Oklahoma Bar Journal

Out With the Old, In With the New: Is it Time to Modernize the Oklahoma Oil and Gas Royalty Clause?

By Chaille G. Walraven

In a 1948 speech to the House of Commons, British Prime Minister Winston Churchill warned, “Those who fail to learn from history are condemned to repeat it.”1 This certainly rings true in the context of royalty litigation. History has shown us that royalty clauses based on subjective standards are prone to litigation. Yet rather than abandon subjective standards altogether, the general industry approach is to add new language to the old standard. The theory, it would seem, is that adding new language will resolve old issues.2 In the words of Professor Merrill, the result of this approach is, “The crazy old structure remains, like a house which has been built onto, time and again.”3 Given the history of Oklahoma royalty litigation over the last two decades alone, it may be time to consider laying a new foundation.

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Many years ago, the average royalty owner signed an oil and gas lease prepared by the producer with little to no substantive negotiation.4 But times are changing. There is a growing trend of royalty owners who are better informed about the gas marketing process, negotiate for certain clauses in their oil and gas leases and actively monitor how their royalties are reported. Royalty owners today want to understand how their royalties are calculated and paid. Unfortunately, the expectation of being well informed often goes unmet. Because royalty owners are not involved in the marketing process, they have no way to verify whether they are being paid correctly (let alone how they are being paid) based solely on their check detail. Perhaps the number one complaint from royalty owners today is a simple lack of transparency. As more royalty owners begin to question how their royalties are being paid, the concern is that royalty litigation, especially individual actions, will only continue to increase in the coming years.

Most royalty clauses today are tethered to a marketable product standard, yet what precisely constitutes a “marketable product” has been a topic of fierce debate.5 In addition to being subjective, this standard also creates inherent conflict between royalty owners and producers.6 It is worth remembering the oil and gas lease was meant to create a mutually beneficial relationship between mineral owners and producers.7 In order to restore this relationship and improve trust between the parties, we should consider anchoring royalty valuations to an objective standard. The question we must ask ourselves is whether we can draft a royalty provision that will not only provide an objective standard for royalty calculations but that is also acceptable to both sides.8 Given the proliferation of litigation on this issue, the long-term benefits of structuring a new royalty clause are worth considering.



Prior to the deregulation of interstate pipelines and natural gas sales prices, producers generally sold natural gas to pipeline companies at the lease premises for the maximum lawful price.9 However, the Natural Gas Policy Act of 1978 and the Natural Gas Wellhead Decontrol Act of 1989 revolutionized the markets by removing many of the constraints that limited how producers could market natural gas.10 Yet while the natural gas market rapidly evolved, royalty lease language continued to remain relatively static.11

Following this industry change, the Oklahoma Supreme Court issued a series of opinions articulating the marketable product standard that governs most royalty litigation today.12 While virtually all producers and a growing number of royalty owners have heard of Mittelstaedt, disagreement continues as to what precisely constitutes a marketable product. While the court in Mittelstaedt did not provide a definition for “marketable product,” it did note that certain processes were usually necessary to obtain a marketable product: “It is common knowledge that raw or unprocessed gas usually undergoes certain field processes necessary to create a marketable product. These field activities may include, but are not limited to, separation, dehydration, compression, and treatment to remove impurities.”13

In today’s deregulated market, many producers enter into contracts with midstream companies that provide for the gathering, compressing and processing of natural gas. The costs associated with gathering, compressing and processing (namely, who pays for those costs) are the root of the problem. This is compounded by the fact that how these costs are paid can vary from producer to producer. Contracts with midstream companies can be structured on a fee basis, where midstream companies charge the producer a certain fee for each MMBtu that is gathered, compressed and/or processed.14These contracts can also be structured on a percent-of-proceeds (POP) basis, where the midstream company retains a percentage of the proceeds as compensation for its services.15 Oftentimes, such contracts also provide for a percentage of gas volumes to be used by the midstream company as fuel for its equipment in the field or the plant. While these contracts may seem fairly straightforward in and of themselves, when they intersect with a producer’s obligation to produce a marketable product, controversy abounds. Many producers take the position that the raw gas stream is sold at or near the lease under the midstream contract, and the producer has therefore discharged its duty to obtain a marketable product upon delivering the raw gas to the midstream company. Most royalty owners take the position that irrespective of midstream contract terminology, the raw gas is still raw gas at or near the lease and raw gas is not a marketable product. These competing views have only added more fuel to the litigation fire.



