CHAPTER 9 THE NEW MARKETABLE CONDITION RULE: IS IT REALLY NEW OR HAS IT BEEN THIS WAY ALL ALONG?

• Jurisdiction: United States

Federal and Indian Oil & Gas Royalty Valuation and Management
(Oct 2018)
CHAPTER 9
THE NEW MARKETABLE CONDITION RULE: IS IT REALLY NEW OR HAS IT BEEN THIS WAY ALL ALONG?
John F. Shepherd
Holland & Hart LLP
Denver, CO

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JOHN F. SHEPHERD is a partner in the Denver office of Holland & Hart LLP. He specializes in natural resources, public land, oil and gas, and environmental law. Regarding royalty matters, he has successfully handled a broad array of cases related to federal, state, and private royalties, including class actions and qui tam claims, and regularly advises clients on royalty compliance. John is listed in The Best Lawyers in America in the areas of natural resources law, energy law, and administrative law. He is also listed by Colorado Super Lawyers in the areas of energy and oil and gas. In 1998, he was the Natural Resources Distinguished Practitioner-in-Residence at the University of Denver College of Law. He served as a Trustee for the Rocky Mountain Mineral Law Foundation during 1993-1995. He was co-chair of the public lands program for the Mineral Law Foundation's Annual Institute in 2009. John has addressed a variety of natural resources, public land and environmental issues in presentations at the Annual Institute and Special Institutes of the Mineral Law Foundation. His prior presentations on royalty issues include: The Relationship Between Transportation, Marketing, and the Royalty Clause, SPECIAL INSTITUTE ON DRAFTING AND NEGOTIATING OIL AND GAS LEASES (Rocky Mtn. Min. L. Fdn. 2018); and Special Royalty Litigation Issues: Fraud, Fiduciary Relationships and Punitive Damages, SPECIAL INSTITUTE ON PRIVATE OIL & GAS ROYALTIES (Rocky Mtn. Min. L. Fdn. 2003). He has also discussed "marketable condition" issues at programs on Federal and Indian Royalty sponsored jointly by ONRR and the Petroleum Accountants' Society of Oklahoma. John is a graduate of Dartmouth College (A.B., magna cum laude, 1976) and the University of Denver College of Law (J.D., Order of St. Ives, 1979).

I. INTRODUCTION

The "marketable condition" rule is not new. It has been part of the royalty calculation regulations for federal oil and gas leases for many decades, extending almost as far back as the statute creating the federal oil and gas leasing system, the Mineral Leasing Act of 1920. Under this rule, the lessee-producer must bear all costs to make the oil, gas, and other products marketable. The only costs that can be deducted in the calculation of federal royalty are "transportation" and "processing" costs.

The rub is what costs fall in the category of nondeductible marketing costs, and what costs fall in the category of deductible transportation and processing costs. The line between these categories is not precisely drawn. And the regulatory definition of marketable condition is likewise not precise - the product must be in a condition that "will be accepted by a purchaser under a sales contract typical for the field or area."¹

While the rule itself is not new, what is new, at least in the last 15 years, is a broadened interpretation of the rule by the Office of Natural Resources Revenue ("ONRR") and its predecessor agency the Minerals Management Service ("MMS"). ONRR's more recent interpretation seems to amount to a per se rule that gas is not marketable until it meets the pressure and quality requirements of the mainline transmission pipeline on which the gas is ultimately sold. And this interpretation applies even if (i) the pipeline on which the gas is sold happens to be hundreds of miles away from the field where the gas is produced, or (ii) the gas could have been marketed on other pipelines closer to the field with less stringent pressure and quality requirements.

This paper traces the history of the marketable condition rule and evolution of the rule into its current interpretation. As will be seen, for many decades, application of the rule by MMS, the Interior Board of Land Appeals ("IBLA"), and the courts focused on the producer's contracts in or near the field where the gas was produced: what were the terms of those contracts? Resale contracts far away from the field were not part of the equation. Now the focus is not so much on the terms of any "typical contracts," but instead on the ability to meet transmission pipeline specifications to deliver gas to what ONRR and the courts have called the "dominant end-use market."

