West Virginia Jury Finds That EQT Improperly Calculated Landowners’ Royalty on Shale Gas

Robert J. Burnett  is a director and chair of Houston Harbaugh’s Oil and Gas practice. To learn more about our work with landowners and royalty owners, visit our Oil and Gas Law practice page.
A Federal jury in the Northern District of West Virginia recently found that EQT Production Company (EQT) breached the parties’ oil/gas lease by utilizing the “work back” method to calculate the landowner’s royalty. In Richards v. EQT Production Company, the plaintiffs-landowners argued that their royalty was artificially reduced by EQT’s practice of “netting out” post-production costs incurred between the wellhead and the downstream point-of-sale. Many drillers in the Marcellus Shale region, like EQT, apply the “work back” method when calculating landowner royalties regardless of the actual language in the underlying royalty clause. As detailed below, such blind reliance on the “work back” method was soundly rejected by the jury in Richards and serves as a stark reminder that the actual language in the parties’ oil and gas lease must be followed and given effect.

At issue in Richards were three oil and gas leases executed in 1951 concerning three parcels located in Ritchie County, West Virginia (the “1951 Leases”). The 1951 Leases all contained the identical royalty clause:

“In consideration of the Premises the said party of the second part, covenants and agrees: 1st-to deliver to the credit of the Lessors, their heirs or assigns, free of cost, in the pipe line to which the Lessee may connect the wells…the equal one-eighth (1/8) part of all oil produced and saved from the leased premises; and second, to pay…one-eighth (1/8) of the market price of the gas from each and every gas well drilled on said premises, the product from which is marketed and sold off the premises, said gas to be measured by a meter.”

The original lessee drilled a number of shallow vertical wells on the leasehold and tendered royalties without deducting any post-production costs. EQT subsequently acquired the 1951 Leases and in 2016 drilled six horizontal Marcellus Shale wells. Thereafter, in November 2016, EQT began paying royalties to the Richards for the hydrocarbons produced from these six Marcellus Shale wells.

Despite the clear language set forth in the 1951 Leases, EQT did not calculate the Richards’ royalty based on an actual “market price”. Instead, EQT calculated the royalty based on an artificially diluted “index” price. EQT sold the gas at or near the wellhead to an affiliate, EQT Energy, pursuant to a “Base Contract for Sale of Natural Gas” (the “Gas Sales Contract”). The Gas Sales Contract established a pricing formula whereby EQT was paid a fixed price in an amount equal to “the first of the month index price applicable to the interstate pipeline/gas gathering system into which the gas is delivered, less gathering-related charges, retainage and any other agreed to charges.”1 Based on this language in the Gas Sales Contract, the eventual price paid to EQT by EQT Energy was actually less than the true market price – the costs of gathering and compression were deducted from the index price resulting in a reduced sale price. The Richards’ royalty was then calculated on this reduced index value. EQT argued that because the Gas Sales Contract contemplated a wellhead sale, it was authorized to utilize the “work back” method to arrive at a wellhead value. However, as noted above, the 1951 Leases did not identify or designate the wellhead as the royalty valuation point.

The Richards filed suit in February 2017 alleging, inter alia, that EQT breached the 1951 Leases by calculating the royalty on the reduced index value. The Richards argued that under a “market value” lease, such as the 1951 Leases, royalties must be paid based on the actual market value of the gas itself. As one court once observed, when calculating a royalty under such a lease, the gas value is determined by “the price that a willing buyer would pay a willing seller [for the gas] in a free market…” See, Imperial Colliery Co. v. Oxy USA, Inc., 912 F.2d 696 (4th Cir. 1990). In this case, the Richards argued, the market price was the “first of the month index price” at the TETCO M2 pipeline – the location where a willing buyer was, in fact, paying a willing seller for the gas. Moreover, since the 1951 Leases did not identify or designate the wellhead as the royalty valuation point, the Richards further argued that EQT had no contractual authority to net-out the gathering and compression costs that were incurred between the wellhead and the TETCO M2 pipeline. By doing so, EQT was artificially reducing the purported index price and thereby calculating the royalty on a value other than the “market price” required by the 1951 Leases.

In September 2018, the matter was tried before a jury in Clarksburg, West Virginia. The jury agreed with the Richards and found that EQT had “failed to pay the Richards the full amount of the royalties due.” The jury awarded $191,998.61 in damages.

The author believes this was the correct outcome. The 1951 Leases do not identify or designate the wellhead as the royalty valuation point. As such, there is no textual support in the leases themselves which would justify use of the “work back” method. It is well-settled that the “work back” method is applicable only in those circumstances where the lease itself expressly designates the wellhead as the royalty valuation point but the gas is actually sold down-steam at a remote location off the lease. In those situations, a driller may net-out the intervening costs to arrive at a wellhead value, as is implicitly required by the lease. See, Kilmer v. Elexco Land Services, Inc., 990 A2d 1147 (Pa. 2010) (“…to calculate the price of natural gas at the wellhead (and thus the royalties), they argue that we must work backward from the value-added price received at the point of sale by deducting the companies’ costs of turning the gas into a marketable commodity”). The 1951 Leases, however, contained no such language.

EQT’s reliance on the wellhead language conveniently set forth in the Gas Sales Contract was misplaced. First and foremost, the Richards were not a party to the Gas Sales Contract and never consented to its terms. As such, the Gas Sales Contract alone could not unilaterally alter or change the express terms of the 1951 Leases. Second, the Gas Sales Contract was a transaction between affiliates. Such transactions are inherently suspect and have been rejected by other courts. See, W.W. McDonald Land v. EQT Production, 983 F.Supp.2d 790 (S.D. W.Va. 2013) (“[T]he defendant cannot calculate royalties based on a sale between subsidiaries at the wellhead when the defendants later sell the gas in an open market a higher price”); Howell v. Texaco, 112 P.3d 1154 (Okla. 2004) (“an intra-company contract is not an arm’s length transaction [and] is not a legal basis on which a producer can calculate royalty payments”); Beer v. XTO Energy, 2010 WL 4767115 (W.D. Okla. 2010) (gas sales at wellhead between two controlled affiliated companies not appropriate for royalty calculation). Accordingly, EQT’s effort to unilaterally change the royalty valuation point was correctly rejected by the jury.

1 The applicable interstate pipeline index was/is the TETCO Market Zone “2”.

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10/08/2018