Issues » Comments on Rules and Regulations

Appendix C

THE ROYALTY BARGAIN
by John S. Lowe, George W. Hutchison Professor of Energy Law

January 28, 2000

1. Introduction

My name is John S. Lowe. I am currently the George W. Hutchison Professor of Energy Law at Southern Methodist University. I have worked as a law professor teaching and writing about oil and gas law for more than 25 years at SMU, the University of Tulsa, and the University of Toledo. I have been a Visiting Professor at the University of Texas, a Distinguished Visiting Professor at the University of Denver, and the Visiting Judge Leon Karelitz Chair in Oil and Gas Law at the University of New Mexico. I hold a B.A. in economics from Denison University and an LL.B. from Harvard University. I am admitted to practice law in Ohio, Oklahoma and Texas.

I am a Past Chair of the Section of Natural Resources, Energy and Environmental Law of the American Bar Association, a 13,000-member professional organization. I have served as Secretary and as a member of the Executive Committee of the Rocky Mountain Mineral Law Foundation; I am currently a Trustee of that organization. I am Treasurer of the Advisory Board of the International Oil and Gas Educational Center of the Southwestern Legal Foundation. I am a former Member of the Council of the Oil, Gas and Mineral Law Section of the State Bar of Texas. I have been honored by the National Association of Royalty Owners for service to its members.

I have written extensively about oil and gas law, including the royalty obligation. I am the author of Oil and Gas Law in a Nutshell (West 3d ed. 1995). I am one of the editors (with E. Kuntz, O. Anderson, E. Smith and D. Pierce) of Cases and Materials on Oil and Gas Law (West 3d ed. 1998), which is the most widely used law school casebook on the subject. I am Maintenance Editor of two major oil and gas law treatises, Summers’ Oil and Gas Law and Kuntz’ Law of Oil and Gas, as well as the author of volumes 6, 7 and 7A of West’s Texas Forms (3d ed. 1997) and the Minerals, Oil and Gas section of Vol. 28 of West’s Legal Forms (3d ed. 1997). I am one of the Editors of the Oil and Gas Reporter, Matthew Bender's monthly publication. I have written many law journal articles that address royalty issues, including Developments in Non-Regulatory Oil and Gas Law, 32nd Oil and Gas Inst. 117 (Matthew Bender 1981); Developments in Non-Regulatory Oil and Gas Law: The Issues of the Eighties, 35th Oil & Gas Inst. 1 (Matthew Bender 1984); Current Lease and Royalty Problems in the Gas Industry, 23 Tulsa L.J. 547 (1988); Defining the Royalty Obligation, 49 SMU L.J. 223 (1996); and Royalty Calculation in Texas, 50^th Oil and Gas Inst. Appendix Ch. 3 (Matthew Bender1999).

I am familiar with and understand the development of the law and custom and usage relating to royalties. I also have an opinion of the common understanding of those principles by people in the oil and gas industry, based on thousands of conversations with landmen, lease administrators, division order analysts, and lawyers for oil companies and royalty owners.

I have been solicited by the American Petroleum Institute to comment upon the Proposed Rules published by the Minerals Management Service at 64 Fed.Reg.73820 (December 30, 1999) in light of the history and nature of the royalty bargain. The opinions that I express are my own and not necessarily those of Southern Methodist University or the Hutchison Endowment. My opinions are based upon my 30 years experience in the oil and gas industry as a lawyer and a law professor, as well as the sources that I reference.

2. A Short History of Royalty

The economic function of a royalty is to hedge against uncertainty. When parties can determine with certainty the quantity and value of things that they wish to buy or sell, they probably will fix a lump sum or a unit price. In the case of oil and gas, however, the existence of the substance – let alone the quantity, quality and price – is uncertain. Common practice in the oil and gas industry, as well as other extractive industries, therefore, is that a major part of the compensation of leasing mineral owners is in the form of a royalty – a portion of production or its value that is delivered or paid free of the costs of production as oil or gas is produced. If production is prolific, the royalty owner benefits and the lessee is burdened more than if production is slight.