As will also be seen, the definition of marketable condition that MMS adopted in 1988 was intentionally broad, reserving to the agency "latitude" to adjust to possibly changing market

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conditions. Until the 1990s, most gas was sold at the wellhead, and royalty calculation was not that difficult. Producers generally paid royalty on what they received from the sale and ONRR generally accepted those payments as proper. With deregulation of the natural gas industry in the 1980s and 1990s, gas marketing has become much more complex and producers have sought to increase their net price by marketing gas in distant markets. These changes in gas marketing have no doubt played a role in ONRR's evolving interpretation of "marketable condition."²

Thus far, the courts reviewing challenges to ONRR's current interpretation have upheld the agency. While acknowledging the agency's definition of marketable condition as "ambiguous," and the producers' interpretation of the rule as "reasonable," the courts have ruled in favor of the agency by giving "substantial deference" to an agency's interpretation of its own regulations.

ONRR's current interpretation may have resolved some of the uncertainty over when gas is in marketable condition, but it has also led to other issues in calculating and paying royalty. The end of this paper will identify those issues and possible solutions being considered.

II. EARLY REGULATIONS AND CASES

A. The 1936 and 1942 Operating Regulations

The first regulations clearly to impose a marketable condition requirement on federal oil and gas leases were the oil and gas operating regulations adopted in 1936. These regulations provided in Section 2(n): "It is an obligation of the lessee to put into marketable condition all products produced from the leased land and pay royalty thereon, without recourse to the lessor for deductions on account of costs of treatment or of costs of shipping."³ In 1942, the Secretary published revised oil and gas operating regulations, and retained much the same language in 30 C.F.R. § 221.31.⁴

The 1942 regulations also provided: "The present policy is to allow the use of a reasonable amount of dry gas for operation of the gasoline plant, the amount allowed being determined or approved by the supervisor, but no allowance shall be made for boosting residue gas, or other expenses incidental to marketing."⁵ This regulation, which is still in effect in modified form today, is sometimes referred to as the "boosting" rule.

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B. The Texas Co. Case

Two of the early cases to address the marketable condition rule were The Texas Co.⁶ and California Co. v. Udall.⁷ These cases eventually formed the basis for the marketable condition rules MMS adopted in its 1988 regulations. They have been discussed and applied - or distinguished - in virtually every marketable condition case since.

In The Texas Co., the lessee produced gas from two oil wells in a large oil field. It contracted with a third party to gather and compress the gas, and to deliver it to the buyer's pipeline at a central point in the field. In paying royalty, it deducted the "handling charges" paid for gathering and compression. The U.S. Geological Survey ("USGS," a predecessor to MMS) disallowed the deductions.⁸

The lessee-producer argued that the sales contract called for delivery of gas at a pressure of 1,000 psi, and that without compression, the gas could not be marketed. Nonetheless, the gas needed no further treatment after separation at the wellhead, and was therefore in "marketable condition."⁹

The Acting Solicitor for the Department affirmed the USGS.¹⁰ He explained that the "lessee has not shown that the gas can be marketed at the pressure with which it comes from the wells."¹¹ Furthermore, the lessee "agreed to deliver the gas at a given pressure presumably in order to sell the gas. It cannot reasonably expect the lessor to assume the cost of meeting the lessee's obligation in this respect."¹² Finally, he concluded that this situation was not analogous to cases involving transportation of a product elsewhere in order to market it. Nor was it analogous to manufacturing.¹³

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C. The California Co. Case

In California Co., the lessee produced gas from different horizons at different pressures. The contract for sale of the gas called for delivery of gas in its natural state, but required the gas to meet the specifications for transmission in a pipeline (minimum pressure and maximum water content and liquefiable hydrocarbons). Some of the gas did not meet these specifications and had to be compressed and/or treated; about 30% of the gas needed compression. The lessee deducted the costs incurred to meet the pipeline specifications - primarily compression costs.¹⁴

The court emphasized (as did the Acting Solicitor in The Texas Co.) that transportation costs were not involved; the gas was conditioned and delivered to the purchaser a "short distance" from the wells.¹⁵ Nor was the gas transformed by manufacturing.¹⁶ The court framed the key question as whether royalty is due on the "raw product as it comes from the well, no matter what its condition" or instead "the product readied for the market in and to which it is being sold."¹⁷ The court held that royalty was due on the product after it had been readied for market.

In language that has been oft-quoted in later royalty cases, the court explained that, "Theoretically any gas - any 'production' - is 'marketable'.... There is a clear difference between 'marketing'...