This rule has been determined to be nonsignificant for the purpose of Executive Order 12866 and, therefore, has not been reviewed by the Office of Management and Budget.

Also, pursuant to the requirements set forth in the Regulatory Flexibility Act, James R. Baker, Administrator, GIPSA, has determined that this final rule will not have a significant economic impact on a substantial number of small entities as defined in the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ).

GIPSA regularly reviews its user-fee financed programs to determine if the fees are adequate. GIPSA has and will continue to seek out cost-saving opportunities and implement appropriate changes to reduce costs. Such actions can provide alternatives to fee increases. However, even with these efforts, GIPSA's existing fee schedule will not generate sufficient revenues to cover program costs while maintaining an adequate reserve balance. In fiscal year (FY) 1998, GIPSA's operating costs were $23,021,166 with revenue of $21,776,323, resulting in a loss of $1,244,843 and a reserve balance of $55,862. In FY 1999, GIPSA's operating costs were $22,883,063 with revenue of $22,971,204 that resulted in a positive margin of $88,141. As of December 31, 1999, GIPSA's FY 2000 operating costs were $6,066,322 with revenue of $6,333,381 that resulted in a positive margin of $267,059. Even with the positive margins for FY 1999 and thus far for FY 2000, the reserve balance was $569,669, below the desired 3-month operating reserve of approximately $5.7 million.

Employee salaries and benefits are major program costs that account for approximately 84 percent of GIPSA's total operating budget. A general and locality salary increase that averages 4.8 percent for GIPSA employees, effective January 2000, will increase program costs by approximately $691,613.

We have reviewed the financial position of our inspection and weighing program based on the increased salary and benefit costs, along with the projected FY 2000 workload. Based on the review, we have concluded that nearly half of the projected $691,613 salary increase can be absorbed through existing program efficiencies. Therefore, the other half needs to be covered through an increase in fees that will collect an estimated $390,000 in additional revenues.

The fee increase primarily applies to entities engaged in the export of grain. Under the provisions of the USGSA, grain exported from the United States must be officially inspected and weighed. Mandatory inspection and weighing services are provided by GIPSA on a fee basis at 37 export facilities. All of these facilities are owned and managed by multi-national corporations, large cooperatives, or public entities that do not meet the criteria for small entities established by the Small Business Administration.

Some entities who request nonmandatory official inspection and weighing services at other than export locations could be considered small entities. The impact on these small businesses is similar to any other business; that is, an average 2.4 percent increase in the cost of official inspection and weighing services. This nominal increase should not significantly affect any business requesting official inspection and weighing services. Furthermore, any of these businesses that wish to avoid the fee increase may elect to do so by using an alternative source for inspection and weighing services. Such a decision should not prevent the business from marketing its products.

There would be no additional reporting or record keeping requirements imposed by this action. In compliance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the information collection and record keeping requirements in Part 800 have been previously approved by the Office of Management and Budget under control number 0580-0013. GIPSA has not identified any other Federal rules which may duplicate, overlap, or conflict with this final rule.

This final rule has been reviewed under Executive Order 12988, Civil Justice Reform. This action is not intended to have a retroactive effect. The USGSA provides in § 87g that no subdivision may require or impose any requirements or restrictions concerning the inspection, weighing, or description of grain under the Act. Otherwise, this final rule will not preempt any State or local laws, regulations, or policies unless they present irreconcilable conflict with this final rule. There are no administrative procedures that must be exhausted prior to any judicial challenge to the provisions of this final rule.

On January 3, 2000, GIPSA proposed in the Federal Register (65 FR 75) to increase fees for official inspection and weighing services performed under the USGSA by approximately 2.4 percent.

The USGSA (7 U.S.C. 71 et seq. ) authorizes GIPSA to provide official grain inspection and weighing services and to charge and collect reasonable fees for performing these services. The fees collected are to cover, as nearly as practicable, GIPSA's costs for performing these services, including related administrative and supervisory costs. The current USGSA fees were published in the Federal Register on December 23, 1998 (63 FR 70990), and became effective on February 1, 1999. A correction to the minimum fees for stowage examinations was published in the Federal Register and became effective on February 11, 1999 (64 FR 6783).

GIPSA regularly reviews its user-fee financed programs to determine if the fees are adequate. While GIPSA continues to explore ways to reduce its costs, the existing fee schedule will not generate sufficient revenues to cover program costs while maintaining an adequate reserve balance. In FY 1998, GIPSA's operating costs were $23,021,166 with revenue of $21,776,323, resulting in a loss of $1,244,843 and a reserve balance of $55,862. In FY 1999, GIPSA's operating costs were $22,883,063 with revenue of $22,971,204, resulting in a positive margin of $88,141. As of December 31, 1999, GIPSA's FY 2000 operating costs were $6,066,322 with revenue of $6,333,381 that resulted in a positive margin of $267,059. Even with the positive margins for FY 1999 and thus far for FY 2000, the reserve balance was $569,669, below the desired 3-month operating reserve of approximately $5.7 million.

Employee salaries and benefits are major program costs that account for approximately 84 percent of GIPSA's total operating budget. The January 2000 general and locality salary increase that averages 4.8 percent for GIPSA employees will increase program costs by an estimated $691,613. Based on a review of projected FY 2000 workload and operating costs, the Agency has determined that approximately half of the projected $691,613 salary increase can be absorbed through existing program efficiencies. The other half needs to be covered through an increase in fees that will collect an estimated $390,000 in additional revenues.

The hourly fees covered by this rule will generate revenue to cover the basic salary, benefits, and leave for those employees providing direct service delivery. Other associated costs, including nonsalary related overhead, are collected through other fees contained in the fee schedule and are at levels that would not require any change under this rule.

The current hourly fees are:

GIPSA has also identified certain unit fees, for services not performed at an applicant's facility, that contain direct labor costs and would require a fee increase. Further, GIPSA has identified those costs associated with salaries and benefits that are covered by the administrative metric tonnage fee. The 2.4 percent cost-of-living increase to salaries and benefits covered by the administrative tonnage fee results in an average overall increase of 2.4 percent to the administrative tonnage fee.

GIPSA received two comments during the 60-day comment period. The comments came from two grain trade associations. Both associations generally supported the proposed rule; however, each one encouraged the Agency to seek ways to streamline operations in an effort to reduce costs. One commentor suggested that GIPSA strive to reduce overall staffing, thereby reducing the impact of future cost-of-living raises. The commentor further suggested that GIPSA set a goal for administrative and supervisory costs not to exceed 20 percent of the total cost of service. Finally, one association suggested the fee increases only be applied to the hourly rates and certain unit rates and not to the administrative tonnage fee. This, in the association's view, would serve as a financial incentive to automate the inspection and weighing services at export facilities.

GIPSA has and will continue to explore ways to reduce costs. Current program improvements have enabled the Agency to avoid passing the full 4.8 percent salary increase on to its customers through increased fees. Similar efforts will continue in the future, including the introduction of new technology that improves program efficiencies and reduces staffing needs.

The Agency's efforts to reduce the number of employees providing service has been a direct result of program initiatives designed to streamline operations at export elevators. The Agency has and will continue to explore ways to streamline these operations. Over the past several years, automated material handling systems have been introduced at export locations. These systems have reduced the number of employees needed to perform service. Other efforts currently underway, including inspection automation and automation of specific administrative functions, will provide more timely and efficient service. These initiatives not only address future costs of providing service, but are designed to help improve the operational efficiencies of export facilities, thereby reducing the overall exporters' costs.

Increasing only the hourly and unit fees fails to address the increased supervision and administrative salary costs covered by the administrative tonnage fee. The recommendation to establish a 20 percent cap on supervision and administrative costs reflects a strong desire to control costs. The USGSA has had a 40 percent cap since FY 1985. Since that time, the Agency has operated well below that level and will continue to establish appropriate goals and objectives to address future supervision and administrative costs.

Efforts to contain and reduce these costs have and will continue to be taken. However, these efforts will not adequately cover the increased salary costs incurred by the pay raise. GIPSA, therefore, must increase all hourly fees, certain unit fees, and the administrative tonnage fee by 2.4 percent in order to recover the increased supervision administrative costs.

Accordingly, GIPSA is applying an approximate 2.4 percent increase to those hourly rates, certain unit rates, and the administrative tonnage fee, as proposed, in 7 CFR 800.71. Table 1—Fees for Official Services Performed at an Applicant's Facility in an Onsite GIPSA Laboratory; Table 2—Services Performed at Other Than an Applicant's Facility in a GIPSA Laboratory; and Table 3, Miscellaneous Services.

This rule has been determined to be nonsignificant for the purpose of Executive Order 12866 and, therefore, has not been reviewed by the Office of Management and Budget.

Also, pursuant to the requirements set forth in the Regulatory Flexibility Act, James R. Baker, Administrator, GIPSA, has determined that this rule will not have a significant economic impact on a substantial number of small entities as defined in the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ).

GIPSA regularly reviews its user-fee-financed programs to determine if the fees are adequate. GIPSA has and will continue to seek out cost saving opportunities and implement appropriate changes to reduce costs. Such actions can provide alternatives to fee increases. However, even with these efforts, GIPSA's existing fee schedule will not generate sufficient revenues to cover program costs while maintaining an adequate reserve balance. In fiscal year (FY) 1998, GIPSA's operating costs were $3,820,820 with revenue of $4,011,446, resulting in a positive margin of $190,626 and a negative reserve balance of $895,584. In FY 1999, GIPSA's operating costs were $4,105,564 with revenue of $4,412,131 that resulted in a positive margin of $306,567 and a negative reserve balance of $508,628. As of December 31, 1999, GIPSA's FY 2000 operating costs were $1,246,614 with revenue of $1,429,461 that resulted in a positive margin of $182,847 and a negative reserve of $168,447.

Employee salaries and benefits are major program costs that account for approximately 84 percent of GIPSA's total operating budget. A general and locality salary increase that averages 4.8 percent for GIPSA employees, effective January 2000, will increase program costs. This salary adjustment will increase GIPSA's costs by approximately $135,000, based on the projected FY 2000 work volume of 3.9 million metric tons.

We have reviewed the financial position of our rice inspection program based on the increased salary and benefit costs, along with the projected FY 2000 workload. Based on that review, we have concluded that we cannot absorb the increased costs due to the FY 2000 Federal salary increase with the current negative reserve balance. This fee increase will collect an estimated $138,000 in additional revenues.

This fee increase primarily applies to GIPSA customers that produce, process, and market rice for the domestic and international markets. There are approximately 550 such customers located primarily in the States of Arkansas, Louisiana, and Texas. Many of these customers meet the criteria for small entities established by the Small Business Administration criteria for small businesses. Even though the fees are being increased, the increase will not be excessive (4.8 percent) and should not significantly affect those entities. Those entities are under no obligation to use our service and, therefore, any decision on their part to discontinue the use of our service should not prevent them from marketing their products.

There will be no additional reporting or record keeping requirements imposed by this action. In compliance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the information collection and record keeping requirements in Part 868 have been previously approved by the Office of Management and Budget under control number 0580-0013. GIPSA has not identified any other Federal rules which may duplicate, overlap, or conflict with this rule.

This final rule has been reviewed under Executive Order 12988, Civil Justice Reform. This action is not intended to have a retroactive effect. This action will not preempt any State or local laws, regulations, or policies unless they present irreconcilable conflict with this rule. There are no administrative procedures that must be exhausted prior to any judicial challenge to the provisions of this rule.

On January 3, 2000, GIPSA proposed in the Federal Register (65 FR 78) to increase fees for official rice inspection services performed under the AMA by approximately 4.8 percent. Under the provisions of the AMA of 1946 (7 U.S.C. 1621, et seq. ), rice inspection services are provided upon request and GIPSA must collect a fee from the customer to cover the cost of providing such services. Section 203 (h) of the AMA (7 U.S.C. 1622(h)) provides for the establishment and collection of fees that are reasonable and, as nearly as practicable, cover the costs of the services rendered. These fees cover the GIPSA administrative and supervisory costs for the performance of official services, including personnel compensation, personnel benefits, travel, rent, communications, utilities, contractual services, supplies, and equipment.

The rice inspection fees were last amended on February 12, 1999, and became effective March 1, 1999 (64 FR 7057). These fees were to cover, as nearly as practicable, the level of operating costs as projected for FY 1999. They presently appear at 7 CFR 868.91 in Tables 1 and 2.

GIPSA continually monitors its cost, revenue, and operating reserve levels to ensure that there are sufficient resources for operations. During FY 1998, GIPSA implemented cost-saving measures in an effort to provide more cost effective services. The purpose of these measures was to reduce operating costs in order to reduce the negative retained earnings in this program. The cost containment measures included employee buyouts and better cross utilization of personnel between programs.

In FY 1998, the program generated revenue of $4,011,446 with operating costs of $3,820,820, resulting in a positive margin of $190,626. Even though we generated a positive margin for the year, we continued to operate with a negative reserve balance of $895,584. The rice program's FY 1999 revenue was $4,412,131 with operating costs of $4,105,564, that resulted in a positive margin of $306,567 and a negative reserve balance of $508,628. The rice inspection program has been slowly recovering from a long-standing deficit. Through a series of small fee increases and cost-cutting measures, GIPSA has reduced the level of the negative reserve balance from $939,147 in FY 1994 through FY 1999 to a negative level of $508,628. As of December 31, 1999, GIPSA's FY 2000 operating costs were $1,246,614 with revenue of $1,429,461 that resulted in a positive margin of $182,847 and a negative reserve of $168,447.

However, employee salaries and benefits are major program costs that account for approximately 84 percent of GIPSA's total operating budget. A general and locality salary increase that averages 4.8 percent for GIPSA employees, effective January 2000, will increase program costs. This salary adjustment will increase GIPSA's costs by approximately $135,000. GIPSA cannot absorb this increase in salary costs with a deficit in the reserve balance and, at the same time, continue our efforts to reduce costs to eliminate the existing deficit. In FY's 1998 and 1999, GIPSA inspected 3.9 million metric tons of rice, and projections indicate that similar amounts will be inspected for FY 2000. The Agency will continue its efforts to streamline costs associated with providing service to further reduce the negative reserve balance. However, we must recover the projected $135,000 increase in salaries and benefits in order to accomplish this goal. GIPSA estimates that the fee increase will generate an additional $138,000 in revenue, based on the projected FY 2000 work volume of 3.9 million metric tons.

The costs associated with salaries and benefits are recovered by the hourly rates for personnel performing direct service. Other associated costs, including non-salary related overhead, are collected through other fees contained in the fee schedule and are at levels that do not require any change. GIPSA is implementing a 4.8 percent increase to the hourly rates and certain unit rates in 7 CFR Part 868.91, Table 1—Hourly Rates/Unit Rate Per CWT and Table 2—Unit Rates. Currently, the regular workday contract and noncontract fees are $40.80 and $50.00, respectively, while the nonregular workday contract and noncontract fees are $56.80 and $69.00, respectively. The unit rate per hundredweight for export port services is currently $.05 per hundredweight. The other current unit rates are:

GIPSA received no comments in response to the proposed rulemaking published January 3, 2000, at 65 FR 78.

Section 203 of the AMA (7 U.S.C. 1622) provides for the establishment and collection of fees that are reasonable and, as nearly as practicable, cover the costs of the services rendered. These fees cover the GIPSA costs, including administrative and supervisory costs, for the performance of official services, including personnel compensation, personnel benefits, travel, rent, communications, utilities, contractual services, supplies, and equipment.

Section 114 of the Energy Policy Act of 1992 (EPAct), Public Law 102-486, requires integrated resource planning (IRP) by Western's customers. Western implemented EPAct through the Energy Planning and Management Program (EPAMP) in October 1995. EPAMP was published in the Code of Federal Regulations at 10 CFR part 905.

