Royalty management: Oil value for royalty due on Federal leases; establishment,

 
CONTENT

[Federal Register: December 30, 1999 (Volume 64, Number 250)]

[Proposed Rules]

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From the Federal Register Online via GPO Access [wais.access.gpo.gov]

[DOCID:fr30de99-44]

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Part IV

Department of the Interior

Minerals Management Service

30 CFR Part 206

Establishing Oil Value for Royalty Due on Federal Leases; Proposed Rule

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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 206

RIN 1010-AC09

Establishing Oil Value for Royalty Due on Federal Leases

AGENCY: Minerals Management Service, Interior.

ACTION: Further supplementary proposed rule.

SUMMARY: The Minerals Management Service (MMS) is proposing further changes to its proposed rulemaking regarding the valuation, for royalty purposes, of crude oil produced from Federal leases. MMS is proposing to: eliminate MMS-published differentials; change the way that actual costs of transportation are calculated; change the definition of ``affiliate'' because of a judicial decision in a case decided after the close of the most recent comment period; issue binding value determinations; and add specific regulatory language regarding the issue of ``second-guessing'' a sale under an arm's-length contract. These amendments are intended to simplify and improve the proposed rule.

DATES: Submit comments on or before January 31, 2000.

ADDRESSES: Send your written comments to David S. Guzy, Chief, Rules and Publications Staff, Royalty Management Program, Minerals Management Service, P.O. Box 25165, M.S. 3021, Denver, Colorado 80225-0165; or e- Mail David__Guzy@mms.gov.

FOR FURTHER INFORMATION CONTACT: David S. Guzy, Chief, Rules and Publications Staff, Royalty Management Program, Minerals Management Service, phone (303) 231-3432, FAX (303) 231-3385, e-Mail David__Guzy@mms.gov.

SUPPLEMENTARY INFORMATION: The principal authors of this further supplementary proposed rule are David A. Hubbard and Deborah Gibbs Tschudy of the Royalty Management Program (RMP) and Peter Schaumberg and Geoffrey Heath of the Office of the Solicitor in Washington, D.C.

MMS is specifying a deadline for comments that is less than the 60 days recommended by Executive Order No. 12866. MMS believes that a 30- day comment period is appropriate in this instance because it previously extended and reopened the comment periods for several earlier proposed versions of this rule. MMS also held numerous workshops across the country to obtain public input on this proposed rulemaking. MMS also plans to hold public hearings during the 30-day comment period to give interested parties the opportunity to fully discuss and comment on this further supplementary proposed rule. MMS will publish specific dates and locations for the hearings in the Federal Register.

Most of the provisions in this supplementary proposed rule were in included in previous proposed rules. All of the comments we received thus far are part of the rulemaking record and MMS will consider all such comments before issuing a final rule. Therefore, it is unnecessary for commenters to resubmit earlier comments on provisions that are not proposed for further change. MMS requests that comments focus on the new proposals addressed in this supplementary proposed rule.

  1. Background

    This further supplementary proposed rule proposes changes to valuation rules in 30 CFR part 206 that have been in effect since March 1, 1988 (the 1988 rules).

    The 1988 rules were developed based on the concept that gross proceeds received under an arm's-length contract represented the best measure of the value of production for royalty purposes. Further, those rules implicitly assumed the existence of a competitive and transparent market at the lease (or in the field or area) that could be used to determine the value of production not sold at arm's-length.

    Characteristics of competitive markets include: (1) There is a large number of sellers, no one of whom commands a large share of the total market, (2) the products of different sellers are functionally identical and buyers have no preference among sellers, (3) there are so many buyers that sellers and buyers do not establish personal relationships with one another, and (4) buyers are perfectly informed about the prices of different sellers. In the context of particular leases or fields, generally there is not a large number of sellers. Further, one or a few of the producers in the lease or field often control a large share of the production sold. In addition, at the lease or field level, there are a limited number of buyers and sellers. Moreover, because of the proprietary nature of individual contract sales of crude oil, lessees usually will not know the prices at which other lease interest holders sell their oil. In other words, generally there is no price transparency at the lease or field level. None of the comments submitted throughout this nearly four-year rulemaking effort demonstrated that as a general rule a competitive market exists at the lease.

    The overall lack of a truly competitive market at the lease has been compounded by the significant changes that occurred in the domestic industry during the 1980's and early 1990's, which had a profound effect on how crude oil is marketed today. These changes included: (1) The major oil companies' creation of separate affiliates for production, marketing and refining; (2) overall decline in domestic production and increased dependence on foreign imports and influence of international trading practices on domestic supply; (3) sharply increased volatility of oil prices marked by the price collapse in early 1986 (the last year in which posted prices exceeded spot market prices), and the rapid rise and decline in prices in late 1990 and early 1991 in response to the Gulf War; (4) entry and expansion of resellers, traders, and brokers who bought, transported, and sold domestic crude oil, taking advantage of pricing and location discrepancies in much the same way they were doing on the international market; and (5) development of a futures market for crude oil which alleviated many of the risks of spot trading. While many of these factors may be seen as increasing the level of competition, none of them served to increase the level of price transparency (i.e., the ability to discern the prices actually paid) at the lease or field or to simplify application of the existing oil valuation rules.

    The 1988 rules placed heavy emphasis on posted prices as a measure of royalty value, particularly when valuing oil disposed of not at arm's-length and under no-sales conditions. Posted prices historically were the primary mechanism for pricing domestic crude oil before the 1980's. However, with the disruption of global petroleum supplies in the 1970's and decontrol of domestic crude oil prices in 1981, the domestic petroleum industry began moving away from posted prices and towards the spot and futures markets to buy and sell crude oil. In fact, studies commissioned by States and advice from MMS consultants (Innovation & Information Consultants, Inc.; Micronomics, Inc.; Reed Consulting Group; and Summit Resource Management, Inc.) found that: (1) sales prices are often above posted prices and are linked, in some form, to market prices, such as spot or futures prices, or represent premia over posted prices; (2) major producers have few truly outright sales; (3) most major producers use buy/sell exchanges; (4) there are regional differences in the

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    domestic crude oil market, particularly on the West Coast and in the Rocky Mountain Region, owing to differences in market concentration and availability of transportation options; and (5) posted prices have become a progressively less reliable indicator of the market value of crude oil since the late 1980s.

    Development of the futures market and comprehensive publication of spot prices increased the market transparency of crude oil clearing prices. As a result, market participants became less willing to accept long-term sales contracts at fixed prices and instead negotiated short- term contracts with sales prices linked to spot or futures prices or to premia over posted prices. Major oil companies, however, generally continued to pay royalties on their production transferred not at arm's-length based on posted prices.

    Recognizing that posted prices no longer reflected market value, State and private royalty owners in Alaska, California, Louisiana, New Mexico, and Texas brought lawsuits against several major oil companies over improper oil pricing and underpaid royalties. These lawsuits resulted in several oil companies paying additional royalties and some adjusting their posted prices to better reflect market value.

    The majority of Federal lease oil production in fact is not sold at arm's length at or near the lease. Most Federal lease oil production is either moved directly to a refinery without a sale or disposed of under an exchange agreement (e.g., buy/sell agreements) in which the lessee exchanges oil at one location for oil at another location. Exchange agreements frequently do not reference a price, but rather only the relative difference in the value of crude oils exchanged and thereby obscure the oil's actual market value. When the agreement does state a price but is conditioned upon the lessee's purchase of crude oil at a subsequent exchange point, the price specified in the exchange agreement does not represent the value of the oil. In a buy-sell exchange, the parties may state any base price they wish, because their primary concern is the difference in value between the oil sold and the oil purchased.

    This rulemaking proposes to amend the current regulations by eliminating posted prices as a measure of value and relying instead on arm's-length sales prices and spot market prices as market value indicators. Today, spot prices are readily available to industry participants via price reporting services, and these and similar prices play a significant role in crude oil marketing in terms of the basis upon which deals are negotiated and priced.

    Comments received so far during the rulemaking process made it apparent that regional differences exist in the domestic crude oil market. These differences are due in large part to geographic isolation of markets. Accordingly, this further proposed rule would establish different valuation procedures for three different regions: California and Alaska, the Rocky Mountain Region, and the rest of the country.

    This proposal adopts parts of the February 1998 proposal, but includes modifications contemplated in the outline published in the March 12, 1999 notice of reopening of public comment period and notice of workshops, and a variety of other modifications in response to public comments.

  2. History of This Rulemaking

    MMS published an advance notice of its intent to amend the 1988 rules on December 20, 1995 (60 FR 65610). The purpose of that notice was to solicit comments on new methodologies to establish the royalty value of Federal (and Indian) crude oil production in view of the changes in the domestic petroleum market and particularly the market's move away from posted prices as an indicator of market value. The comment period on this advance notice closed on March 19, 1996.

    Based on comments received on the advance notice, together with information gained from a number of presentations by experts in the oil marketing business, MMS published its initial notice of proposed rulemaking on January 24, 1997 (62 FR 3742). That proposal set out specific valuation procedures that focused on New York Mercantile Exchange (NYMEX) prices and Alaska North Slope (ANS) spot prices as value indicators, depending on the location of the production. It also clarified the lessee's duty to market the production at no cost to the Federal Government and required the lessee to use actual transportation costs instead of Federal Energy Regulatory Commission (FERC) tariffs for transportation allowances. The comment period for that proposal was to expire March 25, 1997, but was twice extended--first to April 28, 1997 (62 FR 7189), and then to May 28, 1997 (62 FR 19966). MMS held public meetings in Lakewood, Colorado, on April 15, 1997, and Houston, Texas, on April 17, 1997, to hear comments on the proposal.

    In response to the variety of comments received on the initial proposal, MMS published a supplementary proposed rule on July 3, 1997 (62 FR 36030). That proposal expanded the eligibility requirements for valuing oil disposed of under arm's-length transactions. The comment period on that proposal closed August 4, 1997.

    Because of the substantial comments received on both proposals, MMS reopened the rulemaking to public comment on September 22, 1997 (62 FR 49460). MMS specifically requested comments on five valuation alternatives arising from the public comments. The initial comment period for that request was to close October 22, 1997, but was extended to November 5, 1997 (62 FR 52518). During the comment period MMS held seven public workshops to discuss valuation alternatives: in Lakewood, Colorado, on September 30 and October 1, 1997 (62 FR 50544); Houston, Texas, on October 7 and 8, 1997, and again on October 14, 1997 (62 FR 50544); Bakersfield, California, on October 16, 1997 (62 FR 52518); Casper, Wyoming, on October 16, 1997 (62 FR 52518); Roswell, New Mexico, on October 21, 1997 (62 FR 52518); and Washington, D.C. on October 27, 1997 (62 FR 52518).

    As a result of comments received on the proposed alternatives and comments made at the public workshops, MMS published a second supplementary proposed rule on February 6, 1998 (63 FR 6113), applicable to Federal leases only. The comment period for this second supplementary proposed rule was to close on March 23, 1998, but was extended to April 7, 1998 (63 FR 14057). MMS held five public workshops (63 FR 6887) on the second supplementary proposed rule, as follows: Houston, Texas, on February 18, 1998; Washington, D.C. on February 25, 1998; Lakewood, Colorado, on March 2, 1998; Bakersfield, California, on March 11, 1998; and Casper, Wyoming, on March 12, 1998.

    Based on a request by Senator Breaux (Louisiana) to hold a meeting between industry and the Department of the Interior (DOI) to explain the direction DOI was going in the final rule, MMS once again opened the public comment period from July 9 through July 24, 1998. Two such meetings were held, on July 9 and July 22.

    On July 16, 1998, as a result of comments during the prior comment period, MMS published a further supplementary proposed rule that clarified some of the changes MMS intended to make when the proposed rule became final.

    Also, on July 21, Representatives Miller (California) and Maloney (New York) sponsored a meeting between DOI, States, the Indian community, and

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    multiple special interest groups. In that meeting DOI received a variety of comments in support of its efforts to move forward with the rule and against some of the changes promoted by industry.

    The July 22 meeting involved further discussion of industry's issues and recommendations regarding the proposed rule. MMS immediately developed written responses to each industry issue and recommendation based on its published statements in prior proposed rules. MMS also extended the comment period for the proposed rule until July 31 to permit comment on the industry recommendations and MMS's responses.

    On July 28, 1998, MMS and Departmental officials met with Senate staff members to further explain the content and rationale of the proposed rule. The notes from all of these meetings were posted on MMS's Internet Homepage for interested parties to review during the comment period.

    On August 31, 1998, the Assistant Secretary for Land and Minerals Management wrote a letter to members of the Senate outlining the direction the final rule might take on several of the major issues. On October 8, 1998, the President signed the FY 1999 Department of the Interior Appropriations Act that contained language extending the moratorium prohibiting MMS from publishing a final rule until June 1, 1999. On March 4, 1999, the Secretary announced a reopening of the comment period in response to requests by Members of Congress and parties interested in moving the process forward to publish a final rule. The MMS published a Federal Register Notice on March 12, 1999, reopening the comment period through April 12, 1999, and announced that it would hold public workshops in Houston, Texas; Albuquerque, New Mexico; and Washington, D.C. to discuss specific areas of the rule. The MMS extended the comment period through April 27, 1999, to provide commenters adequate time to provide comments following the workshops.

    The February 6, 1998, proposal, as modified by the July 16, 1998, further supplementary proposed rule and through consideration of all comments received during the rulemaking process, led to this further supplementary proposed rule.

    In the discussion below, we use the following conventions: the January 24, 1997, proposed rule is termed the January 1997 proposal; the July 3, 1997, supplementary proposed rule is termed the July 1997 proposal; the September 22, 1997, notice reopening the public comment period is termed the September 1997 notice; the February 6, 1998, second supplementary proposed rule is termed the February 1998 proposal; the July 16, 1998, further supplementary proposed rule is termed the July 1998 proposal; and the March 12, 1999, notice of reopening of public comment period and notice of workshops is termed the March 1999 notice.

  3. Summary and Discussion of Proposed Rule

    This proposed rule incorporates changes made in response to comments on the January 1997 proposal, the July 1997 proposal, the September 1997 notice, the February 1998 proposal, the July 1998 proposal, and the March 1999 notice. As in the February 1998 proposal, we also added and renumbered sections and further reorganized the rule for readability.

    Because this proposed rule is a product of changes made in response to comments received throughout this rulemaking, the preambles of each of the previous proposals and notices may be consulted in conjunction with this preamble to trace the evolution of this proposal.

    Note that the renumbering and reorganization for this proposal resulted in the following modifications to the existing rule:

    Section

    Modification

    Secs. 206.100 and 206.101................ Revised. Sec. 206.102............................. Revised and redesignated as Secs. 206.102, 206.103, 206.104, 206.105, 206.106, 206.107, and 206.108. Secs. 206.103 and 206.104................ Redesignated as Secs. 206.119 and 206.109, respectively. Sec. 206.105............................. Revised and redesignated as Secs. 206.110, 206.111, 206.114, 206.115, 206.116, 206.117, and 206.118. Sec. 206.106............................. Revised and redesignated as Sec. 206.120. New Secs. 206.112 and 206.113............ Added.

    In addition, we rewrote all sections of the existing rule in plain English so the entire rule would read consistently.

    Before proceeding with the summary and discussion of this proposal, it is necessary to explain further why MMS is not proposing further changes in certain areas.

    Duty to Market. It is a well-established principle that lessees have the obligation to market lease production for the mutual benefit of the lessee and lessor, without deduction for the costs of marketing. See, e.g., Walter Oil and Gas Corp., 111 IBLA 260 (1989); Arco Oil and Gas Co., 112 IBLA 8 (1989); Taylor Energy Co., 143 IBLA 80 (1998) (motion for reconsideration pending); Yates Petroleum Corp., 148 IBLA 33 (1999); Amerac Energy Corp., 148 IBLA 82 (1999) (motion for reconsideration pending); Texaco Exploration and Production Inc., No. MMS-92-0306-O&G (1999) (concurrence by the Secretary) (action for judicial review pending, Texaco Exploration and Production Inc. v. Babbitt, No. 1:99CV01670 (D.D.C.)).

    In the context of Federal leases, the D.C. Circuit referred to this implied lease covenant many years ago in California Co. v. Udall, 296 F.2d 384, 387 (D.C. Cir. 1961), stating that ``the lessee was obligated to market the product.'' The duty to market at no cost to the lessor is not unique to Federal leases. See, e.g., Merrill, Covenants Implied in Oil and Gas Leases (2d Ed. 1940), Secs. 84-86 (Noting ``[n]o part of the costs of marketing or of preparation for sale is chargeable to the lessor''); ``Direct Gas Sales: Royalty Problems for the Producer,'' 46 Okla. L. Rev. 235 (1993); Amoco Production Co. v. First Baptist Church of Pyote, 579 S.W.2d 280 (Tex. Civ. App. 1979), writ ref'd n.r.e., 611 S.W.2d 610 (Tex. 1981), and cases cited in these authorities.

    This duty to market means that the lessee must act as a prudent marketer. The duty to market is an implied covenant of virtually all oil and gas leases, whether the leases are private, Federal, or State leases. MMS as lessor has never shared in the ``risks'' of marketing and has never allowed deductions from royalty value for marketing costs. This proposed rulemaking makes no change to the lessee's duty to market.

    The decisions cited above establish several principles. First, the lessee has an implied duty to prudently market the production for the mutual benefit of both the lessee and the lessor. The creation and development of markets is the essence of that obligation. As the IBLA correctly expressed it ten years ago in Arco Oil and Gas Co., supra:

    The creation and development of markets for production is the very essence of the lessee's implied obligation to prudently market production from the lease at the highest price obtainable for the mutual benefit of the lessee and lessor. Traditionally,

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    Federal gas lessees have borne 100 percent of the costs of developing a market for gas. Appellant has cited no authority, nor do we find any, which supports an allowance for creation and development of markets for the royalty share of production.

    112 IBLA at 11.

    Because of industry's repeatedly-expressed concerns in the comments and workshops, MMS emphasizes that this does not imply that lessees are somehow prohibited from marketing at the lease and must market production ``downstream.'' Lessees may market at the lease without breaching the duty to market. However, if a lessee chooses to market downstream, the choice to do so is for the mutual benefit of itself and the lessor, and does not affect the lessee's relationship to the lessor. The choice to market downstream does not make marketing costs deductible or permit the lessee to disregard part of the sales price obtained at a downstream market.

    In addition, lessees have always borne all of the marketing costs. The Department has not knowingly permitted an allowance or deduction from royalty value for marketing costs. As the Board held a decade ago in Walter Oil and Gas Corp., supra:

    The only allowances recognized as proper deductions in determining royalty value are transportation allowances for the cost of transporting production from the leasehold to the first available market, which has been considered a relevant factor pursuant to 30 CFR. Sec. 206.150(e) * * * and processing allowances for processed gas authorized by 30 C.F.R. Sec. 206.152(a)(2) (1987) * * *. Walter's unsupported assumption that it is somehow entitled to deduct its marketing costs from royalty value fails in the face of contrary regulatory requirements * * *.

