignating paragraph (a)(5) as paragraph (a)(6), adding a new paragraph (a)(5) and revising newly designated paragraph (a)(6) to read as follows: § 3137.21 What must I include in an NPR-A unit agreement?

(a)* * *

(3)The anticipated participating area size and well locations (see § 3137.80(b) of this subpart);

(5)A provision that acknowledges the BLM consulted with and provided opportunities for participation in the creation of the unit and a provision that acknowledges that the BLM will consult with and provide opportunities for participation in the expansion of the unit by —

(A)The regional corporation, if the unit acreage contains the regional corporation's mineral estate; or

(B)The State of Alaska, if the unit acreage contains the state's mineral estate.

(6)Any optional terms which are authorized in § 3137.50 of this subpart that you choose to include in the unit agreement. 15. Amend § 3137.23 by revising paragraph

(d)introductory text, removing “and” from the end of the paragraph (f), redesignating paragraph

(g)as paragraph (h), and adding a new paragraph

(g)to read as follows: § 3137.23 What must I include in my NPR-A unitization application?

(d)A statement certifying—

(g)A discussion of the proposed methodology for allocating production among the committed tracts. If the unit includes non-Federal oil and gas mineral estate, you must explain how the methodology takes into account reservoir heterogeneity and area variation in reservoir producibility; and 16. Amend § 3137.41 by revising the introductory paragraph of the section to read as follows: § 3137.41 What continuing development obligations must I define in a unit agreement? A unit agreement must provide for submission of supplemental or additional plans of development which obligate the operator to a program of exploration and development (see § 3137.71 of this subpart) that, after completion of the initial obligations — 17. Amend § 3137.80 by revising paragraph

(a)and the first sentence of paragraph

(b)to read as follows: § 3137.80 What are participating areas and how do they relate to the unit agreement?

(a)Participating areas are those committed tracts or portions of those committed tracts within the unit area that are proven to be productive by a well meeting the productivity criteria specified in the unit agreement.

(b)You must include a description of the anticipated participating area(s) size in the unit agreement for planning purposes to aid in the mitigation of reasonably foreseeable and significantly adverse effects on NPR-A surface resources. * * * 18. Amend § 3137.81 by revising paragraph

(a)to read as follows: § 3137.81 What is the function of a participating area?

(a)The function of a participating area is to allocate production to each committed tract within a participating area. The BLM will allocate production for royalty purposes to each committed tract within the participating area using the allocation methodology agreed to in the unit agreement (see § 3137.23(g) of this subpart). 19. Amend § 3137.85 by revising paragraph

(b)to read as follows: § 3137.85 What is the effective date of a participating area or modified allocation schedule?

(b)The effective date of a modified participating area or modified allocation schedule is the earlier of the first day of the month in which you file the proposal for a modification or such other effective date as may be provided for in the unit agreement and approved by the BLM, but no earlier than the effective date of the unit. 20. Revise § 3137.111 to read as follows: § 3137.111 When will BLM extend the primary term of all leases committed to a unit agreement or renew all leases committed to a unit agreement? If the unit operator requests it, the BLM will extend the primary term of all NPR-A leases committed to a unit agreement or renew the leases committed to a unit agreement if any committed lease within the unit is extended or renewed under §§ 3135.1-5 or 3135.1-6. If the BLM approves a lease renewal under § 3135.1-6(b), the BLM will require a renewal fee of $100 per acre for each lease in the unit that is renewed. 21. Amend § 3137.131 by revising the second and third sentences of the section to read as follows: § 3137.131 What happens if the unit terminated before the unit operator met the initial development obligations? * * * You, as lessee, forfeit all further benefits, including extensions and suspensions, granted any NPR-A lease because of having been committed to the unit. Any lease that the BLM extended because of being committed to the unit would expire unless it had been granted an extension or renewal under §§ 3135.1-5 or 3135.1-6. 22. Amend § 3137.134 by revising paragraph

(b)to read as follows: § 3137.134 What happens to committed leases if the unit terminates?

(b)An NPR-A lease that has completed its primary term on or before the date the unit terminates will expire unless it is granted an extension or renewal under §§ 3135.1-5 or 3135.1-6. [FR Doc. E8-1647 Filed 2-1-08; 8:45 am] BILLING CODE 4310-84-P FEDERAL COMMUNICATIONS COMMISSION 47 CFR Part 64 [CC Docket No. 94-129; FCC 07-222] Implementation of the Subscriber Carrier Selection Changes Provisions of the Telecommunications Act of 1996; Policies and Rules Concerning Unauthorized Changes of Consumers' Long Distance Carriers; LEC Coalition Application for Review Regarding Carrier Change Rules AGENCY: Federal Communications Commission. ACTION: Final rule. SUMMARY: In this document, the Commission denies an Application for Review filed by a coalition of local exchange carriers (“LEC Petitioners”) regarding the Commission's carrier change verification rules. Specifically, the Commission affirms that it is not permissible for an executing carrier to block a carrier change submission by a submitting carrier, based on the executing carrier's own finding that the customer's information does not match exactly the information in the executing carrier's records. DATES: Effective February 4, 2008. ADDRESSES: Federal Communications Commission, 445 12th Street, SW., Washington, DC 20554. FOR FURTHER INFORMATION CONTACT: Nancy Stevenson, Consumer & Governmental Affairs Bureau at

(202)418-7039 (voice), or e-mail *Nancy.Stevenson@fcc.gov* . SUPPLEMENTARY INFORMATION: On July 8, 2005, an application for review was filed by a coalition of local exchange carriers against the Commission's *Implementation of the Subscriber Carrier Selection Changes Provisions of the Telecommunications Act of 1996* , declaratory ruling, DA 05-1618, published at 71 FR 2895 (January 18, 2006). This is a summary of the Commission's *document* FCC 07-222, adopted December 18, 2007, released January 4, 2008, denying the application for review. Copies of document FCC 07-222 and any subsequently filed documents in this matter will be available for public inspection and copying during regular business hours at the FCC Reference Information Center, Portals II, 445 12th Street, SW., Room CY-A257, Washington, DC 20554. Document FCC 07-222 and any subsequently filed documents in this matter may also be purchased from the Commission's duplicating contractor at Portals II, 445 12th Street, SW., Room CY-B402, Washington, DC 20554. Customers may contact the Commission's duplicating contractor at their Web site: *http://www.bcpiweb.com* or call 1-800-378-3160. To request materials in accessible formats for people with disabilities (Braille, large print, electronic files, audio format), send an e-mail to *fcc504@fcc.gov* or call the Consumer & Governmental Affairs Bureau at

(202)418-0530 (voice) or

(202)418-0432 (TTY). Document FCC 07-222 can also be downloaded in Word and Portable Document Format

