Kentucky’s ‘At The Well’ Rule for Determining Royalties Owed Under an Oil and Gas Lease


By:  Michael J. Gartland (Copyright 2016 ©)


Royalty defined.

Every oil and gas lease provides for a royalty to the landowner/lessor.  A royalty has been defined as “the landowner’s share of production, free of expenses of production.”[2]  The word “production” is widely understood to mean the oil, gas, and other minerals that the lessee extracts from the ground at the wellhead, which is where the lessee reduces the same to physical possession.[3]  The term “royalty” is understood to mean the lessor’s cost-free share of the raw mineral produced at the point of capture, or at the wellhead.[4]  The standard royalty is one-eighth of production, or twelve and one-half percent (12.5%).


The two methods utilized to calculate royalties.

In the United States, two methods are utilized to calculate royalties owed under an oil and gas lease.  The two approaches are commonly referred to as the “at the well” rule, also known as the “work-back” or “net-back” method, and the “marketable product” or “first marketable product” approach.[5]

Under the “at the well” rule, the lessor receives royalties based on the wellhead price of the natural gas.  Because gas is rarely sold at the wellhead, but rather is typically sold at a point of sale far away from the point of capture, a natural gas lessee is entitled under the “at the well” rule to deduct certain downstream, post-production costs incurred to get the gas to the point of sale, where the sales price will be greater than if the gas were to be sold at the wellhead.  In order to obtain an enhanced price for the gas, the lessee will incur costs for gathering, compression, treatment and transportation of the gas from the wellhead to the point of sale.[6]  The “at the well” rule permits the lessee to proportionally allocate (i.e., deduct) these costs from the ultimate sales price, to determine an “at the well” value.[7]  For this reason, the “at the well” rule is “often referred to as the ‘work-back’ or ‘net-back’ method.”[8]  The majority of oil and gas producing states have adopted the “at the well” rule when interpreting oil and gas leases that do not specify a method for calculating “production.”[9]

An alternative approach to royalty calculation in a handful of jurisdictions has come to be known as the “marketable product” or “first marketable product” method.[10]  States that have adopted this approach include Colorado, Kansas, Oklahoma and West Virginia.[11]  Under this approach, the royalty is still thought of as the lessor’s cost-free share of production, but “production” is understood not simply as the initial capture of the raw mineral at the wellhead, but rather is thought of as extending to the production of a “marketable” product.[12]  Under the “marketable product” approach, if marketability requires the gas to be compressed, processed, treated and transported, the associated costs must be borne by the lessee, free of contribution from the royalty interest.[13]


The Kentucky Supreme Court holds that Kentucky is an “at the well” rule jurisdiction.

In Baker v. Magnum Hunter Production., Inc., the Kentucky Supreme Court was called upon to determine whether the royalty under two different oil and gas leases should be calculated under the “at the well” rule or the “marketable product” method.  Both leases contained an identical royalty provision as to the production of natural gas under which the lessee agreed “[t]o pay Lessor one-eighth of the market price at the well for gas sold or for the gas so used from each well off the premises.”[14]  Both the trial court and a unanimous Court of Appeals held that Kentucky law does not embrace the “marketable product” approach to royalty calculation.[15]  The Kentucky Supreme Court affirmed.[16]

In affirming the decision of the appeals court, Baker relied on three published decisions:  Reed v. Hackworth,[17] Warfield Natural Gas Company v. Allen,[18] and Rains v. Kentucky.[19]  A brief discussion of each case is in order.

In Reed, Kentucky’s then-highest court considered a gas lease that provided the lessor with the standard one-eighth share of production royalty, but was “silent as to the place of market and the price of the gas.”[20]  The lessee contracted to sell the natural gas to a utility company, and the lessee agreed to build a pipeline from the well to the utility company’s facilities in exchange for a loan to finance the pipeline build and the utility’s agreement to purchase the gas eventually piped.[21]  Under the agreement, the utility was to pay $.25 per unit for the gas, $.10 of which was understood to be a transportation charge.[22]  The royalty owner brought suit, claiming that its royalty should have been based on the full $.25 per unit paid to the lessee.[23]  The trial court entered a judgment in favor of the royalty owner, which was reversed on appeal.[24]  Because the lease was silent as to the place of market and the price, the Reed court held that deducting the $.10 per unit transportation charge from the $.25 per unit sales price was not unreasonable to determine the “at the well” value of the gas.[25]  The court noted that calculating the royalty on $.15 per unit was “consonant with the expert testimony that had been introduced to the effect that comparable sales in the area indicated an ‘at the well’ market value in the neighborhood of $.12 to $.15 [per unit].”[26]

