Devon Energy Corp. v. Kempthorne

• Decision Date: 23 December 2008
• Docket Number: No. 07-5299.,07-5299.
• Citation: 551 F.3d 1030
• Parties: DEVON ENERGY CORPORATION, Appellant v. Dirk KEMPTHORNE, Secretary of the Interior, Appellee.
• Court: U.S. Court of Appeals — District of Columbia Circuit

551 F.3d 1030

DEVON ENERGY CORPORATION, Appellant v. Dirk KEMPTHORNE, Secretary of the Interior, Appellee.

No. 07-5299.

United States Court of Appeals, District of Columbia Circuit.

Argued September 15, 2008.

Decided December 23, 2008.

Appeal from the United States District Court for the District of Columbia, (No. 04cv00821).

Deborah B. Haglund argued the cause for appellant. With her on the briefs was Charles D. Tetrault.

Erik Milito and Michele Schoeppe were on the brief for amicus curiae American Petroleum Institute in support of appellant.

Sambhav N. Sankar, Attorney, U.S. Department of Justice, argued the cause for appellee. With him on the brief was Michael T. Gray, Attorney. R. Craig Lawrence, Assistant U.S. Attorney, entered an appearance.

Before: BROWN, Circuit Judge, and EDWARDS and SILBERMAN, Senior Circuit Judges.

Opinion for the Court filed by Senior Circuit Judge EDWARDS.

EDWARDS, Senior Circuit Judge:

The United States leases the rights to extract and sell natural gas from lands owned by the Government. In exchange, lessees, like appellant Devon Energy Corporation ("Devon"), agree to pay the United States royalties on the natural gas they are able to produce. This case arises from a final order issued by the United States Department of the Interior ("DOI" or "Interior") requiring Devon retroactively to recalculate royalties owed to the Government pursuant to its lease to extract coalbed methane from federal land in Wyoming.

At issue is the agency's interpretation of its "marketable condition rule." The rule was included as a part of DOI's 1988 Revision of Gas Royalty Valuation Regulations, which establish the framework for calculating the royalty value of coalbed methane gas production. In its disputed order, DOI held that the marketable condition rule precluded Devon from deducting certain costs associated with compression and dehydration when calculating the "gross proceeds" upon which royalties are owed. DOI determined that gas cannot enter a pipeline and move to a purchaser unless it meets the requirements of the pipeline, which typically requires compression to raise its pressure and dehydration to reduce its water content. Thus, DOI concluded that if gas is not sufficiently compressed and dehydrated to be deliverable to the point of purchase through the pipeline, it is not in marketable condition. Devon filed suit in the District Court to challenge Interior's order. The District Court denied Devon's motion for summary judgment and granted the Secretary's cross-motion. On appeal, Devon argues that DOI's order is inconsistent with the plain language of the marketable condition rule, and also inconsistent with DOI's own prior interpretation of the rule.

We affirm the judgment of the District Court. First, we find that Interior's interpretation of the marketable condition rule reflects a perfectly reasonable construction of the rule. It is clear that the agency's order is not at odds with the plain language of the rule, nor does it effectively "amend," rather than reasonably construe, the rule. Second, we reject Devon's claim that DOI's order conflicts with a prior interpretation of the marketable condition rule. Devon argues that its position finds support in guidance documents distributed by agency personnel after DOI's promulgation of the 1988 regulations. However, as Devon concedes, these contested guidance documents were distributed by agency individuals who had no authority either to amend the marketable condition rule or to issue authoritative guidelines on behalf of the agency.

I. BACKGROUND

A. Statutory and Regulatory Framework

Through its Minerals Management Service ("MMS"), Interior issues and administers leases authorizing the removal of natural gas from federal land. The Mineral Leasing Act, 30 U.S.C. §§ 181 et seq. (2000), "was intended to promote wise development of these natural resources and to obtain for the public a reasonable financial return on assets that `belong' to the public." California Co. v. Udall, 296 F.2d 384, 388 (D.C.Cir.1961). Under the Mineral Leasing Act, the producer-lessees must pay the government-lessor "a royalty at a rate of not less than 12.5 percent in amount or value of the production removed or sold from the lease." 30 U.S.C. § 226(b)(1)(A). In the Federal Oil and Gas Royalty Management Act, the Secretary of the Interior was instructed by Congress to create a comprehensive inspection, collection, accounting, and auditing system to ensure that the government receives the royalties owed. 30 U.S.C. § 1711(a) (1982).