Western's Administrator is required by EPAct to initiate a public process to review Western's IRP regulations within 1 year after January 1, 1999. The Administrator is authorized at that time to revise Western's criteria for approving integrated resource plans “to reflect changes, if any, in technology, needs, or other developments.”

Both the wholesale and retail aspects of the electric utility industry are changing, and change is expected to continue. The 15 States within which Western markets power have taken very different approaches to deregulation with diverse schedules for implementing any changes to the status quo. Additionally, the timing and scope of any Federal restructuring legislation is uncertain. Given the increasingly competitive and deregulated electricity marketplace, Western's IRP regulations, which were adopted under the traditional utility planning framework, have been reviewed through a formal public process and consequently revised.

Western is adopting an approach that features customer choice and flexibility, and reflects the transition of the electric utility industry. Customers can choose to continue preparing IRPs, or can adopt approaches that are emerging in lieu of IRP requirements. These new approaches are (1) complying with a defined level of investment in demand-side management (DSM) and/or renewable energy, including a public benefits program, or (2) complying with mandated energy efficiency and/or renewable energy activities and related reporting requirements.

Only subparts A and B of the existing regulations are being revised.

Western published the notice of proposed rulemaking and public forum in the Federal Register at 64 FR 62604 on November 17, 1999. A formal public information and comment forum was held in Denver, Colorado, on November 30, 1999. Nine customer representatives attended, and formal transcripts were made available through Western's Corporate Services and Regional offices. The formal public comment period closed on December 30, 1999. Western received comments from 29 customers and other stakeholders. All comments were extensively reviewed and, where appropriate, incorporated into the Final Rule. The Discussion of Comments provides Western's response to all comments. Comments and related responses were consolidated where possible.

General comments and discussion precede the comments relating to specific sections. Specific comments are grouped under the appropriate section heading and followed by Western's responses.

One commenter suggested that Western should continue to update the IRP process as the industry continues to restructure. Two commenters said that the proposed changes to the IRP rule seem to minimize requirements for small utilities while maintaining inflexible requirements for larger utilities. One commenter noted that Western should capitalize words such as “Customer” and “Integrated Resource Planning” to match contractual language.

Western will continue to evaluate the changing utility industry and the impacts of the changes on IRP regulations, and initiate a public process to review the regulations at appropriate intervals. As Section 114 EPAct and § 905.24 of the final rule state, the regulations may be changed to reflect changes in technology, needs, or other developments.

It is not Western's intent to change the rule solely to benefit small customers. The rule has been revised to further accommodate multi-state entities, especially in the minimum investment report alternative (§ 905.16), and member-based associations (MBA) and IRP cooperatives. Western believes that large customers have considerable opportunities to perform streamlined IRP and alternative reporting based on the revised rule, especially in light of changes in the utility industry that impact large customers.

Western agrees that there is a strong relationship between contractual language and language incorporated into the IRP rule. However, the rule has been revised to comply with the President's initiative to use plain language in government writing. Capital letters for contractual terms are not used in this rule because their use does not meet plain language guidelines.

One commenter suggested that the phrase “and to extend the long-term firm power resource commitments” be deleted from the first sentence. Another commenter said that Western should refer specifically to part 905 in the first paragraph.

Section 905.1 describes the purposes of EPAMP, which includes both the IRP regulations in subpart B of part 905 (which is revised in this final rule) and the Power Marketing Initiative in subpart C of part 905 (which is not revised). It is inappropriate, therefore, to remove the phrase “and to extend the long-term firm power resource commitments” because the phrase describes the purpose of the Power Marketing Initiative.

The title of part 905, “Energy Planning and Management Program,” is now included in both the title of § 905.1 and in the text. This change more clearly identifies the content of the paragraph while meeting plain language guidelines. Western believes it is unnecessary to otherwise refer specifically to part 905 within the subpart.

One commenter suggested that the phrase “at the lowest system cost” should still be included in the definition of “integrated resource planning.”

The definition of “integrated resource planning” in § 905.2 was shortened to ensure a more concise and easily understood definition, while having the same intended meaning as before. Western removed “at the lowest system cost” because its meaning was interpreted as a mandate to select the energy resources that had the lowest dollar price. As a result, it actually became a barrier to pursuing DSM and renewable energy activities, which are usually more expensive than purchasing non-renewable resources. Although this was not the intent of EPAct, Western has removed this and other similar language for clarity because Western is interested in fostering DSM and renewable energy. This change in no way invalidates an IRP that selects resources based on least cost; Western is simply not mandating this approach.

The sentence following the original definition, which was not part of the definition but an explanation of the process of preparing and IRP, was moved to § 905.11, where the process of preparing an IRP is more appropriately discussed.

Some commenters said that the statutory criteria set forth in EPAct should be adhered to without modification, while many commenters applauded Western's willingness to consider changes to the criteria that accommodate changes in the electric utility industry. Some commenters noted that, despite streamlining, the IRP criteria are still too comprehensive and too restrictive given changes in the utility industry. Two commenters suggested Western accept more summary descriptions, decreasing its reliance on strict numerical data.

One comment suggested the phrase “for new energy resources” be added to the end of the first sentence in § 905.11(a). One commenter noted that, in § 905.11(a), “must” should be replaced with “should.” One comment suggested Western should not drop the “least cost” criteria. One comment suggested that Western's proposal to allow customers to determine their own action planning horizons is inconsistent with EPAct.

Many comments requested Western add the modifier “to the extent practicable” to the first sentence of § 905.11(b)(3), as it is in the existing regulations. One comment requested Western add the modifier “ample opportunity” to the first sentence of § 905.11(b)(4), as it is in the existing regulations. Many commenters said that if additional load forecasting information is requested in the IRP review process, Western should accept any other required report containing this type of information that is submitted to the Department of Energy (DOE) or the Federal Energy Regulatory Commission (FERC). One commenter noted Western should require only the information necessary to define load characteristics, and not the specific nature of the use of that power, relating to the load forecasting criteria (§ 905.11(b)(5)).

Section 114 of EPAct gives Western the authority to review its IRP program and to revise the IRP compliance criteria set forth in EPAct (42 U.S.C. 7276b(b)), which have been implemented through EPAMP at 10 CFR part 905, to reflect changes in technology, needs, or other development. Because Western's IRP regulations were developed under the traditional utility planning framework, which no longer applies to many customers due to wholesale and retail electric competition, Western believes it is essential to review and subsequently revise the criteria.

Additionally, Western's criteria revisions reduce reporting and paperwork burdens for customers and Western. Western streamlined the IRP criteria in § 905.11(b) to make them less comprehensive and restrictive, especially by changing the regulations to state that Western will accept summary information from customers rather than full data. While customers must include the criteria detailed in § 905.11(b), many of the items within in these criteria—for example, the list of what the options evaluated should relate to in § 905.11(b)(1)—are general guidelines and not strict requirements. Western's intent is not to dictate resource choices or specific mechanisms for resource planning, but rather to provide a general outline for IRP that meets the spirit and intent of EPAct. Reducing the criteria further would not meet the spirit or intent of EPAct even in light of the changing nature of the electric utility industry. Accepting even more summary information would not allow Western to adequately evaluate IRPs and annual reports and amendments.

It is not appropriate to add the phrase “for new energy resources” to the end of the first sentence in § 905.11(a) because EPAct makes no such limitation. IRPs may, at the customer's discretion, incorporate all energy resources. Limiting an IRP to only new energy resources may be contrary to sound resource planning.

“Must” has replaced “shall” in § 905.11(a) to meet plain language guidelines. The comment that “should” was used in the original language in § 905.11(a) is incorrect. The original language, which was taken from the sentence following the definition of “integrated resource planning” in EPAct and § 905.2, used the verb “shall.” Because EPAct Section 201(2) mandates these components of IRP, Western will continue to use “must” rather than “should.”

Western has dropped the “designation of least-cost options” criteria, previously located at § 905.11(b)(3), deleting some language that is no longer relevant and moving the remaining relevant language to the “identification of resource options” criteria (§ 905.11(b)(1)). Because least cost is no longer a deciding factor for many customers— and is often perceived as a barrier for some customers in further pursuit of DSM and renewable energy—Western believes it may impede effectively implementing IRP.

Because Section 114 of EPAct gives Western authority to revise its IRP criteria, allowing customers to determine their own action planning horizons in § 905.11(b)(2) is not inconsistent with EPAct. Moreover, determining action planning horizons is essential for customers facing wholesale competition. Many customers must make resource decisions on real-time bases that simply could not be planned for in advance and therefore included in either short-term or long-term action plans. Action planning flexibility is essential in the changing electric utility industry.

Western has returned the modifier “to the extent practicable” to § 905.11(b)(3), environmental effects, to reflect the language in EPAct. Western has returned the modifier “ample opportunity” to § 905.11(b)(4), public participation. It was removed to accommodate plain language, but keeping it in the rule allows customers to continue to meet the public involvement criteria in a manner consistent with the language of EPAct.

Western will accept information required by DOE, FERC, or another entity so long as it contains adequate load forecasting information. Western's intent is not to require duplicative efforts, but to ensure Western receives the specific customer information needed to fully evaluate the IRP. Western only requires the information necessary to define load characteristics, and will request information about the specific nature of the use of that power only in those rare cases where it is necessary to adequately evaluate the IRP.

A. Comment

One commenter requested that the phrase “Such IRP or IRPs shall constitute the MBA's IRP where the MBA subcontracts or acts as an agent but does not assume power supply responsibility” be returned to § 905.12(b)(2), as it is in the existing regulations.

Western agrees that under § 905.12(b)(2), the IRP may constitute the MBA's IRP where the MBA subcontracts or acts as an agent but does not assume power supply responsibility. The definition of MBA in § 905.2 meets the intent of the phrase, so in light of plain language guidelines and the need for clarity in the regulations, Western does not feel it is necessary to adopt this comment.

One comment suggested that an existing IRP cooperative should be able to file the new report alternatives on behalf of its participants.

Western agrees that an IRP cooperative should be able to file a minimum investment report on behalf of its participants, just as a consultant can now prepare and submit an IRP or small customer plan on behalf of a utility or end-use customer. Language has been added to § 905.12(b)(3) to this effect.

One commenter said that Western cannot extend the definition of small customer to include members of joint-action agencies (JAA) and generation and transmission (G&T) cooperatives with power supply responsibility because EPAct specifically excludes these entities, while some commenters noted that the ability of individual members of JAAs and G&T cooperatives to prepare small customer plans would greatly simplify the task of meeting Western's IRP requirements for a substantial number of customers.

One commenter suggested that “customer” should be added after “utility” in § 905.15(e)(1)(i) to mirror the language used in the definition of small customer (§ 905.2).

After further review, Western determined that the best approach is not to include members of JAAs and G&T cooperatives with power supply responsibility within the small customer provision. However, Western does have the ability to change the criteria for determining IRP compliance, as set forth in Section 114 of EPAct. Western also noted that JAA and G&T cooperative members with less than 25 gigawatthours (GWh) use and sales may have limited managerial, economic, and resource capability, similar to other small customers. Their resource scenarios are often similar, and their ability to conduct IRP just as limited. Accordingly, Western has created new, reduced IRP compliance criteria for JAA and G&T cooperative customers not qualifying for “small customer” status and yet have less than 25 GWh use and sales and have limited managerial, economic, and resource capability, at § 905.11(c). These criteria mirror the criteria set forth in the small customer provision at § 905.15, and are consistent with the flexibilities provided to Western under EPAct. These certain customers must conduct IRP, but under less stringent criteria to reflect their limited capabilities. Unlike the small customer provision, qualifying customers do not need to notify Western in advance if complying through the use of these reduced IRP compliance criteria. Western will use qualifying customers' annual IRP progress reports to verify ongoing eligibility.

“Customer” has been added after “utility” in § 905.15(e)(1)(i) as suggested, to match the definition in § 905.2.

Western received a number of general comments about the proposed new alternatives—minimum investment report, public benefits report, and EE/RE report. One commenter noted that the alternatives appear to be essentially the same, so they should be combined.

A number of comments suggested that eligibility for State, Tribal, and Federal Government mandates on these alternatives is too narrow, and that the alternatives should also be open to standard-setting by local governing boards such as city councils and utility boards. Another commenter said alternatives should include mandates set by either State law or State policy. One comment suggested Western should establish some of its own mandates for minimum investments and EE/RE reports. One commenter noted the proposed alternatives should only be applicable in States in which retail competition exists.

One commenter requested that in instances where the State, Tribal, or Federal Government has implemented a program that meets Western's alternatives, Western defer its review authority and accept every report on or stemming from these programs.

Some comments called for additional clarification as to how State, Tribal, or Federal mandates are to be applied for multi-state entities, such as MBAs and IRP cooperatives.

Some commenters noted that Western should add provisions to the alternatives to allow for joint reporting by a group of customers.

One commenter noted that Western was not requiring customers to submit revisions to approved alternative reports every 5 years, as provided for IRPs and small customer plans.

Several municipalities and rural electric cooperatives asked if preparing energy efficiency plans as required by their State's public utility commission could satisfy any of Western's alternative reporting requirements.

Western believes that the EE/RE report alternative is clearly different from the minimum investment and public benefits report alternatives, in large part because it applies only to end-use customers. Western agrees that the minimum investment report and public benefits report are essentially the same. Western eliminated the separate public benefits report alternative and combined the relevant public benefits language with the minimum investment report alternative. Language noting that public benefits charges are included within the definition of minimum investment report has been added in § 905.2, as well.

Western does not agree that limiting the alternatives to mandates set only by State, Tribal, and Federal Governments is too narrow. Likewise Western believes it is inappropriate for it to set such mandates. Because of the broad and open nature of lawmaking and regulatory processes at the State and Federal levels in comparison to the processes of Western's customers, Western is reluctant to accept any lesser mandates. Additionally, as a Federal agency, Western defers to Tribes' sovereign authority to set their own minimum investment or EE/RE reporting requirements.

While Western always reviews submissions—whether IRP or alternatives—for reasonableness, Western is more comfortable with broad decision making (State or Federal) that customers must follow by law, and prefers to rest on the minimum investment and EE/RE requirements set at higher levels of government. Customers not under the jurisdiction of State, Tribal, or Federal Governments with minimum investment or EE/RE reporting requirements must meet the IRP or small customer provision, as applicable.

Similarly, Western does not agree that the energy efficiency and renewable energy mandates for all alternatives should be allowed by State policy. State law or State regulations developed by the public utilities commission or its equivalent must be the standard. Policy adopted by State end-use customers does not meet the intent of the alternative reporting requirements. Otherwise, State end-use customers are setting their own minimum investment or EE/RE requirements, which is contradictory to the intent of these regulations.

Western does not agree that the proposed alternatives should only be applicable in States where retail competition exists. The passage of EPAct created wholesale competition, followed by FERC's mandate for open access to transmission systems. These events have had a far larger impact on utility resource planning and use than retail competition. Wholesale competition drives resource decisions, especially real-time and short-term resource acquisition.

Western will not defer its authority in instances where the State, Tribal, or Federal Government has implemented a program that meets the alternatives, because this approach would not satisfy our obligations. EPAct mandates that Western collect, evaluate, and report on data to meet EPAct's IRP requirements. Western must report on the data annually to Congress, and, to meet this requirement, must receive adequate data from all customers. While Western will accept reports that fully meet the criteria contained in the alternative provisions (§ 905.16 and § 905.17, respectively), a request to submit the reports must be submitted and approved prior to submitting the report.

