Comments Invited

Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views or arguments as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. FAA-2003-15847/Airspace Docket No. 03-ASO-13.” The postcard will be date/time stamped and returned to the commenter. All communications received before the specified closing date for comments will be considered before taking action on the proposed rule. The proposal contained in this notice may be changed in light of the comments received. All comments submitted will be available for examination in the Office of the Regional Counsel for Southern Region, Room 550, 1701 Columbia Avenue, College Park, Georgia 30337, both before and after the closing date for comments. A report summarizing each substantive public contact with FAA personnel concerned with this rulemaking will be filed in the docket.

An electronic copy of this document may be downloaded through the Internet at http://dms.dot.gov. Recently published rulemaking documents can also be accessed through the FAA's Web Page at http://www.faa.gov or the Superintendent of Document's Web Page at http://www.access.gpo.gov/nara. Additionally, any person may obtain a copy of this notice by submitting a request to the Federal Aviation Administration, Office of Air Traffic Airspace Management, ATA-400, 800 Independence Avenue, SW., Washington, DC 20591, or by calling (202) 267-8783. Communications must identify both docket numbers for this notice. Persons interested in being placed on a mailing list for future NPRM's should contact the FAA's Office of Rulemaking, (202) 267-9677, to request a copy of Advisory Circular No. 11-2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.

The FAA is considering an amendment to Part 71 of the Federal Aviation Regulations (14 CFR Part 71) to amend Class E5 airspace at Maxton, NC. Class E airspace designations for airspace areas extending upward from 700 feet or more above the surface of the earth are published in Paragraph 6005 of FAA Order 7400.9K, dated August 30, 2002, and effective September 16, 2002, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document would be published subsequently in the Order.

The FAA has determined that this proposed 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, when promulgated, will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views or arguments as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “”Comments to Docket No. FAA-2003-15848/Airspace Docket No. 03-ASO-14. The postcard will be date/time stamped and returned to the commenter. All communications received before the specified closing date for comments will be considered before taking action on the proposed rule. The proposal contained in this notice may be changed in light of the comments received. All comments submitted will be available for examination in the Office of the Regional Counsel for Southern Region, Room 550, 1701 Columbia Avenue, College Park, Georgia 30337, both before and after the closing date for comments. A report summarizing each substantive public contact with FAA personnel concerned with this rulemaking will be filed in the docket.

An electronic copy of this document may be downloaded through the Internet at http://dms.dot.gov. Recently published rulemaking documents can also be accessed through the FAA's Web Page at http://www.faa.gov or the Superintendent of Document's Web Page at http://www.access.gpo.gov/nara. Additionally, any person may obtain a copy of this notice by submitting a request to the Federal Aviation Administration, Office of Air Traffic Airspace Management, ATA-400, 800 Independence Avenue, SW., Washington, DC 20591, or by calling (202) 267-8783. Communications must identify both docket numbers for this notice. Persons interested in being placed on a mailing list for future NPRM's should contact the FAA's Office of Rulemaking, (202) 267-9677, to request a copy of Advisory Circular No. 11-2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.

The FAA is considering an amendment to part 71 of the Federal Aviation Regulations (14 CFR part 71) to amend Class E5 airspace at Smithfield, NC. Class E airspace designations for airspace areas extending upward from 700 feet or more above the surface of the earth are published in Paragraph 6005 of FAA Order 7400.9K, dated August 30, 2002, and effective September 16, 2002, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document would be published subsequently in the Order.

The FAA has determined that this proposed 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, when promulgated, 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 proposes to amend 14 CFR part 71 as follows:

Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views or arguments as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. FAA-2003-15849/Airspace Docket No. 03-ASO-15.” The postcard will be date/time stamped and returned to the commenter. All communications received before the specified closing date for comments will be considered before taking action on the proposed rule. The proposal contained in this notice may be changed in light of the comments received. All comments submitted will be available for examination in the Office of the Regional Counsel for Southern Region, Room 550k, 1701 Columbia Avenue, College Park, Georgia 30337, both before and after the closing date for comments. A report summarizing each substantive public contact with FAA personnel concerned with this rulemaking will be filed in the docket.

An electronic copy of this document may be downloaded through the Internet at http://dms.dot.gov. Recently published rulemaking documents can also be accessed through the FAA's Web Page at http://www.faa.gov or the Superintendent of Document's web page at http://www.access.gpo.gov/nara. Additionally, any person may obtain a copy of this notice by submitting a request to the Federal Aviation Administration, Office of Air Traffic Airspace Management, ATA-400, 800 Independence Avenue, SW., Washington, DC 20591, or by calling (202) 267-8783. Communications must identify both docket numbers for this notice. Persons interested in being placed on a mailing list for future NPRM's should contact the FAA's Office of Rulemaking, (202) 267-9677, to request a copy of Advisory Circular No. 11-2A, Notice of Procedure Rulemaking Distribution System, which describes the application procedure.

The FAA is considering an amendment to Part 71 of the Federal Aviation Regulations (14 CFR Part 71) to amend Class E5 airspace at Rocky Mount, NC. Class E airspace designations for airspace areas extending upward from 700 feet or more above the surface of the earth are published in Paragraph 6005 of FAA Order 7400.9K, dated August 30 2002, and effective September 16, 2002, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document would be published subsequently in the Order.

The FAA has determined that this proposed 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, 2979); 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, when promulgated, 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 proposes to amend 14 CFR part 71 as follows:

Comments Invited

Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views or arguments as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. FAA-2003-15845/Airspace Docket No. 03-ASO-11.” The postcard will be date/time stamped and returned to the commenter. All communications received before the specified closing date for comments will be considered before taking action on the proposed rule. The proposal contained in this notice may be changed in light of the comments received. All comments submitted will be available for examination in the Office of the Regional Counsel for Southern Region, Room 550, 1701 Columbia Avenue, College Park, Georgia 30337, both before and after the closing date for comments. A report summarizing each substantive public contact with FAA personnel concerned with this rulemaking will be filed in the docket.

An electronic copy of this document may be downloaded through the Internet at http://dms.dot.gov. Recently published rulemaking documents can also be accessed through the FAA's web page at http://www.faa.gov or the Superintendent of Document's web page at http://www.access.gpo.gov/nara. Additionally, any person may obtain a copy of this notice by submitting a request to the Federal Aviation Administration, Office of Air Traffic Airspace Management, ATA-400, 800 Independence Avenue, SW., Washington, DC 20591, or by calling (202) 267-8783. Communications must identify both docket numbers for this notice. Persons interested in being placed on a mailing list for future NPRMs should contact the FAA's Office of Rulemaking, (202) 267-9677, to request a copy of Advisory Circular No. 11-2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.

The FAA is considering an amendment to Part 71 of the Federal Aviation Regulations (14 CFR Part 71) to amend Class E5 airspace at Raleigh, NC. Class E airspace designations for airspace areas extending upward from 700 feet of more above the surface of the earth are published in Paragraph 6005 of FAA Order 7400.9K, dated August 30, 2002, and effective September 16, 2002, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document would be published subsequently in the Order.

The FAA has determined that this proposed 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, when promulgated, 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 proposes to amend 14 CFR Part 71 as follows:

The FAA published a notice of proposed rulemaking on August 8, 2003, (68 FR 47269) and the section titled “Initial Regulatory Flexibility Analysis” was inadvertently left out. This document corrects that error.

Correction: In FR Doc. 03-20277 published on August 8, 2003 (68 FR 47269), on page 47271, in column 3, before the paragraph heading “International Trade Impact Assessment,” add the following information:

The Regulatory Flexibility Act of 1980 (RFA) establishes “as a principle of regulatory issuance that agencies shall endeavor, consistent with the objective of the rule and of applicable statutes, to fit regulatory and informational requirements to the scale of the business, organizations, and governmental jurisdictions subject to regulation.” To achieve that principle, the RFA requires agencies to solicit and consider flexible regulatory proposals and to explain the rationale for their actions. The RFA covers a wide-range of small entities, including small businesses, not-for-profit organizations and small governmental jurisdictions.

Agencies must perform a review to determine whether a proposed or final rule will have a significant economic impact on a substantial number of small entities. If the agency determines that it will, the agency must prepare a regulatory flexibility analysis as described in the RFA.

However, if an agency determines that a proposed or final rule is not expected to have a significant economic impact on a substantial number of small entities, section 605(b) of the RFA provides that the head of the agency may so certify and a regulatory flexibility analysis is not required. The certification must include a statement providing the factual basis for this determination, and the reasoning should be clear.

The FAA conducted the required review of this proposal and determined that it would have a significant economic impact on a substantial number of small entities. Accordingly, pursuant to Section 603 of the Regulatory Flexibility Act, the Federal Aviation Administration has prepared the following initial regulatory flexibility analysis.

The FAA is proposing to continue the existing safety standards in SFAR 71 without a termination date as a result of the reduction in accidents and incidents involving air tour operators in Hawaii and NTSB recommendations. The rationale for the major provisions of the NPRM are summarized below:

Safety provisions addressing the risks of beyond the shore operations. Based on an analysis of the risks of beyond the shore operations and NTSB recommendations, the FAA concludes that the benefits of these provisions justify the costs. Based on survivors' testimony, life preservers alone are insufficient in preventing loss of life in helicopter accidents over water. Without floats, helicopters sink very quickly upon impact, giving occupants little time to exit the aircraft. The FAA believes that helicopter floats, in conjunction with life preservers and pre-flight briefing on water ditching procedures, would significantly improve the chances of survival. Therefore, this proposal would require life preservers and passenger briefings for all air tours and floats for helicopters.

Provisions addressing weather. Between 1982 and 1994 there were 12 weather related accidents in Hawaii while between 1994 and 2002 there were 3 weather related accidents. This illustrates the effectiveness of the existing SFAR 71 weather related provisions and warrant their continuation.

The objective of this proposal is to continue a higher level of safety for Hawaii air tours. Under the United States Code, the FAA Administrator is required to consider the following matter, among others, as being in the public interest: assigning, maintaining, and enhancing safety and security as the highest priorities in air commerce. [See 49 U.S.C. 40101(d)(1).] Additionally, it is the FAA Administrator's statutory duty to carry out her responsibilities “in a way that best tends to reduce or eliminate the possibility or recurrence of accidents in air transportation.” [See 49 U.S.C. 44701(c).] Accordingly, this notice proposes to amend title 14 of the Code of Federal Regulations to continue the safety requirements of air tour operations in Hawaii, without a termination date.

The FAA concludes that all of the entities affected by the proposed amendments are small according to thresholds established by the Small Business Administration (i.e., employ fewer than 1,500 employees). An estimated 6 part 91 operators and 24 part 135 operators would be affected by the rule. The part 91 operators own about 11 aircraft, while the part 135 operators have about 80 aircraft. This proposed rule would impose total annualized costs per operator of approximately $99,000. According to a Small Business Administration analysis of Bureau of Census data for non-scheduled air transportation firms,1 firms with fewer than 500 employees have average revenues of $1.87 million. The estimated cost to each of these small entities is approximately 5.3 percent of the average revenue of non-scheduled air transportation firms with fewer than 500 employees based on the SBA's Census data cited.

The annualized cost for completing the performance plan and conducting the passenger briefing would impose average annualized costs per operator of approximately $43,500.

The proposed rule would not overlap, duplicate, or conflict with existing Federal rules.

Affected operators and helicopter air tour pilots have petitioned the FAA to amend SFAR 71. They argue that SFAR 71's 1500-foot minimum altitude requirement is “cumbersome and lacks flexibility in dynamic circumstances.” The petitioners also maintain that allowing air tour flights as low as 300 feet above the surface would make SFAR 71 safer in certain circumstances.

The FAA has considered the petitioners' views in formulating this proposed rule. The issues raised are similar to comments received by the agency during the three SFAR rulemaking preceding this proposed rule. The FAA concludes that 1,500 feet provides a pilot with more distance, and, thus time, to avoid an accident or to deal with an error. An altitude of 300 feet provides 80 percent less distance and thus, much less reaction time.

The FAA lacks reliable revenue and profit data on the individual entities affected by this rule, but the estimated cost to each of these small entities is approximately 5.3 percent of the average revenue of non-scheduled air transportation firms with fewer than 500 employees based on the SBA's Census data. Hawaii air tour operators have been subject to the proposed provisions of this rule since 1994. While there are fewer operators today than in 1994, the cause cannot be directly attributed to SFAR 71 but rather, the vagaries and nature of the tourism market. New air tour operators have entered the market after making the business decision to accept the provisions of this rule. The FAA invites comment on the potential impact of the proposal on revenues and profits.

The FAA estimates that none of the operators currently providing air tour flights would elect to stop providing the service. These operators have been complying with these provisions since 1994.

All Hawaiian entities in the air tour market are small. Accordingly, the costs imposed by this proposal would be borne almost entirely by small businesses. The estimated costs are proportional to the frequency of operations and thus the burden is not disproportionate. Air tour safety in Hawaii has been significantly improved, and the FAA believes that the only way to continue this is to maintain these higher standards on these entities.

The FAA has made several conservative assumptions in this analysis, which may have resulted in an overestimate of the costs of the proposal. For example, the FAA assumes that the pilot in command would conduct all pre-flight briefings but the provision only requires the pilot to “ensure that each passenger has been briefed”. The briefing could be recorded or provided by a lower paid employee. Also, the helicopter life preserver costs may be overestimated since there is a voluntary industry standard to which 13 helicopter tour operators subscribe that requires occupants to wear a personal flotation device.

The proposed regulations that are the subject of these corrections are under section 382 of the Internal Revenue Code.

As published, this notice of proposed rulemaking by cross-reference to temporary regulations and notice of public hearing contains errors that may prove to be misleading and are in need of clarification.

Accordingly, the publication of the notice of proposed rulemaking by cross-reference to temporary regulations and notice of public hearing (REG-108676-03), which is the subject of FR. Doc. 03-16230, is corrected as follows:

1. On page 38247, column 3, in the preamble, under the subject heading ADDRESSES, line 3, the language “5226, Internal Revenue Service, POB” is corrected to read “5207, Internal Revenue Service, POB”.

2. On page 38248, column 1, in the preamble, under the subject heading FOR FURTHER INFORMATION CONTACT, line 5, the language “Treena Garrett, (202) 622-7180 (not toll-” is corrected to read “Treena Garrett, (202) 622-3401 (not toll-”.

The MMS is proposing to amend the existing regulations at 30 CFR 206.100 et seq., governing the valuation of crude oil produced from Federal leases for royalty purposes, and related provisions governing the reporting thereof. The current regulations became effective on June 1, 2000. The producing industry filed a lawsuit challenging several of the provisions in the 2000 rule. Independent Petroleum Association of America v. Baca, Civil No. 00-761 (RCL) (D.D.C.), and American Petroleum Institute v. Baca, Civil No. 00-887 (RCL) (D.D.C.) (consolidated). That lawsuit is still pending.

MMS conducted four public workshops on March 4-6, 2003, in Denver, Colorado; Albuquerque, New Mexico; Houston, Texas; and Washington, DC. At those workshops, MMS asked for discussion regarding, among other things, the best published index to use in valuing production not sold at arm's length and related timing issues, greater specificity regarding allowable transportation costs, the rate of return on undepreciated capital investment in calculating actual transportation costs, and the royalty effect of sales under joint operating agreements. After considering the input from these workshops, MMS is proposing these amendments in an effort to improve the current rule.

The amendments proposed do not alter the basic structure or underlying principles of the June 2000 rule. In proposing these amendments, the Department of the Interior reaffirms that the value for royalty purposes of crude oil produced from Federal leases is value at or near the lease. But in determining value at the lease of production not sold under an arm's-length contract at the lease, MMS is not restricted to a comparison to arm's-length sales of other production occurring in the field or area. MMS may begin with a “downstream” price or value, and determine value at the lease by deducting the costs of transporting oil to downstream sales points or markets, or by making appropriate adjustments for location and quality.

