This action is directed to the public in general, and to current and former Federal employees and applicants for Federal employment in particular, who may want to allege a prohibited personnel practice or other violation of civil service law, rule, or regulation by a Federal agency.

OSC is correcting an erroneous statutory citation to federal merit system principles in its regulation on filing complaints of prohibited personnel practices at 5 C.F.R. 1800.1(a)(12). The citation in the current regulation refers to 5 U.S.C. 2302(b)(1). This citation, however, is incorrect, and should read 5 U.S.C. 2301(b).

This action is taken under the Special Counsel's authority, at 5 U.S.C. 1212(e), to publish regulations in the Federal Register. Under the Administrative Procedure Act, at 5 U.S.C. 553(b)(3)(B), statutory procedures for agency rulemaking do not apply “when the agency for good cause finds (and incorporates the finding and a brief statement of reasons therefor in the rules issued) that notice and public procedure thereon are impracticable, unnecessary, or contrary to the public interest.” OSC finds that such notice and public procedure are unnecessary and contrary to the public interest, on the grounds that: (1) this amendment is technical and non-substantive; and (2) the public benefits from early correction of an incorrect statutory citation.

OSC is submitting this final rule to Congress and the General Accounting Office pursuant to the Congressional Review Act. The rule is effective upon publication, as permitted by 5 U.S.C. 808. Pursuant to 5 U.S.C. 808(2), OSC finds that good cause exists for this effective date, based on the reasons cited in the preceding paragraph.

This rule has been determined to be not significant and was not reviewed by the Office of Management and Budget (OMB) under Executive Order 12866.

The information collection requirements contained in this regulation have been approved by the Office of Management and Budget (OMB) under the provisions of 44 U.S.C. chapter 35 and have been assigned OMB control number 0575-0172, in accordance with the Paperwork Reduction Act (PRA) of 1995. This rule does not impose any new or modified information collection requirements.

This rule has been reviewed under Executive Order 12988, Civil Justice Reform. In accordance with that Executive Order: (1) All state and local laws and regulations that are in conflict with this rule will be preempted; (2) no retroactive effect will be given to this rule; and (3) administrative proceedings in accordance with the regulations of the National Appeals Division of USDA at 7 CFR part 11 must be exhausted before bringing suit in court challenging action taken under this rule unless those regulations specifically allow bringing suit at an earlier time.

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub. L. 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, 2 U.S.C. 1532, RHS generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures to State, local, or tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. When such a statement is needed for a rule, section 205 of the UMRA generally requires RHS to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, more cost-effective or least burdensome alternative that achieves the objectives of the rule. This rule contains no Federal mandates (under the regulatory provisions of Title II of the UMRA) for State, local, and tribal Governments or the private sector. Therefore, this rule is not subject to the requirements of sections 202 and 205 of the UMRA.

The following programs are affected by this final rule: 10.410 Very Low to Moderate Income Housing Loans, 10.417 Very Low-Income Housing Repair Loans and Grants, 10.770 Water and Waste Disposal Loans and Grants (Section 306C).

For the reasons set forth in the final rule related Notice to 7 CFR part 3015, subpart V, only the Water and Waste Disposal Loans and Grants are subject to Executive Order 12372 which requires intergovernmental consultation with State and local officials.

This document has been reviewed in accordance with 7 CFR part 1940, subpart G, “Environmental Program.” It is the determination of RHS that this action does not constitute a major Federal action significantly affecting the quality of the human environment, and in accordance with the National Environmental Policy Act of 1969, Pub. L. 91-190, an Environmental Impact Statement is not required.

This rule has been reviewed with regard to the requirements of the Regulatory Flexibility Act (5 U.S.C. 601-612). The undersigned has determined and certified by signature of this document that this rule will not have a significant economic impact on a substantial number of small entities since this rulemaking action does not involve a new or expanded program.

The RHS published an interim final rule on November 22, 1996 (61 FR 59761-59802) for reengineering and reinventing how direct loans and grants under sections 502 and 504 of the Housing Act of 1949 are made and serviced. The Agency made the decision to publish this as an interim final rule in order to give the public the opportunity to comment on four particular sections. These sections cover areas where the Agency needed further comment and analysis completed to determine the impact of the changes on the section 502 program. The areas that were of most concern to the RHS related to payment subsidies and defining modest housing. Analyses and research were done based on the comments received, and the Agency has made revisions to the definition of modest housing, which will increase our level of customer service and reduce costs to the taxpayer by increasing the modest housing limit in areas where the limit was too low to finance modest homes, especially new construction, and lowering the limit in other areas where the financing of housing was considered more than “modest.” The result will be a more equitable and flexible program serving more customers at a lower cost to the taxpayer.

This final rule includes provisions pertaining to the definition of a modest dwelling and the maximum loan limit that an applicant can receive to purchase a single-family residence. In order to implement this rule, States must gather certain data on improved lot sales for each county in their state. States will be allowed up to 45 days to gather the information, conduct an analysis, and prepare a recommendation to be submitted to the Administrator. Upon receipt, the Administrator will review and, if acceptable, approve the State's recommendation during the next 45-day period. Once the State receives approval, they will make the new maximum loan limits available in the State Office and their local offices.

All provisions of this rule are effective 30 days after publication in the Federal Register , except the maximum loan limit, which will be effective 90 days from the date of publication. All pending applications will be subject to this final rule unless the applicant received Form RD 1944-59, “Certificate of Eligibility,” or submitted a contract for the purchase of a property or to build a home prior to the effective date of the new maximum loan limits. Details of the provisions adopted in this rule are given in the “Discussion of Comments” section.

The interim final rule was published in the Federal Register on November 22, 1996, with a 30-day comment period that ended December 26, 1996. Seven comments were received from Rural Development personnel, housing advocacy groups, developers, builders, housing authorities, housing organizations, and other interested parties. Written comments were requested specifically for the following four sections: 3550.53(g), 3550.57(a), 3550.63, and 3550.68. These comments are discussed below. Comments also were received on three additional sections: 3550.53(a), 3550.53(h), and 3550.56(b). These unsolicited comments have not been addressed.

Six comments were received on this section. Two comments were in favor of using the same principal, interest, taxes and insurance (PITI) ratio of 33 percent for both low and very low-income applicants. They felt this would be simpler and fairer for both income groups. One commentor felt that using 29 percent promoted very low-income applicants to carry more debt. Two commentors felt that the PITI ratio should be capped at 29 percent for both low and very low-income applicants. One commentor felt that the 29 percent cap coupled with exclusively using the equivalent interest rate method of payment assistance would promote applicants' shopping for more affordable housing. The other commentor felt that using 29 percent PITI would make the program consistent with the Guaranteed Housing Program.

The Agency considered these comments and determined that there is merit in having different PITI ratios for very low- and low-income applicants. Low-income applicants have relatively more disposable income for PITI and can afford to pay a higher amount for PITI than very low-income applicants. The Agency determined that the two separate PITI ratios at 29 percent for very low-income and 33 percent for low-income should continue. The lower PITI ratio for very low-income applicants allows them to pay a more affordable payment and keeps the overall subsidy provided at a lower rate. Very low-income applicants have less disposable income available with which to make payments. The amount of subsidy will be lower due to the overall lower payment. As for the total debt (TD) load of very low-income applicants, the 41 percent ratio allows a very low-income applicant to carry some debt load considered a necessity, such as medical expenses or a car payment.

One commentor recommended lowering the PITI ratios because of the high cost of construction in the commentor's particular State and the fact that many people in the State live a subsistence lifestyle with little or no cash income. The issue in this comment had more to do with cash for repayment. The program is a loan program. The program requires that eligible recipients repay their loan and; therefore, some type of adequate cash income is needed to do so.

One commentor agreed that the ratios set forth in the interim final rule are fair and similar to those in other mortgage lending programs.

Five comments were received regarding the definition of modest dwelling. Four of these agreed that the use of 203(b) of the National Housing Act (12 U.S.C. 1709(b)) is the best way to determine modest housing. Two of these were of the opinion that there are many areas where some reduction from these limits is in order. The Agency has studied the effect of the use of the section 203(b) limits of the National Housing Act and the cost of modest housing in rural areas. The adoption of the section 203(b) limits of the National Housing Act has led in many areas to the financing of housing that RHS believes to be more than “modest.” In addition, the limits are so low in other areas, and are not based on rural statistics, that the Agency is unable to finance homes (especially new construction). A modification of the loan limits is needed because of the desire to serve as many low and very low—income rural residents as possible and to ensure that the Agency is clearly financing only modest homes.

Several possibilities were explored for defining modest housing. One of these compared the adjusted county median income to typical loan amounts made during fiscal years 1991 through 1995, while square footage limitations defined modest housing. The response to this proposal was generally negative. Some thought it was too complicated while others thought that the section 203(b) limit of the National Housing Act is more recognized and understood, whereas median income is not.

The Agency then conducted an historical analysis of the relationship between the section 203(b) limit of the National Housing Act and section 502 loan amounts. This analysis showed that in most States, the 203(b) limit of the National Housing Act exceeds the cost of historically modest housing. It was clear that the 203(b) limit of the National Housing Act has little or no correlation to the actual price of rural housing, particularly in counties that are not “high cost.” In addition, the historical data supported the claim that in the majority of counties, RHS has made loans significantly lower than 203(b) of the National Housing Act.

Also, the Agency utilized a nationally recognized source for providing residential cost data related to new construction to assist in this endeavor. The vehicle calculated costs for new construction on a county by county basis throughout the country, based on parameters that closely defined modest housing in terms of size and amenities. These numbers did not include the cost of an improved site. States were requested to establish the market value of improved sites including the market value of the lot, the cost of water and sewer hookup or well and a septic system, driveway and landscaping, based upon their own market analysis of comparable sales or other substantiated data. Each Rural Development State Office was provided the construction cost numbers and was asked to add the market value of an improved site to these numbers to arrive at a maximum loan limit. A majority of the states indicated that this loan limit most closely represented the type of modest housing being constructed in their State.

In addition, consideration was given to allow States to use a recognized established loan limit such as those set by a State Housing Authority as long as the limits were within a close percentage (5 to 10 percent) of the limit for construction cost plus market value of the unimproved site discussed above.

Another commentor was concerned that lower cost should not be confused with low quality, and that quality construction with good insulation and structural soundness will decrease the likelihood of defaults. The Agency supports quality construction. In accordance with 42 U.S.C. 1479(a), the Agency requires in § 3550.57 that new homes to be built in accordance with the building code for the particular area of the country where the house is being constructed. Additionally, 7 CFR part 1924, subpart A, exhibit D requires that houses be insulated according to the Model Energy Code (MEC) appropriate for the area.

The discussion of modest housing limits and maximum loan amounts are closely related. See §3550.63, Maximum loan amount, for a full discussion of these comments. In sum, the Agency has determined that “modest housing” generally may not have a market value in excess of the maximum loan limit under that section.

The comments under this section were essentially identical to those received on §§ 3550.53(g), 3550.57(a), and 3550.68. The Agency received six comments on the maximum loan amounts. One of the commentors felt that using State non-metro average income would be a better way to determine maximum loan amount. While it is true that housing fair market values are higher in areas of higher income, based on the Agency's past experience, there is no consistent direct relationship between income and housing values across the country. In other words, housing values are more related to location. Areas across the country with similar median incomes do not necessarily have similar housing values. Therefore, this comment was not adopted.

Another commentor recommended a provision for exceeding the appraised value when another affordable housing agency or non-profit is providing forgivable loans for closing or down payment assistance. The Agency allows the appraised value to be exceeded by the cost of an appraisal and other allowable closing costs, regardless of where the financing is obtained. However, the Agency agrees that some flexibility should be allowed when forgivable loans or grants are provided for the purpose of down payment assistance and closing costs. The Agency has determined that in those cases where there is a grant or forgivable subordinate affordable housing products, the total debt may exceed the market value by the amount of the forgivable loan or grant up to 5 percent. This will provide the needed flexibility and not put the Agency at undue risk of loss. Any additional amount above the appraised value is not authorized and would leave the Agency unsecured in the event of default. The Agency also has revised the security requirements at § 3550.59(a)(2) accordingly to allow a junior lien if the junior lien will not interfere with the purpose of repayment of the RHS loan. If the junior lien involves a grant or forgivable subordinate affordable housing product, the total debt may exceed the market value by the amount of the forgivable loan or grant up to 5 percent.

Three of the comments received supported the reduction to a percentage of the 203(b) limit of the National Housing Act. Two of these agreed that State Directors should have the ability to determine which areas need higher maximum loan amounts.

After considering all of the comments and the above options, the Agency has concluded that there is no simple solution in determining maximum loan amount. Therefore, the Agency will provide States with some flexibility in determining the maximum loan amount in their State. The Agency will provide each State with the option of choosing between the cost data plus the market value of an improved lot, or the State Housing Authority (SHA) limit, as long as the SHA limit is within 10 percent of the cost data plus the market value of an improved lot. States must determine which value most appropriately reflects the value of modest for the area. However, either option cannot exceed the current 203(b) limit of the National Housing Act.

Both of these methods rely on actual market data for the cost of constructing a dwelling in a specific area, plus data a state collects for the market value of an improved site. The Agency will provide construction cost data to each state annually, and states will be required to publish a State Administrative Notice annually establishing limits that are to be used. The flexibility added to this section negates the need for an area-wide exception to the modest dwelling requirement of § 3550.57, so it has been removed.

There were four comments received. One commentor stated that only one method of calculating subsidy should be used and recommended using the equivalent interest rate (EIR) method. The same commentor felt that the EIR is the only method that takes the price of a house into consideration when determining affordability and that use of the floor computation does not give the applicant the option of choosing lower priced housing. The floor computation is the relationship between a borrower's adjusted income and the applicable adjusted median income in the area in which the security property is located.

Another commentor suggested that floor payments should be made in one percent increments from 22 to 26 percent. The same commentor went on to propose that the EIR scale should be modified to reflect interest rates divided in 1/4 percent interest increments and five percent income increments. This commentor suggested that subsidy would be easier to determine based on a flat percentage of an applicant's adjusted income. Another commentor suggested subsidy based on an applicant paying a flat 30 percent of annual income for principal, interest, taxes, insurance and utilities and maintenance.

In response to these comments, the Agency has made no changes to the policy established in the interim rule. The Agency uses the floor and EIR comparison method of determining payment subsidy to reduce the costs of the program and; therefore, increase the number of families we can assist. This method allows subsidy costs to be at a minimum while maintaining affordability for low and very low-income families. Applicants are not asked to pay any more than 22, 24, or 26 percent of their income, depending on the percent of median income, for total PITI. The Agency has used this formula since 1996 and has experienced no problems with it. The Agency considers these percentages reasonable for a very low- or low-income applicant to pay for housing costs and is not proposing any changes to the payment assistance formula at this time.

In addition to the changes being made to §§ 3550.53(g), 3550.57(a), and 3550.63, we are also providing the following technical corrections, omission corrections and clarifications of the interim rule. A summary of these technical corrections and clarifications follows. Conforming changes are also being made to update obsolete references in other regulations associated with the Direct Section 502 and 504 programs.

The definition for “modest housing” was modified due to the changes in §§ 3550.57(a) and 3550.63 discussed above. This change makes the sections consistent.

A paragraph from the obsolete 7 CFR 1944.22(c) was inadvertently omitted in this section in the interim rule. This paragraph allows for refinancing of a non-RHS debt if the loan is $5,000 or more and is necessary for repairs to correct major deficiencies and make the dwelling decent, safe and sanitary and the refinancing is necessary for the borrower to show repayment ability, regardless of the delinquency. This final rule corrects that omission.

The credit requirements of this section have been interpreted inconsistently. The language is confusing because it includes both installment debts such as a car loan and credit card debt. These two distinct types of credit must be looked at in their own context. Therefore, we are clarifying the indicators of unacceptable credit to include payments on any account where the amount of the delinquency exceeded one installment for more than 30 days within the last 12 months and payments on any account which was delinquent for more than 30 days on two or more occasions within a 12-month period. A correction was made to state that Agency debts that were debt settled within the last 36 months or are being considered for debt settlement is considered adverse credit. Corrections were also made to this section by renumbering and redesignating paragraphs.

In addition to addressing the above comments, we added an omission from the obsolete 7 CFR 1944.8(a)(2)(i), which required an applicant to have adequate and dependable income. Dependably available income is a basic eligibility requirement, which necessitates the need to re-introduce this into the calculation of repayment ability. The determination of income dependability will include consideration of an applicant's past history of annual income.

A correction was made to this section to change wording from family member to household member in calculating adjusted income. This is necessary to make the section internally consistent, as all household income must be included in determining annual and adjusted income.

A correction was made to this section to clarify how the market value may be exceeded up to 5 percent when a junior lien involves a grant or a forgivable affordable housing product.

This section has been changed for clarity to remove the reference to the non-program interest rate. This section is for program loans only.

Spelling and grammatical corrections have been made to the first paragraph.

This section has been changed to correct the OMB control number from 0575-0166 to 0575-0172.

This subpart has been modified to include a section on the Consolidated Farm and Rural Development Act section 306C (7 U.S.C. 1926c) Water and Waste Disposal Grants to individuals. The information on section 306C was previously included in 7 CFR part 1944, subpart J, Exhibit D, which was eliminated by the interim rule. Putting this information in 7 CFR part 3550 corrects the omission.

This section has been modified to include a statement that the subpart also covers section 306C Water and Waste Disposal Grants.

This section was modified to clarify the indicators of unacceptable credit to include payments on any account where the amount of the delinquency exceeded one installment for more than 30 days within the last 12 months and payments on any account which was delinquent for more than 30 days on two or more occasions within a 12-month period. A correction was made to state that Agency debts that were debt settled within the last 36 months or are being considered for debt settlement is considered adverse credit. Corrections were also made to this section by renumbering and redesignating paragraphs.

This section has been corrected to remove the reference to the HUD Section 203(b) limit. This is necessary due to the change in the definition of modest dwelling.

This section has been modified to increase from $2,500 to $7,500 the dollar amount required before a mortgage must be obtained, due to section 702 of the American Homeownership and Economic Opportunity Act of 2000, Public Law 106-569 that amended § 504(a) of the Housing Act of 1949. This section is for section 504 loans only.

A correction has been made to state that the grant must be repaid if the property is sold in less than 3 years from the date the grant agreement was signed rather than when the grant was approved. This clarifies and provides consistency in determining the applicable 3-year timeframe.

These sections have been added to include a section on 306C Water and Waste Disposal Grants. The information on Section 306C was previously included in 7 CFR part 1944, subpart J, Exhibit D which was eliminated by the interim rule. Putting this information in 7 CFR part 3550 corrects the omission.

This section has been changed to correct the OMB control number from 0575-0166 to 0575-0172.

This section has been modified to clarify and provide additional guidance on how value appreciation of a property with a cross-collateralized loan is to be determined.

A correction has been made to this section for clarity to change the wording from selling security property to transferring title to secured property. This provides additional guidance for approval of assumptions of property regardless of how title is transferred.

This section has been changed to correct the OMB control number from 0575-0166 to 0575-0172.

A sixth servicing action example has been added to further clarify when an account may be reamortized using the promissory note interest rate.

This section has been corrected to state that RHS may accept partial payments on an accelerated loan and continue with the foreclosure if allowed by state law.

This section has been changed to correct the OMB control number from 0575-0166 to 0575-0172.

This section has been modified to clarify that program Real Estate Owned (REO) properties are reserved for buyers eligible for Rural Housing Direct or Guaranteed SFH programs rather than just Direct program eligible applicants. The section has also been clarified to state that an offer from a buyer on a program REO property who does not qualify for Direct or Guaranteed financing will be considered to have been received the day after the reservation period ends. This changes the sentence from reading “section 502 program loan” to “Direct or Guaranteed loan.”

This section has been changed to correct the OMB control number from 0575-0166 to 0575-0172.

Conforming changes and technical corrections have been made to parts 1806, 1822, 1924, 1925, 1927, 1930, 1940, 1944, 1948, 1950, 1951, 1955, 1965, and 1980 accordingly.

In a staff requirements memorandum (SRM) dated August 10, 1999, the Commission directed the NRC staff to initiate a rulemaking to require that decommissioning trust agreements be in a form acceptable to the NRC in order to increase assurance that an adequate amount of decommissioning funds will be available for their intended purpose. This SRM was in response to SECY-99-170 (July 1, 1999), “Summary of Decommissioning Fund Status Reports,” in which the NRC staff noted that it intended to continue to review decommissioning trust agreements in license transfers on a case-by-case basis and impose appropriate conditions in the orders approving these transfers. In response to the SRM, the NRC staff issued a rulemaking plan for Decommissioning Trust Provisions, SECY-00-0002, on December 30, 1999. The plan called for amending 10 CFR 50.75 and revising Regulatory Guide 1.159, “Assuring the Availability of Funds for Decommissioning Nuclear Reactors.” The Commission approved the plan on February 9, 2000, and directed the NRC staff to include specific trust fund terms and conditions necessary to protect funds fully in the rule itself. The Commission also suggested that sample language for trust agreements consistent with the terms and conditions within the rule be provided in the associated regulatory guide.

The NRC published a proposed rule for Decommissioning Trust Provisions on May 30, 2001 (66 FR 29244). That proposed rule required that the trust provisions be in a form acceptable to the NRC and contain general terms and conditions that the NRC believes are required to ensure that funds in the trusts will be available for their intended purpose. To accomplish this objective, the NRC proposed to modify paragraphs 10 CFR 50.75(e)(1)(i) and (ii), and to add a new paragraph, 10 CFR 50.75(h) to its regulations. The changes in § 50.75(e) specify that the trust should be an external trust fund in the United States, established under a written agreement and with an entity that is a State or Federal government agency or an entity whose operations are regulated by a State or Federal agency. Paragraph 50.75(h) discusses the terms and conditions that the NRC believes are necessary to ensure that funds in the trusts will be available for their intended purpose.

In response to a comment, paragraph 72.30(c)(5) has been modified for consistency with § 50.75(e) and (h), as a conforming change. As an accompaniment to this rulemaking, the NRC has updated Regulatory Guide 1.159, to include sample trust fund language containing these terms and conditions. Draft Regulatory Guide DG-1106, the proposed revision 1 of Regulatory Guide 1.159, was published for comment along with the proposed rule.

The Commission received 36 letters, from 34 commenters, containing approximately 280 comments on the proposed rule and draft regulatory guide. Seventeen of the commenters were licensees, 11 were representatives of utility groups (many of whose members are licensees), three were State agencies or commissions, one was the National Association of State Regulatory Utility Commissioners (NARUC), and two were investment management companies. Copies of the letters are available for public inspection and copying for a fee at the Commission's Public Document Room, located at 11555 Rockville Pike, Room O-1 F23, Rockville, Maryland 20852.

Documents created or received at the NRC after November 1, 1999, are also available electronically at the NRC's Public Electronic Reading Room on the Internet at http://www.nrc.gov/reading-rm.html . From this site, the public can gain entry into the NRC's Agencywide Document Access and Management System (ADAMS), which provides text and image files of NRC's public documents. These same documents also may be viewed and downloaded electronically via the interactive rulemaking website established by NRC for this rulemaking at http://ruleforum.llnl.gov.

Comments: Several of the commenters supported the NRC's goal to maintain regulatory oversight over nuclear decommissioning trust funds, where necessary, and agreed that the NRC may need to take a more active oversight role regarding decommissioning trust agreements. Two other commenters commended the NRC for undertaking this rulemaking and fully supported the NRC's efforts to ensure that a utility industry made more efficient through competition remains a safe and reliable industry. Similarly, one commenter said it understands and agrees with the NRC's concern that the decommissioning trust corpus be safeguarded from investment risks. The Nuclear Energy Institute (NEI) stated that “[u]pon taking into account the comments and suggestions for improvement * * *, NRC's proposed rulemaking and proposed guidance likely will enhance the assurance for decommissioning funding already provided by the industry and should improve public confidence that all nuclear power reactors will be properly decommissioned.” Ten commenters endorsed NEI's comments. One of those commenters also endorsed the comments submitted by Winston & Strawn on behalf of the Utility Decommissioning Group and the Tennessee Valley Authority. However, one licensee stated that the NRC should withdraw the notice of proposed rulemaking because existing regulations from the NRC, the Internal Revenue Service (IRS), and the State regulatory agencies are more than adequate to protect the public health and safety. In their view, the proposed rulemaking is duplicative of existing requirements and would add unnecessary regulatory burden without a corresponding safety benefit.

