Royalty valuation: Should royalty obligations be determined intrinsically, theoretically, or realistically? Part 1. Why all the fuss? What does history reveal?

Natural Resources Journal

Volumn 37, Issue 3, 1997, Pages 547-610

  Anderson, Owen L ^a  

^a UNIVERSITY OF OKLAHOMA   (United States)

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EID: 26844559873     PISSN: 00280739     EISSN: None     Source Type: Journal    
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References (288)

1. By "typical gas royalty provision," I mean the host of gas royalty clauses that are found in various printed oil and gas lease forms used throughout the country by lessees in acquiring lease rights and that provide for the payment of a royalty in money based upon a fraction or percentage of value or price. Not included in this definition are flat-rate gas royalty clauses, in-kind gas royalty clauses, and gas royalty clauses that are specially drafted on behalf of lessors. Although the focus of this essay is on the gas royalty clause, this essay speaks to oil royalty clauses that call for the payment of royalty in money based upon a fraction or percentage of value or price. Not included are in-kind oil royalty clauses, clauses that specify that royalty is payable on the "posted" field price, or oil royalty clauses drafted specifically by lessors. For a recent discussion of these latter topics, see Gary B. Conine, Crude Oil Royalty Valuation: The Growing Controversy over Posted Prices and Market Value, 43 ROCKY MTN. MIN. L. INST. 18-1 (1997).
2. See generally, Robert S. Raynes, Jr., A Royalty Pain in the Gas: What Costs May Be Properly Deductible from a Gas Royalty Interest?, 98 W. VA. L. REV. 1199 (1996);
3. John S. Lowe, Defining the Royalty Obligation, 49 SMU L.REV. 223 (1996);
4. Susan R. Richardson, Gas Royalties: Issues for the Third Millennium, 47 INST. ON OIL & GAS L. & TAX'N 15-1 (1996);
5. Carroll Martin & Jane Webre, Gas Royalty Issues: Who, What, How and When? Valuation and Payment in Today's Market, 46 INST. ON OIL & GAS L. & TAX'N 2-1 (1995);
6. Maria J. Williams et al., Determining the Lessor's Royalty Share of Post-Production Costs: Is the Implied Covenant to Market the Appropriate Analytical Framework?, 41 ROCKY MTN. MIN. L. INST. 12-1 (1995);
7. Owen L. Anderson, Calculating Royalty: "Costs" Subsequent to Production-"Figures Don't Lie, But . . . .," 33 WASHBURN L.J. 591 (1994) [hereinafter Anderson, Figures Don't Lie];
8. David E. Pierce, Royalty Calculation in a Restructured Gas Market, 13 E. MIN. L. FOUND. PROC. 18-1 (1992);
9. Arthur J. Wright & Carla J. Sharpe, Direct Gas Sales: Royalty Problems for the Producer, 46 OKLA. L. REV. 235 (1993);
10. 1 & 2 Mineral Law Series, FEDERAL AND INDIAN OIL & GAS ROYALTY VALUATION AND MANAGEMENT (1992);
11. James C.T. Hardwick & J. Kevin Hayes, Gas Royalty Issues Arising from Direct Gas Marketing, 43 INST. ON OIL & GAS L. & TAX'N 11-1 (1992);
12. Si M. Bondurant, Royalty Owner Rights Under Division Orders, 25 TULSA L.J. 571 (1990);
13. Kevin L. Sykes, The Royalty Clause: A Guide for the Commoner, 11 EASTERN MIN. L. FOUND. PROC. 22-1 (1990);
14. John S. Lowe, Current Lease and Royalty Problems in the Gas Industry, 23 TULSA L.J. 547 (1988);
15. Richard C. Maxwell, Oil and Gas Royalties - A Percentage of What?, 34 ROCKY MTN. MIN. L. INST. 15-1 (1988);
16. 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);
17. J. Clayton LaGrone, Calculating the Landowner's Royalty, 28 ROCKY MTN. MIN. L. INST. 803 (1982);
18. Charles W. McDermott, Fee Oil and Gas Lease Royalty- Variations and Problems, 28 ROCKY MTN. MIN. L. INST. 1171 (1982);
19. Owen L. Anderson, David v. Goliath: Negotiating the "Lessor's 88" and Representing Lessors and Surface Owners in Oil and Gas Lease Plays, 27B ROCKY MTN. MIN. L. INST. 1029 (1982) [hereinafter Anderson, David v. Goliath];
20. G.D. Ashabranner, The Oil and Gas Lease Royalty Clause - One-Eighth of What?, 20 ROCKY MTN. MIN. L. INST. 163 (1975);
21. 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);
22. Louis A. Fischl, Ascertaining the Value or Price of Gas for Purposes of the Royalty Clause, 21 OKLA. L. REV. 22 (1968);
23. 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);
24. 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);
25. 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).
26. In Part 1, § III, I will focus on the history of royalty provisions from ancient times to the early 20th Century, including early case law and the commentary of traditional legal scholars who have influenced oil and gas case law. In Part 2, the focus will be on more recent royalty case law.
27. Although not the prime focus of this essay, in Part 2, I will also comment on the proper meaning of "market value," "market price," "proceeds," or "amount realized" as these words are used in royalty clauses. Contrary to what some courts have held, I believe these terms were intended to be and should be treated as essentially synonymous.
28. In this regard, I will examine how courts have and should construe the words "at the well* and "free of cost ... in the pipeline" - phrases commonly found in royalty clauses.
29. 3 EUGENE KUNTZ, LAW OF OIL & GAS § 40.5(b) (1989).
30. See, e.g., Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994).
31. Cf., Atlantic Richfield Co. v. California, 262 Cal. Rptr. 683 (Ct. App. 1989) (holding that production ends at the wellhead) with TXO Prod. Corp. v. State ex rel. Comm'r of the Land Office, 903 P.2d 259 (Okla. 1994) (holding that production ends after any necessary compression, dehydration and gathering).
32. See Gulf Oil Corp. v. Reid, 337 S.W.2d 267 (Tex. 1960); Ice Bros. Inc. v. Bannowsky, 840 S.W.2d 57 (Tex. App.-El Paso 1992, no writ); Riley v. Merriwether, 780 S.W.2d 919 (Tex. App.-El Paso 1989, writ denied & reh'g of writ of error overruled); Sellers v. Briedenbach, 300 S.W.2d 178 (Tex. App.-San Antonio 1957, writ ref'd); Holchak v. Clark, 284 S.W.2d 399 (Tex. Civ. App.-San Antonio 1955, writ ref'd); Stanolind Oil & Gas Co. v. Barnhill, 107 S.W.2d 746 (Tex. Civ. App.-Amarillo 1937, writ ref'd).
33. See, e.g., Clifton v. Koontz, 325 S.W.2d 684 (Tex. 1959).
34. Texas Oil & Gas Corp. v. Vela, 429 S.W.2d 866 (Tex. 1968).
35. Exxon Corp. v. Middleton, 613 S.W.2d 240 (Tex. 1981).
36. See Transamerican Natural Gas Co. v. Finklestein, 933 S.W.2d 591 (Tex. App.-San Antonio en banc 1996, writ denied) (holding that royalty is not due on take-or-pay settlement revenues); Hurd Enters. v. Bruni, 828 S.W.2d 101 (Tex. App.-San Antonio 1992, writ denied) (holding that royalty is not due on take-or-pay settlement revenues under the implied covenant to market); Mandell v. Hamman Oil & Ref. Co., 822 S.W.2d 153 (Tex.-Houston [1st Dist.] App. 1991, writ denied) (holding that royalty is not due on take-or-pay settlement revenues under royalty clause allowing lessor to take royalty gas in kind but expressly obligating lessee to use best efforts to obtain the most favorable market for production); Kilam Oil Co. v. Bruni, 806 S.W.2d 264 (Tex.-San Antonio App. 1991, writ denied) (holding that royalty is not due on take-or-pay settlement revenues).
37. Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996) (regarding transportation). Accord, Judice v. Mewbourne Oil Co., 939 S.W.2d 133 (Tex.-San Antonio 1996) (regarding compression costs - companion case to NationsBank that also deals with division orders). As I will explain in Part 2 of this essay, these two decisions, however, may have little, if any, value as precedent.