Federal lessees are not obligated to sell crude oil downstream of the lease. Lessees are at liberty to sell production at or near the lease, even if selling downstream might have resulted in a higher royalty value for the production than selling it at the lease. If lessees do choose to sell downstream, the choice to sell downstream does not make otherwise non-deductible costs deductible (for example, marketing costs). See Independent Petroleum Association of America, et al. v. DeWitt, 279 F.3d 1036 (D.C. Cir. 2002), cert. denied sub nom., Independent Petroleum Association of America, et al. v. Watson, _U.S._, 123 S. Ct. 869 (Jan. 13, 2003).

In the following discussion, we group the proposed changes by issue category and discuss the specific proposed changes to specific sections of the rule in that context.

For crude oil not sold at arm's length, the existing rule at § 206.103 provides for the use of spot prices at defined market centers published in approved publications both of which are listed in Federal Register Notices available on the MMS Internet site at http://www.mrm.mms.gov/Laws_R_D/FRNotices/, as the basis for valuation of crude oil for most of the country except the Rocky Mountain Region. (In the Rocky Mountain Region, spot prices are the basis for the third “benchmark.”) Our experience with the rule and comments we have received lead us to believe that, at this time, New York Mercantile Exchange (NYMEX) futures prices may represent a more reliable and better assessment of current oil values than spot prices.

Use of the NYMEX price as the basis for royalty value may have several advantages, not the least of which is the fact that the volume of transactions and the number of participants is so large that, at least theoretically, no one entity could manipulate the resultant price. This is an issue partly because of the recent publicity and questions about the information provided to spot price reporting services and the effect such potentially inaccurate information has on spot prices in general. In addition, there is only one NYMEX price, and it is available from any number of sources. There would be no question about the “correct” publication to use to obtain the applicable index price.

Further, various questions have arisen about the timing of application of index prices. Published spot prices for specific months generally represent the market's assessment of prices for crude oil delivered during that month, but determined between the 26th day of the month 2 months prior to the delivery month and the 25th day of the month immediately preceding the delivery month. This is not true for California, where all the days in the calendar month preceding the month of delivery are used to assess spot prices applicable to the month of delivery.

MMS has studied the correlation between several public indicia of crude oil prices (e.g., trading month spot prices, NYMEX prices, etc.) and the values actually used in paying royalties to MMS on crude oil sold at arm's length. These studies demonstrate that calendar-month NYMEX prices (applying the “roll”, ( as discussed below, to Gulf of Mexico, mid-continent, and Permian Basin production) have the highest correlation to reported arm's-length sales values of any publicly-available indices. We have examined both onshore and Gulf of Mexico crude oil types, and this conclusion applies to both.

Under the proposed rule, the “initial” or “base” NYMEX price that would be used to value production in a given production month is calculated by averaging the daily NYMEX settlement prices for each trading day in that month for deliveries in the first future month (known as the “prompt month”), excluding weekends and holidays. The prompt month changes during the production month so that in the beginning of the month the prompt month is the first month after the month of production. According to the NYMEX rules, trading ends at the close of business on the third business day prior to the 25th calendar day of the month (or the first business day prior to the 25th) preceding the delivery month. After that date the prompt month becomes the second month after the production month. See the NYMEX Web site for the specifications: http://www.nymex.com/jsp/markets/lsco_fut_specif.jsp.

We are proposing to exclude weekends and holidays for two reasons. First, if we include weekends and holidays, we would need to assign a price from other days on which trades actually take place. The normal way to do this is to use the preceding day's price (usually Friday's) on the assumption that that is the most accurate reflection of the price for deliveries that take place on the weekend. However, that results in weighting Fridays three times as much as other days. MMS does not believe there is a justification for overweighting Friday prices. The second reason that MMS is proposing to exclude weekends and holidays is that it is MMS's understanding that it is more common industry practice to exclude them in calculating monthly average prices on the NYMEX.

For example, to value production from Federal leases in March 2003 using NYMEX prices, you would average the NYMEX settlement prices published each business day in March, between March 1 and March 22, for April 2003, and between March 23 and 31 for May 2003. Importantly, this calculation is based on “trading days during the calendar month.” This is different from “trading month,” which is a term of art defined in these rules, as discussed below.

The 2000 rule uses prices assessed for the trading period that is as close to concurrent with the production month as possible. However, we've received comments that this period this is not consistent with the way industry does business. Under this proposal, the daily NYMEX prices used correspond more closely to the production month than under the existing rule.

MMS is proposing to apply a “roll” to the initial NYMEX oil prices from leases in the Gulf of Mexico and the mid-continent, including the Permian Basin. The “roll” is a commonly used measure of the trend of NYMEX prices for future deliveries in those areas. Proposing use of the roll necessitates proposing to change the definition of “trading month.” In section 206.101 of the current rule, “trading month” is defined in terms of spot market sales. Because the NYMEX price is the measure of value under the proposed rule, and because MMS proposes to use the roll, MMS proposes to change the definition of “trading month” to conform with NYMEX definitions and practice.

MMS proposes to define trading month to mean the period extending from the second business day before the 25th day of the second calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the second business day before the last business day preceding the 25th day of that month) through the third business day before the 25th day of the calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the third business day before the last business day preceding the 25th day of that month), unless the NYMEX publishes a different definition or different dates on its official Web site, http://www.nymex.com, in which case the NYMEX definition will apply.

Prices reported for futures contracts on the NYMEX are not limited to deliveries in the prompt month. Rather, trades could be made in March 2003 for deliveries in April 2003 or in several subsequent months. Due to the fact that the NYMEX prices are future price estimates, and therefore inherently reflect increases or decreases in prices based upon expected trends, an adjustment to such estimates is necessary in order to extrapolate back to current price estimates, upon which royalty calculations are based. This adjustment factor is the “roll,” which is added to the initial NYMEX price when the market is falling (to correct for the fact that the current price should be higher than the future price in a falling market) and subtracted from the initial NYMEX prices when the market is rising (to correct for the fact that the current price should be lower than the future price if the market is rising). We are proposing to use the roll because we believe it represents current market practice in establishing the sales price for crude oil production in certain regions of the country.

The roll formula includes the future prices for the two months beyond the prompt month, which is not the same as the prompt month used to determine the initial NYMEX price and assigns a progressively smaller weight to the second and third months. This is consistent with MMS's understanding of the common industry practice, including the weights and basis for the prices in the formula below. Specifically, the roll is calculated as follows:

• P0=the average of the daily NYMEX settlement prices for deliveries during the prompt month that is the same as the month of production, as published for each day during the trading month for which the month of production is the prompt month.

• P1=the average of the daily NYMEX settlement prices for deliveries during the month following the month of production, as published for each day during the trading month for which the month of production is the prompt month.

• P2 = the average of the daily NYMEX settlement prices for deliveries during the second month following the month of production, as published for each day during the trading month for which the month of production is the prompt month.

Note that although prices P0, P1, and P2 represent separate prices for periods 1, 2, and 3 months beyond the trading month, respectively, they are all determined during the same trading month. The roll may be a positive or a negative number, and, therefore, increase or decrease the royalty value, depending on whether the futures market is falling or rising.

For example, assume that the month of production for which you must determine royalty value is March 2003. March was the prompt month on the NYMEX (for year 2003) from January 22 through February 20, which is the trading month in this case. April is the first month following the month of production, and May is the second month following the month of production. As explained above, to determine the initial NYMEX price which the roll will adjust, for March 2003 production you first take the average of the daily settlement prices published for each business day from March 1 through March 20 for deliveries in April (the prompt month) and for each business day from March 21 through March 31 for deliveries in May (after May becomes the prompt month).

To calculate P0, a different set of days is used. P0 is the average of the daily NYMEX settlement prices for deliveries during March published for each business day between January 22 and February 20 (the trading month). P1 is the average of the daily NYMEX settlement prices for deliveries during April published for each business day during the same trading month (i.e., between January 22 and February 20). Similarly, P2 is the average of the daily NYMEX settlement prices for deliveries during May published for each business day during the same trading month used for P0 and P1. In this example, assume that P0 = $28.00 per bbl, P1 = $27.70 per bbl, and P2 = $27.10 per bbl. In this declining market, the roll = .6667 × ($28.00 minus; 27.70) + .3333 × ($28.00 − 27.10) = $.20 + $.30 = $.50. Fifty cents per barrel would then be added to the initial NYMEX settlement price used as the basis for royalty valuation. We have developed an illustration of this example and others which are available on the MMS Web site at http://www.mrm.mms.gov/OilVal/ValGuid.htm.

In this example, since the market is falling, prices that traders anticipate during the trading month (March) for deliveries in a future prompt month are lower than the prices at which oil actually is selling during March. The roll accounts for that trend. The roll will have the opposite effect in a rising market. The roll will be a subtraction from the initial NYMEX price calculation (adding a negative number to the NYMEX price) because traders anticipate higher prices for the future prompt months than actually are occurring during the calendar month of production.

The roll would be added to the initial NYMEX price used as the basis for royalty valuation, except for leases in California, Alaska, and the Rocky Mountain Region. The reason for this limitation is that at the workshops, industry representatives stated that they use the roll primarily for Gulf of Mexico and mid-continent production, and not for production in California, Alaska, or the Rocky Mountain Region.

While MMS expects the basic operation of the NYMEX market to be the same for the foreseeable future, it is not so clear that the roll will be a permanent feature of the marketplace. Therefore, MMS proposes that the Director of MMS would have the option of terminating use of the roll when MMS believes that using the roll is no longer a common industry practice at the end of each two-year period following the effective date of this paragraph through notice published in the Federal Register no later than 60 days before the end of the two-year period. Further, MMS also proposes to have the option to redefine how the roll is calculated to comport with changes in industry practice through notice published in the Federal Register no later than 60 days before the end of the two-year period. MMS will explain its rationale when it publishes the notice. MMS believes that this flexibility is appropriate so that the valuation standards more closely reflect market developments. MMS specifically requests comments on whether this is appropriate, and whether a two-year period is appropriate.

MMS is proposing to use NYMEX-based value as the basic measure of value for production not sold at arm's length in all areas except for the Rocky Mountain Region, where MMS proposes to use it as the revised third benchmark (proposed to be redesignated as section 206.103(b)(3)). As discussed earlier, the roll would not be added to the NYMEX price in the Rocky Mountain Region since its use does not reflect current industry practice there. The base NYMEX price would be adjusted for location and quality differentials and actual transportation costs back to the lease, as explained below.

Under the 2000 rule, market center index (spot) prices are adjusted to determine the value of production at the lease through location and quality differentials and deduction of actual transportation costs. See 30 CFR § 206.103 and 206.112. Location and quality differentials are derived from lessees' own arm's-length exchange agreements or, if exchanges are not at arm's-length, through MMS approval. Actual transportation costs from the lease to a market center or intermediate exchange point are determined under 30 CFR § 206.110 and 206.111 according to whether transportation arrangements are arm's-length or non-arm's-length.

Adopting the NYMEX price as the basis for royalty valuation requires an additional adjustment beyond those in the current rule because the NYMEX price is defined only at Cushing, Oklahoma for light sweet crude oil. Therefore, differentials from Cushing to market centers other than Cushing are necessary. MMS believes that many lessees do not have arm's-length exchange agreements between each market center to which they transport or trade and Cushing. Therefore, MMS proposes to allow the use of published differentials when lessees do not exchange oil to Cushing at arm's length. Accordingly, MMS proposes to define a new term, “WTI differential,” as follows:

Example. Assume the production month is March 2003. Industry trade publications perform their price surveys and determine differentials during January 26 through February 25 for oil delivered in March. (California is an exception. In California, the survey covers the calendar month of February for March deliveries.) The WTI differential (for example, the West Texas Sour crude at Midland, Texas, spread versus WTI) applicable to valuing oil produced in the March 2003 production month would be determined using all the business days for which differentials are published during the period January 26 through February 25. Note, in this example, that the days used in the monthly average calculation of the WTI differential are different than the days used to calculate the NYMEX price and are different than the days used to calculate the roll.

This definition is intended to allow the lessee a method of calculating an accurate price at a market center near the lease so that crude oil produced from the lease can be accurately valued. The price at each market center would be the average of the daily NYMEX settlement prices published during the calendar month of production (including the roll, if applicable) plus or minus the appropriate WTI published differential. The lessee would then calculate a further differential from the market center to the lease.

For example, if a producer does not have an arm's-length exchange agreement to Cushing, and the applicable NYMEX price (including the roll) is $29.00/bbl, and the WTI differential for Light Louisiana Sweet (LLS) crude oil is plus $.30/bbl at St. James, Louisiana, the value at St. James would be $29.30. That value must be further adjusted from the market center to the lease by applicable location and quality differentials and for actual transportation costs between the lease and the market center.

Continuing the example, if a lessee produced Eugene Island (EI) sour crude and transported it from the lease to Burns Terminal at a cost of $1.19 per barrel, where it exchanged it at arm's length for LLS at St. James on the basis of $27.50/bbl for the EI crude and $28.80/bbl for the LLS, the value of the EI crude would be $29.30 (the LLS value at St. James) less the location and quality differential from the exchange agreement ($1.30), or $28.00. The lessee could then take the transportation allowance of $1.19 to get a value of $26.81 at the lease.

Changing from spot market index price-based valuation to NYMEX-based valuation and adding a definition for “WTI differential” would require a revision in the definition of “MMS-approved publication.” In the context of the proposed valuation scheme, and because NYMEX prices are widely available, the only context in which MMS approval of a publication would be needed is for determining the WTI differential. Accordingly, the proposed rule would revise the definition of “MMS-approved publication” to read:

MMS-approved publication means a publication MMS approves for determining WTI differentials.

MMS requests specific comments about changing the valuation basis for transactions not at arm's length from spot to NYMEX prices, and to a calendar month average of such prices. MMS also requests specific comments on whether weekends and holidays should be included in the calculation of the average NYMEX price (and, if so, what price should be assigned to days on which no price is published). Further, MMS requests comments on whether it should include the “roll” in the calculation of the proper NYMEX price and whether the roll should apply only to areas other than California, Alaska, and the Rocky Mountain Region. MMS also requests comments on (1) whether lessees should use the location and quality differentials in their own arm's-length exchange agreements between Cushing and the lease or market center in preference to WTI differentials and (2) the circumstances under which they should use one or the other.

Under proposed section 206.103(a), for leases in California and Alaska, you must adjust the NYMEX price for applicable location and quality differentials and you may adjust for actual transportation costs, as described at section 206.112. MMS also requests comments on whether it should retain ANS spot prices as the valuation basis for crude oil produced in California and Alaska instead of changing the valuation basis to the NYMEX price.

Based on requests we have received for valuation guidance and future valuation agreements for the Rocky Mountain Region, as well as our experience with RIK in that area, we believe that very few producers in the Rocky Mountain Region have actual trades of crude to Cushing. The same situation may apply to production in other areas, especially California. Therefore, in many cases producers do not have access to information to make adjustments to a price at Cushing. MMS therefore is proposing a change in how location and quality adjustments are made when you don't have an actual location and quality differential between Cushing and either the lease or a location to which you actually transport or exchange the oil.