This licensee also believes that the proposed rule is inconsistent with the NRC's regulatory burden reduction initiative. Another commenter expressed similar views and stated that the proposed rule may eliminate some of the flexibility of the existing rule. Yet another commenter opposing the rule said that if the NRC intends to continue to impose decommissioning funding conditions in individual licenses, there is no need for the rule.

Five commenters noted that given the wide variety of trust instruments in effect, it is fitting that the NRC not develop a uniform trust fund agreement that would be mandatory for all licensees. Another commenter stated that the NRC's proposed approach in adopting standard rules regarding decommissioning trust funds is superior to the existing NRC practice of applying specific license conditions on a case-by-case basis.

A commenter stated that NRC's discussion of Test 4 in the statement of considerations for the proposed rule describes that licensees “generally” prepare annual reports, etc. and does not specifically list annual calculation of the estimated cost as required by 10 CFR 50.75(b)(2). Further, the Test 4 description specifies that “* * * these reports can be supplied to the NRC upon request * * *.” This availability upon request and the biennial reporting appear sufficient. The Test 4 discussion should justify removing 10 CFR 50.75(b)(2), or an explanation of the benefit of annual adjustments to the calculation vs. the biennial frequency of the funding status should be provided.

Response: With respect to the comments calling for the NRC to withdraw the rule, the Commission does not intend to do so. The Commission's position, as stated in the proposed rule (66 FR 29244) is that, “[u]ntil recently, direct NRC oversight of the terms and conditions of the decommissioning trusts was not necessary because rate regulators typically exercised such authority. With deregulation, this oversight may cease and the NRC may need to take a more active oversight role.” Given that the NRC will not require (except in the one instance where all power reactor licensees, both rate regulated and otherwise, will be required to notify the NRC in advance of decommissioning trust withdrawals if these withdrawals are made before to permanent cessation of operations) the trust provisions of this rulemaking to be imposed on those licensees remaining under State or Federal Energy Regulatory Commission (FERC) regulation, the NRC does not interpret this action as being duplicative of existing requirements and adding unnecessary regulatory burden.

With respect to the comment stating that there would be no need for the rule if the NRC continues to impose decommissioning funding conditions in individual licenses, the NRC has always believed that it is preferable and more efficient to adopt standard rules, as opposed to applying specific license conditions on a case-by-case basis.

As for the comment on the discussion of Test 4 in the statement of considerations for the proposed rule and the commenter's request to remove 10 CFR 50.75(b)(2), the NRC was not proposing any change to that section by this action and no change is presently under consideration. The NRC still intends to require licensees to calculate their estimated decommissioning costs annually, even if these values are not required to be submitted to the NRC annually.

Following is a listing of the specific comments on the proposed rule and the NRC's response to them. The comments on the draft regulatory guide are then listed and discussed.

Comments: One of the most often repeated comments dealt with the proposed rule's requirement to be applicable to all licensees, even if they are under FERC or State regulation. The commenters said that the NRC should more clearly explain its conclusion that the proposed rule is necessary to ensure that decommissioning funds will be available when needed. There is no evidence that any reactor licensee has lacked adequate funds to safely complete the decommissioning process. In effect, licensees would have to expend resources to address a problem that has yet to occur. Because licensees are required to report on their funding levels to the NRC every two years (10 CFR 50.75(f)(1)), the reports already allow the NRC time to fashion an appropriate remedy, should one be necessary, to protect public health and safety. The NRC has not reviewed current practices by State or Federal rate regulators to establish a baseline for evaluating any possible changes in the management of decommissioning trust funds in response to deregulation. Another layer of regulatory oversight should not be added where adequate regulatory safeguards exist, such as FERC and/or State oversight. One commenter stated that its State Public Utility Commission (PUC) approved the commenter's decommissioning funding collections and permits funding of items not included in the NRC's definition of “decommissioning.” Therefore, additional NRC requirements regarding the use of these funds would hinder the commenter's ability to access and use the funds as approved by the PUC and would unnecessarily intrude on local ratemaking functions that are an exclusive province of State governments.

Two commenters stated that the NRC should include a way for licensees to ascertain whether a conflict of applicable standards between the NRC's proposed rule and existing State and Federal regulations requires the execution of an entirely new trust agreement. Also, the NRC should convene a conference with FERC and NARUC to explore conflicts between existing standards and the NRC's rule.

One commenter stated that licensees who are State entities and who have additional safeguards under State law should be exempt from the proposed rule because it is based on the premise that deregulation will remove existing accounting and financial controls on owners of nuclear power plants. These commenters argued that this rule is not applicable to California Municipal Utilities Association (CMUA) members, who operate under the same regulatory and legal restrictions that applied before the changes to the electric utility industry in California. CMUA members are public agencies bound by the same stringent investment restrictions after deregulation as before.

Two commenters stated that the proposed rule is duplicative of Internal Revenue Code requirements and IRS implementing regulations, that place additional restrictions on the use of qualified nuclear decommissioning trusts. The commenters assert that existing IRS requirements are sufficient to protect the NRC's interest in the proper use of decommissioning funds. Under the IRS regime, licensees may experience tax advantages under the Internal Revenue Code section 468A by commingling funds for all decommissioning purposes and depositing them in a tax “qualified” fund. The NRC should explicitly permit the use of funds for all decommissioning purposes and eliminate barriers in its regulations to the full collection of funds authorized by rate-setting authorities.

Two other commenters asserted that the final rule should acknowledge the potential of transfers from non-qualified portions of the trust to the qualified portions without the NRC's notice or approval. Similarly, the scope of the proposed rule is not clear because it does not articulate whether the amendments are applicable to all nuclear decommissioning trusts (qualified and unqualified), or whether the amendments are intended to apply to trusts that accumulate funds for expenses not within the NRC definition of “decommissioning.”

An organization representing the nuclear power industry stated that because there are a variety of ways for licensees to comply with the rule that are equally as binding as the terms of the underlying trust agreement, 10 CFR 50.75(h)(1) should be revised to allow licensees alternatives for achieving rule compliance by inserting the words “investment guidelines for, or other binding arrangements governing” so that it would read: “Licensees using prepayment or an external sinking fund to provide financial assurance shall provide in the terms of, investment guidelines for, or other binding arrangements governing, the trust, escrow account, Government fund, or other account used to segregate and manage the funds * * *.”

Another commenter stated that it is not clear whether provisions in the proposed rule will supersede license conditions previously imposed in license transfer proceedings, or whether licensees with existing license conditions governing decommissioning trusts must apply to amend their licenses and whether these amendment applications would then be subject to hearings. The inference is that the proposed rule would be applicable to all existing and future reactors, as the rule is silent on the matter.

Response: The NRC acknowledges that the proposed rule could be burdensome for licensees still regulated by PUCs and FERC, with no significant improvement in the public health and safety. Therefore, the final rule will only apply to licensees that are no longer regulated by State PUCs or FERC, with the exception that all power reactor licensees, both rate regulated and otherwise, will be required to notify the NRC in advance of decommissioning trust withdrawals if these withdrawals are made before permanent cessation of operations. The reason for this is that some licensees, even though continuing to be rate regulated, may make withdrawals without their rate regulator's knowledge. Given that any such withdrawals before permanent cessation of operations are likely to be very rare, the NRC believes that this requirement should not be burdensome. The NRC also excludes from this requirement any withdrawals from one decommissioning fund that are immediately deposited in another decommissioning trust fund either for one unit or between units ( e.g. , from a non-qualified to a qualified trust fund). This change would essentially eliminate the potential for conflicts of standards between NRC, and State and Federal regulations. These modifications also eliminate the need for a conference on this subject.

However, the NRC does not agree with the comments that IRS requirements are sufficient to protect the NRC's interest in the proper use of decommissioning funds because these requirements relate primarily to tax treatment of decommissioning funds and may not be sufficient to satisfy the NRC's public health and safety concerns.

As to the comment on the suggested revision to 10 CFR 50.75(h)(1), the change has been made because the NRC recognizes the benefit of allowing alternatives for achieving rule compliance that do not have any adverse impact on the public health and safety.

With respect to the comment seeking clarification about whether the proposed rule supersedes license conditions, the NRC's position is that licensees will have the option of maintaining their existing license conditions or submitting to the new requirements.

Lastly, in response to the same commenter's second question, the rule is to be applicable to all present and future licensees that are or will no longer be under FERC or State rate regulation or that otherwise meet the NRC's definition of “electric utility,” with the same exception as noted above. All licensees will be required to notify the NRC in advance of decommissioning trust withdrawals if these withdrawals are made before permanent cessation of operations or if they are not made under a post-shutdown decommissioning activities report or license termination plan.

Comments: The section of the proposed rule that generated the greatest number of responses (fourteen) from commenters related to notification of disbursements from the trust. Some commenters claim the 30-day notification is not needed because there is no basis for presuming that an independent trustee will disburse amounts held in the decommissioning trust fund for purposes other than those specified. The notification requirement would impose a significant regulatory burden on both the licensees and the NRC by creating a process for disbursement approvals for decommissioning funds without a public health and safety justification. There are no standards to guide licensees and the NRC staff on whether a disbursement would be permissible. The 30-day disbursement notification would be a major burden on licensees during decommissioning and even during decommissioning planning because notifications would be required frequently.

The commenter stated that at most, the rule should require a one-time notification before initial withdrawals for decommissioning or planning. Also, licensees may incur charges waiting for NRC approval while labor and resources have been staged and ready to work. Trust vendors or service providers would not appreciate having to wait 30 days for payment with the added risk of possibly having the payment disallowed by the NRC. Further, there may be cases where relatively minor day-to-day expenses are incurred or where expenses must be paid promptly and NRC review is not required to meet the agency's regulatory concerns. If so, the NRC could add a de minimis exception. These commenters suggested that the NRC could prohibit funds from making two or more simultaneous disbursements of 0.99 percent of trust principal in order to avoid the notification requirement of the proposed rule. The NRC has not identified any case where improper disbursements have been made from a decommissioning trust and does not have enough staff to review invoices from decommissioning contractors that would only increase paperwork.

With respect to the 30 day disbursement notice under proposed 10 CFR 50.75(h), another commenter stated that “Licensees that have complied with the requirements of 10 CFR 50.82(a)(4) regarding submittal of a Post Shutdown Decommissioning Activities Report (PSDAR) and control trust fund disbursements in accordance with the provisions of 10 CFR 50.82(a)(6), (a)(7), and (a)(8), should be exempt from any further restrictions on disbursements.” This commenter suggested that its modification to the proposed rule is particularly appropriate because it allows licensees to use the 3 percent of decommissioning trust fund monies for planning activities before plant retirement as provided at 10 CFR 50.82(a)(8)(ii). There is little need for the NRC to require a 30-day advance notice from those facilities utilizing the trusts for pre-planning decommissioning activities. Also, the clarifying wording in Section 2.2.2.4 of DG-1106 needs to be included in 10 CFR 50.75(h)(1)(iii).

The commenter then suggested modifying proposed 10 CFR 50.75(h)(1)(iii) to allow plants in the process of being decommissioned to be grandfathered because the proposed requirement would not add any assurances that funding is available and would duplicate other notifications. Similarly, another commenter stated that 10 CFR 50.75 (h)(1)(iii) proposes to restrict disbursements or payments until final decommissioning has been completed. It is possible that State PUCs could require overfunded trusts to rebate money to ratepayers (rather than merely adjust the future collection rate). This commenter suggested that the rule should allow the NRC to approve such a disbursement following adequate review.

One commenter stated that NRC should revise the proposed 10 CFR 50.75(h)(1)(iii) to indicate the inclusion of nuclear decommissioning trusts (NDTs) in license transfers. In DG-1106, the NRC recognized that the 30-day notice should be provided to the NRC before disbursing funds, but should not apply to plants withdrawing funds under 10 CFR 50.82(a)(8)(i). This exception is not noted in the proposed rule. Another commenter stated that the proposed rule would duplicate reports for those plants active in decommissioning and that the rule should exempt those facilities involved in decommissioning under 10 CFR 50.82. Similarly, 10 CFR 50.75(h)(4) should be modified so that subsection (h) would not apply to any plant which already has an NRC-approved decommissioning plan. Another commenter stated that licensees who have docketed a PSDAR and a site-specific cost estimate under 10 CFR 50.82 should be exempt from the reporting requirements and adjustments to cost estimates of 10 CFR 50.75.

Several commenters noted that “ordinary expenses” or “ordinary administrative expenses” should be defined, and that those paid periodically from the trust should be exempt from the 30-day disbursement notification. Or, as a commenter noted, the NRC should clarify which specific expenses paid from a fund would require NRC notification. One commenter stated the definition should be consistent with Internal Revenue Code section 468A(e)(4)(B) where expenses are defined as “administrative costs (including taxes) and other incidental expenses of the fund (including legal, accounting, actuarial, and trustee expenses) in connection with the operation of the fund.”

Response: With respect to the comments on the 30-day notification for disbursements, the NRC needs to have this information in a timely fashion in order to effectively monitor licensees, especially when a licensee is not in decommissioning under the PSDAR or an approved license termination plan under 10 CFR 50.82.

One concern with the 30-day disbursement notice was the problems it would potentially cause for licensees during the process of decommissioning or decommissioning planning. The proposed rule did not explicitly indicate that licensees who have complied with 10 CFR 50.82(a)(4) would be exempt from restrictions on disbursements. The NRC agrees with this comment and this change has been made in the final rule because, as a commenter noted, the proposed requirement would not add any assurances that funding is available and would duplicate notification requirements at § 50.82.

Other comments focused on the need for definitions of “ordinary expenses” and “ordinary administrative expenses.” The NRC, as a matter of consistency and expediency, decided to make use of the IRS Code section 468A(e)(4)(B) definition of expenses where they are defined as “administrative costs (including taxes) and other incidental expenses of the fund (including legal, accounting, actuarial, and trustee expenses) in connection with the operation of the fund.”

For clarification and consistency, the final rule includes the words of Section 2.2.2.4 of DG-1106 in 10 CFR 50.75(h)(1)(iii), as suggested by one commenter. Further, the rule language has been changed throughout from “30 days” to “30 working days.”

Comments: Another major area of concern for twelve commenters in the proposed 10 CFR 50.75(h)(1)(i)(B) was the requirement that the trust hold only “investment grade” securities. As one commenter noted, a requirement of “investment grade” investments in the trust is unnecessary because of applicable standards under State law, the proposed 10 CFR 50.75(h)(1)(i)(C), and the “prudent investor” standard used and defined by the FERC. Adoption of a different standard by another regulatory agency would be problematic. The “prudent investor” standard should apply in situations where other regulators have not mandated an investment standard or specific investment restrictions to eliminate the possibility of conflicts between NRC and other requirements. Also, this requirement goes beyond conditions imposed in license transfer orders. Another commenter suggests that the “investment grade” standard apply at the time of purchase and not require immediate sale of the investment at the time of downgrade. This commenter stated that the use of the term “investment grade” in the proposed rule is not necessary and that the “prudent investor” standard, as defined in FERC regulations should be used. “Investment grade” is not clearly defined in the regulation, would be subject to the vagaries of future regulatory interpretation, and is unnecessarily restrictive.

Response: The NRC agrees that the term “investment grade” is redundant because the “prudent investor” standard is an appropriate standard defined by the FERC. (Equivalent standards established under State law would also be acceptable.) Therefore, “investment grade” was deleted from the final rule and “prudent investor” is used in its place.

Comments: Five commenters called for the elimination of the prohibition of a trust ownership of securities of other nuclear power reactor licensees, or for the NRC to set a limit on the amount of assets in entities owning one or more nuclear power plants. These commenters argued that the NRC has not provided a clear basis for categorically excluding investments in any entity with an ownership interest in a nuclear power plant. According to another commenter, the proposed prohibition in a trust's ownership interest in “one or more nuclear power plants” should be deferred to applicable investment guidelines under State law. One commenter stated that, by prohibiting investment in securities of other nuclear power plant licensees, NRC is implying the ownership of a nuclear power reactor is a risky investment. The commenter also stated that such a prohibition was possibly out of the NRC's jurisdiction. Further, placing these restrictions on fund managers is not practical and has no clear connection to protection of the public health and safety. Any final rule should permit a de minimis investment in otherwise prohibited securities.

The proposed “nuclear securities” restriction is very ambiguous as it would apply to fixed income investments. Investment opportunities that are limited by ambiguous regulations will unnecessarily result in lower investment returns than otherwise would be the case. Still another commenter pointed out that the proposed restriction on ownership of securities with nuclear exposure is inconsistent with use of the “prudent investor standard.”

One commenter noted that public systems are concerned that the proposed rule not be used to prevent a municipal licensee from investing in securities issued by the State government, another municipality, or other instruments of the State in which the municipal licensee is located. If the NRC rejects this proposal, the commenters request that debt securities and like instruments already held in decommissioning trust accounts be exempted from this restriction.

Seven commenters opined that 10 CFR 50.75(h)(1)(i)(A) should be modified to clarify the term “non-nuclear sector mutual funds” and to permit investments in bank-maintained nonnuclear sector collective or commingled funds, such as “Common Trust Funds.” One commenter did not find the proposed 10 CFR 50.75(h)(1)(i)(A) clear with respect to “any other entity owning one or more nuclear power plants” and asked: Is the rule intending to allow investment in securities of an entity that is part owner of a nuclear power plant? Is the rule intending to disallow investment in a mutual fund in which 2 percent of the fund is invested in securities of a parent company whose subsidiary is a minority owner of a foreign or domestic nuclear power plant? Is the term “nuclear power plant” inclusive of those being decommissioned and those licensed to operate?

One final related comment was that licensees, and trustees in the absence of directions from licensees, should be authorized to prudently allocate trust assets across the entire risk/return spectrum. Prudent diversification can be beneficial for all stakeholders.

Response: The proposed prohibition of ownership in securities of other nuclear power reactor licensees was instituted to forestall members of the nuclear industry from solely investing their nuclear decommissioning funds in each other's securities. Contrary to one commenter's assertion that the prohibition implies that nuclear power is a risky investment and possibly out of the NRC's jurisdiction, the NRC believes that this requirement is consistent with fund diversification.

The NRC agrees with the suggestion that the requirement permit a de minimis investment in otherwise prohibited mutual fund investments. The final rule sets the de minimis level at 10 percent of the total value of a decommissioning trust account, at or below which investments in securities of companies owning nuclear power plants would be allowed.

With respect to the comment referring to the ambiguity of the proposed restriction as it would apply to fixed income investments, the Commission continues to believe that such a restriction should apply. However, because the rule will not apply to licensees that meet the definition of “electric utility” and that a de minimis level of investment is now permitted, any effect of such a restriction should be substantially mitigated.

As to the comment suggesting that the proposed prohibition in the trust's ownership of municipal or State-owned nuclear power plants be deferred to applicable State law, by having the rule apply to only those licensees not meeting the NRC's definition of “electric utility” that includes cooperatives and public power entities, this issue is rendered moot. The concern relating to the proposed rule not allowing a municipal licensee from investing in securities issued by a State government is likewise rendered moot. The NRC notes that even if the proposed rule were adopted as written, it would not have prevented municipal licensees from investing in State instruments as long as those instruments were not specifically tied to the nuclear plants.

Some commenters wanted clarification of the term “non-nuclear sector mutual funds.” This term can be understood in the context of the NRC's definition of “nuclear sector mutual funds.” The NRC interprets these funds as being ones in which the fund invests primarily in entities owning nuclear power plants. Funds that invest in electric utilities would be nuclear sector mutual funds if the majority of the value of securities were from NRC licensees. As stated previously, a licensee may invest in nuclear sector mutual funds as long as its share of the licensee's portfolio is less than 10 percent.

In response to some of the specific questions asked, the NRC considers partial owners of a nuclear power plant to be the same as full owners and thus should be counted within the 10 percent de minimis restriction for their respective shares of decommissioning trust assets. The rule will disallow investment in a mutual fund in which at least 50 percent of the fund is invested in securities of a parent company whose subsidiary is an owner of a domestic nuclear power plant either fully or partially. Similarly, the term “nuclear power plant” is inclusive of those being decommissioned and those licensed to operate.

Comments: One commenter stated that the proposed 10 CFR 50.75(h)(1)(i)(D) should be deleted. The commenter's position is that the “prudent investor standard” implies that if the trusts may be more broadly diversified to include alternative investments such as private equity, then the company should be able to select funds and managers it considers the best qualified. This is not “day-to-day” management of the funds, but strategic management of the funds. Virginia Electric and Power Company suggested that day-to-day investment decisions should be defined as “the hands on management of a stock or bond portfolio, which includes making decisions to buy and sell individual stocks and bonds.” It should not include formation of the trust's investment policy and the selection of investment advisors, mutual funds, pooled funds, collective funds, and limited partnerships. Licensees should be empowered to make strategic decisions to ensure that the best strategies and advisors are employed for the trust. Licensees' interests are aligned with those of the trust, they have superior knowledge of the decommissioning liability, and they have a broad base of financial and investment expertise. Requiring a third party manager to administer strategic investment decisions when the utility is well qualified to do so is fiscally inefficient and increases the cost of managing the funds.

Similarly, several commenters stated that the NRC should more specifically define the “day-to-day management” activities that would be prohibited by the rule. Alternatively, these commenters suggested that the NRC eliminate this prohibition entirely and allow licensees to prudently determine the level of their involvement necessary to adequately administer their decommissioning trust. Also, under the proposed 10 CFR 50.75(h) the NRC could interpret a trust investment direction as being “day-to-day investment management control” and cause the trust to pay for external investment management services to direct the trusts investment. This prohibition is overly broad. Licensees should be allowed to give some direction to fund managers when it comes to the licensee's decommissioning fund. A commenter suggested that this prohibition be eliminated, or, if the NRC has examples where licensees who have outside managers have engaged in “day-to-day management” of the fund in a detrimental way, this prohibition should be better defined. Another stated that the proposal is overly burdensome in that it would increase costs without providing any added protection of the public health and safety.

Several commenters stated that the NRC's proposed limitation on licensee involvement in investment decisions in 10 CFR 50.75(h)(1)(i)(D) should be changed to restrict licensees from engaging in this activity, rather than trustees who do not ordinarily engage in this type of activity. Also, it would require licensees to spend more money to use commercial investment management services without an adequate explanation from the NRC as to whether the benefits to be derived from this requirement, if any, would outweigh the added regulatory burden that would result. These commenters also stated that governmental agencies should be granted an exception from 10 CFR 50.75(h)(1)(i)(D) when decommissioning trust fund investments, as directed by the governmental agency, are limited to investments permitted for the investment of public funds under applicable State law. Further, the selling of the investments could conflict with an existing contract or require a licensee to suffer additional compliance costs. The NRC must recognize and accommodate circumstances when current State law already provides sufficient safeguards. These commenters concluded that 10 CFR 50.75(h)(1)(i)(D) would add costs, reduce accountability, and is unnecessary to achieve the stated purposes of the proposed amendments.

Similarly, another commenter stated that the proposed rule is flawed because it limits the right of public power owners to direct trust fund assets to investments that are permitted and regulated under State and local law, ( e.g. , investments in securities issued by the State government of a municipal licensee or other State or local municipality) the selling of which would conflict with an existing contract or require a licensee to suffer additional compliance costs without Federal compensation, or that might affect the rights of public power minority owners upon license transfers of owner-operators. Two commenters said that an exception should be made to 10 CFR 50.75(h)(1)(i) for political subdivisions of States when investment management is addressed by State statute and meets “prudent man” standards.

One commenter representing several licensees suggested adding the following to the proposed 10 CFR 50.75(h)(1)(i)(D): “* * *, except in the case of passive fund management of trust funds where such management is limited to investments tracking market indices.” The commenter stated that this would permit passive index fund management by a licensee, its affiliates or subsidiaries, but would not constitute “day-to-day management.” Passive index funds replicate the performance of established index funds and do not require active or day to day stock or security selection. Commenter asserted that these funds also satisfy the “prudent investor standard.” Further, this activity could provide substantial cost savings to licensees, because the licensee, rather than an outside fund manager, can perform the mechanics necessary to participate in the index fund at a savings to the decommissioning trust fund. The commenter stated that the bottom line is that it is cheaper to run large amounts of index funds in-house by the sponsor than pay an investment manager several basis points to perform the same function.

Response: The Commission agrees with many of the comments raised in this section. For example, the limitation on fund management in the final rule was modified to state that licensees may provide day-to-day direction to the trustee for buying and selling index funds, such as “Standard and Poors 500.” The final rule was further modified as the result of another comment by restricting licensee involvement in investment decisions as opposed to trustee involvement as was originally proposed. The comments calling for an exception for licensees that are governmental agencies or for licensees located in States in which State statutes mandate investment management were addressed in the final rule by specifying that § 50.75(h)(1) applies to those licensees that are not “electric utilities.” Governmental agencies, by the NRC's definition in § 50.2 are considered electric utilities as are those licensees still under State regulation. The NRC agrees with the last comment that suggested a modification which would permit passive index fund management by a licensee, its affiliates or subsidiaries, and the final rule was changed accordingly. The proposed solutions have no negative impact on public health and safety, but they provide savings and efficiencies, and clarity compared to the proposed rule. Changes have been made in the regulatory guide to reflect these modifications.

