Minerals Management Service, Interior.
The Minerals Management Service (MMS) is amending the existing regulations regarding valuation, for royalty purposes, of oil produced from Indian leases. These amendments will clarify and update the existing regulations.
Effective February 1, 2008.Start Further Info
FOR FURTHER INFORMATION CONTACT:
Sharron L. Gebhardt, Lead Regulatory Specialist, Minerals Management Service, Minerals Revenue Management, P.O. Box 25165, MS 302B2, Denver, Colorado 80225, telephone (303) 231-3211, fax (303) 231-3781, or e-mail Sharron.Gebhardt@mms.gov. The principal authors of this final rule are John Barder of Minerals Revenue Management, MMS, Department of the Interior, and Geoffrey Heath of the Office of the Solicitor, Department of the Interior, Washington, DC.End Further Info End Preamble Start Supplemental Information
The MMS published a proposed rule in the Federal Register on February 13, 2006 (71 FR 7453), referred to in this rule as the 2006 Indian Oil Proposed Rule or, simply, the proposed rule, that would amend the regulations governing the valuation for royalty purposes of crude oil produced from Indian leases. Before developing the proposed rule, MMS held a series of eight public meetings in March and June 2005 to consult with Indian tribes and individual Indian mineral owners and to obtain information from interested parties. The intent of the proposed rulemaking was to add more certainty to the valuation of oil produced from Indian lands, eliminate reliance on oil posted prices, and address the unique terms of Indian tribal and allotted leases—in particular, the major portion provision. Because of the response from Indian tribes and industry to the proposed rule, MMS plans to convene a negotiated rulemaking committee that will make recommendations regarding the major portion provision in Indian tribal and allotted leases.
For clarification, relevant rulemaking activity is listed below.
|Publication date||Federal Register reference||Publication title||Referred to in this final rule as|
|July 7, 2006||71 FR 38545||Reporting Amendments Proposed Rule||2006 Reporting Amendments Proposed Rule.|
|February 13, 2006||71 FR 7453||Indian Oil Valuation Proposed Rule||2006 Indian Oil Proposed Rule.|
|March 10, 2005||70 FR 11869||Federal Gas Valuation Final Rule Public Workshop on Proposed Rule—Establishing Oil Value for Royalty Due on Indian Leases||2005 Federal Gas Final Rule.|
|February 22, 2005||70 FR 8556||(Proposed Rule of February 12, 1998 (63 FR 7089) and Supplementary Proposed Rule of January 5, 2000 (65 FR 403 are withdrawn)||2005 Establishing Oil Value for Royalty Due on Indian Leases—Workshop.|
|May 24, 2004 Effective August 1, 2004||69 FR 29432||Federal Oil Valuation Final Rule Technical Amendment||2004 Federal Oil Final Rule Technical Amendment.|
|May 5, 2004 Effective August 1, 2004||69 FR 24959||Federal Oil Valuation Final Rule||2004 Federal Oil Final Rule.|
|September 28, 2000||65 FR 58237||Establishing Oil Value for Royalty Due on Indian Leases: Proposed Rule||2000 Indian Oil Proposed Rule.|
|March 15, 2000 Effective June 1, 2000—Amended 2004||65 FR 14022||Establishing Oil Value for Royalty Due on Federal Leases: Final Rule||2000 Federal Oil Final Rule.|
|February 28, 2000||65 FR 10436||Establishing Oil Value for Royalty Due on Indian Leases Supplementary Proposed Rule and Notice of Extension of Comment Period||2000 Indian Oil Revised Supplementary Proposed Rule.|
|January 5, 2000||65 FR 403||Establishing Oil Value for Royalty Due on Indian Leases Supplementary Proposed Rule||2000 Indian Oil Supplementary Proposed Rule.|
|August 10, 1999: Effective January 1, 2000||64 FR 43506||Amendments to Gas Valuation Regulations for Indian Leases Final Rule||1999 Indian Gas Final Rule.|
|April 9, 1998||63 FR 17349||Establishing Oil Value for Royalty Due on Indian Leases: Proposed Rule Extension of Public Comment Period||1998 Indian Oil Proposed Rule Comment Period Extension.|
|February 12, 1998||63 FR 7089||Establishing Oil Value for Royalty Due on Indian Leases Proposed Rule||1998 Indian Oil Proposed Rule.|
|January 15, 1988||53 FR 1184||Part 3—Revision of Oil Product Valuation Regulations and Related Topics Final Rule||1988 Oil Valuation Final Rule.|
II. Comments on the Proposed Rule
The MMS received comments from the following entities: Two Indian tribes, three industry trade associations, eight oil and gas producers, and one individual. The comments were generally not supportive of the changes outlined in the 2006 Indian Oil Proposed Rule. The most controversial topics were the proposed modification of Form MMS-2014, Report of Sales and Royalty Remittance, as part of the proposed major portion calculations, and the proposed transportation allowance changes.
The following chart summarizes the changes to definitions adopted in this final rule. The comments addressing the specific issues are summarized in the discussion that follows the chart.
|Definition||Change proposed in 2006 Indian Oil Proposed Rule||This final rule|
|Affiliate||Add new definition||Adds new definition as proposed.|
|Area||Revise definition||Not adopted as proposed.|
|Arm's-length contract||Revise definition||Adopts as proposed.|
|Designated area||Add new definition||Not adopted as proposed.|
|Exchange agreement||Add new definition||Adds new definition as proposed.|
|Gross proceeds||Revise definition||Revises as proposed.|
|Indian tribe||Revise definition||Revises as proposed.|
|Individual Indian mineral owner||Add new definition||Adds new definition as proposed.|
|Lessee||Revise definition||Revises proposed definition.|
|Lessor||Add new definition||Adds new definition as proposed.|
|Like-quality lease products||Eliminate||Eliminates as proposed.|
|Like-quality oil||Replace and modify existing definition of Like-Quality Lease Products||Adds new definition as proposed.|
|Load oil||Eliminate||Eliminates as proposed.|
|Location differential||Add new definition||Adds new definition as proposed.|
|Marketable condition||Revise definition||Revises proposed definition in light of comments.|
|Marketing affiliate||Eliminate||Eliminates as proposed.|
|Minimum royalty||Eliminate||Eliminates as proposed.|
|Net profit share||Eliminate||Eliminates as proposed.|
|Net-back method||Eliminate||Eliminates as proposed.|
|Oil||Revise definition||Revises as proposed.|
|Oil shale||Eliminate||Eliminates as proposed.|
|Oil type||Add new definition||Not adopted as proposed.|
|Operating rights owner||Add new definition||Adds new definition as proposed.|
|Posted price||Eliminate||Eliminates as proposed.|
|Quality differential||Add new definition||Adds new definition as proposed.|
|Selling arrangement||Eliminate||Not eliminated as proposed.|
|Tar sands||Eliminate||Eliminates as proposed.|
In the 2006 Indian Oil Proposed Rule, MMS proposed to add a definition of the term affiliate and revise the definition of arm's-length contract in § 206.51 to conform to the 2004 Federal Oil Final Rule and to align the rule with the court's decision in National Mining Association v. Department of the Interior, 177 F.3d 1 (DC Cir. 1999).
Comment: The MMS received one comment regarding the proposed change to the definition of affiliate. The industry association commenter stated that “[o]pposing economic interest is not a defined term, and MMS does not state any factors that will be considered in determining whether parties to a contract have opposing economic interest. MMS should define the term ‘opposing economic interests' and incorporate determining factors from the Vastar decision in the definition.”
MMS Response: The MMS examines whether two parties have opposing economic interests on a case-by-case basis under existing precedents. We have included the undefined phrase “opposing economic interest” in our definition of “arm's-length contract” since the oil royalty valuation rules were first issued in 1988.
The definition of “arm's-length contract” as originally proposed in 1987 did not include the requirement for “opposing economic interests.” Our 1987 proposal defined “arm's-length contract” simply to include “a contract or agreement between independent, nonaffiliated persons.” 52 FR 1858 (January 15, 1987). However, at the urging of a state commenter, MMS included the “opposing economic interest” concept in the final rule in 1988. The state commenter stressed that even though the inclusion of additional criteria such as “adverse economic interest” would increase subjectivity, “the appeals process is in place to provide protection against arbitrary decisions.”
The 1988 rule established the basic principles of MMS royalty valuation that have not changed over time. See Revision of Oil Product Valuation Regulations and Related Topics, 53 FR 1184 (Jan. 15, 1988) (“Although the parties may have common interests elsewhere, their interests must be opposing with respect to the contract in issue. The general presumption is that persons buying or selling products from Federal and Indian leases are willing, knowledgeable, and not obligated to buy or sell.”) We affirm those principles today.