The term "royalty" derives from the feudal system in England, where the term was developed to distinguish the share of production reserved by the Crown from the production rights of those granted the right to work mines and quarries to develop minerals owned by the Crown. See Taylor v. Peck, 116 N.E.2d 417, 418 (Ohio 1953); See also Samuel H. Glassmire, Law of Oil and Gas Leases and Royalties Û 10, at 55 -56 (1935); Harriet S. Daggett, Mineral Rights in Louisiana 247 (1949). "Royalty" was also used in feudal England in the context of landlord/tenant relations. Feudal lords received title to land directly from the Crown on the condition that they would render future services. The lords in turn permitted their tenants to cultivate the land in return for a share of the products of the tenants’ efforts. Feudal tenants held only a "working interest" in land, producing crops at their own labor and expense. The share of the products given to landlords by tenants was termed "royalty" since it was the portion accruing to the landowners as a result of the royal grant or favor.

The modern oil and gas lease, which conveys the right to develop minerals and provides for a concomitant royalty to the mineral owner, evolved over the years from forms used to brine water (from which salt was extracted), which in turn developed from solid minerals mining leases. See generally Lesley Moses, The Evolution and Development of the Oil and Gas Lease, 2 Oil & Gas Inst. 1 (1951).

1. Royalty is due "at the well," not on downstream entrepreneurship

Historically, the royalty bargain has been that the royalty owner receives a fractional part of the production or production revenues "at the well," where the product from which the royalty is paid comes into being. Royalty has excluded value added by the lessee’s entrepreneurship activities "downstream" – away from the lease.

The practice has a long history. In the Middle Ages, when the Crown enfeoffed feudal lords, the King retained a "royalty" right to take gold or silver that might be found in the lands he had conveyed. When the King alienated the right to mine, he typically reserved part of all the ore to be delivered "on top of the ground free of charge," which was also called "royalty." A.J. Thuss, Jr., Texas Oil and Gas Û 117 at 156 (2d ed. 1935). When King Charles II granted the colony of Pennsylvania to William Penn in 1681, the royal patent reserved "one-fifth of all the gold and silver discovered in the region." Samuel H. Glassmire, Law of Oil and Gas Leases and Royalties Û 10, at 55 -56 (1935). The civil law embodied a similar concept. Spanish law recognized the dominio radical – literally the King’s "root ownership"of minerals contained in the soil of the lands of his subjects. The right derived from the Mining Ordinance of 1783, which listed royal minerals, set out a procedure by which subjects could produce them, and authorized a royalty to the King called the derecho del quinto ("the tax of the fifth part"). Walace Hawkins, El Sal del Rey 9 (1947).

In the United States, royalty clauses in private-lands oil and gas leases have used terms like "market value," "amount realized," and "market price" to describe a royalty at the production point, before the lessee has applied its entrepreneurship to enhance value by transporting, processing or marketing. See, e.g., Curtis M. Oakes, Benoit's Oil and Gas Forms 7 (2d ed. 1939) ("To pay lessor . . . the equal one-eighth (1/8) of the gross proceeds at the prevailing market rate"), quoting Producers' 88 Standard Lease Form; Samuel H. Glassmire, Law of Oil and Gas Leases and Royalties Û 10, at 28 (1935) ("one-eighth of the gross proceeds of the gas at the prevailing market rate"); Richard L. Benoit, Cyclopedia of Oil and Gas Forms 171 (1926) ("one-eighth of the net proceeds, based on the market or selling price at the well"). See also Wall v. United Gas Pub. Serv. Co., 152 So. 561, 562 (La. 1934) ("one-eighth (1/8) of the value of such gas calculated at the market price per thousand feet"); George Siefkin, Rights of Lessor and Lessee with Respect to Sale of Gas and as to Gas Royalty Provisions, 4 Oil & Gas Inst. 181, 214 (1953) ("the equal one-eighth (1/8) of the gross proceeds at the prevailing market rate, for gas used off the premises") (emphasis in original), discussing the royalty clause in a typical Kansas lease.