Comments: Five commenters stated that NRC should allow licensees to take credit for decommissioning trust earnings through the entire projected decommissioning period. Other commenters stated that, even if a plant is dismantled and decommissioned after shutdown, the credit should be allowed during the dismantlement period because decommissioning activities will not be completed immediately after the termination of operation. Also, licensees should be allowed to assume up to a maximum of ten years of earnings credit through the decommissioning period. One commenter suggested modifying the proposed 10 CFR 50.75(h)(1)(iii) because in DG-1106, the NRC recognized that the 30 day notice should be provided to the NRC before disbursing funds but should not apply to plants withdrawing funds under 10 CFR 50.82(a)(8)(i). This exception is not noted in the proposed rule. The commenter also noted that their modification to the proposed rule is particularly appropriate because it allows licensees to use the 3 percent of decommissioning trust fund monies for planning activities before plant retirement as provided at 10 CFR 50.82(a)(8)(ii). There is little need for the NRC to require a 30-day advance notice from those facilities utilizing the trusts for pre-planning decommissioning activities. Another commenter noted that NRC should permit all licensees to take credit for expected earnings during operation using the 2 percent figure during the decommissioning period, at least for the period coincident with DECON ( i.e. , approximately 7 years). This interpretation should also apply for a greater period if the licensee submits appropriate preliminary site-specific cost estimates and/or decommissioning planning information to the NRC.

Two commenters stated that 10 CFR 50.75(e)(1)(i) and (ii) should be modified to allow credit for decommissioning trust earnings during periods of safe storage, final dismantlement, and license termination, regardless of whether a licensee uses a site-specific cost estimate or the NRC “formula amount.”

Lastly, a commenter noted that one possible interpretation of the regulations does not take into account the actual process by which decommissioning will occur. As a consequence, a licensee could end up collecting substantially more money than would be necessary for decommissioning funding simply because of unrealistic assumptions concerning the timing of decommissioning and expenditures for decommissioning shutdown. However, a licensee is not going to expend all decommissioning funds immediately after shutdown. Even when the licensee adopts an immediate dismantlement option for decommissioning, that process will still require several years to complete decommissioning. Although the withdrawals from the fund would be made on an ongoing basis, the assets retained would continue to grow. The commenter asserted that given the NRC's interpretation, licensees are being compelled to collect millions of dollars more during plant operation than will be necessary, even under the most conservative assumptions regarding the timing of decommissioning. The commenter suggested that clarification is needed regarding credit for projected earnings during periods of safe storage, final dismantlement, and license termination in the rule because the regulatory guidance is creating a requirement not directed by the rule.

Response: First, it should be noted that § 50.75(e)(1) and (2) also require full funding of decommissioning “at the time termination of operation is expected.” Thus, the commenters have not provided a complete picture of the situation. Second, the generic formulas are based on immediate dismantlement as the assumed method of decommissioning. Therefore, those licensees certifying to formulas can not take a 2-percent credit into a SAFSTOR period. However, a 2-percent credit can be used when a site-specific estimate is explicitly based on deferred dismantlement. Third, credits may be timed for outlays for decommissioning expenses. Licensees certifying only to the formula amounts ( i.e. , not a site-specific estimate) can take credit into the dismantlement period ( e.g. , the first 7 years after shutdown.) The final rule has been revised to reflect these points.

Comments: Eight commenters stated that the NRC should define what is meant by a “material” modification to a trust that would require a 30-day advance notification to the NRC in more detail. If the proposed rule is adopted as written, the redundant reporting requirements should be deleted. The commenter further stated that the 30-day notification for licensees making material changes to trust agreements should not apply to those changes caused by State or Federal mandated changes. Lastly, the NRC should be required to notify licensees if there were no objections to proposed amendments.

Two commenters noted that the NRC should be aware that certain amendments to trust agreements in the proposed rule may require PUC approval. As an example, two other commenters noted that their PUCs approved the way the different types of decommissioning funds are handled in a single external trust, and any significant change in this handling would require PUC notification and review. Therefore, the commenters wish to be able to continue with this commingling of funds through the completion of the commenters' plant decommissioning. The proposed 10 CFR 50.75(h)(1)(iii) would preclude such a commingling of funds in a single external trust account, because withdrawals from the fund under the proposed rule would be allowed only for radiological decommissioning costs. The commenter is concerned that the withdrawals it has been able to make would not be possible under the proposed rule, even though NRC has pre-approved: (1) The construction and associated costs of a dry storage facility; (2) the schedule for this construction and for incurring these costs; and (3) the schedule for and manner of (commingling) accumulating funds to cover these costs.

Two commenters suggested an addition to the rule that “* * * any amendment to the license of a utilization facility which does no more than delete specific conditions relating to terms and conditions of decommissioning trust agreements involves ‘no significant hazards consideration.’ ” The commenters stated that licensees should be provided relief from any conflicts or inconsistencies between the final rule and specific license conditions. Licensees that currently have separate license conditions in this area should have the option to amend their licenses to remove those conditions. The commenters also stated that a generic finding of no significant hazards consideration would facilitate the review and approval of these administrative amendments.

Response: The NRC's definition of “material” modifications includes actions such as a change of a trustee, changes of provisions relating to withdrawals from the trust, changes relating to the beneficiary, changes relating to the duration or term of the trust, or other changes potentially affecting the ability of the trust agreement to provide reasonable assurance of decommissioning funds. Modifications that are not material would include, for example, changes in fee structures paid to a trustee, changes in arbitration provisions between the trustee and the licensee, changes in the investment advisor, if applicable, or investments, provided the changes comply with other aspects of this rule.

As to the second comment in this section relating to PUC approval, it has been noted that much of this rule will not apply to licensees under PUC regulation. Further, with respect to commingling of funds, the Commission does not object to that practice as long as the licensees are able to provide a separate accounting showing the amount of funds earmarked for radiological decommissioning versus utilities not subsumed under the NRC's definition of decommissioning in 10 CFR 50.2.

The last comment suggested an addition to the rule to provide relief from any conflicts or inconsistencies between the final rule and specific license conditions. Licensees will be able to decide for themselves whether they prefer to keep or eliminate their specific license conditions. Because these changes would be to conditions that resulted from license amendments ( i.e. , license transfers) that already generically involve “no significant hazards” considerations, any amendments to conform or eliminate these conditions would likewise involve “no significant hazards.”

Comments: Two commenters stated that the rule should not preclude foreign financial institutions from serving as trustees (proposed 10 CFR 50.75(e)(1)(ii)) if a licensee can demonstrate that there would be an equivalent level of assurance. The proposed amendment to § 50.75(e) would require the trust to be overseen by an entity that is an appropriate State or Federal government agency or whose operations are regulated by a State or Federal agency. The commenters also stated that clarification is needed as to what this amendment would actually require, who would qualify as an appropriate agency, and what role that agency would have in the administration of the decommissioning trust. The amendment would also preclude the use of an insurance product, which the NRC presently allows, to satisfy decommissioning funding requirements. Many of the presently used insurance companies are domiciled outside of the U.S. The commenters further stated that it is not clear why there should be a requirement that only companies regulated by State or Federal agencies can be trustees for decommissioning purposes, when such a requirement does not apply to insurers used to satisfy financial assurance requirements for operating reactors.

Response: A licensee may have a foreign financial institution serving as trustee if the licensee can demonstrate to the NRC that there would be an equivalent level of assurance as there would be under a U.S. trustee. At a minimum, the foreign trustee would need to have a business branch in the U.S. that is regulated by a State or Federal entity. Also, the amendments in these regulations only apply to trust agreements, not insurance coverage. Thus, licensees who choose to use insurance for decommissioning assurance may use foreign insurers.

Comments: Seven commenters stated that the proposed 10 CFR 50.75(h)(1)(iii) fails to acknowledge the possible accumulation of trust funds for purposes of funding spent fuel management and non-radiological decommissioning costs, but that such an accumulation should be encouraged by the NRC. Several of the commenters suggested that restrictions should not apply to funds held in trust for purposes other than radiological decommissioning, e.g. , spent fuel storage or non-radiological decommissioning costs. The commenters asserted that a licensee cannot completely fulfill its NRC regulatory decommissioning obligation while fuel resides in the spent fuel pool and in keeping with the principle that the beneficiaries of the plant's production should pay the full life-cycle costs, respectively. Collection of these funds is usually encouraged or required by PUCs. Also, complete “greenfield” decommissioning is usually required if the property is not owned by the licensee. The commenters stated that if the NRC determines that these funds should be placed in separate trusts or sub-accounts to avoid the proposed restrictions, the NRC should provide licensees an opportunity to move these funds into separate trusts or accounts before the implementation of the new rule.

Alternatively, a commenter noted that NRC should clarify that the proposed 10 CFR 50.75(h)(1)(iii) disbursement restrictions apply only to funds held in trust for radiological decommissioning, not non-radiological decommissioning. Some decommissioning trust funds are required by non-NRC regulatory agencies to include decommissioning activities that NRC does not require and their estimates would then exceed those of the NRC. The commenter wishes to ensure its continued ability to protect ratepayers from any financial risks associated with nuclear decommissioning. However, the proposed 10 CFR 50.75(h)(1)(iii) would restrict disbursements from the trust, escrow account, Government fund, or other account to ordinary administrative expenses, decommissioning expenses, or transfer to another financial assurance method until final decommissioning has been completed. The commenter suggested that even though separate trust funds could theoretically be established for NRC radiological decommissioning and other decommissioning activities, it would not necessarily be practical or cost-effective to require the physical demolition and waste disposition work activities to institute artificial accounting to ensure which fund pays for which activities. Likewise, if demolition funds were estimated assuming an area might be radiologically contaminated, those funds would have to be transferred to a different trust fund in order to pay for demolition if the area was determined to not be contaminated during the actual decommissioning.

Two commenters noted that the proposed rule and draft guidance restrict the use of the trust funds for specified purposes including “decommissioning expenses.” The NRC's definition of “decommissioning” excludes a range of public benefit activities that rate-setting authorities often find necessary and appropriate for public funding, e.g. , returning a site to “greenfield” condition. The commenters stated that the proposed rule and guidance must clearly state that a nuclear decommissioning trust may disburse funds for these other purposes as long as funds have been authorized by a public rate-setting authority, such as a PUC, and have been collected for these purposes.

Additional commenters also noted that the NRC's rules on the use of decommissioning trust funds should permit cleanup of non-radiological substances and structures. Dual jurisdiction over the nuclear power industry gives States the authority over the economics of nuclear generation costs. New York State has exercised this authority by allowing utilities to place collected monies from ratepayers in the decommissioning trust funds to pay for both the radiological and non-radiological segments of the decommissioning process. These commenters suggested that the NRC should clarify that the funds may be used to remove non-radiological substances and structures, and restore the sites back to greenfield conditions. Also, the NRC should allow licensees to withdraw funds for non-radiological purposes before the completion of the radiological decommissioning activities.

For about 8 years, another commenter has been withdrawing monies from its trust fund under 10 CFR 50.82(a)(8)(i), as necessary to accomplish radiological decommissioning activities, spent fuel management activities, and some non-radiological decommissioning activities according to the expenditure schedule detailed in the plant-approved cost estimate and funding plan. This commenter stated that combining radiological decommissioning, non-radiological, and spent fuel funds has been economically and functionally advantageous.

Response: The first comment in this section calls on the NRC to encourage the accumulation of trust funds for the purposes of spent fuel management and non-radiological decommissioning costs. The collection of funds for spent fuel management is already addressed in 10 CFR 50.54(bb) where it indicates that licensees need to have a plan, including financing, for spent fuel management. Any NRC requirements with respect to the accumulation of funds for non-radiological decommissioning costs would be beyond the range of the NRC's legal authority. The NRC does not object to licensees mingling funds for decommissioning activities as defined by the NRC and for other activities outside the NRC's definition. However, if funds are mingled in this way, licensees need to ensure that separate sub-accounts are established so funds for each type of activity are appropriately identified.

As to the statement made by commenters that restrictions should not apply to funds held in trust for purposes other than radiological decommissioning, the Commission's position is that withdrawals for non-radioactive decommissioning expenses that do not affect the amount of funds remaining for radiation decommissioning costs are not covered by this rule. However, the Commission is not proposing that licensees institute separate trusts to account for the different types of activity. The Commission appreciates the benefits that some licensees may derive from their use of a single trust fund for all of their decommissioning costs, both radiological and not; but, as stated above, a licensee must be able to identify the individual amounts contained within its single trust.

The remainder of the comments relating to State jurisdiction and licensees already in decommissioning become moot because this rule will not apply to licensees under State or FERC regulation or to licensees withdrawing monies under 10 CFR 50.82.

Comments: Eleven commenters noted that the proposed rule does not contain any plans for transition from the existing provisions to the new requirements. The rule provides neither a period for an effective date nor any plans for transition from existing trust agreements to the requirements of the proposed rule. These commenters stated that it is also not clear if the new rule only applies to licenses in a deregulated environment or licensees who are pursuing renewal or license transfer of all licenses. The NRC should clarify what actions licensees must take with regard to existing trust agreements and when these actions must be completed if the proposed rule becomes final. The NRC should allow licensees sufficient time to review and conform trust documents to comply with the final rule to avoid, or at least minimize, adverse financial impact on decommissioning funds resulting from compliance with the proposed rule. These commenters suggested that grandfathering or a reasonable transition period should be allowed for existing decommissioning funding arrangements that cannot be amended or terminated without substantial penalties.

One commenter stated that the implementation period should be no shorter than 90 days and that the rule should permit case-by-case extensions where there is good cause. A second commenter stated that a transition period of at least six months before the new requirements are made effective is needed. Another commenter suggested that the implementation period should be extended to a period of “not less than one year” because a small number of trustees act for a large number of licensees and their trusts. Still another commenter stated that the NRC needs to clearly state its expectations regarding when licensees are expected to modify their trust documents to conform to the proposed rule. The commenter proposed that for plants not undergoing license transfer or license renewal, a two-year period should be specified to allow for a smooth transition to the rule, following its effective date.

Another commenter pointed out that changes may require other non-NRC regulatory approvals. Still another commenter stated that the NRC should make it clear that its silence as to a proposed disbursement, or its approval after objection, will have no effect upon parties' rights under contracts or other regulations governing the expenditure of decommissioning funds. Lastly, another commenter suggested that the proposed investment limitations should be implemented to all new investments 90 days following the implementation of the rule. This commenter noted that requiring changes to the existing portfolios would result in increased costs because of the fees and there are potential tax consequences. The last comment on this point stated that the implementation statement could include a clause requiring implementation of the rule if ownership will be changing or before elimination of State and FERC oversight of decommissioning funding during the implementation period.

Response: The Commission has decided that the implementation of this rule will be one year from its date of publication in the Federal Register . This should be sufficient to help licensees avoid negative financial impacts on the decommissioning funds. With respect to the point on parties' rights under contracts, the NRC does not believe that this rule will interpose the NRC in contractual disputes that do not affect protection of public health and safety. The last comment in this section is rendered moot because the rule will not, in general, apply to licensees under FERC or PUC regulation, or who otherwise meet the NRC's definition of “electric utility.”

Comments: A few commenters stated that the proposed action was, in fact, a backfit, contrary to the NRC's stated position. Therefore, a backfit analysis is required because the NRC already requires a decommissioning fund to be segregated from a licensee's assets and outside its administrative control, and permits withdrawals only for legitimate decommissioning expenditures. These commenters further stated that because the NRC is capable of imposing additional conditions when necessary in license transfer proceedings, the proposed rule does not appear necessary to protect the public health and safety. These commenters asserted that the NRC should not seek to invoke the “adequate protection” exception to the Backfit Rule in this case, but should perform the requisite analysis of costs and benefits under the standards of 10 CFR 50.109(a)(3).

Another commenter stated that an adequate backfit analysis has not been performed because the analysis does not mention how this 30-day notice before fund use during actual decommissioning activities will adversely affect licensees. This commenter asserted that the reliance on the effect of the loss of PUC/FERC jurisdiction and oversight due to deregulation fails to acknowledge or consider that many licensees are not deregulated and may never be fully deregulated. The NRC has not articulated why existing rules fail to ensure adequate protection and no example is given of a licensee who lacked financial assurance to complete decommissioning in a safe and timely manner. This commenter further stated that the NRC has not provided any analysis of how the NRC could more effectively ensure the availability of adequate funds for decommissioning in a more efficient and less restrictive manner.

Response: The NRC believes that by eliminating most of the requirements that “electric utility” licensees comply with the rule and by explicitly eliminating the requirement to provide advance notification of decommissioning fund expenditures when § 50.82 applies, the backfit concern is eliminated. Most of the comments related to the possibility of dual regulation, which is not the case under this final rule. Further, the rule language has been changed from “30 days” to “30 working days.”

The following comments were submitted by one commenter each and do not fit into one of the major categories listed above.

Comment: The proposed rule does not correspond to the “Discussion” and “Section-by-Section Analysis” in the Federal Register notice. The rule's “Discussion” section focuses entirely on decommissioning trusts, but this focus is not reflected in the proposed rule. It is particularly unclear if the use of decommissioning trust funds is mandatory under 10 CFR 50.75(e) or if other less formal arrangements are also acceptable. The commenter recommends that use of the trust funds be mandatory unless there are compelling reasons that less formal arrangements can provide equivalent protection. The rule's “Discussion” section focuses entirely on decommissioning trusts, but this focus is not reflected in the proposed rule.

Response: After 1988 and as amended in 1998, the NRC, under 10 CFR 50.75 has allowed a variety of financial assurance mechanisms. However, virtually all nuclear power reactor licensees have decided to make use of decommissioning trusts; hence, the focus and emphasis on trusts in this rule.

Comment: “* * * (T)he proposed rule itself would not require decommissioning trusts. An arrangement that is not a trust will not have a trust instrument and may not entrust decommissioning funds to someone with the fiduciary obligations of a trustee.”

Response: As stated above, virtually all nuclear power reactor licensees have decided to make use of decommissioning trusts; hence, the focus and emphasis on trusts in this rule.

Comment: Proposed 10 CFR 50.75 (e)(1)(i), states that “Prepayment is the deposit * * * of cash or liquid assets * * *” It then goes on to state that “Prepayment may be in the form of a trust, escrow account, Government fund, certificate of deposit, deposit of government securities, or other payment acceptable to the NRC.” This commenter claims that “Trusts,” “escrow accounts,” and “Government funds” are not forms of prepayment.

Response: “Trusts,” “escrow accounts,” and “Government funds” may be used as forms of prepayment as long as they are established in accounts that are independent from the licensee. Further, certificates of deposit and deposits of Government securities are among those securities that could be deposited in a prepayment account.

Comment: A commenter claimed an inconsistency on several bases between the words of the proposed § 50.75 (e)(1)(i) “ * * * trust, escrow account, Government fund, certificate of deposit, deposit of Government securities, or other payment shall be established pursuant to a written agreement * * *” versus the following words in the “Section-by Section Analysis:” “The sentence would call for the trust to be an external trust fund held in the United States, established pursuant to a written agreement * * *”. First, the commenter noted that “the apparent intent of the rule is to require decommissioning trusts for both prepayments and external sinking funds. Escrow accounts and certificates of deposit are not the same as trusts, although a certificate of deposit could be held within a trust.” Next the commenter stated that the language is “confusing” in that “government funds, certificates of deposit, government securities and other payments are not ‘established pursuant to a written agreement’ but rather are types of funding.” The commenter was not aware of licensees using Government funds for their decommissioning funding. The commenter stated that if these arrangements do not exist and are not expected to be created, the rule should be modified to delete any reference to them. However, if that is not the case and these arrangements do exist, the rule should be written to allow use of Government funds if they ensure the same level of certainty as decommissioning trusts.

Response: A major portion of the response to this comment is contained in the previous response. The intent of the rule is not to require decommissioning trusts for prepayments and sinking funds, but to focus on making these trusts stronger. As indicated, the rule focuses on external trusts because almost all licensees use them. However, the final rule has been modified to state that similar provisions are to be included in escrow accounts and Government funds. Although the commenter apparently was not aware of licensees using Government funds for their decommissioning funding, one State has essentially established a Government fund for the nuclear plant located in its State.

Comment: The same commenter stated that “Government funds are, however, typically within the control of government bodies and may be used for the purposes allowed by law. Judicial enforcement of amended statutory provisions could be much more problematic than judicial enforcement of a trust agreement.”

Response: NRC has traditionally granted deference to State ratemaking mechanisms. However, case law has long established Federal preeminence with respect to protection of public health and safety under the Atomic Energy Act of 1954, as amended.

Comment: A commenter stated that “If sinking fund payments and prepayments into external decommissioning trusts are used by virtually all nuclear power plant licensees * * * there would appear to be no good reason for confusing language that would allow less certain arrangements to maintain decommissioning funds.”

Response: After 1988 and as amended in 1998, the NRC, under 10 CFR 50.75, has allowed a variety of financial assurance mechanisms. However, virtually all nuclear power reactor licensees have decided to make use of decommissioning trusts; hence, the focus of this rule on trusts. The NRC sees no need to limit the licensees' available options that the NRC has determined provide equivalent levels of assurance.

Comment: The Commission should clarify that replenishment of a decommissioning working capital fund would be a permissible disbursement from the decommissioning trust fund.

Response: Because the rule will not apply to those licensees operating under 10 CFR 50.82, the point is moot.

Comment: The disbursement process should provide an option for a licensee to be the party presenting the request for disbursements and the party to disburse the funds, rather than the fund trustee. Compliance with the regulations may result in significant cost for a licensee. Along these lines, the commenter believes that the NRC's estimate of 40-80 hours being required for a licensee to revise its trust agreement to comply with the proposed regulations is “unduly low.” If the rule would result in a loss in the value of the fund, the existing trust arrangement should be “grandfathered” or the licensee should be able to seek a waiver from NRC on this requirement.

Response: The NRC agrees with the proposed option for a licensee to be the party presenting the request for disbursement and the party to disburse the funds. The change has been made to the rule to reflect this option. Even though there was only one commenter who questioned the 40 to 80 staff-hour estimate to revise a trust agreement and the Commission believes that its estimate was within the range anticipated by the other commenters, it has increased the estimated range up to 60 to 120 hours. The last comment referred to a potential loss in fund value because of the rule. The Commission does not see this as being a problem because of the allowance of de minimis levels of certain types of investments and the one-year implementation of the rule.

Comment: The proposed rule does not make clear if the transfer of nuclear plant ownership interests would be facilitated by more uniform decommissioning trust agreements, or if the NRC's intends to require uniform agreements. If the trustee is the sole entity authorized to submit requests for disbursements, this needlessly adds cost and delay to the process and provides no greater assurance of the availability of funds for decommissioning. The NRC should give licensees the option of being the party that submits the disbursement requests and that transmits payments to decommissioning contractors.

Response: The Commission is not advocating uniform agreements and is only seeking provisions that enhance public health and safety. Further, as indicated above, the Commission will allow disbursement requests to be submitted by a licensee.

Comment: In order to facilitate license transfers, the NRC should clarify that its regulation will have no effect on the allocation of rights, obligations, or liabilities established by contract or directly applicable orders. If uniform trust agreement provisions were required, they may create an unintended impediment to plant transfers in the future. The rule should state that the regulation would not affect in any manner the rights, obligations, and liabilities of the parties involved in the sale of a nuclear power plant ownership interest.

Response: The Commission agrees with the first comment that the “regulation will have no effect on the allocation of rights, obligations, or liabilities established by contract or directly applicable orders.” With regard to uniform trust provisions, the NRC is not requiring uniform trust provisions except in specified areas, so the point is moot. Finally, the Commission disagrees with the last statement that “the regulation would not affect in any manner the rights, obligations, and liabilities of the parties involved in the sale of a nuclear power plant ownership interest.” As stated earlier, the NRC is not mandating uniform trusts but will require certain provisions to protect public health and safety.

Comment: The NRC should convene a public technical conference to explore issues relating to the proposed regulation. Also, the NRC should gather more information and issue a revised notice of proposed rulemaking before proceeding.

Response: The NRC believes the final rule, which is not applicable to licensees still under State or FERC regulation, except as noted for the reporting requirement, clears much of the confusion apparently caused by the proposed rule. Therefore, the Commission does not believe a conference or the collection of additional information is necessary.

