ROGERS, WELLMAN, AND THE NEW IMPLIED MARKETPLACE COVENANT
| Jurisdiction | United States |
(Sept 2003)
ROGERS, WELLMAN, AND THE NEW IMPLIED MARKETPLACE COVENANT
Eugene Kuntz Professor in Oil, Gas & Natural Resouces
The University of Oklahoma College of Law
Norman, Oklahoma
§ 1.01 Introduction.
§ 1.02 Rogers: Facts, Trial by Jury, and Court of Appeals Ruling.
§ 1.03. Rogers: The Colorado Supreme Court's Opinion and Analysis.[1] The Sound of Silence.[2] Marketability: Undefined in Garman.[3] Marketability: Defined in Rogers.[4] The Erroneous Jury Instruction.
§ 1.04. Wellman: When it rains, it pours.
§ 1.05 Conclusion.
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§ 1.01 Introduction.
In early 2000, I penned a royalty valuation article that contained the following conclusion:
Unfortunately, given the mix of views encountered in the various states concerning royalty valuation standards, we may have arrived at the worst possible result, which is that royalty valuation must be determined on a state-by-state, interest-by-interest, and clause-by-clause basis.1
I now add the phrase "whim-by-whim" to this list. Having studied royalty valuation cases for over 28 years, I can briefly summarize my personal thoughts about many modern royalty valuation cases: although I am seldom surprised, I am often appalled.
Although my views2 on royalty-valuation, like the diverse views of other commentators on royalty valuation,3 have been often ignored or misinterpreted by the
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courts,4 I (and I hope others) remain undeterred in an effort to bring some level of common sense to royalty-valuation law. Oil and gas resources are too strategically important to the future prosperity and security of the United States to leave this policy discussion solely in the hands of jurists. My views, which are similar to those of the Kansas Supreme Court5 and consistent with the traditional common law views of royalty,6 straddle a royalty-valuation fence somewhere between the views of royalty owners and the views of oil and gas operators. Unfortunately, case law in Colorado7 and Texas8 has respectively widened the pastures on each side of this fence. Today's assigned topic is Colorado case law-specifically Rogers v. Westerman Farm Co.9 Current Lease and Royalty Problems in the Gas Industry, 23 TULSA L.J.. 547 (1988); Richard C. Maxwell, Oil and Gas Royalties—A Percentage of What?, 34 ROCKY MTN. MIN. L. INST. 15-1 (1988); Frederick R. Parker, Jr., Costs Deductible by the Lessee in Accounting to Royalty Owners for Production of Oil or Gas, 46 LA. L. REV. 895 (1986); J. Clayton LaGrone, Calculating the Landowner's Royalty, 28 ROCKY MTN. MIN. L. INST. 803 (1982); Charles W. McDermott, Fee Oil and Gas Lease Royalty-Variations and Problems, 28 ROCKY MTN. MIN. L. INST. 1171 (1982); Frank G. Harmon, Gas Royalty-Vela, Middleton, and Weatherford, 33 INST. ON OIL & GAS L. & TAX'N 65 (1982); G.D. Ashabranner, The Oil and Gas Lease Royalty Clause-One-Eighth of What?, 20 ROCKY MTN. MIN. L. INST. 163 (1975); Richard B. Altman & Charles S. Lindberg, Oil and Gas: Non-Operating Oil and Gas Interests' Liability for Post-Production Costs and Expenses, 25 OKLA. L. REV. 363 (1972); Louis A. Fischl, Ascertaining the Value or Price of Gas for Purposes of the Royalty Clause, 21 OKLA. L. REV. 22 (1968); Clyde E. Wilbern, Problems Relating to the Accounting for Gas Royalties, Including Shut-in Royalties, 18 INST. ON OIL & GAS L. & TAX'N 57 (1967); Earl A. Brown, Royalty Clauses in Oil and Gas Leases: Their Nature, Construction and Remedies for Breach Thereof, 16 INST. ON OIL & GAS L. & TAX'N 139 (1965); George Siefkin, Rights of Lessor and Lessee with Respect to Sale of Gas and as to Gas Royalty Provisions, 4 INST. ON OIL & GAS L. & TAX'N 181 (1953).
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§ 1.02 Rogers: Facts, Trial by Jury, and Court of Appeals Ruling.