Western agrees that additional clarification is needed regarding application of the new alternatives to multi-state entities. Accordingly, Western has developed a new paragraph (c) in the minimum investment report alternative at § 905.16. A multi-state customer choosing to comply with the minimum investment alternative must apply the highest minimum investment level mandated by any State or Tribal jurisdiction within its service territory to all customers in States or Tribal jurisdictions without mandated minimum investments. In instances where more than one State or Tribal jurisdiction has a minimum investment requirement, those should be applied to customers within that State or Tribal jurisdiction. To qualify for the minimum investment alternative, however, the highest investment level must still be applied to customers in States or Tribal jurisdictions without requirements. Alternatively, multi-state entities can complete the streamlined IRP outlined in § 905.11. Western is willing to work with multi-state entities to ensure the most effective, and least burdensome, compliance mechanism.

Western will allow minimum investment reports to be submitted by MBAs on behalf of the MBA or one or more of its members, and by IRP cooperatives on behalf of its participants, as detailed in § 905.16(a). This is also demonstrated by applying the definitions of customers and MBAs in § 905.2, to statements in § 905.12(b) and (c).

Western agrees it should require customers to submit revisions to their approved alternative reports every 5 years, as provided for IRPs and small customer plans, and has revised the regulations accordingly.

Municipalities and rural electric cooperatives subject to State regulatory jurisdiction can potentially satisfy the requirements of the minimum investment report alternative based on energy efficiency plans prepared to comply with requirements established by their State's public utility commission. They must submit requests to prepare the minimum investment reports and, if Western approves the requests, must submit reports, meeting the requirements of these regulations, particularly § 905.16.

One commenter requested that customers be allowed to continue meeting the levels of minimum investment established by State, Tribal, or Federal mandate once the mandate has expired or is otherwise no longer in effect. One comment suggested the minimum investment requirement should include the full array of DSM, including both energy efficiency and load management, instead of just energy efficiency.

Because Western is allowing the State, Tribal, or Federal mandate to set the minimum level of investment and related parameters, subject to Western's review for reasonableness, Western cannot allow customers to continue applying the minimum investment once the mandate no longer exists. If the State, Tribal, or Federal Government chooses to terminate the mandate, Western sees no compelling reason to continue to recognize an expired standard.

Western agrees that it should not restrict the permissible demand-side minimum investment activities to just those that can be categorized as energy efficiency, so it has expanded the list of acceptable categories in § 905.16(b)(1) and elsewhere by changing the term “energy efficiency” to “DSM,” which includes energy efficiency, load management, and other demand-side measures.

Many comments suggested that Schedule 5 of Energy Information Administration (EIA) Report No. 861, EIA Report No. 412, and Federal Energy Regulatory Commission (FERC) Form No. 1, be acceptable as approved reports under the EE/RE report alternative. One commenter said that the EE/RE report is not a substitute for IRP, and should be withdrawn. One commenter noted that reports submitted by Federal agencies in accordance with Section 303 of Executive Order (EO) 13123 should be considered as meeting the EE/RE reporting requirement, while another comment suggested any reporting requirement should be waived for Federal customers under the mandate of EO 13123 because compliance with EO 13123 sufficiently satisfies the intended goals of EPAct.

The intent underlying the EE/RE report was not clearly understood by customers and stakeholders, so additional clarifying language has been added to § 905.17. The language emphasizes that the EE/RE report applies only to end-use customers, and that it is based on a mandate by a State, Tribal, or Federal Government to implement energy efficiency and/or renewable energy activities within a specified timeframe, for which there is also an associated reporting requirement. Therefore, EIA Reports No. 861 and 412, and FERC Form No. 1 cannot be accepted because they have no mandated energy efficiency or renewable energy requirements. Western will, however, accept any of these reports as all or part of an annual IRP progress report so long as it meets by itself, or meets when supported by additional information, the IRP annual reporting criteria set forth in § 905.14, IRP annual reporting.

Western believes the EE/RE report is an acceptable alternative to the IRP because of the associated energy efficiency and/or renewable energy mandate.

In general, it is Western's belief that the reports for specific Federal end-use customers under EO 13123 will be acceptable as EE/RE reports. However, a requirement to comply with EO 13123 does not excuse a Federal end-use customer from complying with this rule. Western does not agree that a report submitted by a Federal agency in accordance with EO 13123 should automatically be considered as meeting the EE/RE reporting requirements. Any Federal end-use customer must first request EE/RE report status and then submit reports that provide data specific to that Federal end-use customer. Western must report to Congress annually about the activities undertaken by its customers, so the agency must receive adequate information, as specified in § 905.17, about the activities of the Federal end-use customer. Aggregate reports of the agency where the end-use customer is only a part are not acceptable. The EE/RE report must contain customer-specific data.

Some commenters noted that Western needs to clarify whether this section applies to the small customer plan and new alternatives as well as the IRP. A number of commenters said that there should be no IRP reporting obligation in those States that have adopted retail restructuring. Some commenters requested that water conservation measures be allowed in addition to energy efficiency and renewable energy in Western's alternatives. One commenter noted that “shall” was changed to “will,” and that there should be a clarifying statement that this language change was editorial in nature.

This section applies to small customer plans and new alternatives as well as IRP. To make this clearer, Western changed the word “IRP” in the title of the section to “plans and reports” and moved this section so that it follows the IRP, small customer provision, minimum investment report, and EE/RE report sections.

Western does not agree that there should be no IRP reporting obligation in those states that have adopted retail restructuring. Neither wholesale nor retail competition negate Section 114 of EPAct. Even though our customers may be subject to retail competition, Western will continue to require each of its customers to comply with the IRP or an applicable alternative under this rule.

Western has considered water planning, efficiency improvements, and conservation in the same manner it considers energy planning and efficiencies for IRP and small customer planning, as detailed in § 905.18(d). Accordingly, Western will consider water conservation measures for the new alternatives, so long as the mandates for the new alternatives extend to water conservation measures. Western will not allow measures other than those identified by alternative-related State, Tribal, or Federal mandates, and will additionally use the reasonableness criteria as detailed in Section 114 of EPAct and § 905.18(a) in reviewing all plans and reports.

Western changed “shall” to “will” to comply with the requirements for plain language. The change is editorial and does not suggest any substantive change.

One comment suggested a time period for resubmittal of reports that is similar to language in “Western's review of IRPs” paragraph be included in § 905.19, as well.

Western agrees that time periods for resubmitting plans and reports should be consistent. We have moved the “Western's review of IRPs” paragraph from § 905.13 to § 905.19, and added additional language to clearly indicate the resubmittal timing pertains to IRPs, small customer plans, minimum investment reports, and EE/RE reports.

One comment suggested that instead of imposing the existing penalty scheme for non-compliant customers, Western should penalize customers up to the amount they “under-spent” on a given public benefits program. A commenter also suggested that, for penalties, Western should limit the liability to 10 percent of power charges and earmark the penalty funds to a public benefits fund for investment in energy efficiency and renewable energy in the non-complying customer's service territory. One commenter noted that Western should clarify that the 30-day good faith period for compliance applies to all plans and reports.

Other than plain language revisions, and clarifications to ensure that the penalties and 30-day good faith period are applicable to all plans and reports, Western will not implement any changes to the penalty provisions. The penalty scheme is mandated in Section 114 of EPAct, and Western believes these standards are adequate to ensure compliance with the rule.

One commenter said that a reference to the exemptions under FOIA should be added, and broadened to include 10 CFR part 1004.10. The intent should be further clarified by designating as proprietary any information that relates to State retail competition which state law and/or regulation has classified as proprietary. One commenter said that, if Western requests additional information to support Western's review of IRP submittals, Western should agree to use due diligence in protecting the information. The commenter also suggested Western ensure customers have flexibility in determining a reasonable level of data collection and reporting given individual situations.

Western has removed the specific reference to 10 CFR part 1004.11, and will not include a specific reference to 10 CFR part 1004.10, recognizing that these references are too narrow, may change, and therefore may not remain accurate. Instead, Western has added the term “applicable” in front of FOIA, to make it clear that any FOIA exemptions may be requested and, if appropriate, granted. Western has also added the phrase, “recognizing that certain competition-related customer information may be proprietary,” to the end of the last sentence.

Given customer concerns over proprietary and potentially proprietary information, Western will accept summary information in the IRP rather than full data. However, customers should not have unlimited discretion in determining the amount of data required by Western. Western is always willing to work with customers to ensure we receive adequate, but not unnecessary, data. However, Western must have access to sufficient data to verify that customers are meeting the intent of EPAct and the IRP regulations. Western understands customers' concerns over proprietary information, and will ensure that it applies FOIA protections to customer information.

Western has an exemption from centralized regulatory review under Executive Order 12866; accordingly, no clearance of this rulemaking by the Office of Management and Budget (OMB) is required.

The Regulatory Flexibility Act of 1980, 5 U.S.C. 601, et seq. , requires Federal agencies to perform a regulatory flexibility analysis if a proposed regulation is likely to have a significant economic impact on a substantial number of small entities. Western's Administrator certified that the proposed rule would have no significant adverse impact on a substantial number of small entities because the proposed revisions to these regulations reduce paperwork and financial and other burdens, as well as reporting redundancies for small entities. Western did not receive any comments on this certification.

In accordance with the Paperwork Reduction Act of 1980, 44 U.S.C. 3501-3520, Western has received approval from OMB to collect customer information in this rule, under control number 1910-1200.

Western prepared an environmental impact statement (EIS) and record of decision (ROD) pursuant to NEPA for EPAMP, which established the existing IRP requirements for Western power customers. The EIS met the requirements of NEPA, 42 U.S.C. 4321, et seq. , the Council on Environmental Quality Regulations for implementing NEPA (40 CFR parts 1500-1508), and the DOE NEPA Implementing Procedures and Guidelines (10 CFR part 1021). Since the proposed revisions would modify the IRP requirements addressed in the EPAMP EIS, Western completed a review and determined a supplemental EIS is not required. A revised EPAMP ROD has been issued.

Executive Order 13132 (64 FR 43255, August 4, 1999) imposes certain requirements on agencies formulating and implementing policies or regulations that preempt State law or that have federalism implications. Agencies are required to examine the constitutional and statutory authority supporting any action that would limit the policymaking discretion of the States and carefully assess the need for such actions. Western has examined this rule and determined that it does not preempt State law and does 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. No further action is required by Executive Order 13132.

Title II of the Unfunded Mandates Reform Act of 1995 requires each agency to assess the effects of Federal regulatory action on State, local, and Tribal governments and the private sector. Western has determined that this regulatory action does not impose an additional Federal mandate on State, local, or Tribal governments or on the private sector.

With respect to the review of existing regulations and the promulgation of new regulations, section 3(a) of Executive Order 12988, “Civil Justice Reform” (61 FR 4729, February 7, 1996), imposed on Executive agencies the general duty to adhere to the following requirements: (1) Eliminate drafting errors and ambiguity; (2) write regulations to minimize litigation; and (3) provide a clear legal standard for affected conduct rather than a general standard and promote simplification and burden reduction. With regard to the review required by section 3(a), section 3(b) of Executive Order 12988 specifically requires that Executive agencies make every reasonable effort to ensure that the regulation: (1) Clearly specifies the preemptive effect, if any; (2) clearly specifies any effect on existing Federal law or regulation; (3) provides a clear legal standard for affected conduct while promoting simplification and burden reduction; (4) specifies the retroactive effect, if any; (5) adequately defines key terms; and (6) addresses other important issues affecting clarity and general draftsmanship under any guidelines issued by the Attorney General. Section 3(c) of Executive Order 12988 requires Executive agencies to review regulations in light of applicable standards in section 3(a) and 3(b) to determine whether they are met or if it is unreasonable to meet one or more of them. Western has completed the required review and determined that, to the extent permitted by law, the regulations meet the relevant standards of Executive Order 12988.

Section 654 of the Treasury and General Government Appropriations Act, 1999 (Pub. L. 105-277) requires Federal agencies to issue a Family Policymaking Assessment for any proposed rule that may affect family well-being. The final rule has no impact on the autonomy or integrity of the family as an institution. Accordingly, Western has concluded that it is not necessary to prepare a Family Policymaking Assessment.

Under Executive Order 13084 (Consultation and Coordination with Indian Tribal Governments), Western may not issue a discretionary rule that significantly or uniquely affects Indian tribal governments and imposes substantial direct compliance costs. The incremental amendments involved in this rulemaking would not have such effects. Accordingly, Executive Order 13084 does not apply to this rulemaking.

As required by 5 U.S.C. 801, DOE will report to Congress on the promulgation of the rule prior to its effective date. The report will state that it has been determined that the rule is not a “major rule” as defined by 5 U.S.C. 804(3).

Pursuant to the authority of sections 10(b), 13, 14, 19, et al., of the Federal Reserve Act, the Board has amended its Regulation A (12 CFR part 201) to incorporate changes in discount rates on Federal Reserve Bank extensions of credit. The discount rates are the interest rates charged to depository institutions when they borrow from their district Reserve Banks.

The “basic discount rate” is a fixed rate charged by Reserve Banks for adjustment credit and, at the Reserve Banks' discretion, for extended credit. In increasing the basic discount rate from 5.25 percent to 5.5 percent, the Board acted on requests submitted by the Boards of Directors of the twelve Federal Reserve Banks. The new rates were effective on the dates specified below. The 25-basis-point increase in the discount rate was associated with a similar increase in the federal funds rate approved by the Federal Open Market Committee and announced at the same time.

The Board and the Reserve Banks remain concerned that increases in demand will continue to exceed the growth in potential supply, which could foster inflationary imbalances that would undermine the economy's record economic expansion. Against the background of their long-run goals of price stability and sustainable economic growth and of the information currently available, the Board and the Reserve Banks believe the risks are weighted mainly toward conditions that may generate heightened inflation pressures in the foreseeable future.

Pursuant to section 605(b) of the Regulatory Flexibility Act (5 U.S.C. 605(b)), the Board certifies that the change in the basic discount rate will not have a significant adverse economic impact on a substantial number of small entities. The rule does not impose any additional requirements on entities affected by the regulation.

The provisions of 5 U.S.C. 553(b) relating to notice and public participation were not followed in connection with the adoption of the amendment because the Board for good cause finds that delaying the change in the basic discount rate in order to allow notice and public comment on the change is impracticable, unnecessary, and contrary to the public interest in fostering price stability and sustainable economic growth.

The provisions of 5 U.S.C. 553(d) that prescribe 30 days prior notice of the effective date of a rule have not been followed because section 553(d) provides that such prior notice is not necessary whenever there is good cause for finding that such notice is contrary to the public interest. As previously stated, the Board determined that delaying the changes in the basic discount rate is contrary to the public interest.

A proposal to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) by superseding AD 98-01-15, amendment 39-10277 (63 FR 1909, January 13, 1998), which is applicable to certain Airbus Model A330 and A340 series airplanes, was published in the Federal Register on December 14, 1999 (64 FR 69674). The action proposed to continue to require repetitive operational tests of the override mechanism of the trimmable horizontal stabilizer (THS), and to require replacement of existing FCPC's with improved FCPC's, which would terminate the repetitive operational tests.

Interested persons have been afforded an opportunity to participate in the making of this amendment. No comments were submitted in response to the proposal or the FAA's determination of the cost to the public.

The FAA has determined that air safety and the public interest require the adoption of the rule as proposed.

None of the airplanes affected by this action are on the U.S. Register. All airplanes included in the applicability of this rule currently are operated by non-U.S. operators under foreign registry; therefore, they are not directly affected by this AD action. However, the FAA considers that this rule is necessary to ensure that the unsafe condition is addressed in the event that any of these subject airplanes are imported and placed on the U.S. Register in the future.