Many producers take the position that the entire stream of raw, unprocessed gas is sold at or near the lease under a contract with a midstream company. As support for this argument, the producer frequently relies on the argument that title to the gas stream passes at or near the lease to the midstream company.16 Not surprisingly, royalty owners take the position that the actual sale is not completed until the final volume and value is determined, which often is at a point downstream
of the lease.

To illustrate this conflict, let’s say that the O.K. Corral Well is located in rural western Oklahoma and produces lean natural gas that is saturated with water vapor and low in pressure. Two different producers, Earp and Ringo, market their share of the gas under the well. Producer Earp contracts with a midstream company to gather the gas, compress it, dehydrate it and then deliver the gas to the ANR Pipeline. The midstream company charges Producer Earp $20 for these services. Producer Earp then sells the gas on the ANR Pipeline for $100. Producer Earp and the royalty owner both agree the gas was actually sold for $100, and midstream costs were incurred in the amount of $20. Under royalty clauses tied to the marketable product standard, Producer Earp must satisfy the Mittelstaedt factors before any of the $20 costs may be shared with the royalty owner. And if the royalty clause expressly limits (or allows) certain midstream costs, the $20 is also subject to those royalty provisions.

Producer Ringo, however, takes a more creative approach. Producer Ringo enters into a contract with the same midstream company for its share of the same gas stream. But Producer Ringo structures its contract on a POP basis. The midstream company takes custody of the gas at the lease, gathers the gas, compresses it, dehydrates it and then sells the gas on the ANR Pipeline for $100. However, in addition to taking custody of the gas at the lease, the midstream company is also bestowed with “title” to the gas. The midstream company retains $20 as compensation for its services and remits the remaining $80 of proceeds to Producer Ringo. However, unlike Producer Earp, Producer Ringo disagrees with the royalty owner that the gas was actually sold on the ANR Pipeline for $100. Rather, Producer Ringo claims the gas was sold back at the lease for only $80. Producer Ringo further claims there were no midstream costs incurred at all because the gas was sold at the lease. According to Producer Ringo, the gas was sold under a “wellhead sales contract.”18 Consequently, Producer Ringo claims the Mittelstaedt factors do not apply to the $20 retained by the midstream company. Even more concerning, Producer Ringo claims that because there were no midstream costs, royalty clauses that expressly limit the sharing of midstream costs also do not apply.

Far from being an ideology war, these “wellhead sales contracts” have a real economic impact on the royalty owner. Royalty owners under the first scenario 1) have a reported gross sales value of $100, 2) are not subjected to the midstream costs expressly disallowed in their royalty clause and 3) are afforded greater transparency in how their royalties are calculated. Contrast that with the royalty owners under the second scenario who 1) have a reported gross sales value of only $80, 2) are subjected to midstream costs, even if those midstream costs are expressly disallowed in their royalty clause and
3) are often afforded no transpar
ency at all since midstream costs are not reported on the check detail.

These midstream contracts have a direct impact on how the royalty owner gets paid. Yet the royalty owner is not privy to this contract and has no input on the terms of such contract. Royalty owners often find themselves at the mercy of how the producer elects to structure the midstream contract. Oil and gas leases are also generally assignable, so royalty owners have little control over which producer they may eventually end up with. Because many royalty clauses are tied to a marketable product standard or specifically identify midstream costs that cannot be shared with the royalty owner, the “wellhead sales contract” necessarily invites litigation.