American courts frequently have recognized directly that a lessee is entitled to entrepreneurial uses of production without sharing benefits with the royalty owner. In Wilkins v. Nelson, 99 So. 607 (La. 1924), the Louisiana Supreme Court denied a royalty owner's claim to a share of gasoline revenues where gasoline was extracted from a well producing only gas and the lease provided for a flat rental for gas. In Phillips Petroleum Co. v. Record, 146 F.2d 485 (5th Cir. 1944), and Phillips Petroleum Co. v. Ochsner, 146 F.2d 138 (5th Cir. 1944), the Fifth Circuit held that "market value at the well" royalty was based on the value of the gas at the well despite the fact that the lessee actually exchanged the gas produced with another who used the gas to generate heat and light, uses that commanded a higher price but which had no established market at the well. The court noted that the "Lessee . . . received the gas as owner under its lease, and it was obligated to pay appellee the market value at the well, no more and no less, and this without regard to the use made of it. Id. at 141. In Sowell v. Natural Gas Pipeline Co. of America, 789 F.2d 1151 5th Cir. 1986), the court held that gas royalties based on the average market price being paid for gas in a six-county area were paid for all of the constituents of that gas, including gas liquids collected in "drip pots" between the wellhead, the metering station and the processing plant. The court reasoned that, because production triggered the obligation to pay royalty, the rights and obligations of the parties should be assessed at the wellhead. Carter v. Exxon Corp., 842 S.W.2d 393 (Tex. App.-- Eastland 1992, writ denied), held that a lease calling for royalty based upon "market value at the well" did not permit the royalty owner to share in revenues generated by the lessee in manufacturing liquid products downstream from the well because "at the well" required royalty to be determined on "gas that is produced in its natural state, not on the components of the gas that are later extracted." Id at 397.

Case law recognizes that royalty is due at the well, rather than downstream, even when the lease does not stipulate that the calculation is "at the well." Wall v. United Gas Public Service Co., 152 So. 561 (La. 1934), is the classic case. In Wall the relevant lease royalty clause provided that when gas was sold or used off the premises, "the grantor shall be paid one-eighth (1/8) of the value of such gas calculated at the market price . . . ." Id. at 562. Gas from the well was transported about two miles and sold, along with gasoline extracted from the gas stream, for 5.8 cents per MCF. The lessees paid royalty based upon the market price of the gas at the well, approximately four cents per MCF. The lessors sued, contending that royalty should be based upon the price for which the gas was sold off the lease after transportation. The Louisiana Supreme Court ruled in favor of the lessee, reasoning that "the parties intended that, if there was a market for gas in the field, the current market price there should be paid. There is where the gas was reduced to possession and there is where ownership of it sprang into existence." Id. at 563. The royalty obligation does not extend to downstream entrepreneurial functions of the lessee. See also Sartor v. United Carbon Co., 163 So. 103 (La. 1935); Sowell v. Natural Gas Pipeline Co. of Am., 789 F.2d 1151 (5th Cir. 1986); Phillips Petroleum Co. v. Record, 146 F.2d 485 (5th Cir. 1944); Phillips Petroleum Co. v. Ochsner, 146 F.2d 138 (5th Cir. 1944); Danciger Oil & Ref., Inc. v. Hamill Drilling Co., 141 Tex. 153, 171 S.W.2d 321 (1943); Scott Paper Co. v. Taslog, Inc., 638 F.2d 790 (5th Cir. 1981); and the discussion at George Siefkin, Rights of Lessor and Lessee with Respect to Sale of Gas and as to Gas Royalty Provisions, 4 Oil & Gas Inst. 181, 191-203 (1953).

Finally, the rationale of the cases recognizing that royalty is subject to post-production costs also indirectly supports a bargain that excludes entrepreneurship proceeds from the royalty obligation. It is axiomatic that the working interest must bear all of the costs of producing oil or gas; royalty is free of costs incurred "at the well" because those costs are required to create the production from which the royalty share comes. It is equally clear, however, as I will discuss below, that where royalty is valued by working back from downstream sales, costs incurred by the working interest to move or improve the product must be deducted from the downstream sales price to adjust that price "at the well." The net effect is that no royalty is due on revenues generated by a lessee's downstream or entrepreneurial activities.

Other commentators have also concluded that production activity is distinguishable from value-enhancing activities such as gathering, processing and marketing in defining the royalty obligation. See, e.g., Richard C. Maxwell, Oil and Gas Royalties — A Percentage of What?, 34 Rocky Mtn. Min. L. Inst. 15 -1, Û15.03 (1988); Richard J. Pierce, Jr., Lessor/Lessee Relations in a Turbulent Gas Market, 38 Oil & Gas Inst. 8 -1, Û 8.03[2] (1987); David E. Pierce, Royalty Calculation in a Restructured Gas Market, 13 E. Min. L. Inst. 18 -1, Û 18.03 (1992).