Comment: One commenter suggested that the NRC should provide guidance as to what its expectations are with respect to arbitration provisions often contained in trust agreements governing disputes between a trustee and grantor.

Response: The NRC has no position on arbitration positions contained in trust agreements because those provisions are beyond the NRC's legal authority.

Comment: The NRC should provide a list of the public and private companies that own or operate power reactors within the meaning of the rule.

Response: A complete list of licensees/owners of nuclear power plants may be found in “Owners of Nuclear Power Plants,” NUREG/CR-6500, Rev. 2, (March 2002). The NRC intends to revise this publication approximately every 2 years.

Comment: One commenter stated that the rule should be revised to eliminate the unnecessary requirement for power reactor licensees that maintain an NRC-approved, site-specific decommissioning cost estimate and funding plan to also meet the minimum certification amount under 10 CFR 50.75(c). The rule should be revised to specify that for power reactor licensees that maintain NRC-approved site-specific decommissioning cost estimates and funding plans, the requirements of 10 CFR 50.75(c) do not apply. If such a rule revision is not made, then the subject statement in DG-1106 should be reworded or eliminated.

Response: The commenter is incorrect in indicating the rule should be revised. The Commission's position remains that the site-specific estimates may be used as a basis for a funding plan if the amount to be provided is “* * * at least equal to that stated in paragraph (c)(2) of * * *” (§ 50.75). The Commission does not intend to allow use of site-specific amounts lower than the formula values. The subject statement in DG-1106 has been addressed.

Comment: The NRC should consider conforming changes to 10 CFR 72.30, “Financial assurance and recordkeeping for decommissioning.” 10 CFR 72.30(c) and (d) apply to Part 50 power plant licensees who store spent fuel in an Independent Spent Fuel Storage Installation under either a Part 72 specific license or a general license. Compliance between Parts 50 and 72 would be beneficial to both the NRC for enforcement purposes and licensees for compliance purposes.

Response: For the sake of consistency, 10 CFR 72.30(c)(5) is being modified to reflect the suggested compliance.

Comment: The commenter urged the NRC to continue to recognize the separate and cooperative roles State commissions and the NRC play in regulating nuclear utilities and to work with States on developing mechanisms to protect decommissioning funds.

Response: The NRC agrees with the comment. The rule will not be applicable to those licensees under State or FERC rate regulation, except as noted for the reporting requirement. Further, the NRC continues to work with the States through regular periodic contact with State regulatory authorities. Lastly, as the following comment indicates, the NRC believes that the rule continues to give State commissions the flexibility that they need to ensure the adequacy of decommissioning funds while protecting consumers within their jurisdiction.

Comment: A commenter stated that in specifying “that the trust should be an external trust fund in the United States, established pursuant to a written agreement and with an entity that is a State or Federal government agency or an entity whose operations are regulated by a State or Federal agency” the proposed rule continues to give State commissions the flexibility that they need to ensure the adequacy of decommissioning funds while protecting consumers within their jurisdiction.

Response: The NRC agrees with the comment.

Comment: The NRC should be careful to assure that State commission authority to achieve these goals is not inadvertently undermined. As proposed, the NRC's rulemaking appears to provide enough standardization to achieve the goal of ensuring the security of decommissioning funds while allowing enough generality to achieve the goal of maximizing after-tax yields.

Response: The Commission agrees with the comment. As indicated throughout this document, the NRC will not impose this rule on licensees remaining under State regulation, except as noted for the reporting requirement.

Comment: The NRC should clarify that nothing in its final rule will preempt any State authority from reviewing the transfer of a nuclear facility's assets out of rate base and the impact on ratepayers.

Response: The NRC will not do anything in this rule to preempt any State authority from reviewing the transfer of a nuclear facility's assets out of rate base and the impact on ratepayers. This is also consistent with the response to the preceding comment.

Comment: An investment management firm claimed the proposed rule would “unfairly damage” their business and also deprive nuclear power plant owners of “a significant investment area for diversification of nuclear decommissioning trust funds.”

Response: The Commission believes the 10-percent de minimis limit on nuclear sector investments adequately addresses this concern.

Comment: Finally, several commenters stated that modifications should be made to the Draft Regulatory Guide to make it consistent with the changes made to the final rule.

Response: The Regulatory Guide has been modified to reflect the changes made to the final rule.

Comments were also received on the draft regulatory guide DG-1106. The comments were grouped by section and responded to by the NRC.

Comment: Section 1.1 should be modified to provide guidance for applying existing rules to potential new reactor designs that are not covered by the existing 10 CFR 50.75(c).

Response: The generic formulas can not apply if licensee is not a boiling water reactor or a pressurized water reactor, so any potential new reactor designs must be site specific. The guidance will be modified to highlight this fact.

Comment: Section 1.1.1 should recognize that the certification amounts in 10 CFR 50.75 are specific for BWRs and PWRs. Other reactor licensees need to certify they will have adequate funds for decommissioning; however, an exemption is not needed if the amount differs from the BWR and PWR specified formulas. This comment also applies to Section 2.6.1.

Response: As noted above, site-specific estimates would need to be developed.

Comment: The last sentence of Section 1.1.2 should read “The level of detail necessary to support the cost estimate is discussed in Regulatory Position 1.3.”

Response: This change has been made.

Comment: The NRC's discussion of Test 4 describes that licensees “generally” prepare annual reports, etc., and does not specifically list annual calculation of the estimated cost as required by 10 CFR 50.75(b)(2). Further, the Test 4 description specifies that “* * * these reports can be supplied to the NRC upon request * * *” This availability upon request and the biennial reporting appears sufficient. The Test 4 discussion should justify removing DG Sections 2.2.8 and 1.2 or an explanation of the benefit of annual adjustments to the calculation versus the biennial frequency of the funding status should be provided.

Response: Section 50.75(f)(1) states that “Each power reactor licensee shall report, on a calendar-year basis, to the NRC by March 31, 1999, and at least once every 2 years thereafter on the status of its decommissioning funding for each reactor or part of a reactor that it owns.” Further, the NRC regulations (10 CFR 50.75(c)) provide the tables for the minimum amounts for reasonable decommissioning financial assurance for PWRs and BWRs. Therefore, the Commission sees no need for removing Sections 1.2 and 2.2.8 of the regulatory guide (which refer to these parts) as the commenter requested. The Commission believes that the required biennial reports, along with the right to request more frequent reports because of certain circumstances to protect the public health and safety are the best vehicles to provide this necessary information.

Comment: The second and third paragraphs of Section 1.2 are confusing.

Response: The NRC believes that the comment and response immediately following adequately address this issue and clarify this Section.

Comment: In Section 1.2, the reader should be referred to the guidance provided in the most current revision of NUREG-1307 and then expressly state that the example given in the text is an example of a calculation for a specific year only. As written, there may be conflicting guidance between the NUREG and the Regulatory Guide in future years if each is not revised at the same time.

Response: This change has been made.

Comment: The last sentence of the last paragraph in Section 1.2 should be separated into a new paragraph because it applies to more than non-electric utility applicants and licensees.

Response: This change has been made.

Comment: The last paragraph in Section 1.2 should refer to Regulatory Position 1.4, not 1.5.

Response: This change has been made.

Comment: Section 1.3 also should be modified to provide guidance for applying existing rules to potential new reactor designs that are not covered by the existing 10 CFR 50.75(c).

The section needs to be further modified to clarify that licensees may provide for the funding of spent fuel management and non-radiological decommissioning costs.

Response: As noted above, any new reactor design application will need to contain site specific decommissioning cost estimates. In the responses to comments on the proposed rule, the Commission has indicated that licensees may provide for the funding of non-radiological decommissioning costs, that are not under the Commission's legal authority. Also, as indicated in those responses, 10 CFR 50.54(bb) addresses the funding of spent fuel management.

Comment: The commenter does not see a need for DG-1085, the draft regulatory guide discussing cost estimates, to be referenced in Section 1.3.

Response: The Commission sees nothing wrong in providing information on resources that will be available to assist licensees in this area.

Comment: Regulatory position 1.4.1 of DG-1106, states that “For licensees using site-specific cost estimates ( i.e. , research and test reactor licensees, power reactor licensees not covered by 10 CFR 50.75(c), or * * *)” The commenter stated that it is not clear what is meant by “power reactor licensees not covered by 10 CFR 50.75(c),” since even licensees who are maintaining site-specific cost estimates are required to meet the minimum certification amount specified in 10 CFR 50.75(c). The commenter strongly supported this statement provided it accompanies an associated revision to the rule to eliminate the unnecessary requirement for power reactor licensees that maintain an NRC-approved, site-specific decommissioning cost estimate and funding plan to also meet the minimum certification amount in 10 CFR 50.75(c).

The rule should be revised to specify that for power reactor licensees that maintain NRC-approved, site-specific decommissioning cost estimates and funding plans, the requirements of 10 CFR 50.75(c) do not apply. If such a rule revision is not made, then the subject statement in DG-1106 should be reworded or eliminated.

Response: Licensees not covered by 10 CFR 50.75(c) would include non-PWR and non-BWR reactor designs or those undergoing decommissioning under § 50.82. With regard to the commenter's second comment requesting the elimination of the minimum certification amount in 10 CFR 50.75(c), the Commission has previously considered and rejected the option of allowing licensees to use site-specific estimates less than the minimum amounts. Licensees continue to have the option of submitting an exemption request to the Commission for a lower amount.

Comment: Two commenters noted that the last sentence of Regulatory Position 1.4.3 should be revised to replace the reference to “Regulatory Position 2.2.5.” to “Regulatory Position 2.1.5.”

Response: This change has been made.

Comment: Regulatory Position 1.5, which is referenced in several places of the draft regulatory guide, does not exist. It is not clear if Regulatory Position 1.2, 1.4, 2.2.8 or some other section was the intended reference.

Response: The intended reference is Regulatory Position 1.4 and this change has been made.

Comment: In Section 2.1.5, the reference to “Regulatory Position 1.5” should read 1.4.

Response: This change has been made.

Comment: The last sentence in Section 2.1.5 should have “as needed” added to it.

Response: This change has been made.

Comment: The annual adjustment frequency in Section 2.1.5 for licensees that are no longer rate regulated or do not have access to a non-bypassable charge is too frequent. Short-term market fluctuations could lead to more frequent adjustments than truly necessary and result in greater administrative costs. Because, decommissioning is normally a long-term investment, frequent changes could lead to losses and increased investment costs. Although the fund's adequacy should be evaluated annually, annual adjustments may not be prudent.

Response: The last sentence of Section 2.1.5 has been revised to indicate that adjustments, as needed, to the amount of funds set aside should be made at least once every 2 years, in conjunction with the biennial reporting requirement by licensees that are no longer rate-regulated or do not have access to a non-bypassable charge. Licensees who remain rate regulated should make these adjustments at least every 6 years, in conjunction with rate cases.

Comment: Regulatory Position 2.2.1 of DG-1106 should be revised to “An applicant or licensee using an escrow account, certificate of deposit, or trust agreement * * * may use the sample wording for these methods contained in Appendices B.1, B.2, and B.3, respectively.” This change is consistent with similar wording in Regulatory Position 2.3.1 of DG-1106.

Response: This change has been made.

Comment: The funding mechanism will not ensure that adequate information concerning funds is provided to the NRC. It is the licensee's responsibility to do so under the rule. Even the sample instruments in the appendices do not include NRC reporting requirements, nor should they (Section 2.2.1). Also, Section 2.2.2.5 should be revised to delete “terms relating to the provision of information to the NRC” from the description of key provisions of a trust.

Response: The Commission has deleted what was item (e), “it will ensure that adequate information concerning the funds is provided to NRC,” from Draft Regulatory Guide Section 2.2.1. Also, the words “key terms relating to the provision of information to NRC” has been deleted from Section 2.2.2.5 of the Draft Regulatory Guide.

Comment: Replace the word “indicia” in Section 2.2.1 with another word.

Response: The word “indicia” was replaced with the word “indicators.”

Comment: The methods listed in Section 2.2.1 should be identified in the same order as they are listed in the appendices ( i.e. , the escrow account should be listed first because it is B-1, and the trust agreement should be listed last because it is B-3.)

Response: This change has been made for the sake of consistency.

Comment: The first sentence of Section 2.2.1 references Appendices B.1, B.2, and B.3. The appendices are labeled as B-1, B-2, and B-3. The titles should be consistent.

Response: This change has been made.

Comment: Section 2.2.2.1 should not indicate the need for identification of a license number and NRC docket number. This minor change would reduce the burden of nuclear decommissioning trust agreement amendments necessary to conform to the new NRC rule and guidance.

Response: The words “by license or NRC docket number” were deleted from the draft regulatory guide. As long as licensees use a plant name or other specific identifier, no specific use of docket or license number is necessary.

Comment: Section 2.2.2.2 should have reference to Section 468A eliminated because it is unnecessary. Also, the section should have an addition to indicate that there are existing nuclear decommissioning trust agreements that govern multiple trusts for multiple licensed facilities, an existing practice acceptable to the NRC.

Response: The second and last sentences at Section 2.2.2.2 have been modified to now read: “A single trust agreement may establish two or more Nuclear Decommissioning Funds when a nuclear power plant is owned by two or more licensees. Similarly, a trust agreement may contain both “qualified” and “non-qualified” decommissioning funds pursuant to Internal Revenue Code 468A.” Trusts should be segregated by sub-accounts or some other means to clearly identify NRC-defined decommissioning costs for each unit.

Comment: Several commenters suggested a reconciliation of a 30-day notice for disbursements with DG-1106. They stated that the rule does not provide for the notice exception contained in the draft regulatory guide Section 2.2.2.4 and that no NRC notification should be required for any expenditure specifically permitted under any of the provisions of 10 CFR 50.82(a)(8), i.e. , the exception from notice requirements should include not only 10 CFR 50.82(a)(8)(i), but also 10 CFR 50.82(a)(8)(ii). Lastly, Section 2.2.2.4 should be revised to specifically describe the acceptable forms that a written notice of intent may take to begin expending funds for such purpose. Acceptable forms should include an NRC approval of a site-specific decommissioning cost estimate and funding plan that includes activity costs and schedules related to spent fuel management and non-radiological decommissioning.

Response: These comments are all addressed by the fact that decommissioning trust requirements of the final rule do not apply to licensees that are in decommissioning and thus subject to Part 50.82(a)(8). The regulatory guide was modified to address the comment.

Comment: The last sentence of Regulatory Position 2.2.2.5 does not contribute to the intent of this revision to the Regulatory Guide to provide more detailed guidance to assist in implementing the changes in the NRC's regulations. Some examples and/or characteristics of changes to trust agreements that would not be considered “material” would be of more assistance to licensees wishing to implement the new rule.

Response: As previously mentioned, in response to comments received on modifications to trusts, the NRC defines “material” modifications to include actions such as change of trustee, change of provisions relating to withdrawals from the trust, changes relating to the beneficiary, changes relating to the duration or term of the trust, or other changes potentially affecting the ability of the trust agreement to provide reasonable assurance of decommissioning funds. Modifications that are not material would include, for example, changes in fee structures paid to a trustee, changes in arbitration provisions between the trustee and the licensee, changes in investment advisor, if applicable, or investments, provided the changes comply with other aspects of this rule.

Comment: One commenter suggested that Section 2.2.3 be modified to reflect their comments relating to dual regulation regarding investment standards, re-phrasing the limitations on licensee involvement in investment decisions, and clarification regarding non-nuclear sector collective or commingled funds and pre-existing investments. Another revision in the section is suggested to conform the guidance to the explicit terms of proposed 10 CFR 50.75(h)(1)(i)(A).

Response: The Commission considers the proposed revision consistent with its position on dual regulation. The revision clarifies the Commission's intent and the change has been made.

Comment: This commenter referred only to paragraph C.2.2.3.3 of Draft Regulatory Guide DG-1106. The commenter urged NRC to drop its prohibition of trust agreements investing “in securities of other power reactor licensees or any entity owning or operating one or more nuclear power plants” and suggested that the direct investment be limited “to 10% or less of trust assets.” The commenter also claimed that the proposed rule would “unfairly damage” their business and also deprive nuclear power plant owners of “a significant investment area for diversification of nuclear decommissioning trust funds.”

Response: The final rule has been modified to allow licensees to own securities of other nuclear power plants, but to limit them to 10 percent or less of trust assets. As a result, Section 2.2.3.3 of the revised regulatory guide has also been modified.

Comment: A commenter proposed that the Commission delete Section 2.2.3.5 which recommends that those licensees not under FERC or PUC jurisdiction limit investments to “investment grade,” as defined in that section. The commenter noted that use of the generally accepted term “prudent investor” standard, as defined by FERC negates the need for the NRC to make use of the term “investment grade.”

Response: The Commission has modified the rule and the guidance so that only the term “prudent investor” standard is used. Section 2.2.3.5 has been deleted.

Comment: A commenter proposed that the NRC revise Section 2.2.8 to clarify how licensees may take credit for earnings during the decommissioning period. This is problematic for licensees that operate multiple, modular reactors at a single site.

Response: With respect to the modular reactors, the assumptions of earnings credit should track the estimated cash flows for decommissioning expenses for each module.

Comment: A few commenters noted that the draft regulatory guide contains guidance that is inconsistent with the rule. The 2-percent rate of return credit beyond the period of operation into the safe-storage period is not allowed in Section 2.2.8 of the regulatory guide, but allowed in proposed 10 CFR 50.75(e)(1)(i) and (ii). There are also inconsistencies with the handling of credit for periods of final dismantlement and license termination.

Response: As noted in response to a similar comment on the rule, the 2-percent credit can only be used for the period up to shutdown if the amount is based on the formulas in § 50.75(c). If the amount is based on a site-specific study that explicitly includes SAFSTOR, the licensee can then take the 2-percent credit into the storage period.

Comment: In Section 2.3.1, the first sentence references Appendices B.4, B.5, and B.6. The appendices are labeled as B-4, B-5, and B-6. The titles should be consistent.

Response: This change has been made.

Comment: The third bullet in Section 2.3.2 is confusing.

Response: The bulleted item has been modified to read “For insurance, an original or conformed copy of the insurance policy.”

Comment: The appendix in Section 2.4.2 is incorrectly identified in this section. The appendix referred to should be B-3.2.

Response: This change has been made.

Comment: The regulatory position referred to in Section 2.4.3 should be 2.2.5, not 2.2.2.

Response: This change has been made.

Comment: In Section 2.6.1, the information which the report must include incorrectly states that “any contracts upon which the licensee is relying pursuant to 10 CFR 50.75(e)(1)(ii)(C).” The commenter believed that 10 CFR 50.75(e)(1)(v) is the more appropriate reference. Further, the commenter suggested that this appears to be an ideal location to reiterate the guidance provided in Regulatory Issue Summary (RIS) 2001-07 for the biennial reports.

Response: The commenter is correct in noting that 10 CFR 50.75(e)(1)(v) is the more appropriate reference in this section and the change has been made. Reference to RIS 2001-07 was also added to Section 2.6.1.

Comment: The content of the periodic report on decommissioning funding as described in Section 2.6.2 appears excessive. If more detailed information is desired for a specific trust, the information can be looked at on a case-by-case basis.

Response: The second sentence of Section 2.6.2 has been modified to read “ * * * although it would be helpful if they indicate broad categories of investments as a percent of the total trust portfolio * * *.”

Comment: The next to the last sentence in Section 2.6.2 should read “ * * * as provided in 10 CFR 50.75(e)(1)(i) or (ii).”

Response: This change has been made.

Comment: Regulatory Position 2.7 is redundant and would be more pertinent and focused if it were replaced with “In 10 CFR 50.82(a)(9), submittal of a license termination plan is required at the time a licensee applies for termination of license. The license termination plan must include an updated site-specific estimate of remaining decommissioning costs, as described in detail in NUREG-1700, “Standard Review Plan for Evaluating Nuclear Plant Reactor License Termination Plans,” and RG 1.179, “Standard Format and Content of License Termination Plans for Nuclear Power Reactors.”'

Response: The point raised by the commenter is valid and the change has been made.

Comment: The definitions of “qualified decommissioning funds” and “non-qualified decommissioning funds” should be added to the glossary of financial terms provided in DG-1106, Appendix A.

Response: The NRC uses the terms in reference to Section 468A of the Internal Revenue Code. A footnote has been added to Section 2.1.5 to clarify this reference.

Comment: The methods of financial assurance contained in DG-1106, Appendix B appear to contradict the requirements and allowances in 10 CFR 50.75(e).

Response: Appendix B was modified to note that the examples provided in the appendix are for some of the mechanisms allowed in NRC regulations.

Comment: Appendix B-1, paragraph 4 should include that remaining funds should be returned to the licensee or other specified party upon receipt of documentation of license termination.

Response: This requested change was not made. Although the Commission has no objection to those words being contained in a trust fund provision it is beyond NRC's jurisdiction.

Comment: Section 5 of Appendix B-3 “Sample Trust Fund” should be revised to reflect the obligations imposed by proposed 10 CFR 50.75(h)(1)(ii) and a commenter's proposed 10 CFR 50.75(h)(1)(iii).

Response: This comment reflects the Commission's position that withdrawals made under § 50.82(a)(8) will not be subject to the 30-working day notification requirement. Section 5 of Appendix B-3 was revised.

Comment: Section 6 of Appendix B-3 “Sample Trust Fund” should be revised to reflect a commenter's statement regarding non-nuclear sector collective or commingled funds and pre-existing investments. Section 6(b) should be deleted because it is an issue that should be addressed in negotiations between the licensees and trustees. Other changes are also proposed to account for a commenter's proposed dual regulation regarding investment standards, the proposed 10 CFR 50.75(h)(1)(i)(D), and the proposed modification on the limitations on licensee involvement in investment decisions.

Response: Section 6 has been modified to reflect the Commission's clarification on non-nuclear sector collective or commingled funds and pre-existing investments. Section 6(b) has not been modified because this language has been included only as part of a sample of a trust agreement and does not reflect any NRC requirement that this language be included. Other modifications have been made to reflect the Commission's position on dual regulation, day-to-day investment decisions and licensee involvement in investment decisions.

Comment: Section 8 of Appendix B-3 “Sample Trust Fund” subsections should be renumbered to correct a typographical error.

Response: This change has been made.

Comment: Section 15 of Appendix B-3 “Sample Trust Fund” should be modified to reflect the requirements of the proposed 10 CFR 50.75(h)(1)(ii).

Response: This section has been modified to reflect the 30-working day notification of amendments to the trust agreement.

Comment: Appendices B.3.2.2 and B.3.3 should be changed to B-3.2.2 and B-3.3 to be consistent with titles of other appendices.

Response: These changes have been made.

Comment: In Appendix B-6.5, Item 9, the 120-day time frame should be changed to 180 days to allow sufficient time for action, because the period also included notification and the NRC's review time. Also, in Item 10, the 30 days should be changed to 90 days to allow sufficient time to prepare, review, and approve an alternative financial assurance mechanism.

Response: These changes have been made.

Comment: Appropriate changes should be made to Regulatory Guide 1.159 to correspond to the final rule.

Response: The necessary changes were made.

Comment: Even though neither insurance nor long term contracts are used by many licensees, it would be useful for the NRC to provide guidance for each as it does for the other methods of financial assurance.

Response: First, the guide was written to address the standard, most widely used industry financial assurance methods, which includes trust agreement and guarantees but not insurance and long term contracts. Second, long-term contracts and insurance policies are likely to vary so much that it would be difficult to develop sample language that could encompass all uses of these mechanisms. However, the NRC will consider adding sample language for these mechanisms after it has gained more experience with their use by licensees.

Comment: DG-1106 should include guidance for the application of the self-guarantee as allowed by 10 CFR 50.75(e)(1)(iii)(C).

Response: When using the self-guarantee mechanism, a licensee needs to pass the financial tests as discussed in 10 CFR part 30, Appendix C—Criteria Relating to Use of Financial Tests and Self Guarantees for Providing Reasonable Assurance of Funds for Decommissioning.

Comment: The commenter suggested modifications to DG-1106 to clarify the NRC's guidance for applying the existing rules to potential new reactor designs that are not covered by the current formula amount in 10 CFR 50.75(c).

Response: As indicated above, new reactor designs will be required to use site-specific decommissioning cost estimates.

Comment: The guide is inconsistent in the use of recommendations and requirements.

Response: The NRC staff reviewed the guide and made changes where necessary. Of course, requirements should only be used in reference to being in compliance with regulations and recommendations in reference to approved ways of meeting requirements, often contained in guidance.