38. In Phillips Petroleum Co. v. Bynum, 155 F.2d 196, 198 (5th Or. 1946), cert. denied, 323 U.S. 714 (1946), the court used the term "intrinsic value" to describe the value of gas for which there was no established market price at the wellhead.
39. Id.
40. See, e.g., Gard v. Kaiser, 582 P.2d 1311 (Okla. 1978).
41. See Roye Realty & Developing, Inc. v. Watson, No. 76,848, 1996 WL 515714 (Okla. Sept 10, 1996 reh'g denied) (holding that royalty is not due on "take or pay" payments).
42. Tara Petroleum Corp. v. Hughey, 630 P.2d 1269 (Okla. 1981) (construing a gas royalty clause specifying that royalty was payable "at the market price at the well").
43. TXO Prod. Corp. v. State, 903 P.2d 259 (Okla. 1994); Wood v. TXO Prod. Corp., 854 P.2d 880 (Okla. 1992).
44. Smith v. Sun Oil Co., 135 So. 15 (La. 1931).
45. Merritt v. Southwestern Electric Power Co., 499 So.2d 210 (La. App. 1986) (concerning compression costs). But see Wegman v. Cent. Transmission, Inc., 499 So.2d 436 (La. App. 1986) (concerning gathering costs without compression or dehydration).
46. Henry v. Ballard & Cordell Corp., 418 So. 2d 1334 (La. 1982) (holding that lessor has the burden of overcoming the presumption that market price equals contract price). See also Hillard v. Stephens, 637 S.W.2d 581 (Ark. 1982). But see Diamond Shamrock Corp. v. Harris, 681 S.W.2d 317 (Ark. 1984) (holding that contract price did not control where gas beneath a large geographic area was dedicated to a gas contract seven years before the lands were actually leased).
47. Frey v. Amoco Prod. Co., 603 So. 2d 166 (La. 1992) (construing royalty due on "the amount realized at the well from ...[gas] sales").
48. For example, as in Oklahoma (and contrary to Texas), Montana courts seem to have adopted the view that production is satisfied, for purposes of the habendum clause, when a completed gas well is capable of production in paying quantities. Fey v. A.A. Oil Corp., 285 P.2d 578 (Mont. 1955). But, actual production, like Texas (and contrary to Oklahoma), is required in the case of an oil well. Severson v. Barstow, 63 P.2d 1022 (Mont. 1936). And also, as in Texas (and contrary to Oklahoma), Montana courts have held that market-based royalty clauses require that royalty be determined when gas is actually produced at the wellhead and sold, not when the gas sales contract is made. Montana Power Co. v. Kravik, 586 P.2d 298 (Mont. 1978), appeal after remand, 616 P.2d 231 (Mont. 1980).
49. See, e.g., Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994) (stating that, absent language to the contrary, royalty is owed on the value of gas as a first-marketable product).
50. Federal and state oil and gas lease forms are beyond the scope of this article. In addition, detailed royalty clauses found in lease forms drafted on behalf of lessors are largely beyond the scope of this article; however, the basic approach to lessor-drafted clauses should be the same: (1) royalty should be payable on "production;" (2) production is not complete until a "first-marketable product" has been obtained; and (3) express provisions of the royalty clause should govern over the first two general principles. In cases of doubt, however, just as it is appropriate to construe lessee-drafted clauses against the lessee, it is appropriate to construe lessor-drafted clauses against the lessor.
51. Indeed, in many states, the earliest cases are federal decisions that are decided on the basis of what the federal court presumes state law to be.
52. U.S. Industry Under Attack far Alleged Royalty Underpayments, OIL & GAS J., Oct. 28, 1996, at 19-20.
53. See, e.g., Williams et al., supra note 2; Pierce, supra note 2.
54. Anderson, Figures Don't Lie, supra note 2.
55. See, e.g., Atlantic Richfield v. California, 262 Cal. Rptr. 683 (Ct. App. 1989); West v. Alpar, 298 N.W.2d 484 (N.D. 1980). Moreover, during this same time period, there were undoubtedly cases that were settled without a reported decision. I was involved in negotiating one such settlement in 1983, North Dakota v. Gulf Oil Corp., No. A1-81-201 (D.N.D. 1983).
56. Helvering v. Bankline Oil Co., 303 U.S. 362, 366 (1938).
57. Commissioner v. Southwest Exploration Co., 350 U.S. 308, 312 (1956).
58. The Income Tax Law of 1913, Pub. L. No. 63-16, § H.B., 38 Stat. 114, 167.
59. Pub. L. No. 64-271, § 5(a)(8th)(a), 39 Stat. 756, 759.
60. Id. For properties acquired prior to March 1, 1913, the taxpayer was allowed to recover through depletion the fair market value of the asset on that date.
61. Pub. L. No. 65-254, 40 Stat. 1057 (1919).
62. Revenue Act of 1921, Pub. L. No. 67-98, § 214(a)(10), 42 Stat. 227, 241.
63. Revenue Act of 1924, Pub. L. No. 68-176, § 204(c), 43 Stat. 253, 260. This limitation is currently 100%.
64. Pub. L. No. 69-20, § 204(c), 44 Stat. 9. The House had initially proposed a 25% depletion allowance. The Senate defeated efforts to raise the depletion rate to 40%, but passed amendments providing for a 30% rate. Ultimately, the two bodies compromised at 27.5%.
65. Thereafter, percentage depletion was extended to many nonrenewable and renewable resources, although the percentage rates varied. For example, while the percentage rate for oil and gas was set at 27.5%, the rate for coal was set at 5%, the rate for metals at 15%, and the rate for sulfur at 23%. Revenue Act of 1932, Pub. L. No. 72-154, § 114(b)(4), 47 Stat. 169, 203.
66. 26 U.S.C. §§ 612, 613(a), 613A(a)-(c) (1997).
67. Under cost depletion, the taxpayer's deduction is a fraction of the estimated recoverable reserves taken from the adjusted basis in the productive property - a basis which declines due to prior deductions.
68. Subject to several limitations, the intangible drilling cost deduction allows for the immediate deduction (rather than the capitalization) of many costs associated with the drilling of a well, such as construction of road access, preparation of the well site, and expenses incurred in the drilling of a well.
69. The pool of capital doctrine (a doctrine not generally available to taxpayers outside of the oil, gas, and mineral industries) allows two or more taxpayers to contribute money, services, equipment, and property to a drilling venture without treating the transaction as a taxable event.
70. Pub. L. No. 91-172, § 501(a), 83 Stat. 487, 629.
71. Pub. L. No. 94-12, § 501, 89 Stat. 26, 47.
72. 26 U.S.C § 613A (1997). Today, a 22% depletion rate is available for gas sold under qualifying fixed-price, long-term contracts; however, such contracts are largely a thing of the past. 26 U.S.C. § 613A(b)(3)(A) (1997) and 26 C.F.R. § 1.613A-7(d) (1997). In King Ranch, Inc. v. United States, 946 F.2d 35 (5th Cir. 1991), the Fifth Circuit Court of Appeals held that a royalty owner may claim this percentage depletion rate whenever gas is being sold under one of these qualifying contracts, even if royalty is payable on the basis of current market values. Qualifying stripper wells qualify for depletion rates between 15% and 25%, depending on the price of oil. 26 U.S.C. § 613A(c)(6) (1997); Revenue Reconciliation Act of 1990, Pub. L. No. 101-508, § 11.523(a).
73. Pub. L. No. 94-455, 90 Stat. 1520.
74. Tax Reform Act of 1986, Pub. L. No. 99-514, § 412(a), 100 Stat. 2085, 2227.
75. 26 U.S.C. § 57(a)(1) (1997).
76. 26 U.S.C. § 613A(c)(3) (1997).
77. 26 U.S.C. §§ 611-13 (1997); 26 C.F.R. § 1.611-1(b)(1) (1997).
78. For example, in North Dakota, in 1980, due to an initiated measure, total severance taxes on oil increased from 5% to 11.5%. See 1980 N.D. Laws 649, codified at N.D. CENT. CODE ch. 57-51.1 (dealing with the 6.5% oil extraction tax) and N.D. CENT. CODE ch. 57-51 (dealing with the 5% oil and gas production tax).
79. See, e.g., Cannelton Sewer Pipe Co. v. United States, 364 U.S. 76 (1960).
80. Revenue Act of 1926, Pub. L. Ch. 69-20, §§ 204(c)(2), 234(a)(8), 44 Stat. 14, 41; Revenue Act of 1928, Pub. L. Ch. 70-562, §§ 23(1) - (m), 114(b)(3); 26 U.S.C. § 23 (1997).