2. Determining "Value"

What if there is no market at the lease? How, then, is "value" to be determined? The courts take a pragmatic approach: "Market value is a question of fact. . . . [T]he point is to determine the price a reasonable buyer would have paid . . . at the well when produced." Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225, 238-239 (5th Cir.1984). See also Montana Ry. Co. v. Warren, 137 U.S. 348 (1890). Actual sales at the wellhead at the time of production are the best evidence of value. In the absence of the producer's breach of an implied covenant to market or the existence of circumstances that distort the economics of the transaction, an actual arms-length sale at the wellhead establishes market value. Cabot Corp. v. Brown, 754 S.W.2d 104 (Tex. 1987); Shamrock Oil & Gas Corp. v. Coffee, 140 F.2d 409 (5th Cir.), cert. denied, 323 U.S. 737 (1944). Sales comparable in time, quantity, quality, and availability to market are the favored proof of value where there are no sales at the wellhead. Ashland Oil, Inc. v. Phillips Petroleum Co., 554 F.2d 381, 386-387 (10th Cir. 1975), cert. denied, 434 U.S. 968 (1977); accord Phillips Petroleum Co. v. Ochsner, 146 F.2d 138 (5th Cir. 1944). "The absence of an available market does not mean that the [product] lacks value, however." Scott Paper Co. v. Taslog, Inc., 638 F.2d 790, 799 (5th Cir. 1981). Where there are neither actual sales nor comparable sales in the area of the well, the courts use a "work-back" or "net-back" method of royalty valuation, establishing value at the wellhead by deducting costs incurred by the working interest from the downstream sales price to "work back" to value at the wellhead. Ashland Oil, Inc. v. Phillips Petroleum Co., 463 F. Supp. 619, 620 (N.D. Okla. 1978), aff'd in part, rev'd in part, 607 F.2d 335 (10th Cir. 1979), cert. denied, 446 U.S. 936 (1980). "A starting place for the work-back method can be any point in the production-processing-sale chain where a dollar figure can be established by reliable evidence . . . ." Ashland Oil Co., 607 F.2d at 336; see also Ashland Oil, 554 F.2d at 387.

The hierarchy of royalty valuation methods is entirely logical. Market value is what a willing buyer and willing seller would agree upon under the circumstances. Ashland Oil, Ashland Oil, Inc. v. Phillips Petroleum Co., 463 F. Supp. 619, 626 (N.D. Okla. 1978), aff'd in part, rev'd in part, 607 F.2d 335 (10th Cir. 1979), cert. denied, 446 U.S. 936 (1980); State v. Carpenter, 126 Tex. 604, 89 S.W.2d 979 (1936); Exxon Corp. v. Jefferson Land Co., 573 S.W.2d 829, 830 (Tex. Civ. App. — Beaumont 1978, writ ref'd n.r.e.). Where gas is actually sold at the wellhead in a transaction negotiated at the time of sale, all elements of the definition and the transaction are in congruity unless the sale is not at arms length or the parties act unreasonably; thus, an actual sale at the wellhead is the best evidence of value. Comparable sales illustrate an available market and are strong evidence of value where there are no actual sales. The circumstances of comparable sales, however, will never be completely the same as the circumstances at the wellhead. Ashland Oil, Inc. v. Phillips Petroleum Co., 554 F.2d 381, 386 (10th Cir. 1975), cert. denied, 434 U.S. 968 (1977) (rejecting a determination of value based on data covering "a broad time span and a wide geographical distribution, [because] [t]he transactions . . . were too remote in time or place."). The work-back method "is the least desirable method of determining market price`" because it begins furthest from the wellhead so that there are likely to be more variables to consider. Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225, 239 (5th Cir.1984), (quoting Montana Power Co. v. Kravik, 586 P.2d 298, 303-304 (Mont. 1978). But the work-back method "can be just as accurate as any other method . . ." though "it is more difficult to apply." Ashland Oil, 554 F.2d at 387; see also Piney Woods, 726 F.2d at 240.