Other courts have recognized the potential abuse in allowing producers to move the point of sale by relying on the midstream contract. Recently, the North Dakota Supreme Court analyzed this type of transaction in Newfield Expl. Co. v. State ex rel. North Dakota Brd. of Univ.19In Newfield, the producer alleged it properly calculated royalties “based on the gross amount paid to [it] by the midstream company because the gas was sold at the wellhead.20 However, the North Dakota Supreme Court held that no actual sale took place at the wellhead, irrespective of attempts to transfer titleat the well: “While title to the gas passes at the well, the transaction is not complete, and full value of the consideration paid to Newfield is not determined until Oneok has incurred the cost of making the gas marketable and subsequently sold the marketable gas.”21

When interpreting the midstream contract, the North Dakota Supreme Court found it compelling that “consideration paid to [the lessee] is not determined until” after midstream services had been completed.22 Likewise, the 5th Circuit Court of Appeals found this distinction controlling. In Piney Woods,23 the 5th Circuit recognized the potential abuse of focusing on the passage of title under the midstream contract:

The lessors had no say in Shell’s choice of where to put the passage of title. Their interests were either irrelevant or adverse to Shell’s. Shell and its buyers wanted to avoid state pipeline regulations; but their decision to do so had the effect of placing the “point of sale” on the lease, thereby avoiding Shell’s obligation to pay royalties based on market value.The opportunity for manipulation is apparent.Harmon, for example, counsels producers to “attempt to obtain appropriate contract amendments which would move the sales point onto the premises of each lease from which gas delivered under the contract is produced” to avoid payment of market value royalty.24

The Supreme Court of Wyomingalso reached the same result in State v. Davis Oil Co.25 In Davis, the court held that for purposes of the oil and gas lease, the “passage of title does not determine whether gas is sold ‘at the wells’[.]”26 As long as midstream contracts continue to impact how payment is calculated under the standard royalty clause, both producers and royalty owners must recognize the fact that a court (or jury) may ultimately be interpreting the royalty clause for them.



Adding another layer of complexity to the debate is the fact that many royalty owners today are negotiating for changes to the standard lease form the producer provides. A growing number of royalty owners refuse to accept lease forms that expressly allow the producer to charge the royalty owner for all costs incurred in making a marketable product. This has led to a dramatic increase in the number of enhancement royalty clauses in recent years. The interpretation of the enhancement clause was recently litigated in a case out of the 4th Circuit, Corder v.
Antero Resources Corp.27 In Corder, the royalty clause was the standard enhancement royalty clause used in many leases today, to wit:

It is agreed between the Lessor and Lesee (sic) that notwithstanding any language herein to the contrary, all oil, gas or other proceeds accruing to the Lessor under this lease or by state law shall be without deduction, directly or indirectly, for the cost of producing, gathering, storing, separating, treating, dehydrating, compressing, processing, transporting, and marketing the oil, gas and other products produced hereunder to transform the product into marketable form; however, any such costs which result in enhancing the value of the marketable oil, gas or other products to receive a better price may be deducted from Lessor’s share of production so long as they are based on Lessee’s actual cost of such enhancements. However, in no event shall Lessor receive a price that is less than, or more than, the price received by Lessee.28

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The enhancement clause essentially distinguishes two categories of costs: 1) those that are transformative in nature and 2) those that are enhancing in nature.29 Costs that “transform” the oil, gas and other products are prohibited, but costs that “enhance” such products are allowed if all of the other conditions precedent are met. Of course, neither the royalty owner nor the producer could agree on which products were included in the phrase “oil, gas and other products” or what “transform the product into marketable form” meant:

Although the parties clearly intended to differentiate between these costs, the Market Enhancement Clause fails to indicate when Antero’s efforts become enhancing rather than transforming. This transition hinges on what the parties intended to include as “oil, gas, and other products,” and when those products become marketable...To Antero, NGLs are not “other products” and the Plaintiffs’ raw gas is marketable. To the Plaintiffs, NGLs are “other products” and only residue gas and NGLs are marketable. Whether the parties intended to include NGLs as “other products” within the Market Enhancement Clause for which Antero bears the manufacturing costs, or intended to exclude NGLs as “other products” and thereby require the Plaintiffs to share the cost of extracting and fractionating NGLs, are material questions of fact that remain unclear.30

To the royalty owners, the phrase “transform the product into marketable form” refers to the specifically enumerated services that transform raw gas into residue gas and NGLs. To the royalty owners, residue gas and NGLs were the intended products they bargained for under their enhancement clause. Of course, producers disagree. This resolution will turn on what products the parties were intending when they entered into the royalty clause.