As was predicted by the commenter in 1988, the appeals process has not only provided protection against arbitrary decisions, but it has also resulted in administrative precedent interpreting the phrase “opposing economic interest.” For example, through appeals such as Vastar Resources, Inc., 167 IBLA 17 (2005), the Department of the Interior has determined that “opposing economic interests” need not be absolute in order to meet the definition of an “arm's-length contract.” Accordingly, MMS will focus on the parties' economic interests in the specific contract at issue, Start Printed Page 71233and the fact that the parties may have common interests elsewhere does not necessarily negate their ability to have opposing economic interests with respect to the contract under view. Further, opposing economic interests are rarely absolute even within a single contract. For example, between two parties to an oil and gas lease, some economic interests are common and some are opposed. When oil is taken in kind, the common economic interest of production may appear to outweigh the remaining opposing economic interests. In Vastar, the Interior Board of Land Appeals considered objective factors such as the contentious negotiations leading to the execution of the contract, the terms of the contract, and the parties' subsequent conduct as evidence of the parties' opposing economic interests regarding the particular sales contract.
For purposes of interpreting the definition of “opposing economic interests,” MMS will follow the decisions of the Interior Board of Land Appeals until further rulemaking prescribes otherwise.
This final rule adopts the proposed definitions of affiliate and arm's-length contract. The MMS believes the existing definitions at § 206.51, should be amended to be consistent with the DC Circuit's decision in National Mining Association v. Department of the Interior, 177 F.3d 1 (DC Cir. 1999). The new definition of affiliate and the clarification to the definition of arm's-length contract will also make the definitions consistent with the 2004 Federal Oil Final Rule.
As we explained in amending the definition of “affiliate” in the Federal crude oil valuation rule promulgated on March 15, 2000 (effective June 1, 2000):
In National Mining Association v. Department of the Interior, 177 F.3d 1 (DC 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 5. 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. * * *
In the final rule, 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, paragraph (2) of the definition in the final rule, instead of creating a presumption of control, identifies a number of factors that MMS will consider in determining whether there is control under the circumstances of a particular case.
65 FR 14022, 14039 (Mar. 15, 2000). We adopt the same amendment here for Indian leases. Thus, the final rule replaces the presumption of control (and the consequent presumption of a non-arm's-length relationship) in the current rule, in the event of ownership or common ownership of 10 through 50 percent of the voting stock, with a case-by-case examination of the circumstances.
We emphasize that MMS will not presume control in the event of ownership or common ownership of 10 through 50 percent. MMS anticipates that in considering the factors identified in paragraph (2) of the definition, the facts of a particular case would demonstrate control (and therefore affiliation) only in exceptional circumstances. MMS anticipates that the facts will show that the relationship between corporate entities with minority ownership or common ownership is an arm's-length relationship in the vast majority of cases. MMS presumes in the absence of other evidence that transactions between corporate entities with minority ownership or common ownership are undertaken in good faith. The applicable rule is generally expressed in State Public Utilities Commission ex rel. Springfield v. Springfield Gas and Electric Company, 291 Ill. 209, 234.
Whether a contract or arrangement between the lessee and its purchaser should be regarded as arm's length or non-arm's length does not depend on whether the lease is a Federal lease or an Indian lease.
The MMS proposed to change the definition of area as part of the proposed major portion value calculation changes. This final rule does not include the proposed change to the definition of area. That term is still used in the major portion valuation provisions, which remain unchanged in this final rule for the reasons explained below. Therefore, the definition of area at § 206.51 is retained.
This final rule does not include the proposed definition of designated area because, as explained below, this final rule does not adopt the proposed major portion valuation provisions.
This final rule adopts the proposed definition of exchange agreement, which is used in the new valuation provisions at § 206.52(e).
This final rule includes the proposed changes to the definition of gross proceeds. This change is consistent with the 2004 Federal Oil Final Rule and makes helpful technical clarifications. There were no comments on this proposed change.
This final rule adopts the proposed definitions of Indian tribe and individual Indian mineral owner. The new wording clarifies that this rule applies to Indian tribes for whom the U.S. holds a mineral in trust or to individual Indians who hold title to a mineral subject to a restriction against alienation. This is more specific than the former reference to lands held in trust or subject to a restriction against alienation.
This final rule adopts the proposed definitions of lessee and operating rights owner, except that the final rule does not adopt clause (3) of the proposed definition of “lessee.” With one exception, the changes in wording that are adopted are technical corrections and clarifications.
As the Court noted in Fina Oil and Chemical Corp. v. Norton, 332 F.3d 672 (DC Cir. 2003), regarding gross proceeds and the definition of “lessee,” the term “lessee” was defined by Federal statute as “any person to whom the United States, an Indian tribe, or an Indian allottee issues a lease, or any person who has been assigned an obligation to make royalty or other payments required by the lease.” Public Law No. 97-451 § 3(7), 96 Stat. 2447, 2449 (amended in 1996 to read “any person to whom the United States issues an oil and gas lease or any person to whom operating rights in a lease have been assigned”), codified at 30 U.S.C. 1702(7). The 1988 regulations followed this statutory definition. In the Fina case, the court found that MMS improperly sought to use a wholly-owned subsidiary's arm's-length resale proceeds as the measure of the lessee's gross proceeds in conflict with the regulation's plain language. (Under the 1988 valuation rules, the affiliate's resale proceeds were used as value only if the affiliate was a “marketing affiliate,” defined as an affiliate of the lessee whose function was to acquire only the lessee's production and market that production. The royalty value of oil transferred non-arm's length to the marketing affiliate was the affiliate's gross proceeds, provided the marketing affiliate sold the oil at arm's length.) The Fina court suggested that if MMS believes that basing value on the intra-corporate transfer is too favorable to producers, it should amend the regulations through notice-and-comment rulemaking, not under the Start Printed Page 71234guise of interpretation. MMS is doing so in this final rule in the revised 30 CFR 206.52(a).
In this respect, this rule is making the same change made in the Federal crude oil valuation rule in 2004 at 30 CFR 206.102(a). In many respects, this final Indian oil valuation rule follows the same organization and structure as the Federal oil valuation rule promulgated on March 15, 2000, as amended May 5, 2004. The final Federal oil valuation rule adopted in March 2000 did not distinguish between “marketing affiliates,” as defined in 1998, and other affiliates, because MMS adopted an altogether new valuation approach. That is, the value of oil produced from a Federal lease and transferred to any affiliate is now determined by the affiliate's ultimate disposition of that oil or, at the lessee's option under certain conditions, at an index-based value or other applicable measure. The definition of “marketing affiliate” therefore was removed from the Federal oil valuation rule.
In the Indian lease context, MMS did not propose, and this final rule does not include, an index-based valuation option because for the vast majority of Indian leases, it is either impractical or impossible to derive reliable adjustments for location and quality between the lease and a market center with reliable published index prices. Further, in view of the lower volumes and number of transactions involved for most Indian leases, such an option would serve little purpose. As explained elsewhere in this preamble, the final rule simply adopts the proposal to replace the “benchmarks” originally promulgated in 1988, which have proven to be difficult to apply in practice, with the first arm's-length sale (minus any transportation costs) as the basis of value in the event of a non-arm's-length transfer by the lessee, and where the oil is sold at arm's-length before refining—a rare circumstance in the context of Indian leases that produce crude oil.
Since the general valuation approach adopted today eliminates the “marketing affiliate” distinction by focusing on the first arm's-length sale, it is appropriate that the definition of “marketing affiliate” be removed from these regulations. However, it does not follow that the definition of “lessee” needs to be amended. Moreover, MMS has written this rule in plain English format, using the term “you” to mean a lessee, operator, or other person who pays royalties under this subpart. In all, particularly in light of the removal of the definition of “marketing affiliate,” MMS is adopting the definition of “lessee” as proposed without proposed clause (3) incorporating affiliates. As the term “lessee” is used throughout the final rule, it either refers to the royalty payor or is specifically distinguished from the term “affiliate.” This change continues to support the general valuation approach adopted today and is consistent with statutory interpretation principles set out in United States v. Bestfoods, 524 U.S. 51, 61 (1998).
Currently, there is no definition of the term lessor in any of the Indian valuation regulations. Because this term is used in numerous places in the regulations, MMS proposed to add a definition in the 2006 Indian Oil Proposed Rule. This final rule adopts the proposed definition of lessor.