(PDF)at: *http://www.fcc.gov/cgb/policy* . Paperwork Reduction Act of 1995 Analysis The document does not contain new information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA), Public Law 104-13. In addition, 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* 47 U.S.C. 3506(c)(4). Synopsis Section 64.1120(a)(2) of the Commission's rules provides that “[a]n executing carrier shall not verify the submission of a change in the subscriber's selection of a telecommunications service received from a submitting carrier.” The Commission affirms that it is not permissible for an executing carrier to block a carrier change submission by a submitting carrier, based on the executing carrier's own finding that the customer's information does not match exactly the information in the executing carrier's records. The Commission expressed concern that executing carriers could use the verification process as a means to delay or deny carrier change requests in order to benefit themselves or their affiliates. While the Commission agreed that allowing executing carriers to re-verify carrier change requests could, under certain circumstances, help deter slamming, it ultimately concluded that the anti-competitive effects of re-verification outweighed the potential benefits. The LEC Petitioners contend that the Bureau mischaracterized their argument. Rather, according to the LEC Petitioners, under general principles of agency law, an executing carrier simply has a much more limited obligation to its subscribers not to make changes to subscriber accounts without prior indication from the subscriber that the submitting carrier request was so authorized. The LEC Petitioners liken their actions to that of a clerk at a liquor store that asks a customer for identification as a condition of purchase. The Commission disagrees with LEC Petitioners and finds there is no material distinction between rejecting a carrier change request because of a determination that the customer is not authorized, and rejecting a change request because the LEC has determined that customer information does not match the LEC's records. As the Bureau emphasized in its declaratory ruling, and as commenters reiterate here, the Commission has already clearly defined the roles of the submitting and executing carrier in a carrier change request. Specifically, in the course of verifying the subscriber's intention to change long distance service, a submitting carrier's independent, third-party verifier is required to elicit confirmation that the person contacted is authorized to make the change (that is, either the party or an agent of the party identified on the account). As to executing carriers, the Commission's rules simply require “prompt execution of changes verified by a submitting carrier.” As stated in the declaratory ruling, the mere fact that the name(s) contained in the executing carrier's LEC account information may differ from that of the contact person listed on the submitting carrier's change request does not necessarily indicate a lack of authority or agency on the part of the person requesting the IXC change. The Commission finds credible, and LEC Petitioners do not dispute, that “customers often authorize a spouse, a roommate, or other associate to act on their behalf,” or may use a different name for billing purposes, and this information may not reside in the LEC's files. The Commission does not believe the LEC Petitioners' liquor store analogy is applicable to the actions at issue here. In the LEC Petitioners' purported analogy, the customer is directly requesting a product sold by that store. Here, an executing carrier seeks to block a transaction that has already occurred between a customer and another carrier. The LEC Petitioners also argue that the Bureau erred when it failed to consider their arguments in light of *AT&T* v. *FCC* . In that decision, the court found that the Commission could not require submitting carriers to obtain actual authorization from a subscriber for a carrier change. Instead, the court found that Section 258 of the Act provides that carriers must comply only with “such verification *procedures* as the Commission shall prescribe (emphasis added).” The court added that requiring actual authorization was tantamount to holding submitting carriers to a strict liability standard, but that no such standard was contained in section 258 of the Act. The LEC Petitioners point to the court's statement that the customer's local exchange carrier “might be able to verify the subscriber's identity by consulting its own customer records,” to support their proposition that they should not have to presume that any name submitted in connection with a carrier change order is authorized by the subscriber. The Commission disagrees. In *AT&T* v. *FCC* , the court reviewed the Commission's enforcement action imposing forfeiture against AT&T for slamming. That decision concerned only the obligations of a submitting carrier; it did not address the rights or obligations of LECs. The specific language cited by the LEC Petitioners occurs in the context of the court's explanation of why the Commission exceeded its statutory authority in creating an “actual authorization from the subscriber” requirement and enforcing it against AT&T. The Bureau cited several examples (provided by the LEC Petitioners) of situations in which a LEC could, under the Commission's rules, legitimately reject a submitting carrier's change request, such as when a customer is already subscribed to the submitting carrier, when a customer has a PIC freeze in place, or when PIC changes are not permitted ( *e.g.* , certain college dormitory rooms). The LEC Petitioners argue that rejection of a carrier change for the reasons at issue here cannot be disallowed if it is in fact permissible for a LEC to utilize its records when processing a carrier change request, as in the examples described above. The Commission disagrees. The Commission reiterates that carriers may access account information in the course of effectuating carrier changes, and we do not believe that, under the limited circumstances described above, an executing carrier's return of a carrier change to the submitting carrier constitutes re-verification in violation of the Commission's rules. The Commission's objection to the LEC actions at issue here is not related to their consulting account information *per se* during the course of executing a carrier change. Rather, it violates Commission rules for executing carriers to make an independent determination with respect to the ability of a person to authorize a carrier change based on such information. Executing carriers have means (other than re-verification) of protecting their customers that do not interfere with competition or undermine consumer choice. Executing carriers can, for example, alert customers to preferred carrier changes, such as by highlighting changes to customers' accounts in customer billings, and can offer a preferred carrier freeze option to customers who are concerned about slamming. However, as the Commission expressed in the past, re-verification by executing carriers could function as a *de facto* preferred carrier freeze in situations where a subscriber has not requested such a freeze. The Commission emphasized that the imposition of a preferred carrier freeze must be authorized by the consumer to minimize any anticompetitive effects and to maintain flexibility for consumers. While preferred carrier freezes can provide consumers with extra protection from slamming, freezes by their very nature impose additional burdens on subscribers, and as such should only be enacted as a result of consumer choice. In the declaratory ruling, the Bureau reiterated this concern with respect to the LEC Petitioners' actions. The LEC actions at issue here serve to restrict consumer control by eliminating the consumer's ability to designate someone (such as a spouse) as authorized to change telecommunications service without first contacting the local carrier, thereby increasing the ability of the executing carrier to act in an anti-competitive manner. Endorsement of the LEC Petitioners' policies would result in inconvenience and delays for customers. The Commission continues to believe that the actions of the LEC Petitioners can, and do, result in *de facto* preferred carrier freezes where the customer has not requested such a freeze. Finally, the Commission notes that IUB and NASUCA commented in support of the LEC Petitioners. While the Commission declines to grant the LEC Petitioners' request to reverse the Bureau's finding in the declaratory ruling, the Commission recognizes that state authorities may have verification requirements for matters within their jurisdiction that are stricter than those of the Commission. As the Commission recognized in the *Third Report and Order* , FCC 00-255, published at 66 FR 12877 (March 1, 2001), states have valuable insight into the slamming problems experienced by consumers in their respective locales. Accordingly, the Commission declined to require that “states * * * limit their verification requirements so that they are no more stringent than those promulgated by this Commission.” As was noted in the declaratory ruling, the Commission's decision here concerns the question of permissible actions by private companies, not actions by a state regulatory agency. Congressional Review Act The Commission will not send a copy of document FCC 07-222 pursuant to the Congressional Review Act, *see* 5 U.S.C. 801(a)(1)(A), because no new rules were adopted in the document. Ordering Clauses Pursuant to the authority contained in sections 1, 2, 4(i), and 258 of the Communications Act of 1934, as amended, 47 U.S.C. 151, 152, 154(i), and 258, and sections 1.115 and 64.1120(a)(2) of the Commission's rules, 47 CFR 1.115 and 64.1120(a)(2), document FCC 07-222 is adopted. Pursuant to the authority contained in sections 1, 2, 4(i), and 258 of the Communications Act, of 1934, as amended, 47 U.S.C. 151, 152, 154(i), and 258, and sections 1.115 and 64.1120(a)(2) of the Commission's rules, 47 CFR 1.115 and 64.1120(a)(2), the LEC Petitioners' Application for Review is denied. Federal Communications Commission. Marlene H. Dortch, Secretary. [FR Doc. E8-1980 Filed 2-1-08; 8:45 am] BILLING CODE 6712-01-P 73 23 Monday, February 4, 2008 Proposed Rules DEPARTMENT OF JUSTICE 28 CFR Part 58 [Docket No: EOUST 101] RIN 1105-AB29 Procedures for Completing Uniform Forms of Trustee Final Reports in Cases Filed Under Chapters 7, 12, and 13 of Title 11 AGENCY: Executive Office for United States Trustees (EOUST), Justice. ACTION: Notice of proposed rulemaking. SUMMARY: The Department of Justice, through its component, EOUST, is issuing this notice of proposed rulemaking