The Mineral Leasing Act gives DOI the authority "to prescribe necessary and proper rules and regulations and to do any and all things necessary to carry out and accomplish the purposes of" the Act. 30 U.S.C. § 189. Pursuant to this directive, DOI has issued a number of regulations governing the royalty valuation process. In 1988, DOI conducted a major rulemaking that modified the then-existing gas royalty valuation regulations. See Revision of Gas Royalty Valuation Regulations and Related Topics, 53 Fed.Reg. 1230, 1272 (Jan. 15, 1988); 30 C.F.R. § 206.152 (1988). The 1988 regulations establish the framework for calculating the royalty value of the coalbed methane gas production at issue here. Under this regulatory framework, royalties are calculated on the basis of the total value a lessee receives for its production. The regulations specify that the "value of production" should be no less "than the gross proceeds accruing to the lessee for lease production," minus certain allowable deductions. 30 C.F.R. § 206.152(h); see also Amoco Prod. Co. v. Watson, 410 F.3d 722, 725 (D.C.Cir.2005), aff'd sub nom., BP Am. Prod. Co. v. Burton, 549 U.S. 84, 127 S.Ct. 638, 166 L.Ed.2d 494 (2006).

When calculating "gross proceeds," DOI regulations have long interpreted the Mineral Leasing Act to require lessees to put the gas into marketable condition at no cost to the United States — the so-called "marketable condition rule." The 1988 regulations confirmed this requirement. See 30 C.F.R. § 206.152(i) (governing unprocessed gas); 30 C.F.R. § 206.153(i) (governing processed gas); see also California Co., 296 F.2d at 387-88 (affirming marketable condition requirement). Marketable condition is defined in the DOI regulations as "lease products which 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." 30 C.F.R. § 206.151. If a lessee sells "unmarketable" gas at a lower price, the gross proceeds are "increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services" to place the gas in marketable condition. 30 C.F.R. § 206.152(i); Amoco, 410 F.3d at 725-26.

The 1988 regulations also provide that the lessee may deduct its actual costs of transporting the gas from the wellhead to the point of sale when gas produced from the lease is sold at a market remote from the lease. 30 C.F.R. § 206.157(a)-(b). This "transportation allowance" includes "only those costs which are directly related to the transportation of lease production." 53 Fed.Reg. at 1261. A transportation allowance is defined as "an allowance for the reasonable, actual costs of moving [gas] to a point of sale or delivery off the lease ... or away from a processing plant." 30 C.F.R. § 206.151.

B. Facts and Proceedings Below

Devon leases land from the United States in Wyoming's Powder River Basin, which contains the natural gas known as coalbed methane. These leases cover three fields — Kitty, Spotted Horse, and Rough Draw — each of which contains a large number of individual gas-producing wells. The gas produced from the wells is gathered at central delivery points ("CDPs") that have been approved by the Bureau of Land Management as the points of measure for the royalty due on the gas. After the gas leaves a CDP, it goes through a complex series of compression and dehydration processes as it travels "downstream" to the Buckshot processing plant in preparation for eventual sale. See Valuation Determination for Coalbed Methane Production from the Kitty, Spotted Horse, and Rough Draw Fields, reprinted in Joint Appendix ("J.A.") 57 ("Valuation Determination"); see also Chart, J.A. 460.

The production process varies slightly in the three fields, but the differences are not material. Essentially, each CDP is connected to a small diameter pipeline. Gas travels from the CDP through the pipeline to one of several "screw compressors," which compress the gas to raise its pressure. The gas then travels through the pipeline to a "field booster," a reciprocating compressor that further raises the pressure of the gas. The gas then enters a dehydrator, which removes water. Valuation Determination, J.A. 61. At this point, the gas enters a 24-inch high-pressure gas pipeline, which begins at what is known as the Landeck Station and runs 126 miles to the Buckshot Gas Plant. Approximately 30 miles from the Landeck Station, the gas enters a large compressor called the "MTG Booster," which compresses the gas to raise the pressure from 450-500 pounds per square inch ("psi") to approximately 1,200 psi. The gas travels the remaining 96 miles to the Buckshot Gas Plant, losing approximately one-third of its pressure on the way. Id. at 66.

When the gas arrives at the Buckshot Gas Plant, excess carbon dioxide is removed, the gas is dehydrated, and the gas is compressed from approximately 800 psi to 1,100 psi. At that pressure, Devon delivers the treated gas into one of two lateral pipelines. The gas is transported to various purchasers through these pipelines. Id.

On November 2, 1995, DOI and MMS personnel serving on a group called the Royalty Policy Board met to discuss how the royalty calculation regulations should be applied to coalbed methane production. See Royalty Policy Board Meeting Minutes, Nov. 2, 1995, reprinted in ...