This final rule does not include the proposed definition of oil type because the final rule does not adopt the proposed major portion provisions. As explained further below, MMS plans to refer the major portion issue to a negotiated rulemaking committee. In this final rule, the term like-quality lease products will be changed to like-quality oil, and the reference to similar legal characteristics in the current definition of like-quality lease products will be deleted. The term like-quality lease products is not used in the regulations governing Indian oil valuation at §§ 206.50 through 206.55. The definition at § 206.51 is identical to the definitions in the 2005 Federal Gas Final Rule and 1999 Indian Gas Final Rule (see §§ 206.151 and 206.171). The existing regulations at § 206.51 and the changes made in this final rule, however, refer to like-quality oil; and this final rule therefore will define that term. The existing definition refers to “similar chemical, physical, and legal characteristics.” Crude oil has not been price-controlled in the last 25 years, and there are no legal classifications of crude oil that have any bearing on royalty valuation issues. We therefore have deleted the reference to similar legal characteristics.
This final rule includes the proposed definitions of location differential and quality differential because those terms are used in the provisions governing valuation of oil disposed of under arm's-length exchange agreements.
In the 2006 Indian Oil Proposed Rule, MMS proposed to change the definition of the term marketable condition in § 206.51 to mean lease products
that are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract or transportation contract typical for disposition of production from the field or area.
The current definition refers to lease products
that are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area.
Summary of Comments: Three industry associations commented on this proposed change. With respect to the proposed change in the definition of marketable condition to add a reference to transportation contracts, one industry association said:
We do accept that MMS has the authority to require the lessee to put the oil in the condition that contracts for the sale and purchase of oil typical in a field or area require, or to pay MMS on the value that oil in such condition would realize. * * *
We believe it is clear that it would not be reasonable for a producer of sour oil on the outer continental shelf to be required to sweeten oil simply because the pipeline in the area happens to be unwilling to transport any sour oil. Similarly, if oil is of a viscosity that allows it to be transported by truck, but which is too viscous to be transported by the local pipeline without blending, blending is not needed to put the oil in marketable condition. The oil is marketable in exactly the form it is in. It is acceptable to the party who will ultimately use it. * * *
[W]e strongly disagree with the proposal to require a lessee to meet the requirements of transportation contracts at no cost to the lessor. MMS has given no reasons for this proposed change and we believe that it is clear that the requirements of transportation contracts are different in kind from the requirements of sales contracts and that such costs are costs associated with transportation and should be deductible.
Another industry association opposes the proposed change to the definition of marketable condition because, in the association's view, it arbitrarily classifies certain deductible transportation costs as nondeductible costs of placing production in marketable condition. The third commenting industry association stated that it did not understand the proposed change.
MMS Response: The marketable condition rule has always required lessees to remove basic sediment and water to the level required for the relevant pipeline. There appears to be no controversy in this respect. It is not our intention to require a lessee to sweeten sour oil at its own expense simply because a particular pipeline does not accept sour oil and the marketable condition rule has never been interpreted to impose such a requirement.
MMS is not adopting the proposed change to the definition of “marketable condition” in this final rule because it Start Printed Page 71235is not necessary to do so, particularly in the context of crude oil production and sales. MMS will continue to use the existing definition, which is the same as the definition used in the Federal oil valuation rule. MMS continues to follow the marketable condition principle set out in United States v. General Petroleum Corp. of California, 73 F.Supp. 225, aff'd, Continental Oil Co. v. United States, 184 F.2d 802 (9th Cir. 1950).
This final rule eliminates the definitions of the terms load oil, minimum royalty, net profit share, oil shale, and tar sands because none of those terms is used either in the existing regulations governing Indian oil valuation at §§ 206.51 through 206.55 or in this final rule. This final rule also deletes the last sentence of the existing definition of oil, because neither the existing § 206.51 definition nor this final rule refers to or uses the term tar sands.
This final rule also eliminates the definitions of marketing affiliate, net-back method, and posted price because the regulations no longer contain those terms.
This final rule retains the definition of selling arrangement in the existing § 206.51, which the 2006 Indian Oil Proposed Rule would have eliminated, because the transportation allowance provisions of the existing regulations at § 206.55 are not changed in this final rule, as explained below. Those provisions use the term selling arrangement. The MMS recognizes that payors no longer report royalties or allowances by selling arrangement. The MMS published the 2006 Reporting Amendments Proposed Rule that would amend the transportation allowance rules and eliminate that term. However, a final rule has not been published. Therefore, MMS has not eliminated the term selling arrangement in this final rule.
B. General Valuation Approach
The 2006 Indian Oil Proposed Rule first analyzed where oil is produced from Indian leases and how it is marketed. Among other things, the discussion in the preamble to the 2006 Indian Oil Proposed Rule noted that the overwhelming majority of crude oil produced from Indian leases is reported as being sold at arm's length at the lease. There are relatively few non-arm's-length dispositions of oil reported and only one situation in which the lessee or its affiliate refines oil produced from the lessee's leases. In all other instances, it appears that oil is sold at arm's length at some point before it is refined. There are also very few instances in which lessees are reporting transportation allowances. At the present time, only two lessees of Indian leases are reporting transportation allowances for crude oil. One of those involves a non-arm's-length transportation arrangement. Currently, one of the major producing tribes takes more than 90 percent of its royalty oil in-kind.
In addition, Indian tribal and allotted leases are distributed geographically much differently than Federal leases, and oil produced from Indian leases is marketed much differently than oil produced from Federal leases. Except for the possibility of some oil sold in Oklahoma, which accounts for only about 10 percent of the oil sold from Indian leases, oil produced from Indian leases apparently does not flow to, and is not exchanged to, Cushing, Oklahoma, where New York Mercantile Exchange (NYMEX) prices are published. Thus, with the exception of Oklahoma and possibly one type of oil produced in Wyoming, it is extremely difficult to obtain reliable location and quality differentials between Cushing and areas where the large majority of the oil is produced from Indian leases, including the San Juan Basin, northeastern Utah, Wyoming (for other oil types), and Montana. Even in Oklahoma, almost all the oil sold from Indian leases is reported to MMS as sold at arm's length.
In light of these facts, and in contrast to the earlier 1998 Indian Oil Proposed Rule Comment Period Extension and the 2000 Indian Oil Supplementary Proposed Rule, in the 2006 Indian Oil Proposed Rule, MMS proposed not to use either NYMEX or spot market index pricing as primary measures of value for oil produced from Indian leases. Because of the environment in which Indian oil is produced and marketed, MMS proposed in the 2006 Indian Oil Proposed Rule to value oil at the gross proceeds the lessee or its affiliate receives in an arm's-length sale. In the event a lessee first transfers its oil to an affiliate and the oil is sold at arm's length before being refined, MMS proposed to use the arm's-length sale by the affiliate as the basis for royalty valuation. In addition to the fact that the first arm's-length sale is the best measure of the value of the oil, the proposed approach also would resolve the issue created by the DC Circuit's interpretation of the gross proceeds rule and the term lessee in the Federal gas royalty valuation rules in Fina Oil and Chemical Corp. v. Norton, supra.
In the rare situations in which the sale occurs away from the lease, the 2006 Indian Oil Proposed Rule provided for transportation allowances. The MMS also proposed to specify that if a lessee sells oil produced from a lease under multiple arm's-length contracts instead of just one contract, the value of the oil would be the volume-weighted average of the total consideration for all contracts for the sale of oil produced from that lease.
Further, in the event that the lessee or its affiliate enters into one or more arm's-length exchanges, and, if the lessee or its affiliate ultimately sells the oil received in exchange, the value would be the gross proceeds for the oil received in exchange, adjusted for location and quality differentials derived from the exchange agreement(s). If the lessee exchanges oil produced from Indian leases to Cushing, Oklahoma, value would be the NYMEX price, adjusted for location and quality differentials derived from the exchange agreements. If the lessee does not ultimately sell the oil received in exchange and does not exchange oil to Cushing, the lessee must ask MMS to establish a value based on relevant matters.
Finally, if the lessee transports the oil produced from the lease to its own or its affiliate's refinery, the 2006 Indian Oil Proposed Rule would require the lessee to value the oil at the volume-weighted average of the gross proceeds paid or received by the lessee or its affiliate, including the refining affiliate, for purchases and sales under arm's-length contracts of other like-quality oil produced from the same field (or the same area if the lessee does not have sufficient arm's-length purchases and sales from the field) during the production month, adjusted for transportation costs. If the lessee purchases oil away from the field(s) and if it cannot calculate a price in the field(s) because it cannot determine the seller's cost of transportation, it would not include those purchases in the weighted-average price calculation.