    111 IBLA at 265.

    Lessees may deduct from value only those costs allowed by the regulations. The only deductible costs are transportation costs, processing costs (for ``wet'' gas with heavier entrained liquid hydrocarbons), and, for leases which so provide, an operating allowance under Sec. 206.120.

    Further, marketing costs are not deductible, regardless of whether the lessee bears them directly or transfers the marketing function or costs to a contractor or an affiliate.

    Moreover, the fact that marketing arrangements enhance the lessee's ability to obtain a higher price does not imply that marketing costs are deductible. It also follows that a lessee may not deduct or disregard for royalty purposes the additional benefits it gains or value it receives through obtaining a higher price through its marketing skill or expertise. If the lessee manages to obtain a higher price for its oil through skillful marketing efforts, that higher price, less transportation costs, is the minimum royalty value under the gross proceeds rule.

    At the same time, the location of the market at which the lessee chooses to sell its production does not change the lessee's obligation. Much of industry's opposition to the duty-to-market provision during this rulemaking process revolves around the argument that when royalty value is based on the sale of production at a downstream location, the downstream transportation, risks, and related services add more value to the oil than is reflected in allowances MMS permits.

    The industry commenters' argument is contrary to established principles and uniform longstanding practice. Valuation based upon a ``downstream'' sale or disposition of production has been commonplace for many years. For sales at distant markets, the lessee is entitled to an allowance for transportation costs, but not for marketing costs. Sales away from (or ``downstream'' from) the lease often are the starting point for determining royalty value, and the costs of transportation always have been allowed in order to ascertain value at or near the lease. A lessee who transports production to sell it at a market remote from the lease or field is entitled to an allowance for the costs of transportation. See 30 C.F.R. 206.104, 206.105 (crude oil), 206.156 and 206.157 (gas) (1988-present). Before the 1988 regulations, transportation costs were allowed under judicial and administrative cases. See, e.g., United States v. General Petroleum Corp., 73 F. Supp 225 (S.D. Cal. 1946), aff'd, Continental Oil Co. v. United States, 184 F.2d 802 (9th Cir. 1950); Arco Oil and Gas Co., 109 IBLA 34 (1989); Shell Oil Co., 52 IBLA 15 (1981); Shell Oil Co., 70 I.D. 393, 396 (1963).

    An excellent example is Marathon Oil Co. v. United States, 604 F. Supp. 1375 (D. Alaska 1985), aff'd, 807 F.2d 759 (9th Cir. 1986), cert. denied, 480 U.S. 940 (1987). In that case, Marathon produced natural gas from Federal leases in Alaska, and sold it in Japan after overseas transportation in liquid form by tanker. The court held that MMS properly deducted Marathon's costs of transportation (including liquefaction) from the sales price in Japan to derive the royalty value (gross proceeds) at the lease.

    Indeed, transportation allowances have been common for decades precisely because the initial basis for establishing value often is a ``downstream'' sales price. Industry's argument that MMS is somehow improperly trying to ``tap into'' the benefits industry derives from its marketing expertise clouds the real issue. If a lessee can obtain a better price by selling away from the lease, then it will do so. How the lessee markets its production is its decision. The lessor is entitled to its royalty share of the total value derived from the production regardless of how the lessee chooses to dispose of it. The United States as lessor always has shared in the ``benefit'' of ``downstream'' marketing away from the lease, and has allowed deductions for the cost of transportation accordingly.

    Moreover, these principles do not change in the event that a wholly-owned or wholly-commonly-owned affiliated marketing entity buys other production at arm's length from other working interest holders in the field at the same price it pays to its affiliated producer. The industry wants to limit royalty value to supposedly ``comparable'' sales at the lease even when the lessee receives a higher price for its production. In effect, industry wants to force MMS to adopt a ``lowest common denominator'' theory of valuation--i.e., the price at which any production is sold at arm's length at the lease will be the value of production initially transferred non-arm's-length, even if the latter production nets a higher price in the open market. That position is incorrect for several reasons.

    First, it would enable a lessee whose enterprise realizes more proceeds or greater value for its production than some other producers in the field to avoid paying royalty on part of those proceeds. If the lessee sells downstream, its gross proceeds are the higher price realized on the sale downstream, minus the lessee's transportation costs, regardless of the fact that other producers sold for less. The industry's position is directly contrary to Marathon Oil Co. v. United States, supra. If the lessee first transfers to a wholly-owned or wholly-commonly-owned affiliate who then resells at arm's length downstream, it is still true that the producing entity could have sold its production at the point and at the price its affiliate did, instead of using the wholly-owned affiliate arrangement. It is perfectly proper to value the production of a producer who markets through a wholly- owned affiliate at a higher level than the production that other producers sell at arm's length in the first instance, when the gas (or oil) marketed through the wholly-owned affiliate commands a higher price. Indeed, this is the very situation which the Third Circuit correctly anticipated in Shell Oil Co. v. Babbitt, 125 F.3d 172 (3d Cir. 1997).

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    Further, the industry's position would create an incentive for a lessee to sell some small percentage of its production at the lease at arm's length for a lower price so that it can pay royalty on the rest of its production at that price. Such a result is contrary to the intent and meaning of the gross proceeds rule.

    MMS agrees that the duty to market production for the mutual benefit of the lessee and the lessor at no cost to the lessor is not the same as the lessee's duty to put production into marketable condition at no cost to the lessor. However, the fact that the two duties are not identical does not support the industry commenters' position. The decision of the Secretary and the Assistant Secretary for Land and Minerals Management in Texaco Exploration and Production Inc., supra (at pp. 16-19), discusses the relationship of the two duties and MMS affirms their rationale.

    Industry comparable sales model. In this proposal, MMS did not adopt the industry-proposed comparable sales model to value production not sold at arm's length. We continue to believe that there are meaningful spot prices applicable to production in all areas other than the Rocky Mountains. With the exception of the Rocky Mountain Region, spot and spot-related prices drive the manner in which crude oil is bought and traded in the U.S. Spot prices play a major role in crude oil marketing and are readily available to lessees through price reporting services.

    We believe spot prices are the best indicator of the value of production and are preferable to attempting to use supposedly comparable arm's-length sales in the field or area. Commenters have not demonstrated the consistent existence or availability of such transactions for volumes sufficient to use for royalty valuation. Contrary to the industry commenters, MMS believes that nationwide about two-thirds of crude oil production is disposed of non-arm's length. As previously mentioned, the general lack of competitive and transparent markets at the lease makes the attempt to find comparable sales transactions far inferior to the use of index prices.

    In addition, the various industry proposals have substantial practical difficulties since companies are not privy to other companies' ``comparable'' sales transactions. Even if a comparable sales model included only a lessee's own arm's-length sales or purchases, such information is unaudited for current periods. Further, it is difficult to determine what portion of lease production must be sold at arm's length to reliably determine the value of the remainder of the production. This supplementary proposed rule thus primarily uses index prices, adjusted for location and quality, to establish value for oil not sold at arm's length.

    California, and the West Coast in general, has long been recognized as a separate crude oil market isolated from the rest of the country. ANS crude is competitive with California crudes. While it may be true that only 10 percent of ANS crude is sold on the spot market, over 30 percent of the oil refined in California is ANS oil. An interagency study has found that companies engaged in buying and selling California crude oil commonly use ANS spot prices as the benchmark for determining California crude values (Final Interagency Report on the Valuation of Oil Produced from Federal Leases in California, May 16, 1996; Long Beach litigation). These companies apparently have no difficulty in adjusting the ANS prices for quality differences to derive the prices, including premia over postings, they are willing to pay for California crude oils. MMS believes ANS spot prices are a recognized benchmark for valuing California crudes and a reliable indicator of the market value of California crude oils.

    Comments alleging that ANS spot prices are unreliable because ANS crude is thinly traded were analyzed for MMS by Innovation & Information Consultants, Inc. (Memorandum to MMS file, September 25, 1997). They report that it is the spot market for local California crude oils, not ANS crude, that is thinly traded and thus leads to unreliable price indices. They also report that there is a high degree of correlation between ANS spot prices and prices actually paid for California crudes. They indicate that the major oil companies in California regularly make comparisons between California crude oils and ANS with the understanding and expectation that a California crude should equate to ANS in value after accounting for location and quality differences.

    The Rocky Mountain benchmarks for production not sold at arm's length are hierarchical and would not allow lessees to choose the benchmark most favorable to them. Rather, a lessee would have to use the first benchmark that applies to its situation--that is, first tendering, then a weighted average of sales and purchases, then Cushing, Oklahoma, adjusted spot prices, and lastly an MMS-established value. MMS proposes adopting a particular tendering alternative (designed with what MMS intends as safeguards against manipulation) as a first benchmark for the Rocky Mountain Region for production not sold at arm's length because of the lack of a reliable spot price in that region. One of the Rocky Mountain State commenters recommended this method as the initial benchmark in that region. MMS has acquiesced in that recommendation but nevertheless has substantial concerns about the potential for manipulation of tendering programs. MMS would closely monitor the reliability and workability of this benchmark. MMS's response to the comments regarding minimum volume and bid requirements is provided in Section IV below.

  4. Section-by-Section Analysis

    Before discussing the individual sections of this proposed rule, it is appropriate to review the basic premises of this proposal. When crude oil is produced, it is either sold at arm's length or is refined without ever being sold at arm's length. If crude oil is exchanged for other crude oil at arm's length, the oil received in the exchange is either sold at arm's length or is refined without ever being sold at arm's length. Under this proposal, oil that ultimately is sold at arm's length before refining generally will be valued based on the gross proceeds accruing to the seller under the arm's-length sale. This includes oil that is exchanged at arm's length where the oil received in exchange is ultimately sold at arm's length. (The exceptions reflect particular circumstances in which MMS believes the arm's-length sale does not or may not reliably reflect the real value.) However, this proposal also provides the option for the lessee to apply index prices or benchmark values because of the difficulty of ``tracing'' production in some exchanges and affiliate resales. If oil (or oil received in exchange) is refined without being sold at arm's length, then the value would be based on appropriate index prices or other methods, as explained below.

    These principles would apply regardless of whether oil is sold or transferred to one or more affiliates or other persons in non-arm's- length transactions before the arm's-length sale, and regardless of the number of those non-arm's-length transactions. They also would apply if an arm's-length exchange occurs before an arm's-length sale. (However, MMS believes that if there are multiple exchanges before an arm's- length sale, using the ultimate arm's-length sales price may in some cases require too much ``tracing'' of the oil to be cost-efficient for lessee and lessor alike. Consequently, under such circumstances, MMS would provide the option to determine value

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    based either on the arm's-length gross proceeds or on an index or benchmark basis. The same option would be provided for valuing production that is first sold or transferred to an affiliate and then resold at arm's length.)

    Section 206.100 What is the purpose of this subpart?

    Proposed section 206.100 includes the content of the existing section except for minor wording changes to improve clarity. At Sec. 206.100(a), we have added some further language clarifying the respective roles of lessees and designees. (Those terms are defined in Sec. 206.101, and those definitions follow the definitions contained in Section 3 of the Federal Oil and Gas Royalty Management Act, 30 U.S.C. 1702, as amended by Section 2 of the Federal Oil and Gas Royalty Simplification and Fairness Act, Public Law 104-185, 110 Stat. 1700.)

    Specifically, if you are a designee and you or your affiliate dispose of production on behalf of a lessee, references to ``you'' and ``your'' in the rule would refer to you or your affiliate. In this event, you would have to report and pay royalty by applying the rule to your and your affiliate's disposition of the lessee's oil. If you are a designee and you report and pay royalties for a lessee but do not dispose of the lessee's production, the references to ``you'' and ``your'' would refer to the lessee. In that case, you as a designee would have to determine royalty value and report and pay royalty by applying the rule to the lessee's disposition of its oil. Some examples will illustrate the principle.

    Assume that the designee is the unit operator, and that the operator sells all of the production of the respective working interest owners on their behalf and is the designee for each of them. For each of those working interest owners, the operator, as designee, would report and pay royalties on the basis of the operator's disposition of the production. For example, if the operator transferred the oil to its affiliate, who then resold the oil at arm's length, the royalty value would be the gross proceeds accruing to the designee's affiliate in the arm's-length resale under Sec. 206.102, or the appropriate index or benchmark value under Sec. 206.103, as explained further below.

    Alternatively, assume the operator is the designee but a lessee disposes of its own production. Assume the lessee transfers its oil to an affiliate, who then resells the oil at arm's length. In this case, the operator would have to obtain the information from the lessee, and report and pay royalties on the basis of the gross proceeds accruing to the lessee's affiliate in the arm's-length resale under Sec. 206.102, or, at the lessee's option, on the basis of the appropriate index or benchmark value under Sec. 206.103.

    In some cases, the designee is the purchaser of the oil. Assume the operator disposes of the lessee's oil and that the operator is not affiliated with the designee-purchaser. Because the lessee's sale to the designee is an arm's-length transaction, then under Sec. 206.102 the designee would report and pay royalty on the total consideration (the gross proceeds) it paid to the lessee.

    The content of proposed Sec. 206.100(b) and (c) is the same as in the corresponding existing paragraphs, but we rewrote them for clarity. Paragraph (b) says that this subpart would not apply if these regulations are inconsistent with a Federal statute, a settlement agreement between the United States and a lessee resulting from administrative or judicial litigation, or an express provision of an oil and gas lease subject to this subpart. If so, the statute, settlement agreement, or lease provision would govern to the extent of the inconsistency.

    Proposed paragraph (c) says MMS may audit and adjust all royalty payments. We removed existing paragraph (d). It said the regulations in this subpart are intended to ensure that the United States discharges its trust responsibilities concerning Indian oil and gas leases. Since Indian leases are subject to a separate set of valuation regulations at 30 CFR 206.50 that include the same language as existing paragraph (d), we believe the existing language at paragraph 206.100(d) is not needed.

    Section 206.101 Definitions.

    The definitions section remains largely the same as in the January 1997 proposal. However, MMS proposes several additions and clarifications consistent with changes to the rule throughout the rulemaking process and in response to comments received.

    The July 1997 proposal (62 FR 36030) added a definition of non- competitive crude oil call as well as a new definition of competitive crude oil call. This supplementary proposed rule does not use either of these terms. Therefore, they have been deleted from the proposed definitions section.

    However, oil subject to a noncompetitive crude oil call would be examined in view of paragraphs 206.102(c)(1) and (c)(2) to determine whether the prices received represent market value. The value of oil involved in a noncompetitive crude oil call thus ultimately would be the lessee's total consideration or the value determined by the non- arm's-length methods in Sec. 206.103.

    We propose to modify the definition of arm's-length contract to remove the criteria for determining affiliation. Instead, these criteria would be included in the new definition of affiliate discussed below.

    We also propose to modify the definition of exchange agreement to delete the statement that exchange agreements do not include agreements whose principal purpose is transportation. MMS believes that transportation exchanges, while having different purposes than other types of exchanges, properly should be included under the generic definition of exchange agreements. We also propose to add, for clarity, several examples of other types of exchange agreements. These would include, but not be limited to, exchanges of produced oil for specific types of crude oil (e.g., West Texas Intermediate); exchanges of produced oil for other crude oil at other locations (Location Trades); exchanges of produced oil for futures contracts (Exchanges for Physical, or EFP); exchanges of produced oil for similar oil produced in different months (Time Trades); exchanges of produced oil for other grades of oil (Grade Trades); and multi-party exchanges (for example, party A exchanges with party B, who then exchanges with party C, who then exchanges with party A).

    We also propose to modify the definition of gross proceeds to clarify that they include payments made to reduce or buy down the purchase price of oil to be produced later. The concept that such payments are part of gross proceeds was included in the January 1997 proposal at paragraph 206.102(a)(5). Moving this provision directly to the gross proceeds definition would further clarify the components of gross proceeds and improve the structure of the rule.

    We also clarified that gross proceeds would include payments for marketing, along with payments for such services as dehydration, measurement, and gathering. All of these are services that the lessee must perform at no cost to the Federal Government.

    Also, since this proposal bases valuation for some production on crude oil spot prices for other than ANS oil, we propose to change the definitions of index pricing and MMS-approved publication to include other spot prices. Index pricing would mean using ANS crude oil spot prices, WTI crude oil spot prices at Cushing, Oklahoma, or other appropriate crude oil spot prices for royalty valuation. MMS-approved

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    publication would mean a publication MMS approves for determining ANS spot prices, other spot prices, or location differentials.

    We also would delete the definitions of aggregation point, prompt month and NYMEX because they are not used in this proposal. All three of these terms were used in earlier versions of the proposed rule in applying various non-arm's-length benchmarks. But this proposal would apply spot, rather than NYMEX prices, and eliminate proposed Form MMS- 4415, so none of these definitions would be needed.

    We also would add three new definitions of terms used in the February 1998 proposal and incorporated in this proposal. They are affiliate, Rocky Mountain Region, and tendering program.

    ``Affiliate would mean a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:

    (1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person would constitute control. Ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut.

    (2) If there is ownership or common ownership of between 10 and 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person, MMS would consider the following factors in determining whether there is control under the circumstances of a particular case:

    (i) the extent to which there are common officers or directors;

    (ii) with respect to the voting securities, or instruments of ownership, or other forms of ownership,

    (A) the percentage of ownership or common ownership;

    (B) the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons;

    (C) whether a person is the greatest single owner; and

    (D) whether there is an opposing voting bloc of greater ownership;

    (iii) operation of a lease, plant, or other facility;

    (iv) the extent of participation by other owners in operations and day-to-day management of a lease, plant, or other facility; and

    (v) other evidence of power to exercise control over or common control with another person.

    (3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, would be affiliates.''

    The July 1998 proposal (63 FR 38356) retained the criteria for determining affiliation that are contained in the existing rule. The March 1999 notice that included the letter to the Senate (64 FR 12268) also indicated that MMS likely would retain the same criteria that are in the existing rule.

    In response to the March 1999 notice, industry commenters proposed a set of criteria which lessees could use to rebut the presumption of control that arises from ownership or common ownership of between 10 and 50 percent. While MMS does not agree with the industry proposal, a judicial decision in a case decided after the close of the most recent comment period affects the criteria for determining control and the associated presumption in the existing rule.