81. In 1973, the Federal Trade Commission reported as follows: Under this system [of percentage depletion], the major integrated firms have an incentive to seek high crude prices. The high crude prices are, however, a cost to major firms' refineries. Thus, an increase in crude prices implies an increase in crude profits but a decrease in refinery profits. The integrated oil companies gain because the depletion allowance reduces the tax on crude profits, while refinery profits are not subject to the same advantageous depletion deduction. A simple model developed by the FTC suggests that for American integrated firms that typically produce between 40 and 80 percent of their crude needs, it pays to raise crude prices to a point where refinery profits have been reduced to zero.... ... [T]he tax laws have made it highly remunerative for integrated firms to artificially shift profits away from downstream activities toward the crude end of integrated business.... PERMANENT SELECT COMMITTEE ON SMALL BUSINESS, PRELIMINARY FEDERAL TRADE COMM'N STAFF REPORT ON ITS INVESTIGATION OF THE PETROLEUM INDUSTRY, H.R. Doc. No. 96-433, at 21 (1973). This report further concludes: "The depletion allowance worked to encourage vertically integrated firms to report all profits at the crude oil stage rather than at later stages such as refining and marketing." Id. at 29. "[T]he existence of the depletion allowance for crude production means the profits based on high prices at the crude level are 'worth' more to the integrated firm than profits at other levels." Id. at 32. The report called such prices "artificially high." Id. at 44.
82. This statement assumes that producers accounted for royalty and production tax purposes the same as for income tax purposes. See, e.g., Exxon Corp. v. United States, 33 Fed. Cl. 250, 263-64 (1995) (wherein Exxon made the same accounting for both royalty and depletion purposes), rev'd on other grounds, 88 F.3d 968 (Fed. Cir. 1996).
83. The royalty owner and overriding royalty owner can take depletion on their share of the gas. The law requires that the depletion allowance be" apportioned equitably between the lessor and lessee." 26 U.S.C. § 611(a), (b)(1) (1997).
84. The Tax Court recognized this net benefit to lessees in Shamrock Oil & Gas Corp. v. Commissioner, 35 T.C. 979, 1035 (1961), aff'd, 346 F.2d 377 (5th Cir. 1965).
85. The basis and formula for making these calculations vary from lessee to lessee and are given varying treatment by the courts. See generally Anderson, Figures Don't Lie, supra note 2.
86. PRELIMINARY REPORT - DEPLETION - OIL AND GAS REVENUE ACT OF 1926, 69th Cong., 12-13, at 23 (1927) (finding that major oil companies could stifle competition from independents in the downstream processing, transportation, and refining sectors of the oil and gas industry by cutting their profit margins on these sectors and pushing their overall profits upstream).
87. For example, if the lessee makes a wellhead vicinity sale, gross income from the property ordinarily means the price the taxpayer receives for the production even if the sale is to a downstream affiliate at a price that is below the posted field price. See Rev. Rul. 90-62, 1990-2 C.B. 158. Case law, however, has allowed a taxpayer, in such an instance, to claim depletion on the higher posted price. See, e.g., Exxon, 88 F.3d at 977-78.
88. 26 C.F.R. § 1.613-3 (1997). Royalty owners are treated somewhat differently. If a royalty owner is entitled to royalty on downstream values (not wellhead values) or on current market values (not a lower long-term contract price paid to lessee), the royalty owner is entitled to include all royalty as gross income subject to depletion on the theory that all royalty is simply a payment made for the right to develop the lessor's property. In such a case, the lessee's gross income subject to depletion is limited to the difference between the representative market or field price and the royalty paid. In other words, a royalty owner may get a larger share of the total depletion allowance than the royalty percentage suggests. See generally Charles P. McKeon, Tax Phases of Cycling Operations, 4 INST. ON OIL & GAS L. & TAX'N 281, 298 (1953). See, e.g., Mesa Petroleum Co. v. Commissioner, 58 T.C 374 (1972). To illustrate, if a royalty owner is entitled to 12.5% of the downstream value of gas sold for $2.00, the royalty owner would receive 25¢ royalty and could take depletion on the full amount. At a 27.5% depletion rate, the royalty owner could deduct about 7¢ as depletion. However, the lessee would have to calculate the total depletable value of the gas at its representative market or field price. If this value were $1.00, the lessee must subtract the full 25¢ royalty and claim depletion on the remaining 75¢ - about 21¢. In contrast, if a lessor were limited to depletion on the $1.00 representative market or field price, the lessor could claim a depletion deduction of about 3.5¢ and the lessee could claim about 24¢. Thus, from a percentage depletion standpoint, the lessee can "lose" a portion of its fractional share of the depletion allowance if royalty is owed on the gross value of gas after "manufacturing." Accordingly, to maximize percentage depletion benefits for itself, a lessee would not want the royalty obligation to go downstream of the point at which gross income for purposes of depletion is determined. As an aside, "take or pay" payments are also not gross income from the property subject to depletion, 26 U.S.C. §§ 613A(d)(5) and 613(e)(4) (1997), even though, in a few states, royalties are due on "take or pay" payments. And although a portion of settlements for breach of take or pay contracts may be subject to royalty, such payments cannot be included in gross income from the property for purposes of depletion. Cf, Frey v. Amoco Prod. Co., 603 So. 2d 166 (La. 1992) with Rev. Rul. 77-57, 1977-1 C.B. 166. But see Amherst Coal Co. v. United States, 71-1 T.C. 9223, 27 A.F.T.R.2d 71-460 (4th Or. 1971). Regarding stored gas, a lessee must ordinarily pay royalty on the basis of the initial production of gas, even if the gas is reinjected for storage rather than immediately sold. But the lessee must recognize gross income for purposes of depletion in the year of sale, not in the year of production. Rev. Rul. 76-533, 1976-2 C.B. 189; cf., Sondrol v. Placid Oil Co., 23 F.3d 1341 (8th Cir. 1994). In Sondrol, lessors sued the lessee for faling to pay royalties on the value of gas placed in storage. The lessee sold gas at the wellhead to a third-party processor. Under the arrangement, the processor was expected to resell the resulting dry gas and pay the lessee 75% of the sale proceeds, and the lessee, in turn, anticipated paying royalties to the lessor on the proceeds received from the processor. Initially, the processor sold the processed dry gas to a utility; however, in 1983, the utility curtailed its purchases, but did announce that it would continue to take excess gas and place it in storage. Later when the utility refused to pay for the stored gas, the processor transferred the stored gas back to the lessee who resold it at a much lower price. The lessee then paid royalties on the lower resale price. The royalty clause of the lease provided that the lessee would pay lessors "1/6 of the proceeds received for gas sold from each well ... or the market value at the well of such gas used off the premises...." The lessors argued that the lessee should have continued to pay royalty on the stored gas based upon the gross proceeds payable by the utility prior to curtailment.
89. See, e.g., Exxon, 33 Fed. Cl. 250 (holding a representative market or field price may not include value added by transportation and dehydration); see also Consumers Natural Gas Co. v. Commissioner, 78 F.2d 161 (2d Cir. 1935) (concerning gas that was sold to various consumers after piping the gas a distance of one to five miles from the well); Evans v. Commissioner, 11 T.C. 726 (1948) (concerning oil transportation). Because depletion is available to those taxpayers who have an "economic interest" in a producing property (thereby excluding non-producers), a downstream taxpayer who enters into an arm's length contract with a producer to process gas and extract natural gasoline for a share of either the revenues, dry gas, or gasoline is not entitled to depletion because that taxpayer has no economic interest in the producing property. Revenue Act 1926, Pub L. Ch. 69-20, §§ 204(c)(2), 234(a)(8), 44 Stat. 14, 41; Revenue Act 1928, Pub. L. Ch. 70-562, §§ 23(1)-(m), 114(b)(3); 26 U.S.C § 23 (1997); 26 C.F.R. § 1.611-1(b)(1) (1997). See also Rev. Rul. 68-330, 1968-1 C.B. 291 (stating that to qualify for depletion, the taxpayer must have a capital investment in the oil and gas in place; hence, a taxpayer who takes wet gas after it has been produced at the wellhead by another, extracts the liquids, and gives a share of net proceeds to the producer is not entitled to claim percentage depletion); Greensboro Gas Co. v. Commissioner, 79 F.2d 701 (3rd Cir. 1935) (holding that, for depletion purposes, a gas company who both produces and distributes gas to end users via a pipeline must value gas at the well before it is put into the pipeline); Rev. Rul. 75-6, 1975-1 C.B. 178. See, e.g., Helvering v. Bankline Oil Co., 303 U.S. 362 (1938).