Until the Proposed Rule, federal practice and law has been consistent with this analysis, requiring a lessee to pay royalty on the value of production at the lease and looking first to establish value in the lease area. The Mineral Lands Leasing Act, 30 U.S.C. Û 226(b)(1)(A), provides for royalty "in amount or value of the production removed or sold from the lease." The Outer Continental Shelf Lands Act, 43 U.S.C. ÛÛ 1335(a)(8), 1337(a) and 1337(b)(3), requires that the lessee pay royalty "in amount or value of the production saved, removed, or sold" from leased premises. Courts have interpreted these statutory provisions to mean that royalty should be based on the value of production at the lease. For example, United States v. General Petroleum Corp., 73 F. Supp. 225 (S.D.Cal.1946), held that "value of production" under the Mineral Lands Leasing Act refers to value of oil and gas at the wellhead. Marathon Oil Co. v. United States, 604 F. Supp. 1375 (D. Alaska 1985), aff'd, 807 F.2d 759 (9th Cir. 1986), cert denied, 480 U.S. 940 (1987), upheld a net-back accounting methodology and allowed the lessee to deduct both transportation and marketing costs. Indeed, the MMS' itself has recognized that federal royalty is based upon value of production at the lease, free of cost, rather than in an enhanced value attributable to downstream activities. See Petro-Lewis Corp., 108 IBLA 20 (1989) (appropriate royalty must reflect market price at the lease); See also Notice of Proposed Rulemaking, 52 Fed. Reg. 30776, 30797 (August 17, 1987) (royalty values must be "adjusted for transportation and/or processing to determine value at the lease").

Thus, to the extent that the Proposed Rule would establish as a norm that federal lessees should pay royalty based upon downstream prices – whether spot, futures or transactions – it goes beyond the history and logic of royalty. History and logic suggest that the royalty obligation is limited to the fruits of lessees' production activities.

3. The Treatment of "Downstream" Costs

The black letter law relating to costs incurred beyond the lease is clear and consistent with the general concept of royalty. The lessee must bear all of the costs of production; royalty

1.Though I hesitate to list it as support, my colloquial experience of nearly 30 years dealing with lessors and lessees also supports the distinction between the production function and downstream entrepreneurship that may (or may not) enhance value. In my experience, lessors do not generally expect to share in the benefits (or the risks) of the lessee's entrepreneurship.is free of the costs of production because those costs are required to create the product from which the royalty share comes. Where royalty is valued at the well based upon downstream sales, costs incurred by the working interest to move the product or to improve its quality – costs subsequent to production – must be deducted from the downstream sales price. For discussion, see 3 Howard R. Williams, Oil and Gas Law ÛÛ 645-645.3 (Matthew Bender 1998); 3 Eugene O. Kuntz, The Law of Oil and Gas ÛÛ 39.4, 40.5 (1989); 2 W.L. Summers, Oil and Gas Û 400 (Permanent ed. 1958).

Again, the rationale of the fundamental principle is based upon economic and equitable logic. The value of any commodity depends upon its proximity to market, and the value of oil or gas normally increases as it is moved closer to the burnertip. Thus, costs subsequent to production tend to increase the value of the product and must be deducted from the downstream sales price to obtain an accurate valuation "at the well." As the Fifth Circuit has said:

[I]n determining market value costs which are essential to make a commodity worth anything or worth more must be borne proportionately by those who benefit. To put it another way: in the analytical process of reconstructing a market value where none otherwise exists with sufficient definiteness, all increase in the ultimate sales value attributable to the expenses incurred in transporting and processing the commodity must be deducted. The royalty owner shares only in what is left over, whether stated in terms of cash or an end product.

Freeland v. Sun Oil Co., 277 F.2d 154, 159 (5th Cir.1960) (Italics in original). See also Piney Woods Country Life School v. Shell Oil Co., 539 F.Supp. 957, 971 (S.D.Miss.1982); Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225, 240 (5th Cir.1984).

The rationale is sometimes stated in equitable terms. Since oil or gas usually becomes more valuable as it is moved closer to the place it is used, it would be unfair to the lessee to calculate royalty on the downstream sales price without fully deducting the costs incurred in moving the product and improving its quality, because that would unjustly enrich the royalty owner, whose royalty is due at the well. See Freeland v. Sun Oil Co., 277 F.2d 154, 159 (5th Cir. 1960); Piney Woods Country Life School v. Shell Oil Co., 539 F.Supp. 957, 971, 973 (S.D. Miss. 1982); Miller v. Buck Creek Oil Co., 38 Wyo. 505, 269 P. 43, 45 (1928); Coyle v. Louisiana Gas & Fuel Co., 175 La. 990, 1009, 144 So. 737, 742 (La. 1932).