    In National Mining Association v. Department of the Interior, 177 F.3d 1 (D.C. Cir. 1999) (decided May 28, 1999), the United States Court of Appeals for the District of Columbia Circuit addressed the Office of Surface Mining Reclamation and Enforcement's (OSM's) so-called ``ownership and control'' rule at 30 CFR 773.5(b). That rule presumed ownership or control under six identified circumstances. One of those circumstances was where one entity owned between 10 and 50 percent of another entity. The court found that OSM had not offered any basis to support the rule's presumption ``that an owner of as little as ten per cent of a company's stock controls it.'' 177 F.3d at 6-7. The court continued, ``While ten percent ownership may, under specific circumstances, confer control, OSM has cited no authority for the proposition that it is ordinarily likely to do so.'' Id. (Emphasis added.) In a footnote, the court referred to the existing MMS rule:

    In its brief OSM referred the court to several regulations promulgated by other agencies but none of them presumes control based simply on a ten percent ownership stake, although another Department of Interior regulation does so. See 30 CFR 206.101(b)

    [sic] (``based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership: * * * (b) Ownership of 10 through 50 percent creates a presumption of control''). We do not consider the validity of section 206.101 here.

    The United States did not file a petition for rehearing. Nor did the United States seek Supreme Court review.

    In this proposal, MMS is revising the definition of ``affiliate'' in light of the National Mining Association decision. In the event of ownership or common ownership of between 10 and 50 percent, the second paragraph of the definition in this proposal, instead of creating a presumption of control, identifies a number of factors that MMS would consider in determining whether there is control under the circumstances of a particular case.

    With respect to ownership or common ownership, the new definition would identify such factors as the percentage of ownership, the relative percentage of ownership as compared with other owners, whether a person is the greatest single owner, and whether there is an opposing voting bloc of greater ownership. All of these are relevant factors in determining whether there is control in a particular case.

    For example, company A could own one third of the voting stock of company B, while no other owner owns any percentage close to that. A is the greatest single owner, and it is very likely that A has control of B. If, in addition, A manages the day-to-day operations of B and the other owners effectively are passive investors, it would be very clear that A controls B and that they are affiliates.

    A different example would be if A owns 20 percent of B, at the same time that C and D each own 35 percent of B. In such a case, it would be much harder to demonstrate that A controls B, and doing so would depend on additional facts that would show that A has effective control.

    Yet another example would be if A owns 12 percent of B and other owners own roughly equivalent percentages of B. A may or may not control B, again depending on what additional circumstances are present.

    We emphasize that simply because one entity is found not to control another on the basis of stock ownership and other factors, and therefore that the entities are not affiliates, that does not always mean that the relationship between the two entities is at arm's length. The entities may be engaged in a cooperative venture and therefore not have opposing economic interests. (An example is the situation in Xeno, Inc., 134 IBLA 172 (1995), in which a number of lessees in a large field combined to form another entity to purchase their gas, then gather, compress, and treat it, and then resell it to another purchaser.)

    The proposed definition also identifies other factors in addition to ownership interests that are relevant to determining control. These include the extent of common officers or directors, operation by one entity of a lease or a

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    facility, the extent of participation by different owners in operations and day-to-day management of an entity, and other evidence of power to exercise control or common control. These factors would be evaluated on a case-by-case basis.

    The proposed definition would continue the existing provisions that ownership of more than 50 percent constitutes control, and that relatives, either by blood or marriage, are affiliates regardless of any percentage of ownership or common ownership. Likewise, the proposed definition would continue the exiting provision that ownership of less than 10 percent would presume noncontrol that MMS may rebut. The National Mining Association decision does not affect these provisions.

    Arm's-length contract would mean a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract would have to satisfy this definition for that month, as well as when the contract was executed. Again, we have defined affiliate separately for clarity.

    In our February 1998 proposal, we asked for comments on the Rocky Mountain Area definition. We wanted to know whether other States or regions should be included in this definition and, conversely, whether the definition included States or regions that should be deleted. For example, although some participants in MMS's workshops believed the entire State of New Mexico belongs outside the Rocky Mountain Region for this rule's purposes, others believed that oil marketing in the northwest portion of New Mexico is similar to that in the other Rocky Mountain States. Some of these participants suggested that northwest New Mexico (not including the Permian Basin) more appropriately should be included in the Rocky Mountain Region.

    Several commenters said the term's wording could conflict with the generic use of the term ``area'' elsewhere in the rule. As a result, we changed ``Rocky Mountain Area'' to ``Rocky Mountain Region'' in this supplementary proposed rule.

    We received several comments, pro and con, regarding inclusion of part or all of New Mexico in the Rocky Mountain Region definition. The most telling comment was from the State of New Mexico itself, indicating that production there has much closer ties to Midland, Texas, than any Rocky Mountain markets. Thus, MMS has excluded New Mexico from the definition in this proposal. Other comments about additions and deletions of specific States or regions were limited, and MMS does not believe they warrant further changes to the definition. Rocky Mountain Region would mean the States of Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming.

    For the Rocky Mountain Region, this proposal incorporates tendering as one of the non-arm's-length valuation benchmarks; hence we propose a new definition. Tendering program would mean a company offer of a portion of its crude oil produced from a field or area for competitive bidding, regardless of whether the production is offered or sold at or near the lease or unit or away from the lease or unit. The definition in the February 1998 proposal said ``* * * from a field, area, or other geographical/physical unit for competitive bidding.'' Several commenters said ``or other geographical/physical unit'' was confusing, and one commenter suggested deleting it. Although our intent was to provide for circumstances where tendered oil is produced from a very specific and more finite source than a field or area, we agree that the terminology as originally written could be confusing. Thus we have deleted ``or other geographical/physical unit'' in this proposal. The revised definition should cover all circumstances, since any production tendered will be from a given field or area. The offer and sale of oil under a tendering program would not be limited to offers or sales at or near the lease or unit. Oil could be tendered for bid or sale at remote or ``downstream'' locations. The proposal includes clarifying language to remove any potential ambiguity on this point.

    Several commenters said the definition of ``sale'' should be modified to describe how transfers of production from a working interest owner to the operator under a joint operating agreement should be treated for valuation purposes. Two specific circumstances were described, namely where the operator sells the working interest owner's share of production: (1) At arm's length, or (2) to the operator's affiliate. The commenters said that if the initial transfer from the working interest owner to the operator, or the sale of the working interest owner's production by the operator, were not considered an arm's-length sale, there may be an inappropriate result. For example, the working interest owner might be required to either ``trace'' value back from the operator's affiliate's resale, or apply Sec. 206.103. We are not persuaded that the result under this proposed rule would be inappropriate, and believe that the proposed definition of ``sale'' is clear and succinct.

    Section 206.102 How Do I Calculate Royalty Value for Oil That I or my Affiliate Sell(s) Under an Arm's-length Contract?

    We propose to revise and reorganize Sec. 206.102 as written in the several previous proposed rules. We would revise Sec. 206.102 to specifically address valuation of oil ultimately sold under arm's- length contracts. That sale may occur immediately, or may follow one or more non-arm's-length transfers or sales of the oil or one or more arm's-length exchanges.

    Proposed paragraph (a) states that value is the gross proceeds accruing to you or your affiliate under an arm's-length contract, less applicable allowances. Similarly, if you sell or transfer your Federal oil production to some other person at less than arm's length (except for a non-arm's-length exchange), and that person or its affiliate then sells the oil at arm's length, royalty value would be the other person's (or its affiliate's) gross proceeds under the arm's-length contract. If you transfer under a non-arm's-length exchange, you must use Sec. 206.103.

    For example, a lessee might sell its Federal oil production to a person who is not an ``affiliate'' as defined, but with whom its relationship is not one of ``opposing economic interests'' and therefore is not at arm's length. An illustrative example would be a number of working interest owners in a large field forming a cooperative venture that purchases all of the working interest owners' production and resells the combined volumes to a purchaser at arm's length. Xeno, Inc., 134 IBLA 172 (1995), involved a similar situation for a gas field. If no one of the working interest owners owned 10 percent or more of the new entity, the new entity would not be an ``affiliate'' of any of them. Nevertheless, the relationship between the new entity and the respective working interest owners would not be at arm's length. In this instance, it would be appropriate to value the production based on the arm's-length sale price the cooperative venture received for the oil.

    Paragraph 206.102(a)(3) of the February 1998 proposal was meant to be specific to those cases, such as Xeno, where the transfer is not between affiliates but the sale is not arm's length because the parties do not have opposing economic interests. However, several commenters could not see the difference between (a)(3) and (a)(2); the latter applied only to sales or transfers to an affiliate who then sells the oil at

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    arm's length. Because the result of both paragraphs would be the same, and to stem this confusion, we propose to eliminate previous paragraph (a)(3) and include its intent in revised paragraph (a)(2). That paragraph would now say value is the gross proceeds accruing to the seller under the arm's-length contract, less applicable allowances, where you sell or transfer to your affiliate or another person under a non-arm's-length contract and that affiliate or person or another affiliate of either of them then sells the oil under an arm's-length contract. As a result of this change, paragraph (a)(4) of the February 1998 proposal would now become paragraph (a)(3).

    In all these circumstances, you would have to value the production based on the gross proceeds accruing to you, your affiliate, or other person to whom you transferred the oil (or its affiliate) when the oil ultimately was sold at arm's length unless you elect to use index pricing or benchmarks under Sec. 206.102(d).

    Paragraph (a)(5) of the January 1997 proposal dealt with inclusion in gross proceeds of payments made to reduce or buy down the price of oil to be produced in later periods. We removed this paragraph in the February 1998 proposal but added the concept within the definition of gross proceeds as discussed above. This supplementary proposed rule reflects the February 1998 proposal in this regard without change.

    Proposed paragraph (b) would clarify how to value the oil produced from your lease when you sell or transfer it to your affiliate or to another person under a non-arm's-length contract, and your affiliate, the other person, or an affiliate of either of them sells the oil at arm's-length under multiple arm's-length contracts. In this case, value would be the volume-weighted average of the values established under paragraph (a) for each contract for the sale of oil produced from that lease.

    A number of commenters said that calculating this volume-weighted average value would be extremely problematic because it often would be difficult to tie specific contracts to specific Federal oil production, especially where commingling of various production is involved. MMS acknowledges that proper royalty calculations can be complicated in such situations, but that does not diminish the lessee's duty to pay proper royalties on its Federal production. Even under the existing rules, circumstances similar to those described by the commenters often require that the lessee allocate values and volumes. We believe this provision is consistent with ongoing practice.

    Proposed paragraph (c) would specify two exceptions to the use of arm's-length gross proceeds. It would also require you to apply the exceptions to each of your contracts separately. Proposed paragraphs (c)(1) and (c)(2) would remain largely unchanged from paragraphs (a)(2) and (a)(3) in the January 1997 proposal and from Sec. 206.102(b)(1) (i) and (ii) of the existing rules, except for additional language included in (c)(2) regarding ``second guessing,'' as discussed below.

    Paragraph (a)(4)(ii) of the July 1997 proposal said that where an arm's-length contract price does not represent market value because an overall balance between volumes bought and sold is maintained between the buyer and seller, royalty value would be calculated as if the sale were not at arm's length.

    In the February 1998 proposal, MMS decided to remove that language as a specific, separate provision. Rather, in considering whether an arm's-length contract reflects your or your affiliates' total consideration or market value (proposed paragraphs (c)(1) and (c)(2)), MMS would examine whether the buyer and seller maintain an overall balance between volumes they bought from and sold to each other. Under these paragraphs, if an overall balance agreement were found to exist, MMS would require you to value your production under Sec. 206.103 or the total consideration received.

    Several commenters said that removal of the overall balance provision and relying on MMS to find such agreements put an undue burden on MMS. They further stated that MMS would have great difficulty verifying the existence of such agreements. We continue to believe, however, that verification of overall balancing arrangements, and appropriate follow up, is best left to audit in conjunction with the provisions of paragraphs 206.102 (c)(1) and (c)(2). Thus, this proposal does not contain any specific language regarding overall balancing agreements.

    Likewise, this proposal does not contain any specific language regarding noncompetitive crude oil calls. In response to the July 1997 and February 1998 proposals, and in MMS's public workshops, several commenters asserted that producers often negotiate competitive prices even if a non-competitive call provision exists and a call on production is exercised. We agree and we propose not to treat oil sold under a noncompetitive crude oil call differently than other arm's- length sales. However, because the sale occurred in the context of a noncompetitive crude oil call, MMS would examine the transaction more carefully in view of paragraphs 206.102 (c)(1) and (c)(2) to determine whether the prices received represent market value.

    This supplementary proposed rule contains language in paragraph 206.102(c)(2)(ii) regarding MMS's intent not to ``second guess'' industry marketing decisions. The rule would state that MMS will not use this provision to simply substitute its judgment of the market value of the oil for the proceeds received by the seller under an arm's-length sales contract. The fact that the price received by the seller in an arm's-length transaction is less than other measures of market price, such as index prices or other arm's-length sales, is insufficient to establish breach of the duty to market unless MMS finds additional evidence that the seller acted unreasonably or in bad faith in the sale of oil from the lease.

    In response to industry concerns, in its July 1998 proposal, MMS proposed adding specific language to Sec. 206.102(c)(2)(ii) that MMS would not use the ``breach of duty'' provision to second-guess industry marketing decisions unless the arm's-length prices were substantially below market value. However, in their comments on the July 1998 proposal, industry and their representative organizations stated that the terms ``substantially below'' and ``market value'' were not easily defined and could lead to MMS questioning legitimate transactions. One commenter said that in the past, MMS has rejected legitimate, at-the- lease prices in favor of higher, downstream prices. One commenter believed that as long as a company is acting in good faith, they have nothing to fear with MMS ``second-guessing'' their decisions. One commenter offered alternate ``breach of duty to market'' language.

    At the March 1999 workshops, industry commenters expressed concern that if a company sold production at the lease under an arm's-length arrangement, MMS might later ``second-guess'' the transaction and determine that the royalty should have been paid on a higher price than the company actually received, such as index. They proposed specific language to be added to the rule and preamble.

    One State commenter also proposed specific regulatory language regarding ``second-guessing.'' A public interest group commented that it would support language that MMS will not second-guess arm's-length contract prices received, provided that lessees disclose balancing arrangements between

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    themselves and the unaffiliated companies.

    The provision MMS was attempting to clarify with its proposed additional language is identical to the provision in the existing rules (see 30 CFR 206.102(b)(1)(iii)). It has been in those rules for over a decade and has not been used to second-guess a lessee's marketing decisions to try to impose the benchmarks at Sec. 206.102(c) on arm's- length transactions. It is longstanding MMS policy to rely on arm's- length prices as the best measure of value, and we have no intention of changing this. We expect no expansion of the use of this provision in the future as a result of this proposed rewrite.

    We propose including the term ``unreasonably'' because we think that limiting the proposed provision only to situations involving ``bad faith'' is too narrow. We do not believe that a royalty interest holder should bear the consequences of a lessee's decision to enter into a transaction that no reasonable businessman would agree to. We anticipate that such situations would be extraordinarily rare. However, we believe that the duty to market for the mutual benefit of the lessee and the lessor may be breached by unreasonable actions that do not involve knowing or deliberate bad faith. The July 1998 proposal included language that MMS would not use the provision to dispute lessees' marketing decisions made ``reasonably and in good faith.'' Although some industry commenters initially stated that the term ``good faith'' was too subjective, industry commenters later recommended including this term in their proposed rewrite of this section. Thus, we do not think that the terms ``unreasonable'' or ``bad faith'' are too subjective.

    Requiring a lessee to include in gross proceeds or royalty value, amounts that were improperly deducted for marketing costs, costs of putting production in marketable condition, or other costs that are the responsibility of the lessee, does not constitute ``second-guessing'' an arm's-length contract.

    Proposed paragraph 206.102(d)(1) provides the option, where arm's- length sales follow one or more arm's-length exchanges, to apply either the arm's-length gross proceeds or the index or benchmark value appropriate to the region of production.

    In the February 1998 proposal, MMS expanded gross proceeds valuation to include situations where the oil received in exchange is ultimately sold at arm's length, regardless of the number of exchanges involved. However, many industry comments claimed that tracing multiple exchanges would be overly burdensome. MMS understands the potential administrative burden of tracing. However, we also are well aware of the desire of other producers, as expressed in the meetings sponsored by Senator Breaux and other Senators on July 9 and July 22, 1998, to be able to use prices received in arm's-length sales following multiple exchanges. As a result, under this proposal, MMS would allow lessees the option of using either their arm's-length gross proceeds regardless of the number of arm's-length exchanges preceding the arm's-length sale, or the provisions of Sec. 206.103 (index prices or, in the Rocky Mountain Region, benchmarks). This process would preserve the integrity of the rule's underlying principle of applying arm's-length gross proceeds where appropriate, but still allow use of index/benchmark values that fairly represent market value where ``tracing'' would be too burdensome.

    The chosen option would apply for at least 2 years. The lessee would have to use this method to value all of its crude oil that the lessee or its affiliate sells at arm's length following one or more exchanges.

    The option to choose between index valuation and gross proceeds is not available for oil that is not sold at arm's length after the exchange or for oil subject to non-arm's-length exchanges regardless of whether an arm's-length sale follows such an exchange. The provisions of Sec. 206.103 would apply to such dispositions. We included these qualifications to assure that lessees would not abuse the system by choosing case-specific options or time periods for the purpose of reducing royalty, or by using non-arm's-length exchange differentials to determine royalty value. We acknowledge that exchanges between affiliates are not at arm's length. Because there is potential for inflated differentials in such exchanges, production so transferred, even if followed by an arm's-length sale, would have to be valued at the appropriate index/benchmark value under this proposal.

    Proposed paragraph (d)(2) of this proposal is new and results from comments received throughout the rulemaking process. Some commenters believe that where lessees sell or transfer production to an affiliate and the affiliate resells the oil at arm's length, they should be able to apply an alternative valuation method other than tracing the production to its final disposition. In this proposal, similar to the option for sales following arm's-length exchange agreements, we provide the option to use either the ultimate arm's-length gross proceeds or the appropriate index or benchmark value. Also, proposed paragraph (d)(2)(ii) states that whichever option you select, you must apply that same option for all of your production disposed of through affiliate resales at arm's length, and that you not change this election more often than once every 2 years. Again, we believe this achieves the best balance of valuing production based on arm's-length gross proceeds and limiting administrative burdens.

    Proposed paragraph (e) would be essentially the same as paragraphs (b)(2) and (3) of Sec. 206.102 in the January 1997 proposal and paragraphs (d)(2) and (3) of the February 1998 proposal and comes directly from existing Sec. 206.102(b)(2) and (j). We would eliminate proposed paragraph (b)(1) of the January 1997 proposal (paragraph (d)(1) of the February 1998 proposal) in connection with the change to the definition of ``affiliate'' explained previously in this preamble.

    Proposed section 206.102(e)(2) addresses circumstances in which a purchaser does not pay the full price obtainable by the seller under the contract between them. The proposed section, which is similar to the current section 206.102(j), establishes that if the seller takes reasonable efforts to obtain the highest price to which it is entitled under the contract, then the price it obtains will be the basis for determining value.