Comment: The notification for disbursements and material changes ought to apply to the licensee, rather than the trustee. The proposed rule would require the licensee to notify the NRC of material changes to the trust, while the guide states the trustee is responsible.

Response: Sections 2.2.2.4 and 2.2.2.5 of the guide has been changed to indicate that the licensee is responsible for notifying the NRC of material changes to the trust.

Comment: Estimated tax deductions should be allowed to be assumed to cover taxes on earnings that will be due when investments are sold to meet decommissioning expenses.

Response: The NRC has a long standing policy of not allowing estimated future tax deductions as part of a means to provide decommissioning funding assurance.

Comment: The sample agreements in the appendices do not reflect that the rule permits use of funds for decommissioning planning. They would not allow disbursements until decommissioning is in progress. Spending money on planning before starting decommissioning is a prudent use of funds, when possible.

Response: Spending funds on planning for decommissioning before permanent shutdown is not precluded by this rulemaking and guidance. The NRC will consider clarifying the timing of the use of trust funds for planning in the future.

Comment: For power reactors, a Post Shutdown Decommissioning Activities Report (PSDAR) is submitted rather than a plan until the License Termination Plan is submitted later in the decommissioning. The sample agreements refer to plans and procedures.

Response: The guidance has been reviewed to check for consistency. Changes in the words “plans,” “procedures,” and “reports” were made for clarity where necessary.

Comment: Some of the samples include certification that the licensee is required to commence decommissioning. For most power reactors, the licensee has decided to commence decommissioning rather than being required to do so.

Response: Changes were made to the sample trust fund agreements to indicate that decommissioning “has commenced,” not that it was “required.”

Comment: Ongoing activities may give rise to a need for additional work not anticipated at the time of the last “request.” Also, guidance does not appear to exist regarding specificity requirements associated with the required fund use requests. Overly broad requests may defeat the purpose of the rule while more specific requests may exclude emergent work activities for 30 days. The proposed rule and the draft guidance are inconsistent with respect to expectations relative to the new 30-day disbursement requirement.

Response: The Commission believes that it has addressed this concern by noting that this rule will not be applicable to those licensees in decommissioning under § 50.82.

Comment: One commenter concurred that the trust wording in DG-1106 is not expected to be adopted by the licensees, but believes that the NRC should clarify that directions in the proposed rule that certain trust provisions should be included by power reactor licensees in their trusts does not imply that the general language in the regulatory guide sample trust should be used by power reactor licensees.

Response: This position has been included in the statement of considerations of the final rule.

The final rule clarifies the Commission's position that these new requirements are applicable only to those licensees that are no longer regulated by a State Public Utility Commission (PUC) or the Federal Energy Regulatory Commission (FERC), with the exception that all power reactor licensees, both rate regulated and otherwise, will be required to notify the NRC in advance of decommissioning trust withdrawals if these withdrawals are made before permanent cessation of operations. Further, any nuclear power plant that is no longer operating and under § 50.82 requirements is not affected by this rule. Also, this rule makes a conforming change to § 72.30.

This section is amended by the addition of information to both paragraphs 50.75(e)(1)(i), which describes the prepayment method of financial assurance, and 50.75(e)(1)(ii), which describes the external sinking fund method of financial assurance. The modifications clarify that the trust must be an external trust fund held in the United States, established under a written agreement with an entity that is a State or Federal government agency or whose operations are regulated by a State or Federal agency. Additional information is also included about a licensee's taking credit for projected earnings on decommissioning funds.

This is a new section that implements the following conditions applicable to certain power reactor licensees. The trust agreement must prohibit trust investments in securities or other obligations of the reactor owner or its affiliates, successors, or assigns, or in a mutual fund in which at least 50 percent of the fund is invested in securities of a licensee or parent company whose subsidiary is an owner of a foreign or domestic nuclear power plant. The trust agreement must limit investments to no more than 10 percent of their trust assets in any entity owning one or more nuclear power plants. The trust agreement must stipulate that the agreement cannot be amended in any material respect without 30 working-days prior written notice to the NRC, and that no amendment to the trust may be made if the trustee receives written notice of objection from the NRC within that notice period. The trust agreement must stipulate that the trustee, investment advisor, or anyone else directing investments made by the trust should adhere to a “prudent investor” standard. The trust agreement must provide that no disbursements or payments from the trust (other than for payment of routine administrative expenses or for withdrawals being made pursuant to 10 CFR 50.82(a)(8)) may be made by the trustee until the trustee has first given the NRC 30 working-days prior written notice, and that no disbursements or payments from the trust may be made if the trustee receives written notice of objection from the NRC within that notice period. The person directing the investment of the funds may not use the licensee or its affiliates or subsidiaries as the investment manager for the funds or accept day-to-day management direction of the funds' investments or direction on individual investments by the funds, except in the case of passive fund management of trust funds when this management is limited to investments tracking indices.

This section has been modified to make it consistent with the requirements contained in 10 CFR 50.75(e) and (h).

The NRC is making the documents identified below available to interested persons through one or more of the following methods as indicated.

Public Document Room (PDR). The NRC Public Document Room is located at 11555 Rockville Pike, Room O-1 F23, Rockville, Maryland.

Rulemaking Web Site (Web). The NRC's interactive rulemaking Website is located at http://ruleforum.llnl.gov. These documents may be viewed and downloaded electronically via this Web site.

NRC's Public Electronic Reading Room (PERR). The NRC's public electronic reading room is located at http://www.nrc.gov/reading-rm.html.

The NRC staff contact (NRC Staff). Brian J. Richter, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone (301) 415-1978; e-mail bjr@nrc.gov.

A free single copy of Draft Regulatory Guide DG-1106 may be obtained by writing to the Office of the Chief Information Officer, Reproduction and Distribution Services Section, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or E-mail: DISTRIBUTION@nrc.gov, or Facsimile: (301) 415-2289.

Copies of NUREGS may be purchased from The Superintendent of Documents, U.S. Government Printing Office, Mail Stop SSOP, Washington, DC 20302-0001; Internet: bookstore.gpo.gov ; (202)512-1800. Copies are also available from the National Technical Information Service, Springfield, VA 22161-0002; http://www.ntis.gov; 1-800-533-6847 or, locally, (703) 605-6000. Some publications in the NUREG series are posted at NRC's technical document Web site http://www.nrc.gov/NRC/NUREGS/indexnum.html.

The National Technology Transfer and Advancement Act of 1995, Pub. L. 104-113, requires that Federal agencies use technical standards developed or adopted by voluntary consensus standards bodies unless using such a standard is inconsistent with applicable law or otherwise impractical. In this final rule, the NRC is amending its regulations relating to decommissioning trust provisions for nuclear power plants. This action does not constitute the establishment of a standard that contains generally applicable requirements.

The Commission has determined under the National Environmental Policy Act of 1969, as amended, and the Commission's regulations in subpart A of 10 CFR part 51 that this rule is not a major Federal action significantly affecting the quality of the human environment and, therefore, an environmental impact statement is not required. This revision to the NRC's regulations provides licensees with a codification of requirements and guidance that will specify more fully the provisions of the decommissioning trust agreements. These changes would not result in any increased impact on the environment from decommissioning activities as analyzed in the Final Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities (NUREG-0586, August 1988) and Draft Supplement 1 (NUREG-0586, Draft Supplement 1, October 2001). 1 Therefore, promulgation of this rule would not introduce any impacts on the environment not previously considered by the NRC.

The NRC requested public comments on any environmental justice considerations that may be related to this issue. No comments were received on this issue.

The NRC requested the views of the States on the environmental assessment for this rule. No comments were received from the States on this issue.

This final rule amends information collection requirements that are subject to the Paper Work Reduction Act of 1995 (44 U.S.C. 3501 et seq. ). This rule has been submitted to the Office of Management and Budget for review and approval of the information collection requirements.

The burden to the public for this information collection is estimated to average 6600 to 13,200 hours, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the information collection. Send comments on any aspect of this information collection, including suggestions for reducing the burden, to the Records Management Branch (T-6 E6), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by Internet electronic mail at BJS1@nrc.gov ; and to the Desk Officer, Office of Information and Regulatory Affairs NEOB-10202 (3150-0011), Office of Management and Budget, Washington, DC 20503.

If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not collect or sponsor, and a person is not required to respond to, the information collection.

The Commission has prepared a regulatory analysis on this regulation. The analysis examines the costs and benefits of the alternatives considered by the Commission. The regulatory analysis is available as indicated under the Availability of Documents heading of the Supplementary Information section.

In accordance with the Regulatory Flexibility Act (5 U.S.C. 605(b)), the Commission certifies that this rule does not have a significant economic impact on a substantial number of small entities. This final rule affects only the licensing and operation of nuclear power plants.

The companies that own these plants do not fall within the scope of the definition of “small entities” set forth in the Regulatory Flexibility Act or the size standards established by the NRC (10 CFR 2.810).

The Regulatory Analysis for the final rule also constitutes the documentation for the evaluation of backfit requirements. No separate backfit analysis has been prepared. As defined in 10 CFR 50.109, the backfit rule applies to

The amendments to NRC's requirements for decommissioning trust provisions of nuclear power plants require that decommissioning trust agreements be in a form acceptable to the NRC in order to increase assurance that an adequate amount of decommissioning funds will be available for their intended purpose. Also, as nuclear power reactors have been sold, the NRC has stipulated in connection with license transfers that certain terms and conditions be added to decommissioning trusts. These sales may involve transfers of nuclear power reactors from regulated public utilities to firms that are not regulated as public utilities. Because rate regulators may, as a consequence of utility deregulation, cease to exercise direct oversight over decommissioning trusts, the Commission directed the NRC staff to initiate a rulemaking to require that decommissioning trust agreements are in a form acceptable to the NRC.

Although some of the changes to the regulations are reporting requirements that are not covered by the backfit rule, other elements in the changes are considered backfits because they would modify, supplement, or clarify the regulations with respect to: (1) The fact that the NRC will need to exercise greater oversight of decommissioning trust funds as State Public Utility Commissions reduce their oversight as a result of deregulation within the electric power generation industry, and (2) the NRC exercising more oversight of decommissioning trusts in evaluating license transfer applications. The NRC has concluded on the basis of the documented evaluation required by 10 CFR 50.109(a)(4) and set forth in the regulatory analysis, that the new or modified requirements are necessary to ensure that nuclear power reactor licensees provide for adequate protection of the public health and safety in the face of a changing competitive and regulatory environment not envisioned when the reactor decommissioning funding regulations were promulgated, and that the changes to the regulations are in accord with the common defense and security. Therefore, the NRC has determined to treat this action as an adequate protection backfit under 10 CFR 50.109(a)(4)(ii). Consequently, a backfit analysis is not required and the cost-benefit standards of 10 CFR 50.109(a)(3) do not apply. Further, these changes to the regulations are required to satisfy 10 CFR 50.109(a)(5).

This is not to say that any non-compliance with this rule would place the public health and safety or the common defense and security in immediate jeopardy. Instead, the NRC views these requirements to be necessary to ensure that in the future, at the conclusion of plant operation, adequate funds will be available for decommissioning.

In accordance with the Small Business Regulatory Enforcement Fairness Act of 1996, the NRC has determined that this action is not a major rule and has verified this determination with the Office of Information and Regulatory Affairs of OMB.

For the reasons set out in the preamble and under the authority of the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and 5 U.S.C. 552 and 553; the NRC is adopting the following amendments to 10 CFR part 50 and part 72.

On October 16, 2002, the FAA proposed to amend part 71 of the Federal Aviation Regulations (14 CFR part 71) by amending Class E5 airspace at Tampa, FL (67 FR 63858). This action provides adequate Class E airspace for IFR operations at Vandenberg Airport. Designations for Class E airspace extending upward from 700 feet or more above the surface are published in FAA Order 7400.9K, dated August 30, 2002, and effective September 16, 2002, which is incorporated by reference in 14 CFR part 71.1. The Class E designation listed in this document will be published subsequently in the Order.

Interested parties were invited to participate in this rulemaking proceeding by submitting written comments on the proposal to the FAA. No comments objecting to the proposal were received.

This amendment to part 71 of the Federal Aviation Regulations (14 CFR part 71) amends Class E5 airspace at Tampa, FL.

The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore, (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) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified that this rule will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:

This amendment to part 95 of the Federal Aviation Regulations (14 CFR part 95) amends, suspends, or revokes IFR altitudes governing the operation of all aircraft in flight over a specified route or any portion of that route, as well as the changeover points (COPs) for Federal airways, jet routes, or direct routes as prescribed in part 95.

The specified IFR altitudes, when used in conjunction with the prescribed changeover points for those routes, ensure navigation aid coverage that is adequate for safe flight operations and free of frequency interference. The reasons and circumstances that create the need for this amendment involve matters of flight safety and operational efficiency in the National Airspace System, are related to published aeronautical charts that are essential to the user, and provide for the safe and efficient use of the navigable airspace. In addition, those various reasons or circumstances require making this amendment effective before the the next scheduled charting and publication date of the flight information to assure its timely availability to the user. The effective date of this amendment reflects those considerations. In view of the close and immediate relationship between these regulatory changes and safety in air commerce, I find that notice and public procedure before adopting this amendment are impracticable and contrary to the public interest and that good cause exists for making the amendment effective in less than 30 days.

The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore—(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) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. For the same reason, the FAA certifies that this amendment will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

Accordingly, pursuant to the authority delegated to me by the Administrator, part 95 of the Federal Aviation Regulations (14 CFR part 95) is amended as follows effective at 0901 UTC,

Phoenix Scientific, Inc., 3915 South 48th St. Terrace, P.O. Box 6457, St. Joseph, MO 64506-0457, has informed FDA of a change of address to 3915 South 48th St. Terrace, St. Joseph, MO 64503. Accordingly, the agency is amending the regulations in 21 CFR 510.600 to reflect the change of sponsor's address.

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 congressional review requirements in 5 U.S.C. 801-808.

American Cyanamid, Division of American Home Products, P.O. Box 1339, Fort Dodge, IA 50501, has informed FDA that it has transferred ownership of, and all rights and interest in, the following 25 approved NADAs to Fort Dodge Animal Health, Division of American Cyanamid Co., P.O. Box 1339, Fort Dodge, IA 50501:

Following this change of sponsorship, American Cyanamid is no longer the sponsor of any approved application. Accordingly, 21 CFR 510.600(c) is being amended to remove the entries for American Cyanamid.

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.

Alpharma, Inc., One Executive Dr., P.O. Box 1399, Fort Lee, NJ 07024, filed a supplement to ANADA 200-189 for Lincomycin (lincomycin HCl) Soluble requesting a reduction in the preslaughter withdrawal time to zero days for use of lincomycin soluble powder in medicated drinking water for swine. The supplemental ANADA is approved as of September 19, 2002, and the regulations are amended in § 520.1263c (21 CFR 520.1263c) to reflect the approval. The basis of 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 § 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 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.

Schering-Plough Animal Health Corp., 1095 Morris Ave., Union, NJ 07083, filed NADA 141-206 for NUFLOR (florfenicol) 2.3% Concentrate Solution used to make medicated drinking water for administration to swine for the treatment of respiratory disease associated with several bacterial pathogens. The NADA is approved as of September 4, 2002, and the regulations are amended in 21 CFR part 520 by adding § 520.955 to reflect the approval. The basis of approval is discussed in the freedom of information summary.

In addition, the regulations are amended in 21 CFR 556.283 to establish tolerances for residues of florfenicol in edible tissues of treated swine and to reflect a current format.

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.

Under section 512(c)(2)(F)(ii) of the Federal Food, Drug, and Cosmetic Act (21 U.S.C. 360b(c)(2)(F)(ii)), this approval qualifies for 3 years of marketing exclusivity beginning September 4, 2002.

The agency has determined under 21 CFR 25.33(d)(5) 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.

Boehringer Ingelheim Vetmedica, Inc., 2621 North Belt Hwy., St. Joseph, MO 64506-2002, filed a supplement to approved ANADA 200-008 that provides for the use of BIO-MYCIN 200 (oxytetracycline injection) and OXY-TET 200 (oxytetracycline injection) as treatments for various bacterial diseases in cattle and swine. The supplemental ANADA provides for the administration of these oxytetracycline injectable solutions to lactating dairy cattle. The supplemental application is approved as of September 3, 2002, and the regulations are amended in 21 CFR 522.1660 to reflect the approval. The basis of 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.

Ivy Laboratories, Division of Ivy Animal Health, Inc., 8857 Bond St., Overland Park, KS 66214, filed ANADA 200-346 for COMPONENT TE-H (140 milligrams (mg) trenbolone acetate and 14 mg estradiol, in seven pellets, each pellet containing 20 mg of trenbolone acetate and 2 mg of estradiol) for increased rate of weight gain and improved feed efficiency in heifers fed in confinement for slaughter. Ivy Laboratories' COMPONENT TE-H is approved as a generic copy of Intervet's REVALOR-H, approved under NADA 140-992. The application is approved as of September 27, 2002, and the regulations are amended in 21 CFR 522.2477 to reflect the approval. The basis of 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 10, 2000, the IRS and the Treasury Department published in the Federal Register (65 FR 60136) a notice of proposed rulemaking (REG-105235-99) under section 121 of the Internal Revenue Code. Comments were specifically requested regarding what circumstances should qualify as unforeseen for purposes of the reduced maximum exclusion under section 121(c). Written and electronic comments responding to the notice of proposed rulemaking were received. A public hearing was held on January 26, 2001.

After considering all of the comments, the proposed regulations are adopted as amended by this Treasury decision. Proposed and temporary regulations regarding the reduced maximum exclusion are also published in this issue of the Federal Register .

On September 9, 2002, the IRS published Notice 2002-60 (2002-36 I.R.B. 482), which provides that certain taxpayers affected by the September 11, 2001, terrorist attacks may claim a reduced maximum exclusion for a sale or exchange of the taxpayer's principal residence by reason of unforeseen circumstances.

Under section 121 and the proposed regulations, a taxpayer may exclude up to $250,000 ($500,000 for certain joint returns) of gain realized on the sale or exchange of the taxpayer's principal residence if the taxpayer owned and used the property as the taxpayer's principal residence for at least two years during the five-year period ending on the date of the sale or exchange.

The proposed regulations provide that whether property is used by the taxpayer as the taxpayer's residence, and whether the property is used as the taxpayer's principal residence, depends upon all the facts and circumstances. The proposed regulations further provide that if a taxpayer alternates between two properties, the property that the taxpayer uses a majority of the time during the year will ordinarily be considered the taxpayer's principal residence.

Commentators requested a bright line test or a list of factors to identify a property as the taxpayer's principal residence in the case of a taxpayer with multiple residences. Other commentators questioned whether the property that a taxpayer uses a majority of the time during the year should generally be considered the taxpayer's principal residence, arguing that the determination of the taxpayer's principal residence should be judged on a day-by-day, rather than a year-by-year, basis.

The final regulations continue to provide that the residence that the taxpayer uses a majority of the time during the year will ordinarily be considered the taxpayer's principal residence. However, this test is not dispositive. The final regulations also include a nonexclusive list of factors that are relevant in identifying a property as a taxpayer's principal residence.

Commentators requested clarification of the circumstances in which vacant land surrounding a residential structure would be treated as part of the residence for purposes of section 121. Several commentators maintained that a taxpayer who sells vacant land should be entitled to the section 121 exclusion if the taxpayer used the vacant land in conjunction with a dwelling unit as the taxpayer's principal residence for at least two years.

Under section 1034 and former section 121, a sale of vacant land that did not include a dwelling unit did not qualify as a sale of the taxpayer's residence. See Rev. Rul. 56-420 (1956-2 C.B. 519); Rev. Rul. 83-50 (1983-1 C.B. 41); O'Barr v. Commissioner, 44 T.C. 501 (1965); Roy v. Commissioner, T.C. Memo. 1995-23; Hale v. Commissioner, T.C. Memo. 1982-527. However, if the sale of vacant land was one of a series of transactions that included the sale of the house, and the series of transactions all occurred during the replacement period provided by section 1034 (two years before or after the date of the taxpayer's purchase of a replacement residence), the sale of vacant land and the sale of the house were treated as one sale. See Bogley v. Commissioner, 263 F.2d 746 (4th Cir. 1959); Rev. Rul. 76-541 (1976-2 C.B. 246).

Consequently, the final regulations provide that section 121 applies to the sale or exchange of vacant land that the taxpayer has owned and used as part of the taxpayer's principal residence if the sale or exchange of the dwelling unit occurs within two years before or after the sale or exchange of the vacant land. The vacant land must be adjacent to land containing the dwelling unit and the sale or exchange of the vacant land must otherwise satisfy the requirements of section 121.

For purposes of sections 121(b)(1) and (2) (regarding the maximum limitation amount of the section 121 exclusion), sales or exchanges of the dwelling unit and vacant land are treated as one sale or exchange. Therefore, only one maximum limitation amount of $250,000 ($500,000 for certain joint returns) applies to the combined sales or exchanges of the vacant land and dwelling unit. In applying the maximum limitation amount to sales or exchanges that occur in different taxable years, gain from the sale or exchange of the dwelling unit, up to the maximum limitation amount under section 121(b)(1) or (2), is excluded first, and each spouse is treated as excluding one-half of the gain from a sale or exchange to which section 121(b)(2)(A) and § 1.121-2(a)(3)(i)(relating to the limitation for certain joint returns) apply. Sales or exchanges of the dwelling unit and adjacent vacant land in separate transactions are disregarded in applying section 121(b)(3) (restricting the application of section 121 to only 1 sale or exchange every 2 years) to each other but are taken into account as a sale or exchange of a principal residence on the date of each transaction in applying section 121(b)(3) to that transaction and the sale or exchange of any other principal residence.

Numerous commentators asserted that the two-year use requirement of section 121 should not require actual occupancy. Instead, they argued for a facts and circumstances test similar to the test employed under section 1034. Under that test, a taxpayer's non-occupancy of a residence would count as use if the taxpayer did not intend to abandon the property as the taxpayer's principal residence. The final regulations do not adopt this suggestion because it is inconsistent with the statutory approach under section 121 of aggregating periods of use over a five-year period, and with the legislative history that provides that “a taxpayer must have owned the residence and occupied it as a principal residence for at least two of the five years prior to the sale or exchange.” See H.R. Rep. No. 148, 105th Cong., 1st Sess. 348 (1997), 1997-4 (Vol. 1) C.B. 319, 670; S. Rep. No. 33, 105th Cong., 1st Sess. 37 (1997), 1997-4 (Vol. 2) C.B. 1067, 1117; H.R. Conf. Rep. No. 220, 105th Cong., 1st Sess. 386 (1997), 1997-4 (Vol. 2) C.B. 1457, 1856.

Commentators proposed a special exception to the occupancy requirement for taxpayers who are absent from the home for an extended period of time due to employment but have not purchased a replacement residence. Other commentators suggested that members of the uniformed services and the United States Foreign Service should be accorded a special exception because they are often away from home for extended periods of time. A commentator also requested that the home daycare industry be exempted from the occupancy requirement because calculating the days of actual occupancy presents a particular difficulty for home daycare providers who often use the same space for residential and business purposes.

The final regulations do not adopt these comments because there is no specific authority under section 121 to provide exceptions to the use requirement except in the cases of property of a deceased spouse (section 121(d)(2)), property of a former spouse (section 121(d)(3)(B)), and out-of-residence care (section 121(d)(7)). Moreover, section 1034 contained a special rule for members of the Armed Forces, which Congress did not include in enacting section 121.

Commentators requested that the regulations specify a maximum period of time that would constitute a short temporary absence from the residence and be considered use for purposes of satisfying the two-year use requirement. One commentator suggested that periods of up to five years away from home due to international employment assignments should be considered short temporary absences.

Because the determination of whether an absence is short and temporary depends on the facts and circumstances, the final regulations do not adopt these suggestions.

The proposed regulations provide that if a taxpayer satisfies the use requirement with respect to only a portion of the property sold or exchanged, section 121 will apply only to the gain allocable to that portion. Thus, if the residence was used partially for residential purposes and partially for business purposes (mixed-use property), only that part of the gain allocable to the residential portion is excludable under section 121.

Under section 121(d)(6), the exclusion does not apply to so much of the gain from the sale of the property as does not exceed depreciation attributable to periods after May 6, 1997. Commentators suggested that the enactment of section 121(d)(6) illustrates legislative intent to eliminate the allocation requirement for mixed- use property that existed under prior law.

