CHAPTER 7 SHOOTING THE RAPIDS WITHOUT GOING OVER THE BRINK: THE "WHERE'S" AND "HOW'S" OF GAS ROYALTY VALUATION
| Jurisdiction | United States |
(Sept 2003)
SHOOTING THE RAPIDS WITHOUT GOING OVER THE BRINK: THE "WHERE'S" AND "HOW'S" OF GAS ROYALTY VALUATION
University of Wyoming College of Law
Laramie, Wyoming
[I] INTRODUCTION: THE IMPORTANCE OF IDENTIFYING THE "LOCATION" AND METHOD OF GAS ROYALTY VALUATION
The challenge of determining where and how gas1 should be valued for purposes of royalty calculation is not a new one. Lessors and lessees, and courts and commentators, have grappled for decades with the legal and factual complexities pertaining to the location and method of gas valuation.2 Perhaps the most valuable lesson to derive from those who have long-
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debated this issue is: There is no "right" answer.3 As Professor David Pierce's "royalty theorem" succinctly illustrates, "there will never be peace - under the oil and gas lease,"4 because "when compensation under a contract is based upon a set percentage of the value of something, there will be a tendency by each party to either minimize or maximize the value."5 Even courts cannot agree on how to resolve the lessors' and lessees' valuation tug-o-war. Some judicial approaches operate to the benefit of lessors, some to the benefit of lessees;6 some approaches reflect present market realities, some evolved from prior, highly regulated markets;7 some approaches focus on the lease itself, some employ the law of implied covenants to correct
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perceived inequities in the lease contract.8
This paper illustrates how the royalty valuation process is akin to putting your raft in at the wellhead and negotiating a series of rapids as the gas moves downstream toward the burner tip: it identifies where the rapids are located, explains the most common valuation "maneuvers," and examines "navigation" strategies from both the lessor's and lessee's perspectives. Knowing the downstream course, understanding its obstacles, and identifying your "best line" is important, because where and how you run that course will most definitely affect the bottom line.9
[II] BACKGROUND
The lease royalty clause determines the compensation to be paid to the lessor once production is obtained. Under common law, the lessor's royalty interest attaches to the produced mineral at the wellhead in its natural state. Thus, the wellhead specifies both the location and the quality of the mineral to be valued for royalty calculation purposes.10 Unfortunately, this simple common law principle does not readily translate to the calculation of gas royalties.11 Due to its physical and economic attributes, and the modern, deregulated market, gas often is sold "downstream" from the well after it has been cleaned, dehydrated, processed and compressed.
Royalty disputes arise because instead of providing the lessor with his royalty share "in-kind" or calculating the royalty based on an arm's length sale at the well, the gas royally must be calculated based on a hypothetical "market value" or a downstream sale price. The two key questions then presented are: (1) Where: at what location should the gas be valued for royalty calculation purposes? and (2) How: to what extent may the producer deduct processing and
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other post-production costs when calculating the lessor's royalty; and, if costs can be deducted to calculate royalty, what constitutes a reasonable cost?
The lease itself may answer these questions if the royalty clause specifies the point of valuation and/or enumerates which, if any, downstream costs the lessee may deduct. However, if the royalty clause does not specify location or deductible downstream costs, or is ambiguous in its treatment of these issues, the resolution of a gas royalty dispute will turn on the judicial interpretation of lease terms, the implied covenant to market, and possibly, the application of state statutes. Metaphorically speaking, express lease language may ensure calm waters. More often, however, modern market realities, lease language, the courts, and state legislatures impose royalty valuation eddies that require careful downstream navigation.
