THE FEDERAL OIL AND GAS LEASE MARKETABLE CONDITION DOCTRINE: HOW FAR DOWNSTREAM CAN THE GOVERNMENT GO?

• Jurisdiction: United States

Federal and Indian Oil and Gas Royalty Valuation and Management
(Feb 2007)
CHAPTER 15B
THE FEDERAL OIL AND GAS LEASE MARKETABLE CONDITION DOCTRINE: HOW FAR DOWNSTREAM CAN THE GOVERNMENT GO?
Mike Matthews
Project Analyst, Mineral Audit Division
Department of Audit, State of Wyoming
Cheyenne, Wyoming

MIKE MATTHEWS

Mike Matthews is a Project Analyst with the Department of Audit's Mineral Audit Division. He earned a B.S. in Finance (1989) and a B.S. in Accounting (1990) from the University of Wyoming; and a J.D. (1993) from the University of Wyoming College of Law. He joined the Mineral Audit Division in February of 1999 from private practice.

I. INTRODUCTION^*

The short answer, as far downstream as it takes to place the gas into marketable condition. Why this is the case, as it should be, requires the question to be placed in the proper perspective.

The economics of any mineral development project is contingent upon the value of the mineral or gas in the field. The mineral or gas in the field, undeveloped, must be able to bear all the costs and still provide some incentive for a producer to take the mineral or gas from its undeveloped state all the way to a market; otherwise production would not make sense. One must begin with the understanding that the mineral interest owner owns all of the gas in the field. Thus, ultimately it is the mineral owner's undeveloped minerals that must bear all the costs. When the mineral interest owner agrees to provide the producer with 7/8 of their 100% ownership of the gas or mineral, it is in order get their remaining 1/8 share of the production developed, and in marketable condition. The remaining 1/8 is reserved in the form of a 1/8 royalty. Therefore the entire costs of any project are going to be borne by the royalty owner, as derived through the value of the royalty owner's gas as it exists in the field in its entirety, prior to dividing it up. The royalty owner pays 7/8 of their gas to the producer to bring the remaining 1/8 of their gas out of the ground in a marketable condition. The royalty owner has already compensated the producer for his services, when the royalty owner pays the producer 7/8 of the royalty owner's gas in the field. By payment, we are referring to transfer of ownership in the 7/8 of the mineral interest owner's gas to the producer. Therefore the producer has already been compensated for the costs of doing business - such costs are included in the 7/8's of the gas relinquished by royalty owner, to producer, for his services. Additional allowances and deductions transfer costs from the royalty owner's relinquished 7/8's gas to the royalty owner's remaining 1/8 royalty interest, thus reducing that last 1/8 ownership/royalty interest even further.

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II. MARKETABLE CONDITION DOCTRINE

"The regulations have historically called for a calculation or royalty on the basis of `gross proceeds.'"<sup>1</sup> The Department of Interior (DOI) "has applied the Marketable Condition Rule consistently to all `gross proceeds' . . . since the Rule was promulgated in 1954."² Thus for well over a half a century or longer, DOI has taken and defended the position that gas needs to be placed in marketable condition at no cost to the federal government.³ The United States Court of Appeals, Tenth Circuit reiterated the long standing doctrine known as the marketable condition rule in Amerada Hess while addressing an offshore issue of transportation versus the marketable condition and gross proceeds. The Court cited in two footnotes the CFR sections discussed below, 30 C.F.R. §§ 206.152(h) and 206.152(i) .⁴

30 C.F.R. § 206.152(h) states: "Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for lease production, less applicable allowances." Gross proceeds for royalty purposes are defined under 30 C.F.R. 206.151 Definitions. Gross proceeds include more than "the total monies and other consideration accruing to an oil and gas lessee for the disposition of the gas, residue gas, and gas plant products produced." Gross proceeds also "includes, but is not, limited to, payments to the lessee for certain services such as dehydration, measurement, and/or gathering to the extent that the lessee is obligated to perform them at no cost to the Federal Government." 30 C.F.R. 206.151 .