For example, in the Rocky Mountain Region for sweet crude oil produced from leases in Wyoming, the market center would be Guernsey, Wyoming. Under the proposed rule, you would use the WTI differential for Wyoming Sweet at Guernsey for sweet crude oil, as published in an MMS-approved publication. If you use the WTI differential for Wyoming Sweet at Guernsey, and you transport your oil to Guernsey, you may also subtract actual transportation costs from the lease to Guernsey. If you exchange your oil from the lease to Guernsey, you must apply the appropriate location and quality differential to Guernsey. In the case of much of the crude oil produced from Federal leases in California, MMS anticipates that the market center would be Line 63 (for crude oil of like-quality to the crude oil for which Line 63 spot prices are published) or Kern River (for crude oil of like-quality to the crude oil for which Kern River spot prices are published).

More specifically, if the NYMEX price (unadjusted by the roll) is $29.00 and you do not have an arm's-length exchange agreement between Cushing and anywhere in Wyoming from which you could calculate a location and quality differential for your sweet crude, you would use the Guernsey WTI differential to value your sweet crude oil if you transport or exchange some or all of your oil to Guernsey. If the Guernsey WTI differential, calculated by taking the average of the daily high and lows and then averaged over the published days of the month, was −$.50/bbl, the value at Guernsey would be $29.00 − $.50 = $28.50/bbl. From this value, you could then subtract your transportation costs (or you would adjust for location and quality) from the lease to Guernsey.

If you did not move or exchange any of your oil to Guernsey, you would have to propose an alternative location and quality differential (between the lease and Guernsey) to MMS. You would then apply the WTI differential at Guernsey to adjust to Cushing. MMS is proposing that you may use the differential from the lease to Guernsey that you propose until MMS prescribes a different differential. If MMS prescribes a different differential, you would have to apply MMS' differential to all periods for which you used your proposed differential. You would have to pay any additional royalties resulting from using MMS' differential, plus late payment interest from the original royalty due date, or you would report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).

MMS also requests comments regarding alternative valuation procedures, including differentials, in valuing sour crude oil in light of the fact that the WTI price at Cushing is for light sweet crude oil. For example, would it be useful to begin valuation of sour crude produced in the Rocky Mountain Region at Hardisty, Alberta, Canada (at which spot market prices for sour crude are published in trade publications), and adjust the Hardisty price for the cost of transportation from Casper, Wyoming (a typical delivery point) to Hardisty and from the lease to Casper? Because Hardisty is farther from Rocky Mountain market and refineries, MMS proposed that applicable transportation costs would be added to, rather than subtracted from, this market center's prices. MMS would like to better understand the number of companies for whom Hardisty would be an appropriate market center. Would it be better in such cases for the lessee to consult directly with MMS on the proper valuation procedure rather than MMS providing specifics in the rule?

MMS is proposing to revise the framework of how and when to apply location and quality differentials and transportation allowances in calculating royalty value. The current rules are based on the proposition that the value of oil not sold at arm's length can be accurately measured by known, accepted index prices at market centers. In order to accommodate certain transactions where the oil does not flow to a market center, the current rule allows lessees, in certain circumstances, to value the oil as if its value were the same at some alternative location (such as a refinery) as it would be at a market center. For example, the regulation currently provides that “if you transport lease production directly to * * * an alternate disposal point, you may adjust the index price for your actual transportation costs.” 30 CFR § 206.112(c). However, value at a refinery may not be the same as the value at a market center.

To be sure that all royalty values are properly adjusted by market-based location and quality differentials (and transportation costs) to the NYMEX pricing point (Cushing), MMS is proposing to rewrite section 206.112. Proposed section 206.112 would clarify that if royalty value at the lease is calculated by starting with the NYMEX price, the NYMEX price would then be adjusted by applicable transportation costs or location and quality differentials between the lease and the market center, and then between the market center and Cushing.

Paragraph (a) of proposed section 206.112 would apply to that portion of the oil produced from your lease that is transported or exchanged (or both transported and exchanged) between the lease and the market center. Paragraphs (b) and (c) would apply to the remainder of your oil. Under paragraph (a), if you transport your oil over any segment (i.e., between any two points) between the lease and the market center, you would determine a transportation allowance under either section 206.110 or 206.111. If you exchange your oil for any segment between the lease and the market center, you would use location and quality differentials derived from your arm's-length exchange agreements. (If an exchange agreement is not at arm's-length, you would have to obtain MMS approval for a location and quality adjustment. Until MMS approves a proposed location and quality differential, you would use the location and quality differential derived from your non-arm's-length exchange agreement. If MMS prescribes a different differential, you would have to adjust previously reported and paid royalties, together with appropriate interest payments or credits. If you do not have an arm's-length exchange agreement for your oil between the market center and Cushing, you would use the WTI differential to adjust for location and quality between the market center and Cushing. You could not both take a transportation allowance and apply a location and quality differential between the same two points.

For example, a lessee produces sour crude from a lease in the Gulf of Mexico that trades as Eugene Island (EI) crude. Assume that the lessee transports 35 percent of the oil produced from the lease to the market center at Houma, Louisiana. To determine the value of that 35 percent of the production, the lessee first would determine its transportation allowance from the lease to Houma under section 206.110 or 206.111, as applicable. In the alternative, if the lessee has an arm's-length exchange agreement between the lease and Houma, it would use the location and quality differential derived from that exchange agreement for the change in location covered by the exchange agreement. The lessee would adjust the NYMEX price by the transportation costs or the location and quality differential. If the lessee exchanges the oil under an arm's-length exchange agreement between Houma and Cushing, it would further adjust the NYMEX price by the location and quality differential derived from that agreement. Alternatively, if the lessee did not exchange the oil between Houma and Cushing at arm's length, the lessee would adjust the NYMEX price by the published WTI-EI differential.

Paragraph (a) also addresses the situation in which the lessee both transports and exchanges a particular volume of oil from the lease to a market center. Therefore, assume the lessee transports 35 percent of the oil produced from the lease to Caillou Island and then exchanges that oil with another party at arm's length for Light Louisiana Sweet (LLS) at St. James, Louisiana, which is the LLS market center. To get the royalty value at Caillou Island, the lessee must add the differential in the exchange agreement (assume − $1.00) to the market value of LLS, which is the NYMEX price plus the WTI-LLS differential (assume − $.50). Assuming a NYMEX price of $29.00, the value at Caillou Island would be $27.50. The lessee may then subtract its transportation costs from the lease to Caillou Island (assume $1.00) to determine the royalty value at the lease (a net value of $26.50).

In the case of much of the crude oil produced from Federal leases in California, MMS anticipates that the market center would be Line 63 (for crude oil of like-quality to the crude oil for which Line 63 spot prices are published) or Kern River (for crude oil of like-quality to the crude oil for which Kern River spot prices are published). Therefore, to determine the adjusted NYMEX price for oil transported or exchanged to either of these market centers, the lessee would adjust the NYMEX price for the WTI differential between Cushing and the applicable market center.

Paragraph (b) or (c) of proposed section 206.112 applies when some, but not all of a lessee's oil is exchanged or transported to or through a market center. Paragraph (b) applies if the lessee transports or exchanges (or both transports and exchanges) at least 20 percent of the oil produced from the lease to a market center. In that event, the lessee would value that portion of the oil not transported or exchanged to a market center by the volume-weighted average of the values of the oil valued under paragraph (a). Therefore, in the preceding example, the lessee transported and exchanged 35 percent of its oil from the lease to the market center at St. James. The value of that oil calculated in that example was $26.50/bbl. Assume that the lessee also transported another 45 percent of its oil from the lease to St. James, and that the adjusted NYMEX-based value of that oil was $27.00/bbl. Finally, assume that the lessee transported the remaining 20 percent of the oil to its refinery in New Jersey. Under the current regulation, the lessee must come to MMS for advice as to how to value the portion of the oil transported to New Jersey. Under the proposed rule, to determine the value of that 20 percent, the lessee would calculate the volume-weighted average of the other two dispositions. In this example, the volume-weighted average = ((.35 × 26.50) + (.45 × 27.00))/.8 = $26.78. The value of the 20 percent transported to the lessee's refinery would be $26.78.

MMS seeks comments on this proposal as well as comments on whether 20 percent is a sufficient volume on which to base the value of oil that the lessee could not otherwise value under the current rule. MMS selected the 20 percent figure for this proposal because it is greater than the royalty percentage under the typical offshore lease (162/3 percent).

Paragraph (c) of proposed section 206.112 addresses the situation where the lessee does not transport or exchange at least 20 percent of the oil to a market center. The lessee would use paragraph (a) to value the less than 20 percent portion (if any) that the lessee transports or exchanges (or both transports and exchanges) to a market center. For the remainder of its lease production, the lessee must come to MMS with a proposal for a location and quality differential between the lease and the market center. If MMS approves a different differential, the lessee would have to adjust its previously reported and paid royalties, together with an interest payment or credit. The lessee would use the WTI differential to adjust between the market center and Cushing.

Finally, the current rule is not clear about all situations in which a quality differential would be appropriate. For example, a lessee could transport its oil from the lease to its refinery at a market center, but its oil may be of a higher gravity and a lower sulfur content than the crude for which a price is published at the market center. In this situation, the lessee should make an adjustment for quality even though it has no exchange agreement or quality bank to use to make the adjustment. MMS proposes that in such circumstances, a lessee would use appropriate posted price gravity tables to adjust the value of its produced crude for gravity differences from the market center benchmark crude, and use a factor of 2.5 cents per one-tenth percent difference in sulfur content to adjust for quality when it has neither exchange agreements nor quality banks to fully adjust the quality of its oil to that of the crude oil at the market center. MMS has based this factor on its understanding of common sulfur bank adjustments for California. For instance, MMS understands, from its RIK program, that the All America Pipeline uses a sulfur adjustment of 50 cents per percent, after the first percent difference in sulfur. MMS believes that the typical sulfur content of oil produced from Federal leases is in the one to three percent range. Therefore, MMS' use of 2.5 cents per 0.1 percent sulfur difference would be similar to the factor used by the All America Pipeline. MMS believes that the ability to use a sulfur quality adjustment is a concern in California, but is seeking comments on whether producers in other parts of the country would find it useful as well. MMS also seeks comments on whether these are reasonable differentials, both for California and the rest of the country.

MMS is proposing to amend the regulations governing calculation of actual transportation costs in non-arm's-length situations by changing the allowed rate of return on undepreciated capital investment. In 1988, MMS determined that the appropriate rate of return was equal to the Standard and Poor's BBB bond rate. MMS explained its choice as follows:

In 2000, when MMS revised the oil valuation regulations, MMS explained why it would continue to use the Standard and Poor's BBB bond rate as the rate of return for transportation allowances:

MMS believes that a market-based cost of capital is needed to reflect accurately the actual and necessary costs to owners of transportation systems. The capital costs, in addition to operating and maintenance expenses, must be accounted for in calculating costs. Capital costs are normally accounted for by allowing depreciation plus a rate of return on undepreciated capital investment.

Industry has challenged the 2000 rule as allegedly arbitrary and capricious in the lawsuit cited earlier. Among the challenged aspects of that rule is whether the Standard and Poor's BBB corporate bond rate is sufficient as an average rate of return on transportation capital investments. The 2000 rule also eliminated the exception allowing lessees to use tariffs filed with FERC as a transportation allowance in lieu of calculating actual transportation costs. Consequently, after June 1, 2000, calculation of actual costs, and the use of the rate of return as part of the calculation, was required of all lessees who did not have arm's-length transportation arrangements. The judicial challenge to the 2000 rule has led MMS to reconsider whether BBB is a sufficient rate of return.

When MMS promulgated regulations to value geothermal resources in 1992, MMS believed that the return on capital needed to compute properly a deduction for the costs of generating electricity should be the weighted average of the returns to equity and debt (without considering income tax treatment). That led MMS to determine that two times the BBB rate was appropriate for that calculation.

MMS has examined some rates of return in the oil industry and believes that some weighted average rate of return considering both equity and debt is appropriate as an actual market-based cost of capital. MMS believes that establishing a uniform rate of return on which all parties can rely is preferable to the costs, delays, and uncertainty inherent in attempting to analyze appropriate project-specific or company-specific rates of return on investment.

MMS believes that the subset of companies that have invested, or are likely to invest, in oil pipelines is a very limited subset of the oil industry. MMS also believes that no standard industrial classification corresponds to those who are willing to invest in pipelines. MMS has received a new study from the American Petroleum Institute (“API”), titled “BBB Bond Rate Not an Adequate Measure of Capital Cost,” that concluded that the cost of capital (after taxes) of the Department of Energy's Financial Reporting Service Companies was closer to 1.6 to 1.8 times the Standard and Poor's BBB bond rate. The API study explained that this group of producers included the companies that would be most likely to own pipelines. MMS, through its Offshore Minerals Management, Economics Division, has also studied several years' worth of data for both non-integrated oil transportation companies and larger oil producers, both integrated and independent, that MMS believes are more likely to invest in oil pipelines. This study concluded that that range of rates of return that would be appropriate for oil pipelines would be in the range of 1.1 to 1.5 times the Standard and Poor's BBB bond rate. While the relationship between the rates of return that MMS has examined and the BBB rate has not been constant, MMS is proposing for comment a rate of return of 1.5 times the Standard and Poor's BBB rate as this rate is within the range recommended by its own experts and close to the rate recommended by the industry experts.

In Section 206.110, MMS is proposing to add a new paragraph (b) that would specify many of the costs incurred for transporting oil under an arm's-length contract that are allowable deductions. MMS believes these costs are costs that are directly related to the movement of crude oil to markets away from the lease. Those costs include:

(1) The amount that you pay under your arm's-length transportation contract or tariff.

(2) Fees paid (either in volume or in value) for actual or theoretical line losses.

(3) Fees paid to a pipeline owner for administration of a quality bank.

(4) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires you to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows:

(i) Multiply the volume that the pipeline requires the shipper to maintain in the pipeline by the value of that volume for the current month calculated under section 206.102 or section 206.103, as applicable; and (ii) multiply the value calculated under paragraph (i) by the monthly rate of return, calculated by dividing the rate of return specified in section 206.111(i)(2) by 12.

MMS proposes to allow this deduction because this cost appears to be an actual cost directly associated with transporting oil. In each month for which line fill is required, a shipper incurs the loss of available capital associated with the value of the line fill volume. The proposal therefore would allow a return on that value, calculated as described above. MMS seeks comments on whether this cost should be allowed as part of the transportation deduction.

(5) Fees paid to a terminal operator for loading and unloading of crude oil into or from a vessel, vehicle, pipeline, or other conveyance.

(6) Fees paid for short-term storage (30 days or less) incidental to transportation as required by a transporter.

(7) Fees paid to pump oil to another carrier's system or vehicles as required under a tariff.

(8) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub when you do not sell the oil at the hub. These fees do not include title transfer fees.

MMS proposes to allow lessees to deduct transfer fees paid to a hub operator associated with physical movement of crude oil through the hub when the shipper does not sell the oil at the hub. MMS believes that this also is a cost directly incurred for movement of the oil. MMS believes that title transfer fees are a cost of selling oil, not moving it, and are not deductible.

(9) Payments for a volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation. While this situation does not arise frequently, MMS believes that in such cases, this volumetric deduction is an actual cost incurred in moving oil.

(10) Costs of securing a letter of credit or other surety that the pipeline requires a shipper to maintain. These costs should only include the currently allocable costs applicable to the Federal lease. MMS believes that shippers can generally use two different means of assuring creditworthiness. The first involves a deposit or advanced payment in which the shipper incurs only the costs associated with the time value of money because they receive their deposit back. The other involves actual out-of-pocket costs to obtain a letter of credit, guarantee, or surety bond. MMS believes that these two means should be accounted for differently in calculating your transportation allowance.

