FEDERAL OVERRIDING ROYALTY LITIGATION: SHOULD COURTS USE AN “INTENT SEEKING” OR AN “IMPLIED COVENANT” APPROACH?
| Jurisdiction | United States |
Carver Kirchhoff Schwarz McNab & Bailey, LLC
Denver, Colorado
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I. INTRODUCTION
A. The High Tide of Royalty Litigation
Since at least the mid-1970s, litigation over royalty payments on oil and gas production has escalated as royalty holders have challenged the payments energy producers have made to them.2 Courts have taken a more active role in policing the terms of the contracts -- mineral leases and lease assignments -- that give rise to royalty payment obligations.
Even though a sizeable portion of domestic energy production flows from the federally-owned lands, little royalty litigation to date has involved them -- suggesting that litigation in this area may escalate. Royalties from federal energy production flow to two kinds of recipients: government entities (primarily the federal government, but also Indian tribes, and states who share in the revenue stream) and private overriding royalty owners. Just two published decisions have addressed the issues surrounding royalty payments made to these private royalty holders from federal leases. The first decision to do so, Garman v. Conoco,3 was a watershed case leading to the development of the "implied covenant to market" as the dominant legal interpretation of royalty obligations in Colorado. The second decision, Followwill v. Merit Energy Co.,4 confined itself to traditional tools of contract interpretation and did not cite or follow Garman. This article examines the marked contrast between the reasoning and analysis of the two decisions, and suggests that the Followwill approach may be better suited to resolving royalty disputes that arise from the federal leasehold.
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To review the larger context surrounding these decisions, royalty litigation generally involves challenges to certain deductions from the total amount used to calculate royalties that energy producers frequently take in order to account for the costs of processing gas and bringing it to market. The royalty payment, whether to a lessor or an overriding royalty holder, is generally some fixed percentage of this value.5 What is disputed is how to determine the denominator in the percentage.6 In general, royalties are to be paid free of the costs of production, but this simple generality hides a wealth of complexity. As gas moves from wellhead to burner tip, the producer or downstream marketer incurs costs, and it is frequently unclear at what point the parties agreed to place a value on the gas to be used in calculating royalties and what costs count towards this value. Further complicating the situation is the fact that the design of the process is generally driven by engineering concerns rather than a desire to create streamlined accounting of discrete cost categories.
One case in particular has come to represent the high water mark of this controversy. Rogers v. Westerman Farms,7 which followed the Garman analysis, held that standard language defining royalties with reference to "market value at the well" or similar terms was "silent with respect to the allocation of costs," thus necessitating use of the implied covenant to market to define the royalty obligation.8 Further, the Court held that the covenant to market was not necessarily discharged when the producer brought the gas to the point of sale. The effect of this holding was to require the producer to bear all of the costs of processing required to make the gas marketable on an established commercial marketplace, and to deduct none of these costs before applying the royalty percentage. What surprised many commentators about Rogers is that the language at issue had previously been considered clear enough to sustain several decades of commercial practice and numerous judicial interpretations.9 Rogers thus provoked intense discussion concerning whether and when a court may
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substitute a generally-applicable rule or covenant in place of express contractual language (or other evidence of the intent of the parties) to resolve a royalty dispute.10
B. Background: Royalty Payments on the Federal Leasehold
The federal lands that are the source of much of the nation's energy production are generally administered by the Bureau of Land Management ("BLM"). Another agency within the Department of the Interior, the Minerals Management Service ("MMS"), generally regulates royalties flowing from these lands. Royalties paid on federal production generally include a 12.5% royalty payable to the federal government or the Indian tribe on whose lands the well is located, and which is usually shared in some proportion with the local state government. A smaller payment is often made to private parties in the form of overriding royalties. Overriding royalties are often reserved by transferors of the lease in consideration for the transfer from one lessee to another. For most of the time that the leasing scheme has existed, the BLM standard-form lease agreement capped overriding royalties at no more than 5% of the value of production.11 As some of these leases were transferred from lessee to lessee over time, tens or hundreds of overriding royalty holders could end up sharing this small percentage, complicating the producer's task in computing and paying the royalties.
The BLM standard lease form also contains an express provision stating that it is governed by the Mineral Leasing Act and other federal statutes. The lease form also provides that royalties are to be computed as per MMS regulations. An older BLM form, still frequently found in circulation, defined the royalty obligation owed to the federal government with express reference to the MMS regulations:
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[t]o pay the lessor 12 ½ percent royalty on the production removed or sold from the leased lands computed in accordance with the Oil and Gas Operating Regulations.12
Note that this language does not include the phrase "market value at the well" or "at the wellhead," which is in general use in private mineral leases.
As to the overriding royalty, these are generally created through use of another BLM form used to assign federal leases. Parties merely "fill in the blanks" on a designated space in the standard assignment form to create the overriding royalty obligation -- or, more often than not, leave this part of the form blank except for the bare percentage to be applied. The MMS has developed extensive and complex regulations that define the royalty payment owing from the lessee to the federal government. None of these regulations expressly address overriding royalties, thus leaving open the question of what method is intended to control overriding royalty payments where the parties' choice is less than clear.
Until Followwill, Garman was the sole published opinion to consider the question of whether the federal statutes and regulations are relevant to private overriding royalties. Garman concluded, in a footnote, that they are not.13 Against this background, it was therefore significant that Followwill reached the opposite conclusion, holding based on construction of the leases and lease assignments at issue that the parties had selected federal law, and the MMS royalty calculation method, and had opted out of Wyoming state-law rules of royalty calculation set forth in a Wyoming statute, the Wyoming Royalty Payment Act ("WRPA").14
However, the most remarkable fact about the Followwill opinion is that it was an unremarkable contract analysis, involving thoroughly familiar tools of contract interpretation -- reminiscent of Sherlock Holmes's
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observation that the fact that a dog did not bark on a certain night was the most significant fact about a case.15 Followwill suggests that courts should pause, particularly where production from the federal leasehold is concerned, before abandoning attempts to construe contract language in favor of implied covenants or other default substantive rules.
II. Followwill and the Wyoming Royalty Payment Act
A. The Litigation
Followwill involved plaintiff overriding royalty holders who appeared early in the chain of title beginning with the original lessees of several federal oil and gas leases leading up to the more recent lessees, who were defendants in the litigation. The plaintiffs claimed that their successors in title had taken improper deductions from the value of production before applying the overriding royalty percentage in computing the payments due them. Their claims rested on Wyoming state law, and primarily upon WRPA. The defendants asserted they had properly calculated and paid royalties using the federal method of computation.
WRPA defines an "overriding royalty" as "a share of production, free of all costs of production, carved out of the lessee's interest under an oil and gas lease."16 WRPA defines the "costs of production" referenced in this definition as:
All costs incurred for exploration, development, primary or enhanced recovery and abandonment operations including, but not limited to lease acquisition, drilling and completion, pumping or lifting, recycling, gathering, compressing, pressurizing, heater treating, dehydrating, separating, storing or transporting ... the gas into the market pipeline.17
In this language, a legislature thoroughly familiar with energy production exhaustively enumerated every conceivable process that could be applied to natural gas in the field and prohibited deduction of the associated cost.18
The statute also requires monthly reporting of royalty payments, with monthly penalties for false reporting19 and penalty interest on overdue
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payment obligations.20 With these provisions working together, systemic errors in calculating a royalty quickly translate to...
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