While the duty to obtain a marketable product has been extensively litigated, it is important to remember this duty was based on the premise that royalty owners have no say in the negotiation of post-production services.31 What the Oklahoma Supreme Court recognized roughly three decades agowas that the royalty owner has no input or involvement in the marketing decisions undertaken by the producer. Yet it is often such marketing decisions that drive royalty payment disputes. In order to avoid more litigation, any new royalty clause should offer the royalty owner a substantial ability to understand and verify how royalties are being calculated and paid.



History has taught us that when royalty calculations are left to subjective terms, differing opinions will inevitably follow. If subjectivity is a root cause of conflict between mineral owners and producers, it seems logical to turn to an objective standard. This can be accomplished by tying royalties to an objective measurement, such as index-based prices. A reliable royalty clause can generally be distilled into two components: value and volume. At the end of the day, the royalty owner wants to know
1) how much gas was produced and 2) how that gas was valued.

One way to provide certainty and objectivity to a royalty clause is to provide a fixed dollar amount per MMBtu of gas or barrel of oil. A few (very) old lease forms utilized this approach. Of course, one need only be a casual observer of the oil and gas industry to understand the pitfalls of a static price. Given that in the last two years alone the price of oil has gone from less than $0 a barrel to over $130 a barrel, the deficiencies in
a fixed-price valuation are self-
evident. Any objective standard must take into account the volatility of the energy market – hence the appeal of anchoring royalty valuation to an index price.

A royalty clause that provides for the payment of royalty on MMBtus of gas produced from the leased premises multiplied by an agreed-upon index price provides an objective measurement standard. First, both producers and royalty owners can ascertain what an average index price is for any given month. Second, it does not require any subjective component to calculate. For example, the parties could select the NYMEX-Henry Hub as a starting point.32 The parties could agree to a price based on the NYMEX-Henry Hub to anchor the value of the gas.33 The parties would then negotiate the percentage discount off the index price to reflect the different market locations.

The agreed-upon price can then be multiplied by the number of MMBtus that flow through the custody transfer meter.34 At this point, the royalty clause becomes purely objective. The gross value for royalty purposes can be calculated with mathematical certainty: MMBtus x [NYMEX-Price x % discount]. This gross value is then multiplied by the royalty owner’s decimal share to calculate gross royalty due before taxes. There is no need to determine which midstream costs are allowable under the royalty clause when gas becomes a marketable product or which costs are transformative as opposed to enhancing. There is no need to calculate the monetary value of gas volumes consumed as field fuel or plant fuel. From a purely administrative standpoint, calculating royalties in this manner would be fairly straightforward.

The royalty owner can also independently verify how their royalties are calculated. Unlike pricing under midstream contracts, the index price is publicly available for any royalty owner to confirm. This simple transparency alone could prevent untold future litigation. Further, the royalties do not change when the producer moves to a POP contract, a fee-based contract or even a percent-of-index contract. While the industry has generally been resistant to index-based royalty clauses, it is worth considering the cost of future litigation that will result from subjective-based royalty clauses. As with any change, there would certainly be a learning curve. The lease would also have to identify an alternative index or another agreed-upon royalty formula in the event the selected index becomes unavailable in the future. But if royalty owners and producers could both agree upon an objective royalty clause, both sides would benefit in the long run. In order for royalty disputes to become history (and not our future), we should all take another look at the benefits of an objective royalty clause.




Chaille G. Walraven is a managing director at Graft & Walraven PLLC. She focuses her practice on oil and gas law and real estate matters, with an emphasis on litigation that protects the rights of land and mineral owners.