Comment: The principal comment received regarding the general valuation approach described above was from an Indian tribe. The tribe would prefer that MMS adopt the 2000 Indian Oil Supplementary Proposed Rule that MMS withdrew in February 2005 in the 2005 Establishing Oil Value for Royalty Due on Indian Leases—Workshop Federal Register notice. Failing that, the tribe would prefer that MMS continue to value its oil under the existing regulations at §§ 206.50 through 206.55. The tribe's comments focus on the unreliability of posted prices and the consequent prior proposals to look to NYMEX or spot market index values. The tribe argued that “MMS does not describe the ‘environment’ that it Start Printed Page 71236believes justifies continuing its gross proceeds/posted prices methodology. It provides absolutely no findings of how the environment has changed from the year 2000 to the present year, and how this change justifies its policy reversal.” The tribe further asks, “Why does MMS cite a high percentage of arm's-length transactions as a justification for never using market pricing benchmarks?” None of the industry commenters expressed any objection to using the gross proceeds derived from the affiliate's arm's-length resale as the measure of value if the lessee first transfers oil to an affiliate.
MMS Response: The MMS agrees that posted prices are not a reliable measure of value in the current market environment. Contrary to these comments, the 2006 Indian Oil Proposed Rule does not rely on posted prices. Whether a sales price happens to be established with reference to a posted price in any particular case is irrelevant if the contract was negotiated at arm's length. The 2006 Indian Oil Proposed Rule would not establish value with reference to posted prices independent of actual gross proceeds. The tribe appears to object to using arm's-length gross proceeds if the price set in an arm's-length contract happens to refer to or be based on a posted price. However, it does not explain why the negotiated arm's-length gross proceeds derived by a lessee or its affiliate is an improper or insufficient measure of value.
Further, the tribe's apparent preference for use of NYMEX or spot market index prices overlooks the fact that oil produced from Indian leases in the San Juan Basin is not generally transported or exchanged to Cushing, Oklahoma, or to another market center with an established spot market price. The tribe's comments thus overlook the consequent difficulty in determining reliable location and quality differentials that would be essential in using NYMEX or spot market index prices as a basis for valuation.
Comment: With respect to oil that is exchanged for other oil under exchange agreements, the tribe commented:
Under the law [i.e., the 1988 rules], the Nation's royalty is to be a share of the gross proceeds from the sale of oil from Navajo leases. In the 1988 Rule, MMS determined that the value of tribal oil for royalty purposes could reasonably be calculated using a company's actual gross proceeds based on posted prices. * * * Instead the companies entered into elaborate transfer and exchange agreements with affiliates, which allowed the companies to sell oil produced from Navajo leases for prices that were significantly higher than a company's posted price * * * the Nation's royalty share did not reflect the premium prices the companies received for Navajo oil.
The tribe further comments:
Simply put, MMS has forgotten why it sought to amend its valuation policies beginning with its draft rule in 1997. And those reasons are as valid today as they were in 1997: To eliminate the practices of the oil and gas industry to undervalue production through artificially posted prices for oil at the wellhead, when oil is actually exchanged/ transferred and/or valued at other locations to the benefit of oil companies.
MMS Response: The 2006 Indian Oil Proposed Rule addresses the commenter's concern regarding exchange agreements. Under the proposed rule, any “premium” realized through an arm's-length exchange would be captured in the royalty value because value would be based on the gross proceeds derived from an arm's-length sale of the oil received in exchange (unless the oil is exchanged to Cushing, Oklahoma). If oil is first exchanged not at arm's length, i.e., with an affiliate, the proposed rule would require valuing the oil on the basis of the affiliate's arm's-length resale price in any event.
Comment: One industry association said that it “supports the use of comparable purchases and sales from the same field or area in the situation where the lessee refines its own oil, and the exclusion of off-lease purchases that cannot be normalized.”
MMS Response: No commenter expressed objections to using the volume-weighted average of the gross proceeds paid or received by the lessee or its affiliate, including the refining affiliate, for purchases and sales under arm's-length contracts of other like-quality oil produced from the same field or area, adjusted for transportation costs, if the lessee or the lessee's affiliate refines the lessee's oil.
This final rule therefore adopts the 2006 Indian Oil Proposed Rule approach to replace the “benchmarks” currently outlined at § 206.52(c) for valuing oil not sold at arm's length. If such oil is sold before being refined, value will be based on the affiliate's arm's-length resale price. If the lessee or its affiliate refines the oil without an arm's-length sale, value will be based on the volume-weighted average of the gross proceeds paid or received for arm's-length purchases and sales of other like-quality oil produced from the same field or area.
Further, by adopting the proposed provisions for valuing production disposed of through arm's-length exchange agreements, this final rule ensures that any “premium” realized in the sale of oil received in exchange will be included in the royalty value. This final rule therefore addresses the tribe's comment that MMS should “close a loophole that allows the oil companies to circumvent congressional intent and MMS's rules.”
C. Major Portion Valuation
The 2006 Indian Oil Proposed Rule would have made a number of changes to the major portion valuation provisions of the rule. The proposed rule would have used values reported on Form MMS-2014 for arm's-length sales (and affiliate's arm's-length resales) of Indian oil, and values reported for oil taken in kind, produced from a designated area that MMS would identify. Values reported for oil that is refined without being sold at arm's length would not have been included in the calculation. The proposed rule would not have changed the percentile at which the major portion value is determined, i.e., the 50th percentile by volume plus one barrel of oil.
Under the 2006 Indian Oil Proposed Rule, to normalize reported values for each oil type produced from the designated area to a common quality basis, MMS would have adjusted for API gravity using applicable posted price gravity adjustment tables. The MMS would have calculated separate major portion values for different oil types because the lease provision expressly refers to “like-quality” oil. The MMS would have designated oil types that are produced from each designated area.
To obtain the information necessary to make these calculations and adjustments, the 2006 Indian Oil Proposed Rule would have required the royalty payors to report API gravity and oil type on Form MMS-2014. The MMS then would have arrayed the normalized and adjusted (for transportation costs) values in order from the highest to the lowest, together with the corresponding volumes reported at those values. The major portion value would be the normalized and adjusted price in the array that corresponds to the 50th percentile by volume plus one barrel of oil, starting from the bottom.
Under the 2006 Indian Oil Proposed Rule, lessees initially would have reported on Form MMS-2014 the value of production at the value determined under the other provisions of the rule and would pay royalty on that value. The MMS then would have calculated the major portion values and notified lessees of the major portion values by publishing a notice in the Federal Register and making them available on the MMS Web site, together with the normalized gravity and the adjustment Start Printed Page 71237tables. The lessee then would have compared the major portion value to the value initially reported on Form MMS-2014, normalized and adjusted for gravity and transportation. If the major portion value were higher than the value initially reported, normalized and adjusted for gravity and transportation, the lessee would have had to submit an amended Form MMS-2014, reporting the value as the major portion value, and pay any additional royalty owed.
Comments: The majority of the comments MMS received on the 2006 Indian Oil Proposed Rule addressed the major portion issue. Both of the Indian tribal commenters and all the industry commenters opposed the proposed changes, but for different reasons.
In general, the tribal commenters believed that the percentile at which the major portion should be measured should be consistent with the Indian gas royalty valuation provisions (i.e., the 25th percentile starting from the top of the array, rather than the 50th percentile plus one unit of production starting from the bottom of the array). The tribal commenters also argued that the major portion calculation should not be limited to Indian leases in a “designated area.” One tribal commenter argued that MMS should retain the existing reference to a “field,” and include all Indian, Federal, state, and private leases that may be within the field. The other tribal commenter argued that the calculation either should be expanded to include at least Federal leases outside the designated area or that the designated area should be expanded to include Federal leases in the area. The tribal commenters supported the concept of normalizing oil prices to a uniform quality before calculating the major portion value.
Industry commenters vigorously opposed the proposed requirements to report oil gravity and type. They also opposed any expansion of a designated area to include Federal leases, particularly because the requirement to report oil gravity and type would extend to those Federal leases identified as being within a designated area. The industry commenters asserted that the systems changes that these requirements would necessitate, including both programming changes and the development of different reporting systems for Federal and Indian leases, would be prohibitively expensive and out of proportion to any difference in royalty value that might result. One industry association also argued that including Federal leases in the major portion calculation would result in application to those Federal leases certain records retention requirements that now apply only to Indian leases, causing further disruptions to lessees' recordkeeping and systems operations. Industry commenters agreed with retaining the 50th percentile by volume plus one barrel of oil as the measure of what constitutes the major portion and opposed any suggestion to change that measure to a higher level.