(rule)pursuant to Section 602 of the Bankruptcy Abuse Prevention and Consumer Protection Act of 2005 (BAPCPA). The BAPCPA requires the Department to issue rules requiring uniform forms for final reports (Uniform Forms) by trustees in cases under chapters 7, 12, and 13 of title 11. The BAPCPA requires the rule to strike the best achievable practical balance between: the reasonable needs of the public for information about the operational results of the Federal bankruptcy system; economy, simplicity, and lack of undue burden on persons with a duty to file these reports; and appropriate privacy concerns and safeguards. DATES: Submit comments on or before April 4, 2008. ADDRESSES: Comments on the rule may be submitted via *www.regulations.gov* , by telefax to

(202)307-2397, or by postal mail to Executive Office for United States Trustees (“EOUST”), 20 Massachusetts Ave., NW., 8th Floor, Washington, DC 20530. To ensure proper handling of comments, please reference “Docket No. EOUST 101” on all written and electronic correspondence. FOR FURTHER INFORMATION CONTACT: Roberta A. DeAngelis, Acting General Counsel, or Larry Wahlquist, Office of General Counsel, at

(202)307-1399 (not a toll-free number). SUPPLEMENTARY INFORMATION: Posting of Public Comments Please note that all comments received are considered part of the public record and made available for public inspection online at *http://www.regulations.gov.* Such information includes personal identifying information (such as your name, address, etc.) voluntarily submitted by the commenter. If you want to submit personal identifying information (such as your name, address, etc.) as part of your comment, but do not want it to be posted online, you must include the phrase “PERSONAL IDENTIFYING INFORMATION” in the first paragraph of your comment. You must also locate all the personal identifying information you do not want posted online in the first paragraph of your comment and identify what information you want redacted. If you want to submit confidential business information as part of your comment but do not want it to be posted online, you must include the phrase “CONFIDENTIAL BUSINESS INFORMATION” in the first paragraph of your comment. You must also prominently identify confidential business information to be redacted within the comment. If a comment has so much confidential business information that it cannot be effectively redacted, all or part of that comment may not be posted on *http://www.regulations.gov.* Personal identifying information and confidential business information identified and located as set forth above will be placed in the agency's public docket file, but not posted online. If you wish to inspect the agency's public docket file in person by appointment, please see the FOR FURTHER INFORMATION CONTACT paragraph. Discussion of Rule The administration of all chapter 7, 12, and 13 bankruptcy cases is entrusted to private persons who are trustees under the supervision and oversight of a regional United States Trustee. As distinguished from trustees, United States Trustees are employees of the Department of Justice. In every case, a trustee must file with the court and submit to the United States Trustee a final report and final account of his or her case administration. The United States Trustee reviews these reports and they are then filed with the court. While the trustee final report forms currently used across the country essentially serve the same purpose and convey the same information, the format of the forms and required attachments, and even the names of the forms, can be different. In fact, there are over a hundred different versions of these forms in use throughout the country. With the passage of BAPCPA, Congress directed the Attorney General to draft rules creating nationally uniform forms for trustee final reports. The Attorney General delegated this authority to the Director, Executive Office for United States Trustees. In response to this congressional mandate, the Director publishes this rule, which requires trustees to utilize nationally uniform final report forms rather than the local forms currently in effect. This rule does not impose requirements on the general public; it affects only trustees who are supervised by United States Trustees. UST Forms 102-7-TFR, 102-7-NFR, 102-7-TDR, 102-7-NDR, 102-12-FR-S, 102-13-FR-S, 102-12-FR-C, and 102-13-FR-C are the final report Uniform Forms required by this rule. The information required by these forms is set forth in proposed section 58.7 in the amendatory text below. These Uniform Forms will facilitate the review of a trustee's case administration, which will assist in maintaining the public's trust in the bankruptcy system. In addition, these reports, once filed in a case, will be available to the general public at the office of the clerk of the United States Bankruptcy Court where a case is pending during the hours established by the bankruptcy court clerk. Members of the public should contact individual United States Bankruptcy Courts to obtain information about the policies and procedures for inspection of final reports filed in any particular case. Final reports in cases are also available through the Internet by accessing the Electronic Case Filing System under PACER at *http://www.pacer.psc.uscourts.gov.* These Uniform Forms shall be filed via the United States Bankruptcy Courts Case Management/Electronic Case Filing System (CM/ECF) as a “smart form.” A smart form is a document that is data enabled. When it is saved into the industry standard Portable Document Format (PDF), stored data tags are then available for extraction and searching. This is contrary to a form that is not data-enabled, where the PDF is simply an image of the form and data is not uniformly available for searching. The data-enabled form builds upon the existing Adobe PDF/A standard (Version 1.4). Specifically, the standard incorporates the use of XMP metadata or Acroform field and value (F/V) tags within an Adobe PDF document. The current data schema