90. 26 C.F.R. § 1.613-3 (1997).
91. See, e.g., Brea Canyon Oil Co. v. Commissioner, 77 F.2d 67 (9th Cir. 1935). In this case, the IRS allowed 40% of the gross receipts from the sale of the extracted gasoline to be subject to depletion with the remaining 60% being attributable to manufacturing and not subject to depletion. Id. at 68.
92. See, e.g., Exxon, 88 F.3d 968. In the case of oil, the posted prices for oil in the field usually establish the representative market or field price.
93. See, e.g., Exxon Corp. v. Middleton, 613 S.W.2d 240, 245-46 (Tex. 1981) (comparing 30,000 gas sales contracts covering a substantial portion of the Texas Gulf Coast and concluding that market value equaled the quarterly average of the three highest prices).
94. Id. at 246. See also Shell Oil Co. v. Williams, Inc., 428 So. 2d 798, 802 (La. 1983).
95. See, e.g., Hugoton Prod. Co. v. United States, 349 F.2d 418, 421-26 (Ct. CI. 1965).
96. See, e.g., Scofield v. La Gloria Oil & Gas Co., 268 F.2d 699 (5th Cir. 1959). The "Fiske" method is named for Leland Fiske, former Chief Oil and Gas Engineer for the Dallas Office of the Internal Revenue Service. See generally E. Roy Gilpin, Special Depletion Problems Relating to Gas Production, 12 INST. ON OIL & GAS L. & TAX'N 347, 382 n.43 (1961).
97. Historically, the basic formula subtracts from the downstream sales price the sum of the annual cost of operating the downstream facilities, the annual tax depreciation allowable for such facilities, and an annual return on investment (commonly 20% on the gross investment). See generally McKeon, supra note 65, at 290-91. Because the net sum of this calculation fluctuates with changes in sales prices and with the actual productivity of the plant, averages are established and accepted by the IRS after several years of plant operation. Id.
98. Id.
99. The Fiske method is similar to the work-back method used to calculate gas royalty payments in the common situation where there are no "comparable sales" of gas "at the well." See, e.g., Johnson v. Jernigan, 475 P.2d 396 (Okla. 1970). However, regarding royalty calculations, there is little, if any, credible authority for allowing a lessee to deduct a return on investment, or anything greater than the actual depreciation of the post-production facility over the useful life of the plant, less salvage value. See generally Anderson, Figures Don't Lie, supra note 2.
100. In Exxon Corp. v. United States, 88 F.3d 968 (Fed. Cir. 1996) (holding that value added by transportation and dehydration was not subject to depletion), the Court of Appeals for the Federal Circuit commented as follows on the task of determining a reasonable market or field price (RMFP): [Calculation of the RMFP is a difficult and sometimes onerous task. This difficulty is exacerbated by the fact that the Secretary has declined to promulgate regulations which could provide guidance to taxpayers and the courts. In the absence of such guidance, both the taxpayers and the courts must formulate and evaluate the RMFP based on a common law approach that looks to prior adjudications of depletion allowances. Id. at 976.
101. One critic has argued that the point for determining the gross income from the property should be when the first marketable product has been obtained and should include compression up to the point at which the gas enters the pipeline or a gasoline plant as well as any "processes which the ordinary run-of-the-mill gas operator must perform to establish a marketable product." Richard E. Flint, Gas Compression: Manufacturing, Production, or Marketing, 23 OIL & GAS TAX Q. 233 (1975).
102. See, e.g., Mountain Fuel Supply Co. v. United States., 449 F.2d 816, 822 (10th Cir. 1971); Shamrock Oil & Gas Corp. v. Commissioner, 346 F.2d 377 (5th Cir. 1965). Two cases, however, treat absorption as a production process where the resulting dry gas stream is reinjected into the producing formation for pressure maintenance: Weinert Estate v. Commissioner, 294 F.2d 750 (5th Cir. 1961) and Scofield, 268 F.2d 699. However, the value of the dry gas that is reinjected cannot be included in the gross income from the property. Rev. Rul. 68-665, 1968-2 C.B. 280.
103. Rev. Rul. 75-6, 1975-1 C.B. 178; cf., Louisiana Land & Exploration Co. v. Commissioner, 102 T.C No. 2 (1994) (extraction of sulfur from hydrogen sulfide previously separated from gas was a "mining" process entitling the taxpayer to take percentage depletion on the extracted sulfur).
104. Weinert, 294 F.2d 750; Scofield, 268 F.2d 699.
105. Cycling plants commonly perform initial separation and injection functions - generally regarded as part of production, but they also perform absorption and fractionation functions - generally regarded as manufacturing. The problem of calculating wellhead depletion values where the production is run through a field cycling plant has been explored in detail. Cf. Paul Munter & Don W. Finn, Industry Joint-Product Allocations, 1984-1985, OIL & GAS ACCT. 10-1 (1985) (pointing out that, in evaluating individual sectors of a multi-function facility, an accountant's allocation of costs among the various products in a joint-product facility is generally arbitrary). See generally, McKeon, supra note 65, at 290-9.1.
106. Exxon Corp. v. United States, 88 F.3d 968, 978 (Fed. Cir. 1996).
107. Id.
108. 34 Fed. Reg. 5728-39 (1969).
109. Proposed Regulation § 1.613(a)(2) (1997).
110. Proposed Regulation § 1.613(a)(3)(i)m (1997).
111. 36 Fed. Reg. 19,256 (1971).
112. See, e.g., Cannelton Sewer Pipe Co. v. United States, 364 U.S. 76 (1960).
113. Id. at 89.
114. Id. at 76.
115. See, e.g., United States v. Cherokee Brick & Tile Co., 218 F.2d 424 (5th Cir. 1955) (bricks); Riverton Lime & Stone, Inc. v. Commissioner, 28 T.C. 446 (1957).
116. See, e.g., Monolith Portland Cement Co. v. Riddell, 371 U.S. 537 (1963).
117. 433 F.2d 287 (6th Cir. 1970).
118. 446 F.2d 981 (2d Cir. 1971).
119. 26 C.F.R. § 1.613-4(d)(4)(iv) (1997).
120. Id. § 1.613-4(c)(1) (1997). The calculated price is presumed not to be a "representative market or field price ... if the sum of such price plus the total of all costs of the nonmining processes (including nonmining transportation) which the taxpayer applies to his ore or mineral regularly exceeds the taxpayer's actual sales price of his product." Id. § 1.613-4(c)(6). This limitation is not found in the oil and gas depletion regulations. Cf. Exxon Corp. v. United States, 88 F.3d 968, 972-74 (Fed. Cir. 1996) (reviewing prior case law and concluding that the representative field or market price could exceed a producer's gross income "because of the effects of changing market conditions").
121. 26 C.F.R. § 1.613-4(c) (1997).
122. 26 U.S.C. § 613(c)(2)-(4) (1997). This listing was adopted in 1960 as part of the Public Debt and Tax Rate Extension Act of 1960, Pub. L. No. 86-564. Additional "mining" processes may be added to this list by regulation. 26 U.S.C. §613(c)(4)(I) (1997).
123. 26 U.S.C § 613(c)(2) (1997); see also Rev. Rul. 84-26, 1984-1 C.B. 142; Rev. Rul. 77-457, 1977-2 C.B. 207; Rev. Rul. 73-474, 1973-2 C.B. 201; Ideal Basic Indus., Inc. v. Commissioner, 82 T.C 352 (1984) (holding that in the case of a sale f.o.b. the mine, the seller of ores can treat the entire sales price as gross income from the property); cf. Southwestern Portland Cement Co. v. United States, 435 F.2d 504 (9th Cir. 1970) (illustrating a situation where profit had to be attributed to a particular transportation arrangement). If a broker buys minerals and then resells them, the price the broker pays the miner constitutes the gross income from the property. However, if a broker sells the minerals on behalf of the miner, does not acquire title, and does not guarantee the purchaser's payment, any commission paid to the broker by the miner (although a deductible sales expense) does not need to be deducted in calculating gross income for purposes of depletion. 26 C.F.R. § 1.613(4)(e)(2) (1997); Rev. Rul. 75-115, 1975-1 C.B. 178.
