THE NEW INDIAN GAS VALUATION RULE AN AUDIT PERSPECTIVE

• Jurisdiction: United States

Federal & Indian Oil & Gas Royalty Valuation and Management III
(2000)
CHAPTER 3B
THE NEW INDIAN GAS VALUATION RULE AN AUDIT PERSPECTIVE
Perry Shirley
Minerals Department, Division of Natural Resources The Navajo Nation
Window Rock, Arizona

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TABLE OF CONTENTS

SYNOPSIS

I. Introduction 3B —

II. Background 3B —

III. Compliance Under the New Indian Gas Rule 3B —

A. Compliance With Index-Based Valuation 3B —

B. Compliance With Alternative Methodology for Dual Accounting 3B —

C. Compliance With Safety Net Calculations for Index Zone Leases 3B —

D. Compliance With Non-Index-Based Valuation 3B —

E. Compliance With Actual Dual Accounting Calculation Method 3B —

F. Compliance With Transportation Allowance Determination 3B —

G. Compliance With Processing Allowance Determination 3B —

H. Compliance With Processing Costs for Dual Accounting Purposes 3B —

IV. Conclusion 3B —

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I. Introduction

The Navajo Nation's Minerals Audit Program is one of 19 tribal and State audit programs that have entered into cooperative agreements with the U.S. Department of the Interior, Minerals Management Service (MMS) to conduct audits of their respective mineral leases. The authority for the cooperative agreements are found under Sections 202 and 205 respectively, of the Federal Oil and Gas Royalty Management Act of 1982, as modified by the Enrolled 1992 Appropriation Bill, H.R. 2686-12. The Navajo Nation has been performing compliance reviews of its mineral leases since 1984.

The purpose of this paper is to present a tribal audit perspective through a general overview of the new Indian gas regulations¹ that govern the valuation of natural gas produced from Indian lands. The new Indian gas regulations became effective January 1, 2000 and amended the March 1, 1988 gas valuation regulations for Indian leases. The objective of this paper is to distinguish areas of importance in determining valuation under the new Indian gas regulations, which in turn, may facilitate a better understanding of future compliance reviews. This paper is not intended to provide royalty valuation guidance, specific audit guidance, nor is it intended to promote the position of the Navajo Nation or any other Indian tribe regarding the new Indian gas rule. Because the Navajo Nation's audit authority is limited to audits of Navajo tribal mineral leases, the compliance experiences related herein are those of the Navajo Nation's Minerals Audit Program. Furthermore, the ideas, opinions and viewpoints represented in this paper are those of the author and not necessarily the official views of the Navajo Nation or the Department of the Interior, MMS.

II. Background

It is important to point out the history and origin of the significant compliance issues that have plagued MMS and most tribes with audit delegations since the publication of the March 1, 1988 gas valuation regulations. Regardless of differing lease terms, applicable regulations, policies, etc., the royalty rate equation is a simple one. The three variables in the royalty valuation equation that determines a royalty payment are:

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Royalty=Royalty Rate×Product Value×Production Volume

Most everyone will agree that the royalty rate provision of a lease is fairly straightforward and represents a percentage of the sum of the product value multiplied by the production volume. Our experience has been that the two remaining variables, product value and production volumes are the source of most royalty compliance issues.

Prior to the enactment of the Indian Mineral Development Act of 1982² , which permitted tribes to negotiate their own mineral leasing and development agreements with third parties, most Indian leases consisted of a BIA Standard Lease Form 157, which contained standard terms and provisions drafted by the Department of the Interior under authority of the Indian Mineral Leasing Act of 1938³ . In addition to specifying the royalty rate, paragraph 3(c) of such leases provides that:

"[V]alue ... may, in the discretion of the Secretary, be calculated on the basis of the highest price paid or offered ... at the time of production ... for the major portion of ... gas ... produced and sold from the field where the leased lands are situated... The actual amount realized by the lessee from the sale of said products may, in the discretion of the Secretary, be deemed mere evidence or conclusive evidence of such value... It is understood that in determining the value for royalty purposes of products ... derived from the treatment of gas, a reasonable allowance for the cost of manufacture shall be made, such allowance to be two-thirds of the value of the marketable product unless otherwise determined by the Secretary of the Interior ... and ... royalty will be computed on the value of gas or casinghead gas, or on the products thereof ... whichever is greater. (emphasis added).