In a prior article, I observed that the implied covenant to market was growing like Topsy10 and argued that the covenant was not needed to decide basic royalty-valuation issues.11 I did not realize how right my observation would prove to be, but how strongly one court would disagree with my argument. At a time when the Texas Supreme Court was busily shrinking the implied covenant to market in Yzaguirre v. KCS Resources, Inc.,12 the Colorado Supreme Court was busily expanding it in Rogers 13 by requiring the lessee to pay royalty on gas that is in a first-marketable condition and at a first-market location. While typical fee-lease royalty clauses have been (and should be) fairly construed as expressly requiring the former, I submit that the implied covenant to market should not be used for either purpose-especially to mandate that a lessee pay royalty on the gross value of gas delivered to a first-market location that is physically located beyond the immediate vicinity of the well.
In Rogers, certain lessors brought suit against a number of lessees alleging gas royalty underpayments for production from about 200 gas wells. Although there were four variations in the specific royalty language,14 all of the leases at issue provided for royalty valuation "at the well" or "at the mouth of the well."15 The court initially noted that it drew no distinction between these two phrases for purposes of its opinion.16
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The court stated that the gas was "sweet and dry [i.e., free of natural gas liquids] as it emerges from the well."17 However, the gas that was sold away from the wells was dehydrated (i.e., water was removed) to meet pipeline specifications and gathered and compressed to move it into the interstate pipeline connection. Although the opinion is unclear about the location of the compression operations, compression appears to have taken place at the point where the gathering system converged at the "main line."18 The court does not clarify whether the "main line" is the main gathering line or the interstate pipeline. In any event, the facts suggest that the compression occurred at some central point away from the wells. If so, then the compression was primarily for the purpose of moving the gas (i.e., transportation), as opposed to vacuuming the gas up to the wellhead, which latter purpose would have been a production cost. "Some of the gas ... was sold at the well [one wellhead purchaser was unaffiliated with the producers], some was sold at the interstate pipeline [there were two available and used], and some was used 'in-kind' by the lessors."19 Although the fact that some lessors took some gas for their own use may not have been sufficient to establish that the gas was in a "marketable" condition, any actual arm's-length-equivalent sales of significant quantities at the well should have been sufficient to show that the gas was marketable in fact at the well. The court summarized the parties' perspective of the issues as being whether the dehydration, compression, and gathering were costs necessarily and reasonably incurred to put the gas into a first-marketable condition (the lessors' perspective) or were costs incurred to transport already marketable gas away from the well (the lessees' perspective).20
The court reviewed the downstream contracts regarding the gas, noting that the initial contracts (executed in the 1970s) called for the purchaser to take the gas at the wellhead and to assume the costs of gathering, compression, and dehydration. In the 1980s and 1990s, some of these contracts were amended to move the point of sale for some of the gas away from the well—usually to a pipeline connection. The court states that, under these amendments, the buyer contracted with a third party, Yuma, to gather, compress, and dehydrate the gas, and move it to the interstate pipeline. In addition, under some contracts, gas was sold at the well to Yuma, which then gathered, compressed, and dehydrated the gas and then resold it at the interstate pipeline.21
For gas sold at the wells, the lessors were paid their royalty share based upon the proceeds received by their lessees. Lessors argued that this basis for payment was improper, because the gas was not marketable at the well and because the wellhead sales were-at least in some instances-made to affiliates.
For gas sold away from the wells, the lessors were paid their royalty share after a deduction was made for the costs of gathering, compression, and dehydration. Lessors
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argued that these cost deductions were improper because the costs were necessarily incurred to make the gas marketable.22
The case was ultimately tried before a jury. Because the trial court ruled that the leases were silent regarding the allocation of costs, neither testimony nor evidence was presented about the lease language—although the leases were available to the jury during deliberations. The trial court further ruled that the "at the well" and "at the mouth of the well" lease terms were superceded by the implied covenant to market.23 Subject to these rulings, the jury was asked to determine whether the gas was in a marketable condition at the well. Although all gas was apparently of the same quality, the jury found that the gas sold at the well was marketable at the well (thus, royalties paid on such gas were proper), but that the gas sold away from the well was not marketable at the well (thus, the deductions from royalty were improper).24 Not surprisingly, both parties appealed. On appeal, lessees argued that the trial court erred in concluding that "at the well" and "at the mouth of the well" failed to establish the royalty valuation point and further argued that the jury instruction was erroneous in that it included a good-faith assessment. The lessors, in summary, argued that the jury erroneously found that the gas sold at the well was marketable at the well.25
The Colorado Court of Appeals held that the "at the well" and "at the mouth of the well" provisions contractually established the point of valuation for purposes of transportation, and hence the allocation of costs related to...
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