MMS Response: There appears to be almost no issue regarding major portion valuation on which the tribal and industry commenters agree, and none of the commenters support the major portion provisions of the proposed rule. As a consequence, MMS has decided not to promulgate any amendment to the current major portion provisions at the existing § 206.52(a)(2) in this final rule and to convene a negotiated rulemaking committee to consider all aspects of major portion valuation.
Because of the way the amended valuation provisions for arm's-length sales and non-arm's-length dispositions are codified, paragraphs (a)(2)(i) and (ii) of the existing § 206.52 are redesignated in this final rule as a new § 206.54(a) and (b).
D. Transportation Allowances
The MMS made several proposals regarding transportation allowances in the 2006 Indian Oil Proposed Rule. If the transportation arrangement is at arm's length, the proposed rule would incorporate the provisions of the 2000 Federal Oil Final Rule, as amended in 2004, in calculating that allowance. That allowance is based on the actual cost paid to an unaffiliated transportation provider. For arm's-length transportation allowances, MMS also proposed to eliminate the requirement at § 206.55(c)(1), to file Form MMS-4110, Oil Transportation Allowance Report. Instead of Form MMS-4110, the lessee would have to submit copies of its transportation contract(s) and any amendments thereto within 2 months after the lessee reported the transportation allowance on Form MMS-2014. This proposed change mirrors the elimination of the requirement to file the analogous Form MMS-4295 for arm's-length transportation allowances under the 1999 Indian Gas Final Rule.
For non-arm's-length transportation arrangements, the lessee would have to calculate its actual costs. Under the 2006 Indian Oil Proposed Rule, Form MMS-4110 would still be required, but the requirement to submit a Form MMS-4110 in advance with estimated information would be eliminated. Instead, the lessee would submit the actual cost information to support the allowance on Form MMS-4110 within 3 months after the end of the 12-month period to which the allowance applies. This proposal also mirrors the change made in the 1999 Indian Gas Final Rule at § 206.178(b)(1)(ii).
The MMS also proposed that the non-arm's-length allowance calculation, and the costs that would be allowable and non-allowable under the non-arm's-length transportation allowance provisions, be revised to incorporate the provisions of the 2004 Federal Oil Final Rule.
The 2000 Federal Oil Final Rule provides that the lessee must base its transportation allowance in a non-arm's-length or no-contract situation, on the lessee's actual costs. These include (1) operating and maintenance expenses; (2) overhead; (3) depreciation; (4) a return on undepreciated capital investment; and (5) a return on 10 percent of total capital investment once the transportation system has been depreciated below 10 percent of total capital investment (§ 206.111(b)). The MMS proposed to incorporate the same cost allowance structure into the 2006 Indian Oil Proposed Rule, as discussed in more detail below.
Before June 1, 2000, the regulations for Federal oil valuation provided (as do current Indian oil valuation regulations) that, in the case of transportation facilities placed in service after March 1, 1988, actual costs could include either depreciation and a return on undepreciated capital investment or a cost equal to the initial investment in the transportation system multiplied by the allowed rate of return. The regulations before June 1, 2000, did not provide for a return on 10 percent of total capital investment once the system has been depreciated below 10 percent of total capital investment. The 2000 Federal Oil Final Rule eliminated the alternative of a cost equal to the initial investment in the transportation system multiplied by the allowed rate of return because it became unnecessary in view of the other changes made in the rule and because it had been used in very few, if any, situations.
The 2000 Federal Oil Final Rule also set forth the basis for the depreciation schedule to be used in the depreciation calculation. See § 206.111(h). The MMS proposed to adopt identical provisions for this rule through incorporation, except that the relevant date would have been the effective date of a final rule that adopted those provisions.
In the 2000 Federal Oil Final Rule, the depreciation schedule for a transportation system depended on whether the lessee owned the system on, or acquired the system after, the effective date of the final rule. The MMS Start Printed Page 71238proposed to apply the same principle in the context of Indian leases.
Finally, the 2004 Federal Oil Final Rule, which amended § 206.111(i)(2), changed the allowed rate of return used in the non-arm's-length actual cost calculations from the Standard & Poor's BBB bond rate to 1.3 times the BBB bond rate. In March 2005, MMS promulgated an identical change to the allowed rate of return used in the calculation of actual costs under non-arm's-length transportation arrangements in the 2005 Federal Gas Final Rule, which amended § 206.157(b)(2)(v). The proposed change to this rule would incorporate this same change, for the same reasons the rate of return was changed in the 2004 Federal Oil Final Rule and 2005 Federal Gas Final Rules (i.e., 1.3 times the BBB bond rate more accurately reflects the lessees' cost of capital).
Comments: One of the two tribal commenters offered specific comments on the transportation allowance provisions of the proposed rule. The tribe expressed concern “that the MMS would ultimately apply transportation allowance criteria established for Federal leases upon Indian leases, without due consideration for certain Indian lease provisions and policies.” However, the tribe did not explain which cost elements it believed to be improper and did not identify any difference in relevant lease terms between Indian and Federal leases. The tribe opposes eliminating the Form MMS-4110 filing requirement. The tribe “believes that Indian lessors should and must receive prior notification of all allowance deductions from its [sic] royalty and, if MMS is correct in that transportation allowances are limited for Indian leases, then it should not be burdensome for the few royalty reporters to continue to submit Form MMS-4110.” The tribe opposes changing rate of return used in calculating actual transportation costs under non-arm's-length transportation arrangements and wants MMS to retain the BBB rate in the existing rule at § 206.55(v).
The other tribal commenter appears to oppose the transportation allowance provisions as part of its general opposition to the entire proposed rule.
One of the industry association commenters supports using the same transportation cost elements for Indian and Federal leases. The commenter agrees with the proposed elimination of Form MMS-4110 and supports the proposed change in the rate of return used in calculating actual transportation costs to 1.3 times the BBB bond rate. However, the commenter expresses concerns about the accessibility of that rate and wants MMS to post the rate.
Another industry association commenter says that there is no reason to treat oil pipeline costs differently depending on lessor ownership. That commenter also supports changing the rate of return to 1.3 times the BBB bond rate for the same reason that the rate was changed in the 2004 Federal Oil Final Rule and 2005 Federal Gas Final Rule. This commenter further suggests (presumably referring to non-arm's-length situations) that reporting actual transportation costs in the production month in which they occur is burdensome. The commenter notes that the Royalty Reporting Subcommittee of the Royalty Policy Committee (an MMS advisory committee) developed several options for making prior-period adjustments, but none of the options were adopted because the stakeholders couldn't reach consensus. This commenter also supports eliminating the requirement to pre-file Form MMS-4110 for non-arm's-length transportation arrangements and eliminating any form filing for arm's-length transportation arrangements. The commenter also opposes having to file arm's-length transportation contracts and amendments with MMS as unnecessarily burdensome because lessees have to retain those documents and provide them on request in any event.
MMS Response: At the present, lessees are reporting only three transportation allowances on Indian leases. Two are arm's-length transportation arrangements on certain Ute tribal leases and the other is a non-arm's-length transportation arrangement for production from certain Shoshone and Arapaho leases on the Wind River Reservation.
The issues involved in the proposed amendments to the transportation allowance provisions are difficult and have generated an unusual degree of controversy relative to the very limited number of transactions to which they apply. The MMS believes that further analysis of these questions is appropriate and has decided to reserve the transportation allowance issue for a possible future supplemental final rulemaking. If MMS decides to seek further comment on the transportation allowance provisions of the proposed rule, it will publish an appropriate notice.
In view of the change to the structure of the codified sections of the rule resulting from the changes to the valuation provisions, the existing transportation allowance rules (§§ 206.54 and 206.55 of the existing rule) are redesignated in this final rule as §§ 206.56 and 206.57. Certain conforming amendments are also made to correct cross-references to other sections. Otherwise, the existing rules remain unchanged.
E. Other Issues
In proposed § 206.50, MMS proposed adding a provision that, if the regulations are inconsistent with a Federal statute, a settlement agreement or written agreement, or an express provision of a lease, then the statute, settlement agreement, written agreement, or lease provision would govern to the extent of the inconsistency. A “written agreement” would mean a written agreement between the lessee and the MMS Director, and approved by the tribal lessor for tribal leases, establishing a method to determine the value of production from any lease that MMS expects at least would approximate the value established under the regulations. The MMS received no comments opposed to this provision, and this final rule adopts it.
Regarding records retention, the proposed rule explained that proposed § 206.64 is adapted from § 206.105, and that the time for which records must be maintained is governed by § 103(b) of the Federal Oil and Gas Royalty Management Act, 30 U.S.C. 1713(b), as originally enacted. That requirement is not affected by the change in 30 U.S.C. 1724(f), which was enacted as part of the Federal Oil and Gas Royalty Simplification and Fairness Act of 1996 and applies only to Federal leases. The referenced regulations in proposed § 206.64 reflect this difference. The MMS received no comments opposed to this provision, and this final rule adopts it.