(DTD)is found on *www.usdoj.gov/ust* . Trustees may obtain these “smart form” Uniform Forms from their vendor of trustee case management software. Members of the public may obtain blank Uniform Forms from each United States Trustee field office and from the United States Trustee Program Web site at *http://www.usdoj.gov/ust.* The usage of these Uniform Forms will accomplish Congress' mandate to develop nationally uniform forms for trustee final reports as directed in the BAPCPA. Instead of many different versions of trustee final reports, trustees throughout the country will use the same eight forms. This will greatly assist consumers in being able to understand the administration of bankruptcy cases, especially when a consumer is located in a different region from where the bankruptcy case is located. The usage of these Uniform Forms will also assist Congress in compiling data to accurately analyze bankruptcy trends when making policy decisions. Executive Order 12866 This rule has been drafted and reviewed in accordance with Executive Order 12866, “Regulatory Planning and Review” section 1(b), The Principles of Regulation. The Department has determined that this rule is a “significant regulatory action” and, accordingly, this rule has been reviewed by the Office of Management and Budget (“OMB”). The Department has also assessed both the costs and benefits of this rule as required by section 1(b)(6) and has made a reasoned determination that the benefits of this regulation justify its costs. The costs considered in this regulation include the time incurred by private trustees to complete the Uniform Forms. Since most of the information in the chapter 7 Uniform Forms is already collected in most districts, the additional time required to collect the requisite information and to complete the Uniform Forms should be minimal. 1 An exception may be UST Form 102-7-NDR, which asks for information not presently collected in any district for no-asset cases. The cost of this form is addressed in the Regulatory Flexibility Act section. 1 It is estimated that completion of the chapter 7 Uniform Forms, other than UST Form 102-7-NDR, will take approximately the same amount of time as the current chapter 7 final reports. Therefore, there should not be an appreciable difference in costs to complete the chapter 7 Uniform Forms as compared to current chapter 7 final report forms. In addition, the Uniform Forms will be added to the trustee case management software utilized by chapter 7 trustees. This software is provided to chapter 7 trustees by various banks free of charge in exchange for trustees depositing estate funds in these banks. For chapter 12 and chapter 13 trustees, it is anticipated that an increase in costs will be incurred due to the usage of these chapters 12 and 13 Uniform Forms. However, any associated cost will be an approved administrative expense of a standing trustee's trust operation. 2 2 Please see the Regulatory Flexibility Act section for an explanation of the chapters 12 and 13 Uniform Forms costs. It is estimated that the cost to the government for developing these Uniform Forms is approximately $20,000. The estimated cost to develop a system to store information extracted from these forms, and to analyze the data, is approximately $650,000. Over the next several years, the EOUST anticipates utilizing base resources available for information technology to meet the costs associated with developing the Uniform Forms and a system to store the information extracted from the forms. There will be no additional cost to the government. In fact, this rule will reduce the costs to the government of compiling the information submitted by private trustees. Since the Uniform Forms will be data enabled, the current system of manually compiling case closing information will be replaced by a less time intensive automated system. The benefits of this rule include establishing national uniformity in the final reports submitted by trustees, which will enable Congress, and the general public, to obtain more detailed information regarding bankruptcy cases nationally. This rule will enable Congress and the public to identify, among other things, the amount of debt scheduled in bankruptcy cases, the percentage of claims paid to creditors, the amount of debt discharged, and the value of assets abandoned by trustees. Executive Order 13132 This rule will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, in accordance with Executive Order 13132, it is determined that this rule does not have sufficient federalism implications to warrant the preparation of a Federalism Assessment. Regulatory Flexibility Act In accordance with the Regulatory Flexibility Act (5 U.S.C. 605(b)), the Director has reviewed this rule and certifies that none of the Uniform Forms, except for 102-7-NDR, will have a significant economic impact on a substantial number of small entities. This rule will affect only approximately 1,400 trustees. In addition, trustees already submit to the court essentially the same information as that required by this rule though formats vary in judicial districts. This rule simply creates uniform forms for all trustees to use throughout the country rather than local court forms. For chapter 12 and chapter 13 trustees, it is estimated that there will be an increase in costs in the amount of approximately $7.00 per final report. However, this is less than 1% of chapters 12 and 13 trustees' total operating expenses. Chapters 12 and 13 standing trustees allocate this cost toward an annual budget, which means trustees deduct this cost from funds disbursed from debtors' estates to creditors. Thus, the chapters 12 and 13 Uniform Forms will not have a significant economic impact upon standing trustees. 3 Public comments regarding the economic impact of the Uniform Forms upon trustees are requested. 3 Chapters 12 and 13 case trustees closed less than .001% of chapters 12 and 13 cases in fiscal year 2007. It is anticipated that UST Form 102-7-NDR may have a significant economic impact upon chapter 7 trustees because this form asks for information not presently collected in any district for no-asset cases. Accordingly, EOUST has prepared the following initial Regulatory Flexibility Act analysis. A typical chapter 7 trustee may close as many as 500 no asset cases each year. The current practice allows trustees to file a docket entry “virtual form” for no asset cases, which enables a trustee to quickly complete the process on-line without having to complete a separate form and upload it to the court's electronic filing system. Additionally, a trustee may file many such virtual forms simultaneously in batch mode format. With the introduction of the UST Form 102-7-NDR form, the current practice of filing virtual forms for no-asset cases via the court's electronic filing system will no longer be an option. It is estimated that it will take approximately ten minutes of staff time to collect and input the information required by UST Form 102-7-NDR. A typical staff assistant earns approximately $25 per hour, which means a trustee could incur an additional $2,100 a year in increased costs. However, EOUST is currently exploring alternatives with the Administrative Office of the United States Courts to enhance the transmission of electronic data collected by the courts to EOUST. These include alternatives that would reduce or eliminate the need for trustees to manually enter the information for UST Form 102-7-NDR, which will reduce much of the increased costs mentioned above for this form. 4 In addition, EOUST has requested the Administrative Office of the United States Courts to update their electronic filing system to allow trustees to file multiple UST Form 102-7-NDR forms at once to reduce the burden on trustees and on the court. EOUST specifically invites comments from the public suggesting other methods of reducing or eliminating any additional costs associated with completing the UST Form 102-7-NDR. 4 The enhanced data transmission contemplated by EOUST would also reduce the increased costs for chapters 12 and 13 trustees in completing the Uniform Forms. Paperwork Reduction Act These forms are associated with an open bankruptcy case. Therefore, the exemption under 5 CFR 1320.4(a)(2) applies. Unfunded Mandates Reform Act of 1995 This rule does not require the preparation of an assessment statement in accordance with the Unfunded Mandates Reform Act of 1995, 2 U.S.C. 1531. This rule does not include a federal mandate that may result in the annual expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of more than the annual threshold established by the Act ($123 million in 2005, adjusted annually for inflation). Therefore, no actions were deemed necessary under the provisions of the Unfunded Mandates Reform Act of 1995. Small Business Regulatory Enforcement Fairness Act of 1996 This rule is not a major rule as defined by section 804 of the Small Business Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. 801 *et seq.* 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 significant adverse effects on competition, employment, investment, productivity, and innovation; or on the ability of United States-based companies to compete with foreign-based companies in domestic and export markets. Privacy Act Statement 28 U.S.C. 589b authorizes the collection of the information in the final reports. As part of the trustee's reporting to the court, the United States Trustee, and creditors concerning the trustee's administration of the bankruptcy estate, the United States Trustee will review the information contained in these reports. The United States Trustee will not share the information with any other entity unless authorized under the Privacy Act, 5 U.S.C. 552a *et seq.* EOUST has published a System of Records Notice that delineates the routine use exceptions authorizing disclosure of information. See 71 FR 59818, 59822 (Oct. 11, 2006), JUSTICE/UST-002, “Bankruptcy Trustee Oversight Records.” Providing this information is mandatory under 11 U.S.C. 704. List of Subjects in 28 CFR Part 58 Bankruptcy, Trusts and trustees. For the reasons set forth in the preamble, 28 CFR part 58 is proposed to be amended as set forth below: PART 58—[AMENDED] 1. The authority citation for part 58 is revised to read as follows: Authority: 5 U.S.C. 301, 552; 11 U.S.C. 109(h), 111, 521(b), 727(a)(11), 1141(d)(3), 1202; 1302, 1328(g); 28 U.S.C. 509, 510, 586, 589b. 2. Add section 58.7 to read as follows: § 58.7 Procedures for completing uniform forms of trustee final reports in cases filed under chapters 7, 12, and 13 of the Bankruptcy Code.