The Secretary of the Interior (Secretary) is obligated to act as a fiduciary in the administration of Indian oil and gas leases⁴ . As a fiduciary, charged with supervising the disposition of mineral resources from Indian lands, the Secretary must ensure that Indians receive the maximum revenues from their mineral resources. As interpreted by the Tenth Circuit in Jicarilla Apache Tribe v. Supron Energy Corp., this provision in Section 3(c) of the BIA Standard Lease Form 157 requires that the Secretary take every reasonable step in valuation determinations to maximize Indian royalty revenues, and that royalties shall be paid on the higher of the processed or unprocessed gas values, which must be at least as great as gross proceeds⁵ . In addition, the court in Supron held that when:

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Given two reasonable interpretations, Interior's trust responsibilities require it to apply whichever...yields the Tribe the greatest royalties⁶ .

Indian leases containing these unique valuation provisions⁷ , specifically valuation methods requiring that royalties be calculated using major portion⁸ and dual accounting⁹ (or accounting for comparison) criteria have been problematic, not only from a lessee compliance standpoint but also from an royalty management perspective. The primary reason given by many companies for lack of compliance with these lease provisions is attributed to difficulties in obtaining information and documents necessary to comply with major portion and dual accounting lease requirements. Compliance with major portion requires royalty lessees to have access to other company sales data to calculate the major portion price. Such sales data is considered confidential and subject to certain disclosure protection laws.

The March 1, 1988 gas regulations at 30 CFR §§ 206.152(a)(3)(i) and (ii) and 206.153(a)(3)(i) and (ii) (1988) provides the method of calculating major portion prices prior to January 1, 2000. The major portion price was calculated by arraying the highest price to the lowest price of all sales of gas produced from the same field for each month. The major portion was that price at which 50 percent (by volume) plus 1 mcf of the gas (starting from the bottom) is sold or for gas plant products, 50 percent (by volume) plus 1 unit. For the most part, MMS calculated major portion prices for most Indian gas production using gross proceeds sales data that was reported to its internal Auditing and Financial System (AFS). For Oklahoma Indian groups, other external data was used. Because this process is very labor intensive and time consuming, the calculated major portion prices were not made available to the lessees in a timely manner. This resulted in a related audit issue, the assessment of late payment interest on the major portion price underpayments. Lessees have long contended that it is unfair to require interest on additional royalties when the prices necessary to correctly pay royalties were not available at the time royalties were due.

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Since July 31, 1992, MMS has issued approximately 951 letters to companies related to major portion value deficiencies. This resulted in approximately 635 orders to pay (demand letters) or orders to perform being sent to about 300 companies. Collections have been received on approximately 73% of the orders¹⁰ . The remaining 27% have not been resolved and/or have been appealed administratively. In Burlington Resources Oil and Gas Co.,¹¹ Burlington appealed a decision of the Acting Deputy of Indian Affairs, affirming an order directing Burlington to pay additional royalties on certain Indian oil and gas leases in accordance with a major portion analysis on gas production (MMS-96-0139-IND). Many of the difficulties facing both the lessee and MMS in attempting to meet major portion requirements are presented in this case. While the IBLA held that it was satisfied with the statistical methodology used by MMS to determine major portion prices, it noted that MMS did not separate non-arm's-length transactions and prices from prices obtained in arm's-length transactions in the population considered, despite the requirement in its own regulations that only arm's-length transaction prices shall be considered in the major portion analysis. The IBLA further noted that major portion analysis is required only if arm's-length sales data is available and if the calculations are practical, apparently in disregard of lease term provisions. Tribes will argue that major portion is a lease requirement and that lease terms supercede any regulations to the contrary. Regulations at 30 CFR § 206.150(b) (1988) state:

If the specific provisions of any...oil and gas lease subject to the requirements of this subpart [Subpart D — Federal and Indian Gas] are inconsistent with any regulation in this subpart, then the lease...shall govern to the extend of that inconsistency.

The inadequacies of the AFS to differential non-arm's-length sales from arm's-length sales were also noted. MMS was not precluded from recalculating its major...