While the basic principle that royalty is subject to costs subsequent to production has been unquestioned, there is some disagreement about what specific costs fall within the "subsequent to production" class. One way to state the issue is when is "production" complete for purposes of the royalty clause?

1. "Production" is complete when oil or gas is captured

Until the latter half of the 20^th Century it was generally accepted that "production" occurs for royalty valuation purposes when oil or gas is captured – at the wellhead or on the lease – so that the costs of marketing, transporting, compressing and processing beyond the lease, as well as certain severance and gross production taxes, are charged proportionately to the royalty interest. See, the excellent survey of the development of the law by Justice Owen in the concurring opinion in Heritage Resources, Inc. v NationsBank, 939 S.W.2d 118, 125-29 (Tex. 1996). The rule that "costs subsequent to production" are all costs after capture follows from the principle that royalty is due "at the well," excluding downstream increases in value due to the lessee’s entrepreneurship.

Martin v. Glass, 571 F. Supp. 1406 (N.D. Tex. 1983), is a classic example of this analysis. At issue was whether compression costs could be deducted in calculating the amount due to an overriding royalty interest reserved by lessors in a situation in which the lease addendum was silent as to the place at which the royalty was due. Id. at 1409. The court first concluded that the overriding royalty was due "at the well" by referring back to the underlying lease, which provided for a lessors' royalty based upon the "net proceeds at the well received . . . on or off the premises." Id. at 1410. The court then applied a "plain meaning" test, since there was no evidence that the lease language was used in "a special or technical sense." to hold that "[c]osts incurred prior to production are to be borne by the operator, while costs subsequent to production (those necessary to render the gas marketable) are to be borne on a pro rata basis between operating and nonoperating interests." Id. at 1411-12. The court held that compression costs were properly charged in calculating the royalty because "[t]here existed no purchaser, or market, for the gas as it existed in the wellhead because of its low pressure. Thus, compression being required to market the gas, said charges were post-production costs and as such were properly deductible from nonoperating interests." Id. at 1416.

2. "Production" is complete when the lessee obtains a product in marketable condition

Professor Maurice Merrill stated a theory for a mor e expansive royalty obligation, however, in 1940, based upon the implied covenant to market: "If it is the lessee’s obligation to market the product, it seems necessarily to follow that his is the task also to prepare it for market, if it is unmarketable in its present form." Maurice H. Merrill, Covenants Implied in Oil and Gas Leases Û 85 (2d ed. 1940). Cases and commentators at first gave little support to what was called the "marketable product" or "marketable condition" doctrine. (See, e.g., 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); George Siefkin, Rights of Lessor and Lessee with Respect to Sale of Gas and as to Gas Royalty Provisions, 4 Oil & Gas Inst. 181, 191-203 (1953). Gradually, however, support for Professor Merrill’s doctrine grew. Two cases from Kansas in the 1960s and an Arkansas decision in the late 1980s – all involving gas compression charges – appeared to hold that post-capture costs incurred to make a

2.A comprehensive examination of the derivation and rationale of the marketable product rule may be found at Owen L. Anderson, ROYALTY VALUATION: SHOULD ROYALTY OBLIGATIONS BE DETERMINED INTRINSICALLY, THEORETICALLY, OR REALISTICALLY?Part 1, 37 Nat. Res. J. 547, 604-609 (1997).

marketable product could not be charged to royalty. See Gilmore v. Superior Oil Co., 388 P.2d 602 (Kan. 1964); Schupback v. Continental Oil Co., 394 P.2d 1(Kan. 1964); Hanna Oil and Gas Co. v. Taylor, 759 S.W.2d 563 (Ark. 1988). In 1988, the MMS adopted regulations expressly requiring that federal royalties be based on production in marketable condition. 53 Fed. Reg. 1184 and 1230 (January 15, 1988). Federal lessees must "place oil in marketable condition at no cost to the Federal Government. . . ." 30 C.F.R. Û 206.102(i) (1993).