    Industry commenters suggested rewriting the section now proposed at 206.102(e)(2) to make it virtually identical to the language in section 206.102(j) of the current rule. In other words, industry suggests using the term ``lessee'' instead of ``seller.'' This proposal generally requires arm's-length gross proceeds as royalty value regardless of whether the ultimate seller is the lessee, an affiliate, or another person to whom the lessee has sold or transferred production under a non-arm's-length contract. All of these persons would come within the term ``seller.'' MMS therefore would retain this term instead of using the term ``lessee.''

    Section 206.103 How Do I Value Oil That Is Not Sold Under an Arm's- Length Contract?

    In the February 1998 proposal, this section replaced paragraph 206.102(c) of the January 1997 proposal. This proposal includes a few changes in this section as explained below. This section would deal specifically with valuation of oil you could not value under Sec. 206.102 because the oil is not ultimately sold at arm's length or is otherwise excepted under Sec. 206.102. It

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    may also apply where you have elected one of the options available at Sec. 206.102(d)(1) or (2).

    Also, paragraph 206.102(c)(1) of the January 1997 proposal would have permitted you an option if you first transferred your oil production to an affiliate and that affiliate or another affiliate disposed of the oil under an arm's-length contract. The option was to value your oil at either the gross proceeds accruing to your affiliate under its arm's-length contract or the appropriate index price. For the reasons discussed earlier, we have reinserted that option in this proposal under paragraph 206.102(d)(2). MMS believes that where arm's- length transactions satisfying the provisions of Sec. 206.102 occur, royalty value generally should be the arm's-length gross proceeds. However, providing this option should afford some administrative relief to lessees while assuring receipt of fair royalty values.

    We received various comments about use of ANS spot prices. Most industry commenters said that because there are significant differences between ANS and California crudes in terms of quality, product yield, transportation modes and distances, and timing of production versus delivery, the ANS spot price is not a good value indicator for California crude oil production. The State of California and City of Long Beach, on the other hand, continue to endorse the use of ANS spot prices. They indicate that ANS spot prices are used in many arm's- length transactions and that ANS crude constitutes a large percentage of California refinery feedstock. MMS's own experience, including participation in the interagency task force investigating California oil undervaluation, shows that ANS crude frequently has been used by industry as a valuation benchmark for valuing California crudes. Also, because of the control of the pipeline transportation network in California by a few companies who also act as purchasers of a large portion of California crude oil production, the use of posted prices or contracts based on postings as a basis for valuing crude disposed of at other than arm's-length is questionable. We continue to believe that, with proper adjustments for location and quality differences, the ANS spot price is the best available measure of royalty value for Federal oil production in California that is not sold at arm's length.

    Paragraph 206.103(b) would apply to production from leases in the Rocky Mountain Region, a defined term. As discussed above, production in the Rocky Mountain Region is controlled by relatively few companies, and the number of buyers is more limited than in the Texas, Gulf Coast, or Midcontinent areas. As a result, there is less spot market activity and trading in this area due to the control over production and refining. The majority of written comments we received, as well as oral comments in our public meetings, agreed that a separate valuation procedure is needed for the Rocky Mountain Region. For these reasons, we propose the following valuation hierarchy for the Rocky Mountain Region:

    (1) As in the February 1998 proposal, if you have an MMS-approved tendering program (a defined term), the value of production from leases in the area the tendering program covers would be the highest price bid for tendered volumes. Under your tendering program you would have to offer and sell at least 30 percent of your production from both Federal and non-Federal leases in that area. You also would have to receive at least three bids for the tendered volumes from bidders who do not have their own tendering programs that cover some or all of the same area.

    MMS added the several qualifications stated above to ensure receipt of market value under tendering programs. First, as provided in the February 1998 proposal, royalty value would be the highest price bid rather than some other individual or average value. Several commenters said this is inappropriate because it is possible that a single bidder may only bid on some small portion of the tendered volumes at a high price, but this price would then apply to all tendered volumes. We continue to believe, however, that to assure receipt of market value, value must be based on the highest bid received.

    Second, you would have to offer and sell at least 30 percent of your production from both Federal and non-Federal leases in that area. The rationale for this minimum percentage is to ensure that the lessee puts a sufficient volume of its own production share up for bid to minimize the possibility that it could abuse the system for Federal royalty or State tax payment purposes. MMS originally chose 33\1/3\ percent as the minimum because it exceeded the typical combined Federal royalty rate and effective composite State tax and royalty rates for onshore oil leases by roughly 10 percent. We received various comments that this figure was too high and that it was not appropriate to consider State royalties, since they would not be payable on Federal leases. MMS recognizes this fact but also notes that for the oil- producing states in the Rocky Mountain Region the combined Federal royalty rate and state composite effective tax rate on Federal oil production typically ranges from about 17 to 27 percent. These percentages do not include state royalty rates. In this proposal, we thus chose 30 percent, or just above the high end of the royalty and tax range, as the minimum percentage the lessee would have to tender for sale to assure that some of the lessee's equity share of production generally was involved. Likewise, the tendering program would be required to include non-Federal lease production volumes in the 30 percent determination to ensure that the program isn't aimed at limiting Federal royalty value.

    Third, as in the February 1998 proposal, to ensure receipt of competitive bids, your tendering program would have to result in at least three bids from bidders who do not have their own tendering programs covering some or all of the same area. In response to the February 1998 proposal, we received several comments that requiring three bidders was too stringent and that in many cases there simply would not be that many qualified bidders. We have reviewed this criterion and continue to believe that a minimum number of bidders is essential to ensure receipt of market value. We believe that at least three bidders are needed to provide an adequate measure of market value and have retained this provision in this proposal. Further, MMS is concerned about the possibility of cross-bidding between companies at below-market prices, which could otherwise satisfy the minimum number of bidders requirement. That is why we have retained the stipulation that bids would have to come from bidders who do not also have their own tendering programs in the area.

    (2) As in the February 1998 proposal, for the second method in the valuation hierarchy for the Rocky Mountain Region, value would be the volume-weighted average gross proceeds accruing to the seller under your and your affiliates' arm's-length contracts for the purchase or sale of production from the field or area during the production month. The total volume purchased or sold under those contracts would have to exceed 50 percent of your and your affiliates' production from both Federal and non-Federal leases in the same field or area during that month.

    Under the February 1998 proposal, MMS proposed this method as the next alternative if a qualified tendering program did not exist. It is an effort to establish value based on actual transactions by the lessee and its

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    affiliate(s). We received a number of comments during the rulemaking process that MMS should look not only to sales by the lessee, but also purchases a lessee and its affiliates make in the field or area. Just as for the tendering program, MMS believes a floor percentage of the lessee's and its affiliates' production should be set to prevent any abuse. Although we received several comments that the 50 percent minimum figure is too high, it is not intended to be a more stringent standard than the 30 percent floor associated with the tendering program. That is because the 50 percent floor would apply to the lessee's and its affiliates' sales and purchases in the field or area, rather than just sales as in the tendering program. For example, Company A produces 10,000 barrels of crude oil in a given field during the production month. Company A sells 1,000 barrels under an arm's- length contract. Company A also has a refining affiliate, Company B, that purchases the remaining 9,000 barrels of Company A's production and 5,000 barrels of oil under arm's-length purchase contracts with other producers in the same field. Together the arm's-length sales by Company A and the arm's-length purchases by its affiliate, Company B, are 6,000 barrels, or 60 percent of the lessee's production in the field that month. The volume-weighted arm's-length gross proceeds accruing to Company A and paid by Company B for these 6,000 barrels would represent royalty value for the 9,000 barrels of Company A's Federal lease production in the field that could not be valued under Sec. 206.102.

    This proposal would continue to require using the unadjusted volume-weighted average gross proceeds accruing to the seller in all of the lessee's and its affiliates' arm's-length sales or purchases, not just those that may be considered comparable by quality or volume. We received several comments that this would result in improper valuation of some oil that was significantly different in quality than that associated with the ``average'' oil. However, we believe that production in the same field or area generally would be similar in quality. Further, given that these sales and purchases would have to be greater than 50 percent of all of the lessee's production in the field or area, we believe that it is not necessary to distinguish comparable- volume contracts.

    MMS received several industry comments that the proposed rule would cause hardships for producers who have marketing, but not refining, affiliates. The marketing affiliate takes the producing affiliate's production and also buys production from various other sources before reselling or otherwise disposing of the combined volumes. Section 206.102 of the February 1998 proposal would have required the producer to base royalty value on its marketing affiliate's various arm's-length sales and allocate the proper values back to the Federal lease production. Many commenters said this ``tracing'' would be difficult at best, but others wanted the opportunity to do so. One commenter suggested that as an alternative the lessee should be permitted to base the value of its production on the prices its marketing affiliate pays for crude oil it buys at arm's length in the same field or area.

    We cannot agree with this proposal because an overriding general premise of this rulemaking is that where oil ultimately is sold at arm's length before refining, it should be valued based on the gross proceeds accruing to the seller under the arm's-length sale (with the option to use index or benchmark values under some circumstances as discussed earlier). This means the marketing affiliate's arm's-length resale should form the basis for valuing the producing affiliate's production. To do otherwise would be inconsistent with the way arm's- length resales are treated elsewhere in this proposal.

    (3) As in the February 1998 proposal, if you could not apply either of the first two valuation criteria for the Rocky Mountain Region, value would be the average of the daily mean spot prices published in any MMS-approved publication for WTI crude at Cushing, Oklahoma, for deliveries during the production month.

    This paragraph is very similar to paragraph 206.102(c)(2)(i) of the January 1997 proposal. The main difference is that rather than using NYMEX futures prices, we apply Cushing spot prices in this proposal, as in the February 1998 proposal. This was due to an industry comment that since Cushing spot and NYMEX futures prices track closely over time and that we propose to use spot prices in the other two valuation regions, using the spot price in the Rocky Mountain Region would lend consistency with no downside effects. MMS proposes to make this the third method, to be used only if the first two do not apply, because of distances between Rocky Mountain Region locations and Cushing, Oklahoma, and the additional difficulties in deriving location/quality differentials.

    (4) If you should demonstrate to MMS's satisfaction that paragraphs (b)(1) through (b)(3) would result in an unreasonable value for your production as a result of circumstances regarding that production, the MMS Director may establish an alternative valuation method.

    This method is the last alternative and would be intended for use only in very limited and highly unusual circumstances. We believe there should be very few such alternative valuation methods, and each one should be subject to careful review.

    We received several comments that this option should be offered nationwide. However, we believe this is inappropriate because valid spot prices for which reasonable location and quality adjustments may be made are available throughout the rest of the country. While the Cushing spot price likewise is valid, the remoteness of the Rocky Mountain Region may in some cases cause such severe difficulties in making reasonable location/quality adjustments that an alternative method may be warranted.

    Paragraph 206.103(c) would apply to production from leases not located in California, Alaska, or the Rocky Mountain Region. MMS proposes that value be the average of the daily mean spot prices published in an MMS-approved publication:

    (1) For the market center nearest your lease for crude oil similar in quality to that of your production. For example, at the St. James, Louisiana, market center, spot prices are published for both Light Louisiana Sweet and Eugene Island crude oils. Their quality specifications differ significantly, and you would have to use the spot price for the oil that is similar to your production; and

    (2) For deliveries during the production month.

    You would calculate the daily mean spot price by averaging the daily high and low prices for the month in the selected publication. You would use only the days and corresponding spot prices for which such prices are published. You would be required to adjust the value for applicable location and quality differentials, and you could adjust it for transportation costs, under Sec. 206.112 of this subpart.

    There may be cases where the nearest market center may not be the appropriate one for you to use because the quality of your production better matches that typically traded at another, more distant market center. In such cases, you could use this more distant market center to value your production.

    MMS proposes changing the valuation procedure to use spot, rather than NYMEX, prices, for several reasons. First, we believe that when the NYMEX futures price, properly adjusted for location and quality differences, is

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    compared to spot prices, it nearly duplicates those spot prices. Second, application of spot prices would remove one portion of the necessary adjustments to the NYMEX price--the leg between Cushing, Oklahoma, and the market center location. Although industry continued to object to any form of valuation that begins with values away from the lease, we received several comments that using the spot price rather than NYMEX futures prices would improve administration of the rule with no apparent adverse effects.

    MMS is not proposing any of the alternatives here (or for California and Alaska) that it did for the Rocky Mountain Region where oil cannot be valued under proposed Sec. 206.102. That is because, unlike the Rocky Mountain Region, there are meaningful published spot prices applicable to production in the other regions (e.g., Cushing, Oklahoma; St. James, Louisiana; Empire, Louisiana; Midland, Texas; Los Angeles/San Francisco, California). In the United States, with the exception of the Rocky Mountain Region, spot and related index-type prices drive the manner in which crude oil is bought and traded. Spot prices play a significant role in crude oil marketing. They form a basis on which deals are negotiated and priced and are readily available to lessees via price reporting services. We believe spot prices are the best indicator of value for production from leases outside the Rocky Mountain Region. Therefore, it is not necessary to consider other, less accurate means of valuing production not sold at arm's length for regions outside the Rocky Mountains.

    We received numerous comments about MMS inappropriately moving the value of production away from the lease without permitting deduction of marketing costs or the value added by the lessee and its affiliates. This proposal would not allow the costs of marketing production as a deduction from index prices or prices based on gross proceeds. The requirement to market production for the mutual benefit of the lessee and the lessor at no cost to the lessor is an implied covenant of the lease, and is not unique to Federal leases. See Section III for more detail. With respect to the costs of putting production into marketable condition, see, e.g., Mesa Operating Limited Partnership v. Department of the Interior, 931 F.2d 318 (5th Cir. 1991), cert. denied, 502 U.S. 1058 (1992); Texaco, Inc. v. Quarterman, Civil No. 96-CV-08-J (D. Wyo. 1997). It follows that any payments the lessee receives for performing such services are part of the value of the production and are royalty bearing. MMS is not altering this principle in this proposal. This proposal, in Sec. 206.106 discussed below, simply would make express the longstanding implied covenant to market.

    Proposed paragraph 206.103(d) is paragraph 206.102(c)(3) of the January 1997 proposal with minor clarifying word changes. It states that if MMS determines that any of the index (spot) prices are no longer available or no longer represent reasonable royalty value, then MMS would exercise the Secretary's authority to establish value based on other relevant matters. These could include, for example, well- established market basket formulas.

    Proposed paragraph 206.103(e) addresses situations where you transport your oil directly to your or your affiliate's refinery and believe that use of a particular index price is unreasonable. In that event, you could apply to the MMS Director for approval to use a value representing the market at the refinery. Based on the lack of comments on this provision, which was included in the February 1998 proposal, we included it in this proposal with only minor clarifying changes.

    Section 206.104 What Index Price Publications Are Acceptable to MMS?

    Section 206.104 of this proposal is paragraphs (c)(4), (c)(5), and (c)(6) of Sec. 206.102 from the January 1997 proposal with an added reference to spot prices for crude oil other than ANS. The few comments that MMS received on this section simply said that industry should have some input into which publications are accepted by MMS. We have included this section in this proposal unchanged. MMS would consult with industry groups as appropriate in deciding which publications should be used for index pricing.

    Section 206.105 What Records Must I Keep To Support My Calculations of Value Under This Subpart?

    Proposed section 206.105 specifies that you must be able to show how you calculated the value you reported, including all adjustments. This is important because if you were unable to demonstrate on audit how you calculated the value you reported to MMS, you could be subjected to sanctions for false reporting.

    Section 206.106 What Are My Responsibilities To Place Production Into Marketable Condition and To Market Production?

    Proposed section 206.106 is paragraph 206.102(e)(1) of the January 1997 proposal with minor clarifying word changes. It is unchanged from section 206.106 of in the February 1998 proposal. It says you must place oil in marketable condition and market the oil for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. We received many comments from industry that MMS is inappropriately trying to force industry to bear all marketing costs and that MMS should share in these costs. Comments from States supported the ``duty to market'' concept. We discussed this issue previously. MMS is not altering the lessee's obligation to market production at no cost to the lessor in this proposal.

    The January 1997 proposal also included, at paragraph 206.102(e)(2), a provision regarding the lessee's general responsibility to pay interest if the lessee reports value improperly and underpays royalties, or to take a credit for overpaid royalties. We deleted this provision in this proposal because these matters are already covered in other parts of MMS's regulations.

    Section 206.107 How Do I Request a Value Determination?

    This section of the February 1998 proposal provided that lessees may ask MMS for valuation guidance or propose a valuation method to MMS. It stated that MMS will promptly review the proposal and provide the requestor with a nonbinding determination.

    During the workshops help in March and April 1999 and in their written comments, industry representatives proposed a provision under which MMS would provide binding valuation determinations on a case-by- case basis. Among other provisions, the determination would have no precedential value beyond the facts in the case. Under the industry proposal, the MMS would have 180 days from the date the lessee submitted the request to make a decision, otherwise the request would be deemed approved. An MMS decision on a request would be subject to the existing appeals process.

    Industry commenters cited the need for obtaining timely valuation determinations that can be relied on for satisfying royalty obligations. Industry commenters referred MMS to procedures used by other Federal agencies to provide advance guidance on how to comply with their regulations.

    State commenters expressed general opposition to or concerns with binding determinations, stating that information could be inaccurate, incomplete, or dated and that MMS should have discretion over issuing any binding

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    determinations. A public interest group indicated it would support a binding determination as long as all of the information submitted is correct and verifiable and that the determination only applies to the requestor. A congressional commenter stated that this issue remains of concern and needs to be developed further.

    We disagree with the industry comment to make issuing a determination mandatory. In the vast majority of cases, the lessee will receive a value determination either from the Assistant Secretary, Land and Minerals Management, or from MMS staff. However, there are some situations in which a value determination is not appropriate. In proposed section 206.107(b)(3), we identify some situations in which MMS typically will not issue a value determination. These include: (1) Requests based on hypothetical situations; (2) matters that are inherently factual in nature; and (3) matters that are the subject of pending litigation or administrative appeals.

    We also disagree with the industry comment that there should be a time limit for MMS responses to requests for value determinations. None of the other Federal agency processes identified by the industry commenters includes a time limitation.

    We agree with the industry proposal to allow for lessees to propose a valuation method. We also agree that lessees should be able to rely on valuation methods they propose unless and until MMS modifies or rejects the proposal. However, industry commenters proposed that the lessee's proposed method would be automatically adopted if MMS failed to timely issue a determination.

    We disagree with this comment. First, we did not find a similar approach in any of the other Federal agency procedures identified by the industry commenters. Second, such a system would be open to abuse. A lessee could propose an unreasonable valuation method and rely upon it until MMS had time to evaluate it and reject it. Further, if MMS were unable to respond within the stated time frame, it would be unable to correct an improper valuation method and the consequent undervaluation of oil.

    The industry commenters proposed that lessees could appeal determinations with which they disagreed. A State representative commented that only bills (i.e., orders to pay) should be appealable.