124. 26 CF.R. § 1.613-4(b) (1997). See also Dow Chemical Co. v. Commissioner, 433 F.2d 283 (6th Cir. 1970). See, e.g., Dravo Corp. v. United States, 348 F.2d 542 (Ct. Cl. 1965). Controversies still arise regarding new technologies that did not exist when the list was created. See, e.g., Ranchers Exploration & Development Corp. v. United States, 42 A.F.T.R. 2d 78-5561 (D.N.M. 1978), aff'd, 634 F.2d 487 (10th Cir. 1980) (treating a new process as mining); Rev. Rul. 83-99 (treating the same process as manufacturing).
125. 26 C.F.R. § 1.613-4(g)(2) (1997).
126. 26 C.F.R. § 1.613-4(d) (1997). The formula for calculating proportionate profits is set forth in the regulations as follows: (mining costs / total costs) x gross sales = gross income from mining.
127. 26 C.F.R. § 1.613-4(d)(4) (1997). If the proportionate-profits method is inappropriate, then an alternative calculation method may also be used, e.g., the representative schedule method, 26 C.F.R. § 1.613-4(d)(5) (1997); the comparative prices outside of taxpayer's market method, 26 C.F.R. § 1.613-4(d)(6) (1997); and the rate of return on investment method, 26 C.F.R. § 1.613-4(d)(7) [Reserved]. For a case which discusses several alternative methods, see Portland Cement Co. of Utah v. United States, 338 F.2d 798 (10th Cir. 1964), after remand, 378 F.2d 91 (10th Cir. 1967), after remand, 412 F.2d 894 (10th Cir. 1969), where, under the facts of that particular case, the court rejected the use of a "supply substitute materials" method, i.e., determining gross income from the property by looking at prices received for minerals that could substitute for the taxpayer's mineral in the marketplace.
128. Under this method, the real or constructive sales price of the taxpayer's first marketable product is multiplied by a fraction, the numerator of which is the total mining costs and the denominator of which is the total mining and manufacturing costs. Generally, costs are as determined for tax purposes, although book costs may be used in certain circumstances. Under the alternative rate-of-return method, occasionally permitted where the taxpayer is an integrated miner-manufacturer, a rate of return, to be applied to all mining and manufacturing costs, is determined by dividing the taxpayer's taxable income (before depletion) by the taxpayer's total investment (before depreciation).
129. See, e.g., Hugoton Prod. Co. v. United States, 349 F.2d 418, 426-27 (Ct. Cl. 1965). Because the proportionate-profits method assumes the same percentage of profit for all phases of operations, its use in oil and gas operations would not reflect the greater risk, and hence higher profit, needed for the exploration and production segment of the industry.
130. Dr. Stephen L. McDonald, Professor Emeritus, The University of Texas at Austin, a leading oil and gas economist, responded to my request for a review of my thesis as follows: It is ... obvious that if the royalty base had not been clearly specified in the lease, a dispute is inevitable.... If, for instance, the lessee has some tax reason for transferring profits from one phase in a vertically integrated operation to another, then he might wish to use a royalty base most accommodating to his purposes. It used to be claimed by downstream operations in the oil industry, such as marketing, when operators were entitled to percentage depletion on the market value of extracted oil and gas, that companies deliberately transferred profits from downstream phases to the production phase by artificially raising the transfer price from the latter phase to the next one (refining). To get away with this with the IRS, they would have had to base royalties on the same price. When integrated companies lost the percentage depletion privilege . . ., they would have been motivated to interpret any vague royalty base as being the lower of two alternatives, since they could no longer benefit tax-wise from the higher one. Letter from Dr. Stephen L. McDonald, Professor Emeritus, The University of Texas at Austin, to Owen L. Anderson (January 25, 1996).
131. Anderson, Figures Don't Lie, supra note 2.
132. For discussion of the work-back method, see generally id.
133. A modified proportionate-profits approach would be preferable to the unorthodox work-back approach (which was really a ratemaking approach) taken by the district court in Piney Woods Country Life School v. Shell Oil Co., 539 F. Supp. 957, 963-65 (S.D. Miss. 1982). The court allowed the lessee to deduct all post-wellhead costs plus a 15% rate of return, after taxes, resulting in almost no value for the raw sour gas at the wellhead. This approach recognized no rate of return for the exploration and production operations even though these operations were far riskier.
134. Williams et. al., supra note 2, at 12-4, 12-5.
135. Judicial support for this notion can be found in several cases. See, e.g., Atlantic Richfield Co. v. State, 262 Cal. Rptr. 683, 688 (Ct. App. 1989); Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225, 240 (5th Cir. 1984), cert. denied, 471 U.S. 1005 (1985), aff'd in part, rev'd in part on other grounds, after remand, 905 F.2d 840 (5th Cir. 1990); Wall v. United Gas Pub. Serv. Co., 152 So. 561, 563 (La. 1934).
136. Anderson, David v. Goliath, supra note 2, at 1114-16.
137. Note the distinction here between a "fee simple determinable estate" (which describes both a possessory estate in land and its duration) and the "determinable fee" (used here to describe the duration of a nonpossessory interest). See Shields v. Moffitt, 683 P.2d 530 (Okla. 1984); Discussion Notes, 81 OIL & GAS REV. 159. See generally 2 KUNTZ, supra note 6, § 26.2 at 324-25 (1989).
138. Primary authority (actual contracts, statutes, and decrees) were either not available or available only in a language other than English. Necessarily, I am presuming that these secondary sources and translations are reasonably accurate.
139. Customarily, an additional share (a "tithe") of mineral production was also remitted to monasteries in return for prayers on the miner's behalf.
140. Williams et al., supra note 2, at 12-5.
141. T.A. RICKARD, MAN AND METALS, A HISTORY OF MINING IN RELATION TO THE DEVELOPMENT OF CIVILIZATION (1932).
142. Id. at 370-71.
143. Gold or silver in the lump, as distinguished from coin or manufactured articles; also applied to coined or manufactured gold or silver when considered simply with reference to its value as raw material. 1 THE COMPACT EDITION OF THE OXFORD ENGLISH DICTIONARY 293 (1971).
144. CLYDE PHARR, THE THEODOSIAN CODE AND NOVELS AND THE SIRMONDIAN CONSTITUTIONS, Book X, Title 19 (1952).
145. Augustuses to Cynegius, Praetorian Prefect, given on the third day before the nones of October at Constantinople in the year of the consulship of Richomer and Clearchus, October 5, 384. Id. at 284. Earlier laws levied what appears to be a tax on mining that was payable at a fixed rate. See Emporers Valentinian and Valens Augustuses to Cresconius, Count of Minerals and Mining, given on the fourth day before the ides of December at Paris in the year of the consulship of Valentinian and Valens Augustus, December 10, 365, and Augustuses to Germanianus, Count of the Sacred Imperial Largesses given on the sixth day before the ides of January at Rome in the year of the consulship of Lupicinus and Jovianus, January 8, 367. Id. at 283-84.
146. King Charles III, Mining Law of Spain, Royalty Ordinances for the Director, Regulation, and Government of the Miners of New Spain, Madrid (1783) in 1 JOHN A. ROCKWELL, A COMPILATION OF SPANISH AND MEXICAN LAW, IN RELATION TO MINES, AND TITLES TO REAL ESTATE, IN FORCE IN CALIFORNIA, TEXAS AND NEW MEXICO; AND IN THE TERRITORIES ACQUIRED UNDER THE LOUISIANA AND FLORIDA TREATIES, WHEN ANNEXED TO THE UNITED STATES 49 (1851).
147. Id.
148. Id.
149. Novisima Recopilacion, Vol. iv., p. 366, Title XVIII, Concerning Mines of Gold, Silver, and Other Metals, Law II, Don John I, at Birbisca in the year 1387 (Law 3, tit. 13. Book 6, R.) in 1 ROCKWELL, supra note 123, at 112-13.