[A] Modern Gas Marketing Realities
Historically, the federal government strictly regulated the natural gas market by controlling prices, sales, and interstate pipeline services.12 Most gas sales under the federal regulatory regime of the 1950s through the 1980s took place at or near the well. As Professor Pierce described,
The producer would typically transfer title to the gas, in a sales transaction in the field where produced, to the interstate pipeline company. The pipeline company would then move the gas downstream to the point where it was resold to an end- user or a local distribution company.13
Today's industry is no longer characterized by the lessee's delivery and transfer of title to the gas from a dedicated property to a particular purchaser, at or near the place where it is produced, under a long-term contract. In the aftermath of deregulation in the mid-1980s, producers actively began to engage in downstream marketing efforts. Now a producer may sell its gas in the field, or it may market or transport production as a "package" at a downstream market center or "hub." Moreover, most sales are monthly or otherwise short-term.
The fact that today's natural gas market permits the producer to sell gas at the wellhead, the "burner tip," or any point in between has increased the potential for and complexity of royalty valuation disputes.14 Lessees assume a variety of traditional and entrepreneurial
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marketing roles. They also employ a variety of valuation methods. For example, some lessees pay royalty based on the gas sales price, adjusted for transportation and marketing costs, regardless of whether the royalty clauses specify "market value" or "amount realized."15 Other lessees use a current "index" price or an average price at a market hub to determine "market value."16 Yet others attempt to determine the price in the field where production occurs or use a combination of methods. This variation only heightens the challenge of successfully navigating the valuation course and further highlights the importance of understanding the legal underpinnings of where and how the base royalty should be calculated.
[B] The "Where's": The Wellhead? Downstream?
Lessees want to locate the royalty valuation point as close to the wellhead as possible. Their objective, framed by common law royalty principles, is to pay gas royalties only on the value of the gas when and where it is extracted, and to avoid having to share with lessors the benefits of any downstream processing, aggregating, packaging or marketing investment which increases the gas value.17 Lessors, seeking a share of any enhanced gas value as a result of post- extraction investment, want to locate the royalty valuation point as far downstream from the wellhead as possible.18
Given these competing objectives, you had better identify the point at which gas is likely to be valued under any given lease before you even put the raft in. If the valuation is to occur at the wellhead, you may avoid getting wet altogether. If gas is to be valued on-lease or in the field, you could expect a short, dry trip. However, if the valuation point is the pipeline, the processing plant or some other downstream location, the turbulents could be many and varied, and the trip could be a wet and wild one.
[1] Lease Language Specifying Location
The lease often will specify the location at which gas should be valued for royalty calculation purposes. For example, a "typical" gas royalty clause may provide for valuation at the wellhead:
[O]n gas, including casinghead gas, condensate and other gaseous substances, produced from said land and sold or used off the premises or for the extraction of gasoline or other products therefrom, the market value at the well of one eighth of the gas so sold or used, provided that on gas sold at the well the royalty shall be
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one eighth of the amount realized from such sale.19
Alternatively, the royalty clause might provide for valuation at a point downstream from the wellhead:
In case lessee shall itself use gas in the manufacture of gasoline or other petroleum products therefrom, 1/8 of the sale price at the plant of the gasoline or other petroleum products manufactured or extracted therefrom and which are saved and marketed, after deducting a fair and reasonable cost for extracting or manufacturing said gasoline or other substance, and 1/8 of the market value of residue gas sold or used by lessee in operations not connected with the land herein leased.20
Lessees have argued, with some success, that when the lease specifies the royalty valuation point, as illustrated above, courts should give effect to such express language.21 This result provides the security of a river guide who can steer the raft to the put out point without getting the passengers too wet or drifting too far downstream.
A large snag lies just beneath the surface of such express lease provisions, however. Employing rules of construction favoring lessors, and/or the implied covenant to market,22 some courts have deemed lease language identifying a royalty valuation point to be nondeterminative.23 In resolving the valuation dispute, these courts (known as the "first marketable product jurisdictions")24 proceed to specify the royalty valuation point as the point at
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which gas can first be characterized as a marketable product. Issues related to the difficulty in identifying the point at which gas first becomes a marketable product are discussed in section III.B.
[2] Ambiguous or No Lease Language Specifying Location
Occasionally the royalty clause truly is silent or ambiguous regarding the valuation location. For instance, the royalty may be "described as a share of the 'proceeds' of production without a clear specification as to whether proceeds...
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