III. Procedural Matters
1. Summary Cost and Royalty Impact Data
There will be no additional administrative costs/savings or royalty impacts as a result of this final rule. There will be no change in royalties or administrative burdens to industry, state and local governments, Indian tribes, individual Indian mineral owners, or the Federal Government.
All administrative costs/savings and royalty impacts listed in the 2006 Indian Oil Proposed Rule were the result of the proposed major portion provision, the additional information collection required by that provision, and the transportation allowance provision. The majority of the costs under the 2006 Indian Oil Proposed Rule were Start Printed Page 71239associated with the proposed major portion provision. Neither the proposed major portion provision nor the proposed transportation allowance provision is adopted under this final rule. As a result, the existing provisions at § 206.50 through 206.55 will be retained. In Section II, Comments on the Proposed Rule, MMS explains plans to convene a negotiated rulemaking committee that will make recommendations regarding the implementation of the major portion provision found in most Indian tribal and allotted leases. Also, under Section II D, Transportation Allowance, MMS is reserving the transportation allowances issues for a possible future supplemental final rulemaking.
There are no administrative costs and royalty impacts of this final rule to industry, state and local governments, Indian tribes and individual Indian mineral owners, or the Federal Government.
2. Regulatory Planning and Review, Executive Order 12866
This final rule is not a significant regulatory action. However, in view of the subject matter of the regulation, the Office of Management and Budget has reviewed this rule under Executive Order 12866.
1. This rule will not have an effect of $100 million or more on the economy. It would not adversely affect in a material way the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities.
2. This rule will not create a serious inconsistency or otherwise interfere with an action taken or planned by another agency.
3. This rule will not materially affect entitlements, grants, user fees, loan programs, or the rights and obligations of their recipients.
4. This rule does not raise novel legal or policy issues.
3. Regulatory Flexibility Act
The Department of the Interior certifies that this final rule will not have a significant economic effect on a substantial number of small entities as defined under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). An initial Regulatory Flexibility Analysis is not required. Accordingly, a Small Entity Compliance Guide is not required.
Your comments are important. The Small Business and Agricultural Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small businesses about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the enforcement actions in this rule, call 1-800-734-3247. You may comment to the Small Business Administration without fear of retaliation. Disciplinary action for retaliation by an MMS employee may include suspension or termination from employment with the Department of the Interior.
4. Small Business Regulatory Enforcement Fairness Act (SBREFA)
This final rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This final rule:
1. Will not have an annual effect on the economy of $100 million or more.
2. Will not cause a major increase in costs or prices for consumers, individual industries, Federal, state, Indian, or local government agencies, or geographic regions.
3. Will not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of United States-based enterprises to compete with foreign-based enterprises.
5. Unfunded Mandates Reform Act
In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.):
1. This final rule will not significantly or uniquely affect small governments. Therefore, a Small Government Agency Plan is not required.
2. This final rule will not produce a Federal mandate of $100 million or greater in any year; i.e., it is not a significant regulatory action under the Unfunded Mandates Reform Act. An analysis was prepared for the 2006 Indian Oil Proposed Rule; however, because certain provisions of the proposed rule were not adopted under this final rule, there are no apparent cost and royalty impacts to industry, state and local governments, Indian tribes and individual Indian mineral owners, and the Federal Government. Therefore, an analysis for this final rule was not necessary under Executive Order 12866. See Section III, Procedural Matters, Summary Cost and Royalty Impact Data.
6. Governmental Actions and Interference With Constitutionally Protected Property Rights (Takings), Executive Order 12630
In accordance with Executive Order 12630, this final rule will not have significant takings implications. A takings implication assessment is not required.
7. Federalism, Executive Order 13132
In accordance with Executive Order 13132, this final rule will not have significant federalism implications. A federalism assessment is not required. It will not substantially and directly affect the relationship between Federal and state governments. The management of Indian leases is the responsibility of the Secretary of the Interior, and all royalties collected from Indian leases are distributed to tribes and individual Indian mineral owners. This final rule will not alter that relationship.
8. Civil Justice Reform, Executive Order 12988
In accordance with Executive Order 12988, the Office of the Solicitor has determined that this final rule will not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of the Order.
9. Paperwork Reduction Act of 1995 (PRA)
Based on comments received on the proposed rule, MMS is not revising major portion provisions in the current regulations at 30 CFR 206.50 through 206.55. We have deleted from the final rule all proposed changes to the major portion provisions. We also have revised sections in the proposed rule containing changes to transportation allowances that would have necessitated additional information collections.
During the proposed rulemaking stage, we submitted an information collection request to OMB; OMB did not approve the collection at that time. Because there are no longer any new information collection requirements in the final rule, no further submission to OMB is required. Any information collections remaining in the rulemaking have already been approved under the following OMB Control Numbers:
- 1010-0103 regarding the MMS Indian oil and gas program—current burden hours are 1,276 (expires June 30, 2009); and
- 1010-0140 regarding MMS's primary financial form, the Form MMS-2014, Report of Sales and Royalty Remittance—current burden hours are 158,821 (expires November 30, 2009).
We received comments on the proposed changes to Form MMS-2014 and filing requirements. Commenters primarily objected to the cost of system changes that the proposed changes would have required. These comments are addressed in the preamble of this final rule, and none of the proposed changes are included in the final rulemaking. Start Printed Page 71240
The PRA (44 U.S.C. 3501, et seq.) provides that an agency may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. Until OMB approves a collection of information, you are not obligated to respond.
10. National Environmental Policy Act (NEPA)
This final rule deals with financial matters and has no direct effect on MMS decisions on environmental activities. Pursuant to 516 DM 2.3A (2), Section 1.10 of 516 DM 2, Appendix 1, excludes from documentation in an environmental assessment or impact statement “policies, directives, regulations and guidelines of an administrative, financial, legal, technical or procedural nature; or the environmental effects of which are too broad, speculative, or conjectural to lend themselves to meaningful analysis and will be subject later to the NEPA process, either collectively or case-by-case.” Section 1.3 of the same appendix clarifies that royalties and audits are considered to be routine financial transactions that are subject to categorical exclusion from the NEPA process. None of the exceptions to the categorical exclusion applies.
11. Government-to-Government Relationship With Tribes
In accordance with the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951) and 512 DM 2, we have evaluated potential effects on federally recognized Indian tribes and have determined that the changes we are promulgating will not have any apparent impact on tribes and individual Indian mineral owners. During the writing of this final rule, we have consulted extensively with tribal representatives and individual Indian mineral owners regarding the regulatory changes affecting tribes and individual Indian mineral owners in this final rule. See Section I, Background, for additional information regarding public meetings and consultation with tribes and individual Indian mineral owners. Also see Section III, 13, below.
12. Effects on the Nation's Energy Supply, Executive Order 13211
In accordance with Executive Order 13211, this regulation will not have a significant effect on the Nation's energy supply, distribution, or use. The changes better reflect the way industry accounts internally for its oil valuation and provides a number of technical clarifications. None of these changes will affect significantly the way industry does business and, accordingly, will not affect industry's approach to energy development or marketing. Nor will the rule otherwise impact energy supply, distribution, or use.
13. Consultation and Coordination With Indian Tribal Governments, Executive Order 13175
This final rule does not have tribal implications that will impose substantial direct compliance costs on Indian tribal governments. In accordance with Executive Order 13175, and with the Department's policy to consult with individual Indian mineral owners on all policy changes that may affect them, MMS scheduled public meetings in three different locations, announced in the 2005 Establishing Oil Value for Royalty Due on Federal Leases—Workshop, for the purpose of consulting with Indian tribes and individual Indian mineral owners and to obtain public comments from other interested parties. The public meetings were held on March 8, 2005, in Oklahoma City, Oklahoma; on March 9, 2005, in Albuquerque, New Mexico; and on March 16, 2005, in Billings, Montana. The MMS also held five additional consultation sessions with tribes and individual Indian mineral owners to hear and discuss comments, including sessions in Window Rock, Arizona, on June 7, 2005; Fort Duchesne, Utah, on June 9, 2005; Fort Washakie, Wyoming, on June 15, 2005; Muskogee, Oklahoma, on June 16, 2005; and Anadarko, Oklahoma, on June 17, 2005.
14. 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 its 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 “§ ” and a numbered heading; for example, § 204.200.
(5) What is the purpose of this part?
(6) Is the description of the rule in the “Supplementary Information” section of the preamble helpful in understanding the rule?