In the 1990s, a spate of decisions in Oklahoma, Colorado, and Kansas ruled that "production" is not complete until oil or gas has been both captured and made marketable. See, e.g., Wood v. TXO Production Corp., 854 P.2d 880 (Okla. 1992); TXO Production Corp. v. State of Oklahoma ex rel. Commissioner of the Land Office, 903 P.2d 259 (Okla. 1994); Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994); Sternberger v. Marathon Oil Co., 894 P.2d 788 (Kan. 1995). While these cases are not completely consistent, their underlying premise is that a lessee has an implied duty not only to seek a market for production, but to make production marketable. By this view, "production" is not complete for royalty purposes until the lessee has put the captured product in a marketable condition. Under the marketable product rule, a lessee may charge the royalty for costs of transporting, compressing and processing only if the oil or gas is marketable at the well or if those costs are incurred at a point after the lessee has paid the costs of making the oil or gas marketable.

But while the states have embraced different rules about when "production" is complete, no state has questioned the fundamental principle that once "production" has been obtained, the royalty must share with the lessee subsequent costs of compressing, transporting, processing and marketing. Indeed, the leading statement of the marketable product rule, Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994), affirmed that:

Our answer is limited to those post-production costs required to transform raw gas into a marketable product. As we explained at the outset, many different types of expenses may be involved in the conversion process. Upon obtaining a marketable product, any additional costs incurred to enhance the value of the marketable gas, such as those costs conceded by the Garmans [processing and transportation costs incurred after a marketable product had been obtained], may be charged against nonworking interest owners.

Id. at 660. The Garman Court relied in part for its statement upon federal practice:

When the federal government has considered these processes it has distinguished between "operations that condition a product for market, for which a lessee is not entitled to an allowance, and those that transform it. If transformation is involved, a manufacturing allowance is appropriate." See Exxon Corp., 98 I.D. 110, 127, 118 I.B.L.A. 221 (1991).

Id. at 660, n.26.

Professor Eugene Kuntz, whose analysis the Colorado Supreme Court weighed heavily in reaching its decision in Garman, and who was the chief proponent for the marketable product rule in the latter half of the 20^th Century, also recognized that royalty should be subject to marketing costs after the lessee had put oil in marketable condition:

After a marketable product has been obtained, then further costs in improving or transporting such product should be borne by both lessor and lessee.

* * *

[I]t may be concluded that the lessee has a duty to produce a marketable product and to bear all expenses of such production, that the lessee has a duty to market the product after it is extracted, but that unless the lease reveals a contrary intention, the expenses incident to marketing the product should be shared by the lessor and lessee.

3 Eugene O. Kuntz, The Law of Oil and Gas Û 39.4(b) (1989) (Italics added).

Thus, while state law and legal logic are not in complete agreement as to when "production" is complete, there is no support in either for the proposition that lessees should be required to bear all costs of marketing.

The Summary and Discussion of the Proposed Rule recognizes that the marketing covenant and the duty to put production into marketable condition are different. 64 Fed. Reg. at 73824. It suggests, however, that "the creation and development of markets is the essence" of the implied covenant to market. 64 Fed.Reg. at 73822. I believe that those who wrote the Summary and Discussion of the Proposed Rule misunderstand the implied covenant to market. No implied covenant imposes a duty on lessees to market after "production" at no cost to the lessor.

"Because of the lessee's exclusive control over the production and development of oil and gas, the law imposes upon the lessee certain implied covenants," including an implied covenant to market within a reasonable time and at a reasonable price and an implied covenant to operate diligently and properly. Piney Woods Country Life School v. Shell Oil Co., 539 F.Supp. 957, 973 (S.D. Miss. 1982); Sauder v. Mid-Continent Pet. Corp., 292 U.S. 272, 279, 54 S.Ct. 671, 78 L.Ed. 1255 (1934). Generally, the leasehold interest's obligation is described as a "prudent operator" standard: the lessee must do "Whatever, in the circumstances, would be reasonably expected of operators of ordinary prudence, having regard to the interests of both lessor and lessee . . . ." Brewster v. Lanyon Zinc Co., 140 Fed. 801, 814 (8th Cir. Kan. 1905), quoted with approval in Sa uder, 292 U.S. at 280. For discussion and references to other sources, see Eugene O. Kuntz, John S. Lowe, Owen L. Anderson, Ernest E. Smith and David E. Pierce Cases and Materials on Oil and Gas Law 232-236 (3d ed. West 1998).