In the first case, if you make a cash deposit of two months of the expected transportation charges (say $50,000), and transport 100,000 barrels per month, of which 75,000 barrels are from a Federal lease, you must calculate the cost as follows:

(i) Multiply the deposit by the monthly rate of return, calculated by dividing the rate of return specified in section 206.111(i)(2) by 12, and (ii) multiply that result by the proportion of total production from each Federal lease. In this example, if the Standard and Poor's BBB bond rate was 8%, the allowable monthly rate would be

In the second case involving the expense of a letter of credit or other surety, if you pay your bank $5000 as a non-refundable fee for a letter of credit, you can include the proportion allocable to Federal production in the month that fee is paid, and then never again.

MMS believes that this is a cost that the lessee must incur to obtain the pipeline's transportation service, and therefore is a cost of moving the oil. MMS welcomes comments on whether these are reasonable ways to calculate the actual costs of assuring a lessee's creditworthiness.

You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this paragraph. MMS seeks comments regarding whether these various costs should be allowed, and whether there are other costs directly attributable to the transportation of crude oil that should be included in the final rule.

In section 206.110, MMS proposes a new paragraph (c) that would specify certain costs as not deductible. Those include:

(1) Fees paid for long-term storage (more than 30 days).

(2) Administrative, handling, and accounting fees associated with terminalling.

(3) Title and terminal transfer fees.

(4) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title transfer fees.

(5) Fees paid to brokers.

(6) Fees paid to scheduling service providers.

(7) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production.

(8) Gauging fees.

At the workshops, MMS received some comments that internal costs should be deductible. One person suggested that if an employee's only function were to arrange for downstream transportation of production, that person's salary should be deductible. MMS does not agree. Under the proposed rule, these types of indirect, internal costs are not deductible.

MMS does not believe that any of the above-described costs are incurred directly as part of the process of physically moving the crude oil. MMS seeks comments on whether any of these costs should be deductible.

In section 206.111, MMS proposes to add a new paragraph (b)(6) that would specify many of the costs incurred for transporting oil under a non-arm's-length contract that are allowable deductions, but only to the extent they have not already been included in the actual cost calculation under paragraphs (d) through (j) of this section. Many of these costs are the same as those associated with arm's-length transportation contracts. Those costs include:

(1) Volumetric adjustments for actual line losses.

(2) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires you to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows:

(3) Fees paid to a non-affiliated terminal operator for loading and unloading of crude oil into or from a vessel, vehicle, pipeline, or other conveyance.

(4) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub when you do not sell the oil at the hub. These fees do not include title transfer fees.

(5) A volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation.

These costs parallel those costs itemized in the arm's-length transportation provisions in section 206.110(b) insofar as appropriate for non-arm's-length situations. Several of the specific items allowed under the arm's-length provisions do not occur or are not appropriate for inclusion in a non-arm's-length transportation situation. Specifically, in a non-arm's-length situation, there is no arm's-length transportation tariff. (Instead, the lessee must calculate its actual costs of building and operating the pipeline.) In addition, MMS believes that even if an affiliated pipeline charges quality bank administrative fees to its own affiliate, the lessee/shipper is simply paying its affiliate and that it should not be regarded as part of the actual costs incurred to move oil. Further, in a non-arm's-length situation, decisions regarding short-term storage (and the cost associated with that storage) are under the lessee's or its affiliate's control, and likely may be avoided. MMS therefore believes that it is not appropriate to allow a short-term storage cost. Also, in a non-arm's-length situation, any fees charged by an affiliated pipeline to pump oil over to a third party-carrier's system are paid within the same corporate organization and are not an additional actual cost of transportation. Finally, in non-arm's-length situations, MMS expects that requiring a letter of credit from an affiliated producer is unnecessary and that the corporate organization ordinarily would avoid incurring the costs of the premium necessary for the letter of credit. MMS therefore believes it inappropriate to allow such a deduction.

In contrast to the 2000 rule, which disallows all line losses in non-arm's-length transportation situations, MMS proposes to allow actual, but not theoretical, line losses. MMS believes that actual line losses properly may be regarded as a cost of moving oil. In addition, if there is a line gain, the lessee must reduce its transportation allowance accordingly. In a non-arm's-length situation, however, a charge for theoretical line losses would be artificial and would not be an actual cost to the lessee. While a lessee may have to pay an amount to a pipeline operator for theoretical line losses as part of an arm's-length tariff, in a non-arm's-length situation, line losses, like other costs, should be limited to actual costs incurred.

The MMS also is proposing to add a new paragraph (b)(7) to section 206.111 that would list the costs that expressly are not deductible as transportation costs. These are the same costs discussed above in the section on arm's-length transportation contracts (section 206.110), with one addition, namely, that theoretical line losses are not deductible under non-arm's-length transportation arrangements.

We propose to modify existing § 206.111(h)(5) to remedy an unintended consequence regarding depreciation when calculating a transportation allowance not involving an arm's-length transportation contract. When we amended the rules in March 2000, we intended the revisions regarding depreciation in the current rule to permit, one time only, a new depreciation schedule based on your purchase price when you purchase a transportation system from a previous owner. If a transportation system were sold more than once, subsequent purchasers would have to maintain the then-existing depreciation schedule.

However, existing paragraph (h)(5) says “if you or your affiliate purchase a transportation system at arm's length after June 1, 2000, from anyone other than the original owner, you must assume the depreciation schedule of the person who owned the system on June 1, 2000.” But if A were the original owner and still owned the system on June 1, 2000, and subsequently sold the system to B after June 1, 2000, who in turn sold it to C, the rule as written says that C would have to assume original owner A's depreciation schedule. This was not MMS' intent. To be consistent with the intended result, C should assume B's depreciation schedule in this situation.

Therefore, to reflect the original intent, MMS proposes to modify § 206.111(h)(5) to delete the words “who owned the system on June 1, 2000” and replace them with the words “from whom you bought the system.” This change would enable C in the example above to assume the depreciation schedule of B based on B's purchase price of the transportation system and subsequent reinvestment.

In the preamble to the 2000 rule, MMS explained:

Based upon further consideration of these situations, MMS does not believe there should be a presumption that all of these sorts of transactions are non-arm's-length and are not sales. When a party to a joint operating agreement, who is not the operator, allows the operator to dispose of its share of oil production in exchange for the consideration provided under that agreement, MMS recognizes that some of these arrangements may be sales of the production. The royalty value of the oil so transferred depends on whether the sale is an arm's-length sale. MMS expects that in most of the situations where the lessee is not the operator, the transaction may be at arm's-length. If the sale is at arm's-length, the question then becomes (as in any arm's-length situation) whether any of the exceptions in section 206.102(c) apply. In some circumstances, the sale also may be a marketing agreement, and the operator may be performing the marketing function for the lessee. In such a case, the MMS may determine that the lessee has improperly deducted marketing costs, and MMS may increase the royalty value accordingly. MMS will examine each case on its facts just as it does any other disposition of production.

MMS also proposes to change the reporting instructions in 30 CFR 210.53 with respect to sales under joint operating agreements to facilitate review and audit of these transactions. MMS proposes to add a new paragraph (c) to section 210.53 that would require an operator under a joint operating agreement who is also a designee and who reports and pays royalty on behalf of one or more working interest owners from whom the operator buys production, to report the share of the production it purchased from the working interest owners and the associated royalty payment on a separate line on the Form MMS-2014 from the line on which the operator reports its own share of production and the associated royalty payment.

The MMS is proposing a technical correction to the regulation at section 206.121 that permitted a grace period for reporting and paying royalties after the June 2000 rule became effective to give royalty payors adequate time to change their systems. We are proposing to end-date the grace period for such adjustments, because we consider three years to be sufficient time to have reported and paid royalties under the regulations published in 2000.

Section 206.103(b) applies to production from leases in the Rocky Mountain Region, a defined term. The current rule prescribes a series of four benchmarks described in paragraphs (b)(2) through (b)(5) for valuing production in the Rocky Mountain Region that is not sold at arm's-length. To provide clarity in this section of the rule, MMS is proposing to renumber paragraphs (b)(2) through (b)(5) to make them (b)(1) through (b)(4) so that the four benchmarks correspond with the four paragraph numbers. Other than this renumbering, the only change MMS is proposing to make to the valuation criteria for the Rocky Mountain Region is the change to the third benchmark from spot prices to NYMEX valuation, described above in I. A.

In addition, MMS proposes a technical change to the definition of “affiliate” in section 206.101. MMS would change paragraph (2) of the definition of “affiliate” by striking the words “of between 10 and 50 percent” and substituting therefor the words “10 through 50 percent” because the current definition does not specify the treatment of a situation in which one person owns exactly 50 percent of another.

In addition to issues already identified above on which MMS seeks comments, MMS specifically requests comments on the following issue: Should MMS allow using the NYMEX price to value oil sold at arm's-length in multiple sales downstream of the lease where the lessee does not first transfer to an affiliate and where “tracing” the production from the lease or unit to the specific sale is burdensome?

Under the 2000 rule, most lessees who are relatively large producers have the option of using a spot market index-based value even when the oil is sold at arm's length, because the lessee is working through an affiliate who is the seller in an arm's-length resale. Thus, if a lessee wants to avoid the burden of “tracing” the production to each particular sale out of a large number of sales to different purchasers, it may opt to use index-based value under the current 30 CFR § 206.102(d)(2). Lessees who do not first transfer to an affiliate and who sell directly to a large number of different purchasers do not have this option. MMS seeks comment on whether the option of using NYMEX prices should be extended to these situations in the event that MMS adopts NYMEX-based valuation.

Our practice is to make comments, including names and home addresses of respondents, available for public review during regular business hours and on our Internet site at www.mrm.mms.gov. Individual respondents may request that we withhold their home address from the rulemaking record, which we will honor to the extent allowable by law. There also may be circumstances in which we would withhold from the rulemaking record a respondent's identity, as allowable by law. If you wish us to withhold your name and/or address, you must state this prominently at the beginning of your comments. However, we will not consider anonymous comments. We will make all submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, available for public inspection in their entirety.

Summarized below are the estimated costs and royalty impacts of the proposed rule to all potentially affected groups: Industry, the Federal Government, and State and local governments. The costs and the royalty collection impacts, are segregated into two categories—those that would accrue in the first year after the proposed rule becomes effective and those that would accrue on a continuing basis each year thereafter.

Under this proposed rule, industry would value oil based on a market price that more closely represents the true value of the oil. We believe this may result in industry paying additional royalties compared to the current regulations. We provide estimates below of any significant increased royalties under the proposed rule.

The proposed rule maintains many of the provisions of the Federal oil valuation rule that became effective June 1, 2000 (the June 2000 Rule), including the concept of three separate valuation methodologies linked to different production locations. This analysis also is divided into the same three areas. They include California/Alaska (onshore and offshore), the Rocky Mountain Region, and the “rest of the country” including the Gulf of Mexico. This analysis highlights the impacts of modifying the pricing provisions and methodologies. The allowed adjustments for transportation and quality as outlined in the June 2000 Rule also would change somewhat, and some additional corresponding analysis is necessary.

In valuing production not sold under an arm's-length contract, the June 2000 Rule employed the spot price of the oil most closely associated with the production, with appropriate adjustments for location and quality. The timing of the spot month that corresponds with the production month is the quoted average from an MMS-approved publication from the 26th day of the month prior to the current production month to the 25th day of the current production month. For example, December royalty production is valued using the spot quotes for the oil most similar in location and quality from November 26th through December 25th.

The proposed new methodology for the “rest of the country,” as discussed earlier, is the NYMEX Calendar Month Average daily settlement price with the “roll” and a differential. This method uses a trading month differential (found in MMS-approved publications and based on spot price quotes) applied to the average of the daily NYMEX prices, excluding weekends and holidays, during the production month for deliveries during the prompt month as defined in the proposed rule. For example, for the month of December, assume a producer seeks to value production whose characteristics are closely related to Light Louisiana Sweet (LLS) crude oil. The grade differential established over the period October 26 through November 25 would be applied to the average of the daily NYMEX prompt month prices published for each day in the month of December. The grade differential is the WTI spot price for the period October 26-November 25 less the LLS spot price for the same period. Assuming the WTI value is $29.00 per barrel and the LLS value is $28.00 per barrel, the differential is $1.00 per barrel.

The forward “roll” is added to the calendar month average NYMEX value and is determined by taking a ratio of the difference between the current month value, the 2nd month out future value, and the 3rd month out future value as reported on the NYMEX exchange. Assuming the “roll” calculation results in a value of $0.30 per barrel, the calculated royalty value, assuming the NYMEX calendar month average price is $29.50 per barrel, is $28.80 per barrel (including both the roll and the differential). It is calculated as follows for all royalty production not disposed of at arm's length in the month of December:

We have compared prices under NYMEX adjusted for the roll and the grade differential discussed above with prices calculated under the existing rule based on spot prices at each of the market centers applicable in the “rest of the country—e.g., Midland, St. James, and Empire. We found that over the period April 2000 through December 2002, or the period from approximately when the current rule became effective through the end of calendar year 2002, the adjusted average monthly NYMEX price exceeded the monthly average spot prices for these market centers by about $0.31 per barrel. We also have performed this comparison back to the beginning of 1999 and found that the difference is slightly higher over the entire period January 1999 through December 2002. We chose the $0.31 per barrel increment as the basis for our royalty impact estimates.

In estimating the impact of a change to NYMEX valuation, we made several assumptions in addition to the $0.31 per barrel increment. We assumed that 50 percent of all Federal barrels would be valued under the non-arm's-length provisions, that the offshore royalty rate is one-sixth and onshore royalty rate is one-eighth, and that volumes taken in kind would vary from 50,000 barrels per day to 180,000 barrels per day. The former includes only barrels currently taken in the small refiner program, and the latter includes small refiner volumes plus barrels currently going to the Strategic Petroleum Reserve. We then subtracted the volumes taken in kind and applied the $0.31 per barrel figure to the remaining barrels assumed to be valued under the non-arm's-length provisions. We estimate increased costs to industry in the form of higher royalty payments of $4,303,913 to $11,658,663 million per year.

The current rule specifies Alaska North Slope (ANS) spot prices for oil delivered at Long Beach, California as the valuation basis for all crude produced in California or Alaska and not sold at arm's length. The ANS spot quotes on a monthly average basis (without weekends or holidays) apply directly to the production month. That is, the spot quotes from December 1st through the 31st apply directly to December production. The rule allows for transportation adjustments and quality allowances.

The proposed new methodology is the NYMEX Calendar Month Average daily settlement price with appropriate differentials, but without the “roll” discussed above. This method uses a trade-month differential (found in MMS-approved publications and based on spot price quotes) applied to the average of the daily NYMEX prices, excluding weekends and holidays, published for each day during the production month for deliveries during the prompt month as defined in the proposed rule.

For example, for the month of December, assume a producer seeks to value production whose quality and location are similar to Kern River crude oil (13.4 degree API gravity oil in Kern County). The grade differential established over the period October 26 through November 25 would be applied to the average of the daily NYMEX prompt month prices published for each day in the month of December. The grade differential is the WTI spot price for the period October 26-November 25 less the Kern River spot price for the same period. Assuming the WTI value is $29.00 per barrel and the Kern River value is $20.00 per barrel, the negative $9.00 per barrel differential would be added to the NYMEX calendar month average price corresponding to the month of production (without weekends or holidays). Using the same NYMEX value, $29.50 per barrel, as in the previous example, the royalty value calculation would be as follows:

Because the proposed new valuation method uses new oil types and locations as its basis, location and quality adjustments must be made to the current basis (ANS) to make a meaningful comparison of values calculated under the proposed and current rules. Estimating the proper adjustments with precision is very difficult.

For example, again using Kern River crude oil to compare to ANS, there are significant differences in quality (13.4 degrees for Kern River and 29.5 for ANS) and in location (Kern County, CA and Long Beach, CA). The sulfur content of the two oils is nearly identical, so no sulfur price adjustment is needed. Gravity differential estimates can vary significantly because California posted price adjustment scales vary from $0.15 per degree API gravity to $0.25 per degree or more. The gravity adjustment range would then be from $2.42 to $4.03 per barrel.