The IRS and Treasury Department have reconsidered the allocation rules of the proposed regulations. The final regulations provide that section 121 will not apply to the gain allocable to any portion of property sold or exchanged with respect to which a taxpayer does not satisfy the use requirement if the non-residential portion is separate from the dwelling unit. Additionally, if the depreciation for periods after May 6, 1997, attributable to the non-residential portion of the property exceeds the gain allocable to the non-residential portion of the property, the excess will not reduce the section 121 exclusion applicable to gain allocable to the residential portion of the property. No allocation of gain is required if both the residential and non-residential portions of the property are within the same dwelling unit, however, section 121 will not apply to the gain to the extent of any post-May 6, 1997, depreciation adjustments. The final regulations provide that the term dwelling unit has the same meaning as in section 280A(f)(1), but does not include appurtenant structures or other property.

A commentator asked for clarification regarding how to allocate the basis and the amount realized under the allocation rules between the portions of the property used for business and residential purposes. The commentator suggested that the regulations should require allocation on the same basis used to determine previous depreciation deductions. The regulations adopt this comment and provide that the taxpayer must use the same method to allocate the basis and the amount realized between the business and residential portions of the property as the taxpayer used to allocate the basis for purposes of depreciation, if applicable.

Commentators suggested that the regulations adopt the holdings of Rev. Rul. 66-159 (1966-1 C.B. 162) and Rev. Rul. 85-45 (1985-1 C.B. 183) regarding treatment of sales of property by certain trusts. Rev. Rul. 66-159 holds that, in cases in which the grantor is treated as the owner of the entire trust under sections 676 and 671, gain realized from the sale of trust property used by the grantor as the grantor's principal residence qualifies under section 1034 for the rollover of gain into a replacement residence. Because the grantor is treated as the owner of the entire trust, the sale by the trust will be treated for federal income tax purposes as if made by the grantor.

Rev. Rul. 85-45 holds that, in cases in which the beneficiary of a trust is treated as the owner of the entire trust under sections 678 and 671, gain realized from the sale of trust property used by the beneficiary as the beneficiary's principal residence qualifies for the one-time exclusion of gain from the sale of a residence under former section 121. For the period that the beneficiary is treated as the owner of the entire trust, the beneficiary will be treated as owning the property for section 121 purposes, and the sale by the trust will be treated for federal income tax purposes as if made by the beneficiary.

The final regulations adopt these suggestions and provide that, if a residence is held by a trust, a taxpayer is treated as the owner and the seller of the residence during the period that the taxpayer is treated as the owner of the trust or the portion of the trust that includes the residence under sections 671 through 679. The regulations provide similar treatment for certain single-owner entities.

Commentators requested further clarification of the application of the dollar limitations of section 121(b) to non-married taxpayers who are joint owners of a residence. In response, the final regulations provide that each unmarried taxpayer who jointly owns a principal residence may be eligible to exclude from gross income up to $250,000 of gain that is attributable to each taxpayer's interest in the property.

Section 121(c) provides an exclusion of gain in a reduced maximum amount for taxpayers who have owned or used a principal residence for less than two of the five years preceding the sale or exchange or who have excluded gain from another sale or exchange during the last two years. Taxpayers who fail to meet any of these conditions may qualify for the reduced maximum exclusion if the sale or exchange is by reason of a change in place of employment, health, or unforeseen circumstances.

The proposed regulations explain the general rule and the computation of the reduced maximum exclusion but do not provide rules clarifying what is a sale or exchange by reason of a change in place of employment, health, or unforeseen circumstances. Comments were requested regarding what circumstances should qualify as unforeseen. Because the rules formulated in response to the comments are extensive, the IRS and Treasury Department have concluded that it is appropriate to publish proposed and temporary regulations to provide the public with adequate notice and opportunity to comment. These proposed and temporary regulations are published elsewhere in this issue of the Federal Register . The final regulations provide guidance regarding the computation of the reduced maximum exclusion.

Commentators suggested that the regulations allow a surviving spouse to exclude up to $500,000 of gain if the sale or exchange of the marital home occurs within one year of the death of the decedent spouse and the requirements of section 121 are otherwise met. Under section 121(b)(2), the $500,000 exclusion is only available to spouses who file a joint return. A surviving spouse is eligible to file a joint return with the decedent spouse only for the year of the decedent spouse's death. Therefore, the final regulations do not adopt this suggestion.

Commentators also requested clarification regarding the computation of basis and gain for surviving spouses. They asked for guidance regarding the advantages of titling the marital home in the names of both spouses so that a surviving spouse can obtain a step-up in basis and, consequently, realize less gain from the disposition of the marital home. Because the rules regarding the computation of basis and gain are outside the scope of these regulations, the final regulations do not address these issues.

Commentators suggested that the regulations clarify that a taxpayer who sells a partial interest in the taxpayer's principal residence and more than two years later sells the remaining interest in the same property is entitled to use up to the full exclusion for each sale.

The final regulations provide that a taxpayer may exclude gain from the sale or exchange of partial interests (other than interests remaining after the sale or exchange of a remainder interest) in the taxpayer's principal residence if the interest sold or exchanged includes an interest in the dwelling unit.

However, the IRS and Treasury Department believe that allowing more than the maximum limitation amount with respect to the same principal residence is contrary to the language and intent of section 121. Therefore, only one maximum limitation amount of $250,000 ($500,000 for certain joint returns) applies to the combined sales or exchanges of partial interests.

In this regard, for purposes of determining the maximum limitation amount under section 121(b)(1) and (2), the sales or exchanges of partial interests in the same principal residence are treated as one sale or exchange. In applying the maximum limitation amount to sales or exchanges that occur in different taxable years, a taxpayer may exclude gain from the first sale or exchange of a partial interest up to the taxpayer's full maximum limitation amount and may exclude gain from the sale or exchange of any other partial interest in the same principal residence to the extent of any remaining maximum limitation amount, and each spouse is treated as excluding one-half of the gain from a sale or exchange to which section 121(b)(2)(A) and § 1.121-2(a)(3)(i) (relating to the limitation for certain joint returns) apply.

For purposes of applying section 121(b)(3) (restricting the application of section 121 to only 1 sale or exchange every 2 years), each sale or exchange of a partial interest is disregarded with respect to other sales or exchanges of partial interests in the same principal residence, but is taken into account as of the date of the sale or exchange in applying section 121(b)(3) to that sale or exchange and the sale or exchange of any other principal residence.

Commentators asked for clarification regarding when a taxpayer may make or revoke an election under section 121(d)(8) (election to have the section 121 exclusion apply to a sale or exchange of a remainder interest in the taxpayer's principal residence) or section 121(f) (election to have the section 121 exclusion not apply to a sale or exchange of the taxpayer's principal residence). The final regulations adopt and clarify the provisions of the proposed regulations and provide that a taxpayer may make or revoke either election at any time before the expiration of a three-year period beginning on the last date prescribed by law (determined without regard to extensions) for the filing of the return for the taxable year in which the sale or exchange occurred.

Commentators recommended the creation of a form for taxpayers to use to report the sale or exchange of a principal residence even if the gain is entirely excludable under section 121. The final regulations do not adopt this suggestion because, unlike sales or exchanges under section 1034, no tax attributes of the sold residence carry over to a new residence. Therefore the reporting of excluded gain is unnecessary and would be unduly burdensome for taxpayers.

The regulations provide that taxpayers who would otherwise qualify under the provisions of §§ 1.121-1 through 1.121-4 of the final regulations to exclude gain from a sale or exchange before the effective date of the regulations but on or after May 7, 1997, may elect to apply the provisions of the final regulations for any years for which the period of limitation under section 6511 has not expired. A taxpayer may make the election by filing a return for the taxable year of the sale or exchange that does not include the gain from the sale or exchange of the taxpayer's principal residence in the taxpayer's gross income. Taxpayers who have filed a return for the taxable year of the sale or exchange may elect to apply the provisions of the final regulations for any years for which the period of limitation under section 6511 has not expired by filing an amended return.

The regulations provide that the IRS will not challenge a taxpayer's position that a sale or exchange before the effective date of these regulations but on or after May 7, 1997, qualifies for the section 121 exclusion if the taxpayer has made a reasonable, good faith effort to comply with the requirements of section 121. Compliance with the provisions of the proposed regulations that preceded these final regulations generally will be considered a reasonable, good faith effort.

The regulations provide that the bankruptcy estate of an individual in a chapter 7 or 11 bankruptcy case under title 11 of the United States Code succeeds to and takes into account the individual's section 121 exclusion if the individual satisfies the requirements of section 121. Although the effective date for this provision is on or after publication of final regulations in the Federal Register , in view of the IRS's acquiescence in the case of Internal Revenue Service v. Waldschmidt (In re Bradley) , 222 B.R. 313 (M.D. Tenn. 1998), AOD CC-1999-009 (August 30, 1999), and Chief Counsel Notice (35)000-162 (August 10, 1999), the IRS will not challenge a position taken prior to the effective date of these regulations that a bankruptcy estate may use the section 121 exclusion if the debtor would otherwise satisfy the section 121 requirements.

These regulations apply to sales or exchanges on or after December 24, 2002.

It has been determined that this Treasury decision is not a significant regulatory action as defined in Executive Order 12866. Therefore, a regulatory assessment is not required. It also has been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. chapter 5) does not apply to these regulations, and because these regulations do not impose a collection of information on small entities, the Regulatory Flexibility Act (5 U.S.C. chapter 6) does not apply. Pursuant to section 7805(f) of the Internal Revenue Code, the notice of proposed rulemaking preceding these regulations was submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on its impact on small business.

The principal author of these regulations is Sara Paige Shepherd, Office of Associate Chief Counsel (Income Tax and Accounting). However, other personnel from the IRS and the Treasury Department participated in the development of the regulations.

This document contains amendments to the Income Tax Regulations (26 CFR part 1) under section 121(c) relating to the exclusion of gain from the sale or exchange of the principal residence of a taxpayer who has not owned and used the property as the taxpayer's principal residence for two of the preceding five years or who has excluded gain on the sale or exchange of a principal residence within the preceding two years.

Under section 121(a), a taxpayer may exclude up to $250,000 ($500,000 for certain joint returns) of gain realized on the sale or exchange of the taxpayer's principal residence if the taxpayer owned and used the property as the taxpayer's principal residence for at least two years during the five-year period ending on the date of the sale or exchange. Section 121(b)(3) allows the taxpayer to apply the maximum exclusion to only one sale or exchange during the two-year period ending on the date of the sale or exchange. Section 121(c) provides that a taxpayer who fails to meet any of these conditions by reason of a change in place of employment, health, or, to the extent provided in regulations, unforeseen circumstances, may be entitled to an exclusion in a reduced maximum amount.

On October 10, 2000, a notice of proposed rulemaking (REG-105235-99) under section 121 was published in the Federal Register (65 FR 60136). The proposed regulations did not define change in place of employment, health, or unforeseen circumstances for purposes of the reduced maximum exclusion. Comments were specifically requested regarding what circumstances should qualify as unforeseen. A public hearing was held on January 26, 2001.

The IRS and Treasury Department received numerous comments regarding the reduced maximum exclusion and have concluded that many of these comments should be adopted. However, because the rules formulated in response to these comments are extensive, the IRS and Treasury Department have concluded that the rules relating to the reduced maximum exclusion should be issued as proposed and temporary regulations to provide the public with adequate notice and opportunity to comment. Final regulations under section 121 addressing provisions other than the reduced maximum exclusion are set forth elsewhere in this edition of the Federal Register .

Under the temporary regulations, a reduced maximum exclusion limitation is available to a taxpayer who has sold or exchanged property owned and used as the taxpayer's principal residence for less than two of the preceding five years or who has excluded gain on the sale or exchange of a principal residence within the preceding two years. This reduced maximum exclusion applies only if the sale or exchange is by reason of a change in place of employment, health, or unforeseen circumstances. A sale or exchange is by reason of a change in place of employment, health, or unforeseen circumstances only if the taxpayer's primary reason for the sale or exchange is a change in place of employment, health, or unforeseen circumstances. The taxpayer's primary reason for the sale or exchange is determined based on the facts and circumstances. The temporary regulations provide a list of factors that may be relevant in determining the taxpayer's primary reason. These factors are suggestive only. No single fact or particular combination of facts is determinative of the taxpayer's entitlement to the reduced maximum exclusion.

In addition, for each of the three grounds for claiming a reduced maximum exclusion, the temporary regulations provide a general definition and one or more safe harbors. If a safe harbor applies, the taxpayer's primary reason for the sale or exchange is deemed to be a change in place of employment, health, or unforeseen circumstances.

The temporary regulations provide that a sale or exchange is by reason of a change in place of employment if the taxpayer's primary reason for the sale or exchange is a change in the location of the employment of a qualified individual. Employment is defined as the commencement of employment with a new employer, the continuation of employment with the same employer, or the commencement or continuation of self-employment. A qualified individual is defined as the taxpayer, the taxpayer's spouse, a co-owner of the residence, or a person whose principal place of abode is in the same household as the taxpayer.

The temporary regulations adopt a safe harbor, suggested by commentators, that provides that the primary reason for the sale or exchange is deemed to be a change in place of employment if the new place of employment of a qualified individual is at least fifty miles farther from the residence sold or exchanged than was the former place of employment. If the individual was unemployed, the distance between the new place of employment and the residence sold or exchanged must be at least fifty miles. This standard is derived from section 217(c)(1) relating to the moving expense deduction. The safe harbor applies only if the change in place of employment occurs during the period of the taxpayer's ownership and use of the property as the taxpayer's principal residence. If a sale or exchange does not satisfy this safe harbor, a taxpayer may still qualify for the reduced maximum exclusion by reason of a change in place of employment if the facts and circumstances indicate that a change in place of employment is the primary reason for the sale or exchange.

Commentators proposed that, for purposes of determining whether a sale or exchange is by reason of health, the regulations adopt standards similar to those for the deductibility of medical expenses under section 213(a). Commentators also suggested that the regulations provide that the reduced maximum exclusion by reason of health apply to sales and exchanges due to (1) advanced age-related infirmities, (2) the taxpayer's need to move in order to care for a family member, (3) severe allergies, and (4) emotional problems.

In response to these comments, the temporary regulations provide the general rule that a sale or exchange is by reason of health if the taxpayer's primary reason for the sale or exchange is (1) to obtain, provide, or facilitate the diagnosis, cure, mitigation, or treatment of disease, illness, or injury of a qualified individual, or (2) to obtain or provide medical or personal care for a qualified individual suffering from a disease, illness, or injury. A sale or exchange that is merely beneficial to the general health or well-being of the individual is not a sale or exchange by reason of health.

One commentator suggested that the regulations establish a safe harbor allowing a taxpayer to claim a reduced maximum exclusion if the taxpayer obtains documentation of a specific medical condition from a licensed physician. The temporary regulations provide a safe harbor that the primary reason for the sale or exchange is deemed to be health if a physician (as defined in section 213(d)(4)) recommends a change of residence for reasons of health.

For purposes of the reduced maximum exclusion by reason of health, the term qualified individual includes the taxpayer, the taxpayer's spouse, a co-owner of the residence, a person whose principal place of abode is in the same household as the taxpayer, and certain family members of these individuals. The definition of qualified individual in the case of health is broader than the definition that applies to the exclusions by reason of change in place of employment and unforeseen circumstances to encompass taxpayers who sell or exchange their residence in order to care for sick family members.

The temporary regulations provide that a sale or exchange is by reason of unforeseen circumstances if the primary reason for the sale or exchange is the occurrence of an event that the taxpayer does not anticipate before purchasing and occupying the residence.

Many commentators provided suggestions regarding circumstances that should qualify as unforeseen. A large number of commentators suggested that unforeseen circumstances should encompass divorce or the termination of a permanent residential relationship. Others suggested that unforeseen circumstances should include death, birth, marriage, bankruptcy, the loss of employment, incarceration, admission to an institution of higher learning, natural and man-made disasters, involuntary conversions, and a substantial increase in medical or living expenses leading to a significant change in economic circumstances. One commentator suggested that any delay of over three years in selling the residence due to a decline in the real estate market should be deemed an unforeseen circumstance. A few commentators suggested that unforeseen circumstances should include unfavorable changes affecting the desirability of the property, such as environmental problems, zoning-law changes, slovenly neighbors, and serious nuisance or safety concerns.

The temporary regulations adopt many of these suggestions as safe harbors. A taxpayer's primary reason for the sale or exchange is deemed to be unforeseen circumstances if one of the safe harbor events occurs during the taxpayer's ownership and use of the property. The safe harbor events include the involuntary conversion of the residence, a natural or man-made disaster or act of war or terrorism resulting in a casualty to the residence, and, in the case of a qualified individual: (1) Death, (2) the cessation of employment as a result of which the individual is eligible for unemployment compensation, (3) a change in employment or self-employment status that results in the taxpayer's inability to pay housing costs and reasonable basic living expenses for the taxpayer's household, (4) divorce or legal separation under a decree of divorce or separate maintenance, and (5) multiple births resulting from the same pregnancy. The Commissioner may designate other events or situations as unforeseen circumstances in published guidance of general applicability or in a ruling directed to a specific taxpayer. A taxpayer who does not qualify for a safe harbor may demonstrate that the primary reason for the sale or exchange is unforeseen circumstances, under a facts and circumstances test.

For purposes of the reduced maximum exclusion by reason of unforeseen circumstances, a qualified individual includes the taxpayer, the taxpayer's spouse, a co-owner of the residence, and a person whose principal place of abode is in the same household as the taxpayer.

The regulations include examples illustrating the application of the safe harbors and the facts and circumstances test.

The regulations provide that taxpayers who would otherwise qualify under these temporary regulations to exclude gain from a sale or exchange that occurred before the effective date of the regulations but on or after May 7, 1997, may elect to apply all of the provisions of the temporary regulations to the sale or exchange. A taxpayer may make the election by filing a return for the taxable year of the sale or exchange that does not include the gain from the sale or exchange of the taxpayer's principal residence in the taxpayer's gross income. Taxpayers who have filed a return for the taxable year of the sale or exchange may elect to apply all of the provisions of these regulations for any years for which the period of limitations under section 6511 has not expired by filing an amended return.

The temporary regulations provide that the IRS will not challenge a taxpayer's position that a sale or exchange before the effective date of these regulations but on or after May 7, 1997, qualifies for the reduced maximum exclusion under section 121(c) if the taxpayer has made a reasonable, good faith effort to comply with the requirements of section 121(c) and if the sale or exchange otherwise qualifies under section 121.

These temporary regulations apply to sales and exchanges on or after December 24, 2003.

It has been determined that this Treasury decision is not a significant regulatory action as defined in Executive Order 12866. Therefore, a regulatory assessment is not required. It also has been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. chapter 5) does not apply to these regulations. For the applicability of the Regulatory Flexibility Act (5 U.S.C. chapter 6) refer to the Special Analyses section of the preamble to the cross-reference notice of proposed rulemaking published in the Proposed Rules section in this issue of the Federal Register . Pursuant to section 7805(f) of the Internal Revenue Code, these temporary regulations will be submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on their impact on small business.

The principal author of these regulations is Sara Paige Shepherd, Office of Associate Chief Counsel (Income Tax and Accounting). However, other personnel from the IRS and the Treasury Department participated in the development of the regulations.

The collection of information contained in these final regulations has been previously reviewed and approved by the Office of Management and Budget in accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)) under control number 1545-1578. This final rule makes no substantive change in the previously approved collection of information.

An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a valid control number assigned by the Office of Management and Budget.

Books or records relating to a collection of information must be retained as long as their contents might become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.

On December 18, 2000, the IRS and the Treasury Department published a notice of proposed rulemaking (REG-106542-98; 2001-1 CB 473) in the Federal Register (65 FR 79015) under section 645 relating to an election for certain revocable trusts to be treated and taxed as part of an estate. This notice also contained proposed amendments to the regulations under section 671 relating to reporting rules for a trust, or portion of a trust, that is treated as owned by the grantor or another person under the provisions of subpart E, part I, subchapter J, chapter 1 of the Internal Revenue Code (Code), for the taxable year ending with the death of the grantor or other person. Written comments responding to the notice of proposed rulemaking were received. A public hearing on the notice of proposed rulemaking was scheduled for April 11, 2001, but was canceled when no one requested to speak at the hearing. After consideration of all comments, the proposed regulations, with certain changes in response to the comments, are adopted as final regulations by this Treasury decision.

Under section 645, if both the executor (if any) of an estate and the trustee of a qualified revocable trust (QRT) elect the treatment provided in section 645, the trust shall be treated and taxed for income tax purposes as part of the estate (and not as a separate trust) during the election period. The proposed regulations define a QRT as any trust (or portion thereof) that on the date of death of the decedent was treated as owned by the decedent under section 676 by reason of a power held by the decedent (determined without regard to section 672(e)). In accordance with the legislative history accompanying section 645, the proposed regulations provide that a trust, in which the power is held solely by a nonadverse party, is not a QRT. See H.R. Conf. Rep. No. 220, 105th Cong., 1st Sess. at 711 (1997). In addition, the proposed regulations provide that a trust, in which the power was exercisable by the decedent only with the approval or consent of another person, is not a QRT.

Some commentators suggested that, if the decedent's power to revoke the trust was exercisable only with the approval or consent of a nonadverse party, the trust should qualify as a QRT. Many persons use revocable trusts as property management tools and, to protect the grantor from improvident decisions or undue influence, their trust agreements may provide that any revocation of the trust by the grantor will be effective only if consented to by a nonadverse party. The commentators noted that the prohibition described in the legislative history addresses trusts in which only a nonadverse party has a power to revoke.

In response to these comments, the final regulations provide that a trust that was treated as owned by the decedent under section 676 by reason of a power that was exercisable by the decedent with the consent or approval of a nonadverse party is a QRT. The final regulations also clarify that while a trust, in which the power to revoke is held only by the decedent's spouse and not by the decedent, is not a QRT, a trust, in which the power to revoke is exercisable by the decedent with the approval or consent of the decedent's spouse, is a QRT.

Clarification has also been requested regarding whether a trust qualifies as a QRT if the grantor's power to revoke the trust lapses prior to the grantor's death as a result of the grantor's incapacity. Some trust documents for revocable trusts provide that the trustee is to disregard the instructions of the grantor to revoke the trust if the grantor is incapacitated. The IRS and the Treasury Department believe that, if an agent or legal representative of the grantor can revoke the trust under state law during the grantor's incapacity, the trust will qualify as a QRT, even if the grantor is incapacitated on the date of the grantor's death.

The proposed regulations also provide that a QRT must be a domestic trust under section 7701(a)(30)(E) and that a section 645 election for a QRT must result in a domestic estate under section 7701(a)(30)(D). Several commentators suggested that the section 645 election should also be available in situations in which either the QRT or the related estate, or both, are foreign. According to the commentators, U.S. citizens living abroad frequently use revocable trusts to avoid jurisdictional disputes concerning the decedent's assets, as well as the cumbersome probate and forced heirship rules of several foreign countries. Many of the trusts will be foreign trusts upon the grantor's death and, if a section 645 election is permitted to be made, will become part of a foreign estate. The commentators questioned the authority for the domestic restriction provided in the proposed regulations given that the statute and the legislative history do not explicitly limit the applicability of a section 645 election to domestic trusts and domestic estates. Upon consideration of these comments, the requirements that a QRT be a domestic trust and that the election result in a domestic estate are removed from the final regulations. The IRS and the Treasury Department note, however, that a trust for which a section 645 election is made is treated as an estate for purposes of Subtitle A of the Code, but not for purposes of Subtitle F. Accordingly, information reporting under section 6048 will continue to apply with respect to a foreign trust even though a section 645 election has been made to allow the foreign trust to be taxed as part of an estate for purposes of Subtitle A of the Code.

The proposed regulations used the term personal representative to denote the fiduciary (or fiduciaries) of the decedent's estate. One commentator requested that the definition of personal representative in the proposed regulations be expanded to include a personal representative, as well as an executor and an administrator. To be consistent with the language of the statute, the final regulations use the term executor, instead of personal representative, to denote the fiduciary of the decedent's estate. With the exception of including a personal representative in the definition of an executor as requested by the comment, the definition of executor in the final regulations is generally the same as the definition of a personal representative in the proposed regulations. The definition of executor used in these final regulations, however, is not identical to the definition of an executor under section 2203 of the Code: under these final regulations, a person who has actual or constructive possession of property of the decedent is not an executor unless that person is also appointed, or qualified as an executor, administrator, or personal representative of the decedent's estate.

The section 645 election may be made whether or not an executor is appointed for the decedent's estate. Under the final regulations, if an executor is appointed for the decedent's estate, the executor and the trustee of the QRT make the section 645 election by filing a form provided by the IRS for the purpose of making the section 645 election (election form). If an executor is not appointed for the decedent's estate, the trustee makes the section 645 election by filing the election form. Form 8855, “Election to Treat a Qualified Revocable Trust as Part of an Estate,” will be available for making the section 645 election within six months after the publication of these final regulations.

