ROYALTY VALUATION AND MANAGEMENT 101: A PRIMER (PART A)
| Jurisdiction | United States |
(Feb 2004)
ROYALTY VALUATION AND MANAGEMENT 101: A PRIMER (PART A)
Geoffrey Heath 1
Office of the Solicitor - U.S. Department of the Interior
Washington, D.C.
I. The Mineral Leasing Statutes
The Secretary of the Interior ("the Secretary") leases Federally-owned lands (not excluded from leasing either by statute or other withdrawal) for exploration for, and development and production of, oil and gas under two principal statutes, depending on whether the leased lands are part of the public domain or are acquired lands. 2 Public domain lands are leased under the Mineral Leasing Act (MLA), 30 U.S.C. §§ 181 et seq., originally enacted in 1920. Acquired lands are leased on the same terms as public domain lands under the Mineral Leasing Act for Acquired Lands (the "Acquired Lands Act"), 30 U.S.C. §§ 351 et seq., enacted in 1946.
The MLA, at 30 U.S.C. § 226, requires a royalty of "not less than 12 %p1/2%p per centum in amount or value of the production removed or sold from the lease." The reference to "amount" of production refers to the Secretary's authority to take royalty in kind rather than in money (see 30 U.S.C. § 192). While the MMS takes a significant percentage of the royalty accruing to the United States in kind (i.e., MMS accepts physical delivery of the royalty percentage of the oil or gas produced, which MMS then disposes of through sale or other disposition), it receives the vast majority of royalty in value, i.e., in cash. The question becomes what the proper value of the production is upon which the lessee must calculate the royalty owed. (The royalty rate is applied to the volume and value of the oil or gas produced from the lease to determine the amount of royalty owed. In other words, Volume x Royalty Value x Royalty Rate = Amount Owed. Lessees must pay royalties monthly, with payment due by the end of the month following the production month.)
We generally refer to both public domain and acquired lands as "onshore" lands, to distinguish them from the offshore Outer Continental Shelf (OCS). There are a few additional special categories of onshore lands that are leased under statutes other than the MLA or the Acquired Lands Act. The most prominent example is certain categories of public domain lands that originally were excluded from leasing under the MLA and became available for lease under later statutes. For example, the MLA excluded lands within the National Petroleum Reserve in Alaska (the former Naval Petroleum Reserve No. 4) under 30 U.S.C. § 181 's exclusion of lands within the naval petroleum reserves. Congress made these lands available for lease in 1980 under 42 U.S.C. § 6508. The valuation regulations that apply to production from leases issued under the MLA or the Acquired Lands Act also apply to production from these specialized categories of lands.
The Secretary leases oil and gas deposits underlying the OCS under the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. §§ 1331 et seq., enacted in 1953 and substantially amended in 1978. The OCSLA also requires that the leases provide for a royalty of "not less than 12 %p1/2%p per centum fixed by the Secretary in amount or value of the production saved, removed, or sold." 43 U.S.C. § 1337(a). Though the statute sets a 12 %p1/2%p percent royalty rate as the minimum, most offshore leases not in deep water have a 16 %p2/3%p percent royalty rate. OCS leases yield the substantial majority of oil and gas production from all Federal leases.
Indian tribal lands are leased by the tribes, with the Secretary's approval, under the Indian Mineral Leasing Act (IMLA), 25 U.S.C. §§ 396a-396d , enacted in 1938. Unlike the MLA and the OCSLA, the IMLA does not set a floor royalty rate. Section 396d grants the Secretary the authority to establish the lease terms by rule. See 30 C.F.R. part 211. 3
Indian allotted lands are leased under 25 U.S.C. § 396, enacted in 1909. This very short statutory provision reserves to the Secretary the authority to prescribe the terms upon which leases are to be issued. Like the other mineral leasing statutes, it grants the Secretary general rulemaking authority, which is discussed further below. See 30 C.F.R. part 212. Indian tribal or allottee lessors receive 100 percent of the royalty and other revenues derived from the lease.