    We agree with the State commenter. Under the proposed rule, value determinations issued by the Assistant Secretary would be the final action of the Department and subject to judicial review under the Administrative Procedure Act, 5 U.S.C. 701-706. Additionally, we propose in section 206.107(d)(2) that value determinations by MMS staff would not be subject to administrative appeal. A lessee that disagrees with a value determination by MMS staff may either request reconsideration or choose not to follow the determination, since it would not be binding on the lessee. However, if a lessee, either simultaneously or later, receives an order to pay on the same legal basis as the MMS staff value determination, the lessee may appeal the order under 30 CFR part 290 subpart B. Lessees should not be able to invoke the administrative appeal process until they receive actual orders to pay.

    Industry commenters suggested that the Department should only change a value determination prospectively. A public interest group recommended that MMS should be able to audit the value determination requests, and if MMS finds the information provided by the lessee to be incomplete or incorrect, could change the determination and penalize the lessee.

    We agree that as a general matter, value determinations may be changed only prospectively. The proposed rule expressly states that a value determination issued by the Assistant Secretary ``is binding on both you and MMS until the Assistant Secretary modifies or rescinds it.''

    The proposed rule also provides that a value determination by MMS staff is binding on MMS and delegated States with respect to the specific situation addressed in the determination unless the MMS Director or the Assistant Secretary modifies or rescinds it. This contrasts with value determinations signed by the Assistant Secretary, because MMS staff value determinations are not binding on the lessee. This means that MMS will not issue an order inconsistent with a value determination by MMS staff, but if a lessee does not follow that value determination, it may receive an order requiring it to pay royalties on the same basis as the value determination.

    Under proposed paragraph (e), a change in applicable statutes or regulations on which a value determination is based would supersede the value determination, regardless of whether the MMS Director or the Assistant Secretary modifies or rescinds the value determination. This would apply to all value determinations, including those signed by the Assistant Secretary, and would apply to all periods to which the change in statute or regulation applies.

    Under proposed paragraph (f), the MMS Director or the Assistant Secretary generally would not modify or rescind a value determination retroactively (regardless of whether the Assistant Secretary or MMS staff issued it), unless (1) there was a misstatement or omission of material facts; or (2) the facts subsequently developed are materially different from the facts on which the guidance was based. This reflects the principle that a value determination should not stand if it was obtained through fraud or knowing submission of false information, or if the underlying factual premises on which a value determination is based are not correct. Lessees cannot bind the government through fraudulent means or through determinations that are not based on the actual facts. If it were not possible to retroactively modify or withdraw a value determination in such situations, the government and the public would be open to serious abuse. (MMS generally would not audit the facts presented in a value determination request at the time of the request, but instead would audit these facts as appropriate when auditing payments made under the determination.)

    Proposed section 206.107(g) provides that MMS may make requests and replies available to the public subject to the confidentiality requirements of proposed section 206.108.

    Section 206.108 Does MMS Protect Information I Provide?

    As noted in the February 1998 proposal, Section 206.108 is paragraph 206.102(h) of the January 1997 proposal, but with minor wording changes for clarity.

    Section 206.109 When May I Take a Transportation Allowance in Determining Value?

    Proposed Section 206.109 includes the substance of Sec. 206.104 of the January 1997 proposal with only minor wording changes. However, in this proposal, we removed the last two sentences of paragraph (a) regarding transportation of oil that MMS takes as royalty in kind. These provisions were unnecessary because this issue is addressed in the royalty-in-kind regulations in Sec. 208.8.

    This section also includes the provision that you may not take a transportation allowance greater than 50 percent of the value of the oil determined under this subpart. We received several comments that MMS should relax this limitation. However, paragraph 206.109(c)(2) would continue the existing practice that you may ask MMS to approve a larger transportation allowance by demonstrating that your

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    reasonable, actual, and necessary costs exceed the 50 percent limitation.

    Sections 206.110 and 206.111 How Do I Determine a Transportation Allowance Under an Arm's-Length Transportation Contract, and How Do I Determine a Transportation Allowance Under a Non-Arm's-Length Transportation Contract?

    Proposed sections 206.110 and 206.111 are paragraphs 206.105(a) and (b), respectively, of the existing rule, rewritten to reflect plain English.

    Based on several comments received during the most recent workshops, we are proposing two changes to the calculation of actual transportation costs under Sec. 206.111(g). First, under the current regulations, a change in ownership does not alter the depreciation schedule. That is, a transportation system cannot be depreciated more than once by one or more owners. Proposed paragraph Sec. 206.111(g)(2) would state that an arm's-length change in ownership of a transportation system would result in a new depreciation schedule for purposes of the allowance calculation. If you or your affiliate purchase an existing transportation system at arm's length, your initial capital investment is equal to your purchase price of the transportation system.

    Second, proposed paragraph Sec. 206.111(g)(3) would provide that even after a transportation system has been, depreciated below a value equal to ten percent of your original capital investment, you may continue to include in the allowance calculation a cost equal to ten percent of your initial capital investment in the transportation system multiplied by a rate of return under paragraph (h) of this section. Under the current regulations a lessee is not allowed to claim any depreciation or return on capital once a pipeline is fully depreciated. We are proposing under paragraph Sec. 206.111(g)(3) to allow lessees to continue to claim a return on a portion of their capital investment regardless of the pipeline's depreciation status.

    Paragraph Sec. 206.111(g)(4) (existing paragraph Sec. 206.105(b)(2)(B) of the current regulations), provides an alternative for transportation facilities first placed in service after March 1, 1988. We are not proposing any change to this paragraph, but we specifically request comments on whether this paragraph should be retained in the final rule. We are asking whether this paragraph is necessary in light of the changes we are proposing to the calculation of actual transportation costs and because it is our understanding that this paragraph has been used in few, if any, situations.

    The existing rule uses the Standard and Poor's Industrial BBB bond rate as an allowable rate of return on capital investment for producers who transport oil through their own pipelines (see 30 CFR 206.157(b)(2)(v)). Two commenters from affiliated companies said the use of the BBB bond rate as an allowable return within the calculation of actual costs of transportation is arbitrary and would be considered unacceptable by any court. They said the actual rate should be much higher, reflecting the real rates of return seen in the Gulf of Mexico, and particularly in deep waters to recognize additional risk. They assert that the current rate of return based on one times BBB is too low to accurately reflect a company's cost of capital. At the public workshops held in March and April 1999 and in their written comments, industry commenters stated that the current rate does not adequately account for the cost of equity or the inherent risks of transportation systems. Industry commenters suggested that the rate should be two times the Standard and Poor's BBB bond rate.

    While MMS is not proposing specific changes to the rate of return used in calculating the return on investment under Sec. 206.111(h), we specifically request comments on whether we should modify the rate of return and, if so, what that rate should be. MMS specifically requests comment on modifying the rate of return based on multiples of the Standard and Poor's BBB bond rate, such as 1.5 times or 2 times the BBB bond rate.

    A member of Congress commented that the rate of return should be based on a company's weighted average cost of capital, taking into account both a company's return on debt and return on equity similar to the method used in formal rate making for electric utilities. We request comments on using either a company-specific or industry-wide weighted cost of capital to determine the rate of return. Your comments should address the administrative burden of verifying an individual company's or industry-wide annual weighted average cost of capital.

    We also request comments on any other method of determining the appropriate rate of return applicable to transportation systems for oil production from Federal lands. Consistent with MMS's goals in this rulemaking, any proposed methods should provide certainty and simplicity while assuring that the public receives market value for its royalty interest in Federal lease oil production.

    In the most recent round of comments, industry commenters proposed that transportation allowances in non-arm's-length situations should be based principally on the value of the service. That is, the allowance should be based on what companies pay under arm's-length contracts. Under industry's proposal, where more than 20 percent of the pipeline volume is transported at arm's length, an annualized volume-weighted average of the arm's-length rates would be used. Where less than 20 percent of the volume is arm's-length, the current MMS actual-cost method would apply; however, the rate of return would increase from the current level to twice the Standard and Poor's BBB bond rate. Undepreciated capital investment would never be less than 10 percent of the original capital cost.

    Industry commenters asserted that they only agreed to the MMS actual-cost method under the 1988 rules because of the provision to use FERC tariffs. They oppose MMS proposing to revoke use of tariffs without allowing an adequate transportation allowance rate to be deducted from the value of production at the market centers.

    Comments supporting industry's position that FERC tariffs still should be permitted in lieu of actual costs include: (1) FERC's decisions regarding its jurisdiction were flawed; (2) it was unfair for pipeline owners' transportation allowances to be based on their actual costs while non-owners could use the tariff; (3) the producing affiliate does not have the records needed to calculate actual costs; (4) audit costs for industry and MMS would increase; and (5) FERC's interpretation on jurisdiction applied only to offshore pipelines.

    State commenters agreed with MMS's position under the latest proposed rule. One congressional commenter stated that MMS should confer with FERC and develop a proposal that is more consistent with accepted public rate setting practices.

    MMS did not adopt the industry value-of-service proposal in this proposal because we continue to believe that the cost of service is most appropriate in determining deductions for royalty purposes. This is consistent with longstanding valuation and allowance principles. However, in response to industry comments and as noted above, we propose to modify the way depreciation is claimed when a transportation facility is sold. We also propose to permit a rate of return against a minimum of ten percent of the original capital investment even after the remaining depreciable amount falls below that level. We also are asking for

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    comments on the appropriate rate of return to be used in transportation allowance calculations. We believe these proposed changes and requests for comments respond in a fair and balanced way to the comments received.

    This supplementary proposed rule continues MMS's position that FERC tariffs should not be permitted as a substitute for actual costs in non-arm's-length situations. We continue to believe that FERC tariffs often exceed the transporter's actual costs. Further, we cannot presume FERC's reasoning to be flawed where it has determined that it does not have jurisdiction over offshore pipelines.

    MMS continues to maintain that it is fair to allow a lessee with an arm's-length transportation contract to use the amount it pays to the pipeline while limiting a producer transporting over its own pipeline to its actual costs. In both cases the amount allowed represents the actual costs incurred to transport the oil.

    MMS also maintains that where producing and transporting affiliates are involved, the entity claiming the allowance should be able to acquire any needed records from its affiliate. It may be true that audit costs could be somewhat higher without the FERC tariff option. However, we believe that the principle of permitting only actual costs, including a reasonable rate of return, is consistent with longstanding royalty valuation and allowance principles and fairly and reasonably protects the public interest.

    We also note that even if FERC's non-jurisdictional determinations are exclusive to offshore pipelines, those pipelines involve the great majority of transportation allowance deductions for Federal royalty purposes.

    Section 206.112 What Adjustments and Transportation Allowances Apply When I Value Oil Using Index Pricing?

    Proposed section 206.112 describes how to adjust the index price for location differentials, quality differentials, and transportation allowances depending on how you dispose of your oil.

    In the February 1998 proposal, Sec. 206.112 contained a ``menu'' of possible adjustments that could apply in different circumstances, and Sec. 206.113 prescribed which of the adjustments from the ``menu'' applied to specific circumstances. In this proposal, we have eliminated the ``menu'' and instead combined proposed Secs. 206.112 and 206.113 into one section that describes what adjustments apply when using index pricing. The ``menu'' of options would no longer be necessary with the elimination of aggregation points and MMS-published differentials, as discussed below. This new paragraph would cover all situations regardless of lease location, so there would be no need for geographical breakdown of adjustments and allowances.

    This proposal eliminates the previously-proposed location differential between the index pricing point and the market center. This is because under the valuation procedures proposed under the February 1998 proposal and continued in this proposal, the index pricing point and market center are synonymous.

    Under section 206.112(b)(1) of the February 1998 proposal, MMS would have specified location/quality differentials between aggregation points and market centers. Section 206.118 of the February 1998 proposal would have required lessees to submit a Form MMS-4415, from which MMS would have calculated these differentials. In this further supplementary proposed rule, in response to the various comments received throughout the rulemaking, we have eliminated MMS-published differentials. MMS believes that lessees using index pricing generally would have sufficient information to accurately determine location/ quality differentials, with relatively rare exceptions.

    If a lessee disposes of its oil through one or more exchange agreements, it ordinarily should have the information necessary to determine adjustments to the index price. If the oil is not disposed of through exchange agreements, then the lessee is physically transporting the oil either to a market center or to an alternate disposal point (such as a refinery.) In that event, the lessee would have the necessary information regarding actual transportation costs to claim the appropriate transportation allowance.

    As a result of eliminating MMS-published differentials, the proposed Form MMS-4415 is eliminated from this proposal. Therefore, it is not necessary to address the extensive comments MMS received regarding the content and timing of the form.

    Paragraph 206.112(a) of this supplementary proposed rule would cover situations where you dispose of your production under one or more arm's-length exchange agreements. In this case, you would adjust the index price for any location/quality differentials that reflect the difference in value of crude oil between the point(s) where your production is given in exchange and the point(s) where oil is received in exchange. You could also adjust the index price to reflect any actual transportation costs between the lease and the first point where you give your oil in exchange, and between any intermediate point where you receive oil in exchange to another point where you give the oil in exchange again, and between the last point you receive oil in exchange and a market center or refinery that is not at a market center. These costs would be determined under Secs. 206.110 or 206.111, depending on whether your transportation arrangement is at arm's length or not. (Note again, that if the transportation costs from the lease to the market center or alternate disposal point are already reflected in the location differential between the lease and the market center, you could not claim duplicate transportation costs.) A third adjustment discussed below (paragraph (d)) could be warranted if the quality of your lease production differs from that of the oil you exchanged at any intermediate point (for example, due to commingling at intermediate locations). This last adjustment would be based on pipeline quality bank premia or penalties, but only if such quality banks exist at intermediate commingling points before your oil reaches the market center or alternate disposal point.

    For example, Company A transports its production from a platform in the Gulf of Mexico to an intermediate point under an arm's-length transportation contract for $0.50 per barrel. Company A then enters into an arm's-length exchange agreement between the intermediate point and the market center at St. James, Louisiana. Company A then refines the oil it receives at the market center, so it would have to determine value using an index price under Sec. 206.103. The arm's-length exchange agreement between the intermediate point and St. James contains a location/quality differential of $0.10 per barrel. The average of the daily mean spot prices for St. James (the market center nearest the lease with crude oil most similar in quality to Company A's oil) is $20.00 per barrel for deliveries during the production month. The value of Company A's production at the lease would be $19.40 ($20.00--$0.10--$0.50) per barrel.

    Under paragraph 206.112(a), you would have to determine the differentials from each of your arm's-length exchange agreements applicable to the exchanged oil. Therefore, for example, if you exchange 100 barrels of production under two separate arm's-length exchange agreements for 60 barrels and 40 barrels respectively, you would separately determine the location/quality differential under each of those exchange agreements, and

    [[Page 73836]]

    apply each differential to the corresponding index price.

    As another example, if you produce 100 barrels and exchange that 100 barrels three successive times under arm's-length agreements to obtain oil at a final destination, you would total the three adjustments from those exchanges to determine the adjustment under this subparagraph. (If one of the three exchanges were not at arm's length, you would have to request MMS approval under paragraph (b) for the location/quality adjustment for that exchange to determine the total location/quality adjustment for the three exchanges.) You also could have a combination of these examples.

    Proposed paragraph 206.112(b) addresses cases where your exchange agreement is not at arm's-length. In that case, you must request approval from MMS for any location/quality adjustment.

    Paragraph 206.112(c) would address cases where you transport your production directly to a market center or to an alternate disposal point (for example, your refinery), and establish value based on index prices under Sec. 206.103.

    In the case of transportation directly to a refinery, you would deduct from the index price your actual costs of transporting production from the lease to the refinery with the costs determined under Secs. 206.110 or 206.111 and any quality adjustments determined by pipeline quality banks under paragraph 206.112(d). The index pricing point would be the one nearest the lease.

    For example, a lessee or its affiliate in the Gulf of Mexico might transport its production directly to a refinery on the eastern coast of Texas and not to an index pricing point. Because that production is not sold at arm's length, the lessee would have to base value on the average of the daily mean spot prices for St. James, less actual costs of transporting the oil to the refinery and any quality adjustments from the lease to the refinery.

    Likewise, if a lessee or its affiliate transports Wyoming sour crude oil directly to its refinery in Salt Lake City, Utah, and values the oil based on paragraph 206.103(b)(3), the lessee would have to base value on the average of the daily Cushing spot prices, less the actual cost of transporting the oil to Salt Lake City and any quality adjustments between the lease and the refinery.

    When production is moved directly to a refinery and value must be established using an index, issues arise because the refinery generally is not located at an index pricing point. Consequently, the lessee does not incur actual costs to transport production to an index pricing point, and in any event, the production is not sold at arm's length at that point. The principle underlying the rules and cases granting allowances for transportation costs is that the lessee is not required to transport production to a market remote from the lease or field at its own expense. When the lessee sells production at a remote market, the costs of transporting to that market are deductible from value at that market to determine the value of the production at or near the lease. Where sales occur only at or near the lease, the question of a transportation allowance, as that term always has been understood, does not arise. However, because the lease and the index pricing point may be distant from one another, there is a difference in the value of the production between the index pricing point and the lease location. The question becomes how to determine or how best to approximate that difference in value.

    In theory, one solution would be for MMS to try to derive what it would cost a lessee to move production from the lease to the index pricing point. There are, in MMS's view, several problems with such an approach. First, it would require a burdensome information collection from industry and impose substantial information collection costs on many parties to whom the resulting calculation may never be relevant. Second, in many cases it may well not be possible to obtain information on which to base such a calculation. In many instances, it is likely that no production from the lease or field is transported to the index pricing point that applies under Sec. 206.103. Consequently, in such cases there would be no useful data on which such a cost derivation could be based.

    Another possible solution, in theory, would be for MMS to derive a location adjustment between the index pricing point and the refinery. This might be possible if, for example, there are arm's-length exchanges of significant volumes of oil between the index pricing point and the refinery, and if the exchange agreements provide for location adjustments that can be separated from quality adjustments. But establishing such location adjustments on any scale again would require a burdensome information collection effort. MMS also anticipates that in many cases there would be no useful data from which to derive a location adjustment.

    MMS therefore believes that the best and most practical proxy method for determining the difference in value between the lease and the index pricing point is to use the index price as value at the refinery, and then allow the lessee to deduct the actual costs of moving the production from the lease to the refinery. This is not a ``transportation allowance'' as that term is commonly understood, but rather is part of the methodology for determining the difference in value due to the location difference between the lease and the index pricing point. Nevertheless, it is appropriate to include this deduction for situations in which index pricing is used.

    MMS included this same method in the January 1997 proposal and did not receive any suggestions for alternative methods. We received few comments on this issue in response to the February 1998 proposal. However, one State commented that this method could result in calculation of inappropriate differentials. Absent better alternatives, MMS believes this method is the best and most reasonable way to calculate the differences in value due to location when production is not actually moved from the lease to an index pricing point.