The location differential can be estimated by the use of a tariff between points in Kern County to Long Beach. These tariffs currently range between $.75 and $1.25 per barrel.

Depending on how these differentials apply in specific cases, the result could be deductions from the ANS price from $3.17 to $5.28 per barrel in order to compare the adjusted ANS price to value calculated under the proposed rule. The result could be an overall royalty increase or decrease. Applying the high gravity and location adjustments above to the ANS price from 1999 through 2002 would result in an adjusted ANS price about $1.00 per barrel lower than the price derived under the proposed rule. Applying the low gravity and location adjustments to the ANS price would result in a value about $1.00 above the price derived under the proposed rule.

In estimating the impact of a change to NYMEX valuation, we made several assumptions in addition to the $1.00 per barrel increase or decrease. For California we assumed that 50 percent of all Federal barrels would be valued under the non-arm's-length provisions, that the offshore royalty rate is one-sixth and onshore royalty rate is one-eighth, and that volumes taken in kind in the small refiner program are 10,000 barrels per day. We then subtracted the volumes taken in kind and applied the $1.00 per barrel figure to the remaining barrels assumed to be valued under the non-arm's-length provisions. We estimate a range of −$2,120,650 to +2,120,650 per year in terms of higher or lower royalty payments. This range results because the location and quality adjustments can vary significantly. For Alaska we based our estimate on an average offshore royalty production of 1,600 barrels per day, and we assumed that all production would be valued under the non-arm's-length provisions. Using the same $1.00 per barrel figure that we used in California, we estimate a range of −$584,000 to +584,000 per year in terms of higher or lower royalty payments.

Determining the impact of any proposed modification of the current pricing methodology for valuing oil not sold at arm's-length in the Rocky Mountain Region is also difficult. This is largely because there is no prescribed formula currently in place, but rather a series of benchmark procedures that lessees apply on an individual basis. Although this proposal does involve NYMEX pricing, it would apply only if and when the first two benchmark procedures (which rely exclusively on arm's-length values) are inapplicable. Where the third benchmark applies, valuation of Wyoming Sweet would rely on differentials between WTI at Cushing, Oklahoma, and Wyoming Sweet at Guernsey, Wyoming.

The proposed Wyoming Sweet valuation methodology is identical to that for California, with the obvious substitution of the Wyoming Sweet spot price for the California grades. For December production, the average value of Wyoming Sweet against WTI determined October 26th through November 25th applied to the NYMEX calendar month average becomes the basis of value:

We have compared prices under NYMEX adjusted for the grade differential (and not the “roll,” as discussed earlier) with prices calculated under the existing rule based on spot prices at Guernsey, Wyoming—the only market center in the Rocky Mountain Region. We used the same time period, April 2000 through December 2002, as we did for the Rest of the Country (see footnote 3). Over this period the monthly average spot price exceeded the adjusted average monthly NYMEX price by about $0.04 per barrel. We have also performed this comparison back to the beginning of 1999 and find that the adjusted NYMEX price exceeded the monthly average spot price by about $0.02 per barrel over the entire period January 1999 through December 2002. To illustrate the highest potential cost to industry, we chose the $0.02 per barrel increment of NYMEX over spot as the basis for our benefit and cost estimates.

In estimating the impact of a change to NYMEX valuation, we made several assumptions in addition to the $0.02 per barrel increment. First we assumed that 50 percent of all Federal barrels would be valued under the non-arm's-length provisions. Then, because there are four non-arm's-length benchmarks in the Rocky Mountain Region and only the third benchmark would rely on NYMEX prices, we assumed that 25 percent of all Federal barrels that are valued under the benchmarks would be valued under each of the benchmarks and hence only 25 percent of those barrels would rely on NYMEX prices. (None of the other three benchmarks would change.) Thus 121/2 percent of all Federal barrels would be valued under the third non-arm's-length benchmark. We also assumed that the royalty rate is one-eighth, and that volumes taken in kind (these are from Wyoming only) would be about 4,000 barrels per day. We then subtracted the volumes taken in kind and applied the $0.02 per barrel figure to the remaining barrels assumed to be valued under the non-arm's-length provisions. We estimate higher royalty payments to be about $11,738 per year.

The MMS does not routinely collect detailed allowance information, such as affiliation between the payor and transporter or the cost components used to calculate a non-arm's-length allowance rate. Therefore we had to make several broad assumptions in order to estimate the impact of the proposed rule. We assumed that 50 percent of all allowances are non-arms-length. We also assumed that over the life of the pipeline, allowance rates are made up of 1/3 rate of return on undepreciated capital investment, 1/3 depreciation expenses and 1/3 operation, maintenance and overhead expenses. During FY 2001 royalty payors reported transportation allowance deductions of $45,363,394 for Federal oil production. Based on our assumptions, if 1/2 of the allowance deductions are non-arm's-length, then $22,681,697 of the total allowances fell in this category. If 1/3 of the allowance is made up of the rate of return, this equals $7,560,565. Therefore, we estimated that increasing the basis for the rate of return by 50 percent could result in additional allowance deductions of $3,780,283 ($7,560,565 × .50). Our review of transportation allowances deducted from oil royalties in the States of Wyoming, Colorado, Utah, and New Mexico revealed minimal amounts deducted from onshore leases. Therefore, we assumed that this entire increase would impact offshore royalties only.

For offshore production, we based this estimate on the total offshore oil royalties for FY 2001 of $2,069,450,791. We assumed that 50 percent of all allowances are non-arms-length, and that oil pipeline losses are 0.2 percent of the volume of the production. Therefore, before making the further adjustments discussed below, we estimated this change could result in additional transportation allowances of $2,069,451 per year ($2,069,450,791 × .50 × .002). For onshore production we used total onshore oil royalties for FY 2001 of $252,575,890. We assumed that 50 percent of all allowances are non-arm's-length, and that oil pipeline losses are 0.2 percent of the volume of the production. Therefore, before making the further adjustments discussed below, we estimated this change could result in additional transportation allowances of $252,576 per year ($252,575,890 × .50 × .002).

We also needed to recognize that substantial volumes of offshore production are taken in kind and are not subject to the regulations regarding transportation. We estimated that between 50,000 barrels of oil per day (BOPD) and 180,000 BOPD may be taken in kind. The wide variance in this estimate is caused by the approximately 130,000 BOPD which may be taken in kind and placed into the Strategic Petroleum Reserve. Based on daily offshore Federal production of 222,100 BOPD, the amount of oil transportation subject to these regulations could range from a high of 77 percent of the production to a low of 19 percent of the production. [(222,100 − 50,000) / 222,100 = 77%; (222,100−180,000) / 222,100 = 19%]. Applying the high and low range factors for oil taken in kind, this could result in additional transportation allowance deductions for offshore leases ranging from $393,196 ($2,069,451 × 19%) to $1,593,477 ($2,069,451 × 77%) per year.

For offshore oil production, we based our estimate on the total offshore oil royalty volume for FY 2001 of 81,066,567 barrels. We also estimated that quality bank administrative fees were $0.002 per barrel. We estimated that allowing such fees could result in additional offshore transportation allowances of $162,133 (81,066,567 × $0.002) per year before considering the effects of oil taken in kind. Applying the high and low range factors for oil taken in kind, this could result in additional transportation allowance deductions ranging from $30,805 ($162,133 − 19%) to $124,842 ($162,133 − 77%) per year. For onshore production we used the onshore royalty volume for FY 2001 of 9,496,181 barrels. Allowing such fees could result in additional allowances of $18,992 (9,496,181 × $0.002)

For offshore oil production, we based this estimate on the total offshore oil royalty volume for FY 2001 of 81,066,567 barrels. We estimated that line fill costs ranged from $0.02 to $0.05 per barrel. We then estimated that this factor could result in additional transportation allowances of $1,621,331 (81,066,567 × $0.02) to $4,053,328 (81,066,567 × $0.05) before considering the effects of oil taken in kind. Applying the high and low range factors for oil taken in kind, this could result in additional offshore transportation allowance deductions ranging from $308,052 ($1,621,331 × 19%) to $3,121,062 ($4,053,328 × 77%) per year. For Onshore production we estimated that this factor could result in additional transportation allowances of $189,924 (9,496,181 × $0.02) to $474,809 (9,496,181 × $0.05).

Again we assumed that 50% of allowances were at arm's length. We again based the estimate on the total offshore oil royalty volume for FY 2001 of 81,066,567 barrels. We estimated that letter of credit costs ranged from $0.02 to $0.05 per barrel. We thus estimated that this could result in additional transportation allowances of $810,666 (81,066,567 × $0.02 × .5) to $2,026,664 (81,066,567 × $0.05 × .5). Applying the high and low range factors for oil taken in kind, this could result in additional offshore transportation allowance deductions ranging from $154,027 ($810,666 × 19%) to $1,560,531 ($2,026,664 × 77%) per year. For Onshore production we estimated that this factor could result in additional transportation allowances of $94,962 (9,496,181 × $0.02 ×.5) to $237,405 (9,496,181 × $0.05 × .5).

We estimate that between $4,666,363 and $10,180,195 in additional transportation allowances could be deducted from OCS lease royalties based on an increased rate of return and permissibility of line losses for non-arm's-length allowances; permissibility of quality bank administration fees and line fill costs for both arm's-length and non-arm's-length allowances; and permissibility of letter of credit costs for arm's-length allowances. Also, for these same items we estimate that between $556,454 and $983,782 of additional transportation allowances may be deducted from Onshore Federal lease royalties.

We believe any increases in administrative costs related to changes in non-arm's-length valuation procedures would be minimal. These procedures involve NYMEX prices, which are readily available at no cost from numerous sources. They also involve determination of spot price differentials at various locations. We believe that anyone who uses the non-arm's-length provisions of the current rule already has access to the needed publications and exchange agreements. For some lessees, modification of computer programs related to royalty calculation and payment may be needed. We think that only about 50 of the approximately 800 Federal oil royalty payors would use the non-arm's-length provisions and thus might need to do some reprogramming. Using an estimated cost of $5,000 for each such payor to do its reprogramming, the added one-time cost would be $250,000.

We anticipate that, in a very few cases, companies may request approval of proposed differentials when less than 20 percent of the crude oil is transported or exchanged from the lease. These requests would have to: (1) Be in writing; (2) identify specifically all leases involved, the record title or operating rights owners of those leases, and the designees for those leases; (3) completely explain all relevant facts, including informing MMS of any changes to relevant facts that occur before MMS responds to their request; (4) include copies of all relevant documents; (5) provide the company's analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and (6) suggest the proposed differential. We estimate that there will be two such requests annually. We estimate the annual burden for these requests would be 660 hours (2 × 330), including record keeping. Based on a per-hour cost of $50, we estimate the cost to industry is $33,000.

This rule will not impose any additional burden on local governments. MMS estimates that States impacted by this rule may experience changes in royalty collections as indicated below:

States receiving revenues from offshore Outer Continental Shelf Lands Act Section 8(g) leases would share in a portion of the estimated additional $4,303,913 to $11,658,663 in royalties that would accrue annually from the “rest of the country” under the proposed valuation methodology. Based on each 8(g) State's share of total offshore royalties for FY 2001 and their 8(g) disbursement percentage, we estimate the States' 8(g) share to be between $26,363 and $71,119. Onshore States would receive additional revenue of $317,682.

The State of California would share in a portion of the estimated $2,120,650 increase to $2,120,650 decrease in royalties accruing from California. We estimate that royalties accruing to the State of California for onshore production would range from an increase of about $524,317 to a decrease of about $524,317. We further estimate that its 8(g) share would range from an increase of about $53,692 to a decrease of about $53,692. For Alaska we estimate that its 8(g) share would range from an increase of about $157,680 to a decrease of about $157,680, with no onshore impact. For the Rocky Mountain Region, we estimate an increase in the States' share of royalty revenues of about $5,869 per year.

We estimate that between $33,785 and $73,705 in additional transportation allowances may be deducted from the States' share of Federal royalties for OCS 8(g) leases. In addition, we estimate that between $278,227 and $491,891 may be deducted from the States' share of onshore Federal lease royalties.

Because many of the changes in the proposed rule are technical clarifications and others are relatively minor changes to the valuation mechanisms, the impacts to the Federal Government should be minimal, especially in administration.

The Federal Government would receive an estimated $4,303,913, to $11,658,663 in royalties each year from the “rest of the country,” of which affected States would receive a portion. We estimate the Federal share of offshore royalties to be between $3,642,186 and $10,952,180 and the Federal share of onshore royalties at $317,682. For California we estimate the range of royalty impacts to be from a decrease of $1,542,630 to an increase of $1,542,630 per year. For Alaska, we estimate the range of royalty impacts to be from a decrease of $426,320 to an increase of $426,320 per year. For the Rocky Mountain Region, we estimate an increase in royalty revenues of about $5,869 per year of the estimated additional $11,738 in royalties accruing to production from the affected States.

We estimate that between $4,632,578 and $10,106,490 per year in additional transportation allowances may be deducted from Federal OCS royalties and between $278,227 and $491,891 from onshore royalties.

We anticipate that companies may request approval of proposed differentials when they transport or exchange less than 20 percent of the crude oil from the lease. In processing these requests MMS would have to: (1) Respond in writing; (2) verify all leases involved the record title or operating rights owners of those leases, and the designees for those leases; (3) completely explain all relevant facts; (4) obtain copies of all relevant documents; (5) analyze the issue(s), including citations to all relevant precedents (including adverse precedents); and (6) potentially defend our determination. For the above written requests, we estimate that there will be two responses annually. We estimate that the annual burden for these requests is 660 hours (2 × 330), including record keeping. Based on a per-hour cost of $50, we estimate the cost to the Federal Government is $33,000.

In the table, a negative numbers means a reduction in payment or receipt of royalties or a reduction in costs. A positive number means an increase in payment or receipt of royalties or an increase in costs. For the purpose of calculation of the net expected change in royalty impact, we have assumed that the average for royalty increases or decreases would be the midpoint of the proposed range.

In accordance with the criteria in Executive Order 12866, this proposed rule is not an economically significant regulatory action as it does not exceed the $100 million threshold. The Office of Management and Budget (OMB) has made the determination under Executive Order 12866 to review this proposed rule because it raises novel legal or policy issues.

1. This proposed rule will not have an annual effect of $100 million or adversely affect an economic sector, productivity, jobs, the environment, or other units of Government. MMS has evaluated the costs of this rule, and estimates that industry would incur additional administrative costs of approximately $283,000 in the first year of implementation, and $33,000 in additional administrative costs in subsequent years. The Federal Government would incur $33,000 each year in additional administrative costs.

2. This proposed rule will not create inconsistencies with other agencies' actions.

3. This proposed rule will not materially affect entitlements, grants, user fees, loan programs, or the rights and obligations of their recipients.

4. This proposed rule will raise novel legal or policy issues. See proposed modifications in the Provisions of This Proposed Rule in the attached Threshold Analysis.

I certify that this proposed rule will not have a significant economic effect on a substantial number of small entities as defined under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). An initial Regulatory Flexibility Analysis is not required. Accordingly, a Small Entity Compliance Guide is not required. See the above Analysis titled “Summary of Costs and Royalty Impacts.”

Your comments are important. The Small Business and Agricultural Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small businesses about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the enforcement actions in this rule, call 1-800-734-3247. You may comment to the Small Business Administration without fear of retaliation. Disciplinary action for retaliation by an MMS employee may include suspension or termination from employment with the Department of the Interior.