Guidance has also been requested regarding when the section 645 election must be made if a Form 1041 “U.S. Income Tax Return for Estates and Trusts,” is not required to be filed for the first taxable year of the combined electing trust and related estate, if there is an executor, or of the electing trust if there is no executor, because the combined electing trust and related estate, or electing trust, as the case may be, does not have sufficient income to require the filing of a return. A commentator also suggested permitting the section 645 election to be made at any time during the three year period after the due date for the Form 1041 for the estate's first taxable year. The final regulations do not adopt this suggestion and clarify that, for the election to be valid, the election form must be filed not later than the time prescribed under section 6072 for filing the Form 1041 for the first taxable year of the combined electing trust and related estate, if there is an executor, or of the first taxable year of the electing trust, if there is no executor (regardless of whether there is sufficient income to require the filing of that return). If an extension is granted for the filing of the Form 1041 for the first taxable year of the combined electing trust and related estate, if there is an executor, or the electing trust, if there is no executor, the election form will be timely filed if it is filed by the time prescribed under section 6072 for filing the Form 1041 including the extension granted with respect to the Form 1041.

A commentator noted that, under the proposed regulations, an executor will have direct liability for the tax due on Forms 1041 filed for the combined electing trust and related estate. Accordingly, the executor can be personally liable for tax on the income from assets that are not under the executor's control. Further, the executor may not have sufficient assets in the estate to meet the income tax responsibilities of the combined electing trust and related estate. A commentator also noted that the requirement in the proposed regulations that the trustee agree to cooperate to insure that the Forms 1041 for the combined related estate and electing trust are timely filed and the tax due timely paid places the trustee in an untenable position because the executor controls the filing of the return and the payment of the tax.

The IRS and the Treasury Department note that under section 645, the electing trust is not treated as part of the related estate for purposes of Subtitle F of the Code. Accordingly, although the final regulations permit an electing trust and related estate to file a single, combined Form 1041, the electing trust and related estate continue to be separate taxpayers for purposes of Subtitle F, and the fiduciaries of the electing trust and the fiduciaries of the related estate each continue to have a responsibility for filing returns and paying the tax due for their respective entities even though a section 645 election has been made. Under the final regulations, the executor must file a complete, accurate, and timely Form 1041 for the combined related estate and electing trust for each taxable year during the election period. The trustee of the electing trust must timely provide the executor of the related estate with all the trust information necessary to permit the executor to file a complete, accurate, and timely Form 1041 for the combined electing trust and related estate for each taxable year during the election period. The trustee and the executor must allocate the tax burden of the combined electing trust and related estate in a manner that reasonably reflects the respective tax obligations of the electing trust and related estate. If the tax burden is not reasonably allocated, gifts may be deemed to have been made. The trustee is responsible for insuring that the electing trust's share of the tax burden is paid to the Secretary, and the executor is responsible for insuring that the related estate's share of the tax burden is timely paid to the Secretary.

The proposed regulations provide that, in general, a grantor trust must obtain a taxpayer identification number (TIN) upon the death of the grantor regardless of whether or not the trust had a TIN prior to the death of the grantor. See proposed regulation § 301.6109-1(a)(3). The proposed regulations provide an exception to this general rule. The proposed regulations provide that, if there is an executor and a section 645 election has been made, a TIN must be obtained for the related estate but a TIN is not required to be obtained for the electing trust or for a QRT for which a section 645 election will be made. Further, under the proposed regulations, the payors (as defined in § 301.6109-1(a)(5) of these final regulations) of the electing trust or a QRT for which the section 645 election will be made are to be furnished with the TIN of the estate on Form W-9, “Request for Taxpayer Identification Number and Certification.” The proposed regulations were designed to simplify and lessen the reporting burdens imposed on trustees and executors by the interim guidance in Rev. Proc. 98-13 (1998-1 C.B. 370) by removing the requirement to obtain a TIN for electing trusts and certain QRTs.

Several commentators reported, however, that many trustees automatically obtain a TIN for the QRT immediately after the decedent's death and furnish that TIN to payors. Under the proposed regulations, if a trustee obtains a TIN for a QRT, the trustee must file a completed Form 1041 for the QRT for the short taxable year of the QRT beginning with the decedent's date of death and ending December 31 of that year. If a valid section 645 election is made for the QRT, an amended Form 1041 must be filed for the QRT and the payors of the QRT must be furnished with a revised Form W-9 containing the related estate's TIN. As a result, for trustees that obtain a TIN for a QRT, the procedures in the proposed regulations are more burdensome than the procedures in Rev. Proc. 98-13. In response, the final regulations remove the provision in the proposed regulations that excepted an electing trust and a QRT for which a section 645 election will be made from the general requirement that a grantor trust must obtain a TIN upon the death of the grantor. Under the final regulations, the trustee of an electing trust or a QRT for which a section 645 election will be made obtains a TIN upon the death of the decedent as required by § 301.6109-1(a)(3) of these final regulations and furnishes this TIN to the payors of the trust. Under the final regulations, if a section 645 election will be made for a QRT, the trustee is not required to file a Form 1041 for the short taxable year of the QRT beginning with the decedent's date of death and ending December 31 of that year.

The final regulations also simplify the procedures for obtaining a TIN, furnishing that TIN to the payors, and filing a Form 1041 for a QRT if there is no executor. The proposed regulations provide that, if there is no executor, the trustee must obtain a TIN for the electing trust to file as an estate during the section 645 election period. The payors of the electing trust must be furnished with the TIN obtained by the trust to file as an estate. Under the proposed regulations, if a section 645 election will be made for a QRT, the trustee of the QRT may choose to obtain a TIN for the QRT to file as an estate under section 645 and avoid obtaining a TIN for the QRT to file as a trust. If the trustee of the QRT obtains a TIN to file as a trust (and not as an estate), the trustee is required to file a completed Form 1041 as a trust for the short taxable year of the QRT beginning with the decedent's date of death and ending December 31 of that year. If a section 645 election to treat the QRT as an estate is made after the Form 1041 is filed for the QRT treating the QRT as a trust, the trustee of the QRT is required to file an amended Form 1041 as a trust (excluding the items of income, deduction, and credits that are to be reported on a return filed as an estate), obtain another TIN to file as an estate, provide revised Forms W-9 with the new TIN to the payors of the QRT, and file a Form 1041 as an estate. Under the final regulations, if there is no executor, the trustee of an electing trust or a QRT for which a section 645 election will be made obtains a TIN upon the death of the decedent as required by § 301.6109-1(a)(3) of these final regulations and furnishes this TIN to the payors of the trust. The trustee uses this TIN to file Forms 1041 as an estate during the election period. If a section 645 election will be made for a QRT, the trustee of the QRT is not required to file a Form 1041 for the short taxable year beginning with the decedent's date of death and ending December 31 of that year.

Regardless of whether or not there is an executor, the final regulations retain the requirement that a Form 1041 (including the items of income, deduction, and credit of the QRT) must be filed for the short taxable year of the QRT beginning with the decedent's date of death if a section 645 election will not be made for the trust, or if the trustee and the executor are uncertain whether a section 645 election will be made for the QRT by the due date of the Form 1041 for the short taxable year of the QRT beginning after the decedent's death and ending December 31 of that year.

The proposed regulations provide that, during the election period, if there is an executor, one Form 1041 is filed annually for the combined electing trust and related estate under the name and TIN of the related estate. Information regarding the electing trust is also reported on the Form 1041 as required by the instructions to the Form 1041.

The proposed regulations provide that the electing trust and related estate are treated as separate shares under section 663(c) for purposes of computing distributable net income (DNI) and applying the distribution provisions of sections 661 and 662. The proposed regulations also provide rules for adjusting the DNI of the separate shares with respect to distributions made from one share to another share of the combined electing trust and related estate to which sections 661 and 662 would apply had the distribution been made to a beneficiary other than another share. Under the proposed regulations, the share making the distribution reduces its DNI by the amount of the distribution deduction that it would have been entitled to under section 661 had the distribution been made to a beneficiary other than another share of the combined related estate and electing trust, and, solely for purposes of calculating its DNI, the share receiving the distribution increases its gross income by this amount. One commentator noted that, if the amount distributed from one share to another share includes an item of DNI that is not included in the gross income of the combined electing trust and related estate, this provision in the proposed regulations does not produce an appropriate result because of the operation of section 661(c). Accordingly, the final regulations are revised to provide that the share making the distribution reduces its DNI by the amount of the distribution deduction it would be entitled to under section 661 (determined without regard to section 661(c)), and solely for purposes of calculating DNI, the share receiving the distribution increases its gross income by the same amount.

Commentators requested clarification regarding whether an electing trust will be treated as an estate or a trust for purposes of the rules under section 401(a)(9). Final regulations (TD 8987) under sections 401, 403, and 408 were published in the Federal Register (67 FR 18988) on April 17, 2002. The preamble to those final regulations provides that an electing trust will not fail to be a trust for purposes of section 401(a)(9) merely because the trust elects to be treated as an estate under section 645, as long as the trust continues to be a trust under state law.

Another commentator asked for clarification regarding whether the exception for estates under section 6654(l)(2) with respect to the payment of estimated income tax applies to an electing trust. The final regulations clarify that each electing trust and related estate, if any, is treated as a separate taxpayer for all purposes of Subtitle F of the Code, including, without limitation, the application of section 6654. The final regulations provide, however, that the provisions of section 6654(l)(2)(A) relating to the 2 year exception to an estate's obligation to make estimated tax payments will apply to each electing trust for which a section 645 election has been made.

The proposed regulations provide that the election period terminates on the day before the applicable date. One commentator suggested that section 645(a) should be interpreted as terminating the election period on the last day of the taxable year ending before the applicable date. Another commentator commended the interpretation taken by the proposed regulations because, if the estate is required to file a Form 706, “United States Estate (and Generation Skipping Transfer) Tax Return,” and the election terminates on the last day of the taxable year ending before the applicable date, the election period could terminate prior to the date of final determination of liability for the estate tax, rather than six months after that date. The final regulations continue to provide that the election terminates the day before the applicable date.

If a Form 706 is required to be filed, the proposed regulations provide that the applicable date is the day that is 6 months after the date of final determination of liability for the estate tax. In response to comments, the final regulations provide that the applicable date is the day that is the later of 2 years after the date of the decedent's death or 6 months after the date of final determination of liability for estate tax.

The proposed regulations provide that the date of final determination of liability for the estate tax is the day on which the first of a series of events has occurred. One of the events is the issuance of an estate tax closing letter, unless a claim for refund with respect to the estate tax is filed within six months after the issuance of the letter. Two commentators requested that the issuance of a closing letter be removed from the list of events that can be considered the date of final determination of liability. These commentators contended that the closing letter is not a final determination of liability because the IRS may impose additional estate tax after a closing letter has been issued.

The IRS and the Treasury Department note that the circumstances in which the IRS may impose additional estate tax after a closing letter is issued are very limited. See Rev. Proc. 94-68 (1994-2 C.B. 803). In many cases, the issuance of a closing letter is sufficient to permit the closing of the probate estate and to complete any administration of the electing trust that was necessitated by the decedent's death. The IRS and the Treasury Department believe that eliminating the closing letter from the list of events that are considered a final determination of liability may encourage unduly prolonging the administration of the electing trust and related estate in order to prolong the section 645 election period. While the final regulations retain the issuance of the closing letter as one of the triggers for the date of the final determination of liability, the final regulations have been changed to provide a minimum election period of two years for all electing trusts and related estates, as well as to provide that if the issuance of the closing letter triggers the date of the final determination of liability, the date of the final determination of liability is the date that is 6 months after the date the closing letter is issued, rather than the date the closing letter is issued as provided in the proposed regulations.

Proposed § 1.641(b)-3 provides that, if an estate has joined in making a valid section 645 election, the estate shall not terminate for federal tax purposes prior to the termination of the section 645 election period. Some interpreted proposed § 1.641(b)-3 as requiring the filing of Forms 1041 for the estate until the applicable date even if, prior to that date, the electing trust and the related estate had been completely administered and the assets of the trust and the estate completely distributed. In response, the final regulations provide that the election period terminates on the earlier of the day on which both the electing trust and related estate, if any, have distributed all of their assets, or the day before the applicable date. The final regulations continue to provide that the election does not apply to successor trusts (trusts which are distributees under the trust instrument).

The proposed regulations provide that, if the executor of the related estate is not appointed until after the trustee has made a section 645 election, the section 645 election period will terminate if the later appointed executor refuses to agree to the election. One commentator objected to the termination of the election as a result of the refusal to agree to the election by the later appointed executor. This commentator suggested that the election period should continue after the appointment of the executor and that the person seeking appointment as an executor could either accept or not accept appointment as an executor given the responsibilities of the previously made section 645 election. The IRS and the Treasury Department believe that the later appointed executor must consent to the section 645 election for the election to be valid with respect to the related estate. Accordingly, the final regulations provide that, for the election period to continue, a new election form must be filed by the trustee and the newly appointed executor within 90 days of the executor's appointment. Otherwise the election period terminates the day before the appointment of the executor.

At the close of the last day of the election period, the combined electing trust and related estate, if there is an executor, or the electing trust, if there is no executor, is deemed to distribute all the assets and liabilities of the share (or shares) comprising the electing trust to a new trust in a distribution to which sections 661 and 662 apply. Thus, the combined electing trust and related estate, or the electing trust, as appropriate, is entitled to a distribution deduction to the extent permitted under section 661 in the taxable year in which the election period terminates as a result of the deemed distribution. The new trust must include the amount of the deemed distribution in gross income to the extent required under section 662.

One commentator questioned whether the net capital gains attributable to the electing trust should be included in the sections 661 and 662 calculations for the deemed distribution of the electing trust to a new trust upon the termination of the election period. The final regulations clarify that the net capital gains attributable to the electing trust are includible in the DNI of the share (or shares) comprising the electing trust for the purpose of applying sections 661 and 662 to the deemed distribution to the new trust.

If there is an executor and the electing trust terminates on or before the termination of the section 645 election period, the trustee must file a final Form 1041 under the name and TIN of the electing trust to notify the IRS that the trust no longer exists. This Form 1041 will not include any of the trust's items of income, deduction, and credit because those items will be included on the Form 1041 filed for the combined electing trust and related estate.

If there is an executor, the trustee may not need to obtain a TIN for the new trust deemed to have been created upon the termination of the election period. The trustee must consult the instructions to the Form 1041 upon the termination of the election period to determine if a new TIN must be obtained. If a new TIN is not required to be obtained, the trustee must file Forms 1041 for the new trust under the TIN obtained by the trustee under § 301.6109-1(a)(3) for the QRT following the death of the decedent. If there is no executor, the trustee must obtain a TIN for the new trust deemed to have been created upon the termination of the election period. If a new TIN is required under the regulations or the instructions to the Form 1041, the trustee must file Forms W-9 with the payors of the trust to provide them with the TIN to be used following the termination of the election period.

The final regulations provide that election procedures in paragraph (c), the rules in paragraph (d) regarding obtaining a TIN for the electing trust and QRT, the rules in paragraph (f) regarding the duration of the election period, and paragraph (g) regarding the later appointed executor are effective for estates and trusts of decedents dying on or after December 24, 2002. The final regulations provide that the rules in paragraph (e), regarding the tax treatment and general filing requirements of the electing trust and the related estate, if any, during the election period, and the rules in paragraph (h) regarding the tax treatment of the electing trust and related estate, if any, upon termination of the election period are effective for taxable years ending on or after December 24, 2002. Estates and trusts of decedents dying before December 24, 2002 may follow the election procedures provided in the proposed regulations or Rev. Proc. 98-13. With respect to obtaining a TIN for a QRT and filing a Form 1041 for the short taxable year beginning with the decedent's death and ending December 31 of that year, estates and trusts of decedents dying before December 24, 2002 may follow the procedures in these final regulations, the proposed regulations, or Rev. Proc. 98-13.

The proposed regulations amend § 1.671-4 to clarify that a trust, or portion of a trust, reports under § 1.671-4 for the taxable year that ends with the death of the grantor or other person (decedent) treated as the owner of the trust. If the trust was filing a Form 1041 under § 1.671-4(a) during the life of the decedent, the due date of the Form 1041 for the taxable year ending with the decedent's death is specified in § 1.6072-1(a)(2). Proposed § 1.6072-1(a)(2) provides that the due date for the Form 1041 for the taxable year ending with the death of the decedent is the fifteenth day of the fourth month following the close of the 12-month period which began with the first day of such fractional part of the year. The final regulations under § 1.6072-1(a)(2) are revised to provide that the due date for the Form 1041 filed for the taxable year ending with the decedent's death is the fifteenth day of the fourth month following the close of the 12-month period that began with the first day of the decedent's last taxable year.

Section 301.6109-1(a)(3) of the proposed regulations provides that a trust, all of which was treated as owned by the decedent, must obtain a new TIN upon the death of the decedent, if the trust will continue after the decedent's death. One commentator asked if this provision is intended to apply to an “administrative trust.” Section 1.641(b)-3 recognizes that a trust does not automatically terminate upon the happening of the event by which the duration of the trust is measured. A reasonable period of time is permitted after such event for the trustee to perform the duties necessary to complete the administration of the trust. Section 301.6109-1(a)(3) is intended to clarify that a trust must obtain a new TIN after the death of the decedent, if a trust that was treated as owned by the decedent during the decedent's life will continue for a period of time following the death of the decedent to allow a winding up of the affairs of the trust following the death of the decedent.

For administrative convenience, the proposed regulations provide that if a decedent and others are treated as the owners of a trust and following the decedent's death the decedent's portion remains in the trust, the trust continues to report under the TIN used by the trust prior to the death of the decedent. Commentators found this provision confusing and asked for clarification. The final regulations clarify that this provision applies to a trust that has multiple grantors (or other persons treated as the owners) that must report under § 1.671-4(a) after the death of the decedent because, although a portion of the trust continues to be treated as owned by a grantor or another person, the decedent's portion of the trust is no longer treated as owned by the decedent upon his death. The final regulations provide an example of a situation in which this provision applies.

The following publications are obsolete as of December 24, 2002:

It has been determined that this Treasury decision is not a significant regulatory action as defined in Executive Order 12866. Therefore, a regulatory assessment is not required. It has been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. chapter 5) does not apply and because this rule does not impose a collection of information on small entities, the Regulatory Flexibility Act (5 U.S.C. chapter 6) does not apply to these regulations, and therefore, a Regulatory Flexibility Analysis is not required. Pursuant to section 7805(f) of the Code, the notice of proposed rulemaking preceding these regulations was submitted to the Small Business Administration for comment on their impact on small business.

The principal author of these regulations is Faith Colson, Office of Associate Chief Counsel (Passthroughs and Special Industries). However, other personnel from the IRS and Treasury Department participated in their development.

On September 26, 2002, FinCEN published a final rule (67 FR 60562) implementing sections 313(a) and 319(b) of the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism (USA PATRIOT Act) Act of 2001 (the Act). Section 313(a) of the Act added subsection (j) to 31 U.S.C. 5318, which prohibits a “covered financial institution” from providing “correspondent accounts” in the United States to foreign banks that do not have a physical presence in any country (foreign shell banks). Section 313(a) also requires those financial institutions to take reasonable steps to ensure that correspondent accounts provided to foreign banks are not being used to provide banking services indirectly to foreign shell banks. Section 319(b) of the Act added subsection (k) to 31 U.S.C. 5318, which requires any covered financial institution that provides a correspondent account to a foreign bank to maintain records of the foreign bank's owners and to maintain the name and address of an agent in the United States designated to accept service of legal process for the foreign bank for records regarding the correspondent account.

The September 26, 2002, final rule provided that a covered financial institution could satisfy the requirements of section 313(a) and 319(b) by obtaining from a foreign bank a certification that contained the necessary information, or by otherwise obtaining documentation of the required information. With respect to correspondent accounts that existed on October 28, 2002, the final rule required a covered financial institution to close a correspondent account, within a commercially reasonable time, if the covered financial institution did not receive the certification from the foreign bank, or otherwise obtain documentation of the required information, on or before December 26, 2002.

A significant number of covered financial institutions, principally in the securities industry, have noted that the December 26, 2002, deadline to obtain the required information is proving to be inadequate. Many securities firms indicated that providing an effective explanation of their duties under the Act to a wide variety of foreign banks, which may speak different languages and operate in different ways than their U.S. counterparts, has, in some cases, lengthened the process. Moreover, the broad definition of a correspondent account found in the final rule has increased the number of accounts subject to these requirements and, consequently, has increased the burden on U.S. banks and broker-dealers to secure the required information. Finally, because the Act has generally increased the overall level of regulatory requirements for securities firms and depository institutions, they have been managing an increased overall workload as a result of additional regulations, within a finite set of resources. For these reasons, the process of gathering the necessary information to comply with section 313(a) and 319(b) of the Act is taking longer than the time provided in the September 28 final rule.

This rule extends the time by which a covered financial institution must obtain the information required to satisfy the requirements of sections 313(a) and 319(b) from December 26, 2002, to March 31, 2003. Treasury and FinCEN do not anticipate granting a further extension beyond March 31 and expect that covered financial institutions will comply with the September 26, 2002, final rule with respect to correspondent accounts established for foreign banks that have not provided the required information by that date.

Because this rule extends the time by which a covered financial institution must obtain the information necessary to satisfy the requirements of section 313(a) and 319(b) of the Act before taking actions to terminate a correspondent account, it has been determined that notice and public procedure are unnecessary pursuant to 5 U.S.C. 553 (b)(B) and that a delayed effective date is not required pursuant to 5 U.S.C. 553(d)(1).

It has been determined that this rule is not a significant regulatory action for purposes of Executive Order 12866. Because no notice of proposed rulemaking is required, the provisions of the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ) do not apply.

For the reasons set forth in the preamble, 31 CFR part 103 is amended as follows:

We are amending the offering regulations for United States Savings Bonds of Series HH. Effective January 1, 2003, the investment yield for Series HH savings bonds that are issued or enter into an extended maturity period on or after January 1, 2003, will be set by announcement by the Secretary or the Secretary's designee. We are also removing the table at the end of the offering regulations, since the information contained in the table will change with each announcement of change in the investment yield.

Currently, the investment yield must be changed by an amendment to the regulations.

The purpose of permitting the investment yield to be set by announcement is to provide greater flexibility for the Secretary in responding to market conditions and prevailing interest rates.

This final rule does not meet the criteria for a “significant regulatory action” as defined in Executive Order 12866. Therefore, the regulatory review procedures contained therein do not apply.

This final rule relates to matters of public contract and procedures for United States securities. The notice and public procedures requirements and delayed effective date requirements of the Administrative Procedure Act are inapplicable, pursuant to 5 U.S.C. 553(a)(2).

As no notice of proposed rulemaking is required, the Regulatory Flexibility Act (5 U.S.C. 601, et seq. ) does not apply.

We ask for no new collections of information in this final rule. Therefore, the Paperwork Reduction Act (44 U.S.C. 3507) does not apply.

We did not publish a notice of proposed rulemaking (NPRM) for this regulation. Under 5 U.S.C. 553(b)(B), the Coast Guard finds that good cause exists for not publishing an NPRM, and under 5 U.S.C. 553(d)(3), good cause exists for making this rule effective less than 30 days after publication in the Federal Register . The permit application was not received in time to publish an NPRM followed by a final rule before the necessary effective date. Delaying this rule would be contrary to the public interest of ensuring the safety of spectators and vessels during this event and immediate action is necessary to prevent possible loss of life or property. The Coast Guard has not received any complaints or negative comments with regard to this event.

This temporary safety zone is necessary to ensure the safety of vessels and spectators from hazards associated with a fireworks display. Based on recent accidents that have occurred in other Captain of the Port zones, and the explosive hazard of fireworks, the Captain of the Port Chicago has determined firework launches in close proximity to watercraft pose significant risks to public safety and property. The likely combination of large numbers of recreational vessels, congested waterways, darkness punctuated by bright flashes of light, alcohol use, and debris falling into the water could easily result in serious injuries or fatalities. Establishing a safety zone to control vessel movement around the location of the launch platforms will help ensure the safety of persons and property at these events and help minimize the associated risks.

The safety zone will encompass the waters of Lake Michigan within the arc of a circle with a 1400-foot radius from the fireworks launch site in Monroe Street Harbor with its center in the approximate position 41°52′41″ N, 087°36′37″ W. Entry into, transit through or anchoring within this safety zone is prohibited unless authorized by the Captain of the Port, Chicago or his designated on-scene representative. The designated on-scene representative may be contacted on VHF/FM Marine Channel 16. All geographic coordinates are North American Datum of 1983 (NAD 83).