Should an affected airplane be imported and placed on the U.S. Register in the future, it will require approximately 1 work hour to accomplish the operational test required by AD 98-01-15, and retained in this AD, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of the operational test on U.S. operators is estimated to be $60 per airplane, per test cycle.

It will require approximately 2 work hours to accomplish the FCPC replacements (or 9 work hours if the FCPC on-board replacement modules have been replaced or reprogrammed), at an average labor rate of $60 per work hour. Required parts will be provided to the operator at no charge. Based on these figures, the cost impact of the FCPC replacements required by this AD on U.S. operators will be $120 or $540 per airplane.

Accomplishment of the FCPC replacements required by this AD will allow operators to terminate the repetitive operational tests required by AD 98-01-15, thereby offsetting the cost of the actions required by this AD.

The regulations adopted herein 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, it is determined that this final rule does not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this action (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A final evaluation has been prepared for this action and it is contained in the Rules Docket. A copy of it may be obtained from the Rules Docket at the location provided under the caption ADDRESSES .

Transport Canada, the airworthiness authority for Canada, notified the FAA that an unsafe condition may exist on the BHTC Model 407 helicopters. Transport Canada advises that there have been several reports of cracks to the tail boom skin in the area of the horizontal stabilizer.

BHTC has issued Alert Service Bulletin 407-99-26, dated April 13, 1999 (ASB), which specifies a preflight check of the left-side of the tail boom before the next flight and before the first flight of every day thereafter. The ASB also specifies within the next 25 hours time-in-service (TIS) and thereafter every 50 hours inspecting any tail boom that has accumulated 600 or more hours TIS for a crack and replacing any cracked tail boom before further flight. Transport Canada classified this ASB as mandatory and issued AD CF-99-17, dated June 14, 1999, to ensure the continued airworthiness of these helicopters in Canada.

This helicopter model is manufactured in Canada and is type certificated for operation in the United States under the provisions of section 21.29 of the Federal Aviation Regulations (14 CFR 21.29) and the applicable bilateral airworthiness agreement. Pursuant to this bilateral airworthiness agreement, Transport Canada has kept the FAA informed of the situation described above. The FAA has examined the findings of Transport Canada, reviewed all available information, and determined that AD action is necessary for products of this type design that are certificated for operation in the United States.

Since an unsafe condition has been identified that is likely to exist or develop on other BHTC Model 407 helicopters of the same type design registered in the United States, this AD is being issued to prevent separation of the tail boom and subsequent loss of control of the helicopter. This AD requires a preflight check of the tail boom before further flight and thereafter before the first flight of each day. This AD also requires within 25 hours TIS and thereafter at intervals not to exceed 50 hours TIS, inspecting any tail boom that has accumulated 600 or more hours TIS for a crack with a 10X or higher magnifying glass and replacing any cracked tail boom with an airworthy tail boom before further flight. The actions are required to be accomplished in accordance with the ASB described previously. The short compliance time involved is required because the previously described critical unsafe condition can adversely affect the controllability and structural integrity of the helicopter. Therefore, checking the tail boom for a crack is required prior to further flight and this AD must be issued immediately.

An owner/operator (pilot) may perform the visual check required by this AD but must enter compliance with this AD in the aircraft records in accordance with 14 CFR 43.11 and 91.417(a)(2)(v)). This AD allows a pilot to perform this check because it involves only a visual check for a crack in the tail boom and can be performed equally well by a pilot or a mechanic.

Since a situation exists that requires the immediate adoption of this regulation, it is found that notice and opportunity for prior public comment hereon are impracticable, and that good cause exists for making this amendment effective in less than 30 days.

The FAA estimates that 200 helicopters will be affected by this AD, that it will take approximately 4 work hours to accomplish the inspections, and that the average labor rate is $60 per work hour. Based on these figures, the total cost impact of the AD on U.S. operators is estimated to be $48,000 assuming no tail boom will be replaced.

Although this action is in the form of a final rule that involves requirements affecting flight safety and, thus, was not preceded by notice and an opportunity for public comment, comments are invited on this rule. Interested persons are invited to comment on this rule by submitting such written data, views, or arguments as they may desire. Communications should identify the Rules Docket number and be submitted in triplicate to the address specified under the caption ADDRESSES. All communications received on or before the closing date for comments will be considered, and this rule may be amended in light of the comments received. Factual information that supports the commenter's ideas and suggestions is extremely helpful in evaluating the effectiveness of the AD action and determining whether additional rulemaking action would be needed.

Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the rule that might suggest a need to modify the rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report that summarizes each FAA-public contact concerned with the substance of this AD will be filed in the Rules Docket.

Commenters wishing the FAA to acknowledge receipt of their comments submitted in response to this rule must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. 99-SW-75-AD.” The postcard will be date stamped and returned to the commenter.

The regulations adopted herein 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, it is determined that this final rule does not have federalism implications under Executive Order 13132.

The FAA has determined that this regulation is an emergency regulation that must be issued immediately to correct an unsafe condition in aircraft, and that it is not a “significant regulatory action” under Executive Order 12866. It has been determined further that this action involves an emergency regulation under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979). If it is determined that this emergency regulation otherwise would be significant under DOT Regulatory Policies and Procedures, a final regulatory evaluation will be prepared and placed in the Rules Docket. A copy of it, if filed, may be obtained from the Rules Docket at the location provided under the caption ADDRESSES.

The FAA published this direct final rule with a request for comments in the Federal Register on December 29, 1999 (64 FR 72925). The FAA uses the direct final rulemaking procedure for a non-controversial rule where the FAA believes that there will be no adverse public comment. This direct final rule advised the public that no adverse comments were anticipated, and that unless a written adverse comment, or a written notice of intent to submit such an adverse comment, were received within the comment period, the regulation would become effective on April 20, 2000. No adverse comments were received, and thus this notice confirms that this direct final rule will become effective on that date.

To ensure that we periodically review the need for our CRS rules and their effectiveness, section 255.12 of the rules establishes a sunset date. The original sunset date was December 31, 1997. We have changed the rules' expiration date twice before, once to March 31, 1999, 62 FR 66272 (December 18, 1997), and then to March 31, 2000, 64 FR 15127 (March 30, 1999).

We are now changing the sunset date to March 31, 2001, because we have been unable to complete our reexamination of the current rules by March 31, 2000. Given our view that the current rules should be maintained pending our reexamination of the need for rules, we proposed to change the rules' expiration date to March 31, 2001, and gave interested persons an opportunity to comment on that proposal. 65 FR 11009 (March 1, 2000). We received comments from Delta Air Lines, Amadeus Global Travel Distribution, Worldspan, and the American Society of Travel Agents, all of which supported the proposal.

We adopted our CRS rules because they are necessary to protect airline competition and to ensure that consumers can obtain accurate and complete information on airline services. 65 FR at 11010-11011. Because almost all airlines found it essential to participate in each CRS, market forces did not discipline the price and quality of service offered airlines by the CRSs. Travel agents relied on CRSs to provide airline information and bookings for their customers, and almost all airlines received a large majority of their bookings from travel agencies. Travel agencies typically used only one system (or predominantly used one system even if they had access to two or more systems). Each airline therefore had to participate in an agency's system if it wished to have its services readily saleable by that agency. Each system, moreover, was controlled by airlines or airline affiliates, who could use them to unreasonably prejudice the competitive position of other airlines or to provide misleading or inaccurate information to travel agents and their customers. For these reasons, we adopted rules regulating CRS operations in the United States, 57 FR 43780 (September 22, 1992). 65 FR at 11009-11010.

Our rules included a sunset date, December 31, 1997, to ensure that we would reexamine whether the rules remained necessary and whether they were effective. 57 FR at 43829-43830 (September 22, 1992). We have begun a reexamination of our current rules by publishing an advance notice of proposed rulemaking that invited interested persons to comment on whether we should readopt the rules and, if so, with what changes. 62 FR 47606 (September 10, 1997). Almost all of the parties responding to our advance notice of proposed rulemaking have urged us to maintain CRS rules, and many of them argued that various changes should be made to the rules to strengthen them. 65 FR at 11010.

Because we have been unable to complete our reexamination of the rules, we have twice changed the sunset date, most recently to March 31, 2000. 64 FR 15127 (March 30, 1999). We proposed again to change the expiration date for the rules to March 31, 2001, so that they would remain in effect pending our reexamination of our rules, since we could not complete that reexamination by March 31, 2000. 65 FR 11009 (March 1, 2000). The proposed temporary extension of the current rules would maintain the status quo until we determine which rules, if any, should be adopted. As we explained, maintaining the rules in effect appeared to be necessary to protect airline competition and consumers against unreasonable practices in view of our earlier findings on the market power of the systems and each airline owner's potential interest in using its affiliated CRS to prejudice the competitive position of other airlines. Furthermore, allowing the current rules to expire could be disruptive, since the systems, airlines, and travel agencies have been conducting their operations in the expectation that each system will comply with the rules. 65 FR at 11010-11011.

Finally, maintaining the rules in effect appeared necessary to comply with the United States' obligations under various treaties and bilateral air services agreements to assure foreign airlines a fair and equal opportunity to compete. 65 FR at 11011.

As we stated, our inability to complete the rules' reexamination is unfortunate due to the importance of adapting our rules to current industry conditions. This inability has stemmed from the need to address other airline competition issues that appeared to be more urgent. In addition, recent developments in airline distribution practices, most notably the growing importance of the Internet, are requiring additional study by the staff. As we noted, moreover, our existing rules appear to prevent the practices that present serious threats to airline competition and to the ability of consumers to obtain unbiased and accurate information through the systems. We have been aware, however, that several parties are alleging that the compelling need for certain additional CRS regulations requires us to act promptly on those issues without waiting for the completion of the overall reexamination of the rules. 65 FR 11010.

Because we needed to make the proposed amendment effective by March 31, 2000, we shortened the comment period to ten days. 65 FR at 11009.

We received comments from four parties: Delta Air Lines, Worldspan, Amadeus Global Distribution System (“Amadeus”), and the American Society of Travel Agents (“ASTA”). The commenters agree that the rules should be extended as we proposed. Amadeus, however, urges us to act on its request that we prohibit the tying of a travel agency's access to an airline's corporate discount fares with the agency's use of the system affiliated with that airline (Docket OST-99-5888). ASTA contends that we should act quickly on its proposal that systems be prohibited from selling marketing data derived from travel agent bookings to airlines, which would require the amendment of section 255.10. Worldspan, on the other hand, asserts that we should reexamine the rules in one comprehensive proceeding rather than address selected issues in separate proceedings.

We are changing the rules' sunset date to March 31, 2001, as we proposed. Delta, Amadeus, Worldspan, and ASTA support our proposal, and no one has objected to it. We based our proposal on the findings made by us in earlier CRS rulemakings and the position of almost all parties in the underlying rulemaking Docket OST-97-2881 that CRS rules are still necessary. 65 FR at 11011. In our overall reexamination of the rules we will, of course, consider whether recent developments, such as the divestiture by several airlines of their CRS ownership interests, indicate that there may be little need for some or all of the CRS rules.

ASTA and Amadeus each urge us to act quickly on the specific rule proposals of interest to it. We will consider their requests as part of our consideration of procedures for completing the reexamination of the rules and for updating the rules to reflect current industry conditions. We also plan to announce soon procedures for moving forward with the overall reexamination of the rules.

We have determined for good cause to make this amendment effective on March 31, 2000, rather than thirty days after publication as required by the Administrative Procedure Act, 5 U.S.C. 553(d), except for good cause shown. To maintain the current rules in force, we must make this amendment effective by March 31, 2000. Since the amendment preserves the status quo, it will not require the systems, airlines, and travel agencies to change their operating methods. As a result, making the amendment effective less than thirty days after publication will not burden anyone.

This rule is a nonsignificant regulatory action under section 3(f) of Executive Order 12866 and has not been reviewed by the Office of Management and Budget under that order. The proposal is also not significant under the regulatory policies and procedures of the Department of Transportation, 44 FR 11034 (February 26, 1979).

In our notice of proposed rulemaking, we tentatively determined that maintaining the current rules should impose no significant costs on the CRSs. The systems' continuing compliance with the rules on displays and functionality should not impose a substantial burden, since they have already taken the steps necessary to comply with those requirements. Keeping the rules in effect would benefit participating airlines, since they would otherwise be subjected to unreasonable terms for participation, and benefit consumers, who might otherwise be given incomplete or inaccurate information on airline services. The rules also contain provisions that are designed to prevent abuses in the systems' competition with each other for travel agency subscribers. 65 FR at 11011.

Our last comprehensive CRS rulemaking included an economic analysis, and we stated our belief that that analysis remains applicable to our extension of the rules' expiration date. We concluded that no new economic analysis appeared to be necessary, but we stated that we would consider comments from any party on that analysis before we again revised the rules' sunset date. 65 FR at 11011.

No one filed comments on the economic analysis, so we are basing this rule on the analysis used in our last comprehensive CRS rulemaking. We will prepare a new economic analysis as part of our review of the existing rules, if we determine that rules remain necessary.

This rule does not impose unfunded mandates or requirements that will have any impact on the quality of the human environment.

Congress enacted the Regulatory Flexibility Act of 1980, 5 U.S.C. 601 et seq. , to ensure that small entities are not unnecessarily and disproportionately burdened by government regulations. The act requires agencies to review proposed regulations that may have a significant economic impact on a substantial number of small entities. For purposes of this rule, small entities include smaller U.S. and foreign airlines and smaller travel agencies. Our notice of proposed rulemaking set forth the reasons for our proposed extension of the rules' expiration date and the objectives and legal basis for that proposed rule. 65 FR at 11011.

We also noted that keeping the current rules in force would not change the existing regulation of small businesses. We referred to the final rule in our last comprehensive CRS rulemaking, which contained an analysis underlying our determination that the rules would not have a significant economic impact on a substantial number of small entities. In proposing to revise the sunset date to March 31, 2001, we reasoned that that analysis appeared to remain valid for that proposed extension. We therefore adopted that analysis as our tentative regulatory flexibility statement but stated that we would consider any comments filed on that analysis in connection with the proposal. 65 FR at 11011.

We tentatively concluded that maintaining our existing CRS rules would primarily affect two types of small entities, smaller airlines and travel agencies. The rules would also affect all small entities that purchase airline tickets, since airline fares may be somewhat lower than they would otherwise be, although the amount may not be large, if our CRS rules allow airlines to operate more efficiently than they otherwise would. 65 FR at 11011.

Keeping the rules in effect would benefit smaller airlines that have no ownership interest in a CRS, since the rules prohibit certain potential system practices that could injure the smaller airlines' ability to operate profitably and compete successfully. The rules, for example, bar display bias and discriminatory booking fees. Without the rules, the systems' airline affiliates could use them to prejudice the competitive position of other airlines. 65 FR at 11011-11012.

The rules additionally affect the operations of smaller travel agencies, primarily by prohibiting certain CRS practices that could unreasonably restrict the travel agencies' ability to use more than one system or to switch systems. The rules prohibit CRS contracts that have a term longer than five years, give travel agencies the right to use third-party hardware and software, and prohibit certain types of contract clauses, such as minimum use and parity clauses, that restrict an agency's ability to use multiple systems. By prohibiting display bias based on carrier identity, the rules also enable travel agencies to obtain more useful displays of airline services. 65 FR at 11012.

We invited interested persons to address our tentative conclusions under the Regulatory Flexibility Act in their comments submitted in response to this notice of proposed rulemaking. 65 FR at 11012.

No one filed comments on our Regulatory Flexibility Act analysis. We will adopt the analysis set forth in the notice of proposed rulemaking.

