By Dan Lawrence

In the relationship between the owners of oil and gas and the operators who explore for, develop, produce and sell those minerals, there are few issues that cause more heartburn and strife than the calculation of royalty payments. Mineral owners receive royalty payments accompanied by paperwork from the producer showing the manner in which their payments were calculated, which often – particularly in the case of royalties on gas production – depict the royalty payment being reduced by deductions for expenses associated with activities described as “gathering,” “compression,” “dehydration,” etc. The landowner consults his or her lease, which contains a royalty clause that, at least on its face, seems to have nothing to say about whether or not these are costs that should be taken into account in calculating royalties. Questions and demands to the producer follow, becoming increasingly heated until, eventually, lawyers from both sides square off for a fight.

For decades now, this pattern has been repeated many times in Kansas by oil and gas producers and mineral owners in every corner of the state where oil and gas can be found. Generally speaking, it is one that could be avoided through the simple expedient of more carefully drafting the royalty-related provisions of the subject oil and gas leases to address these sorts of activities directly without ambiguity. The recent case of Fawcett v. Oil Producers, Inc. of Kansas, ____ Kan. ____, 352 P.3d 1032 (2015) emphasizes this: the Kansas Supreme Court in that case rejected the claims of a group of royalty owners who sued their producer for violating the implied–that is, unwritten–obligations of their oil and gas leases–a dispute that could have been avoided or settled more expeditiously if the leases in question had squarely addressed and spelled out how royalties should be calculated.

This article discusses some common royalty provisions and their meaning under Kansas law, along with some suggestions that mineral owners and producers may wish to consider when negotiating or evaluating an oil and gas lease. First, though, there are a couple of fundamental rules that both parties to a mineral lease need to understand:

(1) Because an oil and gas lease is a written contract, it is subject to what is called the “parol evidence rule.” What this means is that the written language of the lease is generally controlling over–and excludes consideration of–any other written or spoken promises or representations that may have occurred up to and during the negotiation of the lease. To put it more simply still, if something that the parties discussed is not in the lease, it may as well have never happened.


(2) Kansas law states that uncertain or unclear provisions in an oil and gas lease are generally resolved in favor of the mineral owner when there is a dispute about their meaning. However, when a mineral owner participates in negotiation of the lease and makes changes to its terms, he or she loses the benefit of this rule. It is therefore important for a mineral owner who chooses to negotiate and revise the lease to ensure that he or she is satisfied with the revised terms, as they will not receive the benefit of the doubt in their interpretation.

When it comes to the royalty provisions addressing payment of royalties on oil, there is generally little variation among lease forms. The lease will usually provide that the mineral owner is entitled to be paid a fraction of the oil produced, calculated “at the market price for oil of like grade and gravity prevailing on the day” it is produced, or similar language. This form of royalty clause is generally deemed to be adequately clear and generates little dispute.

Gas royalties, however, are more complicated. Three types of gas royalty clauses can generally be found in Kansas oil and gas leases: (1) the “proceeds” lease; (2) the “market value” lease; and (3) the “Waechter” lease (a combination of the proceeds lease and the market value lease).

A “proceeds” lease requires royalties to be calculated based on the proceeds from sale of the oil or gas produced from the lease. The following are a few examples of proceeds-type royalty clauses drawn from recently-executed Kansas oil and gas leases:

The lessee shall pay lessor, as royalty, one-eighth of the proceeds from the sale of the gas, as such, for gas from wells where gas only in found. . . .


The lessee shall monthly pay lessor as royalty on gas marketed from each well where gas only is found, one-eighth (1/8) of the proceeds if sold at the well, or if marketed by lessee off the leased premises, then one-eighth (1/8) of its market value at the well.


To pay lessor for gas from each well where gas is found the equal one-eighth (1/8) of the gross proceeds at the prevailing market rate, but, as to gas sold by lessee, in no event more than one-eighth (1/8) of the proceeds received by lessee from such sales. . .

A “market value” or “market price” lease is one that “requires the computation of royalty payments based on the price that would be paid by a willing buyer to a willing seller in a free market.” Fawcett v. Oil Producers Inc. of Kansas, 49 Kan.App.2d 194, 198, 306 P.3d 318 (2013) (citing Matzen v. Cities Service Oil Co., 233 Kan. 846, 851, 667 P.2d 337 (1983)). The following are examples:

To pay lessor for gas of whatsoever nature or kind . . . one-eighth (1/8) at the market price at the well for the gas sold . . . .


[T]o pay lessor for gas of whatsoever nature or kind produced and sold, or used off the premises, or used in the manufacture of any products therefrom, one-eighth (1/8), at the market price at the well . . . .


The lessee shall pay to lessor for gas produced from any oil well and used by the lessee for the manufacture of gasoline or any other product as royalty 1/8 of the market value of such gas at the mouth of the well . . . .