(a)*UST Form 102-7-TFR, Chapter 7 Trustee's Final Report.* A chapter 7 trustee must complete UST Form 102-7-TFR final report

(TFR)before the case may be closed. This report must be submitted to the United States Trustee after liquidating the estate's assets, but before making distribution to creditors, and before filing it with the United States Bankruptcy Court. Pursuant to 28 U.S.C. 589b(d), the TFR must contain the following:

(1)Summary of the trustee's case administration;

(2)Copies of the estate's financial records;

(3)List of allowed claims;

(4)Fees and administrative expenses;

(5)Proposed dividend distribution to creditors; and

(6)Trustee's certification under penalty of perjury that all assets have been liquidated or properly accounted for, and that funds of the estate are available for distribution.

(b)*UST Form 102-7-NFR Chapter 7 Trustee's Notice of Trustee's Final Report.* After the TFR has been reviewed by the United States Trustee and filed with the United States Bankruptcy Court, if the net proceeds realized in an estate exceed $1,500, UST Form 102-7-NFR

(NFR)must be sent to all creditors as the notice required under Fed. R. Bankr. P. 2002(f). The NFR must show the receipts, approved disbursements, and any balance identified on the TFR, as well as the information required in the TFR's Exhibit D. In addition, the NFR must identify the procedures for objecting to any fee application or to the TFR.

(c)*UST Form 102-7-TDR Chapter 7 Trustee's Final Account, Certification The Estate Has Been Fully Administered and Application of Trustee To Be Discharged.* After distributing all estate funds, a trustee must submit to the United States Trustee and file with the United States Bankruptcy Court the trustee's final account, UST Form 102-7-TDR (TDR). The TDR must contain the trustee's certification that the estate has been fully administered and the trustee's request to be discharged as trustee. Pursuant to 28 U.S.C. 589b(d), the TDR must also include the following:

(1)The length of time the case was pending;

(2)Assets abandoned;

(3)Assets exempted;

(4)Receipts and disbursements of the estate;

(5)Claims asserted;

(6)Claims allowed; and,

(7)Distributions to claimants and claims discharged without payment, in each case by appropriate category.

(d)*UST Form 102-7-NDR Chapter 7 Trustee's Report of No Distribution.* In cases where there is no distribution of funds the case trustee must submit to the United States Trustee and file with the United States Bankruptcy Court UST Form 102-7-NDR (NDR). The NDR must contain the trustee's certification, under penalty of perjury, that the estate has been fully administered, that the trustee has neither received nor disbursed any property or money on account of the estate except exempt property to the debtor, and that there is no property available for distribution over and above that exempted by law. In addition, the NDR must set forth the trustee's request to be discharged as trustee. Pursuant to 28 U.S.C. 589b(d), the NDR must also include the following information:

(1)The length of time the case was pending;

(2)Assets abandoned;

(3)Assets exempted;

(4)Claims asserted;

(5)Claims scheduled; and,

(6)Claims discharged without payment.

(e)*UST Form 102-12-FR-S, Chapter 12 Standing Trustee's Final Report and Account and UST Form 102-13-FR-S, Chapter 13 Standing Trustee's Final Report and Account.* After the final distribution to creditors in a chapter 12 or 13 case in which a standing trustee has been appointed, a trustee must submit to the United States Trustee and file with the United States Bankruptcy Court either UST Form 102-12-FR-S for chapter 12 cases or UST Form 102-13-FR-S for chapter 13 cases, which are the trustee's final report and account. In these forms, a trustee must include a certification that the estate has been fully administered if not converted to another chapter and a request to be discharged as trustee. Pursuant to 28 U.S.C. 589b(d), these forms must also include the following information:

(1)The length of time the case was pending;

(2)Assets abandoned;

(3)Assets exempted;

(4)Receipts and disbursements of the estate;

(5)Expenses of administration, including for use under section 707(b), actual costs of administering cases under chapter 12 or 13 (as applicable) of title 11;

(6)Claims asserted;

(7)Claims allowed;

(8)Distributions to claimants and claims discharged without payment, in each case by appropriate category;

(9)Date of confirmation of the plan;

(10)Date of each modification thereto; and,

(11)Defaults by the debtor in performance under the plan.

(f)*UST Form 102-12-FR-C, Chapter 12 Case Trustee's Final Report and Account, and UST Form 102-13-FR-C, Chapter 13 Case Trustee's Final Report and Account.* After the final distribution to creditors in a chapter 12 or 13 case in which a case trustee has been appointed, the trustee must submit to the United States Trustee and file with the United States Bankruptcy Court either UST Form 102-12-FR-C for chapter 12 cases, or UST Form 102-13-FR-C for chapter 13 cases, which are the trustee's final report and account. In these forms, a trustee must include a certification, submitted under penalty of perjury, that the estate has been fully administered if not converted to another chapter and the trustee's request to be discharged from further duties as trustee. Pursuant to 28 U.S.C. 589b(d), these forms must also include the following information:

(1)The length of time the case was pending;

(2)Assets abandoned;

(3)Assets exempted;

(4)Receipts and disbursements of the estate;

(5)Expenses of administration, including for use under section 707(b), actual costs of administering cases under chapter 12 or 13 (as applicable) of title 11;

(6)Claims asserted;

(7)Claims allowed;

(8)Distributions to claimants and claims discharged without payment, in each case by appropriate category;

(9)Date of confirmation of the plan;

(10)Date of each modification thereto; and,

(11)Defaults by the debtor in performance under the plan.

