FEDERAL AND INDIAN LEASE ROYALTY DECISIONSSIGNIFICANT JUDICIAL AND ADMINISTRATIVE CASES FROM 2000-2003

• Jurisdiction: United States

Federal and Indian Oil and Gas Royalty Valuation and Management Book 1
(Feb 2004)
CHAPTER 4B
FEDERAL AND INDIAN LEASE ROYALTY DECISIONSSIGNIFICANT JUDICIAL AND ADMINISTRATIVE CASES FROM 2000-2003
Howard W. Chalker
Office of the Solicitor - Department of the Interior
Washington, D.C.
TABLE OF CONTENTS

I. Marketable Condition Cases

II. Marketing Costs Cases

III. Affiliate Resale/Marketing Costs Cases

IV. "Restructured Accounting" Cases

V. MMS' Regulations Establish Value Cases

VI. Rules for Valuing Production Processed Under a Non-Arm's-Length Processing Arrangement and Application of the Royalty Fairness Act's 33-Month Deadline for Final Decisions in Administrative Appeals Cases

VII. Statute of Limitations Cases

VIII. Contract Settlement Cases

IX. OCSLA Section 6 Cases

This paper provides a summary of several significant judicial and administrative decisions on Federal and Indian oil and gas lease royalty issues issued since the 2000 institute on Federal and Indian Oil and Gas Royalty Valuation and Management. The views expressed in this paper are the personal views of the author and do not necessarily represent the views of the Office of the Solicitor, the Minerals Management Service (MMS), or the Department of the Interior (DOI or Department).

I have been personally involved with many of the cases discussed in this paper.

The cases are organized by subject matter. Within each section, this paper first discusses judicial decisions and then administrative decisions.

I. Marketable Condition

Amoco Production Co. v. Baca, No. 00-02933 and Vastar Resources, Inc. v. Baca, No. 00-01480 (D.D. C. Nov. 14, 2003).

Amoco Production Co. (Amoco) and Vastar Resources, Inc. (Vastar) produced coalbed methane under Federal oil and gas leases in the San Juan Basin of northwest New Mexico. Coalbed methane contains significantly higher levels of carbon dioxide (CO%l2%l) than conventional gas. As a result, CO%l2%l must be removed from the gas after it is extracted before the methane is marketed. Additionally, gas transportation lines generally limit the amount of CO%l2%l allowed in the gas stream.

Amoco and Vastar deducted from royalty value their costs of removing the CO%l2%l from the gas stream. MMS ordered them to pay additional royalties because these deductions were not proper under MMS' regulations. MMS denied the deductions because the removal of CO%l2%l from the gas stream is necessary to place the gas into marketable condition. Because about 10 percent of the gas was sold at the wellhead without the removal of CO%l2%l, Amoco and Vastar challenged MMS' assessment by arguing that it was in marketable condition at the wellhead. The court rejected Plaintiffs' argument because the sale of only 10 percent of the gas at the wellhead did not establish the market for all of the gas. Slip op. at 19.

Next, Amoco and Vastar argued that the costs of removing CO%l2%l from the gas stream were incurred to bring the gas to pipeline quality. On that basis, they asserted that these costs were deductible from royalty value as part of their transportation allowance. The court also rejected this argument, holding that costs necessary to place the gas into marketable condition cannot be deducted as a transportation allowance. Id. at 19-21.

The court also held that (1) "deference is regularly accorded to agency decisions relating to mineral leases and royalty valuation," Id. at 7; (2) Plaintiffs were not entitled to an extraordinary cost processing allowance, Id. at 21-25; and (3) late payment interest was due on the royalty under payments, Id. at 25-27. Additionally, it held that a MMS "Dear Payor letter," which MMS sent to all payors to provide MMS' view on proper deductions, did not violate the Administrative Procedure Act (APA) because it was issued by an MMS royalty official and could not bind the Department. Thus, it was not a rule subject to notice and comment under the APA. Id. at 11.

Significance: This case reaffirms the principle that Federal and Indian lessees must place production into marketable condition at no cost to the lessor. This case has a significant monetary impact because many other producers are raising arguments similar to those of Vastar and Amoco.

Mobil Exploration & Producing U.S. Inc. v Norton, No. 99-3240 (JR) (Mar. 30, 2001).

Mobil Exploration & Producing U.S. Inc. (Mobil) produced gas from offshore leases that contained both hydrogen sulfide and carbon dioxide. Under 30 C.F.R. § 206.158(d)(2)(i) , Mobil asked MMS to grant it an extraordinary cost allowance for its costs of removing both of these impurities. This regulation states that such removal costs must be borne by the lessee unless the lessee can demonstrate that such costs are by standard industry conditions "extraordinary, unusual, or unconventional."

