Sixth Circuit Rules That Driller Must Pay Royalties On Natural Gas Liquids
Imagine you on 135 acres in Butler County, Pennsylvania. You signed an oil/gas lease with XYZ Drilling and you are now receiving production royalties from the three Marcellus Shale wells drilled nearby. Over Cinco de Mayo, you got together with your cousins who own acreage in Washington County. Your cousins inform you that they have also signed an oil/gas lease for their 110 acres but with ABC Production. They are elated with their production royalties – they are getting a royalty for the so-called “dry” gas and also a separate royalty for the natural gas liquids (NGLs) produced from the same wells. Your royalty contains no such line item. Your cousin’s royalty payments are significantly larger than the payments you are receiving. Is XYZ Drilling obligated to pay you a royalty on both the “dry” gas and the any NGLs produced from the same wells? A recent decision from the Sixth Circuit suggests that a driller must pay a royalty on the NGLs produced along with the “dry” gas.
Natural gas, as produced at the wellhead, can have various chemical compositions. In certain areas of Pennsylvania, the gas is nearly entirely methane. This type of gas is known as “dry” gas. The most notable example of “dry” gas is the distinct blue flame that emerges when you turn on your kitchen stove. “Dry” gas is found throughout the Marcellus region but is especially predominant in Tioga, Bradford, Susquehanna and Lycoming counties. Some areas, such as Western Pennsylvania, have what is known as “wet” gas. This gas contains not only methane but also contains heavier hydrocarbon molecules such as ethane, propane and butane. When the temperature or pressure of the gas stream is reduced, these molecules can condense into a liquid form, hence the term “natural gas liquids”.
Unlike “dry” gas, “wet” gas requires significant processing and must be fractionated in order to separate the various NGL products from the gas stream. These post-production activities take place downstream from the well-head at a processing plant. Typically, “dry” gas and NGLs are marketed and sold separately thereby generating two distinct revenue sources. Questions have arisen whether a driller must calculate and pay a royalty on the “dry” residue gas as well as a separate royalty on the downstream NGL products or if the driller can simply calculate a single royalty on the combined, unprocessed volume of raw gas metered at the well-head. In EQT Production Company v. Magnum Hunter Production (No. 18-5372, April 10, 2019), the United States Court of Appeals for the Sixth Circuit Court ruled that a separate royalty was owed on NGLs but the post-production costs incurred during the processing and fractionation of the NGLs could be deducted.
At issue in Magnum Hunter were several “farmout agreements” (“FOA”) entered into between EQT and Magnum Hunter Production (“MHP”). The FOAs allowed MHP to drill wells on lands leased by EQT in Eastern Kentucky and to sell the oil or gas produced by those wells. In exchange, EQT would receive a royalty based on “the gross proceeds received from the sale of oil and/or gas produced from the wells hereunder without deductions of any kind.” In December 2008, MHP built a processing plant and began transporting gas from the FOA wells to that facility, where it was converted into NGLs. Despite the clear language set forth in the FOAs, MHP deducted transportation and processing costs from the NGL revenue, then used the difference as the basis for calculating EQT’s royalty on the NGLs. In 2015, MHP ceased paying any royalty on the NGL sales.
In May 2016, EQT filed a complaint in the Eastern District of Kentucky seeking, inter alia, the payment of unpaid NGL royalties and reimbursement for the transportation and processing costs deducted from the NGL royalty calculation between 2009 and 2015. EQT claimed that it was owed $776,862 in unpaid NGL royalties. EQT further argued that the NGL royalties should be paid without any deductions. These costs were approximately $206,926. MHP defended the suit on the grounds that NGLs were not covered by the FOAs and therefore it had no contractual obligation to pay any royalty on the NGLs.
In July 2017, MHP moved for summary judgment on EQT’s NGL claim. Specifically, MHP argued that it only owed a royalty on the sale of NGL’s if they qualified as “oil and/or gas” the under the FOAs. Since the FOAs themselves only referenced “oil and/or gas”, and not liquids, MHP argued that the NGLs were simply not covered by the FOAs. The District Court agreed and granted MHP’s motion.