(g)*Mandatory Usage of Uniform Forms.* The Uniform Forms associated with this rule must be utilized by trustees when completing their final reports and final accounts. All trustees serving in districts where a United States Trustee is serving must use the Uniform Forms in the administration of their cases, in the same manner, and with the same content, as set forth in this rule:

(1)All Uniform Forms may be electronically or mechanically reproduced so long as all the content and the form remain consistent with the Uniform Forms as they are posted on EOUST's Web site;

(2)The Uniform Forms shall be filed via the United States Bankruptcy Court's Case Management/Electronic Case Filing System (CM/ECF) as a “smart form” meaning the forms are data enabled. Dated: January 18, 2008. Clifford J. White III, Director, Executive Office for United States Trustees. Note: The following appendix will not appear in the Code of Federal Regulations. Appendix—Overview of Uniform Forms Form Title UST Form 102-7-TFR—Chapter 7 Trustee's Final Report UST Form 102-7-NFR—Chapter 7 Trustee's Notice Of Trustee's Final Report And Application For Compensation UST Form 102-7-TDR—Chapter 7 Trustee's Final Account, Certification That The Estate Has Been Fully Administered And Application To Be Discharged UST Form 102-7-NDR—Chapter 7 Trustee's Report Of No Distribution UST Form 102-12-FR-S—Chapter 12 Standing Trustee's Final Report And Account UST Form 102-13-FR-S—Chapter 13 Standing Trustee's Final Report And Account UST Form 102-12-FR-C—Chapter 12 Case Trustee's Final Report And Account UST Form 102-13-FR-C—Chapter 13 Case Trustee's Final Report And Account Before a bankruptcy case may be closed, a chapter 7 trustee must make a final report and final account of the administration of cases in which the trustee liquidates non-exempt assets of debtors. To begin the case closing process with the new Uniform Forms, the chapter 7 trustee will prepare and submit UST Form 102-7-TFR

(TFR)to the United States Trustee who reviews the report prior to it being filed with the United States Bankruptcy Court. The trustee prepares and submits this TFR after completing the liquidation of the assets, but before making distributions to creditors. The TFR contains a summary of the trustee's case administration, copies of the estate financial records, a list of allowed claims, fees and administrative expenses, and a proposed dividend distribution to creditors. The trustee certifies under penalty of perjury that all assets have been liquidated or properly accounted for, and that funds of the estate are available for distribution. After the TFR has been reviewed by the United States Trustee and filed with the United States Bankruptcy Court, if the net proceeds realized in an estate exceed $1,500, a notice required under Fed. R. Bankr. P. 2002(f) is sent to all creditors with a summary of the TFR final report. This notice is UST Form 102-7-NFR. After distribution of all estate funds, a trustee submits to the United States Trustee the trustee's final account, UST Form 102-7-TDR (TDR), which is the last report in the chapter 7 case. This TDR contains the length of time the case was pending, assets abandoned, assets exempted, receipts and disbursements of the estate, claims asserted, claims allowed, and distributions to claimants and claims discharged without payment. The TDR also contains the trustee's certification that the estate has been fully administered and the trustee's request to be discharged as trustee. In cases in which there is no distribution of funds, no asset cases, the case trustee prepares and files with the United States Bankruptcy Court UST Form 102-7-NDR, which is entitled the Report of No Distribution (NDR). UST Form 102-7-NDR contains the trustee's certification, under penalty of perjury, that the estate has been fully administered, that the trustee has neither received nor disbursed any property or money on account of the estate except exempt property to the debtor, that there is no property available for distribution over and above that exempted by law, and the trustee's request to be discharged as trustee. The NDR will also include information concerning the length of time the case was pending, assets abandoned, assets exempted, claims asserted, claims scheduled, and claims discharged without payment. After the final distribution to creditors in a chapter 12 or 13 case in which a standing trustee has been appointed, the trustee will file with the United States Bankruptcy Court UST Form 102-12-FR-S for chapter 12 cases or UST Form 102-13-FR-S for chapter 13 cases, which are the trustee's final report and account. In these forms, a trustee includes a certification that the estate has been fully administered if not converted to another chapter and contains the trustee's request to be discharged as trustee. These forms also include the information required for the TDR as well as the date of confirmation of the chapter 12 or 13 plan, date of each modification, and defaults by the debtor in performance under the plan, if applicable. A standing trustee is appointed by the United States Trustee under 28 U.S.C. 586 and may administer more than one chapter 13 or chapter 12 case, as opposed to a case trustee that is appointed under 11 U.S.C. 1302 or 11 U.S.C. 1202 and may administer only the one case to which the trustee is appointed. After the final distribution to creditors in a chapter 12 or 13 case in which a case trustee has been appointed, the trustee will file with the United States Bankruptcy Court either UST Form 102-12-FR-C for chapter 12 cases, or UST Form 102-13-FR-C for chapter 13 cases, which are the trustee's final report and account. In these forms, a trustee includes a certification, submitted under penalty of perjury, that the estate has been fully administered if not converted to another chapter and the trustee's request to be discharged from further duties as trustee. In addition, the forms contain the same information as that required for chapters 12 and 13 standing trustees. [FR Doc. E8-1450 Filed 2-1-08; 8:45 am] BILLING CODE 4410-40-P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 52 [EPA-R05-OAR-2007-1085; FRL-8519-2] Approval and Promulgation of State Implementation Plans; Ohio: Proposed Approval of Revised Oxides of Nitrogen (NO X ), Phase II, and Revised NO X Trading Rule AGENCY: Environmental Protection Agency (EPA). ACTION: Proposed rule. SUMMARY: EPA is proposing approval of a revision to the Ohio State Implementation Plan

(SIP)submitted by letter on June 16, 2005. This revision addresses the requirements of EPA's NO X SIP Call which requires further reductions in NO X emissions based on cost-effective control measures for large internal combustion engines. The revision also addresses some revisions to the State's NO X SIP Call trading program. EPA is proposing to determine that the Ohio SIP revision satisfies the requirements for Phase II of the NO X SIP Call and the NO X SIP Call trading program because, when implemented, these will meet Ohio's emission reduction requirements under Phase II of the NO X SIP Call. DATES: Comments must be received on or before March 5, 2008. ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R05-OAR-2007-1085, by one of the following methods: 1. *www.regulations.gov:* Follow the on-line instructions for submitting comments. 2. *E-mail: mooney.john@epa.gov* . 3. *Fax:*

(312)886-5824. 4. *Mail:* “EPA-R05-OAR-2007-1085”, John M. Mooney, Chief, Criteria Pollutant Section, Air Programs Branch (AR-18J), U.S. Environmental Protection Agency, 77 West Jackson Boulevard, Chicago, Illinois 60604. 5. *Hand Delivery or Courier:* John M. Mooney, Chief, Criteria Pollutant Section, Air Programs Branch (AR-18J), U.S. Environmental Protection Agency, 77 West Jackson Boulevard, Chicago, Illinois 60604. Such deliveries are only accepted during the Regional Office's normal hours of operation. The Regional Office's official hours of business are Monday through Friday, 8:30 to 4:30, excluding federal holidays. Please see the direct final rule which is located in the Rules section of this **Federal Register** for detailed instructions on how to submit comments. FOR FURTHER INFORMATION CONTACT: John Paskevicz, Engineer, Criteria Pollutant Section, Air Programs Branch (AR-18J), Environmental Protection Agency, Region 5, 77 West Jackson Boulevard, Chicago, Illinois 60604,