150. Law of July 10, 1559, as modified by Philip II in 1584, in 1 ROCKWELL, supra note 123, at 144-47 (emphasis added).
151. Id. (emphasis added).
152. Id. (emphasis added).
153. See generally John C. Lacy, Going with the Current: The Genesis of the Mineral Laws of the United States, 41 ROCKY MTN. MIN. L. INST. 10-1, 10-16 to 10-23 (1995).
154. PEAK DISTRICT MINES HISTORICAL SOCIETY, LEADING MINING IN THE PEAK DISTRICT 10-12 (1968) (emphasis added). One freeing dish held 14 Winchester pints. Id.
155. NELLIE KIRKHAM, DERBYSHIRE LEAD MINING THROUGH THE CENTURIES 32-42 (1968) (emphasis added).
156. The "tithe" is explained as follows: The payment of lead ore tithe was greatly resented by Derbyshire miners. The revolt against this which came to a head in the seventeenth century originated in the previous century. In earlier times lead ore tithe had a religious object, for it had been said with truth that 'tythes were given by the myners for prayers to be made for them evening and morning'. At the Dissolution of the Monasteries in the 1550's laymen became possessed of tithes to a far greater extent than formerly, so that they became a hated tax for which the miner considered he received nothing in return, thus extending his resentment to the clergy. As it was stated at Wirksworth in 1665, when the miner gave the Freeing Dish and paid lot he obtained the right to work his mine, with the right to 'have timber in the King's wastes ... and egress and ingress from the highways to their Groves or Mines'. Cope brought freedom with regard to smelting, so that for all these he received something in return, whereas for tithe he received nothing. Id. at 103-04. From this excerpt, it appears that the tithe (which is not really a "royalty") was payable on net profits.
157. ROBERT R. PENNINGTON, STANNARY LAW: A HISTORY OF THE MINING LAW OF CORNWALL AND DEVON 87-89 (1973) (emphasis added).
158. Id. at 103-06.
159. 1 ROCKWELL, supra note 123, at 558-59 (emphasis added). Although not specifically dated, this commentary was a current analysis of the common law at that time, circa 1850.
160. In the broadest sense, several early cases classified the fixed-price royalty payable for coal as additional purchase money due for the sale of the coal reserves to the miner; these cases gave the lessor/vendor a lien on the coal not mined and removed to secure payment of this purchase price. See, e.g., Manning v. Frazier, 96 Ill. 279 (Ill. 1880); Fairchild v. Fairchild, 9 A. 255 (Pa. 1887); Williamson v. Williamson, 4 S.W.2d 392 (Ky. 1928). On the other hand, where the lessor reserves a portion of the minerals produced, case law has tended to classify the royalty as an "exception" from the grant. See, e.g., Pierce Petroleum Co. v. Empire Gas & Fuel Co., 17 F.2d 758 (5th Cir. 1927).
161. 38 A. 491 (Pa. 1897). My summary of the facts in this case have been somewhat simplified.
162. Id.
163. Id.
164. Id. at 494.
165. Id.
166. Id. at 495.
167. Id.
168. Id. at 494.
169. In cases where the lease provided for the payment of a fixed annual royalty for the balance of a fixed term following the drilling of a well or the opening of a mine, a "reasonable expectation" analysis has also worked to the benefit of a lessee. In these cases, the courts found that the obligation to continue to pay royalty for the balance of the fixed term was implicitly conditioned upon continued production from the well or mine. See also Williams v. Guffey, 35 A. 875 (Pa. 1896). See, e.g., Hewitt Iron Mining Co. v. Dessau Co., 89 N.W. 365 (Mich. 1902) (holding that the specified "minimum" iron royalty was no longer payable once all of the iron had been mined even though the fixed term of the lease had not yet expired); McConnell v. Lawrence Gas Co., 30 Pittsb. L.J. (N.S.) 346 (1890) (holding the continued obligation to pay $500 per year for the balance of the fixed term was conditioned upon an "implied agreement or understanding ... that the well ... be and remain a gas well").
170. One possible exception, which I did not carefully research, is whether there are any cases where the lessee was allowed to deduct a severance tax from a flat-rate royalty. Such cases, however, would most likely turn, at least in part, on the construction of the taxation statute, rather than solely on the construction of the royalty clause.
171. 28 N.J.L. 265 (1860).
172. Id. at 266.
173. Id. at 268.
174. Id. (emphasis added).
175. 61 Cal. 288 (1882).
176. Id. at 290.
177. Id.
178. Id. at 292.
179. See also Poterie Gas Co. v. Poterie, 36 A. 232 (Pa. 1897). Under the lease at issue, the lessee agreed to pay the lessor "1/3 of all the profits realized from oil or gas," found on the premises. The court concluded that the word profits was not equivalent to income, but meant the amount realized from sale of the production after deducting expenses. The case does not indicate whether the court was influenced by the amount of the fraction. See also Paxton v. Benedum-Trees Oil Co., 94 S.E. 472 (W.Va. 1917) (holding that where the lease provided for a 1/8th royalty plus a carried 1/16 working interest, the 1/16th working interest was a net profits interest).
180. 52 P. 1029 (Colo. Ct. App. 1898).
181. Id.
182. Id. at 1029-30.
183. Id. at 1030.
184. Id.
185. Id.
186. Id. (emphasis added).
187. These modern cases will be discussed in Part 2 of this essay.
188. 38 A. 491 (Pa. 1897). Wright is discussed at the beginning of this subsection, supra notes 138-46 and accompanying text.
189. 83 So. 232 (La. 1919).
190. Id. at 233.
191. Id. at 235. Casinghead gas first became commercially important in 1904, and the first compression casinghead gasoline plants were built in the mid-continent in 1909. With the development of the more advanced absorption process in 1917, the extraction of gasoline from casinghead gas became a major segment of the oil and gas industry. This segment declined some in the 1930s when improved refining methods and cracking processes diminished the demand for natural gasoline as a blending agent with refined products. SAMUEL H. GLASSMIRE, LAW OF OIL AND GAS LEASES AND ROYALTIES § 63, at 229 (2d ed. 1938).
192. Wemple, 83 So. at 236.
193. Id. at 237.
194. Id.
195. Id.
196. Id.
197. Id. at 238. In so deciding, the court cited another early casinghead gas case in support of its decision. Locke v. Russell, 84 S.E. 948 (W. Va. 1915) (holding that lessee had properly accounted to the lessor for a share of the "net returns" resulting from the capture of gasoline vapors and was not liable for the flat-rate gas well rental).
198. Wemple, 83 So. at 238.
199. Id.
200. Id.
201. See also, Reynolds v. McMan Oil & Gas Co., 11 S.W.2d 778 (Tex. Comm'n App. 1928); Locke, 84 S.E. 948.
202. Seediscussion of Armstrong v. Skelly Oil Co., infra text accompanying notes 212-20.
203. 211 P. 496 (Okla. 1922).
204. Id. at 497. The dissenting justice referred to this royalty clause as the "usual provision." Id. at 503. This clause was also construed in Hamilton v. Empire Gas & Fuel Co., 230 P. 91 (Kan. 1924) (noting that the lessee had removed water from the oil "in order to render it marketable . . . without cost to [lessor]" and holding that the lessor could not complain about the particular means that the lessee used to measure the oil and to remove water so long as the means are reasonable.)
205. Clark, 211 P. at 499. The term "cut oil" generally refers to an emulsion of oil and water. NORMAN J. HYNE, DICTIONARY OF PETROLEUM EXPLORATION, DRILLING, & PRODUCTION (PennWell 1991).
206. Clark, 211 P. at 499.
207. The third-party purchaser and defendant Slick Oil Co. "were so interlocked that they were under the same general management, occupied the same office, with the same office force, and were headed and directed by practically the same, if not entirely the same, directorate, officials, and office heads." Id. at 507 (supplemental opinion denying a rehearing).
208. As to the oil for which lessor had accepted such settlement, the court held that the lessor had waived his right to have the oil delivered free of cost in the pipeline, but that the lessor was free to demand such delivery in compliance with the lease royalty clause with regard to all oil for which the lessor had not accepted settlement. Id. at 500. Although the case does not appear to involve a formal division order, this case may be the earliest case supporting the notion that a lessor may freely revoke a division order at will.
209. This case is also an early "posted-price" case. After removal of the cut oil, the lessee sold the lessor's royalty oil to an affiliated purchaser at the posted field price; however, at that time, premiums above the posted price were commonly being paid. The court concluded that the lessee's actions constituted conversion and that the lessee should be found liable for the highest market price for the oil so converted between the date of conversion and the verdict. Id. at 502.