This proposed rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This proposed rule:

1. Does not have an annual effect on the economy of $100 million or more. See the above Analysis titled “Summary of Costs and Royalty Impacts.”

2. Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions.

3. Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises.

In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.):

1. This proposed rule will not significantly or uniquely affect small governments. Therefore, a Small Government Agency Plan is not required.

2. This proposed rule will not produce a Federal mandate of $100 million or greater in any year; i.e., it is not a significant regulatory action under the Unfunded Mandates Reform Act. The analysis prepared for Executive Order 12866 will meet the requirements of the Unfunded Mandates Reform Act. See the above Analysis titled “Summary of Costs and Royalty Impacts.”

In accordance with Executive Order 12630, this proposed rule does not have significant takings implications. A takings implication assessment is not required.

In accordance with Executive Order 13132, this proposed rule does not have federalism implications. A federalism assessment is not required. It will not substantially and directly affect the relationship between the Federal and State governments. The management of Federal leases is the responsibility of the Secretary of the Interior. Royalties collected from Federal leases are shared with State governments on a percentage basis as prescribed by law. This proposed rule would not alter any lease management or royalty sharing provisions. It would determine the value of production for royalty computation purposes only. This proposed rule would not impose costs on States or localities. Costs associated with the management, collection and distribution of royalties to States and localities are currently shared on a revenue receipt basis. This proposed rule would not alter that relationship.

In accordance with Executive Order 12988, the Office of the Solicitor has determined that this proposed rule will not unduly burden the judicial system and does not meet the requirements of sections 3(a) and 3(b)(2) of the Order.

This proposed rule contains new information collection requirements that we have submitted to the Office of Management and Budget (OMB) for review and approval under section 3507(d) of the Paperwork Reduction Act of 1995. As part of our continuing effort to reduce paperwork and respondent burden, we invite the public and other Federal agencies to comment on any aspect of the reporting burden.

Submit your comments by fax (202) 395-6566 or e-mail (OIRA_docket@omb.eop.gov) to the Office of Information and Regulatory Affairs, OMB, Attention Desk Officer for the Department of the Interior (OMB Control Number 1010-NEW).

Send copies of your comments to Sharron L. Gebhardt, Regulatory Specialist, Records and Information Management Team, Minerals Management Service, Minerals Revenue Management, P.O. Box 25165, MS 320B2, Denver, Colorado 80225. If you use an overnight courier service, the MMS courier address is Building 85, Room A-614, Denver Federal Center, Denver, Colorado 80225. You may also e-mail your comments to us at mrm.comments@mms.gov. Include the title of the information collection and the OMB Control number in the “Attention” line of your comment. Also include your name and return address. Submit electronic comments as an ASCII file avoiding the use of special characters and any form of encryption. If you do not receive a confirmation that we have received your e-mail, contact Ms. Gebhardt at (303) 231-3211.

OMB has up to 60 days to approve or disapprove this collection of information but may respond after 30 days. Therefore, public comments should be submitted to OMB within 30 days in order to assure their maximum consideration. However, we will consider all comments received during the comment period for this notice of proposed rulemaking.

The annual reporting burden is 1608 hours. We expect approximately 40 responses from 7 Federal lessees to submit the required information. The burden estimates include the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Using an average cost of $50 per hour, the total cost to respondents is $80,400.

Public Comment Policy. The PRA (44 U.S.C. 3501, et seq.) provides that an agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. Before submitting an ICR to OMB, PRA Section 3506(c)(2)(A) requires each agency “* * * to provide notice * * * and otherwise consult with members of the public and affected agencies concerning each proposed collection of information * * *.” Agencies must specifically solicit comments to: (a) Evaluate whether the proposed collection of information is necessary for the agency to perform its duties, including whether the information is useful; (b) evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) enhance the quality, usefulness, and clarity of the information to be collected; and (d) minimize the burden on the respondents, including the use of automated collection techniques or other forms of information technology.

The PRA also requires agencies to estimate the total annual reporting “non-hour cost” burden to respondents or recordkeepers resulting from the collection of information. We have not identified non-hour cost burdens for this information collection. If you have costs to generate, maintain, and disclose this information, you should comment and provide your total capital and startup cost components or annual operation, maintenance, and purchase of service components. You should describe the methods you use to estimate major cost factors, including system and technology acquisition, expected useful life of capital equipment, discount rate(s), and the period over which you incur costs. Capital and startup costs include, among other items, computers and software you purchase to prepare for collecting information; monitoring, sampling, and testing equipment; and record storage facilities. Generally, your estimates should not include equipment or services purchased: (i) Before October 1, 1995; (ii) to comply with requirements not associated with the information collection; (iii) for reasons other than to provide information or keep records for the Government; or (iv) as part of customary and usual business or private practices.

We will summarize written responses to this proposed information collection and address them in our final rule. We will provide a copy of the ICR to you without charge upon request and the ICR will also be posted on our Web site at http://www.mrm.mms.gov/Laws_R_D/FRNotices/FRInfColl.htm.

We will post all comments in response to this proposed information collection on our Web site at http://www.mrm.mms.gov/Laws_R_D/InfoColl/InfoColCom.htm_. We will also make copies of the comments available for public review, including names and addresses of respondents, during regular business hours at our offices in Lakewood, Colorado. Individual respondents may request that we withhold their home address from the public record, which we will honor to the extent allowable by law. There also may be circumstances in which we would withhold from the rulemaking record a respondent's identity, as allowable by law. If you request that we withhold your name and/or address, state this prominently at the beginning of your comment. However, we will not consider anonymous comments. We will make all submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, available for public inspection in their entirety.

This proposed rule deals with financial matters and has no direct effect on Minerals Management Service decisions on environmental activities. Pursuant to 516 DM 2.3A (2), Section 1.10 of 516 DM 2, Appendix 1 excludes from documentation in an environmental assessment or impact statement “policies, directives, regulations and guidelines of an administrative, financial, legal, technical or procedural nature; or the environmental effects of which are too broad, speculative or conjectural to lend themselves to meaningful analysis and will be subject later to the NEPA process, either collectively or case-by-case.” Section 1.3 of the same appendix clarifies that royalties and audits are considered to be routine financial transactions that are subject to categorical exclusion from the NEPA process.

In accordance with the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments “(59 FR 22951) and 512 DM 2, we have evaluated potential effects on Federally recognized Indian tribes and have determined that the changes we are proposing for Federal leases may have an impact on Indian leases. As such, by Federal Register Notice (68 FR 7086) dated February 12, 2003, MMS reopened the comment period on the January 2000 supplementary proposed rule for valuing crude oil produced from Indian leases. The comment period closed on April 14, 2003. MMS will determine how to proceed with that rulemaking based on comments received.

In accordance with Executive Order 13211, this regulation does not have a significant effect on the nation's energy supply, distribution, or use. The proposed changes better reflect the way industry accounts internally for its oil valuation and provides a number of technical clarifications. None of these changes should impact significantly the way industry does business, and accordingly should not affect their approach to energy development or marketing. Nor does the proposed rule otherwise impact energy supply, distribution, or use.

In accordance with Executive Order 13175, this proposed rule does not have tribal implications that impose substantial direct compliance costs on Indian tribal governments

Executive Order 12866 requires each agency to write regulations that are easy to understand. We invite your comments on how to make this rule easier to understand, including answers to questions such as the following: (1) Are the requirements in the rule clearly stated? (2) Does the rule contain technical language or jargon that interferes with its clarity? (3) Does the format of the 56 rule (grouping and order of sections, use of headings, paragraphing, etc.) aid or reduce its clarity? (4) Would the rule be easier to understand if it were divided into more (but shorter) sections? (A “section” appears in bold type and is preceded by the symbol “§ ” and a numbered heading; for example, § 204.200 What is the purpose of this part?) (5) Is the description of the rule in the SUPPLEMENTARY INFORMATION section of the preamble helpful in understanding the proposed rule? What else could we do to make the rule easier to understand?

Send a copy of any comments that concern how we could make this rule easier to understand to: Office of Regulatory Affairs, Department of the Interior, Room 7229, 1849 C Street NW., Washington, DC 20240. You may also e-mail the comments to this address: Exsec@ios.doi.gov.

For the reasons set forth in the preamble, subpart C of part 206 and subpart B of part 210 of title 30 of the Code of Federal Regulations are amended as follows:

1. The authority for part 206 continues to read as follows:

2. Section 206.101 is amended as follows:

A. In the definition of “affiliate” in paragraph (2), the words “between 10 and 50 percent” are removed and the words “10 through 50 percent” are added in their place.

B. The definition of “index pricing” is removed.

C. The definition of “index pricing point” is removed.

D. The definition of “MMS-approved publication” is revised.

E. A new definition of “NYMEX price” is added in alphabetical order.

F. A new definition of “prompt month” is added in alphabetical order.

G. A new definition of “roll” is added in alphabetical order.

H. The definition of “spot price” is removed.

I. The definition of “trading month” is revised.

J. A new definition of “WTI differential” is added in alphabetical order.

The additions and revisions to § 206.101 read as follows:

On December 8, 1989, (54 FR 50709) the Corps issued final regulations at 33 CFR 326.6 for procedures for the initiation and administration of Class I administrative penalty orders under section 309(g) of the Clean Water Act and section 205(e) of the National Fishing Enhancement Act. Under section 309(g) of the Clean Water Act, Class I civil penalties can be assessed for violations of the conditions and limitations of permits issued under section 404 of the Clean Water Act. Under section 205(e) of the National Fishing Enhancement Act, Class I civil penalties can be assessed for violations of permits issued section 10 of the Rivers and Harbors Act of 1899 and/or section 404 of the Clean Water Act for the construction and management of artificial reefs. Our current regulations at 33 CFR 326.6(a)(1) reflect the Class I civil penalty amounts stated in those statutes.

As stated in 33 CFR 326.6(a)(1), Class I civil penalties under section 309(g)(2)(A) of the Clean Water Act cannot exceed $10,000 per violation, with a maximum Class I civil penalty of $25,000. In that subsection, the Class I civil penalty for a violation of a permit issued in accordance with section 205 of the National Fishing Enhancement Act cannot exceed $10,000 for each violation.

According to section 4 of the Federal Civil Penalties Inflation Adjustment Act of 1990, as amended, each Federal agency is required to adjust for inflation the maximum civil monetary penalties that can be imposed pursuant to that agency's statutory authorities.

Under section 6 of the Federal Civil Penalties Inflation Adjustment Act of 1990, as amended, the initial adjustment is limited to 10 percent of the civil penalty amount. Since we have not made any inflation adjustments for the Class I civil penalties since 33 CFR 326.6 was promulgated in 1989, we are limited to a 10 percent increase for these civil penalties. Therefore, we are proposing to increase the Class I civil penalty for violations of the conditions and limitations of Clean Water Act section 404 permits to $11,000 per violation, with a $27,500 maximum penalty. We are also proposing to increase the Class I civil penalty for violations of permits for the construction and management of artificial reefs under section 205 of the National Fishing Enhancement Act of 1984 to $11,000 per violation.

In compliance with the principles in the President's Memorandum of June 1, 1998, regarding plain language, this preamble is written using plain language. The use of “we” in this notice refers the Corps and the use of “you” refers to the reader. We have also used the active voice, short sentences, and common everyday terms except for necessary technical terms.

This action does not impose any new information collection burden under the provisions of the Paperwork Production Act, 44 U.S.C. 3501 et seq. The proposed rule adjusts our civil penalty amounts to comply with the requirements of the Federal Civil Penalties Inflation Adjustment Act of 1990, as amended. Therefore, this action is not subject to the Paperwork Reduction Act.

Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the 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 currently valid OMB control number. For the Corps regulatory program under section 10 of the Rivers and Harbors Act of 1899, section 404 of the Clean Water Act, and section 103 of the Marine Protection, Research and Sanctuaries Act of 1972, the current OMB approval number for information requirements is maintained by the Corps of Engineers (OMB approval number 0710-0003, which expires December 31, 2004).

Under Executive Order 12866 (58 FR 51735, October 4, 1993), the Corps must determine whether the regulatory action is “significant” and therefore subject to review by the Office of Management and Budget (OMB) and the requirements of the Executive Order. The Executive Order defines “significant regulatory action” as one that is likely to result in a rule that may:

(1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or Tribal governments or communities;

(2) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;

(3) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or

(4) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order.

Pursuant to the terms of Executive Order 12866, we have determined that the proposed rule is not a “significant regulatory action” because it does not meet any of these four criteria. The proposed rule adjusts the Class I civil penalty amounts for violations of permit conditions and limitations for activities that involve discharges of dredged or fill material into waters of the United States and/or the construction and management of artificial reefs in navigable waters.

Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires the Corps to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have Federalism implications.” The phrase “policies that have Federalism implications” is defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.”

The proposed rule does not have Federalism implications. We do not believe that adjusting the Class I civil penalties to account for inflation will have substantial direct effects on the States, on the relationship between the federal government and the States, or on the distribution of power and responsibilities among the various levels of government. The proposed rule does not impose new substantive requirements. In addition, the proposed change will not impose any additional substantive obligations on State or local governments since it is applicable only to permittees who violate the conditions and limitations of certain Corps permits. Therefore, Executive Order 13132 does not apply to this proposed rule.

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice-and-comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations and small governmental jurisdictions.

For purposes of assessing the impacts of this proposed rule on small entities, a small entity is defined as : (1) A small business based on Small Business Administration size standards; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; or (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.

After considering the economic impacts of the proposed rule on small entities, we believe that this action will not have a significant economic impact on a substantial number of small entities. Currently, the Corps regulations at 33 CFR 326.6 set the Class I civil penalties under section 309(g)(2)(A) at no more than $10,000 per violation, with a maximum of $25,000. The current Class I civil penalties under section 205 of the National Fishing Enhancement Act can be up to $10,000 per violation. The proposed rule increases those Class I civil penalties by 10 percent, in accordance with the Federal Civil Penalties Inflation Adjustment Act of 1990, as amended. The proposed rule is consistent with current agency practice, does not impose new substantive requirements, and therefore would not have a significant economic impact on a substantial number of small entities.

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 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, the agencies 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, and Tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. Before promulgating a rule for which a written statement is needed, section 205 of the UMRA generally requires the agencies to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows the Corps to adopt an alternative other than the least costly, most cost-effective, or least burdensome alternative if the agency publishes with the final rule an explanation why that alternative was not adopted. Before the Corps establishes any regulatory requirements that may significantly or uniquely affect small governments, including Tribal governments, they must have developed under section 203 of the UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements.

We have determined that the proposed rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and Tribal governments, in the aggregate, or the private sector in any one year. Currently, in 33 CFR 326.6, the Class I civil penalties under section 309(g)(2)(A) of the Clean Water Act may not exceed $10,000 per violation, with a $25,000 maximum. A Class I civil penalty under section 205(e) of the National Fishing Enhancement Act may not exceed $10,000 for each violation. The proposed rule adjusts those civil penalties, through 10 percent increases, to account for inflation, as required by the Federal Civil Penalties Adjustment Act of 1990, as amended. The proposed rule is consistent with current agency practice, does not impose new substantive requirements and therefore does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and Tribal governments, in the aggregate, or the private sector in any one year. Therefore, the proposed rule is not subject to the requirements of sections 202 and 205 of the UMRA. For the same reasons, we have determined that the proposed rule contains no regulatory requirements that might significantly or uniquely affect small governments. Therefore, the proposed rule is not subject to the requirements of section 203 of UMRA.

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (the NTTAA), Pub. L. 104-113, section 12(d) (15 U.S.C. 272 note) directs us to use voluntary consensus standards in our regulatory activities, unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. The NTTAA directs us to provide Congress, through OMB, explanations when we decide not to use available and applicable voluntary consensus standards.