In ruling in favor of MHP, the District Court made two questionable observations. First, the District Court noted that nine (9) of the FOAs incorporated the Kentucky statutory definition of “gas well”. The Kentucky code defined such a well as one which “produces natural gas not associated or blended with crude petroleum”. Since the statutory definition of “gas well” only referenced “natural gas”, the District Court concluded that such a definition, and by extension the FOAs, excluded NGLs. With respect to the remaining FOAs, the District Court noted that those instruments did not define the terms “oil” or “gas” and did not incorporate the Kentucky code definition. As such, the District Court curiously turned to Webster’s dictionary and opined as follows:
“According to Merriam-Webster’s Dictionary of English Usage, “gas” is “a fluid (such as air) that has neither independent shape nor volume but tends to expand indefinitely.” By contrast, “liquids” are “neither solid nor gaseous.” See Merriam-Webster’s Dictionary of English Usage. Because NGLs are liquid in form, rather than gaseous, the Court finds that the term “gas”, as it is used in these two FOAs, unambiguously excludes NGLs.”
EQT appealed the District Court’s decision to the Sixth Circuit. The appellate panel rejected the District Court’s reasoning and held that the NGLs were covered by the FOAs. The Sixth Circuit noted that the District Court erred when it ignored the definition of “oil and gas” which was appended to some of the FOAs. This definition provided that the term “oil and gas” meant “oil, gas, casinghead gas, gas condensate and/or all other liquids or gaseous hydrocarbons and other marketable substances produced therewith…” Although this addendum was not attached to all eleven (11) FOAs, the Sixth Circuit concluded that it was credible evidence of the parties’ intent to include all hydrocarbons produced by the FOA wells. The panel criticized the District Court’s flawed reasoning:
“[I]n this context, there is no dispute that “gas” means “natural gas.” NGLs are produced from natural gas. To the extent the FAOs are silent or ambiguous as to whether components or by-products of natural gas are included within the term “gas”, the court can look to extrinsic evidence, such as the subject matter of the contract and the parties’ intent…”
Given the broad definition of “oil and gas” set forth in the addendum, and the fact that NGLs are “produced from natural gas”, the Sixth Circuit ruled that NGLs were covered by the FOAs. As such, EQT was owed a royalty on the sale of NGL products.
The author submits that this was the correct interpretation as it would be illogical to conclude that some hydrocarbons are subject to a royalty but others, from the ostensibly the same gas stream, are not. Although no Pennsylvania court has specifically addressed this question, the Pennsylvania Supreme Court in United States Steel Corp. v. Hoge, 468 A.2d 1380 (Pa. 1983) did observe that “natural gas” has various molecular components, including natural gas liquids. Given the Pennsylvania Supreme Court’s observation in Hoge, it is plausible that the High Court would reach the same conclusion as the Sixth Circuit.
However, the Sixth Circuit did not stop there. Despite the clear prohibition on deductions set forth in the FOAs, the panel held that MHP could deduct the costs incurred to process and transport the NGLs. This is because Kentucky, unlike Pennsylvania, strictly applies the “at the wellhead” rule. In Kentucky, when a lease or royalty agreement is “silent” as to the place of market and the price of the gas, the default royalty calculation is the “at the wellhead” rule, which allows deductions for post-production costs. See, Baker v. Magnum Hunter Production, Inc., 473 S.W.3d 588(Ky. 2015) (“[V]alue ‘at the well’ is thus the default measure of royalty in Kentucky when a lease is silent….”). EQT argued that the FOAs were not silent, as they specifically stated that the royalty was to be paid “without deduction of any kind”. The Sixth Circuit, in rather circular reasoning, opined that the mere prohibition on deductions did not “explain where gas is to be sold or for how much” and, therefore, in the Panel’s view, the FOAs were silent on that issue.
1 A farmout agreement is “a very common form of agreement between operators, whereby a lessee not desirous of drilling at the time agrees to assign the lease…to another operator who is desirous of drilling the tract.” See, Williams & Meyers, “Manual of Oil and Gas Terms”, p. 336 (14th Ed, 2009).