MMS found that the gas stream and the process of removing the hydrogen sulfide and carbon dioxide may be unusual and unconventional. Regardless, MMS denied Mobil's request because Mobil's costs were, by comparison to other plants, clearly not unusual, unconventional, or extraordinary. Mobil appealed this denial to the IBLA, which remanded it to MMS for further fact finding. Then, the Assistant Secretary - Land and Minerals Management affirmed MMS' denial. The Assistant Secretary held that (1) the gas stream was not unusual merely because of the hydrogen sulfide to carbon dioxide ratio; (2) the plant design was not new or unique; and (3) the costs were not extraordinary compared to other treatment plants. Mobil then sought judicial review.

The court granted the government's motion for summary judgment. First, it held that the costs of removing the hydrogen sulfide, which is commonly called "sweetening," were part of the cost of placing production into marketable condition. It stated that MMS' rule, which prohibits such deductions, 30 C.F.R. § 206.158(d)(1) , was proper under the Outer Continental Shelf Lands Act, 43 U.S.C. §§ 1331 -1356a. Slip op. at 4. The court then held that the Assistant Secretary properly applied 30 C.F.R. § 206.158(d)(2)(i) , when determining that Mobil's costs, when compared to others, were not sufficiently great to qualify for the allowance. The court held that the Assistant Secretary's decision properly included an analysis of all the relevant factors and principles, and articulated a rational connection between the facts and the decision. Slip op. at 6-7.

J-W Operating Company Inc., 159 IBLA 1 (2003), appeal filed,J-W Operating Company v. Triebsch, No. 3-03CV 1470 (N.D. Tex. filed July 1, 2003).

J-W Operating Company Inc. (J-W) produced natural gas from Federal leases in Colorado. J-W sold some of the gas at issue to Kansas Nebraska Natural Gas Company (KN). Some of J-W's sales to KN were at the wellhead and other sales to KN were at a central delivery point off the leases. If J-W's gas did not meet pressure requirements, it was required to reimburse KN 2 to 7 cents per Mcf for KN's costs to compress the gas after it bought it from J-W.

J-W sold other gas to its affiliate, YGS. In turn, YGS resold the gas to third parties. Under one arrangement, YGS provided gathering, dehydration, and compression charges for 69 cents per MMBtu. Under another arrangement, YGS paid J-W its resale price, less 50 cents per Mcf that was attributable to gathering, dehydration, and compression performed by YGS.

MMS assessed additional royalties because J-W failed to pay royalties on additional value it received for gathering, compression, and dehydration of gas. J-W appealed MMS' assessment and raised two basic arguments. It challenged MMS' assessment to the extent that it relied on J-W's wholly-owned affiliate's resale price to establish value. (In reality, YGS was J-W's wholly- owned affiliate. H. G. Westerman owned 100 percent of J-W and 92.5 percent of YGS. H. G. Westerman's brother, Carl Westerman, owned the remaining 7.5 percent of YGS.) It also asserted that the gas was in marketable condition at the wellhead because the wellhead was the market and that the marketable condition rule does not require the lessee to condition the gas so that it is suitable for secondary markets. (The marketable condition rule requires the lessee to place its production into a physical condition so that it will be accepted by a purchaser under a sales contract typical for the field or area, at no cost to the federal lessor. 30 C.F.R. § 206.151 .)

The Interior Board of Land Appeals (IBLA) rejected both of J-W's arguments. It held that YGS' resale of the gas established J-W's royalty value. It also held that the costs of gathering, compression, and dehydration of the gas must be added to royalty value because these procedures are part of the cost of placing the gas into marketable condition. 159 IBLA 11-13. In reaching its decision, it rejected J-W's argument that the market was at the wellhead, noting that the only sales of gas as it came from the wellhead were limited and were to local domestic and agricultural users. In other words, sales of small amounts of untreated production at or near the lease do not establish the lease as the market for the remaining production. It also relied on the sales contracts between J-W and YGS for the sale of the unconditioned gas which stated that the gas had to be put into marketable condition before it could be redelivered. Id. at 13 n.12.

Significance: This case upheld the principle that the lessee must place production into marketable condition at no cost to the Federal lessor. It also stands for the proposition that sales of small amounts of untreated production at or near the lease do not establish the lease as the market for the remaining production.

However, because of the decision in Fina Oil and Chemical Co. v. Norton, 209 F.Supp2d 246 (D.D.C. 2002), rev'd, 332 F.3d 672 (D.C. Cir. 2003), discussed below in Part III., MMS will no longer value J-W's production at the affiliate resale price. Thus, MMS must now revalue...