Our proposed rule contained no direct reporting, record-keeping, or other compliance requirements that would affect small entities. There are no other federal rules that duplicate, overlap, or conflict with our proposed rules.

I certify under section 605(b) of the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ) that this regulation will not have a significant economic impact on a substantial number of small entities.

This proposal contains no collection-of-information requirements subject to the Paperwork Reduction Act, Pub.L. No. 96-511, 44 U.S.C. Chapter 35.

We stated that we had reviewed this rule in accordance with the principles and criteria contained in Executive Order 13132, dated August 4, 1999, and determined that it 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. The rule will not limit the policymaking discretion of the States. Nothing in it would directly preempt any State law or regulation. We are adopting this amendment primarily under the authority granted us by 49 U.S.C. 41712 to prevent unfair methods of competition and unfair and deceptive practices in the sale of air transportation. In our notice of proposed rulemaking, we stated our belief that the policy set forth in the proposed rule is consistent with the principles, criteria, and requirements of the Federalism Executive Order and the Department's governing statute. We welcomed comments on our conclusions.

No one submitted comments on our federalism assessment. Therefore, we will make that assessment final. Because the rule will have no significant effect on State or local governments, as discussed above, no consultations with State and local governments on this rule were necessary.

The statements in the staff accounting bulletins are not rules or interpretations of the Commission, nor are they published as bearing the Commission's official approval. They represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

We are correcting several references and other minor problems found in the following parts under 20 CFR chapter III, revised as of April 1, 1999.

1. Part 401— Privacy and Disclosure of Official Records and Information. We are amending § 401.20(b)((1) to show correct cross-references.

2. Part 402— Availability of Information and Records to the Public. We are amending § 402.35(b)(2) to show correct cross-references.

3. Part 404— Federal Old-Age, Survivors and Disability Insurance (1950- ). We are correcting a typographical error in § 404.337(a), and we are amending §§ 404.401, 404.403(d)(1), 404.450(d), 404.456(c), 404.457(a)(3), 404.1275, 404.1408, and 404.1410(a) to show correct cross-references. Also, we are revising § 404.1201 to restore (a)(1) and (a)(2) which had been inadvertently removed. In addition, we are removing duplicate sentences in § 404.1597a(b)(3)(ii) and (h)(2)(ii).

4. Part 410— Federal Coal Mine Health and Safety Act of 1969, Title IV—Black Lung Benefits (1969- ). We are correcting §§ 410.240(g) and 410.601(a) and (b) to show correct cross-references. We are also correcting the authority citation for Subpart F to show the correct punctuation.

5. Part 416— Supplemental Security Income for the Aged, Blind, and Disabled. We are correcting cross-references in: §§ 416.428, 416.702(“ Essential person ”); 416.929(d)(4); 416.993(a); 416.994a(g)(4) and (g)(6); 416.1104; 416.1202(a); 416.1323(a); 416.1336(b); 416.1442(f)(1); 416.1801(c) (“ Spouse ”); 416.2045(a); and 416.2096(c)(5).

6. Part 422— Organization and Procedures. We are correcting §§ 422.125, 422.135, and 422.135 to show correct cross-references.

Pursuant to section 702(a)(5) of the Act (42 U.S.C. 902(a)(5)), SSA follows the Administrative Procedure Act (APA) rulemaking procedures specified in 5 U.S.C. 553 in the development of its regulations. The APA provides exceptions to its prior notice and public comment procedures when an agency finds there is good cause for dispensing with such procedures on the basis that they are impracticable, unnecessary, or contrary to the public interest. We have determined that, under 5 U.S.C. 553(b)(B), good cause exists for dispensing with the notice and public comment procedures in this case. Good cause exists because these are minor technical changes which make no substantive change in the regulations and have no effect on the public. Therefore, opportunity for prior comment is unnecessary, and we are issuing these changes to our regulations as a final rule. In addition, SSA is not providing a 30-day delay in the effective date of this final rule under 5 U.S.C. 553(d). This is not a substantive rule, and there is no change in policy. Accordingly, the requirements of 5 U.S.C. 553(d) are inapplicable.

SSA has consulted with the Office of Management and Budget (OMB) and determined that this final rule does not meet the criteria for a significant regulatory action under Executive Order 12866. Thus, it was not subject to OMB review.

SSA certifies that this final rule will not have a significant economic impact on a substantial number of small entities since it makes no changes in policy. Therefore, a regulatory flexibility analysis as provided in Public Law 96-354, the Regulatory Flexibility Act, as amended, is not required.

This final rule imposes no additional reporting or recordkeeping requirements subject to OMB clearance.

In a notice published in the Federal Register of April 22, 1997 (62 FR 19580), FDA announced that a food additive petition (FAP 7B4537) had been filed by Japan Vilene Co., Ltd., c/o Center for Regulatory Services, 2347 Paddock Lane, Reston, VA 20191 (current 5200 Wolf Run Shoals Rd., Woodbridge, VA 22192). The petition proposed to amend the food additive regulations to provide for the safe use of 2-propenoic acid, polymer with 2-ethyl-2-(((1-oxo-2-propenyl)oxy)methyl)-1,3-propanediyl di-2-propenoate and sodium 2-propenoate (CAS Reg. No. 76774-25-9) as a fluid absorbent material intended for use in contact with food.

FDA has evaluated data in the petition and other relevant material. Based on this information, the agency concludes that: (1) The proposed use of the additive is safe, (2) the additive will achieve its intended technical effect, and therefore, (3) the regulations in 21 CFR 177.1211 should be amended as set forth below in this document.

In accordance with § 171.1(h) (21 CFR 171.1(h)), the petition and the documents that FDA considered and relied upon in reaching its decision to approve the petition are available for inspection at the Center for Food Safety and Applied Nutrition by appointment with the information contact person listed above. As provided in § 171.1(h), the agency will delete from the documents any materials that are not available for public disclosure before making the documents available for inspection.

The agency has carefully considered the potential environmental effects of this action. FDA has concluded that the action will not have a significant impact on the human environment, and that an environmental impact statement is not required. The agency's finding of no significant impact and the evidence supporting that finding, contained in an environmental assessment, may be seen in the Dockets Management Branch (address above) between 9 a.m. and 4 p.m., Monday through Friday.

This final rule contains no collections of information. Therefore, clearance by the Office of Management and Budget under the Paperwork Reduction Act of 1995 is not required.

Any person who will be adversely affected by this regulation may at any time file with the Dockets Management Branch (address above) written objections by May 1, 2000. Each objection shall be separately numbered, and each numbered objection shall specify with particularity the provisions of the regulation to which objection is made and the grounds for the objection. Each numbered objection on which a hearing is requested shall specifically so state. Failure to request a hearing for any particular objection shall constitute a waiver of the right to a hearing on that objection. Each numbered objection for which a hearing is requested shall include a detailed description and analysis of the specific factual information intended to be presented in support of the objection in the event that a hearing is held. Failure to include such a description and analysis for any particular objection shall constitute a waiver of the right to a hearing on the objection. Three copies of all documents are to be submitted and are to be identified with the docket number found in brackets in the heading of this document. Any objections received in response to the regulation may be seen in the Dockets Management Branch between 9 a.m. and 4 p.m., Monday through Friday.

Med-Pharmex, Inc., 2727 Thompson Creek Rd., Pomona, CA 91767-1861, filed ANADA 200-275 that provides for veterinary prescription use of triamcinolone acetonide cream on dogs for topical treatment of allergic dermatitis and summer eczema. Med-Pharmex's ANADA 200-275 MEDALOG cream is approved as a generic copy of Fort Dodge Animal Health's NADA 46-146 VETALOG® cream. ANADA 200-275 is approved as of February 4, 2000, and 21 CFR 524.2481(b) is amended to reflect the approval. The basis for approval is discussed in the freedom of information summary.

In accordance with the freedom of information provisions of 21 CFR part 20 and 514.11(e)(2)(ii), a summary of safety and effectiveness data and information submitted to support approval of this application may be seen in the Dockets Management Branch (HFA-305), Food and Drug Administration, 5630 Fishers Lane, rm. 1061, Rockville, MD 20852, between 9 a.m. and 4 p.m., Monday through Friday.

The agency has determined under 21 CFR 25.33(a)(1) that this action is of a type that does not individually or cumulatively have a significant effect on the human environment. Therefore, neither an environmental assessment nor an environmental impact statement is required.

This rule does not meet the definition of “rule” in 5 U.S.C. 804(3)(A) because it is a rule of “particular applicability.” Therefore, it is not subject to the congressional review requirements in 5 U.S.C. 801-808.

On October 21, 1999 (64 FR 56882), HUD published a final rule that specified the method HUD will use in allocating housing assistance available to renew expiring contracts with public housing agencies (PHAs) for Section 8 tenant-based housing assistance. As required by statute, the October 21, 1999 final rule was the product of a negotiated rulemaking, following implementation, as further required by statute, of a HUD notice on this subject. The purpose of this document is to correct two typographical errors contained in the October 21, 1999 final rule. Specifically, this document corrects all references to a “CACC” to read “consolidated ACC.” This document also inserts a missing hyphen in one of the references in § 982.102 to “project-based assistance.”

On September 15, 1999, HUD published a final rule (64 FR 50140) that implements sections 1012 and 1013 of the Residential Lead-Based Paint Hazard Reduction Act of 1992 (42 U.S.C. 4851 et seq. ). The purpose of the rule is to ensure that Federally-owned or assisted housing does not pose lead-based paint hazards to young children. The majority of the provisions contained in the final rule will become effective on September 15, 2000 (one year following the date of publication). This document corrects two typographical errors contained in the September 15, 1999 final rule that regard the Section 8 Housing Choice Voucher program (codified at 24 CFR part 982) and the Section 8 Project-Based Certificate program (codified at 24 CFR part 983). The corrections made by this document are as follows:

1. Correction to § 982.305 (PHA approval of assisted tenancy). This document corrects a typographical error contained in § 982.305(b) of the September 15, 1999 final rule. The September 15, 1999 final rule amended paragraph (b)(3) of § 982.305 to reference the lead-based disclosure information required under 24 CFR 35.92(b). This reference is more appropriately set forth in paragraph (b)(1)(ii) of § 982.305. This document makes the necessary correction. As corrected by this document, 982.305(b)(1)(ii) provides that, before the beginning of the initial term of the lease for the unit, the landlord and the tenant must have executed the lease (including the HUD-prescribed tenancy addendum, and the lead-based paint disclosure information as required in 24 CFR 35.13(b)).

2. Correction to § 983.1 (Purpose and applicability). This document corrects a typographical error contained in § 983.1 of the September 15, 1999 final rule. Paragraph (b) of § 983.1 describes the provisions of 24 CFR part 982 that apply to the Section 8 Project-Based Certificate program. The September 15, 1999 final rule amended § 983.1(b) by adding a citation to § 982.401(j). However, the citation did not explain to readers that § 982.401(j) contains applicable lead-based paint requirements. This document adds a parenthetical after the citation to clarify this point.

On October 21, 1999 (64 FR 56894), HUD published a final rule implementing the Section 8 tenant-based program provisions of the Quality Housing and Work Responsibility Act of 1998 (Title V of the FY 1999 HUD Appropriations Act; Pub.L. 105-276, approved October 21, 1998) (referred to as the “Public Housing Reform Act”). Of particular significance, the October 21, 1999 final rule implemented section 545 of the Public Housing Reform Act. Section 545 provides for the complete merger of the Section 8 tenant-based certificate and voucher programs. HUD's regulations for the new Section 8 merger program (known as the “Housing Choice Voucher program”) are located at 24 CFR part 982.

The October 21, 1999 final rule became effective on November 22, 1999. The final rule was preceded by HUD's publication of an interim rule on May 14, 1999 (64 FR 56894). The October 21, 1999 final rule adopted without change the provisions of the interim rule. The final rule also took into consideration of the public comments received on the interim rule, and most of the changes made at the final rule stage were in response to public comment.

This document makes several corrections to the October 21, 1999 final rule. Additionally, this document corrects several regulatory provisions of the Housing Choice Voucher program that were not part of the October 21, 1999 final rule. These technical revisions correct typographical errors and inconsistencies with other HUD program requirements. These corrections are non-substantive, and do not modify or create any new program requirements. The corrections will help to ensure that, once codified in title 24 of the Code of Federal Regulations, the regulations for the new Section 8 merger program are free of error and consistent with other HUD program requirements.

For the convenience of readers, the following discussion of the corrections made by this document is organized in the order of the regulatory section being corrected.

1. Definitions (§ 982.4). This document corrects § 982.4, which sets forth the definitions applicable to the Housing Choice Voucher program. Currently, part 982 refers readers to section 3(b) of the United States Housing Act of 1937 (42 U.S.C. 1437a(b)) for the definitions of several terms applicable to the merger program. This document replaces the cross-reference to section 3(b) with a cross-reference to HUD's regulations at 24 CFR part 5, subpart D. HUD established 24 CFR part 5 to set forth the definitions and other program requirements that are generally applicable to HUD's programs. The definitions provided in part 5 are substantively identical to those located in section 3(b).

2. How applicants are selected: General requirements (§ 982.202). This document corrects § 982.202 to conform with § 982.207 of the October 21, 1999 final rule, since HUD approval is no longer required for the public housing agency (PHA) to adopt a residency preference. This document also corrects an erroneous regulatory citation contained in § 982.202.

3. Waiting list: Administration of waiting list (§ 982.204). This document corrects § 982.204 by removing paragraph (b)(5), which merely repeats the language of paragraph (b)(4).

4. Waiting list: Different programs (§ 982.205). This document corrects § 982.205(b)(1) to clarify the definition of “other housing assistance.” This document also removes § 982.205(b)(3), which incorrectly refers to a PHA offer of assistance under “both the certificate program and the voucher program.” As noted above, the new Housing Choice Voucher program merges the Section 8 tenant-based certificate and voucher programs into a single voucher program. Accordingly, PHAs no longer have two forms of Section 8 tenant-based assistance to offer families.

5. Waiting list: Local preferences in admission to program (§ 982.207). This document corrects § 982.207 to eliminate unnecessary redundancy. Specifically, paragraph (a)(1) of this section provides that the “system of local preferences must be consistent with the PHA plan . . . and with the consolidated plans for local governments in the jurisdiction.” Preferences are already covered under HUD's PHA Plan regulations, which require consistency with the Consolidated Plan (see 24 CFR part 903). Accordingly, it is unnecessary to include the quoted provision in part 982.

This document also corrects a typographical error contained in § 982.207(b)(5) of the October 21, 1999 final rule. Specifically, this document adds a phrase to the end of paragraph (b)(5) that clarifies that single persons who are elderly, displaced, homeless, or persons with disabilities may be granted an admissions preference over other single persons. The phrase “over other single persons” was inadvertently omitted from the October 21, 1999 final rule. This correction will also clarify that a PHA may continue to have a selection preference that was statutorily mandated prior to the enactment of the Public Housing Reform Act.

6. PHA disapproval of owner (§ 982.306) and Owner breach of contract (§ 982.453). This document corrects a typographical error contained in these two sections. Specifically, it replaces the phrase “housing assistance payments contract” with the phrase “HAP contract.”

7. Table of contents for Subpart K—Rent and Housing Assistance Payment. This document corrects several typographical errors contained in the table of contents for part 982, subpart K. As corrected by this document, the table of contents now accurately reflects the sections contained in subpart K.

8. Conversion to voucher program (§ 982.502). This document corrects § 982.502(c) to clarify the elimination of the so-called “shopping incentive.” Under the post-merger voucher subsidy formula (42 U.S.C. 1437f(o)(2), as amended by section 545 of the Public Housing Reform Act), the maximum subsidy for a family may not exceed the actual gross rent of the unit (rent to owner plus tenant-paid utilities) (§ 982.505(b)(2)). This change eliminates the old “shopping incentive” for a family that rents a unit below the applicable payment standard.