(7) 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.Start List of Subjects
List of Subjects in 30 CFR Part 206
- Continental shelf
- Government contracts
- Mineral royalties
- Natural gas
- Public lands—mineral resources
Dated: November 27, 2007.
C. Stephen Allred,
Assistant Secretary for Land and Minerals Management.
For the reasons set forth in the preamble, MMS amendsEnd Amendment Part Start Part
PART 206—PRODUCT VALUATIONEnd Part Start Amendment Part
1. The authority citation for part 206 continues to read as follows:End Amendment Part Start Amendment Part
2. The table of contents for Subpart B—Indian Oil is revised to read as follows:End Amendment Part
Subpart B—Indian Oil
- What is the purpose of this subpart?
- What definitions apply to this subpart?
- How do I calculate royalty value for oil that I or my affiliate sell(s) or exchange(s) under an arm's-length contract?
- How do I determine value for oil that I or my affiliate do(es) not sell under an arm's-length contract?
- How do I fulfill the lease provision regarding valuing production on the basis of the major portion of like-quality oil?
- What are my responsibilities to place production into marketable condition and to market the production?
- Transportation allowances—general.
- Determination of transportation allowances.
- What must I do if MMS finds that I have not properly determined value?
- May I ask MMS for valuation guidance?
- What are the quantity and quality bases for royalty settlement?
- What records must I keep and produce?Start Printed Page 71241
- Does MMS protect information I provide?
3. Sections 206.54 and 206.55 are redesignated as §§ 206.56 and 206.57.End Amendment Part Start Amendment Part
4. In redesignated § 206.56, the reference to “Section 206.52” in paragraph (a) and the reference to “§ 206.52” in paragraph (b)(1) are revised to read “§ 206.52 or § 206.53.” The reference to “§ 206.55” in paragraph (c) is revised to read “§ 206.57.”End Amendment Part Start Amendment Part
5. Sections 206.50 through 206.53 are revised, and §§ 206.54 and 206.55 are added, to read as follows:End Amendment Part
(a) This subpart applies to all oil produced from Indian (tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma). This subpart does not apply to Federal leases, including Federal leases for which revenues are shared with Alaska Native Corporations. This subpart:
(1) Establishes the value of production for royalty purposes consistent with the Indian mineral leasing laws, other applicable laws, and lease terms;
(2) Explains how you as a lessee must calculate the value of production for royalty purposes consistent with applicable statutes and lease terms; and
(3) Is intended to ensure that the United States discharges its trust responsibilities for administering Indian oil and gas leases under the governing Indian mineral leasing laws, treaties, and lease terms.
(b) If the regulations in this subpart are inconsistent with a Federal statute, a settlement agreement or written agreement as these terms are defined in this paragraph, or an express provision of an oil and gas lease subject to this subpart, then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency. For purposes of this paragraph:
(1) Settlement agreement means a settlement agreement that is between the United States and a lessee, or between an individual Indian mineral owner and a lessee and is approved by the United States, resulting from administrative or judicial litigation; and
(2) Written agreement means a written agreement between the lessee and the MMS Director (and approved by the tribal lessor for tribal leases) establishing a method to determine the value of production from any lease that MMS expects at least would approximate the value established under this subpart.
(c) The MMS or Indian tribes may audit, or perform other compliance reviews, and require a lessee to adjust royalty payments and reports.
For purposes of this subpart:
Affiliate means a person who controls, is controlled by, or is under common control with another person.
(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 10 through 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 in 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.
Area means a geographic region at least as large as the defined limits of an oil and/or gas field in which oil and/or gas lease products have 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 in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Indian leases.
BLM means the Bureau of Land Management of the Department of the Interior.
Condensate means liquid hydrocarbons (generally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results 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 thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.
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, and other consideration. Exchange agreements:
(1) May or may not specify prices for the oil involved;
(2) Frequently specify dollar amounts reflecting location, quality, or other differentials;
(3) 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, or in separate agreements; and
(4) May include, but are not limited to, exchanges of produced oil for specific types of oil (e.g., WTI); exchanges of produced oil for other oil at other locations (location 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 and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields usually are given names, and their official boundaries are often designated by oil and gas regulatory agencies in the respective states in which the fields are located.
Gathering means the movement of lease production to a central accumulation or treatment point on the Start Printed Page 71242lease, unit, or communitized area, or to a central accumulation or treatment point off the lease, unit, or communitized area as approved by BLM operations personnel.
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 that the lessee must perform at no cost to the lessor in order to put the production into marketable condition;
(2) The value of services to put the production into marketable condition, such as salt water disposal, that the lessee normally performs but that the buyer performs on the lessee's behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Indian 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 those 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.
Indian tribe means any Indian tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any minerals or interest in minerals is held in trust by the United States or that is subject to Federal restriction against alienation.
Individual Indian mineral owner means any Indian for whom minerals or an interest in minerals is held in trust by the United States or who holds title subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under an Indian mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products. Depending on the context, lease may also refer to the land area covered by that authorization.
Lease products means any leased minerals attributable to, originating from, or allocated to Indian leases.
Lessee means any person to whom the United States, a tribe, or individual Indian mineral owner issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. Lessee includes:
(1) Any person who has an interest in a lease (including operating rights owners); and
(2) An operator, purchaser, or other person with no lease interest who makes royalty payments to MMS or the lessor on the lessee's behalf
Lessor means an Indian tribe or individual Indian mineral owner who has entered into a lease.
Like-quality oil means oil that has similar chemical and physical characteristics.
Location differential means an amount paid or received (whether in money or in barrels of oil) 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.
Marketable condition means lease products that are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area.
MMS means the Minerals Management Service of the Department of the Interior.
Net means to reduce the reported sales value to account for transportation instead of reporting a transportation allowance as a separate entry on Form MMS-2014.
NYMEX price means the average of the New York Mercantile Exchange (NYMEX) settlement prices for light sweet oil delivered at Cushing, Oklahoma, calculated as follows:
(1) Sum the prices published for each day during the calendar month of production (excluding weekends and holidays) for oil to be delivered in the nearest month of delivery for which NYMEX futures prices are published corresponding to each such day; and
(2) Divide the sum by the number of days on which those prices are published (excluding weekends and holidays).
Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities and is marketed or used as such. Condensate recovered in lease separators or field facilities is considered to be oil.
Operating rights owner, also known as a working interest owner, means any person who owns operating rights in a lease subject to this subpart. A record title owner is the owner of operating rights under a lease until the operating rights have been transferred from record title (see Bureau of Land Management regulations at 43 CFR 3100.0-5(d)).
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).
Processing means any process designed to remove elements or compounds (hydrocarbon and nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes that normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.
Quality differential means an amount paid or received under an exchange agreement (whether in money or in barrels of oil) 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.
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.
Selling arrangement means the individual contractual arrangements under which sales or dispositions of oil are made. Selling arrangements are described by illustration in the MMS Oil and Gas Payor Handbook, Volume III—Product Valuation.
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.
WTI means West Texas Intermediate.
You means a lessee, operator, or other person who pays royalties under this subpart.
(a) The value of oil under this section is the gross proceeds accruing to the seller under the arm's-length contract, less applicable allowances determined under §§ 206.56 and 206.57. If the arm's-length sales contract does not reflect the total consideration actually transferred either directly or indirectly from the buyer to the seller, you must value the oil sold as the total consideration accruing to the seller. Use this section 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 have multiple arm's-length contracts to sell oil produced from a lease that is valued under paragraph (a) of this section, the value of the oil is the volume-weighted average of the total consideration established under this section for all contracts for the sale of oil produced from that lease.
(c) If MMS determines that the value under paragraph (a) of this section does not reflect the reasonable value of the production due to either:
(1) Misconduct by or between the parties to the arm's-length contract; or
(2) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor, MMS will establish a value based on other relevant matters.
(i) The 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.
(ii) The fact that the price received by the seller under an arm's-length contract is less than other measures of market price 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 produced from the lease.
(d) You must base value on the highest price that the seller can receive through legally enforceable claims under the oil sales contract. If the seller fails to take proper or timely action to receive prices or benefits to which it is entitled, you must base value on that obtainable price or benefit.
(1) In some cases the seller may apply timely for a price increase or benefit allowed under the oil sales contract, but the purchaser refuses the seller's request. If this occurs, and the seller takes reasonable documented measures to force purchaser compliance, you will owe no additional royalties unless or until the seller receives monies or consideration resulting from the price increase or additional benefits. This paragraph (d)(1) does not permit you to avoid your royalty payment obligation if a purchaser fails to pay, pays only in part, or pays late.
(2) 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.