This rule is not a “significant regulatory action” under section 3(f) of Executive Order 12866, Regulatory Planning and Review, 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 10e of the regulatory policies and procedures of DOT is unnecessary.

Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered whether this rule would have a significant economic impact on a substantial number of small entities. The term “small entities” comprises small businesses, 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.

This regulation will not have a significant economic impact for the following reasons. The regulation is only in effect for less then one hour. The designated area is being established to allow for maximum use of the waterway for vessels to enjoy the fireworks display in a safe manner. In addition, commercial vessels transiting the area can transit around the safety zone. The Coast Guard will inform the public that the regulation is in effect via a Broadcast Notice to Mariners.

Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we offer to assist small entities in understanding the rule so that they can better evaluate its effects on them and participate in the rulemaking process. 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 under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

We have analyzed this rule under Executive Order 13132, Federalism, 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) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.

This rule will not affect a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.

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

The Coast Guard has analyzed this rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and does not create an environmental risk to health or risk to safety that may disproportionately affect children.

We have considered the environmental impact of this rule and concluded that under figure 2-1, paragraph 34(g), of Commandant Instruction M16475.lD, this rule is categorically excluded from further environmental documentation. A written categorical exclusion determination is available in the docket for inspection or copying where indicated under ADDRESSES.

We have analyzed this rule under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. We have determined that it is not a “significant energy action” under that Order because it is not a “significant regulatory action” under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. It has not been designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action. Therefore, it does not require a Statement of Energy Effects under Executive Order 13211.

This rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.

This is a synopsis of the Commission's Report and Order in MM Docket No. 01-215, MM Docket No. 01-252, MM Docket No. 01-212, MM Docket No. 01-210, MM Docket No. 01-214, MM Docket No. 01-304, and MM Docket No. 01-305 adopted December 4, 2002, and released December 9, 2002. The full text of this Commission decision is available for inspection and copying during normal business hours in the FCC Reference Information Center at Portals II, 445 12th Street, SW, Room CY-A257, Washington, DC, 20554. The document may also be purchased from the Commission's duplicating contractor, Qualex International, Portals II, 445 12th Street, SW., Room CY-B402, Washington, DC, 20554, telephone 202 863-2893, facsimile 202 863-2898, or via e-mail qualexint@aol.com .

The Commission, at the request of Big Country Radio, Inc. and Jeraldine Anderson, allots Channel 259A at Sparkman, Arkansas, as the community's first local aural transmission service. See 66 FR 47433 (September 12, 2001). Channel 259A can be allotted at Sparkman in compliance with the Commission's minimum distance separation requirements with no site restrictions. The coordinates for Channel 259A at Sparkman are 33-55-00 North Latitude and 92-50-53 West Longitude.

The Commission, at the request of Charles Crawford, allots Channel 223A at Moberly, Missouri, as the community's sixth local aural transmission service. See 66 FR 50602 (October 4, 2001). Channel 223A can be allotted to Moberly in compliance with the Commission's minimum distance separation requirements with no site restrictions. The coordinates for Channel 223A at Moberly are 39-25-06 North Latitude and 92-26-17 West Longitude.

The Commission, at the request of Maurice Salsa, allots Channel 254A at Kiowa, Oklahoma, as the community's first local aural transmission service. See 66 FR 47433 (September 12, 2001). Channel 254A can be allotted to Kiowa in compliance with the Commission's minimum distance separation requirements with a site restriction of 7.1 kilometers (4.4 miles) west of Kiowa. The coordinates for Channel 254A at Kiowa are 34-42-23 North Latitude and 95-58-48 West Longitude.

The Commission, at the request of Katherine Pyeatt in MM Docket No. 01-210, dismisses her petition for rule making requesting the allotment of Channel 293C3 at Crowell, Texas.

The Commission, at the request of Katherine Pyeatt, allots Channel 242A at Menard, Texas, as the community's second local aural transmission service. See 66 FR 47433 (September 12, 2001). Channel 242A can be allotted to Menard in compliance with the Commission's minimum distance separation requirements with a site restriction of 11.8 kilometers (7.3 miles) northwest of Menard. The coordinates for Channel 242A at Menard are 30-59-47 North Latitude and 99-52-06 West Longitude.

The Commission, at the request of Jeraldine Anderson, allots Channel 287C3 at Menard, Texas, as the community's third local aural transmission service. See 66 FR 54971 (October 31, 2001). Channel 287C3 can be allotted to Menard in compliance with the Commission's minimum distance separation requirements with a site restriction of 11.9 kilometers (7.4 miles) southwest of Menard. The coordinates for Channel 287C3 at Menard are 30-52-29 North Latitude and 99-54-00 West Longitude.

The Commission, at the request of Jeraldine Anderson, allots Channel 247A at San Isidro, Texas, as that community's first local aural transmission service. See 66 FR 54971 (October 31, 2001). Channel 247A can be allotted to San Isidro in compliance with the Commission's minimum distance separation requirements with a site restriction of 4.2 kilometers (2.6 miles) northeast of San Isidro. The coordinates for Channel 247A at San Isidro are 26-45-00 North Latitude and 98-26-00 West Longitude.

1. This is a synopsis of the Media Bureau's Order granting an extension of time for filing comments and reply comments in Review of the Commission's Broadcast and Cable Equal Employment Opportunity Rules and Policies , DA 02-3525, released December 19, 2002.

2. On November 20, 2002, the Commission released a Third Notice of Proposed Rule Making , MM Docket No. 98-204, FCC 02-303, 67 FR 77373 (December 17, 2002) ( Third NPRM ) requesting comments on the appropriate treatment of part-time employees under the Commission's Equal Employment Opportunity rules. Deadlines for comments and reply comments were December 20, 2002, and January 6, 2003, respectively. Notice of the new rulemaking proceeding was not, however, published in the Federal Register until December 17, 2002. In order to ensure that all parties have adequate notice of the rulemaking, the Bureau is extending these deadlines until January 16, 2003, for comments and February 3, 2003, for reply comments.

3. Accordingly, it is Ordered that the date for filing comments and reply comments in this proceeding is Extended to January 16, 2003, and February 3, 2003, respectively.

4. This action is taken pursuant to authority found in sections 4(i) and 303(r) of the Communications Act of 1934, as amended, 47 U.S.C. 4(i) and 303(r), and §§ 0.204(b), 0.283 and 1.46 of the Commission's rules, 47 CFR 0.204(b), 0.283 and 1.46.

Operators of gas, hazardous liquid, and carbon dioxide pipelines and operators of liquefied natural gas facilities must annually submit Management Information System (MIS) reports of drug testing done in the previous calendar year (49 CFR 199.119(a)). One of the uses of this information is to calculate the minimum annual percentage rate at which operators must randomly select covered employees for drug testing during the next calendar year (49 CFR 199.105(c)(2)). If the minimum annual percentage rate for random drug testing is 50 percent, we may lower the rate to 25 percent if we determine that the positive rate reported for random tests for two consecutive calendar years is less than 1.0 percent (49 CFR 199.105(c)(3)). If the minimum annual percentage rate is 25 percent, we will increase the rate to 50 percent if we determine that the positive rate reported for random tests for any calendar year is equal to or greater than 1.0 percent (49 CFR 199.105(c)(4)). Part 199 defines “positive rate” as “the number of positive results for random drug tests * * * plus the number of refusals of random tests * * *, divided by the total number of random drug tests * * * plus the number of refusals of random tests. * * *”

Through calendar year 1996, the minimum annual percentage rate for random drug testing in the pipeline industry was 50 percent of covered employees. Based on MIS reports of random testing done in 1994 and 1995, we lowered the minimum rate from 50 to 25 percent for calendar year 1997 (61 FR 60206; November 27, 1996). The minimum rate remained at 25 percent in calendar years 1998 (62 FR 59297; Nov. 3, 1997); 1999 (63 FR 58324; Oct. 30, 1998); 2000 (64 FR 66788; Nov. 30, 1999); 2001 (65 FR 81409; Dec. 26, 2000); and 2002 (67 FR 2611; Jan. 18, 2002).

Using the MIS reports received this year for drug testing done in calendar year 2001, we calculated the positive rate of random testing to be 0.6 percent. Since the positive rate continues to be less than 1.0 percent, we are announcing that the minimum annual percentage rate for random drug testing is 25 percent of covered employees for the period January 1, 2003, through December 31, 2003.

All sea turtles that occur in U.S. waters are listed as either endangered or threatened under the Endangered Species Act (ESA). The loggerhead ( Caretta caretta ) is listed as threatened. Under the ESA and its implementing regulations (50 CFR 223.205), taking threatened sea turtles, even incidentally, is prohibited, with exceptions identified in 50 CFR 223.206. The incidental take of threatened species may only be legally authorized by an incidental take statement in a biological opinion issued pursuant to section 7 of the ESA, an incidental take permit issued pursuant to section 10 of the ESA, or regulations under section 4(d) of the ESA. In order for an incidental take statement to be issued, the incidental take must be not likely to jeopardize the continued existence of listed species or destroy or adversely modify designated critical habitat.

On October 24, 2000 (65 FR 64670, October 30, 2000), NMFS issued a permit, for a period of 3 years, to authorize the incidental, but not intentional, taking of four stocks of threatened or endangered marine mammals (Fin whale, California/Oregon/Washington stock; Humpback whale, California/Oregon/Washington-Mexico stock; Steller sea lion, eastern stock; and Sperm whale, California/Oregon/Washington stock) by the CA/OR drift gillnet fishery under section 101(a)(5)(E) of the Marine Mammal Protection Act (MMPA) (16 U.S.C. 1371(a)(5)(E)).

To authorize this incidental take of marine mammals listed under the ESA, NMFS completed a formal consultation as required by section 7 of the ESA. This consultation also included an analysis of the effects of the CA/OR drift gillnet fishery on loggerhead turtles. On October 23, 2000, NMFS issued a BO in which it determined that the then current operations of the CA/OR drift gillnet fishery were likely to jeopardize the continued existence of loggerhead turtles.

To avoid the likelihood of the CA/OR drift gillnet fishery jeopardizing the continued existence of loggerhead turtles, NMFS developed a Reasonable and Prudent Alternative (RPA) in the BO that consists of prohibiting CA/OR drift gillnet vessels from fishing in U.S. waters off southern California, south of Point Conception (34°27′ N.) and west to the 120°W., from August 15 through August 31, and January 1 through January 31, during a forecasted, or occurring, El Nino event. On September 20, 2002, NMFS published a proposed rule (67 FR 59243) to implement this RPA to protect loggerhead turtles.

Using the sea surface temperature anomaly charts available on the NOAA Coastwatch West Coast Regional Node web page at http://cwatchwc.ucsd.edu/ and observer data on loggerhead turtle entanglements, NMFS has developed criteria for determining whether El Nino conditions are present along southern California for the purpose of implementing the time and area closure identified in the October 2000 BO. Under the criteria, NMFS uses the monthly sea surface temperature anomaly charts to determine whether there are warmer than normal sea surface temperatures present off of southern California during the months prior to August or January for years in which an El Nino event has been declared by the NOAA Climate Prediction Center. “Normal sea surface temperatures” is the average of the monthly mean sea surface temperatures for 1950-97.

All loggerhead turtles observed entangled in the CA/OR drift gillnet fishery during El Nino events were entangled during months in which the sea surface temperatures ranged from approximately 60°F to 72°F (15.6°C to 22.2°C) and sea surface temperatures differed from the average by approximately 0°F to +4°F (0°C to +2.2°C). The sea surface temperature during the month preceding each observed loggerhead entanglement was either greater than normal or equal to the normal sea surface temperature. The sea surface temperature during the third month and second month prior to each entanglement during an El Nino event was always greater than the normal sea surface temperature for that month. NMFS believes this is because warmer sea surface temperatures are necessary for loggerhead turtles to move into the area. There have been no observed entanglements in this fishery in which any one of the preceding 3 months were colder than normal.

Based on this information, the need to allow sufficient lead time to publish a notice in the Federal Register announcing El Nino conditions prior to the start date of the closure, and the fact that the sea surface temperature charts for a recently completed given month are not available until the following month, NMFS is using sea surface temperature data from the third and second months prior to the month of the closure for determining whether El Nino conditions are present off of southern California. For example, NMFS evaluates sea surface temperatures for October and November to determine whether El Nino conditions in January will trigger a closure to conserve loggerhead turtles. Specifically, if an El Nino has been declared for equatorial waters and the sea surface temperatures off southern California during this 2-month time period are greater than normal, NMFS will publish a Federal Register notice with the determination that El Nino conditions are forecast off of southern California for the purpose of implementing the time and area closure to protect loggerhead turtles. If the sea surface temperatures are normal or below normal and the Assistant Administrator has previously published a Federal Register notice indicating that El Nino conditions are present off southern California, the Assistant Administrator will publish an additional Federal Register notice indicating that El Nino conditions are no longer present for purposes of implementing the closure.

On December 12, 2002, NOAA Climate Prediction Center issued an updated El Nino report which indicated that sea surface temperature anomalies increased in equatorial waters. However, sea surface temperatures off of southern California are not expected to attain positive sea surface temperature anomalies until early Spring 2003. Using the criteria set forth above, NMFS has determined that El Nino conditions are not present for purposes of implementing the time and area closure for January 2003. This determination is based on the October and November monthly sea surface temperature anomaly charts which show ocean waters off southern California were -2° and -1°F (-1.1°C and -0.6°C) below normal respectively. Based on these data, the conditions do not meet the criteria that the preceding second and third month sea surface temperatures prior to the month of January are greater than normal. Therefore, the U.S. waters off southern California, south of Point Conception (34°27′ N.) and west to the 120°W., will remain open to drift gillnet fishing between January 1 through January 31, 2003.

In response to a recommendation by the Pacific Offshore Cetacean Take Reduction Team (TRT), NMFS conducted a preliminary review of observer data to determine whether an alternate closure in June, July, and August would offer the same or better protection than the closure during January 1 through 31 and August 15 through 31. NMFS reviewed observer data from the two most recent El Nino events (1992/1993 and 1997/1998). Using this information, NMFS reviewed the number of observed entanglements of loggerhead turtles that occurred during the months of January, June, July, and August, and calculated the average interaction rate for each of these months. By averaging the most recent 3 years of fishing effort (1999-2001), NMFS estimated future monthly effort in the fishery and calculated preliminary estimates of loggerhead turtle entanglements by month. Based on limited observer data, preliminary analysis indicates that a closure in June, July, and August may provide the same or better protection for loggerhead turtles. The loggerhead turtle interaction rate is higher during the summer months than in January, but fishing effort is low during the summer months. Also, observer data during the summer months is limited. NMFS is continuing to evaluate this alternate closure and is soliciting comment on this management regime.

NMFS received five letters on the proposed rule. Three were in support of the time and area closure and two were opposed to the time and area closure. In addition, NMFS received comments from the TRT at its May 2002 meeting.

Comment 1: One commenter requested that NMFS require fleet-wide satellite vessel monitoring systems as part of the final rule to enforce area closures.

Response: Requiring vessels to install vessel monitoring systems was not part of the proposed action or a term and condition of the incidental take statement or RPA. At this time, based on 20 percent observer coverage, California Department of Fish and Game logbook data, review of fish landing tickets, and the cooperation of the U.S. Coast Guard, NMFS does not believe vessel monitoring systems will be necessary to successfully enforce these closures.

Comment 2: One commenter requested that NMFS continue its observer program at 20 percent and to continue its support for ongoing research on the distribution of sea turtles in the Pacific Ocean to determine which habitats and migratory routes these species use.

Response: NMFS intends to continue monitoring the CA/OR drift gillnet fishery targeting swordfish and thresher shark at 20 percent observer coverage and continue its support for research on the distribution of sea turtles in the Pacific to determine which habitats and migratory routes they use.

Comment 3: One commenter felt that NMFS' use of 3,000 sets as an estimate of annual fishing effort in the October 2000 BO was unrealistically high.

Response: At the time the BO was prepared, 3,000 sets was a reasonable estimate to predict future fishing effort based on a 3-year average using 1997, 1998, and 1999 data. NMFS is aware that fishing effort has continued to decline. Based on fishing effort estimates prepared by California Department of Fish and Game, the annual number of sets for 2000 and 2001 was 1,936 and 1,482 respectively. For the next consultation on the fishery, NMFS will use updated estimates to predict future fishing effort.

Comment 4: One commenter suggested moving the northern boundary of the closed area to 32°45′ N. and the western boundary to 119°30W.

Response: Although there have been no observed loggerhead turtles taken in ocean waters north of 32°45′ N. during El Nino events or west of 119°30′ W., this does not mean that loggerhead turtles are not present in this area. Specifically, during El Nino events, NMFS has limited observer data for this area, with only 77 observed sets in the area east of 120°W. and north of 32°45′ N. and 14 sets between 120°W. and 119°30W. south of 32°45′ N. Therefore, the lack of an observed take in this area may be the result of fewer observations in this area during the summer months of El Nino events. Based on the limited data, NMFS believes the proposed boundaries are not unnecessarily broad.

Comment 5: One commenter indicated that the time and area closure does not address the incidental take of loggerhead turtles outside of El Nino events.

Response: Although one loggerhead turtle was observed taken outside of an El Nino event, NMFS believes this event was an exception and a random event which is not representative of future anticipated takes. Specifically, the animal was taken during a month in which the sea surface temperature was -2°F (-1.1°C) cooler than normal.

Comment 6: One commenter expressed concern that the regulations to implement the time and area closure to protect loggerhead turtles were not implemented by August 2001, as recommended in the BO.

Response: As explained in previous Federal Register notices (66 FR 44549, August 24, 2001; 67 FR 59245, September 20, 2002), the regulations to implement the loggerhead time and area closure need to be in place if El Nino conditions are predicted or are occurring during the month of January or between August 15 and August 31 off the coast of California where loggerhead interactions with the CA/OR drift gillnet fishery have been documented. However, sea surface temperatures off of southern California are not expected to attain positive sea surface temperature anomalies until early Spring 2003.

Comment 7: One commenter recommended that the CA/OR drift gillnet fishery be managed using an ecosystem approach rather than a piecemeal approach, like NMFS' actions to date.

Response: Although the CA/OR drift gillnet fishery is managed primarily by the State of California, NMFS has implemented regulations under section 118 of the MMPA to reduce the incidental mortality and serious injury of strategic marine mammal stocks based upon the recommendations from the TRT. In addition, NMFS has implemented regulations under the ESA to address the incidental take of listed marine mammal and sea turtle species. In the future, the fishery might be regulated by NMFS under the Highly Migratory Species Fishery Management Plan that has been adopted by the Pacific Regional Fishery Management Council (but has not yet been submitted to, or approved by, NMFS).

Comment 8: One commenter requested that NMFS analyze the potential take of listed species such as the blue whale, Guadalupe fur seal, right whale, and sei whale, which are likely to occur inside the area where the fishery operates, although there have been no observed takes of these species in the CA/OR drift gillnet fishery.

Response: In completing the analysis in the BO, NMFS used the best available information. NMFS agrees the absence of documented take does not eliminate the possibility of a future take. However, if future takes are detected, these will be addressed in subsequent biological opinions based on available data at the time.

Comment 9: One commenter requested that NMFS complete a formal rulemaking for the implementation of regulations to address the incidental take of green ( Chelonia mydas ) and olive ridley ( Lepidochelys olivacea ) turtles as well as the long-term ecosystem impacts of shark mortality associated with the CA/OR drift gillnet fishery.

Response: Since the inception of the observer program, NMFS has observed one green turtle and one olive ridley turtle interaction with the CA/OR drift gillnet fishery. Based on these two observations, NMFS is unable to complete meaningful analysis that would lead to useful regulations. The Highly Migratory Species Fishery Management Plan under development by the Pacific Regional Fishery Management Council would, if approved, allow NMFS to manage the fishery for the incidental take of shark species.

Comment 10: One commenter requested that NMFS provide a more meaningful definition of El Nino conditions by focusing on the conditions that need to be present in order for an El Nino to be declared for purposes of implementing the time and area closure.

Response: NMFS developed criteria outlined in the supplementary information section of this interim final rule.

Comment 11: One commenter indicated that the standard used to determine whether El Nino conditions are present in the waters off southern California should include the presence of prey which may affect the migratory patterns of loggerhead turtles in addition to sea surface temperatures.

Response: NMFS does not have sufficient real-time data on prey species abundance off southern California to include this parameter as a criteria for determining whether El Nino conditions are present.

Comment 12: One commenter indicated that the rule should include a periodic review of oceanic conditions to determine whether the closure to protect loggerhead turtles should be lifted if El Nino conditions are no longer present.

Response: As written, the regulatory text of this rule clearly states that the Assistant Administrator will issue a notice when El Nino conditions are no longer present. The criteria that will be used are explained in this preamble, above. To accomplish this, NMFS will conduct a periodic review of oceanic conditions.

Comment 13: One commenter proposed that the January closure be replaced with a closure of June, July and August 1 through 14 and that the northern boundary of the closed area be moved to 32°45′ N and the western boundary be moved to 119°30′ W.

Response: NMFS is considering adjusting the management regime according to this proposal although the analysis has not been completed. However, preliminary analysis on this recommendation is discussed elsewhere in the Supplementary Information section of this interim final rule. Moving the northern and western boundaries of the area closure is discussed under comment 5.

Comment 14: One commenter indicated that NMFS incorrectly calculated the effectiveness of the time and area closure in the BO because NMFS mistakenly included two loggerhead turtles inside the time and area closure when they were actually taken outside of the time and area closure. As a result, the percent reduction in loggerhead interactions with the time and area closure is reduced from 65 percent to 53 percent.

Response: NMFS agrees that there were two loggerhead turtles mistakenly reported inside the time and area closure and the correct percent reduction of the time and area closure is 53 percent.

Pacific Offshore Cetacean Take Reduction Team Recommendations

Comment 15: The TRT recommended that NMFS implement a time and area closure during the months of June, July, and August instead of August 15 through August 31, and January 1 through January 31. This recommendation was based on the number of loggerhead turtle interactions that have occurred during these months, the limited fishing effort during this time period, and the apparent higher entanglement rate.

Response: NMFS is considering this alternative. The preliminary analysis is discussed elswhere in the Supplementary Information section of this interim final rule.

Comment 16: The TRT recommended that NMFS more clearly define what constitutes El Nino conditions that trigger loggerhead restrictions. Specifically, the TRT recommended that NMFS determine if there are specific local conditions or a particular strength of an El Nino that correlate with an increased take of loggerhead turtles in the fishery.

Response: The criteria NMFS is using to determine El Nino conditions are explained in this interim final rule (see above).

Comment 17: The TRT recommended that research be conducted on the movement patterns of loggerhead sea turtles off southern California during El Nino years and their habitat preferences (including water temperature and prey). This information should also be factored into future agency decisions regarding measures for reducing mortality and entanglement of loggerhead turtles.

Response: NMFS equipped five loggerhead turtles off Baja California with satellite transmitter tags that provide location and dive data. In addition, NMFS intends to continue tagging loggerhead turtles off Baja California in subsequent years. These data will be used in future agency decisions.

Comment 18: If NMFS does not accept the TRT's recommendation to replace the January closure with a closure from June, July, and August 1 to August 14, the TRT recommends that the northern limit of the loggerhead closure area be shifted from Point Conception to 33°N. If a loggerhead entanglement occurs north of 33°N in the CA/OR drift gillnet fishery in an El Nino year, the closure area would revert to Point Conception for that January and August and for that period of subsequent El Nino years.

Response: See response to comment 4.

The regulatory text of this interim final rule is identical to the regulatory text of the proposed rule (67 FR 59243, September 20, 2002).

NMFS prepared an EA (August 13, 2001) and a supplement to the EA for this interim final rule and concluded that these regulations would have no significant impact on the human environment. In addition to the status quo and the time and area closures indentified in this interim final rule, NMFS examined several alternatives for reducing or eliminating sea turtle entanglements when developing measures to avoid the incidental take of sea turtles. NMFS searched for a strategy which would provide the most certainty in reducing or eliminating entanglements upon implementation. These strategies included: (1) reducing fishing effort through gear modifications; (2) reducing fishing effort by decreasing the number of vessels; (3) increasing survival of entangled sea turtles; (4) implementing gear modifications to reduce interactions; and (5) changing fishing practices such as shorter soak times. These alternatives were not considered further because NMFS could not be certain that singularly or together they would result in a significant reduction in the level of take and mortality of sea turtles.