For a pre-merger voucher tenancy, the May 14, 1999 interim rule (which was adopted without change by the October 21, 1999 final rule) provides that the elimination of the shopping incentive (by application of § 982.505(b)(2) in the new voucher subsidy calculations) does not apply for calculation of the housing assistance payment prior to the second regular reexamination of family income on or after the merger date—but does not state explicitly that the elimination of the shopping incentive does apply in calculation of subsidy for such pre-merger voucher tenancies from that point on. The rule is now corrected to state positively, as originally intended, that the elimination of the shopping incentive (by application of § 982.505(b)(2)) is applicable for each interim or regular examination effective on or after the effective date of the second regular reexamination of family income and composition on or after the merger date.

9. Voucher tenancy: Payment standard amount and schedule (§ 982.503). This document makes two corrections to § 982.503. Under the Housing Choice Voucher program, the PHA adopts a “payment standard schedule” that sets “payment standard amounts” that are used to calculate the amount of subsidy for families assisted in the PHA's voucher program. This document corrects § 982.503(a)(3) to specify that the PHA schedule may set a single payment standard amount for a whole Fair Market Rent (FMR) area, or may establish a separate payment standard amount for each “designated part” of the FMR area.

The PHA voucher payment standard schedule establishes a single payment standard amount for each unit size. For each unit size, the PHA may establish a single payment standard amount for the whole FMR area, or may establish a separate payment standard amount for each designated part of the FMR area.

Under the terms of the May 14, 1999 interim rule (which was adopted by the October 21, 1999 final rule without change), a PHA may apply for HUD approval to set a payment standard amount—for a part of the FMR area—that is higher than the “basic range” (i.e., the range from 90 percent to 110 percent of the published FMR). However, the October 21, 1999 final rule failed to specify that the PHA may set a payment standard amount for part of an FMR area within or below the basic range.

As corrected by this document, the final rule now provides that the PHA may set payment standard amounts for designated parts of the FMR area. The PHA may establish such payment standard amounts above, within or below the basic range. However, as provided in the May 14, 1999 interim rule, the PHA must request HUD approval to set any payment standard amount that is higher or lower than the basic range. The correction does not change the regulatory requirement for HUD approval of a payment standard amount higher than the basic range (called a “exception payment standard amount”).

The October 21, 1999 final rule is also corrected by deleting § 982.503(b)(1)(iii) concerning authority to establish a higher payment standard if required as a reasonable accommodation for a family that includes a person with disabilities. This subject is now moved to § 982.505(d), since § 982.505 covers establishment of the payment standard for an individual family (whereas § 982.503 concerns the establishment of the PHA payment standard schedule for families in the PHA program).

10. Rent to owner: Effect of rent control (§ 982.509). This document corrects the section heading of § 982.509. The May 14, 1999 interim rule provided an incorrect designation for this section (“Rent to owner in subsidized projects”). The incorrect section heading was adopted by the October 21, 1999 final rule. As corrected, the section heading for § 982.509 reads: “Rent to owner: Effect of rent control.”

11. Distribution of housing assistance payment (§ 982.514). This document corrects § 982.514, to clarify that if the PHA elects to pay the utility supplier directly, the PHA must notify the family of the amount paid to the utility supplier.

12. Family income and composition: Regular and interim examinations (§ 982.516). This document corrects a typographical error contained in § 982.516(g)(1) of the October 21, 1999 final rule. Specifically, this document replaces an incorrect citation to 24 CFR part 760 with the correct citation to 24 CFR 5.230.

13. Rent to owner in subsidized project (§ 982.521). This document corrects § 982.521, by reinserting regulatory language that was accidentally deleted from the pre-merger regulations (at § 982.512).

14. PHA denial or termination of assistance for family (§ 982.552). This document corrects a typographical error contained in § 982.552(x) of the October 21, 1999 final rule. The final rule provides that a PHA may deny or terminate assistance to a welfare-to-work (WTW) family, if the family fails to fulfill its obligations under the WTW voucher program. The final rule inadvertently failed to include the necessary qualifier that a family must “willfully and persistently” fail to fulfill its WTW obligations in order for the PHA to deny or terminate assistance to the WTW family. This document makes the necessary correction.

15. Informal hearing for participant (§ 982.555). This document corrects two typographical errors contained in § 982.555. First, it corrects the paragraph (b)(5) to provide that a PHA is not required to provide a hearing if the PHA determines not to approve a unit or “tenancy” (rather than “lease”). Secondly, this document corrects the title of paragraph (e)(2) to read “Discovery” (rather than “Discover”).

16. Correction to 24 CFR part 983. In addition to the corrections to the part 982 regulations, this document makes a correction to HUD's regulations at 24 CFR part 983. The part 983 regulations establish the requirements governing the Section 8 Project-Based Certificate program. This document removes an outdated statutory citation contained in § 983.1(a).

On December 3, 1999 (64 FR 67982), HUD published a final rule amending its regulations for the Section 8 Management Assessment Program (SEMAP). The December 3, 1999 final rule adopted the amendments to the SEMAP regulations made by HUD's July 26, 1999 (64 FR 40496) interim rule. The July 26, 1999 interim rule made various technical amendments to the SEMAP regulations. The public comment period on the interim rule closed on September 24, 1999. No public comments were submitted on the interim rule. Accordingly, the December 3, 1999 final rule adopted the amendments made by the interim rule without change. The final rule became effective on January 3, 2000.

In addition to finalizing the July 26, 1999 interim rule, the December 3, 1999 final rule also made several amendments to conform the SEMAP regulations to HUD's October 21, 1999 (64 FR 56894) final rule implementing the statutory merger of the Section 8 tenant-based certificate and voucher programs into the new Housing Choice Voucher program (the regulations for this new program are codified at 24 CFR part 982).

The purpose of this document is to correct two typographical errors contained in the SEMAP regulations at 24 CFR part 985. Specifically, § 985.3 provides two incorrect percentages in the provisions regarding the rating of public housing agency (PHA) management performance. The corrections were intended to be part of the December 3, 1999 final rule, but were inadvertently omitted from that rule. This document makes the necessary correction to the December 3, 1999 final rule.

A notice of proposed rulemaking [CGD 08-99-023] was published on November 26, 1999.

One comment was received from Shell Exploration and Production Company requesting that the latitude and longitude for each referenced facility be added into the regulation. The Coast Guard agrees and has made the additions.

The safety zones established by this regulation are in the deepwater area of the Gulf of Mexico. For the purposes of this regulation the deepwater area is considered to be waters of 304.8 meters (1,000 feet) or greater depth extending to the limits of the Exclusive Economic Zone (EEZ) contiguous to the territorial sea of the United States and extending to a distance up to 200 nautical miles from the baseline from which the breadth of the sea is measured. Navigation in the area of the safety zones consists of large commercial shipping vessels, fishing vessels, cruise ships, tugs with tows and the occasional recreational vessel. The deepwater area also includes an extensive system of fairways. The fairways include the Gulf of Mexico East-West fairway, the entrance and exit route of the Mississippi River, and the Houston-Galveston Safety Fairway. Significant amounts of vessel traffic occur in or near the various fairways in the deepwater area.

Shell Offshore, Inc. requested that the Coast Guard establish safety zones around the following Shell platforms in the Gulf of Mexico: the Boxer Platform, The Bulwinkle Platform, the Ursa Tension Leg Platform, the West Delta Platform, the Mars Tension Leg Platform, the Ram-Powell Tension Leg Platform, and the Auger Tension Leg Platform.

The request for the safety zones was made due to the high level of shipping activity around the platforms and the safety concerns for both the personnel aboard the platforms and the environment. Shell Offshore, Inc. indicated that the location, production level, and personnel levels on board the seven platforms make it highly likely that any allision with the platforms would result in a catastrophic event. Some of the platforms are located near the edge of a shipping safety fairway or fairway intersection. Others are located in open waters where no fixed structures previously existed. All are high production oil and gas drilling platforms producing from 100,000 to 250,000 barrels of oil per day, and are manned with crews ranging from approximately 130 to 156 people.

The Coast Guard has reviewed Shell Offshore Inc.'s concerns and agrees that the risk of allision to the platforms and the potential for loss of life and damage to the environment resulting from such an accident warrant the establishment of these safety zones. The West Delta 143 platform covered by this regulation did not meet the deepwater criteria; however, the Coast Guard believes its exposed location adjacent to a safety fairway and volume of throughput necessitated its inclusion into the rulemaking. The regulation would significantly reduce the threat of allisions, oil spills, and releases of natural gas and increase the safety of life, property, and the environment in the Gulf of Mexico.

This rule is not a significant regulatory action under Executive Order 12866 and is not significant under the “Department of Transportation Regulatory Policies and Procedures” (44 FR 11040; February 26, 1979). The Coast Guard expects the economic impact of this rule to be so minimal that a full regulatory evaluation is unnecessary. The impacts on routine navigation are expected to be minimal.

This rule contains no collection of information requirements under the Paperwork Reduction Act (44 U.S.C. 3501 et seq. ).

The Coast Guard has analyzed this rule under the principles and criteria contained in Executive Order 13132 and has determined that it does not have federalism implications under that Order.

The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) governs the issuance of Federal regulations that require unfunded mandates. An unfunded mandate is a regulation that requires a State, local, or tribal government or the private sector to incur direct costs without the Federal Government's having first provided the funds to pay those costs. This rule would not impose an unfunded mandate.

This rule would not effect a taking of private property or otherwise have taking implications under E.O. 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.

This rule meets applicable standards in sections 3(a) and 3(b)(2) of E.O. 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.

We have analyzed this rule under E.O. 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and does not concern an environmental risk to health or risk to safety that may disproportionately affect children.

The Coast Guard considered the environmental impact of this rule and concluded that under section 2-1, paragraph (34)(g) of Commandant Instruction M16475.1C this proposal is categorically excluded from further environmental documentation.

Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ), the Coast Guard must consider whether this regulation will have a significant economic impact on a substantial number of small entities. “Small entities” include small business and not-for-profit organizations that are independently owned and operated, that are not dominant in their field, and that otherwise qualify as “small business concerns” under section 3 of the Small Business Act (15 U.S.C. 632). Since alternate routes are available for the small number of vessels to be affected by this regulation, the Coast Guard expects the impact of this regulation on small entities to be minimal. Therefore, the Coast Guard certifies under 5 U.S.C. 605 (b) that this regulation will not have a significant economic impact on a substantial number of small entities.

The Coast Guard Captain of the Port is establishing a temporary safety zone closing the Intracoastal Waterway at the 17th Street Causeway Bridge, Mile Marker 1065.9, in Fort Lauderdale, FL to all marine traffic. This closure has been requested by the Florida Department of Transportation in order to remove portions of the temporary and existing drawbridges across the waterway by contractors. The work includes removal of a 150-ton bridge span and 179-ton counterweight and will be carried out from several large barges anchored within the waterway. The Coast Guard has reviewed the planned scope of work and has determined that a safety zone and waterway closure are necessary to protect all vessels from potential safety hazards posed by construction activities. The closure of the waterway is scheduled for weekday and evening periods to minimize the impact to the boating community. The Coast Guard will issue Broadcast Notice to Mariners and the Florida Department of Transportation will place electronic message signs at various locations on the Intracoastal Waterway to advise mariners of the scheduled closure. Boat traffic will be directed to Hillsboro Inlet and the Port of Palm Beach to the north and Port Everglades to the south as alternate routes. The closure will be strictly enforced by the Coast Guard and will also be monitored by the Florida Marine Patrol.

In accordance with 5 U.S.C. 553, a notice of proposed rulemaking (NPRM) was not published for this rule and good cause exists for making it effective in less than 30 days after Federal Register Publication. Publishing an NPRM and delaying its effective date would be contrary to public safety since immediate action is needed to minimize potential danger to the public.

This proposal is not a “significant regulatory action” under section 3(f) of Executive Order 12866 and does not require an assessment of potential costs and benefits under section 6(a)(3) of that order. The Office of Management and Budget has not reviewed it under that order. It is not “significant” under the regulatory policies and procedures of the Department of Transportation (DOT) (44 FR 11040: February 26, 1979). The Coast Guard expects the economic impact of this proposal to be so minimal that a full Regulatory Evaluation under paragraph 10(e) of the regulatory policies and procedures of DOT is unnecessary. The safety zone will only be in effect for two 12 hour periods at night, and a 72 hour weekday period during the removal of the temporary drawbridge. Further, mariners have been advised through local notices and have alternate ways around the closure.

Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ), the Coast Guard must consider whether this rule will have a significant economic effect upon a substantial number of small entities. “Small entities” include small business, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000.

The Coast Guard certifies under 5 U.S.C. 605(b) that this rule will not have a significant economic impact on a substantial number of small entities as the regulations will only be in effect for three days during the temporary bridge removal, the closure will be publicized by broadcasts and signs, and mariners can get around the closure by using alternative inlets.

Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-221), we offer to assist small entities in understanding the rule so that they could better evaluate its effects on them and participate in the rulemaking process. Small entities may contact the person listed under FOR FURTHER INFORMATION CONTACT for assistance in understanding and participating in this rulemaking. We also have a point of contact for commenting on actions by employees of the Coast Guard. Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The Ombudsman evaluates these actions annually and rates each agency's responsiveness to small business. If you wish to comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR (1-888-734-3247).

This rule calls for no new collection of information requirements under the Paperwork Reduction Act (44 U.S.C. 3501 et seq. ).

We have analyzed this rule under Executive Order 13132 and have determined that this rule does not have implications for federalism under that order.

The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) governs the issuance of Federal regulations that require unfunded mandates. An unfunded mandate is a regulation that requires a State, local, or tribal government or the private sector to incur direct costs without the Federal Government's having first provided the funds to pay those unfunded mandate costs. This rule will not impose an unfunded mandate.

This rule will not effect a taking of private property or otherwise have taking disproportionately affect children.

This rule meets applicable standards in sections 3(a) and 3(b)(2) of E.O. 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.

We have analyzed this rule under E.O. 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and does not concern an environmental risk to health or safety that may disproportionately affect children.

The Coast Guard has considered the environmental impact of this action and has determined under figure 2-1, paragraph 34(g) of Commandant Instruction M16475.1C, that this rule is categorically excluded from further environmental documentation.

On October 6, 1998, VA published in the Federal Register an interim final rule generally exempting old law and section 306 pension beneficiaries from the requirement to submit annual eligibility verification reports (EVRs). (63 FR 53593-96, October 6, 1998.) The term “old law pension” means the disability and death pension programs that were in effect on June 30, 1960. The term “section 306 pension” means those disability and death pension programs in effect on December 31, 1978. VA uses EVRs to request information, such as income and marital status, that VA needs to determine or verify eligibility for its need-based benefit programs.

We requested interested persons to submit comments on or before December 7, 1998. We received no comments. Based on the rationale set forth in the interim final rule and in this document, we are adopting the interim final rule as a final rule without change, except that we are adding statements explaining that the information collections are approved by the Office of Management and Budget (OMB) under control number 2900-0101. We also affirm the information in the interim final rule document concerning the Regulatory Flexibility Act.

VA submitted the information collection provisions contained in the interim final rule to OMB for review in accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520). The only action concerning information collection is to eliminate certain collections of information. We requested interested parties to submit comments on the collection of information provisions to OMB by October 14, 1998. No comments were submitted. OMB has approved the information collection provisions under control number 2900-0101.

OMB assigns a control number for each collection of information it approves. VA may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.