30 C.F.R. § 206.152(i) further clarifies that: "The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by the lessee's gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the gas in marketable condition or to market the gas." (Emphasis added.) Under the 1988 regulations,⁵ marketable condition for royalty purposes is defined under 30 C.F.R. 206.151 Definitions: "Marketable condition means lease products which are sufficiently free from impurities and otherwise in a condition that they will be accepted by a sales contract typical for the field or area."

As recently, as June 10, 2005 the United States Court of Appeals for the District of Columbia Circuit delivered a decision, in Amoco,⁶ involving "several disputes between the

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government and gas producers over how the need to remove the excess carbon dioxide from coalbed methane, to make it palatable to the mainline pipelines, affects the royalty payment the producers owe the government under those statutes and regulations;"⁷ and shed much appreciated light on what is the geographic limit of the marketable condition doctrine. The Court in Amoco addressed the producers contention that the "statutory provision require[ed] producers to pay royalties based on the "amount or value of the production removed or sold from the lease." 30 U.S.C. § 226(b)(1)(A) (emphasis added). The producers read the underscored phrase as requiring that the physical leasehold be treated as the relevant geographic market, precluding calculation of royalties based on gross proceeds derived from sales remote from the wellhead." The Court in Amoco reasoned that:

Although the producers present a textually plausible reading of section 226,⁸ theirs is not the only one available. The phrase "from the lease" is sufficiently broad to be read as referring simply to the origin of the gas. Gas that is "from the lease" and that is marketed at a remote location can readily be described as gas "removed or sold from the lease." The producers read the statute as if it referred to gas "sold at the lease," but that is not the case. They direct us to no precedent limiting marketable condition to their narrowing construction.⁹

Next the producers argued in Amoco "that the DOI regulation defining gas in "marketable condition" as gas acceptable to "a purchaser under a sales contract typical for the field or area," 30 C.F.R. § 206.151 , requires MMS to consider untreated gas sold at the well-head to be in marketable condition, notwithstanding any later off-lease treatment."¹⁰ The Court in Amoco was persuaded by the Assistant Secretary's rationale "that because the "dominant market for gas from the area is for gas that is utilized in distant markets with a much lower CO2 content," sales contracts for treated gas were typical for the area, while those for untreated gas were not. Amoco Decision at 7; see also ARCO/Vastar Decision at 5."¹¹ The Court in Amoco went on to explain that:

"[t]he regulations define "area" as "a geographic region at least as large as the defined limits of [a] gas field, in which . . . gas lease products have similar quality, economic, and legal characteristics," and define "field" as "a geographic region situated over one or more subsurface . . . gas reservoirs encompassing at least the outermost boundaries of all . . . gas accumulations." 30 C.F.R. § 206.151 (emphases added). Because these terms do not foreclose the possibility of defining a region beyond the geographical limits of a lease-hold, we are hesitant to conclude that the Assistant Secretary's interpretation failed to "sensibly conform[] to the purpose and wording of the regulations." Martin v. Occupational Safety and Health Review Comm'n, 499 U.S. 144, 151 (1991) (internal quotation marks omitted).

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The producers' construction also does not square with the regulatory scheme as a whole. The regulation stipulating that producers are to place gas in marketable condition at no cost to the government does not contain a geographic limit. See 30 C.F.R. § 206.152(i) . More importantly, regulations governing transportation allowances obviously assume that valuation of gas "at a point (e.g., sales point or point of value determination) off the lease" is permissible. Id. § 206.156(a).¹²

In their thorough and exhaustive attempt to narrow the geographic limit of the marketable condition doctrine, producers marshaled an alternative argument before the Court in Amoco. The producers assert that "there is an established demand for untreated gas, [and that] sales of such gas at the wellhead should be treated as `typical' for defining marketable condition."<sup>13</sup> The Court in Amoco accepted as "true that fifteen to twenty percent of the gas purchased from the producers was consumed locally, and [that] it is plausible to conclude that contracts for one-fifth of a product are common enough to be `typical.'"¹⁴ However, the Court reasoned, "it is just as plausible to read typicality as embracing the most common use and sale of gas from the area, and it is not at all obvious from the text and purposes of the regulations that contracts for one-fifth of the gas should govern the regulatory treatment of the remaining eighty...