  1. https://bit.ly/3uhYxKU.
  2. Maurice Merrill, The Oil and Gas Lease-Major Problems, 41 Neb. L. Rev. 488, 491-92 (1962) “Instead, words are added. New phrases, clauses, sentences or sections are added. The crazy old structure remains, like a house which has been built onto, time and again.”
  3. Id.
  4. Owen L. Anderson, Royalty Valuation: Should Royalty Obligations Be Determined Intrinsically, Theoretically, or Realistically?, 36 NRJ 611, 611-612 (1997).
  5. See Pummill v. Hancock Expl. LLC, 2018 OK CIV APP 48, ¶28, 419 P.3d 1268, 1276 “Unfortunately, the Court did not define the meaning of ‘marketable product,’ nor has it done so since.”
  6. Byron C. Keeling & Karolyn King Gillespie, “The First Marketable Product Doctrine: Just What is The ‘Product?’” 37 St. Mary’s L.J. 1, 3-4 (2005).
  7. For purposes of this article, the term “producer” is used to refer to the lessee, and “mineral owner” or “royalty owner” is used to refer to the lessor.
  8. The focus of this article is calculating royalties on natural gas production.
  9. John Shepherd & Tina Van Bockern, Relationship Between Transportation, Marketing, and the Royalty Clause, 3 RMMLF-INST 8, 8-1 (2018).
  10. Id.
  11. See Michael Irvin, The Implied Covenant to Market in the Deregulated Natural Gas Industry, 42 RMMLF-INST 18, §18.01 (1996).
  12. Mittelstaedtv.SantaFeMinerals, Inc.,1998OK7,954P.2d1203; Woodv.TXO Prod. Corp.,1992OK100,854P.2d880; Howellv.Texaco Inc.,2004OK92,112P.3d1154.
  13. Mittelstaedt, 1998 OKat ¶21, 954 P.2d at 1208.
  14. SeePummill v. Hancock Expl. LLC, 2018 OK CIV APP 48, ¶14, fn. 6, 419 P.3d 1268, 1272; Naylor Farms v. Chaparral Energy, LLC, 923 F.3d 779, 783, fn. 2 (10th.Cir.2019); ONEOK, Inc., 10-K Annual Report, March 1, 2022, pg. 9; Enable Midstream Partners, LP, 10-K Annual Report, Feb. 24, 2021, pp. 12-13; DCP Midstream, LP, 10-K Annual Report, Feb. 18, 2022,p.8; Enlink Midstream, LLC, 10-K Annual Report, Feb. 16, 2022, p. 48.
  15. Id.
  16. Naylor Farms at 783, fn. 2; Newfield Expl. Co. v. State ex rel. North Dakota Board. of Univ., 2019 ND 193, ¶3, 931 N.W.2d 478, 479; Piney Woods Country Life Sch. V. Shell Oil Co., 726 F.2d 225, 232 (5th Cir. 1984); State v. Davis Oil Co., 728 P.2d 1107 (Wy. 1986).
  17. Id.
  18. See Naylor Farms at 785, “And neither party suggests Mittelstaedt involved (or even contemplated, for that matter) the type of wellhead sales contracts that Chaparral
    allegedly utilized here.”
  19. 2019 ND 193, 931 N.W.2d 478.
  20. Id. at ¶4.
  21. Id. at ¶11.
  22. Id.
  23. Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225 (5th Cir. 1984) (although Piney Woods addressed a market value lease, the court still found that passage of title to a midstream company does not discharge the duties owed to the royalty owner under the lease).
  24. Id. at 232 (internal citations omitted).
  25. 728 P.2d 1107 (Wy. 1986).
  26. Id. at 1109.
  27. 2021 WL 1912383 (N.D.W. Va. 2021).
  28. Id. at *3.
  29. Id.
  30. Id. at *7-9 (internal citations omitted).
  31. Wood at ¶11, 882-83.
  32. See https://bit.ly/3rm0CUc.
  33. The parties could agree to a number of different arrangements, including the price on the first day of the month, the last day of the month or the arithmetic average of the daily per MMBtu settlement prices during a set period, for example.
  34. If the gas is processed, the parties could approach the royalty clause in two ways. First, the parties could apply the index price to all the MMBtus that flow through the custody transfer meter. In such an event, the royalty owner would forgo any potential liquid uplift. This should be reflected in the royalty owner taking a smaller discount on the index price. Second, rather than applying the index price to all the MMBtus that flow through the custody transfer meter, the index price could be applied to these MMBtus less shrink.

Oklahoma Bar Journal – OBJ 93 Vol 5 (May 2022)