II. Key Lease Terms
In addition to the royalty clause required by statute (or, in the case of Indian leases, prescribed by regulation), almost all the leases contain an express term incorporating the Department's regulations, both those in force at the time the lease is issued and those promulgated thereafter. Almost all the leases also expressly reserve to the Secretary the authority and discretion to establish the reasonable value of production for royalty purposes. (These provisions are in different sections of different lease forms, and it is not necessary here to give lengthy citations to the respective sections of successive lease forms.) As a general matter, the Secretary exercises that discretion through rulemaking under the statutory grants of rulemaking authority discussed below.
The reservation of authority to the Secretary to determine the reasonable value of the production on which the lessee must pay royalty is an unusual feature of Federal and Indian leases. Most oil and gas leases entered into between lessees and private lessors do not reserve to the lessor the authority to determine the royalty value of production. The courts have uniformly upheld the Secretary's broad authority and discretion to establish the reasonable value of production for royalty purposes under the statutes, lease terms, and Departmental regulations. 4 However, the MMS does not possess unlimited discretion. Final agency actions -- both rulemakings and administrative adjudications -- are subject to judicial review under the Administrative Procedure Act, 5 U.S.C. §§ 701 -706.
In some of the lease forms used in earlier years, the royalty clause that reserved authority to the Secretary to establish the value of production contained specific valuation language that was substantively identical to the regulations that were in force at the time the lease was issued. Beginning in 1988, the rules were substantially revised. In cases where there is a conflict between specific lease terms and regulations, the lease terms control. Nevertheless, the effect of the lease terms in these earlier forms was not to effectively "freeze" the then-existing rule in place for leases that contained this language. That is because the lease terms gave broad discretion to the agency to establish value, and listed several different factors that the agency should consider (just as the rule did at that time). The more specific regulations that have followed, beginning with the rewriting of the Federal and Indian oil and gas valuation regulations in 1988, provide for measures of value that are within the scope of the broad discretion provided under these earlier lease provisions.
Most Indian tribal and allotted leases contain two terms that are not contained in Federal leases. One is commonly referred to as the "dual accounting" provision. This provision relates only to natural gas. A substantial portion of the gas produced from Federal and Indian leases is so-called "wet" gas, i.e., gas that contains hydrocarbon compounds heavier than methane (e.g., ethane, propane, butane, etc.) that are liquid when extracted from the gas stream. We often refer to these heavier hydrocarbons as "natural gas liquids" (NGLs). When NGLs are present in any significant quantity, the gas stream must be processed to extract the NGLs, which are valuable royalty-bearing products independent of the "dry" residue methane. So-called "dual accounting" provisions require the lessee to calculate the value of the gas produced in two ways. One is the value of the gas stream before processing ("unprocessed" gas). The second is to calculate the value of the residue gas (methane) after processing, plus the combined values of all the extracted NGLs, minus an allowance for the cost of processing that applies against the value of the NGLs. In other words, royalty value of processed gas = residue gas value ± (NGLs value - processing allowance). 5 The lessee must pay royalty on the higher of these two values. (The dual accounting provision in the lease terms was essentially identical to language in the Indian tribal and allotted leasing regulations that were in force until 1996.)
The other lease term that is unique to Indian leases is the so-called "major portion" provision. This clause provides that in the Secretary's discretion, value may be based on the highest price paid or offered for a "major portion" of the oil or gas produced from the field. (The field may underlie more than one lease (including non-Federal and non-Indian properties) or may be entirely within one lease, depending on the circumstances.) The "major portion" value was initially interpreted as the price at which the 50%gth%g percentile by volume plus one unit (thousand cubic feet (Mcf) of gas or barrel of oil) was sold. As discussed further below, the 1988 rules codified this interpretation. Beginning January 1, 2000, the new Indian gas valuation rules redefined the "major portion" as (in substance) the price at which the 75%gth%g percentile of production is sold. The 2000 Indian gas rule also promulgated certain other related changes. The definition of "major portion" is as yet unchanged for crude oil produced from Indian leases.
III. Royalty Valuation Regulations and Key Principles
A. Summary of History and Development
Each of the mineral leasing statutes discussed above grants the Secretary general rulemaking authority to implement its provisions. E.g., 30 U.S.C. § 189 (MLA); 30 U.S.C. § 359 (Acquired Lands Act); 43 U.S.C. § 1334(a) (OCSLA); 25 U.S.C. § 396d (Indian...
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