Courts and commentators have recognized historically that the implied covenant to market may impose a duty upon a lessee to act on or near the lease to make production possible to take advantage of a market. But the covenant to market imposes no duty to act away from the lease to create a market. See Craig v. Champlin Petroleum Co., 435 F.2d 933 (10th Cir. 1971). See also the discussion at 5 Howard R. Williams & Charles J. Meyers, Oil and Gas Law Û 856.1 (1998); George Siefkin, Rights of Lessor and Lessee with Respect to Sale of Gas and as to Gas Royalty Provisions, 4 Oil & Gas Inst. 181, 203-209 (1953). For example, while the implied covenant to market may possibly require the lessee to install a booster on the lease to force gas into a pipeline (Swamp Branch Oil & Gas Co. v. Rice, 70 S.W.2d 3 (Ky. 1934)) or to construct a plant to permit carbon dioxide production (Libby v. De Baca, 179 P.2d 263 (N.M. 1947)), the lessee has no implied obligation to construct a pipeline to permit production to be marketed. See, e.g., Kretni Dev. Co. v. Consolidated Oil Corp., 74 F.2d 497, 499 (10th Cir. 1934), cert. denied, 295 U.S. 750 (1935); Ashland Oil & Ref. Co. v. Staats, Inc., 271 F. Supp. 571, 575 (D. Kan. 1967) and Fey v. A.A. Oil Corp., 285 P.2d 578, 587 (Mont. 1955). It follows from cases such as these and from the fundamental royalty principles discussed above that the implied covenant to market does not justify imposing all marketing costs on lessees.

Indeed, where the measure of royalty is "value," the cases have imposed no implied-covenant-to-market obligation on the lessee to seek the best price reasonably available – "value" is an objective standard, not related to the lessee’s efforts. See, e.g., Shamrock Oil & Gas Corp. v. Coffee, 140 F.2d 409 (5th Cir.), cert. denied, 323 U.S. 737 (1944); Haynes v. Southwest Natural Gas Co., 123 F.2d 1011 (5th Cir. 1941); Montana Power Co. v. Kravik, 586 P.2d 298 (Mont. 1978); Sartor v. United Gas Public Service Co., 173 So. 103 (La. 1937); Wall v. United Gas Public Service Co., 152 So. 561 (La. 1934); Clear Creek Oil & Gas Co. v. Bushmiaer, 264 S.W. 830 (Ark. 1924); Phillips Petroleum Co. v. Ochsner, 146 F.2d 138 (5th Cir. 1944). An implied covenant does not contradict express lease terms. See e.g., Danciger Oil & Refining Co. v. Powell, 154 S.W.2d 632, 635 (Tex. 1941); and Williamson v. Elf Aquitaine, Inc., 138 F.3d 546, 551 (5th Cir. 1998).

Moreover, nothing in the history or logic of the implied covenant to market justifies penalizing a lessee who markets away from the lease or sells in a non-arm’s-length transaction by denying the full deductibility of marketing costs. A sale to a related party does not breach the implied covenant to market in and of itself. See Garfield v. True Oil Co., 667 F.2d 942 (10th Cir. 1982); Craig v. Champlin Petroleum Co., 435 F.2d 933 (10th Cir. 1971); Parker v. TXO Prod. Corp., 716 S.W.2d 644 (Tex. App.-- Corpus Christi 1986, no writ).

Thus, to the extent that the Proposed Rule would establish as a norm that federal lessees should bear all marketing costs – even those incurred after the lessee has placed production in a marketable condition – it goes beyond the history and logic of royalty. The obligation some jurisdictions place upon lessees to put product into marketable condition does not translate to an obligation to market production free of cost to the royalty. The royalty "bargain" requires that costs "subsequent to production" be shared.

4. Conclusion

In my opinion, the Proposed Rules would impose a duty upon oil producers far beyond the bargain of the royalty obligation at American common law and far beyond the expectations of persons familiar with oil and gas leases. A fundamental principle is that royalty is due "at the well," not on the lessee’s downstream entrepreneurial activities. Where no market exists in the area, "value" may be determined by netting back from a downstream sale, though that is the "least desirable method" of establishing value because of the risk of distortion. But history, case law and logic require that post-production costs – such as marketing – be deducted in reaching "value" by a net-back methodology. Some states extend the lessee’s duty by holding that "production" is not complete until the lessee obtains a marketable product, so that the lessee must pay all costs of capturing and of placing the product in a marketable condition. There is simply no support, however, for imposing an obligation upon the lessee to pay costs of marketing after a product exists in a marketable condition.