    However, if a lessee believes that applying the index price nearest the lease to production moved directly to a refinery results in an unreasonable value based on circumstances of the lessee's production, paragraph 206.103(e) would allow MMS to approve an alternative method if the lessee could demonstrate the market value at the refinery. Although we received a few comments that MMS should not allow such requests, MMS believes it should leave this opportunity open for those limited cases where the procedure discussed above may be shown to be inappropriate. MMS would do a thorough review and analysis of any such requests and would only approve them where the proper alternative value or procedure has been clearly demonstrated.

    It would be the lessee's burden to provide adequate documentation and evidence demonstrating the market value at the refinery. That evidence could include, but not be limited to: (1) Costs of acquiring other crude oil at or for the refinery; (2) how adjustments for quality, location, and transportation were factored into the price paid for the other oil; (3) the volumes acquired for the refinery; and (4) other appropriate evidence or documentation that MMS would require. If MMS approved an alternative value representing market value at the refinery, there would be no deduction for the costs of transporting the oil to the refinery unless specifically identified in the Director's approval. Whether any quality adjustment is available would depend on whether the oil passes through a pipeline quality

    [[Page 73837]]

    bank or if an arm's-length exchange agreement used to get oil to the refinery contains a separately-identifiable quality adjustment.

    Paragraph 206.112(c) would also cover situations where you transport your oil directly to an MMS-identified market center. To arrive at the royalty value, you would adjust the index price by your actual costs of transportation under Secs. 206.110 and 206.111. A second adjustment discussed below (paragraph (d)) may be warranted if the quality of your lease production differs from the quality of the oil at the market center. This adjustment would be based on pipeline quality bank premia or penalties, but only if such quality banks exist at intermediate commingling points before your oil reaches the market center.

    For example, Company A transports its production from a platform in the Gulf of Mexico to St. James, Louisiana, under a non-arm's-length transportation contract with its affiliate. The actual cost of transporting production under Sec. 206.111 is $0.50 per barrel. The average of the daily spot prices at St. James is $20.00 per barrel for deliveries during the production month. The value of Company A's production at the lease would be $19.50 ($20.00--$0.50) per barrel.

    In the February 1998 proposal at paragraph 206.112(e), and in this proposal at paragraph 206.112(d), MMS added a separate adjustment to reflect quality differences based on quality banks between your lease and an alternate disposal point or market center applicable to your lease. You would make these quality adjustments according to the pipeline quality bank specifications and related premia or penalties that may apply in your specific situation. If no pipeline quality bank applies to your production, then you would not take this quality adjustment. Likewise, if a quality adjustment is already contained in an arm's-length exchange agreement from the lease to the market center, you could not also claim a pipeline quality bank adjustment from the lease to an intermediate point or the market center. MMS believes this additional adjustment would more accurately reflect actual quality adjustments made by buyers and sellers.

    Also, in the absence of a quality bank, the proposal does not provide for any adjustments for quality differences between the indexed crude oil and the oil produced at the lease. MMS intentionally limited such adjustments only to those cases where a quality bank applies to the lessee's production. MMS does not want to be in a position of permitting quality adjustments where they may not be warranted. Further, quality adjustments would be reflected in the location differentials applied by lessees from their arm's-length exchange agreements.

    In this proposal, paragraph 206.112(e) contains language from proposed paragraph 206.112(f) of the February 1998 proposal. It states that the term ``market center'' means Cushing, Oklahoma, when determining location/quality differentials and transportation allowances for production from leases in the Rocky Mountain Region.

    Paragraph 206.112(f) of this proposal addresses situations where you may not have access to differentials between the lease and the alternate disposal point or market center, or you may not have access to the actual transportation costs from the lease to the alternate disposal point or market center. In such cases, which should be infrequent, MMS would permit you to request approval for a transportation allowance or quality adjustment. In determining the allowance for transportation from the lease to the alternate disposal point or market center, MMS would look to transportation costs and quality adjustments reported for other oil production in the same field or area, or to available information for similar transportation situations. Under paragraph 206.112(b), you also would have to request approval from MMS for any location/quality adjustments when you have a non-arm's-length exchange agreement.

    In this proposal, we added a new paragraph (g) to Sec. 206.112 to clarify that regardless of how you dispose of your production and which adjustments might otherwise apply, you would not be able to use any transportation or quality adjustment that duplicates all or part of any other adjustment that you use under Sec. 206.112. Moreover, the structure of the proposal is not susceptible to the problem of ``double dipping'' quality adjustments as described by one commenter. Under this proposal, for example, if you disposed of your production under an arm's-length exchange agreement, but transported the oil away from the lease to an intermediate point before giving it in exchange, you would not be able to claim a transportation allowance between the point where you gave the oil in exchange and the point you received oil back in exchange if you used a location differential for the segment between those two points.

    This same principle would apply for all adjustments addressed in Sec. 206.112. That is, any time a lessee took one of the listed adjustments, it could not duplicate any portion of that adjustment as part or all of any other adjustment that otherwise would be allowable.

    Section 206.113 How Will MMS Identify Market Centers?

    Proposed section 206.113 is paragraph 206.105(c)(8) of the January 1997 proposal and Section 206.115 of the February 1998 proposal except that we have eliminated the identification of aggregation points and made minor wording changes. MMS proposes to eliminate the list of aggregation points identified in the January 1997 proposal in conjunction with the elimination of Form MMS-4415.

    In the preamble to the January 1997 proposal, MMS listed market centers for purposes of the rule. That list included Guernsey, Wyoming. MMS proposes to eliminate Guernsey as a market center for the reasons given earlier. Also, we received comments that simply using Los Angeles and San Francisco as market centers for ANS pricing purposes was too broad and that multiple, local delivery points in and near these two cities should be included in the market center definition. So, for purposes of this rulemaking, the Los Angeles market center would includes Hines Station, GATX Terminal, and any of the refineries located in Los Angeles County. The San Francisco market center would include Avon, or any of the refineries located in Contra Costa or Solano Counties.

    Section 206.114 What Are My Reporting Requirements Under an Arm's- Length Transportation Contract?

    Proposed Section 206.114 is paragraph 206.105(c)(1) of the existing rule rewritten in plain English, and is the same as Section 206.116 in the February 1998 proposal.

    Section 206.115 What Are My Reporting Requirements Under a Non-Arm's- Length Transportation Contract?

    Proposed Section 206.115 is paragraph 206.105(c)(2) of the existing rule rewritten in plain English, except paragraph 206.105(c)(2)(iv) is deleted as described in the preamble to the January 1997 proposal. This also corresponds to Section 206.117 in the February 1998 proposal.

    Section 206.116 What Interest and Assessments Apply If I Improperly Report a Transportation Allowance?

    Section 206.116 of this proposal is paragraph 206.105(d) of the existing rule rewritten in plain English, and also corresponds to Section 206.119 of the February 1998 proposal.

    [[Page 73838]]

    Section 206.117 What Reporting Adjustments Must I Make for Transportation Allowances?

    Section 206.117 of this proposal is paragraph 206.105(e) of the existing rule rewritten in plain English, and corresponds to Section 206.120 of the February 1998 proposal.

    Section 206.118 Are Costs Allowed for Actual or Theoretical Losses?

    Section 206.118 of this proposal is paragraph 206.105(f) of the existing rule rewritten in plain English, and corresponds to Section 206.121 of the February 1998 proposal. Reference to the FERC- or State regulatory agency-approved tariffs was deleted in the January 1997 proposal, as it is in this proposal. Although we received a comment that actual or theoretical losses are real costs of transportation, this section would simply continue longstanding policy.

    Section 206.119 How Are the Royalty Quantity and Quality Determined?

    Section 206.119 of this proposal is Sec. 206.103 of the existing rule rewritten in plain English, and corresponds to Section 206.122 of the February 1998 proposal.

    Section 206.120 How Are Operating Allowances Determined?

    Section 206.120 of this proposal is Sec. 206.106 of the existing rule rewritten in plain English, and corresponds to Section 206.123 of the February 1998 proposal.

  5. Procedural Matters

    Public Comment Policy

    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.rmp.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.

    You may also comment via the Internet to www.rmp.mms.gov. Please submit Internet comments as an ASCII file avoiding the use of special characters and any form of encryption. Please also include Attn: Further Supplementary Proposed Rulemaking Establishing Oil Value for Royalty Due on Federal Leases, and your name and return address in your Internet message. If you do not receive a confirmation from the system that we have received your Internet message, contact David S. Guzy directly at (303) 231-3432.

    We will post public comments after the comment period closes on the Internet at www.rmp.mms.gov. You may arrange to view paper copies of the comments by contacting David S. Guzy, Chief, Rules and Publications Staff, telephone (303) 231-3432, FAX (303) 231-3385.

    Executive Order 12866

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

    This further supplementary proposed rule would not have an annual effect of $100 million or adversely affect an economic sector, productivity, jobs, the environment, or other units of Government. We estimate that the economic impact of this further supplementary proposed rule would be about $63.5 million. This estimate represents the net impact of the proposal accounting for both estimated costs and benefits. This proposal would not create inconsistencies with other agencies' actions and would not materially affect entitlements, grants, user fees, loan programs, or the rights and obligations of their recipients.

    The Regulatory Flexibility Act

    The Department of the Interior certifies that this document will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). Accordingly, a Small Entity Compliance Guide is not required. This proposed rule would not affect a substantial number of small businesses. Approximately 800 businesses pay royalties to MMS on oil produced from Federal leases. MMS believes only 45 of the 800 total payors would pay additional royalties under this proposed rule. We further believe that only nine of those 45 payors are small businesses as defined by the U.S. Small Business Administration. MMS further estimates that 97 percent of the remaining 755 payors, or 732, would be considered small businesses. The nine payors that we consider small businesses that would be affected by the rule make up less than 1.15 percent of all the payors reporting to MMS on oil produced from Federal leases and less than 1.25 percent of all the small businesses reporting to MMS on oil produced from Federal leases. A Regulatory Analysis is available upon request.

    Small Business Regulatory Enforcement Fairness Act (SBREFA)

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

    (a) Would not have an annual effect on the economy of $100 million or more;

    (b) Would not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions; and

    (c) Would 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.

    Unfunded Mandates Reform Act of 1995

    This rule would not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. This rule would not change the relationship between MMS, and State, local, or tribal governments. A statement containing the information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531 et seq.) is not required.

    Executive Order 12630

    MMS received a comment on the February 1998 proposal that the proposed rule deprives lessees of their constitutionally protected property rights when royalties are paid based on a higher than actual lease sales price. This is a price that the lessee would find impossible to actually realize because it includes returns on investments and on downstream marketing profits. The commenter asserted that because such a taking would occur if the rule is approved, MMS must prepare a Takings Implication Assessment pursuant to Executive Order 12630.

    The guidelines under Executive Order 12630 require a Federal agency to justly compensate a private property owner if private property is taken for public use. Disagreements over methods of valuing production for royalty purposes do not change the property relationship

    [[Page 73839]]

    between a lessee and the Federal lessor, and do not operate to deprive the lessee of any property interest. Even if a particular valuation method is held to be unlawful or unauthorized, the remedy is to overturn the unauthorized agency action. This does not have constitutional takings implications.

    In accordance with Executive Order 12630, the rule would not have significant takings implications. This rule would not impose conditions or limitations on the use of any private property; consequently, a takings implication assessment is not required.

    Executive Order 13132 (Federalism)

    In accordance with Executive Order 13132, this further supplementary proposed rule does not have Federalism implications. 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 further supplementary 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 further supplementary 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 further supplementary proposed rule would not alter that relationship.

    Executive Order 12988

    In accordance with Executive Order 12988, the Office of the Solicitor has determined that this rule would not unduly burden the judicial system and meets the requirements of Secs. 3(a) and 3(b)(2) of the Order.

    Paperwork Reduction Act

    Under the Paperwork Reduction Act of 1995, we are soliciting comments on information collections which are associated with this further supplementary proposed rulemaking establishing oil value for royalty due on federal leases. Written comments should be received on or before January 31, 2000.

    If you wish to comment, please send your comments directly to the Office of Information and Regulatory Affairs, OMB, Attention: Desk Officer for the Interior Department (OMB Control Number 1010-NEW), 725 17th Street, NW, Washington, D.C. 20503.

    You should also send copies of these comments to us. You may mail comments to David S. Guzy, Chief, Rules and Publications Staff, Minerals Management Service, Royalty Management Program, P.O. Box 25165, MS 3021, Denver, CO 80225-0165. Courier or overnight delivery address is Building 85, Room A-613, Denver Federal Center, Denver, Colorado 80225.

    Section 3506(c)(2)(A) of the Paperwork Reduction Act 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.

    For all of the following information collections, we estimate that there will be 45 respondents who will submit 85 responses. The frequency of response varies by rulemaking section. We estimate the annual proposed burden to be 17,711.5 hours. Based on $50 per hour, the total cost would be $885,575. For estimating the burden on industry, we divided the information collection requirements of the further supplementary proposed rule into five areas. A table for each of the areas and specific details follow: a. Proper Valuation of Oil Not Sold at Arm's-Length

    Annual 30 CFR 206, subpart D

    Reporting & recordkeeping

    Frequency

    Number of

    Burden

    burden requirements

    respondents

    hours

    206.103............................. Calculate value of oil not Monthly.....................

    45 Category 1--222.5 hours;

    4,231.5 sold at arm's-length.

    Category 2--116 hours; Category 3--31.25 hours.

    For the reporting requirements associated with Section 206.103, we estimate that there are 45 respondents (lessees of Federal oil leases) that will be required to perform certain calculations and adjustments monthly. We estimate that the total initial burden for all lessees without arm's-length transactions is 4,231.5 hours at a cost of $211,575.

    We anticipate that companies would have to sort through their exchange agreement contracts before the relevant ones can be compiled and the required information extracted and used in their royalty computations. We believe the further supplementary proposed rule would impact approximately 45 Federal oil lessees that would be required to use index pricing. For purposes of estimating the burden impact of this further supplementary proposed rule, we have categorized these lessees into three categories:

    Category 1 lessees are companies with over 30 million barrels of annual production (this included 13 Federal lessees from our impact analysis).

    Category 2 lessees are companies with annual domestic production between 10 and 30 million barrels (this included four Federal lessees from our impact analysis).

    Category 3 lessees are companies with less than 10 million barrels of annual domestic production (this included 28 Federal lessees from our impact analysis).

    We estimate that Category 1 lessees each would have approximately 1,000 exchange agreement contracts to review to identify the relevant contracts needed for proper valuation under this further supplementary proposed rule. Of those contracts, we estimate that each company would have to use 250 exchange agreements in its royalty reporting. We estimate that the reporting burden for a Category 1 company is 222.5 hours, including 80 hours to aggregate the exchange agreement contracts to a central location, 80 hours to sort and identify the relevant ones, and 62.5 additional hours to extract the relevant information and apply it in reporting royalties. We estimate the total reporting burden for the 13 Category 1 companies would be 2,892.5 hours (222.5 hours x 13 companies), including recordkeeping; using a per-hour cost of $50, the total cost would be $144,625.

    We estimate that Category 2 lessees each would have approximately 250

    [[Page 73840]]

    exchange agreement contracts to review to identify the relevant contracts needed for valuation under this further supplementary proposed rule. Of those contracts, we estimate that each Category 2 company would have to use 63 exchange agreements. We estimate that the reporting burden for a Category 2 company would be 116 hours, including 60 hours to aggregate the exchange agreement contracts to a central location, 40 hours to sort them, and 16 additional hours to extract the relevant information and apply it in reporting royalties. For the 4 Category 2 companies, we estimate the total burden would be 464 hours (116 hours x 4 companies), including recordkeeping; using a per-hour cost of $50, the total cost would be $23,200.

    We estimate that Category 3 lessees each would have approximately 50 exchange agreements to review to identify the relevant contracts needed for valuation under this further supplementary proposed rule. Of those contracts, we estimate that each Category 3 company would have to use 13 exchange agreements. We estimate that the burden for each Category 3 company would be 31.25 hours, including 20 hours to aggregate the exchange agreement contracts to a central location, 8 hours to sort them, and 3.25 additional hours to extract the relevant information and apply it in reporting royalties. For the 28 Category 3 companies, we estimate that the burden would be 875 hours (31.25 hours x 28 companies), including recordkeeping; using a per-hour cost of $50, the total cost would be $43,750.

    We expect the annual burden to decline somewhat as industry becomes more familiar with the proposed valuation requirements. b. Approval of Benchmarks in the Rocky Mountain Region

    Reporting &

    Annual

    30 CFR 206, subpart D

    recordkeeping

    Frequency

    Number of Burden burden requirements

    responses (hours) hours

    206.103(b)(1)................ Obtain MMS approval 1-2 annually........

    2

    400

    800 for tendering program. 206.103(b)(4)................ Obtain MMS approval 1-2 annually........

    2

    400

    800 for alternative valuation methodology.

    For the reporting requirements related to MMS approval of using the benchmarks, we estimate that there will be two responses for each of the two reporting requirements. On occasion, they will be required to submit requests to us in writing.

    We anticipate that a lessee will undertake the following four steps in the formulation of specifics surrounding a tendering program or alternate valuation strategy: (1) formulation of valuation methodology: 100 hours, (2) economic evaluation of methodology: 100 hours, (3) legal review of methodology: 150 hours, and (4) presentation to MMS: 50 hours, for a total of 400 hours.

    We anticipate four requests a year for an annual burden of 1,600 hours, including recordkeeping. Based on a per-hour cost of $50, we estimate that the cost to industry is $80,000. c. Requirements Related to Requested Valuation Determinations and Approval of Location/Quality Adjustments From MMS

    Reporting &

    Annual

    30 CFR 206, subpart D

    recordkeeping

    Frequency

    Number of Burden burden requirements

    responses (hours) hours

    206.107(a)(1)-(6)............ Request a value 1-2 monthly.........

    8

    330

    2,640 determination from MMS. 206.112(b)................... Request MMS approval 1-2 monthly.........

    8

    330

    2,640 for location/ quality adjustment under non-arm's- length exchange agreements. 206.112(f)................... Request MMS for 1-2 monthly.........

    8

    330

    2,640 location/quality adjustment when information is not available.

    We anticipate that the companies may request guidance on how royalty statutes, regulations, administrative decisions, and policies apply to a specific set of facts. Their 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. They must inform MMS of any changes to relevant facts that occur before MMS responds to their request; (4) include copies of all relevant documents; (5) provide their analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and (6) suggest their proposed valuation method.

    For the above written requests, we estimate that there will be eight responses annually for each of the reporting requirements. We estimate the annual burden for each of these is 2,640 hours, including recordkeeping. Based on a per-hour cost of $50, we estimate the cost to industry is $132,000. The total burden is estimated at 7,920 hours and $396,000. d. Requirements Related to Special Requests Due to Unique Circumstances

    Reporting &

    Annual

    30 CFR 206, subpart D

    recordkeeping

    Frequency

    Number of Burden burden requirements

    responses (hours) hours

    206.103(e)(1) and (2)(i)-(iv) Obtain MMS approval 1-2 annually........