(312)886-6084, *paskevicz.john@epa.gov* . SUPPLEMENTARY INFORMATION: In the Final Rules section of this **Federal Register** , EPA is approving the State's SIP submittal as a direct final rule without prior proposal because the Agency views this as a non-controversial submittal and anticipates no adverse comments. A detailed rationale for the approval is set forth in the direct final rule. If no adverse comments are received in response to this rule, no further activity is contemplated. If EPA receives adverse comments, EPA will withdraw the direct final rule and will address all public comments received in a subsequent final rule based on this proposed rule. EPA will not institute a second comment period. Any parties interested in commenting on this action should do so at this time. Please note that if EPA receives meaningful adverse comment on an amendment, paragraph, or section of this rule and if that provision may be severed from the remainder of the rule, EPA may adopt as final those provisions of the rule that are not the subject of an adverse comment. For additional information, see the direct final rule which is located in the Rules section of this **Federal Register** . Dated: January 11, 2008. Gary Gulezian, Acting Regional Administrator, Region 5. [FR Doc. E8-1799 Filed 2-1-08; 8:45 am] BILLING CODE 6560-50-P DEPARTMENT OF HEALTH AND HUMAN SERVICES Centers for Medicare & Medicaid Services 42 CFR Parts 400, 405, 410, 412, 413, 414, 488, and 494 [CMS-3818-RCN] RIN 0938-AG82 Medicare and Medicaid Programs; Conditions for Coverage for End Stage Renal Disease Facilities—Extension of Timeline for Publication of Final Rule AGENCY: Centers for Medicare & Medicaid Services (CMS), HHS. ACTION: Extension of timeline for publication of final rule. SUMMARY: This notice announces an extension of the timeline for publication of the “Medicare and Medicaid Programs; Conditions for Coverage for End Stage Renal Disease Facilities” final rule. This notice is issued in accordance with section 1871(a)(3)(B) of the Social Security Act (the Act), which requires that a notice be published in the **Federal Register** if a final regulation, due to exceptional circumstances, will take longer to publish than 3 years after the publication date of the proposed rule. In this case, the complexity of the rule and scope of public comments warrants the extension of the timeline for publication. DATES: As of February 4, 2008, CMMS announces a delay in the timeline for publication of final rulemaking. FOR FURTHER INFORMATION CONTACT: Lynn Riley,

(410)786-1286. Lauren Oviatt,

(410)786-4683. SUPPLEMENTARY INFORMATION: I. Background On February 4, 2005, we published in the **Federal Register** a proposed rule (70 FR 6184), that would establish new certification requirements for Medicare coverage of dialysis facilities. The proposed revisions would reflect advances in dialysis technology and standard care practices that have developed since the requirements were last revised in their entirety in 1976. II. Notice of Continuation This notice announces an extension of the timeline for publication of a final rule responding to comments on the above proposed rule. Section 1871(a)(3)(B) of the Act requires the Secretary to publish Medicare final regulations no later than 3 years after the publication date of the proposed rule. To meet this 3-year timeframe, the final rule would have to be published by February 4, 2008. Section 1871(a)(3)(B) also provides that under “exceptional circumstances,” the Secretary may extend the initial targeted publication date of a final regulation. The Secretary is required, prior to the regulation's previously established proposed publication date, to provide public notice of this extension in the **Federal Register** , including a brief explanation of the justification for the variation. This notice extends the timeline based on the following exceptional circumstances, which we believe, justify such an extension. 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 large number of public comments we received. We received a large volume of timely comments on the proposed rule. The commenters presented extremely complex and detailed policy and legal issues, which require extensive consultation, review, and analysis. Also, the development of the final rule requires collaboration among other government agencies, including the Centers for Disease Control and Prevention and other agencies under the Department of Health and Human Services. We note that extensive coordination has been needed to ensure that these provisions follow guidelines and rules of all affected administrative agencies. In addition, this final rule is extremely comprehensive because it updates and revises policies regarding infection control, water and dialysate quality, hemodialyzer re-use, self dialysis in the home, and clinical management of the dialysis patients' anemia management. Therefore, the incorporation of these updates has required extensive time, outreach, and collaboration to ensure that the final rule's provisions are consistent with technological and scientific advancement in the provision of dialysis services. We believe that an extension of the publication timeline is necessary and appropriate to ensure that we are able to address all of the comments and issues raised in response to the February 4, 2005 proposed rule. Therefore, this notice extends the timeline for publication of the final rule until February 4, 2009. Authority: Section 1871 of the Social Security Act (42 U.S.C. 1395hh). (Catalog of Federal Domestic Assistance Program No. 93.773 Medicare—Hospital Insurance Program; and No. 93.774, Medicare—Supplementary Medical Insurance Program) Dated: January 31, 2008. Ann Agnew, Executive Secretary to the Department. [FR Doc. E8-2051 Filed 2-1-08; 8:45 am] BILLING CODE 4120-01-P 73 23 Monday, February 4, 2008 Notices DEPARTMENT OF AGRICULTURE Forest Service DEPARTMENT OF THE INTERIOR Bureau of Land Management Notice of Intent To Prepare a Supplemental Environmental Impact Statement AGENCY: Forest Service, USDA, and Bureau of Land Management, DOI. ACTION: Notice of Intent to prepare a Supplemental Environmental Impact Statement to analyze and disclose new information relative to oil and gas leasing of 44,720 acres on the Big Piney Ranger District. SUMMARY: The Bureau of Land Management (BLM), after receiving nominated oil and gas lease parcels and appropriate lease stipulations from the Forest Service (FS), sold and issued 12 leases, and sold 23 other leases that have not been issued. An appeal to the Interior Board of Land Appeals

(IBLA)resulted in a stay being granted for the 12 issued leases. Upon request, the appeal was remanded back to the BLM for resolution. The IBLA decision held that BLM had relied on an inadequate/stale NEPA analysis in reaching its decision to sell and issue the lease parcels. In the case of oil and gas leasing decisions on National Forest system lands, and in conformance with a MOU between the BLM and FS which identifies the need for BLM to be a cooperating agency, the NEPA analysis that was relied on by BLM to inform leasing decisions was adopted from the appropriate and applicable Forest Service NEPA. This supplemental EIS will address the issues identified by IBLA as inadequately or inappropriately addressed in previous NEPA analyses informing leasing decisions, and other issues identified through scoping. DATES: Comments concerning new information or issues not previously considered in the leasing analysis must be postmarked no later than 45 days from the publication of this notice in the **Federal Register** . The Draft Supplemental EIS (DSEIS) is expected in May of 2008 and the Final Supplemental Environmental Impact Statement (FSEIS) is expected in September of 2008. ADDRESSES: Send written comments to Stephen Haydon, Forest Minerals Staff, Bridger-Teton National Forest, 340 N. Cache, PO Box 1888, Jackson, WY 83001-1888. Send electronic comments to: *comments-intermtn-bridger-teton@fs.fed.us* ; with the subject clearly titled “Leasing EIS”. FOR FURTHER INFORMATION CONTACT: Stephen Haydon, Project Leader. SUPPLEMENTARY INFORMATION: The Bridger-Teton National Forest made an oil and gas leasing decision in the forest plan signed in 1990. Subsequent Environmental Assessments were completed in the early 1990s to consider the impacts of oil and gas leasing in various Management Areas throughout the Forest. Since the early 1990s, several issues that have some bearing on oil and gas leasing have arisen and new information has become available. The Forest reviewed those issues and the new information and documented that review in a Supplemental Information Report dated February 25, 2004. The Forest Supervisor concluded that the new issues and information did not alter the previous leasing decision in the Forest Plan. Subsequently, in 2005 the Forest Service sent lease parcels covering 44,720 acres to the BLM for competitive lease sale. The BLM offered, sold and issued leases on 20,963 acres in December 2005 and April 2006, and sold but did not issue leases on the remaining 23,757 acres in June and August 2006. Following protest and BLM State Director's Review, an appeal to the Interior Board of Land Appeals