Reed relied on Rains and Warfield.  Both of these cases involved the standard one-eighth production royalty and were silent as to how or where the production was to be valued.[27]  The courts in Rains and Warfield held that “the presumption with respect to such royalty provisions is that [the] royalty is to be valued ‘at the well side.’”[28]  In Rains, the lessee sold the gas at the well side to a pipeline company for $.06 per unit, and the pipeline company then transported the gas at its sole expense to the point of sale where it was sold for $.42 per unit.[29]  Not surprisingly, the lessor brought suit claiming that its royalty should have been based on the $.42 per unit sales price, not the $.06 per unit the gas was sold for at the well side.[30]  The Rains court rejected the lessor’s argument, explaining that:

While the lessee of a gas well may be under the duty of using reasonable effort to market the gas, we are not inclined to view that this duty, in the absence of a contract to that effect, is so exacting as to require him to market the gas by obtaining a franchise from some town or city and distributing the gas to the inhabitants thereof.  On the contrary, he fully complies with his duty if he sell the gas at a reasonable price at the well side to another who is willing to undergo the risk of expending a large amount of money for the purpose of distributing the gas to the ultimate consumers.  We are therefore constrained to view that under the contract in question appellant was entitled to either $50.00 a year for each well or to one-eighth of the fair market price of the gas at the well side.[31]


Reed, Warfield and Rains, the Kentucky Supreme Court reasoned, make clear that the lessor’s cost-free share of production (i.e., the royalty) is based on the value of the raw gas captured at the well.[32]  A royalty and gas lease that is silent on the measure of production will be understood, “absent some clear indication to the contrary,” to intend the “at the well” approach of measuring production.  A royalty and gas lease that uses “market price at the well” language, as the leases at issue in Baker did, will be understood as intending the “at the well” approach as well.[33]


After Baker, it is beyond dispute that, absent lease language to the contrary, an oil and gas lessee may deduct from the sale prices post-production costs for gathering, compression, treatment and transportation of the gas from the wellhead to the point of sale under Kentucky’s “at the well” rule.  These costs invariably result in an enhanced price for the gas at the wellhead.  A lessor must be vigilant in making sure that the lessee is actually incurring such post-production costs, which are not reported by the lessee to the lessor.  In this era of ever-declining natural gas royalties, underpayment of royalty litigation has become common place due to unsubstantiated post-production costs that the lessee claims it incurred in moving gas to the point of sale.  Such costs must “reflect actual, reasonable expenditures”[34] before they may lawfully be deducted by the lessee from the sales price of the gas.


For more information about this topic or any other litigation matter, please contact Michael J. Gartland at

[1]  This article is a service for friends and clients of DelCotto Law Group PLLC.  The opinions expressed in this article are intended for general guidance only and not as recommendations for specific situations.  As always, readers should consult a qualified attorney for specific legal guidance.

[2]  Baker v. Magnum Hunter Prod., Inc., 473 S.W.3d 588, 592 (Ky. 2015) (quoting Ramming v. Nat. Gas Pipeline Co. of Am., 390 F.3d 366, 372 (5th Cir. 2005)).

[3]  Id.

[4]  Id.

[5]  Id. at 592-94.

[6]  Id. at 591.

[7]  Id. at 592-93.

[8]  Id. at 593.

[9]  Id. at 595.

[10]  Id. at 594.

[11]  Id. (citing Rachel M. Kirk, Comment, Variations in the Marketable-Product Rule from State to State, 60 Okla. L. Rev. 769 (2007)).

[12]  Baker, 473 S.W.3d at 594.

[13]  Id.

[14]  Id. at 590 (emphasis added).

[15]  Id.

[16]  Id.

[17] 287 S.W.2d 912 (Ky. 1956).

[18] 88 S.W.2d 989 (Ky. 1935).

[19] 255 S.W. 121 (Ky. 1923).

[20]  Baker, 473 S.W.3d at 593 (quoting Reed, 287 S.W.2d at 913).

[21]  Id.

[22]  Id.

[23]  Id.

[24]  Id.

[25]  Id.

[26]  Id.

[27]  Id.

[28]  Id.

[29]  Id.

[30]  Id.

[31]  Id. at 593-94 (quoting Rains, 255 S.W. at 122-23).

[32]  Id. at 594.

[33]  Id.

[34]  Nami Res. Co., LLC v. Asher Land and Mineral, Ltd., — S.W.3d —-, 2015 WL 4776376, at *2 (Ky. Ct. App. Aug. 14, 2015).


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