    2

    330

    660 to use value determined at refinery. 206.110(b)(2)................ Propose

    1-2 annually........

    2

    330

    660 transportation cost allocation method to MMS when transporting more than one liquid product under an arm's-length contract.

    [[Page 73841]]

    206.110(c)(1) and (3)........ Propose

    1-2 annually........

    2

    330

    660 transportation cost allocation method to MMS when transporting gaseous and liquid products under an arm's-length contract. 206.111(g) and (g)(1)........ Elect actual

    1-2 annually........

    2

    330

    660 transportation cost method and depreciation method for non-arm's- length transportation allowances. 206.111(i)(2)................ Propose

    1-2 annually........

    2

    330

    660 transportation cost allocation method to MMS when transporting more than one liquid product under a non- arm's-length contract. 206.111(j)(1) and (3)........ Propose

    1-2 annually........

    2

    330

    660 transportation cost allocation method to MMS when transporting gaseous and liquid product under a non- arm's-length contract..

    There are several provisions in the further supplementary proposed rule that allow the lessee to propose some special consideration because the existing provisions of the rule may not precisely fit their situation. Like the written requests outlined above, their 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. They must inform MMS of any changes to relevant facts that occur before MMS responds to their request; (4) include copies of all relevant documents; (5) provide their analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and (6) suggest their proposed valuation method.

    For the reporting requirements related to special requests because of unique circumstances, we estimate that there will be two responses for each of the six situations above. We estimate the annual burden for each of these is 660 hours, including recordkeeping. Based on a per- hour cost of $50, we estimate the cost to industry is $33,000. The total burden is estimated to be 3,960 hours and $198,000. e. Currently Approved Information Collections

    Reporting &

    Annual

    30 CFR 206, subpart D

    recordkeeping

    Frequency

    Number of Burden burden requirements

    responses (hours) hours

    206.105...................... Retain all records Burden covered under OMB Control No. 1010- showing how value

    0061. was determined. 206.109(c)(2)................ Request to exceed Burden covered under OMB Control No. 1010- regulatory limit--

    0095. Form MMS-4393. 206.114 and 115(a)........... Report a separate Burden covered under OMB Control No. 1010- line for

    0022. transportation allowances--Form MMS-2014. 206.114 and 115(c)........... Submit

    Burden covered under OMB Control No. 1010- transportation

    0061. documents upon MMS request.

    National Environmental Policy Act of 1969

    This rule would not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the National Environmental Policy Act of 1969 is not required.

    Clarity of This Regulation

    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 this clarity? (3) Does the format of the 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 ``Sec. '' and a numbered heading; for example Sec. 206.100.) (5) Is the description of the rule in the ``Supplementary Information'' section of the preamble helpful in understanding the 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.

    List of Subjects 30 CFR Part 206

    Coal, Continental shelf, Geothermal energy, Government contracts, Indians--lands, Mineral royalties, Natural gas, Petroleum, Pubic lands--mineral resources, Reporting and recordkeeping requirements.

    Dated December 22, 1999. Sylvia V. Baca, Assistant Secretary for Land and Minerals Management.

    For the reasons given in the preamble, 30 CFR Part 206 is proposed to be amended as set forth below:

    PART 206--PRODUCT VALUATION

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

    Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et seq.; 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et seq., and 1801 et seq.

    2. Subpart C--Federal Oil is revised to read as follows:

    Subpart C--Federal Oil

    Sec. 206.100 What is the purpose of this subpart? 206.101 Definitions.

    [[Page 73842]]

    206.102 How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm's-length contract? 206.103 How do I value oil that is not sold under an arm's-length contract? 206.104 What index price publications are acceptable to MMS? 206.105 What records must I keep to support my calculations of value under this subpart? 206.106 What are my responsibilities to place production into marketable condition and to market production? 206.107 How do I request a value determination? 206.108 Does MMS protect information I provide? 206.109 When may I take a transportation allowance in determining value? 206.110 How do I determine a transportation allowance under an arm's-length transportation contract? 206.111 How do I determine a transportation allowance under a non- arm's-length transportation arrangement? 206.112 What adjustments and transportation allowances apply when I value oil using index pricing? 206.113 How will MMS identify market centers? 206.114 What are my reporting requirements under an arm's-length transportation contract? 206.115 What are my reporting requirements under a non-arm's-length transportation contract? 206.116 What interest and assessments apply if I improperly report a transportation allowance? 206.117 What reporting adjustments must I make for transportation allowances? 206.118 Are costs allowed for actual or theoretical losses? 206.119 How are the royalty quantity and quality determined? 206.120 How are operating allowances determined?

    Subpart C--Federal Oil

    Sec. 206.100 What is the purpose of this subpart?

    (a) This subpart applies to all oil produced from Federal oil and gas leases onshore and on the Outer Continental Shelf (OCS). It explains how you as a lessee must calculate the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms. If you are a designee and if you dispose of production on behalf of a lessee, the terms ``you'' and ``your'' in this subpart refer to you. If you are a designee and only report for a lessee, and do not dispose of the lessee's production, references to ``you'' and ``your'' in this subpart refer to the lessee and not the designee. Accordingly, you as a designee must determine and report royalty value for the lessee's oil by applying the rules in this subpart to the lessee's disposition of its oil.

    (b) If the regulations in this subpart are inconsistent with:

    (1) A Federal statute;

    (2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation; or

    (3) An express provision of an oil and gas lease subject to this subpart, then the statute, settlement agreement, or lease provision will govern to the extent of the inconsistency.

    (c) MMS may audit and adjust all royalty payments.

    Sec. 206.101 Definitions.

    The following definitions apply to this subpart:

    Affiliate means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:

    (1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.

    (2) If there is ownership or common ownership of between 10 and 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:

    (i) The extent to which there are common officers or directors;

    (ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership,

    (A) The percentage of ownership or common ownership;

    (B) The relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons;

    (C) Whether a person is the greatest single owner; and

    (D) Whether there is an opposing voting bloc of greater ownership;

    (iii) Operation of a lease, plant, or other facility;

    (iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, or other facility; and

    (v) Other evidence of power to exercise control over or common control with another person.

    (3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.

    ANS means Alaska North Slope (ANS).

    Area means a geographic region at least as large as the limits of an oil field, in which oil has similar quality, economic, and legal characteristics.

    Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.

    Audit means a review, conducted under generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees, designees or other persons who pay royalties, rents, or bonuses on Federal leases.

    BLM means the Bureau of Land Management of the Department of the Interior.

    Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without processing. Condensate is the mixture of liquid hydrocarbons resulting from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.

    Contract means any oral or written agreement, including amendments or revisions, between two or more persons, that is enforceable by law and that with due consideration creates an obligation.

    Designee means the person the lessee designates to report and pay the lessee's royalties for a lease.

    Exchange agreement means an agreement where one person agrees to deliver oil to another person at a specified location in exchange for oil deliveries at another location. Exchange agreements may or may not specify prices for the oil involved. They frequently specify dollar amounts reflecting location, quality, or other differentials. Exchange agreements include buy/sell agreements, which specify prices to be paid at each exchange point and may appear to be two separate sales within the same agreement. Examples of other types of exchange agreements include, but are not limited to, exchanges of produced oil for specific types of crude oil (e.g., West Texas Intermediate); exchanges of produced oil for other crude oil at other locations (Location Trades); exchanges of produced oil for futures contracts (Exchanges for Physical, or EFP); exchanges of produced oil for similar oil produced in different months (Time Trades); exchanges of produced oil for other grades of oil (Grade Trades); and multi-party exchanges.

    Field means a geographic region situated over one or more subsurface oil

    [[Page 73843]]

    and gas reservoirs and encompassing at least the outermost boundaries of all oil and gas accumulations known within those reservoirs, vertically projected to the land surface. State oil and gas regulatory agencies usually name onshore fields and designate their official boundaries. MMS names and designates boundaries of OCS fields.

    Gathering means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area, or to a central accumulation or treatment point off the lease, unit, or communitized area that BLM or MMS approves for onshore and offshore leases, respectively.

    Gross proceeds means the total monies and other consideration accruing for the disposition of oil produced. Gross proceeds also include, but are not limited to, the following examples:

    (1) Payments for services such as dehydration, marketing, measurement, or gathering which the lessee must perform at no cost to the Federal Government;

    (2) The value of services, such as salt water disposal, that the producer normally performs but that the buyer performs on the producer's behalf;

    (3) Reimbursements for harboring or terminaling fees;

    (4) Tax reimbursements, even though the Federal royalty interest may be exempt from taxation;

    (5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods, by allocating such payments over the production whose price the payment reduces and including the allocated amounts as proceeds for the production as it occurs; and

    (6) Monies and all other consideration to which a seller is contractually or legally entitled, but does not seek to collect through reasonable efforts.

    Index pricing means using ANS crude oil spot prices, West Texas Intermediate (WTI) crude oil spot prices at Cushing, Oklahoma, or other appropriate crude oil spot prices for royalty valuation.

    Index pricing point means the physical location where an index price is established in an MMS-approved publication.

    Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of oil or gas--or the land area covered by that authorization, whichever the context requires.

    Lessee means any person to whom the United States issues an oil and gas lease, an assignee of all or a part of the record title interest, or any person to whom operating rights in a lease have been assigned.

    Location differential means an amount paid or received under an exchange agreement that results from differences in location between oil delivered in exchange and oil received in the exchange. A location differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell exchange agreement.

    Market center means a major point MMS recognizes for oil sales, refining, or transshipment. Market centers generally are locations where MMS-approved publications publish oil spot prices.

    Marketable condition means oil sufficiently free from impurities and otherwise in a condition a purchaser will accept under a sales contract typical for the field or area.

    MMS-approved publication means a publication MMS approves for determining ANS spot prices, other spot prices, or location differentials.

    Netting means reducing the reported sales value to account for transportation instead of reporting a transportation allowance as a separate line on Form MMS-2014.

    Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs, remains liquid at atmospheric pressure after passing through surface separating facilities, and is marketed or used as a liquid. Condensate recovered in lease separators or field facilities is considered oil.

    Outer Continental Shelf (OCS) means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.

    Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).

    Quality differential means an amount paid or received under an exchange agreement that results from differences in API gravity, sulfur content, viscosity, metals content, and other quality factors between oil delivered and oil received in the exchange. A quality differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell agreement.

    Rocky Mountain Region means the States of Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming.

    Sale means a contract between two persons where:

    (1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights such as the right to buy back similar quantities of oil from the buyer elsewhere;

    (2) The buyer pays money or other consideration for the oil; and

    (3) The parties' intent is for a sale of the oil to occur.

    Spot price means the price under a spot sales contract where:

    (1) A seller agrees to sell to a buyer a specified amount of oil at a specified price over a specified period of short duration;

    (2) No cancellation notice is required to terminate the sales agreement; and

    (3) There is no obligation or implied intent to continue to sell in subsequent periods.

    Tendering program means a company offer of a portion of its crude oil produced from a field or area for competitive bidding, regardless of whether the production is offered or sold at or near the lease or unit or away from the lease or unit.

    Transportation allowance means a deduction in determining royalty value for the reasonable, actual costs of moving oil to a point of sale or delivery off the lease, unit area, or communitized area. The transportation allowance does not include gathering costs.

    Sec. 206.102 How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm's-length contract?

    (a) The value of oil under paragraphs (a)(1) and (a)(2) of this section is the gross proceeds accruing to the seller under the arm's- length contract, less applicable allowances determined under this subpart, unless you exercise an option provided in paragraph (d)(1) or (d)(2) of this section. See paragraph (c) of this section for exceptions. Use this paragraph (a) to value oil that:

    (1) You sell under an arm's-length sales contract; or

    (2) You sell or transfer to your affiliate or another person under a non-arm's-length contract and that affiliate or person, or another affiliate of either of them, then sells the oil under an arm's-length contract.

    (b) If you sell under multiple arm's-length contracts oil produced from a lease that is valued under paragraph (a) of this section, the value of the oil is the

    [[Page 73844]]

    volume-weighted average of the values established under this section for each contract for the sale of oil produced from that lease.

    (c) This paragraph contains exceptions to the valuation rule in paragraph (a) of this section. Apply these exceptions on an individual contract basis.

    (1) In conducting reviews and audits, if MMS determines that any arm's-length sales contract does not reflect the total consideration actually transferred either directly or indirectly from the buyer to the seller, MMS may require that you value the oil sold under that contract either under Sec. 206.103 or at the total consideration received.

    (2) You must value the oil under Sec. 206.103 if MMS determines that the value under paragraph (a) of this section does not reflect the reasonable value of the production due to either:

    (i) Misconduct by or between the parties to the arm's-length contract; or

    (ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor.

    (A) MMS will not use this provision to simply substitute its judgment of the market value of the oil for the proceeds received by the seller under an arm's-length sales contract.

    (B) The fact that the price received by the seller in an arm's length transaction is less than other measures of market price, such as index prices, is insufficient to establish breach of the duty to market unless MMS finds additional evidence that the seller acted unreasonably or in bad faith in the sale of oil from the lease.

    (d)(1) If you enter into an arm's-length exchange agreement, or multiple sequential arm's-length exchange agreements, and following the exchange(s) you or your affiliate sell(s) the oil received in the exchange(s) under an arm's-length contract, then you may use either Sec. 206.102(a) or Sec. 206.103 to value your production for royalty purposes.

    (i) If you use Sec. 206.102(a), your gross proceeds are the gross proceeds under your or your affiliate's arm's-length sales contract after the exchange(s) occur(s). You must adjust your gross proceeds for any location or quality differential, or other adjustments, you received or paid under the arm's-length exchange agreement(s). If MMS determines that any arm's-length exchange agreement does not reflect reasonable location or quality differentials, MMS may require you to value the oil under Sec. 206.103. You may not otherwise use the price or differential specified in an arm's-length exchange agreement to value your production.

    (ii) When you elect under Sec. 206.102(d)(1) to use Sec. 206.102(a) or Sec. 206.103, you must make the same election for all of your production sold under arm's-length contracts following arm's-length exchange agreements, and you may not change your election more often than once every two years.

    (2)(i) If you sell or transfer your oil production to your affiliate and that affiliate or another affiliate then sells the oil under an arm's-length contract, you may use either Sec. 206.102(a) or Sec. 206.103 to value your production for royalty purposes.

    (ii) When you elect under Sec. 206.102(d)(2) to use Sec. 206.102(a) or Sec. 206.103, you must make the same election for all of your production that your affiliates resell at arm's length, and you may not change your election more often than once every two years.

    (e) If you value oil under paragraph (a) of this section:

    (1) MMS may require you to certify that your or your affiliate's arm's-length contract provisions include all of the consideration the buyer must pay, either directly or indirectly, for the oil.

    (2) You must base value on the highest price the seller can receive through legally enforceable claims under the contract.

    (i) If the seller fails to take proper or timely action to receive prices or benefits it is entitled to, you must pay royalty at a value based upon that obtainable price or benefit. But you will owe no additional royalties unless or until the seller receives monies or consideration resulting from the price increase or additional benefits, if:

    (A) The seller makes timely application for a price increase or benefit allowed under the contract;

    (B) The purchaser refuses to comply; and

    (C) The seller takes reasonable documented measures to force purchaser compliance.

    (ii) Paragraph (e)(2)(i) of this section will not permit you to avoid your royalty payment obligation where a purchaser fails to pay, pays only in part, or pays late. Any contract revisions or amendments that reduce prices or benefits to which the seller is entitled must be in writing and signed by all parties to the arm's-length contract.

    Sec. 206.103 How do I value oil that is not sold under an arm's-length contract?

    This section explains how to value oil that you may not value under Sec. 206.102.

    (a) Production from leases in California or Alaska. Value is the average of the daily mean ANS spot prices published in any MMS-approved publication during the calendar month preceding the production month.

    (1) To calculate the daily mean spot price, average the daily high and low prices for the month in the selected publication.

    (2) Use only the days and corresponding spot prices for which such prices are published.

    (3) You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under Sec. 206.112.

    (b) Production from leases in the Rocky Mountain Region Value your oil under the first applicable of the following paragraphs:

    (1) If you have an MMS-approved tendering program, the value of production from leases in the area the tendering program covers is the highest price bid for tendered volumes.

    (i) You must offer and sell at least 30 percent of your production from both Federal and non-Federal leases in that area under your tendering program.

    (ii) You also must receive at least three bids for the tendered volumes from bidders who do not have their own tendering programs that cover some or all of the same area.

    (iii) MMS will provide additional criteria for approval of a tendering program in its ``Oil and Gas Payor Handbook.''

    (2) Value is the volume-weighted average gross proceeds accruing to the seller under your and your affiliates' arm's-length contracts for the purchase or sale of production from the field or area during the production month. The total volume purchased or sold under those contracts must exceed 50 percent of your and your affiliates' production from both Federal and non-Federal leases in the same field or area during that month.

    (3) Value is the average of the daily mean spot prices published in any MMS-approved publication for WTI crude at Cushing, Oklahoma, for deliveries during the production month.

    (i) Calculate the daily mean spot price by averaging the daily high and low prices for the month in the selected publication.

    (ii) Use only the days and corresponding spot prices for which such prices are published.

    (iii) You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under Sec. 206.112.

    (4) If you demonstrate to MMS's satisfaction that paragraphs (b)(1) through (b)(3) of this section result in an unreasonable value for your production as a result of circumstances regarding

    [[Page 73845]]

    that production, the MMS Director may establish an alternative valuation method.

    (c) Production from leases not located in California, Alaska, or the Rocky Mountain Region. Value is the average of the daily mean spot prices published in an MMS-approved publication:

    (1) For the market center nearest your lease for crude oil similar in quality to that of your production (for example, at the St. James, Louisiana, market center, spot prices are published for both Light Louisiana Sweet and Eugene Island crude oils--their quality specifications differ significantly); and

    (2) For deliveries during the production month. Calculate the daily mean spot price by averaging the daily high and low prices for the month in the selected publication. Use only the days and corresponding spot prices for which such prices are published. You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under Sec. 206.112.

    (d) If MMS determines that any of the index prices referenced in paragraphs (a), (b), and (c) of this section are unavailable or no longer represent reasonable royalty value, in any particular case, MMS may establish reasonable royalty value based on other relevant matters.

    (e) What if I transport my oil to my refinery and believe that use of a particular index price is unreasonable?

    (1) You may apply to the MMS Director for approval to use a value representing the market at the refinery if:

    (i) You transport your oil directly to your or your affiliate's refinery, or exchange your oil for oil delivered to your or your affiliate's refinery; and

    (ii) You must value your oil under this section at an index price; and

    (iii) You believe that use of the index price is unreasonable.