(IBLA)was filed for the December and April lease sales. The appeal included “Request for Stay,” which the IBLA granted. Upon request by the BLM, IBLA remanded the appeals back to the BLM for resolution. This supplemental analysis will address the resource issues and effects analysis concerns identified by IBLA and additional issues identified through this scoping effort. Purpose and Need for Action The purpose and need for action is to determine whether and to what extent analysis of new issues and information might alter the oil and gas leasing decision as it relates to the 44,720 acres forwarded to the BLM for competitive lease sale. This action is needed to address the appropriateness of the previous leasing decisions, to decide the final disposition of the suspended existing leases and lease parcels, and to be responsive to the IBLA remand requiring incorporation of the new issues and information in the BLM decision to lift the suspension of lease parcels and issue oil and gas leases. Proposed Action The proposed federal action is to lift the current suspension on the issued December 2005 and April 2006 leases and to issue those that were sold but not issued from the June and August 2006 sales. To do so requires the analysis of new issues and information not available to the deciding officials at the time the leasing decision was made. Possible Alternatives The alternatives to be considered may include continuation of the current leasing decision contained in the forest plan, and the no action alternative, and potentially others identified in scoping. The no action alternative would involve not issuing the leases that have been sold but not issued, and the cancellation of the leases that were sold. Additional alternatives may be identified once scoping is completed. Lead and Cooperating Agencies The Forest Service is the lead agency. The BLM and the State of Wyoming are cooperating agencies. Responsible Official The Forest Service responsible official for determining if and to what extent the analysis of new issues and information would alter the oil and gas leasing decision contained in the BTNF Forest Plan (36 CFR 228.102(d)) is Kniffy Hamilton, Forest Supervisor, Bridger-Teton National Forest, 340 N. Cache (P.O. Box 1888), Jackson, Wyoming 83001. The BLM responsible official for final decision (43 CFR 3101.7) relative to the issuance or disposition of the leases and lease parcels is Robert A. Bennett, State Director, BLM—Wyoming State Office, 5353 Yellowstone (P.O. Box 1828), Cheyenne, Wyoming 82009. Nature of Decision To Be Made The Forest Service will determine if and how the current Forest Plan oil and gas leasing decision, as it relates to the 44,720 acres, should be changed based on new information. If a new decision is determined not to be needed following preparation of the Supplemental environmental impact statement, that determination is not subject to appeal in accordance with 36 CFR 215.12. The BLM will then decide whether or not the revised FS NEPA analysis is adequate, and subsequently whether to lift the suspension on the existing leases and whether or not to issue leases on the other lease parcels. Scoping Process Scoping for a supplemental statement is not required (40 CFR 1502.9(c)(4)), but due to the length of time since scoping associated with the current leasing decision was conducted, the agencies are soliciting comments specific to new issues or information. Letters will be sent to the forest mailing list of known interested parties. Public meetings held in 2006 in association with forest plan revision efforts generated issues relative to oil and gas leasing. Comments received during those meetings will be considered in this supplemental analysis. The scoping process will assist the agencies in identifying specific issues to be addressed related to the purpose and need and the scope of the decision. Mail comments to the addresses given above for further information. Ongoing information related to the proposed action and related analysis will be posted on the Bridger-Teton National Forest Web site *http://www.fs.fed.us/r4/btnf* . Preliminary Issues Preliminary issues associated with the proposed action include:

(1)The drilling and production of wells subsequent to leasing could impact air quality and air quality related values, with emphasis on cumulative effects due to extensive development in the Pinedale area.

(2)The T&E listed Lynx, or its habitat, could be impacted by subsequent exploration and development activities.

(3)Impacts to water quality due to subsequent surface disturbing activities could adversely affect the Colorado River Cutthroat Trout.

(4)The development of a transportation system to support field development could adversely affect mule deer migration routes in the area and fragment habitat. Comment Requested This notice of intent initiates the scoping process which guides the development of the supplemental environmental impact statement. *Early Notice of Importance of Public Participation in Subsequent Environmental Review:* A Supplemental DEIS will be prepared for comment. The comment period on the SDEIS will be for a perod of 45 days from the date the Environmental Protection Agency publishes the notice of availability in the **Federal Register** . The Forest Service believes, at this early stage, it is important to give reviewers notice of several court rulings related to public participation in the environmental review process. First, reviewers of a DEIS must structure their participation in the environmental review of the proposal so that it is meaningful and alerts an agency to the reviewer's position and contentions. *Vermont Yankee Nuclear Power Corp.* v. *NRDC, 435 U.S. 519, 553 (1978).* Also, environmental objections that could be raised at the DEIS stage but that are not raised until after completion of the final environmental impact statement may be waived or dismissed by the courts. *City of Angoon* v. *Hodel, 803 F.2d 1016, 1022 (9th Cir. 1986)* and *Wisconsin Heritages, Inc.* v. *Harris, 490 F. Supp. 1334, 1338 (E.D. Wis. 1980).* Because of these court rulings, it is very important that those interested in this proposed action participate by the close of the 45-day comment period so that substantive comments and objections are made available to the Forest Service at a time when it can meaningfully consider them and respond to them in the final environmental impact statement. To assist the Forest Service in identifying and considering issues and concerns on the proposed action, comments on the DEIS should be as specific as possible. It is also helpful if comments refer to specific pages or chapters of the draft statement. Comments may also address the adequacy of the DEIS or the merits of the alternatives formulated and discussed in the statement. Reviewers may wish to refer to the Council on Environmental Quality Regulations for implementing the procedural provisions of the National Environmental Policy Act at 40 CFR 1503.3 in addressing these points. Comments received, including the names and addresses of those who comment, will be considered part of the public record on this proposal and will be available for public inspection. (Authority: 40 CFR 1501.7 and 1508.22; Forest Service Handbook 1909.15, Section 21) Dated: January 25, 2008. Kniffy Hamilton, Forest Supervisor, Bridger-Teton National Forest. Jane D. Darnell, Acting Wyoming State Director, Bureau of Land Management. [FR Doc. 08-472 Filed 2-1-08; 8:45 am]

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