210. Although the court refers here to the "plaintiff" lessor, the context of the paragraph clearly indicates that the court was intending to refer to the lessee's duty.
211. Id. at 501 (emphasis added).
212. This point is made by Glassmire in the very same paragraph in which he acknowledges the lessee's duty as determined in Clark to provide tankage for the removal of cut oil so as to make it marketable. GLASSMIRE, supra note 168, § 58, at 219.
213. 18 Ohio C.C. 12 (1898).
214. Id.
215. Id. at 17.
216. Id. at 18.
217. See discussion supra text accompanying notes 157-63.
218. 213 P. 646 (Kan. 1923).
219. Id. at 647. "Rental value of the pipe line built by the defendants was found to be $15,000 per year, and the reasonable transportation charge for transporting gas from the field ... was found to be 7 cents per 1,000 cubic feet."
220. Id. Because the lessor had a right to use part of the gross production of gas for domestic purposes, the court noted that the lessor's right to gas royalty was limited to gas which was both "produced and marketed."
221. 288 S.W. 431 (Tex. Comm'n App. 1926).
222. Id. at 433. Also, pursuant to the contract, the buyer accounted to the lessee and lessor on the same basis for the proceeds of sale of the residue gas. Id.
223. Id. at 431.
224. Id. at 433.
225. Id.
226. 112 P. 965 (Okla. 1910).
227. The nature of the Barton/Laclede agreement is unclear. The court calls the Barton/Laclede transaction a contract. Later, the court refers to the gas being discovered on "the said lease with [Barton]." Id. Thus, Barton appears to be the lessor and Laclede, the lessee; however, it is possible that Barton is a co-lessee or assignor who reserved an overriding royalty.
228. Id.
229. This is also unclear. At one point the court says that Laclede "agreed to sell gas to ... Bellevue." Id. At another point, due to the unfortunate use of a pronoun, it is unclear whether Laclede sold gas to Bellevue at a price based upon in 50% of the resale price, or whether Laclede agreed to pay Bellevue 50% of the ultimate sales price in return for the service of "piping and selling" the gas. Id.
230. Id.
231. Id. at 965-66.
232. This early decision may illustrate a partial misunderstanding of the intent of that portion of the royalty clause calling for royalty on gas "utilized and sold off the premises." Id. at 965. Often gas was not sold or used off the premises. It was often vented, flared, or occasionally used on the leased premises for lease operations. Undoubtedly, Laclede intended that royalty would be payable based upon revenues actually received for gas that was actually marketed (or payable based upon the value of gas used for other than lease operations), less any costs incurred in transporting the gas to a distant market.
233. This change was perhaps made in response to the holding in Barton.
234. Courts have not expressly addressed the question of whether this type of arrangement constitutes a bona fide sale of a marketable product or, in reality, a contract for the performance of a service to make gas marketable (or in some cases, to transport gas to market, or both). Obviously, under this arrangement, a third party was willing to take title to the gas, process it, perhaps transport it, and resell it for a portion of the revenues. Hence, the third party does assume part of the risk of loss of gas and loss of profits - a risk that would not ordinarily be assumed under a pure service contract. Moreover, this practice is so well established that to challenge its bona fides now would disrupt long-settled custom and practice. Nevertheless, apart from executing division orders that may have reflected this arrangement, lessors have not been a party to these contracts. It is likely, however, that some outright arm's-length-equivalent sales of wet gas to gasoline plant operators could be identified which would establish that wet gas is, in fact, a first-marketable product. See, for example, Armstrong v. Skelly Oil Co., 55 F.2d 1066 (5th Cir. 1932), discussed immediately infra.
235. 55 F.2d 1066 (5th Cir. 1932) (applying Texas law).
236. Id. at 1067.
237. Id.
238. Id. The court also noted that the royalty valuation method was the one approved by the Department of the Interior "in dealing with casinghead gas on Indian lands."
239. In a companion case, decided on the same day and rejecting lessor's argument that the lessee had violated the implied covenant to drill additional wells, the court noted that the gas in question was also sour and, due to an
240. Id. at 1068.
241. Id.
242. Id.
243. Of course, there is more recent contrary authority, which will be discussed in Part 2.
244. 255 S.W. 121 (Ky. App. 1923). See also Scott v. Steinberger, discussed supra text accompanying notes 195-97.
245. Id. The italicized words were hand written in a blank on the form.
246. Id.
247. Id.
248. Id.
249. Id.
250. 264 S.W. 830 (Ark. 1924).
251. Id. at 831.
252. Id. at 832. This case also sustained the lessee's practice of meeting demand by ratably producing its wells through periodic shutting in of production so "each one [well] would furnish its proportionate part of the gas used by the industrial consumers." Id.
253. Id.
254. Id. These measures of damages are also found in the Uniform Commercial Code. U.C.C. §§ 2-713(1)-(2), 2-723(2).
255. 264 S.W. at 831-32. At the first of these points, the court refers to this payment as "royalty." Id. at 831. Thus, "owners" must be a reference to other lessors.
256. Id. at 832
257. Id.
258. For analogous case law, see Phillips Petroleum v. Bynum, 155 F.2d 196 (5th Cir. 1946) (holding that market price for gas sold to pipelines is not an appropriate measure of value for gas processed in gasoline extraction plants), and Tara Petroleum Corp. v. Hughey, 630 P.2d 1269 (Okla. 1981) (holding that royalty payable on "market price" may be paid on the contract price for which the particular lessee sold the gas, rather than the spot market price of gas at the time of production).
259. 88S.W.2d989 (Ky.1935).
260. Id. at 990.
261. Id.
262. Id. at 991-92.
263. Accord Reed v. Hackworth, 287 S.W.2d 912 (Ky. App. 1956) (royalty is not owed on sums attributable to the transportation of gas); Rains v. Kentucky Oil Co., 255 S.W. 121 (Ky. 1923).
264. See, e.g., Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225 (5th Cir. 1984), cert. denied, 471 U.S. 1005 (1985).
265. 264 S.W. 830 (Ark. 1924).
266. 88 S.W.2d 989 (Ky. 1935).
267. This view has been espoused by Professor Pierce. See generally Pierce, supra note 2.
268. The actual price paid for gas at the wells was 2.5©. The court, however, awarded royalty based upon a the downstream sales price (10©) less transportation costs (3.5©) for a royalty value of 6.5©. Admittedly, it is uncertain whether the 2.5© price was a bona fide one.
269. See, e.g., Tara Petroleum v. Hughey, 630 P.2d 1269 (Okla. 1981).
270. Under a broad implied covenant to market, perhaps the rule would be that the lessee was implicitly obligated to pay royalty on the greater of the value of the gas at the well (based on comparable sales) or on the actual downstream proceeds of sale less expenses (based on a work-back analysis); however, not even the late Professor Merrill, the leading advocate of implied covenants, suggested this. See generally MAURICE H. MERRILL, COVENANTS IMPLIED IN OIL AND GAS LEASES §§ 84-89 (2d. ed. 1940).
271. See generally, Anderson, Figures Don't Lie, supra note 2; Pierce, supra note 2.
272. MERRILL, supra note 247, § 85.
273. Altman & Lindberg, supra note 2; Williams et al., supra note 2, at 12-16 to 12-25.
274. This principle is so fundamental that contracts scholars only discuss it in the context of whether unforeseen costs may excuse performance under the doctrines of impossibility and impracticability. There is never a suggestion that the other party to the contract is charged with costs. For example, Professor Farnsworth notes that "courts have only occasionally held that a duty is discharged on the ground of mere increase in the expense of performing it. They have generally concluded that the additional expense, even if traceable to an identifiable supervening event, does not rise to the level of impracticability." E. ALLAN FARNSWORTH, CONTRACTS § 9.6 (2d ed. 1990);
275. see also 18 WALTER H.E. JAEGER, WILLISTON ON CONTRACTS § 1963 (3d ed. 1978) ("The fact that by supervening circumstances, performance of a promise is made more difficult and expensive . . . will not excuse the promisor.");
276. ARTHUR LINTON CORBIN, CORBIN ON CONTRACTS § 1333 (1962) ("A supervening discovery of facts that make the promised performance more difficult or expensive..., if they are such as are commonly foreseeable and in contemplation, has almost always been held not to discharge the contractor from his duty.").