    (2) You must provide adequate documentation and evidence demonstrating the market value at the refinery. That evidence may include, but is not limited to:

    (i) Costs of acquiring other crude oil at or for the refinery;

    (ii) How adjustments for quality, location, and transportation were factored into the price paid for other oil;

    (iii) Volumes acquired for and refined at the refinery; and

    (iv) Any other appropriate evidence or documentation that MMS requires.

    (3) If the MMS Director approves a value representing market value at the refinery, you may not take an allowance against that value under Sec. 206.112(b) unless it is included in the Director's approval.

    Sec. 206.104 What index price publications are acceptable to MMS?

    (a) MMS periodically will publish in the Federal Register a list of acceptable publications based on certain criteria, including but not limited to:

    (1) Publications buyers and sellers frequently use;

    (2) Publications frequently mentioned in purchase or sales contracts;

    (3) Publications that use adequate survey techniques, including development of spot price estimates based on daily surveys of buyers and sellers of ANS and other crude oil; and

    (4) Publications independent from MMS, other lessors, and lessees.

    (b) Any publication may petition MMS to be added to the list of acceptable publications.

    (c) MMS will reference the tables you must use in the publications to determine the associated index prices.

    Sec. 206.105 What records must I keep to support my calculations of value under this subpart?

    If you determine the value of your oil under this subpart, you must retain all data relevant to the determination of royalty value. You must be able to show how you calculated the value you reported, including all adjustments for location, quality, and transportation, and how you complied with these rules. Recordkeeping requirements are found at part 207 of this title. MMS may review and audit your data, and MMS will direct you to use a different value if it determines that the reported value is inconsistent with the requirements of this subpart.

    Sec. 206.106 What are my responsibilities to place production into marketable condition and to market production?

    You must place oil in marketable condition and market the oil for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. If you use gross proceeds under an arm's-length contract in determining value, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform to place the oil in marketable condition or to market the oil.

    Sec. 206.107 How do I request a value determination?

    (a) You may request a value determination from MMS regarding any Federal lease oil production. Your request must:

    (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. You must inform MMS of any changes to relevant facts that occur before we respond to your request;

    (4) Include copies of all relevant documents;

    (5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and

    (6) Suggest your proposed valuation method.

    (b) MMS will reply to requests expeditiously. MMS may either:

    (1) Issue a value determination signed by the Assistant Secretary, Land and Minerals Management; or

    (2) Issue a value determination by MMS staff; or

    (3) Inform you in writing that MMS will not provide a value determination. Situations in which MMS typically will not provide any value determination include, but are not limited to:

    (i) Requests for guidance on hypothetical situations;

    (ii) Matters that are inherently factual in nature; and

    (iii) Matters that are the subject of pending litigation or administrative appeals.

    (c)(1) A value determination signed by the Assistant Secretary, Land and Minerals Management, is binding on both you and MMS until the Assistant Secretary modifies or rescinds it.

    (2) After the Assistant Secretary issues a value determination, you must make any adjustments in royalty payments that follow from the determination and, if you owe additional royalties, pay late payment interest under 30 CFR 218.54.

    (3) A value determination signed by the Assistant Secretary is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.

    (d)(1) A value determination issued by MMS staff is binding on MMS and delegated States with respect to the specific situation addressed in the determination unless the MMS Director or the Assistant Secretary modifies or rescinds it.

    (2) A value determination by MMS staff is not an appealable decision or order under 30 CFR part 290 subpart B. If you receive an order requiring you to pay royalty on the same basis as the value determination, you may appeal that order under 30 CFR part 290 subpart B.

    (e) A change in applicable statute or regulation on which any value determination is based takes precedence

    [[Page 73846]]

    over the value determination, regardless of whether the MMS Director or the Assistant Secretary modifies or rescinds the value determination.

    (f) The MMS Director or the Assistant Secretary generally will not modify or rescind a value determination retroactively, unless:

    (1) There was a misstatement or omission of material facts; or

    (2) The facts subsequently developed are materially different from the facts on which the guidance was based.

    (g) MMS may make requests and replies under this section available to the public, subject to the confidentiality requirements under Sec. 206.108.

    Sec. 206.108 Does MMS protect information I provide?

    Certain information you submit to MMS regarding valuation of oil, including transportation allowances, may be exempt from disclosure. To the extent applicable laws and regulations permit, MMS will keep confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.

    Sec. 206.109 When may I take a transportation allowance in determining value?

    (a) What transportation allowances are permitted when I value production based on gross proceeds? This paragraph applies when you value oil under Sec. 206.102 based on gross proceeds from a sale at a point off the lease, unit, or communitized area where the oil is produced, and the movement to the sales point is not gathering. MMS will allow a deduction for the reasonable, actual costs to transport oil from the lease to the point off the lease under Sec. 206.110 or Sec. 206.111, as applicable. If MMS takes it royalty in kind, see Sec. 208.8.

    (b) What transportation allowances and other adjustments apply when I value production based on index pricing? If you value oil using an index price under Sec. 206.103, MMS will allow a deduction for certain location/quality adjustments and certain costs associated with transporting oil as provided under Sec. 206.112.

    (c) Are there limits on my transportation allowance?

    (1) Except as provided in paragraph (c)(2) of this section, your transportation allowance may not exceed 50 percent of the value of the oil as determined under this subpart. You may not use transportation costs incurred to move a particular volume of production to reduce royalties owed on production for which those costs were not incurred.

    (2) You may ask MMS to approve a transportation allowance in excess of the limitation in paragraph (c)(1) of this section. You must demonstrate that the transportation costs incurred were reasonable, actual, and necessary. Your application for exception (using Form MMS- 4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to make a determination. You may never reduce the royalty value of any production to zero.

    (d) Must I allocate transportation costs? You must allocate transportation costs among all products produced and transported as provided in Secs. 206.110 and 206.111. You must express transportation allowances for oil as dollars per barrel.

    (e) What additional payments may I be liable for? If MMS determines that you took an excessive transportation allowance, then you must pay any additional royalties due, plus interest under 30 CFR 218.54. You also could be entitled to a credit with interest under applicable rules if you understated your transportation allowance. If you take a deduction for transportation on Form MMS-2014 by improperly netting the allowance against the sales value of the oil instead of reporting the allowance as a separate line item, MMS may assess you an amount under Sec. 206.116.

    Sec. 206.110 How do I determine a transportation allowance under an arm's-length transportation contract?

    (a) If you or your affiliate incur transportation costs under an arm's-length transportation contract, you may claim a transportation allowance for the reasonable, actual costs incurred for transporting oil under that contract, except as provided in paragraphs (a)(1) and (a)(2) of this section and subject to the limitation in Sec. 206.109(c). You must be able to demonstrate that your contract is arm's length. You do not need MMS approval before reporting a transportation allowance for costs incurred under an arm's-length contract.

    (1) If MMS determines that the contract reflects more than the consideration actually transferred either directly or indirectly from you or your affiliate to the transporter for the transportation, MMS may require that you calculate the transportation allowance under Sec. 206.111.

    (2) If MMS determines that the consideration paid under an arm's- length transportation contract does not reflect the reasonable value of the transportation due to either:

    (i) Misconduct by or between the parties to the arm's-length contract; or

    (ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor, then you must calculate the transportation allowance under Sec. 206.111.

    (A) MMS will not use this provision to simply substitute its judgment of the reasonable oil transportation costs incurred by you or your affiliate under an arm's-length transportation contract.

    (B) The fact that the cost you or your affiliate incur in an arm's length transaction is higher than other measures of transportation costs, such as rates paid by others in the field or area, is insufficient to establish breach of the duty to market unless MMS finds additional evidence that you or your affiliate acted unreasonably or in bad faith in transporting oil from the lease.

    (b)(1)(i) If your arm's-length transportation contract includes more than one liquid product, and the transportation costs attributable to each product cannot be determined from the contract, then you must allocate the total transportation costs to each of the liquid products transported.

    (ii) Your allocation must use the same proportion as the ratio of the volume of each product (excluding waste products with no value) to the volume of all liquid products (excluding waste products with no value).

    (iii) You may not claim an allowance for the costs of transporting lease production that is not royalty-bearing.

    (2) You may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS will approve the method unless it is not consistent with the purposes of the regulations in this subpart.

    (c)(1) If your arm's-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, then you must propose an allocation procedure to MMS.

    (2) You may use your proposed procedure to calculate a transportation allowance until MMS accepts your cost allocation.

    (3) You must submit your initial proposal, including all available data, within three months after the last day of the month for which you propose an allocation procedure.

    (d) If your payments for transportation under an arm's-length contract are not on a dollar-per-unit basis, you must convert whatever consideration is paid to a dollar-value equivalent.

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    (e) If your arm's-length sales contract includes a provision reducing the contract price by a transportation factor, MMS will not consider the transportation factor to be a transportation allowance.

    (1) You may use the transportation factor in determining your gross proceeds for the sale of the product.

    (2) You must obtain MMS approval before claiming a transportation factor in excess of 50 percent of the base price of the product.

    Sec. 206.111 How do I determine a transportation allowance under a non-arm's-length transportation arrangement?

    (a) If you or your affiliate have a non-arm's-length transportation contract or no contract, including those situations where you or your affiliate perform your own transportation services, calculate your transportation allowance based on the reasonable, actual costs provided in this section.

    (b) Base your transportation allowance for non-arm's-length or no- contract situations on your or your affiliate's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either:

    (1) Depreciation and a return on undepreciated capital investment under paragraphs (g)(1) and (h) of this section, or

    (2) A cost equal to the initial capital investment in the transportation system multiplied by a rate of return under paragraph (g)(2) of this section.

    (c) Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.

    (d) Allowable operating expenses include:

    (1) Operations supervision and engineering;

    (2) Operations labor;

    (3) Fuel;

    (4) Utilities;

    (5) Materials;

    (6) Ad valorem property taxes;

    (7) Rent;

    (8) Supplies; and

    (9) Any other directly allocable and attributable operating expense which you can document.

    (e) Allowable maintenance expenses include:

    (1) Maintenance of the transportation system;

    (2) Maintenance of equipment;

    (3) Maintenance labor; and

    (4) Other directly allocable and attributable maintenance expenses which you can document.

    (f) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

    (g) You may use either depreciation and a return on remaining undepreciated capital investment or a return on depreciable capital investment as described in paragraph (b) of this section. After you have elected to use either method for a transportation system, you may not later elect to change to the other alternative without MMS approval.

    (1) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, or a unit-of-production method. After you make an election, you may not change methods without MMS approval. You may not depreciate equipment below a reasonable salvage value.

    (2) An arm's-length change in ownership of a transportation system will result in a new depreciation schedule for purposes of the allowance calculation. If you or your affiliate purchase an existing transportation system at arm's length, your initial capital investment is equal to your purchase price of the transportation system.

    (3) Even after a transportation system, has been depreciated below a value equal to ten percent of your original capital investment, you may continue to include in the allowance calculation a cost equal to ten percent of your initial capital investment in the transportation system multiplied by a rate of return under paragraph (h) of this section.

    (4) For transportation facilities first placed in service after March 1, 1988, you may use as a cost an amount equal to your initial capital investment in the transportation system multiplied by the rate of return under paragraph (h) of this section. You may not claim an allowance for depreciation.

    (h) The rate of return is the industrial bond yield index for Standard and Poor's BBB rating. Use the monthly average rate published in ``Standard and Poor's Bond Guide'' for the first month of the reporting period for which the allowance applies. Calculate the rate at the beginning of each subsequent transportation allowance reporting period.

    (i) Calculate the deduction for transportation costs based on your or your affiliate's cost of transporting each product through each individual transportation system. Where more than one liquid product is transported, allocate costs consistently and equitably to each of the liquid products transported. Your allocation must use the same proportion as the ratio of the volume of each liquid product (excluding waste products with no value) to the volume of all liquid products (excluding waste products with no value).

    (1) You may not take an allowance for transporting lease production that is not royalty-bearing.

    (2) You may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS will approve the method if it is consistent with the purposes of the regulations in this subpart.

    (j)(1) Where both gaseous and liquid products are transported through the same transportation system, you must propose a cost allocation procedure to MMS.

    (2) You may use your proposed procedure to calculate a transportation allowance until MMS accepts your cost allocation.

    (3) You must submit your initial proposal, including all available data, within three months after the last day of the month for which you request a transportation allowance.

    Sec. 206.112 What adjustments and transportation allowances apply when I value oil using index pricing?

    When you use index pricing to calculate the value of production under Sec. 206.103, you must adjust the index price for location and quality differentials and you may adjust it for certain transportation costs, as follows:

    (a) If you dispose of your production under one or more arm's- length exchange agreements, then

    (1)(i) You must adjust the index price for location/quality differentials. You must determine those differentials from each of your arm's-length exchange agreements applicable to the exchanged oil.

    (ii) Therefore, for example, if you exchange 100 barrels of production from a given lease under two separate arm's-length exchange agreements for 60 barrels and 40 barrels respectively, separately determine the location/quality differential under each of those exchange agreements, and apply each differential to the corresponding index price.

    (iii) As another example, if you produce 100 barrels and exchange that 100 barrels three successive times under arm's-length agreements to obtain oil at a final destination, total the three adjustments from those exchanges to

    [[Page 73848]]

    determine the adjustment under this paragraph (a)(1)(iii). (If one of the three exchanges was not at arm's length, you must request MMS approval under paragraph (b) of this section for the location/quality adjustment for that exchange to determine the total location/quality adjustment for the three exchanges.) You also could have a combination of these examples.

    (2) You may adjust the index price for actual transportation costs, determined under Sec. 206.110 or Sec. 206.111

    (i) From the lease to the first point where you give your oil in exchange; and

    (ii) From any intermediate point where you receive oil in exchange to another intermediate point where you give the oil in exchange again; and

    (iii) From the point where you receive oil in exchange and transport it without further exchange to a market center, or to a refinery that is not at a market center.

    (b) For non-arm's-length exchange agreements, you must request approval from MMS for any location/quality adjustment.

    (c) If you transport lease production directly to a market center or to an alternate disposal point (for example, your refinery), you may adjust the index price for your actual transportation costs, determined under Sec. 206.110 or Sec. 206.111.

    (d) If you adjust for location/quality or transportation costs under paragraph (a), (b), or (c) of this section, also adjust the index price for quality based on premia or penalties determined by pipeline quality bank specifications at intermediate commingling points or at the market center. Make this adjustment only if and to the extent that such adjustments were not already included in the location/quality differentials determined from your arm's-length exchange agreements.

    (e) For leases in the Rocky Mountain Region, for purposes of this section, the term ``market center'' means Cushing, Oklahoma, unless MMS specifies otherwise through a document published in the Federal Register.

    (f) If you cannot determine your location/quality adjustment under paragraph (a) or (c) of this section, you must request approval from MMS for any location/quality adjustment.

    (g) You may not use any transportation or quality adjustment that duplicates all or part of any other adjustment that you use under this section.

    Sec. 206.113 How will MMS identify market centers?

    MMS periodically will publish in the Federal Register a list of market centers. MMS will monitor market activity and, if necessary, add to or modify the list of market centers and will publish such modifications in the Federal Register. MMS will consider the following factors and conditions in specifying market centers:

    (a) Points where MMS-approved publications publish prices useful for index purposes;

    (b) Markets served;

    (c) Input from industry and others knowledgeable in crude oil marketing and transportation;

    (d) Simplification; and

    (e) Other relevant matters.

    Sec. 206.114 What are my reporting requirements under an arm's-length transportation contract?

    You or your affiliate must use a separate line entry on Form MMS- 2014 to notify MMS of an allowance based on transportation costs you or your affiliate incur. MMS may require you or your affiliate to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Recordkeeping requirements are found at part 207 of this title.

    Sec. 206.115 What are my reporting requirements under a non-arm's- length transportation contract?

    (a) You or your affiliate must use a separate line entry on Form MMS-2014 to notify MMS of an allowance based on transportation costs you or your affiliate incur.

    (b) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable oil transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems.

    (c) MMS may require you or your affiliate to submit all data used to calculate the allowance deduction. Recordkeeping requirements are found at part 207 of this title.

    Sec. 206.116 What interest and assessments apply if I improperly report a transportation allowance?

    (a) If you or your affiliate net a transportation allowance against the royalty value on Form MMS-2014, you will be assessed an amount up to 10 percent of the netted allowance, not to exceed $250 per lease selling arrangement per sales period.

    (b) If you or your affiliate deduct a transportation allowance on Form MMS-2014 that exceeds 50 percent of the value of the oil transported without obtaining MMS's prior approval under Sec. 206.109, you must pay interest on the excess allowance amount taken from the date that amount is taken to the date you or your affiliate file an exception request MMS approves.

    (c) If you or your affiliate report an erroneous or excessive transportation allowance resulting in an underpayment of royalties, you must pay the additional royalties plus interest under 30 CFR 218.54.

    Sec. 206.117 What reporting adjustments must I make for transportation allowances?

    (a) If your or your affiliate's actual transportation allowance is less than the amount you claimed on Form MMS-2014 for each month during the allowance reporting period, you must pay additional royalties plus interest computed under 30 CFR 218.54 from the beginning of the allowance reporting period when you took the deduction to the date you repay the difference.

    (b) If the actual transportation allowance is greater than the amount you claimed on Form MMS-2014 for each month during the allowance form reporting period, you are entitled to a credit plus interest under applicable rules.

    Sec. 206.118 Are costs allowed for actual or theoretical losses?

    You are allowed a deduction for oil transportation which results from payments (either volumetric or for value) for actual or theoretical losses only under an arm's-length contract. You may not take such a deduction under a non-arm's-length contract.

    Sec. 206.119 How are royalty quantity and quality determined?

    (a) Compute royalties based on the quantity and quality of oil as measured at the point of settlement approved by BLM for onshore leases or MMS for offshore leases.

    (b) If the value of oil determined under this subpart is based upon a quantity or quality different from the quantity or quality at the point of royalty settlement approved by the BLM for onshore leases or MMS for offshore leases, adjust the value for those differences in quantity or quality.

    (c) You may not claim a deduction from the royalty volume or royalty value for actual or theoretical losses. Any actual loss that you may incur before the royalty settlement metering or measurement point is not subject to royalty if BLM or MMS, as appropriate, determines that the loss is unavoidable.

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    (d) Except as provided in paragraph (b) of this section, royalties are due on 100 percent of the volume measured at the approved point of royalty settlement. You may not claim a reduction in that measured volume for actual losses beyond the approved point of royalty settlement or for theoretical losses that are claimed to have taken place either before or after the approved point of royalty settlement.

    Sec. 206.120 How are operating allowances determined?

    MMS may use an operating allowance for the purpose of computing payment obligations when specified in the notice of sale and the lease. MMS will specify the allowance amount or formula in the notice of sale and in the lease agreement.

    [FR Doc. 99-33613Filed12-29-99; 8:45 am]

    BILLING CODE 4310-MR-P