A Waechter lease is a hybrid of the two foregoing lease types, providing that royalties will be calculated based on either proceeds or market value, depending upon the location where gas is sold. Named after the case of Waechter v. Amoco Production Co., 217 Kan. 489, 509-12, 537 P.2d 228 (1975), the royalty language at issue in Waechter provided as follows:

Lessee shall pay lessor monthly as royalty on gas marketed from each well one-eighth (1/8) of the proceeds if sold at the well, or, if marketed by lessee off the leased premises, then one-eighth (1/8) of the market value thereof at the well.

These three lease types continue to predominate in Kansas. Yet a careful review of Kansas law makes clear that each of these three main categories of oil and gas leases described above are all, in some way, inadequate to provide producers and royalty owners with certainty regarding their royalty obligation (for producers) and royalty entitlement (for mineral owners). The best way to address this problem is for both parties to the oil and gas lease to spell out and specifically identifying what costs may be taken into account in calculating royalty.

In connection with this effort, we suggest clients conceptualize royalty deductions as falling into two general categories that they should be aware of and attempt to address in the language of the royalty clause. The first category can be described as consisting of monetary deductions, i.e., charges that reflect actual expenses incurred by the producer in connection with its operations. These commonly include the following:

    • Gathering, which may be provided by a third-party (for example, ONEOK owns–or used to own–large gathering systems connected to the Bushton plant in western Kansas) or an affiliate of the producer. Gathering, of course, refers to the system of typically low-pressure, low-diameter pipe used to collect gas from the well and centralize it, ultimately terminating (usually) at the inlet to a processing plant.

    • Treatment charges, as distinct from processing, used to remove hydrogen sulfide or other compounds that present an impediment to gathering by threatening the integrity of the gathering system (e.g., by corrosion when the hydrogen sulfide or CO2 combines with water to create sulfuric acid or carbonic acid).

    • Dehydration, which is exactly what it sounds like: mechanical and other processes to reduce the moisture content of the gas to ensure that water does not collect in the gathering system, impeding flow and potentially damaging equipment, lines, and facilities, particularly in cold temperatures.

    • Compression, used to overcome declining reservoir pressure, to move the gas along the gathering system to the processing plant, and to achieve the high pressure necessary to enter the transmission pipeline.

The following is an example of a royalty clause that attempts to address these concerns.

The Lessee shall not deduct any costs incurred by the Lessee or any of the Lessee’s related entities, whether such costs are incurred on or off the Leased Premises, or whether incurred directly or indirectly, for any part of the costs of producing, gathering, treating, compressing, dehydrating, readying, or measuring, the Oil and Gas Substances.

Another factor which can affect the payment of royalty, and which arises primarily–though not solely–out of the use of compression, might be described as a volumetric deduction: the loss of a portion of the gas stream in which the royalty owner owns an interest, and for which loss the owner is not paid. Some producers will “monetize” the volumetric deduction by calculating the lost volume, converting it to a dollar value, and then sharing that information with the royalty owner on his or her check stub, but that is not always the case. This loss (which is also described as “shrink,” “line loss,” “burn,” or “shrink and burn”) can happen as the result of a simple lack of integrity in the miles-long gathering system that permits small volumes of gas, here and there, to leak and be lost. More often, however, the volume loss is due to the use of the gas as fuel for compressors. The loss can be sizable. On one Kansas gathering system, “shrink and burn” between the wellhead and the outlet of the gathering system consumed 15% of the total gas stream. It is an amount worth addressing through the inclusion of something like the following provision:

Lessee shall pay the Lessor royalty on the same basis as set forth in sub-paragraphs (a) and (b) above [addressing oil and gas royalties, respectively], on the Oil and Gas Substances extracted but not sold due to shrinkage, line loss, or for any other reason.

Royalty calculation-related disputes in Kansas and other jurisdictions have also arisen when royalties are calculated based upon a sale price negotiated between the producer of the lease and a downstream affiliate which the producer owns and controls. In these situations, questions can arise over whether such a sale is truly “arm’s length” and really reflects the value of the gas, leading to a dispute over possible royalty underpayment. This is therefore another potential source of disputes that can be–and should be–addressed in the royalty-related provisions of the oil and gas lease. An exemplary provision intended to address this concern can provide as follows:

The Lessee shall pay the Lessor royalties for gas, condensate, distillate, casinghead gas, helium, and all other gases and related liquids, including their constituent parts, produced and sold from the Leased Premises on [Insert Fraction] of the gross proceeds received by the Lessee, or any of its related entities, from an arms-length sale to an unrelated third party.

Hopefully, the suggestions above will provide some guidance to mineral owners and producers seeking to avoid disputes about royalty payment. However, oil and gas is a complicated area of law. As a Colorado court observed, “the law of oil and gas is unlike any other area.” Davis v. Cramer, 808 P.2d 358, 359 (Colo. 1991). When in doubt, consultation with an oil and gas attorney is encouraged. Tom Kitch, Greg Stucky, David Seely and Dan Lawrence of Fleeson Gooing practice in this area.