277. 3 KUNTZ, supra note 6, § 40.
278. Id. § 40.5(b) (1989) (emphasis added). Kuntz does acknowledge that case decisions "are not all consistent with this analysis." Id.
279. R. HEMINGWAY, THE LAW OF OIL AND GAS § 7.4 (3d ed. 1991) (emphasis added).
280. The late Professor Victor KuIp supports the first-marketable-product view as follows: Sometimes the product must be treated before it is marketable. No part of the expense of doing so is chargeable to the lessor in the absence of a special provision in the lease, although present-day leases divide the expense proportionately to the interest. VICTOR H. KULP, OIL AND GAS RIGHTS § 10.71 (1954).
281. Kulp does not explain how "present-day leases" divide marketing expenses. Messers Lawrence Mills and J. C. Willingham address the lessee's duty to market as follows: The ordinary commercial oil and gas lease, however, provides that the lessee shall deliver, to the credit of the lessor, free of cost, into the pipe line to which he shall connect his wells the equal of one-eighth of all the oil produced and saved from the premises. Gas royalties sometimes follow the same form.... LESSEE'S DUTY TO PUT PRODUCT IN MARKETABLE SHAPE This covenant is held to carry with it a duty to treat the oil or gas and put it in marketable condition for delivery to the pipe line. Otherwise stated, it frequently happens that under great pressure the oil becomes mixed with water or other foreign substance which must be removed in order to make it marketable. It is the duty of the lessee, without expense to the lessor, to treat the oil and remove the water and "U.S." (Basic sediment), so that the pipe line will purchase.... Just how far the doctrine of duty to treat is applicable is an undecided question. Reasoning from the analogy of the duty to drill additional wells it would seem that the lessee could not be required to undertake an entirely unprofitable transaction.... If, on the other hand, the lessee covenants to deliver in tanks at the well or into the pipe line, there is room for argument as to the construction. If he (the lessee) may elect which he will do then he would seem to satisfy his obligation by putting the royalty oil in a tank without treating. If that be correct, then he would, in such a case, be entitled to charge lessor his proportion of the expense of treatment. These questions come up from time to time when a well produces some off-color product unsuitable for market through ordinary channels. Cut oil is one, liquid asphalt another.... Where unusual expense is required, and the contract does not cover the case, if the lessee undertakes to treat his own, it would seem to be his duty to also handle the royalty with a right to reimbursement for a proportionate share of expense.... Oil may be produced at a point remote from a pipe line. By reason of difference in gravity it may not be acceptable to a pipe line otherwise available. Gas may be found at a distance from a gas line; or the pressure may be so low in proportion to that maintained in the line that it cannot be delivered into the line without the erection of a booster station.... Is the lessee bound to market? If so, at whose expense? The implied duty to operate is said to include the duty to market. But this is a matter of reasonable diligence and does not touch the question of expense. It seems reasonable to assume that the lessee is not bound to market at a loss. Nor does it seem reasonable to assume that he is bound to construct a pipe line for many miles or undertake other large outlays of expense merely because a profit can be figured on paper. If there is danger of drainage, he is in duty bound to protect the lines by drilling offset wells, providing it can be done at a profit. So, by analogy, if marketing is necessary to prevent drainage, he is bound to market if it can be done at a profit. Ordinarily in such case the expense would not be excessive. There might, however, be cases of actual or probable drainage where the expense of marketing would be excessive and might or might not be handled at a profit.... It has been held, however, that the lessor is entitled only to his oil or gas or the value thereof at the well and not at some distant market. So, if the lessee constructs a pipe line or deals with another to do so, he is entitled to charge against the lessor his proportion of the reasonable rental value of such line. The lessor, however, is not liable for the cost of such line. Where the lessee undertakes to and does market his own oil or gas by pipe line or tank car, it would seem that he would be bound to take the royalty share along with his own, but is only liable for the reasonable value of the royalty share at the well. L. MILLS & J.C. WILLINGHAM, THE LAW OF OIL AND GAS §§ 126, 129, 130 (1926). This excerpt recognizes a duty to market free of expense to the lessor if the expenses are not excessive. This duty does not include a duty to transport, nor does it include a duty to market a product at a loss. Since no court has ever held that a lessor must proportionately bear expenses incurred in preventing drainage, the authors' analogy to the implied covenant to protect against drainage suggests that the lessee would be required to bear all reasonable expenses necessarily incurred to obtain a first-marketable product if the resulting product could be marketed at a profit.
282. A.W. Walker, Jr., The Nature of the Property Interests Created by an Oil and Gas Lease in Texas, 10 TEX. L. REV. 291, 313 (1932).
283. A.J. THUSS, JR., TEXAS OIL AND GAS § 126 (2d ed. 1935).
284. See supra note 251. Several scholars, with only limited citation to pertinent authority, summarize what they believe to be the governing law on royalty valuation without stating whether they agree with that law. For example, Professor Howard Williams states: A royalty or other nonoperating interest in production is usually subject to a proportionate share of the costs incurred subsequent to production where, as is usually the case, the royalty and nonoperating interest is payable 'at the well'. 3 HOWARD R. WILLIAMS, OIL AND GAS LAW § 645.2 (1995).
285. And in a terms manual, Professor Williams and his co-author, the late Professor Charles Meyers, offer various definitions of the term 'royalty,' including: Although royalty is not subject to the costs of production, usually if is subject to costs incurred after production, e.g., production or gathering taxes, costs of treatment of the product to render it marketable, costs of transportation to market. 8 HOWARD R. WILLIAMS & CHARLES H. MEYERS, OIL AND GAS LAW (MANUAL OF OIL AND GAS TERMS) 971 (1995) (emphasis added).
286. Professor Robert Sullivan recognizes the marketable-product view in his summary of the law regarding the lessee's implied covenant to market oil. The lessee is subject to an implied covenant to market the oil and gas that is produced from the leased premises in order that the lessor may receive his royalty thereon. If the oil is not merchantable, the lessee must prepare it for market, and the lessor is not liable for his proportionate share of the cost in the absence of an appropriate provision in the lease.... Transportation to a distant point where there is no market in the field is not within the purview of this implied covenant, and the lessor must bear the cost of transporting his royalty share of production. ROBERT SULLIVAN, HANDBOOK OF OIL AND GAS LAW § 92 (1955) (emphasis added).
287. Regarding gas, however. Professor Sullivan's summary is less clear: . . . The lease provides for payment of the royalty at the market price, market value, or proceeds at the mouth of the well. Therefore, if the gas must be transported, the lessor must bear his proportionate share of the cost of marketing. It is the price that is actually paid by buyers for the same commodity in the same market, i.e., for the same purpose. Id. § 70. To this point, Professor Sullivan's view seems similar to Professor Merrill's view. Professor Sullivan explicitly recognizes that it is the lessee's duty to make oil merchantable without expense to the lessor, and regarding gas, transportation is the only expense specifically mentioned as a marketing cost to be shared by the lessor. Moreover, he suggests that royalty is to be payable on a "price that is actually paid by buyers for the same commodity in the same market." This language suggests that royalty is to be calculated on gas that is in a marketable condition. Following this statement, however, he then states: It is not necessarily the same as "market value" or "fair market value" or "reasonable worth." Where the market price cannot be established because there are no comparable sales, the actual or intrinsic value can be shown. Where there is no market price at the wells, the jury is permitted to consider every factor that relates to the market value at the well. Where the lessee sells the gas on a long term contract at a fixed price, it is advisable to secure the consent of the lessor. Id. This latter excerpt suggests that gas royalty may be computed by determining its wellhead value without regard to its actual marketability at that point. Because he supports the above statements with citations to cases, Professor Sullivan was most likely summarizing the various views reflected in case law without offering his own opinion on what the general rule should be. Likewise, the late Professor W. L. Summers reports: Most courts hold that the lessor's royalty should be computed upon the basis of the market value of the gas in the field, if such market value actually exists, and if it does not, upon the basis of the reasonable value of such gas as established by competent evidence. 3A W.L. SUMMERS, THE LAW OF OIL AND GAS § 589 (1958) (emphasis added).
288. See also EARL A. BROWN, THE LAW OF OIL AND GAS LEASES §§ 6.03-.05 (1958); GLASSMIRE, supra note 171, §§ 58-59, 62-63.