(e) If you or your affiliate enter(s) into an arm's-length exchange agreement, or multiple sequential arm's-length exchange agreements, then you must value your oil under this paragraph.
(1) If you or your affiliate exchange(s) oil at arm's length for WTI or equivalent oil at Cushing, Oklahoma, you must value the oil using the NYMEX price, adjusted for applicable location and quality differentials under paragraph (e)(3) of this section and any transportation costs under paragraph (e)(4) of this section and §§ 206.56 and 206.57.
(2) If you do not exchange oil for WTI or equivalent oil at Cushing, but exchange it at arm's length for oil at another location and following the arm's-length exchange(s) you or your affiliate sell(s) the oil received in the exchange(s) under an arm's-length contract, then you must use the gross proceeds under your or your affiliate's arm's-length sales contract after the exchange(s) occur(s), adjusted for applicable location and quality differentials under paragraph (e)(3) of this section and any transportation costs under paragraph (e)(4) of this section and §§ 206.56 and 206.57.
(3) 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 exchange agreement does not reflect reasonable location or quality differentials, MMS may adjust the differentials you used based on relevant information. You may not otherwise use the price or differential specified in an arm's-length exchange agreement to value your production.
(4) If you value oil under this paragraph, MMS will allow a deduction, under §§ 206.56 and 206.57, for the reasonable, actual costs to transport the oil:
(i) From the lease to a point where oil is given in exchange; and
(ii) If oil is not exchanged to Cushing, Oklahoma, from the point where oil is received in exchange to the point where the oil received in exchange is sold.
(5) If you or your affiliate exchange(s) your oil at arm's length, and neither paragraph (e)(1) nor (e)(2) of this section applies, MMS will establish a value for the oil based on relevant matters. After MMS establishes the value, you must report and pay royalties and any late payment interest owed based on that value.
(f) You may not deduct any costs of gathering as part of a transportation deduction or allowance.
(g) You must also comply with § 206.54.
(a) The unit value of your oil not sold under an arm's-length contract is the volume-weighted average of the gross proceeds paid or received by you or your affiliate, including your refining affiliate, for purchases or sales under arm's-length contracts.
(1) When calculating that unit value, use only purchases or sales of other like-quality oil produced from the field (or the same area if you do not have sufficient arm's-length purchases or sales of oil produced from the field) during the production month.
(2) You may adjust the gross proceeds determined under paragraph (a) of this section for transportation costs under paragraph (c) of this section and §§ 206.56 and 206.57 before including those proceeds in the volume-weighted average calculation.
(3) If you have purchases away from the field(s) and cannot calculate a price in the field because you cannot determine the seller's cost of transportation that would be allowed under paragraph (c) of this section and §§ 206.56 and 206.57, you must not include those purchases in your weighted-average calculation.
(b) Before calculating the volume-weighted average, you must normalize the quality of the oil in your or your affiliate's arm's-length purchases or sales to the same gravity as that of the oil produced from the lease. Use applicable gravity adjustment tables for the field (or the same general area for like-quality oil if you do not have gravity adjustment tables for the specific field) to normalize for gravity.
Example to paragraph (b):
1. Assume that a lessee, who owns a refinery and refines the oil produced from the lease at that refinery, purchases like-quality oil from other producers in the same field at arm's length for use as feedstock in its refinery. Further assume that the oil produced from the lease that is being valued under this section is Wyoming general sour with an API gravity of 23.5°. Assume that the refinery purchases at arm's length oil (all of which must be Start Printed Page 71244Wyoming general sour) in the following volumes of the API gravities stated at the prices and locations indicated:
|10,000 bbl||24.5°||$34.70/bbl||Purchased in the field.|
|8,000 bbl||24.0°||34.00/bbl||Purchased at the refinery after the third-party producer transported it to the refinery, and the lessee does not know the transportation costs.|
|9,000 bbl||23.0°||33.25/bbl||Purchased in the field.|
|4,000 bbl||22.0°||33.00/bbl||Purchased in the field.|
2. Because the lessee does not know the costs that the seller of the 8,000 bbl incurred to transport that volume to the refinery, that volume will not be included in the volume-weighted average price calculation. Further assume that the gravity adjustment scale provides for a deduction of $0.02 per 1/10 degree API gravity below 34°. Normalized to 23.5° (the gravity of the oil being valued under this section), the prices of each of the volumes that the refiner purchased that are included in the volume-weighted average calculation are as follows:
|10,000 bbl||24.5°||$34.50||(1.0° difference over 23.5° = $0.20 deducted).|
|9,000 bbl||23.0°||33.35||(0.5° difference under 23.5° = $0.10 added).|
|4,000 bbl||22.0°||33.30||(1.5° difference under 23.5° = $0.30 added).|
3. The volume-weighted average price is ((10,000 bbl × $34.50/bbl) + (9,000 bbl × $33.35/bbl) + (4,000 bbl × $33.30/bbl)) / 23,000 bbl = $33.84/bbl. That price will be the value of the oil produced from the lease and refined prior to an arm's-length sale, under this section.
(c) If you value oil under this section, MMS will allow a deduction, under §§ 206.56 and 206.57, for the reasonable, actual costs:
(1) That you incur to transport oil that you or your affiliate sell(s), which is included in the weighted-average price calculation, from the lease to the point where the oil is sold; and
(2) That the seller incurs to transport oil that you or your affiliate purchase(s), which is included in the weighted-average cost calculation, from the property where it is produced to the point where you or your affiliate purchase(s) it. You may not deduct any costs of gathering as part of a transportation deduction or allowance.
(d) If paragraphs (a) and (b) of this section 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.
(e) You must also comply with § 206.54.
(a) For any Indian leases that provide that the Secretary may consider the highest price paid or offered for a major portion of production (major portion) in determining value for royalty purposes, if data are available to compute a major portion, MMS will, where practicable, compare the value determined in accordance with this section with the major portion. The value to be used in determining the value of production, for royalty purposes, will be the higher of those two values.
(b) For purposes of this paragraph, major portion means the highest price paid or offered at the time of production for the major portion of oil production from the same field. The major portion will be calculated using like-quality oil sold under arm's-length contracts from the same field (or, if necessary to obtain a reasonable sample, from the same area) for each month. All such oil production will be arrayed from highest price to lowest price (at the bottom). The major portion is that price at which 50 percent by volume plus one barrel of oil (starting from the bottom) is sold.
You must place oil in marketable condition and market the oil for the mutual benefit of yourself and the Indian lessor at no cost to the lessor, unless the lease agreement provides otherwise. If, in the process of marketing the oil or placing it in marketable condition, your gross proceeds are reduced because services are performed on your behalf that would be your responsibility, and if you valued the oil using your or your affiliate's gross proceeds (or gross proceeds received in the sale of oil received in exchange) under § 206.52, you must increase value to the extent that your gross proceeds are reduced.
6. Sections 206.58 through 206.62 are added to read as follows:End Amendment Part
(a) If MMS finds that you have not properly determined value, you must:
(1) Pay the difference, if any, between the royalty payments you made and those that are due, based upon the value MMS establishes; and
(2) Pay interest on the difference computed under § 218.54 of this chapter.
(b) If you are entitled to a credit due to overpayment on Indian leases, see § 218.53 of this chapter. The credit will be without interest.
You may ask MMS for guidance in determining value. You may propose a value method to MMS. Submit all available data related to your proposal and any additional information MMS deems necessary. We will promptly review your proposal and provide you with non-binding guidance.
(a) You must compute royalties on the quantity and quality of oil as measured at the point of settlement approved by BLM for the lease.
(b) If you determine the value of oil under §§ 206.52, 206.53, or 206.54 of this subpart based on a quantity or quality different from the quantity or quality at the point of royalty settlement approved by BLM for the lease, you must adjust the value for those quantity or quality differences.
(c) You may not deduct from the royalty volume or royalty value actual or theoretical losses incurred before the royalty settlement point unless BLM determines that any actual loss was unavoidable.
(a) On request, you must make available sales, volume, and transportation data for production you sold, purchased, or obtained from the field or area. You must make this data available to MMS, Indian Start Printed Page 71245representatives, or other authorized persons.
(b) You must retain all data relevant to the determination of royalty value. Document retention and recordkeeping requirements are found at §§ 207.5, 212.50, and 212.51 of this chapter. The MMS, Indian representatives, or other authorized persons may review and audit such data you possess, 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 or the lease.
The MMS will keep confidential, to the extent allowed under applicable laws and regulations, any data or other information 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, 43 CFR part 2.
[FR Doc. E7-24318 Filed 12-14-07; 8:45 am]
BILLING CODE 4310-MR-P