Section 101(a)(5)(A) of the Marine Mammal Protection Act (Act) gives the Secretary of the Interior (Secretary) through the Director of the U.S. Fish and Wildlife Service (We) the authority to allow the incidental, but not intentional, taking of small numbers of marine mammals, in response to requests by U.S. citizens (You) [as defined in 50 CFR 18.27(c)] engaged in a specified activity (other than commercial fishing) in a specified geographic region.

Under the provisions of the Act, and based on our finding and the best scientific evidence available that the total of such taking for the 3-year period will have a negligible impact on these species and will not have an unmitigable adverse impact on the availability of these species for taking for subsistence use by Alaska Natives, we will allow the incidental taking of polar bears and Pacific walrus. These regulations set forth: (1) permissible methods of taking; (2) means of effecting the least practicable adverse impact on the species and their habitat and on the availability of the species for subsistence uses; and (3) requirements for monitoring and reporting.

The term “take” as defined by the Act means to harass, capture, or kill, or attempt to harass, hunt, capture, or kill any marine mammal.

Harassment as defined by the Act, as amended in 1994, “* * * means any act of pursuit, torment, or annoyance which—

(i) has the potential to injure a marine mammal or marine mammal stock in the wild; or

(ii) has the potential to disturb a marine mammal or mammal or marine mammal stock in the wild by causing disruption of behavioral patterns, including, but not limited to, migration, breathing, nursing, breeding, feeding, or sheltering.”

As a result of 1986 amendments to the Act, we amended 50 CFR 18.27 (i.e., regulations governing small takes of marine mammals incidental to specified activities) with a final rule published on September 29, 1989. Section 18.27(c) included, among other things, a revised definition of “negligible impact” and a new definition for “unmitigable adverse impact” as follows. Negligible impact is an impact resulting from the specified activity that cannot be reasonably expected to, and is not reasonably likely to, adversely affect the species or stock through effects on annual rates of recruitment or survival. Unmitigable adverse impact means an impact resulting from the specified activity:

(1) that is likely to reduce the availability of the species to a level insufficient for a harvest to meet subsistence needs by:

(i) causing the marine mammals to abandon or avoid hunting areas,

(ii) directly displacing subsistence users, or

(iii) placing physical barriers between the marine mammals and the subsistence hunters, and

(2) that cannot be sufficiently mitigated by other measures to increase the availability of marine mammals to allow subsistence needs to be met.

Industry conducts activities such as oil and gas exploration, development, and production in marine mammal habitat, and risks violating the prohibitions on the taking of marine mammals. Although Industry is under no legal requirement to obtain incidental take authority, Industry has chosen to seek authorization to avoid the uncertainties associated with conducting activities in marine mammal habitat. Along with their request for incidental take authority, Industry has also developed and implemented polar bear conservation measures.

On December 17, 1991, BP Exploration (Alaska), Inc., for itself and for Amerada Hess Corporation, Amoco Production Company, ARCO Alaska, Inc., CGG American Service, Inc., Conoco Inc., Digicon Geophysical Corp., Exxon Corporation, GECO Geophysical Co., Halliburton Geophysical Services, Inc., Mobil Oil Corporation, Northern Geophysical of America, Texaco Inc. Unocal corporation, and Western Geophysical company requested that we promulgate regulations pursuant to Section 101(a)(5) of the Act.

The geographic region defined in Industry's 1991 application included offshore waters beginning at a north/south line at Barrow, Alaska, east to the Canadian border, including all Alaska state waters and all Outer Continental Shelf (OCS) waters. The onshore region was defined by the same north/south line at Barrow, extending 25 miles inland and east to the Canning River. The Arctic National Wildlife Refuge was excluded from Industry's application.

On November 16, 1993 (58 FR 60402), we issued final regulations to allow the incidental, but not intentional, take of small numbers of polar bears and Pacific walrus when such taking(s) occurred during Industry activities during year-round operations in the Beaufort Sea Region as described in the preceding paragraph. The regulations were issued for 18 months. At the same time, the Secretary of the Interior directed us to develop, then begin implementation of, a polar bear habitat conservation strategy before extending the regulations beyond the initial 18 months for a total 5-year period as allowed by the Act. On August 14, 1995, we completed development of, and issued, our Habitat Conservation Strategy for Polar Bears in Alaska to ensure that the regulations met with the intent of the 1973 International Agreement on the conservation of Polar Bears. On August 17, 1995, we issued the final rule and notice of availability of a completed final polar bear habitat conservation strategy (60 FR 42805). We then extended the regulations for an additional 42 months to expire on December 15, 1998.

On August 28, 1997, BP Exploration (Alaska), Inc., submitted a petition for itself and for ARCO Alaska, Inc., Exxon Corporation, and Western Geophysical Company for rulemaking pursuant to Section 101(a)(5)(A) of the Act, and Section 553(e) of the Administrative Procedure Act (APA). Their request sought regulations to allow the incidental, but not intentional, take of small numbers of polar bears and Pacific walrus when takings occurred during Industry operations in Arctic Alaska. Specifically, they requested an extension of the incidental take regulations beginning at 50 CFR 18.121 for an additional 5-year term from December 16, 1998, through December 15, 2003. The geographic extent of the request was the same as that of previously issued regulations beginning at 50 CFR 18.121 that were in effect through December 15, 1998 (see above).

The petition to extend the incidental take regulations included two new oil fields (Northstar and Liberty). Plans to develop each field identified a need for an offshore gravel island and a buried subsea pipeline to transport crude oil to existing onshore infrastructure (Note: the term of these regulations will expire prior to the operation of Liberty; therefore, we neither analyzed nor authorized incidental take of polar bear and Pacific walrus at the Liberty prospect by this action, in part due to the preliminary and incomplete status of information available). Based on preliminary information related to subsea pipelines published in a Draft Environmental Impact Statement (DEIS) for the Northstar project, we were unable to make a finding of negligible impact and issue regulations for the full 5-year period. The information published in the Northstar DEIS suggested that the probability of an oil spill was 21-23 percent over the life of the project, and that up to 30 polar bears could be killed by a spill.

On November 17, 1998, we published proposed regulations (63 FR 63812) to allow the incidental, unintentional take of small numbers of polar bears and Pacific walrus in the Beaufort Sea and northern coast of Alaska. On January 28, 1999, we issued final regulations effective through January 30, 2000. These regulations did not authorize the incidental take of polar bears and Pacific walrus during construction or operation of subsea pipelines in the Beaufort Sea.

The U.S. Army Corps of Engineers finalized the Northstar Environmental Impact Statement in February 1999. Construction of the Northstar gravel island and subsea pipeline is scheduled for the winter of 1999-2000, with production beginning in the latter half of 2000. The Liberty development is proposed for early 2003. The Department of the Interior's Minerals Management Service (MMS) prepared a Preliminary Draft EIS for the Liberty development that was available as a working copy for participating and cooperating agencies. The MMS plans to issue a Draft EIS for Liberty this year.

These regulations respond to the August 28, 1997, request by BP Exploration (Alaska), Inc. for the extension of ongoing incidental take regulations. That request was for a period of 5 years, from December 16, 1998, through December 15, 2003. As previously mentioned, we issued regulations for 1 year that expired on January 30, 2000. On February 3, 2000 (65 FR 5275), we reinstated these regulations effective through March 31, 2000, to ensure that we had adequate time to consider public comments on this final rulemaking. This rule is effective March 30, 2000 and remains effective through March 31, 2000.

These regulations are for a 3-year period from March 31, 2000 and include all activities associated with the Northstar project. These regulations do not authorize the actual activities associated with the oil and gas exploration, development, and production, but rather authorized the incidental, unintentional take of small numbers of polar bears and Pacific walrus associated with those activities. The MMS, the U.S. Army Corps of Engineers, and the Bureau of Land Management are responsible for permitting activities associated with oil and gas activities in Federal waters and on Federal lands. The State of Alaska is responsible for activities on State lands and in State waters. These regulations allow Industry to incidentally take small numbers of polar bear and Pacific walrus within the same area as covered by our previous regulations as defined by a north/south line at Barrow, Alaska, including all Alaska State waters and all OCS waters, and east of that line to the Canadian border, with the onshore region being the same north/south line at Barrow, 25 miles inland and east to the Canning River. The Arctic National Wildlife Refuge is excluded from these regulations.

This rule requires an applicant to obtain from us a Letter of Authorization (LOA) to conduct exploration, development, and production activities pursuant to the regulations. Each group or individual conducting an oil and gas industry-related activity within the area covered by these regulations may request an LOA.

Applicants for LOAs must submit a plan to monitor the effects on polar bears and walrus that are present during the authorized activities. Applicants for LOAs must also include a Plan of Cooperation. The purpose of the Plan is to ensure that the impact of oil and gas activity on the availability of the species or stock for subsistence uses is negligible. The Plan must provide the procedures on how Industry will work with the affected Native communities and what actions will be taken to avoid interference with subsistence hunting of polar bears and Pacific walrus.

We will evaluate each request for an LOA on the specific activity and the specific location, and we will condition each LOA for that activity and location, if necessary. For example, a request to conduct activities on barrier islands with active bear dens or a history of polar bear denning may be conditioned to avoid the area until after the bears normally exit their dens.

In accordance with 50 CFR 18.27, Industry submitted a request for the promulgation of incidental take regulations pursuant to Section 101(a)(5)(A) of the Act. Activities covered in this regulation include Industry exploration, development, and production of oil and gas, as well as wildlife monitoring associated with these activities.

Exploration activities include, but are not necessarily limited to, geological surveys; geotechnical site investigations; reflective seismic exploration; vibrator seismics data collection; airgun and water gun seismic data collection; explosive seismic data collection; vertical seismic profiles; geological surveys; construction and use of drilling structures such as artificial (gravel) islands, caisson-retained islands, ice islands, bottom-founded structures (concrete island drilling system—CIDS, and single steel drilling caisson—SSDC), ice pads and ice roads; oil spill prevention, response, and cleanup; site restoration and remediation. Exploratory drilling for oil and associated support activities includes, but is not necessarily limited to, transportation to site, setup to 90-100 person camps, support camps (lights, generators, snow removal, water plants, wastewater plants, dining halls, sleeping quarters, mechanical shops, fuel storage, camp moves, landing strips, aircraft support, health and safety facilities, data recording facility and communication equipment), building gravel pads, building gravel islands with sandbag and concrete block protection, ice islands, ice roads, gravel hauling, gravel mine sites, road building, pipelines, electrical lines, water lines, road maintenance, buildings, and facilities, operating heavy equipment, digging trenches, burying pipelines, and covering pipelines, sea lift, water flood, security operations, dredging, moving CIDS, moving floating drill units, helicopter support, and drill ships such as the CANMAR Explorer III and the Kulluk.

Development activities associated with oil and gas industry operations include, but are not necessarily limited to, road construction; pipeline construction; waterline construction; gravel pad construction; camp construction (personnel, dining, lodging, maintenance shops, water plants, wastewater plants); transportation (automobile, airplane, and helicopter traffic; runway construction; installation of electronic equipment); well drilling; drill rig transport; personnel support; and demobilization, restoration, and remediation.

Production activities include, but are not necessarily limited to, personnel transportation (automobile, airplane, helicopter, boats, rollagons, cat trains, and snowmobiles), and unit operations (building operations, oil production, oil spills, cleanup, restoration, and remediation).

A large number of variables influence exploration activities, therefore, predictions as to the exact dates and locations of exploratory operations that will take place over the next 3 years is speculative. However, requests for LOAs must include specific details regarding dates, duration, and geographic locations of proposed activities.

Alaska's North Slope encompasses an area of 88,280 square miles and contains 13 separate oil and gas fields in production: Prudhoe Bay, North Prudhoe Bay State, Kuparuk, Endicott, Point McIntyre, Lisburne, Milne Point, Cascade, West Beach, Niakuk, Schrader Bluff, Badami and Sag Delta North. Additional discoveries have been made at the Northstar and Alpine fields, both of which are now in the development phase.

During the period covered by the regulations, we anticipate a similar level of activity at existing production facilities as during the previous 6 years. The addition of new exploration, development, and production activities will increase human activity and the likelihood of polar bear sightings. We do not believe that the overall activity level will have a measurable impact on polar bears during the 3-year period covered by these regulations. One addition is the new Northstar project, the first offshore production facility on the North Slope which requires a subsea pipeline to transport crude oil to the Trans-Alaska Pipeline System.

Pacific walrus (Odobenus rosmarus) typically inhabit the waters of the Chukchi and Bering seas. Most of the population congregates near the ice edge of the Chukchi Sea pack ice west of Point Barrow during the summer. In the winter, walrus inhabit the pack ice of the Bering Sea, with concentrations occurring in the Gulf of Anadyr, south of St. Lawrence Island, and south of Nunivak Island.

Walrus occur infrequently in the Beaufort Sea. Data from our Marking, Tagging, and Reporting Program show that, from 1994 through 1997, 73 walrus were reported killed by Barrow hunters. Tagging certificates show that nearly all of the 73 walrus were taken west of Barrow. In 6 years of monitoring Industry's activities in the Beaufort Sea, on-site monitors have observed only two walrus.

Polar bears ( Ursus maritimus ) occur in the Northern Hemisphere, where their distribution is circumpolar and they live in close association with polar ice. In Alaska, their distribution extends from south of the Bering Strait to the U.S.-Canada border. Two stocks occur in Alaska: the Chukchi/Bering seas stock, whose size is unknown, and the Southern Beaufort Sea stock, which was estimated in 1992 to number about 1,800 bears.

Females without dependent cubs breed in the spring and enter maternity dens by late November. Females with cubs do not mate. An average of two cubs are usually born in December, and the family group emerges from the den in late March or early April. Only pregnant females den for an extended period during the winter; however, other polar bears may burrow out depressions to escape harsh winter winds. Reproductive potential (intrinsic rate of increase) is low. The average reproductive interval for a polar bear is 3-4 years. The maximum reported age of reproduction in Alaska is 18 years. Based on these data, a polar bear may produce about 8-10 cubs in her lifetime. The loss of whole litters of cubs would result in additional reproductive effort sooner than if cubs survived. Even though reproduction increases, however, survival decreases.

The fur and blubber of the polar bear protect it from the cold air and frigid water. Newly emerged cubs of the year may not have a sufficient layer of blubber to maintain boy heat when immersed in water for long periods of time. Cubs abandoned prior to the normal weaning age of 2.5 years likely will not survive.

Ringed seals ( Phoca hispida ) are the primary prey species of the polar bear; however, occasionally, polar bears hunt bearded seals ( Erignathus barbatus ) and walrus calves. Polar bears also scavenge on marine mammal carcasses washed up on shore and eat non-food items such as styrofoam, plastic, car batteries, antifreeze, and lubricating fluids.

Polar bears have no natural predators, and they do not appear to be prone to death by disease or parasites. The most significant source of mortality is humans. Since 1972, with the passage of the Act, only Alaska Natives are allowed to hunt polar bears in Alaska. Bears are used for subsistence purposes such as the manufacture of handicraft and clothing items. The Native harvest occurs without restrictions on sex, age, number, or season, providing the population is not depleted and takes are non-wasteful. From 1980-1997, the total annual harvest in Alaska averaged 103 bears. The majority of this harvest (70 percent) came from the Chukchi and Bering Seas area.