The proposed rule does not involve technical standards. Therefore, we did not consider the use of any voluntary consensus standards.

Executive Order 13045, “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997), applies to any rule that: (1) Is determined to be “economically significant” as defined under Executive Order 12866, and (2) concerns an environmental health or safety risk that we have reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, we must evaluate the environmental health or safety effects of the proposed rule on children, and explain why the regulation is preferable to other potentially effective and reasonably feasible alternatives.

The proposed rule is not subject to this Executive Order because it is not economically significant as defined in Executive Order 12866. In addition, it does not concern an environmental or safety risk that we have reason to believe may have a disproportionate effect on children.

Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 6, 2000), requires agencies to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” The phrase “policies that have tribal implications” is defined in the Executive Order to include regulations that have “substantial direct effects on one or more Indian tribes, on the relationship between the Federal government and the Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes.”

The proposed rule does not have tribal implications. It will not have substantial direct effects on tribal governments, on the relationship between the Federal government and the Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes. Currently, in 33 CFR 326.6, the Class I civil penalties under section 309(g)(2)(A) of the Clean Water Act may not exceed $10,000 per violation, with a $25,000 maximum for any Class I civil penalty. In that subsection of the Corps regulations, a civil penalty under section 205(e) of the National Fishing Enhancement Act may not exceed $10,000 for each violation. The proposed rule adjusts those civil penalties through a 10 percent increase to account for inflation, as required by the Federal Civil Penalties Adjustment Act of 1990, as amended. It is generally consistent with current agency practice and does not impose new substantive requirements. Therefore, Executive Order 13175 does not apply to this proposed rule.

The Corps prepares appropriate environmental documentation, including Environmental Impact Statements when required, for all permit decisions. Therefore, environmental documentation under the National Environmental Policy Act is not required for this proposed rule. The proposed rule only revises our Class I civil penalties to account for inflation, as required by the Federal Civil Penalties Adjustment Act of 1990, as amended. Appropriate environmental documentation has been, or will be, prepared for each permit action that is subjected to the Class I administrative penalty process.

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. We will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States. A major rule cannot take effect until 60 days after it is published in the Federal Register. The proposed rule is not a “major rule” as defined by 5 U.S.C. 804(2).

Executive Order 12898 requires that, to the greatest extent practicable and permitted by law, each Federal agency must make achieving environmental justice part of its mission. Executive Order 12898 provides that each Federal agency conduct its programs, policies, and activities that substantially affect human health or the environment in a manner that ensures that such programs, policies, and activities do not have the effect of excluding persons (including populations) from participation in, denying persons (including populations) the benefits of, or subjecting persons (including populations) to discrimination under such programs, policies, and activities because of their race, color, or national origin.

The proposed rule is not expected to negatively impact any community, and therefore is not expected to cause any disproportionately high and adverse impacts to minority or low-income communities. The proposed rule relates solely to the adjustments to Class I civil penalties under section 309(g)(2)(A) of the Clean Water Act and section 205(e) of the National Fishing Enhancement Act to account for inflation.

The proposed rule is not a “significant energy action” as defined in Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The proposed rule relates solely to the adjustments to Class I civil penalties under section 309(g)(2)(A) of the Clean Water Act and section 205(e) of the National Fishing Enhancement Act to account for inflation. The proposed rule is consistent with current agency practice, does not impose new substantive requirements and therefore will not have a significant adverse effect on the supply, distribution, or use of energy.

For the reasons set forth in the preamble, the Corps is proposing to amend 33 CFR 326.6(a)(1) as follows:

The Cost Accounting Standards Board's rules, regulations and Standards are codified at 48 CFR chapter 99. The Office of Federal Procurement Policy Act, 41 U.S.C. 422(g)(1), requires the Board, prior to the establishment of any new or revised Cost Accounting Standard, to complete a prescribed rulemaking process. The process generally consists of the following four steps:

1. Consult with interested persons concerning the advantages, disadvantages and improvements anticipated in the pricing and administration of government contracts as a result of the adoption of a proposed Standard (e.g., promulgation of a Staff Discussion Paper.)

2. Promulgate an Advance Notice of Proposed Rulemaking (ANPRM).

3. Promulgate a Notice of Proposed Rulemaking (NPRM).

4. Promulgate a Final Rule.

This ANPRM is issued by the Board in accordance with the requirements of 41 U.S.C. 422(g)(1)(B) and (C), and, is step two of the four-step process.

The CAS and Federal Acquisition Regulation (FAR) have dealt with issues associated with ESOPs ever since ESOPs became popular in the late 1970s as a vehicle for providing incentive compensation to employees, as well as a means for corporations to finance their capital requirements. The popularity of ESOPs was greatly enhanced by their inclusion in the Employee Retirement Income Security Act of 1974 (ERISA) and by several beneficial changes to the Federal Income Tax Code in that same time period.

At first, the issues that arose were regarded as allowability matters that were to be treated in the FAR (or one of its predecessors, the Defense Acquisition Regulations or Armed Services Procurement Regulations). The views of the CASB were sought primarily on an advisory basis. However, after issuance of the decision of the Armed Services Board of Contract Appeals (ASBCA) in the “Parsons case,” Ralph Parsons Co., ASBCA Nos. 37391, 37946, and 37947, December 20, 1990, 91-1 BCA 23648, reconsideration denied 91-2 BCA 23751, various government commenters suggested to the CASB that ESOP cost measurement and period assignment matters warranted placement on the CASB's agenda. These suggestions were amplified in light of the decision of the ASBCA in Ball Corp., ASBCA No. 49118, April 3, 2000, 00-1 BCA 30864. This position has been reiterated both by the Department of Defense and by some contractors.

The Board first considered issuing an Interpretation of its existing Standards, but then decided that additional research was needed. Various approaches for dealing with ESOP accounting issues were considered by the CASB and other interested parties in the late 1990s. On September 15, 2000, the Board issued a Staff Discussion Paper (SDP) on this topic (65 FR 56008, Sept. 15, 2000).

After the Board reviewed and discussed the public comments received in response to the Staff Discussion Paper, the staff was asked to perform additional research. The staff explored three different options: (a) Modify CAS 9904.415 so that the contribution to the ESOP could be treated as deferred compensation for government contract costing purposes; (b) Develop a separate Standard based on the “contribution approach;” and, (c) Develop a separate Standard based on Generally Accepted Accounting Principles (GAAP). The Board has tentatively decided to proceed with option (a).

The Board received sixteen (16) sets of public comments in response to the Staff Discussion Paper.

These comments came from contractors, government agencies, professional associations, industry associations, and individuals.

The majority of respondents agreed on several issues related to ESOPs for government contract costing purposes:

1. Generally Accepted Accounting Principles (GAAP), in particular SOP 93-6, do not provide adequate guidance for measuring ESOP costs.

2. There should be no distinction between “pension” and “deferred compensation” ESOPs in the measurement of ESOP costs.

3. The fair value of the stock should be established when title to the stock is transferred to the ESOP.

4. ESOP costs should be measured by the cost incurred by the contractor rather than the value of compensation received by employees.

5. The form of payment used to make distribution of ESOP benefits to employees is not relevant to the measurement of a contractor's ESOP costs.

There was, however, no strong consensus as to whether CAS 9904.412 or 9904.415 (or both) should be amended, or whether a new Standard should be adopted regarding ESOP costs.

This proposal is based upon continuing research performed by the staff of the Cost Accounting Standards Board, public comments received in response to the SDP, and deliberations of the Board. The various comments and proposals are discussed in greater detail under Section E, Public Comments. The Board would like to thank all the organizations and individuals who provided comments and information in response to the Staff Discussion Paper.

While there have been distinctions drawn in the past between “pension” and “deferred compensation” ESOPs, the Board has concluded that all ESOP costs should be treated consistently as deferred compensation.

Based on the comments received in response to the Staff Discussion Paper, the Board has also determined that specific guidance is required regarding the measurement of ESOP contributions and the assignment of ESOP costs to cost accounting periods. Specifically, the Board believes that the contractor's ESOP cost should be measured by the contribution made to the ESOP, not by the value of compensation received by the employee. In addition, the Board believes that these costs should be systematically assigned to the cost accounting periods in which ESOP awards are made to employees.

CAS has never explicitly dealt with the cost of ESOPs. These costs can be significant. However, there have been numerous efforts by contracting parties to apply the provisions of existing CAS, principally CAS 9904.412 and 9904.415, to the ESOP cost determination process. These efforts have resulted in a distinction between “pension ESOPs” and “deferred compensation ESOPs” in Government contract cost accounting. This distinction is not recognized in other fields of accounting.

Historically, many controversies regarding accounting for ESOP costs have been resolved at the local level by entering into an advance agreement between the contracting parties. Nevertheless, this is a cost accounting issue that has not been adequately dealt with within the framework of existing CAS. The Board recognizes that the diversity of current practices is not conducive to uniformity and consistency in cost measurement, assignment, or allocation of costs—the stated objectives of CAS.

The Board believes that these amendments will lead to a significant increase in uniformity and consistency in this important area of contract cost measurement. The Board also believes that the benefits of such improvements in contractor cost accounting practices should be substantial, and should greatly outweigh any added costs.

The proposed amendments make clear that all ESOP cost determinations will become subject to CAS 9904.415. In addition, CAS 9904.412 is proposed to be amended to exclude the coverage of the costs of ESOPs that meet the definition of a pension plan.

The proposed amendments adopt the “contribution” approach for ESOP cost measurement. Using this approach, contractors' contributions to ESOPs for a cost accounting period become the basis for ESOP cost determination. That part of the contribution that is assignable to the cost accounting period would be recognized as deferred compensation cost for the period. This recognition as an assignable cost is, in turn, based on the identification of ESOP awards that have been made to employees during the period that qualify as deferred compensation in accordance with the corresponding definition incorporated in the Standard. In essence, the ESOP costs assignable to a cost accounting period are that part of the annual contribution that is attributable to the awards made to employees during the period.

The proposed transition method is designed to ensure that the adoption of this proposal will not cause changes to existing arrangements that contracting parties may have developed to deal with their existing ESOP cost determinations. In particular, the intent is that contractor/government advance agreements for existing ESOPs should not be disturbed. The emphasis is on making sure the procedures incorporated in this proposal are applied only to the measurement, assignment and allocation of costs of new ESOPs that are established after this proposal becomes effective, if ultimately adopted by the CASB.

The Paperwork Reduction Act, Public Law 96-511, does not apply to this proposal, because these amendments impose no paperwork burden on offerors, affected contractors and subcontractors, or members of the public which requires the approval of OMB under 44 U.S.C. 3501, et seq. The records required by this proposed rule are normally maintained by contractors that claim reimbursement of ESOP costs under government contracts.

Because the transition provision incorporated into this proposal ensures that arrangements for determining costs for existing ESOPs are not changed, the economic impact of these amendments, if any, on contractors is expected to be minor.

As a result, the Board has determined that this rule will not result in the promulgation of a “major rule” under the provisions of Executive Order 12866, and that a regulatory impact analysis will not be required. Furthermore, this proposal does not have a significant effect on a substantial number of small entities because small businesses are exempt from the application of the Cost Accounting Standards. Therefore, this rule does not require a regulatory flexibility analysis in accordance with the Regulatory Flexibility Act of 1980.

This proposal is based upon responses to the CASB SDP entitled “Accounting for the Cost of Employee Stock Ownership Plans” that was published in the Federal Register on September 15, 2000 (65 FR 56008). Altogether, 16 responses were received, classified as follows:

The SDP asked six specific questions and the responses to these questions are discussed below. In addition to these responses, several commenters submitted additional comments on topics not covered directly by the six questions; others summarized in general terms the more significant features of their detailed responses. The comments received and the Board's actions are summarized below.

Does GAAP (SOP 93-6) provide sufficient guidance for accounting for the costs of ESOPs for Government contract costing purposes? Please discuss the rationale of your answer to this question.

Comments: Thirteen commenters acknowledged that SOP 93-6 does not provide adequate guidance for accounting for ESOPs for Government contracting purposes. Most of these commenters recognized that GAAP is not intended to address Government contracting issues.

Nevertheless, three of these commenters, the National Defense Industrial Association (NDIA), Boeing and Darrell J. Oyer & Co., recognized that GAAP contains some useful guidance. One of these commenters, Darrell J. Oyer & Company, explains this as follows:

Two commenters, McDermott, Will & Emery and the Project on Government Oversight (POGO), thought that GAAP may provide adequate guidance for Government contract costing purposes. McDermott, Will & Emery commented favorably on the comprehensive treatment of the topic in SOP 93-6 and then stated that if “* * * the cost accounting standards for government contracts purposes were to differ materially from the requirements of SOP 93-6, contractors could be placed in an extremely awkward, illogical, and perhaps untenable position.” This commenter also pointed out that any deviation from GAAP would require companies to keep two sets of books.

POGO expressed concerns about differing treatments for pension and deferred compensation ESOPs, valuation of shares acquired by ESOPs, and interest expense incurred by leveraged ESOPs as areas of potential abuse. POGO was principally concerned with the apparent current practice in Government contract cost accounting where “* * * interest expense may be passed on to contractors (and ultimately taxpayers) as a form of “employee compensation.” POGO contrasted this practice with SOP 93-6 requirements that stipulate that “* * * interest expense incurred in financing leveraged ESOPs is clearly reflected on financial statements as such.”

However, POGO characterized its opinion that contractors should be required to account for ESOP costs using SOP 93-6, as “tentative.” POGO stated:

Response: The CAS Board recognizes that there are instances when GAAP is not appropriate for measuring costs on Government contracts. This is due, in part, to significant differences between the objectives of CAS and those of GAAP. CAS seeks to promote consistency and uniformity in the measurement, assignment and allocation of costs on Government contracts, while the broad objectives of GAAP relate to the fair presentation of income, cash flows, assets, liabilities and stockholders' equity in financial statements. GAAP does not embrace the CAS concern for appropriate accumulation and estimating of costs to specific cost objectives. The CAS Board believes that ESOPs are an instance where GAAP would be inappropriate for determining costs on Government contracts for the following reasons:

1. For contract costing purposes, the Government recognizes and reimburses a contractor's actual costs, as defined at 48 CFR 9904.401-30(a)(2). As stated in the May 1992 CASB “Restatement of Objectives, Policies and Concepts” (57 FR 31036), the Standards are intended to “provide criteria for the allocation to cost objectives of the costs of resources used.” In the case of ESOPs, the costs of resources used are the amount of the company's contribution to the ESOP. The contribution represents the contractor's actual total costs to acquire shares that are awarded to employees; that is, the amount of contractor resources used to provide the deferred compensation to the employee. The value of the stock at distribution to employee accounts generally does not reflect a contractor's actual costs.

2. The cost for a leveraged ESOP measured using GAAP changes from period to period based on fluctuations in stock prices. The Government should not share in fluctuations of stock prices, whether up or down, that occur during the period between the time when an ESOP trust originally acquires shares and when those shares are distributed to employee accounts. The policy that the Government should not participate in the fluctuation of stock prices is already embodied in CAS 9904.415 related to stock options. The Preamble to CAS 9904.415, states:

3. Congressional intent is to encourage the use of ESOPs. However, if the measurement date prescribed by GAAP were used for Government contracting purposes, it would significantly limit the use of leveraged ESOPs by Government contractors, particularly contractors whose stock is not widely traded. Government contractors could still use ESOPs, but would potentially suffer from financial disadvantages if leveraging caused a material effect on a company's debt to equity ratio. Often the establishment of a leveraged ESOP adversely affects a company's debt to equity ratio since the value of the company's stock may drop significantly after the leveraged ESOP is established due to the ESOP debt recognized on a contractor's books. Over a period of time, as the debt is paid off, the value of the stock can be expected to return to pre-ESOP levels. In the commercial marketplace, where the price a company receives for its product is not totally based on actual costs incurred, the company does not necessarily have to reduce the price of its products to reflect smaller deferred compensation awards resulting from the drop in stock value. This is not the case with Government cost-based contracting, since the contractor is only reimbursed for its actual costs incurred.

If GAAP were to be adopted for measuring the cost of a leveraged ESOP, the fair value of stock would become the basis for reimbursement of ESOP costs under Government contracts. Since the fair value of stock of Government contractors, whose stock is not widely traded, is lower after the initiation of a leveraged ESOP, the use of GAAP measurement requirements would impair those Government contractors' ability to recover sufficient monies to cover the debt payment of the leveraged ESOP.

The CAS Board notes there was consensus among the respondents to its SDP that the cost of ESOPs should be measured as the amount of the contractor's total contribution.

Do you believe that distinguishing between “pension” and “deferred compensation” ESOP type is useful in the Government contract costing environment and that this feature should be included in any future CAS promulgation on this topic? Please include the rationale for your answer to this question.

Comments: With one exception (the DOD Inspector General), all commenters agreed that the distinction between “pension” and “deferred compensation” ESOPs serves no useful purpose. They described such distinction as either irrelevant, confusing, meaningless, artificial, specious or not useful. McDermott, Will & Emery described the relevance of the distinction as follows:

The Section of Public Contract Law of the American Bar Association (ABA) and Abt Associates Inc. attributed the concept of different types of ESOPs to a Government attempt to disallow interest costs related to ESOP financing. This view was expressed by the Public Contract Law Section of the ABA:

The DOD Inspector General (DOD IG) provided the following comments in support of its argument that there should be a distinction in the treatment of “pension” and “deferred compensation” ESOPs for Government contract costing purposes:

The Board notes that Boeing recognized that a uniform approach is needed for all ESOPs for cost measurement purposes, but was not specific as to the section of CAS that should be amended for that purpose. Although, the DOD IG stated that a distinction should be made between “pension” and “deferred compensation” ESOPs for Government contract costing purposes, several other commenters, including DynCorp and AIA, indicated that the “status quo” is acceptable and no further action by the Board is needed. Since the current practice recognizes, in effect, a distinction between these two types of ESOPs, then acceptance of the “status quo” would also imply that these commenters believe that distinguishing between the two types of ESOPs would be useful in the government contract costing environment. Therefore, the notion that there are two different types of ESOPs, “pension” and “deferred compensation” ESOPs, may have more support than indicated by the sole affirmative response received to this question.

Response: It is widely recognized that the two different types of ESOPs, “pension” and “deferred compensation” ESOPs, are recognized only in the Government contract costing environment. The Government was compelled to make this distinction as the result of the ASBCA's decision in Ralph Parsons Co., supra. The ASBCA held that since FAR 31.205-6(j)(8) (ESOPs) is included in the pension section of the cost principle, it does not apply to ESOPs that do not meet the definition of a pension. Therefore, those ESOPs that do not meet the definition of a pension are considered to be deferred compensation covered by FAR 31.205-6(k), which incorporates CAS 9904.415 in its entirety.

The DOD IG's comments about qualified pensions refer to ERISA, not to CAS. The only distinction between pensions and deferred compensation in the CAS is the requirement that pension benefits be payable for life. This distinction is not found in ERISA. The Board does not agree that ERISA qualification for pension plans should be the sole determining factor for which CAS should be applied in the measurement and assignment of ESOP costs for Government contracting purposes.

The Board agrees with the majority of commenters that no distinction should be made between “pension” and “deferred compensation” ESOPs in measurement and assignment of cost. Therefore, the proposed amendments would eliminate this distinction in the measurement and assignment of ESOP costs. As a consequence, a significant step will be taken to improve uniformity and consistency in the cost accounting practices among Government contractors in like circumstances—a primary objective of the Board. Furthermore, the current differences in the recognition and measurement of the interest element in the ESOP cost calculations among the two different types of ESOPs will be eliminated.

In summary, the Board proposes that CAS 9904.412 be amended to ensure that no ESOP is subject to the provisions of that Standard. At the same time, it is proposed that CAS 9904.415 be amended so that all the ESOPs become subject to that Standard.

If you believe that a distinction between ESOP types is useful and should be included in any future CAS promulgations, do you also believe that amendments, or an interpretation, to CAS 9904.412 and/or CAS 9904.415 is the appropriate action for the Board to take?

Comments: Since in response to Question 2, only one commenter indicated that a distinction between ESOP types is useful, it might have been expected that a single response would be obtained to this question. However, a total of nine commenters provided their opinion as to which Standard should be changed. Of the remaining seven commenters, five responded that no amendments or clarifications to either CAS 9904.412 or 9904.415 are required, and the other two (ESOP Association and Abt Associates Inc.) provided no specific response to this question.

Of the nine commenters who recommended that changes are required, three stated that CAS 9904.415 should be amended (DOD, ABA and POGO); two believe that CAS 9904.412 should be amended (Parsons, Brinkerhoff and United Technologies), three expressed no preference as to which standard should be amended (NDIA, Darrell J. Oyer & Co., and McDermott, Will & Emery); and one (the DOD IG) recommended that both CAS 9904.412 and 9904.415 be amended.

In addition, two commenters (United Technologies and DynCorp), who consider ESOPs defined contribution plans, believe that, given the Ball decision, CAS 9904.412 and 9904.415 would produce the same results.

The Boeing response reflects the view of the five commenters who thought that no amendments to existing Standards are required (Boeing, Lockheed Martin, AIA, ALCOA, DynCorp):

We believe the current provisions of CAS 9904.412 and 9904.415 are adequate if properly interpreted. If clarification is desired to avoid interpretive disputes, amendments or interpretations to existing standards could be useful * * *.

Response: The purpose of this question was to solicit opinions as to what format any Board action in this area should take. However, the responses that were obtained varied greatly and did not clearly point to any specific course of action.

Regarding the main thrust of the question, whether it would be more appropriate to deal with ESOPs under CAS 9904.412 or 9904.415, the Board believes that ESOPs have more in common with deferred compensation plans than with pension plans. Therefore, the Board proposes amendments to CAS 9904.415 to provide for the measurement and assignment of ESOP costs, and to CAS 9904.412 to clearly state that it is not applicable to ESOPs, including those plans which provide benefits that are “payable for life.”

Do you believe that the fair value of the shares released by an ESOP to individual employee accounts should be established at the date when the title to these shares is transferred to the ESOP or should it be the date when the shares are committed to be released to employee accounts? If you would like to propose a different date or a modified version of the two dates referred to above, please explain.

Comments: The majority of commenters (13 of 16) indicated that for shares transferred to an ESOP trust, the fair value should be established at the date when the title to these shares is transferred to the trust. Several commenters expanded on this basic response. It was frequently stressed that the contribution to the trust could be in the form of cash as well as shares, and thus, the critical date should be the date when an irrevocable transfer is made to the trust either in cash or in stock. These commenters, including two Government agencies, probably would agree with the following, rather general, statement made by Parsons Brinkerhoff:

McDermott, Will & Emery, however, does not agree with this type of response and indicated that the CAS Board should strive for conformance with GAAP and, in particular, with SOP 93-6. McDermott, Will & Emery believes that the proper valuation date should be the date when the shares are committed to be released to employee accounts. McDermott, Will & Emery stated:

Response: The Board agrees with the majority of commenters and is proposing to adopt the “contribution” approach to ESOP cost accounting as the best measure of a contractor's cost to provide the ESOP benefit awarded to employees. Therefore, the value of shares transferred to an ESOP should be established as of the date when the title to the shares is transferred to the trust.

The Board also notes that in adopting this approach, risks associated with changes in the market value of stock or property subsequent to the date the title to such stock or property is transferred to the ESOP, either up or down, are borne by the ESOP trust. From this perspective, the government does not bear any risk or perceived conflict of interest associated with share price fluctuations after the contribution has been made as pointed out by Lockheed Martin. This is consistent with the current CAS 9904.415 provision regarding stock options.

The Board believes that any other measurement date, such as that suggested by McDermott, Will & Emery, would not reflect the contractor's cost in providing the ESOP benefit and would, therefore, be inappropriate for the measurement of costs for government contracting purposes. McDermott, Will & Emery's rationale is based on its desire to avoid differences between financial accounting and contract cost accounting. As discussed in the Board's response to Question 1, GAAP are not appropriate for determining ESOP costs on Government contracts.

For contract costing purposes, should a distinction be made between measurement of the “cost to the company” or measurement of compensation “received by the employee?” Please explain. If a distinction should be made, please also comment on the method that should be used to measure this amount.

Comments: All the commenters who responded to this question either stated directly or implied that a distinction should be made between measurement of “cost to the company” and the measurement of “compensation received by the employee.” With one exception (McDermott, Will & Emery), they also all stated that the proper measurement should be the “cost to the company.” The line of thought of this majority is exemplified by the following two quotes. First, NDIA stated:

The same point of view, in different words, was also expressed by the Public Contract Law section of the ABA:

McDermott, Will & Emery disagreed with the majority response stating that GAAP should prevail for the purpose of Government contract cost accounting in order to maintain consistency between financial and Government contract reporting and to increase contractors' profitability. At the same time, their comments cited a potential weakness in the GAAP methodology for financial reporting purposes. The commenter's justification for this position is stated as follows:

The scenario that could prove to be detrimental to a contractor under such circumstances is further described by the commenter in response to another question:

Response: The Board agrees with the majority of commenters that a distinction exists between measurement of the “cost to the company” and the measurement of “compensation received by the employee.” The Board has determined that the relevant concept in the measurement of ESOP costs for Government contracts is the “cost to the company.” Therefore, the Board proposes adoption of the “contribution”pproach to ESOP cost measurement.

Regarding the comments of McDermott, Wills & Emery, the Board notes that the use of the “compensation received by the employee” as the measurement of ESOP costs could result in the reimbursements to contractors in excess of their actual costs as defined at CAS 9904.401-30(a)(2). The commenter would have the Board believe that failure to adopt GAAP will unfairly penalize contractors by reducing their revenues. However, under cost-type Government contracts it is intended that the contractor be reimbursed actual costs and, in addition, be paid a negotiated profit. In the commenter's example, the costs submitted by the contractor for reimbursement would not constitute actual costs incurred, but could include amounts in excess of actual costs. Such inflated amounts would represent additional profit to the contractor, not reimbursement of a contractor's costs. In the subject example, total profit would be enlarged beyond that contemplated in contract negotiations. This enlargement would be contrary to the intent of the contracting parties and would result in increased costs to the Government in the form of a “windfall” profit to the contractor. Conversely, if McDermott, Will & Emery's example is changed to reflect a decrease in the price of a company's stock since the shares were acquired by the ESOP, in accordance with GAAP, the company would be reimbursed only for the decreased value of the shares under Government contracts and would likely not recover its actual costs incurred. In such a situation the contractor would be unfairly penalized by reduced profitability and decreased working capital.

Should the form of payment of ESOP benefits to the employee make a difference in measuring the cost allocable to Government contracts? If so, how should the cost be determined?

Comments: All of the fourteen commenters who responded to this question were unanimous in their conclusion that the form of payment of ESOP benefits should make no difference in measuring the cost allocable to Government contracts. This response from DOD is fairly typical:

Response: The Board agrees with the commenters that the form of payment to employees should not make any difference to the ESOP cost measurement process for government contract costing purposes. The Board notes that neither the value nor form of distribution of ESOP awards to employees determines the contractor's cost of providing the ESOP benefit.

Comments: Several commenters stressed the public policy aspect of ESOPs and, in particular, Congressional support for these plans. These commenters seem to suggest that any Standard on this topic should not interfere with the original Congressional intent of encouraging employee ownership through ESOPs.

Response: The Board believes that the proposed amendments to CAS 9904.415 would not interfere with the intent of Congress.

Comments: Another theme included in the comments was that whatever problems there might have been a few years ago with ESOP cost measurement, these issues have been, in effect, clarified and resolved by the ASBCA in its decision in Ball Corporation, supra.

Lockheed Martin Corporation summarized this point of view as follows:

Response: The Board believes that clarification of the measurement and assignment of ESOP costs is needed to promote uniformity and consistency in accounting for ESOP costs, despite the decision in Ball Corporation, supra. That decision did not address the contribution method of measuring ESOP costs incorporated into these proposed amendments. The ASBCA's decision in that case was limited to a determination that the fundamental requirements of the measurement criteria in CAS 9904.415-40(b) had been met by the contractor, that neither CAS 9904.415-50(d) or (e) was applicable in that instance, and that the Government had not demonstrated that the contractor's ESOP contributions failed to represent the present value of the future benefits.

Interested persons are invited to participate by submitting data, views, or arguments with respect to this ANPRM. All comments must be in writing and submitted in accordance with the instructions indicated in the ADDRESSES section.

Accordingly, for the reasons set forth in the preamble, it is proposed to amend part 9904 as follows:

The Magnuson-Stevens Fishery Conservation and Management Act requires NMFS and the Council to identify EFH in fishery management plans. The EFH regulations at 50 CFR 600.815(a)(8) encourage Councils to identify HAPCs within EFH based on the ecological importance of the habitat, sensitivity to human-induced environmental degradation, stress to the habitat from development activities, and/or rarity of the habitat.

On June 6, 2001, NMFS published a notice of intent to prepare an EIS for the EFH components of the following five management plans: the Fishery Management Plan (FMP) for the Groundfish Fishery of the Bering Sea/Aleutian Islands (BSAI) Area, the FMP for groundfish of the Gulf of Alaska, the FMP for BSAI Commercial King and Tanner Crabs, the FMP for the Scallop Fishery off Alaska, and the FMP for the Salmon Fishery in the EEZ off the Coast of Alaska (66 FR 30396). NMFS requested written comments and gave notice of six scoping meetings. NMFS noted that three types of actions will be analyzed in the EIS: (1) describe and identify EFH for the fisheries; (2) identify HAPCs within EFH; and (3) minimize to the extent practicable the adverse effects of fishing on EFH.

On January 10, 2002, NMFS published a notification of preliminary alternative approaches for EFH and HAPC and requested written comments (67 FR 1325). Subsequently, based on public comment at the April, 2003, Council meeting, NMFS and the Council determined that it would be most effective to identify an approach to HAPC designation first, and then to consider specific candidate HAPCs through a separate process. For this first iteration of the HAPC process, any resulting HAPC designations and associated fishery management measures would be promulgated on the same time line as any measures resulting from the EFH EIS. The Council may also consider additional HAPCs in the future.

The EFH EIS will evaluate five alternative approaches for identifying HAPCs. Under Alternative 1, the FMPs would be amended to remove the present identification of HAPCs. Under Alternative 2, HAPCs would remain as they are currently identified in the Council's FMPs: living substrates in shallow waters, living substrates in deep waters, and freshwater areas used by anadromous fish. Under Alternative 3, HAPC designations would be constrained to explicit geographically defined sites or locations, such as a particular seamount. Under Alternative 4, habitat types would be selected based on the HAPC considerations in the regulations, and HAPC sites would then be selected within the habitat types. Under Alternative 5, HAPC areas would be identified for individual FMP species based on the productivity of the habitat.

The timeline for completing the EFH EIS has been revised since the scoping meetings held in 2001. The current schedule is as follows: Council review of preliminary draft EIS from September 15 - October 14, 2003; Draft EIS published for public comments by January 16, 2004; public comment period on draft EIS no later than January 16 - April 15, 2004; Final EIS published by June 1, 2005; Record of Decision by August 14, 2005; any resulting FMP amendments and final regulations by August 13, 2006; concurrent HAPC process with any implementing regulations by August 13, 2006.