Polar bears in the near shore Alaskan Beaufort Sea ware widely distributed in low numbers across the area with an average density of about one bear per 30 to 50 square miles. However, polar bears have been observed congregating on barrier islands in the fall and winter because of available food and favorable environmental conditions. Polar bears will occasionally feed on bowhead whale carcasses on barrier islands. In November 1996, biologists from the U.S. Geological Survey observed 28 polar bears near a bowhead whale carcass on Cross Island, and approximately 11 polar bears within a 2-mile radius of another bowhead whale carcass near the village of Kaktovik on Barter Island. In October 1997, we observed 47 polar bears on barrier islands and the mainland from Prudhoe Bay to the Canadian border, a distance of approximately 100 miles.

Oil and gas industry activities that generate noise such as air and vessel traffic, seismic surveys, ice breakers, supply ships, and drilling may frighten or displace Pacific walrus. Nonetheless, the primary range of the Pacific Walrus is west of Point Barrow. Pacific walrus do not normally range into the Beaufort Sea. Occasionally, a single walrus may be sighted east of Point Barrow. From 1994 to 1997, two Pacific walrus were sighted during an open-water seismic program. The program was conducted in the vicinity of Gwydyr Bay approximately 10 miles west of Prudhoe Bay. Marine mammal monitors sighted one sub-adult walrus approximately 5 miles northwest of Howe Island and BP Exploration's Endicott Unit. The second, a single adult walrus, was observed from a survey aircraft approximately 20 miles north of Pingok Island.

In winter, Pacific walrus inhabit the pack ice of the Bering Sea. As the winter range of the Pacific walrus is well beyond the geographic area covered by these regulations (as defined above), we do not expect any impacts to walrus from oil and gas activities during winter.

If walrus are present, their movements may be affected by stationary drilling structures. Walrus are attracted to certain activities and are repelled from others by noise or smell. In 1989 an incident occurred during a drilling operation in the Chukchi Sea where a young walrus surfaced in the center hole (i.e., moonpool) of a drill ship. The crew used a cargo net to remove the walrus from the drilling area, after which the walrus left the scene of the incident and was not seen again. No similar incidents have been reported in the area of these regulations.

Seismic surveys generally take place on solid ice or in open water. Since walrus activity occurs near the ice edge, interactions between walrus and seismic surveys are unlikely.

Due to the small number of walrus in the area covered by the regulations, any take reasonably likely to or reasonably expected to be caused by oil and gas activities will not result in more than a negligible impact on this species.

As the primary range of Pacific walrus is west and south of the Beaufort Sea, it is not surprising that few walrus are harvested in the Beaufort Sea along the northern coast of Alaska. Walrus constitute a small portion of the total marine mammal harvest for the village of Barrow. In the past 6 years, 73 walrus were reported taken by Barrow hunters. Reports indicate that all but 1 of the 73 walrus were taken west of Point Barrow, beyond the limits of the incidental take regulations. Hunters from Nuiqsut and Kaktovik do not normally hunt walrus east of Point Barrow and have taken only one walrus in the last 10 years. Therefore, due to the small number of walrus in the Native subsistence hunting areas covered by the regulations, any take reasonably likely to or reasonably expected to be caused by oil and gas activities will have no unmitigable adverse impacts on the availability of the Pacific walrus for subsistence use by Alaska Natives.

In the southern Beaufort Sea, polar bears spend the majority of their lives on the ice, which limits the opportunity for impacts from Industry. For example, although polar bears have been documented in open water, miles from the ice edge or ice floes, it is a relatively rare occurrence. Therefore, any takes resulting from exploration activities in the open-water season will not have more than a negligible impact on the polar bear.

Polar bears also spend a limited amount of time on land, coming ashore to feed, den, or move to other areas. At times when the ice edge is near shore and then quickly retreats northward, bears may remain along the coast or on barrier islands for several weeks until the ice returns. For those brief periods, the likelihood of interactions between polar bears and Industry activities increases. We have found that polar bear interaction planning and training requirements of the LOA process have increased polar bear awareness and have helped minimize these encounters. For example, in 1999 Exxon terminated work on Flaxman Island due to the presence of several polar bears in the vicinity of the work area.

Disturbances to denning females, either on land or on ice, are of particular concern. As part of the LOA application for seismic surveys during denning season, Industry provides us with the proposed seismic survey routes. To minimize the likelihood of disturbance to denning females, we evaluate these routes along with information about known polar bear dens, historic denning sites, and probable denning habitat. A standard condition of LOAs requires Industry to maintain a 1-mile buffer between survey activities and known denning sites. In addition, we may require Industry to avoid denning habitat until bears have left their dens. To further reduce the potential for disturbance to denning females, we are conducting research in cooperation with Industry to evaluate the use of remote sensing techniques, such as Forward Looking Infrared (FLIR) imagery, to detect active dens.

Industry activities that occur on or near the ice have greater possibility for encountering polar bears. Depending upon the circumstances, bears can be either repelled from or attracted to sounds, smells, or sights associated with these activities. As mentioned above, the LOA process requires the applicant to develop a polar bear interaction plan for each operation. These plans outline the steps the applicant will take to minimize impacts, such as garbage disposal procedures to reduce the attraction of polar bears. Interaction plans also outline the chain of command for responding to a polar bear sighting. In addition to interaction plans, Industry personnel participate in polar bear interaction training while on site. The result of these polar bear interaction plans and training is that when a bear encounters Industry activities, it is detected quickly, and responded to appropriately. Most often, this response involves deterring the bear from the site, with minimal effect. Without such plans and training, an undesirable outcome could be lethal take in defense of human life.

Over the span of our incidental take regulations, Industry reported 103 polar bear sightings. Of these, only 29 were instances where a bear was attracted to and/or deterred from the site. We have no indication that encounters that merely alter the behavior and movement of individual bears have any long-term effects on those bears. It is therefore unlikely that the small number of benign encounters between polar bears and Industry will have a significant overall effect on the populations.

No lethal takes have occurred during the period covered by incidental take regulations. Even before regulations were issued, lethal takes by Industry were a rare occurrence. since 1968, there have been two documented cases of lethal take of polar bears associated with oil and gas activities. In both instances, the lethal take was in defense of human life.

Based on the above discussion, any take reasonably likely to or reasonably expected to be caused by oil and gas activities will not result in more than a negligible impact on this species.

In addition to routine operations, the potential exists for polar bears to be impacted by oil spills. Spills of crude oil and petroleum products associated with onshore production facilities are usually minor spills that are contained and removed upon discovery. As polar bears spend the majority of their time offshore, they are unlikely to encounter oil from an onshore spill.

Oil spills are of concern in the marine environment, where spilled oil will accumulate at the ice edge, in leads, and similar areas of importance to polar bears. Oil spilled from offshore production activities was not considered in our previous regulations. The Northstar Project will transport crude oil from a reconstructed gravel island in the Beaufort Sea to shore via a 5.96-mile buried subsea pipeline. The pipeline will be buried in a trench in the sea floor deep enough to reduce the risk of damage from ice gouging and strudel scour. Construction of the Northstar project began in the winter of 1999-2000.

Polar bears are at risk from an oil spill in the Beaufort Sea. Limited data from a Canadian study suggest that polar bears experimentally oiled with crude oil may die. This finding is consistent with what is known of other marine mammals that rely on their fur for insulation. The Northstar FEIS concluded that mortality of up to 30 polar bears could occur as the result of an oil spill greater than 1,000 barrels. This estimate was based on observations of aggregations of polar bears on barrier islands in the Beaufort Sea.

Two independent lines of evidence support our determination that only a negligible impact to the Beaufort Sea polar bear stock will occur from Northstar, one largely anecdotal, and the other quantitative. The largely anecdotal information is based on observations of polar bear aggregations on barrier islands and coastal areas in the Beaufort Sea. This information suggests that polar bear aggregations may occur for brief periods in the fall. The presence and duration of these aggregations are influenced by the presence of sea ice near shore and the availability of marine mammal carcasses, notably bowhead whales. In order for significant impacts to polar bears to occur, an oil spill would have to occur, an aggregation of bears would have to be present, the spill would have to contact the aggregation, and many of the bears would have to be killed. We believe the probability of all these events occurring simultaneously is low.

The quantitative rationale for negligible impact is based on a risk assessment that considered oil spill probability estimates for the Northstar Project, an oil spill trajectory model, and a polar bear distribution model. The Northstar FEIS provides estimates of the probability that one or more spills greater than 1,000 barrels of oil will occur over the project's life of 15 years. We consider here only spill probabilities for the drilling platform and subsea pipeline as these are the spill locations that will affect polar bears. Using exposure variables and production estimates from the Northstar EIS, we estimate the likelihood of one or more spills greater than 1,000 barrels in size occurring in the marine environment is 3-10 percent during the 3-year period covered by the regulations.

Applied Sciences Associates, Inc., was contracted by BP Exploration Inc. to run the OILMAP oil spill trajectory model. The size of the modeled spill was set at 3,600 barrels, simulating rupture and drainage of the entire subsea pipeline. Each spill was modeled by tracking the location of 100 “spillets,” each representing 36 barrels. Spillets were driven by wind, and their movements were stopped by the presence of sea ice. Open water and broken ice scenarios were each modeled with 250 simulations. A solid ice scenario was also modeled, in which oil was trapped beneath the ice and did not spread. In this event, we found it unlikely that polar bears will contact oil, and removed this scenario from further analysis. Each simulation was run for 96 hours with no cleanup of containment efforts simulated. At the end of each simulation, the size and location of each spill was represented in a geographic information system (GIS).

Telemetry data suggest that polar bears are widely distributed in low numbers across the Beaufort Sea with a density of about one bear per 30-50 square miles. Movement and distribution information was derived from radio and satellite relocations of collared adult females. The U.S. Geological Survey, Biological Resources Division, developed a polar bear distribution model based on an extensive telemetry data set of over 10,000 relocations. Using a technique called “kernel smoothing,” they created a grid system centered over the Northstar production island and estimated the number of bears expected to occur within each 0.25km  2 grid cell. Each of the simulated oil spills was overlaid with the polar bear distribution grid. If a spillet passed through a grid cell, the bears in that cell were considered killed by the spill. In the open water scenario, the estimated number of bears killed ranged from less than 1 to 78,with a median of 8. In the broken ice scenario, results ranged from less than 1 to 108, with a median of 21. These results are based on an “average” distribution of polar bears and do not include potential aggregation of bears.

We estimated the likelihood of occurrence of mortality for various numbers of bears by multiplying the probability of mortality by the spill probability for each period of the year, and summing those probabilities over the entire year. We calculated that the probability of a spill that will cause mortality of one or more bears is 0.9-3.1 percent. As the threshold number of bears is increased, the likelihood of that event decreases; the likelihood of taking more bears becomes less and less. Thus the probability of a spill that will cause a mortality of 5 or more bears is 0.7-2.5 percent; for 10 or more bears is 0.6-2.0 percent; and for 20 or more bears is 0.3-1.1 percent.

The greatest source of uncertainty in our calculations is the probability of an oil spill occurring. The oil spill probability estimates for the Northstar Project were calculated using data for subsea pipelines outside of Alaska and outside of the Arctic. These spill probability estimates, therefore, do not reflect conditions that are routinely encountered in the Arctic, such as permafrost, ice gouging, and strudel scour. They may include other conditions unlikely to be encountered in the Arctic, such as damage from anchors and trawl nets. Consequently, there is some uncertainty about oil spill probabilities as presented in the Northstar FEIS. If the probability of a spill were actually twice the estimated value, however, the probability of a spill that will cause a mortality of one or more bears is still low (about 6 percent).

This analysis is dependent on numerous assumptions, some of which underestimate, while others overestimate, the potential risk to polar bears. These include variation in spill probabilities during the year, the length of time the oil spill trajectory model was run, whether or not containment occurred during the trajectory model, lack of efforts to deter wildlife during the model runs, contact with a spillet constitutes mortality, and that aggregations of bears were not included. We determined that the assumptions that will overestimate and underestimate mortalities were generally in balance.

We conclude that if an oil spill were to occur during the fall or spring broken-ice periods, a significant impact to polar bears could occur. However, in balancing the level of impact with the probability of occurrence, we conclude that the probability of serious impacts (large-volume spills that cause high polar bear mortalities) is low. Therefore, the total expected taking of polar bear during oil and gas industry exploration, development, and production activities will have No more than a negligible impact on this species.

Within the area covered by the regulations, polar bears are taken in Barrow, Nuiqsut, and Kaktovik; however, it is not considered a primary subsistence species in these villages. Data from our Marking, Tagging, and Reporting Program indicate that from July 1, 1993, to June 30, 1998, a total of 94 polar bears was reported harvested by residents of Barrow; 7 by residents of the village of Nuiqsut; and 10 by residents of the village of Kaktovik. Hunting success varies considerably from year to year because of variable ice and weather conditions. Native subsistence polar bear hunting could be affected by an oil spill. Hunting areas where polar bears are historically taken may be viewed as tainted by an oil spill.

Industry works with local Native groups to achieve a cooperative relationship between oil and gas activities and subsistence activities. The Industry works with the local Native groups to develop a Plan of Cooperation to address subsistence mitigation measures to be incorporated into the Industry's plan of operation. Any taking of polar bears likely to result from oil and gas activities will not have an umitigable adverse impact on the availability of polar bears for taking for subsistence uses.

Based on past LOA monitoring reports, we believe that any take resulting from the interactions between Industry and marine mammals (Pacific walrus and polar bears) has had a negligible impact on these species. Additional information, such as subsistence harvest levels and incidental observations of polar bears near shore, provides evidence that these populations have not been adversely affected. The projected level of activities during the period covered by the regulations (existing onshore development and proposed exploratory activities) are similar in scale to previous levels. Therefore, we conclude that any take reasonably likely to or reasonably expected to occur as a result of projected onshore activities will have a negligible impact on polar bears and Pacific walrus.

While the actual construction and operation of the Northstar development is not expected to significantly increase the impacts to Pacific walrus and polar bears, concern about potential oil spills in the marine environment was raised in the Northstar FEIS. We have analyzed the likelihood of an oil spill in the marine environment that will kill a significant number of polar bears and found it to be negligible. Thus, after considering the cumulative effects of existing onshore development, exploratory activities, and the new Northstar subsea pipeline, we find that the total expected takings of polar bears during oil and gas industry exploration, development, and production activities will have a negligible impact on polar bears and Pacific walrus and will have no unmitigable adverse impacts on the availability of these species for subsistence use by Alaska Natives.

Based on the previous discussion, we make the following findings regarding this action:

We find, based on the best scientific information available, the results of monitoring data from our previous regulations and the results of our modeling assessments, that any take reasonably likely to result from the effects of oil and gas related exploration, development, and production activities from March 30, 2000 through March 31, 2003, in the Beaufort Sea and adjacent northern coast of Alaska will have a negligible impact on polar bears and Pacific walrus and their habitat. In making this finding, we are following Congressional direction in balancing the potential for a significant impact with the likelihood of that event occurring. The specific Congressional direction that justifies balancing probabilities with impacts follows:

The FMP was developed jointly by the Councils, with the Mid-Atlantic Council having the administrative lead. A Notice of Availability for the FMP was published in the Federal Register on June 29, 1999 (64 FR 34759), and solicited public comment through August 30, 1999. The proposed rule to implement the FMP was published in the Federal Register on August 3, 1999 (64 FR 42071), and solicited public comments through September 17, 1999. NMFS made the decision to partially approve the FMP on September 29, 1999. A final rule to implement the FMP was published in the Federal Register January 11, 2000 (65 FR 1557), to be effective on February 10, 2000. A delay in effectiveness of the final rule was filed on February 10, 2000, and published on February 15, 2000 (65 FR 7460), which made the effective date of this rule March 15, 2000. A second delay in effectiveness of the final rule was filed on March 15, 2000, and published on March 21, 2000 (65 FR 15110), which made the effective date of this rule March 27, 2000. The final rule will now be effective April 3, 2000.