As the Marcellus Shale development enters its seventeenth year, drillers are becoming more creative and aggressive in their effort to avoid lease language that was intended to prohibit or restrict the deduction of post-production costs. Many landowners sought to insulate their royalties from such deductions by negotiating royalty clauses which either expressly or implicitly designated the royalty valuation point as being at the point-of-sale, as opposed to the wellhead. The effect of this subtle yet critical distinction was to preclude application of the so-called “net back” method. Under this method, drillers may deduct costs incurred between the wellhead and the downstream point-of-sale. Conversely, when the point-of-sale is designated as the royalty valuation point, drillers are, in theory, prohibited from deducting those intervening costs. This is typically accomplished by drafting a royalty clause which states that the royalty will be paid on the “price paid” to the driller or the “proceeds received” by the driller. But, what happens when the royalty clause inadvertently references both valuation methods? Unfortunately, many oil and gas leases in Pennsylvania contain this drafting ambiguity. And drillers have seized on this ambiguity. They now routinely argue that any reference to the wellhead in the royalty clause, regardless of context, automatically means that the royalty must be valued at that location. A federal court in Pittsburgh recently adopted this “form over substance” argument and ruled that deductions were proper despite lease language that required the royalty to be based on the “gross sales price.”
At issue in Coastal Forest Resources v. Chevron USA, Inc., was a November 21, 2007 oil and gas lease concerning 356 acres in Greene County, Pennsylvania (the “2007 Lease”). The royalty clause in the 2007 Lease provided as follows:
Gas: To pay Lessor as royalty for all gas and the constituents thereof, including all liquid, solid or gaseous substances produced and saved from any sand or sands on the leases [sic] premises, an amount equal to five-thirty-seconds (5/32) or 15.625% of the gross sales price received by Lessee from the sale of such gas and the constituents thereof at the wellhead.
In April 2020, the lessee, Chevron Appalachia, LLC (“Chevron”), tendered production royalties to the landowner from eight (8) wells located in the “Commonwealth A Northwest Unit”. The landowner contested and disputed Chevron’s practice of deducting post-production costs from their April 2020 production royalty. These costs totaled $53,834. Chevron refused to cease taking such deductions and refused to reimburse the landowner. On July 24, 2020, the landowner filed suit alleging a material breach of the 2007 Lease.
In November 2020, Chevron filed a Motion to Dismiss under F.R.C.P. 12(b)(6). Chevron argued that because the royalty clause contained the phrase “at the wellhead”, the 2007 Lease was automatically and unequivocally controlled by the Pennsylvania Supreme Court’s decision in Kilmer v. Elexco Land Services, 990 A.2d 1147 (Pa. 2010). Under Kilmer and its progeny, when gas is sold downstream of the wellhead, the purported netback method is used to allocate post-production costs between the lessor and the lessee in order to arrive at a wellhead value. Here, the gas was sold downstream from the wellhead. Chevron therefore utilized the netback method to deduct gathering and other processing costs incurred between the wellhead and the eventual downstream point-of-sale. Such practice, according to Chevron, was authorized and permissible under Kilmer. Chevron’s argument, however, assumed that the 2007 Lease expressly designated the wellhead as the royalty valuation point. In addition, Chevron’s argument essentially required the court to ignore the phrase “gross sales price received by Lessee” set forth in the royalty clause. Under Chevron’s theory, this language meant nothing and was completely pre-empted by the “at the wellhead” reference.
Before we address the substance of the Coastal Forest Resources opinion, a brief review of the various components of a typical royalty clause is warranted. As the Texas Supreme Court recently observed, each royalty clause essentially has three (3) components: i) the royalty fraction (e.g., 12.54% of 16.5%), ii) the “yardstick” (e.g., market value, proceeds or price) and iii) the location for measuring the yardstick (e.g., at the wellhead or the point-of-sale). See, Bluestone Natural Resources v. Walker Murray, (No. 19-0469, March 12, 2021). Let’s briefly examine the second and third components.
The “yardstick” component provides guidance as to the source of the royalty. There are typically two “yardsticks” which are utilized in modern oil and gas leases: the market value of the gas or the actual proceeds received from the sale of gas. The Texas Supreme Court further described the two “yardsticks” as follows:
“Proceeds” or “amount realized” clauses required measurement of the royalty based on the amount the lessee in fact receives under its sales contract for the gas. Union Pac. Res. [Grp.] v. Hankins, 111 S.W.3d 69, 72 (Tex. 2003) (citing Yzaguirre [v. KCS Res., Inc.], 53 S.W.3d [368,] 372 [(Tex. 2001)]). By contrast, a “market value” or “market price” clause requires payment of royalties based on the prevailing market price for gas in the vicinity at the time of sale, irrespective of the actual sale price. Yzaguirre, 53 S.W.3d at 372. The market price may or may not be reflective of the price the operator actually obtains for the gas. Id. At 372-73.
See, Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008).
There are two methods of determining the market value of gas: i) comparable sales or ii) the netback method. Under the comparable sales method, the value of the gas at the wellhead is calculated by averaging the prices that the driller and other producers have received in the same production field for gas of comparable quality and quantity. Evidence of comparable sales, however, is often difficult to ascertain, so the work-back or netback method developed as the preferred alternative. Under this method, the value of the gas at the wellhead is calculated by taking the downstream sale price and subtracting the processing and movement costs incurred between the wellhead and the point-of-sale. See, Atlantic Richfield v. State, 262 Cal. Rptr. 683, 688 (Cal. Ctr. App. 1989) (noting that the royalty is calculated “by working back from the price of the point-of-sale, deducting the cost of processing and transportation from the wellhead.”) Thus, when there is no actual market for gas at the wellhead or when there is insufficient evidence of comparable sales, the netback method allows a driller to calculate the value of the gas at the wellhead by subtracting the intervening costs. See, Kilmer v. Elexco Land Services, 980 A.2d 1147 (Pa. 2010) (“…we must work backward from the value-added price received at the point-of-sale by deducting the companies’ cost of turning the gas into a marketable commodity”).
The second “yardstick” measures the royalty on the proceeds actually received by the lessee. The Texas Supreme Court has consistently held that under a “proceeds” clause or an “amounts realized” clause, the landowner is granted “the right to a percentage of the sale proceeds with no adjustment for post-production costs.” See, Burlington Resources, 573 S.W.3d 198 (Tex. 2019); see also, Chesapeake Exploration, LLC v. Hyder, 483 S.W.3d 870, 871 (Tex. 2016) (noting that under a ‘proceeds lease’, the “price-received basis for payment in the lease is sufficient itself to excuse the lessors from bearing post-production costs”); Warren v. Chesapeake Exploration, 759 F.3d 413 (5th Cir. 2014) (stating that an “amount realized” clause, standing alone, will create a royalty interest free of post-production costs); Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008) (“[P]roceeds clauses requires measurement of the royalty based on the amount the lessee in fact receives under its sales contract for the gas”); Judice v. Mewbourne Oil Co., 939 S.W. 2d 133 (Texas 1996) (“the term gross proceeds means the royalty is to be based on the gross proceeds received…”). So, unlike the market value “yardstick”, the proceeds “yardstick” is typically free of post-production costs. Both “yardsticks”, however, can be impacted by the third and final component: the location where the “yardstick” is measured.
The third component is critical. It establishes the point from which the lessee, if necessary, “works back” to calculate and determine the value of the gas. See, Bluestone Natural Resources, supra. The “yardstick” is typically measured at either two locations: at the wellhead or at the point-of-sale. This is commonly known as the royalty valuation point. If the valuation point is designated at the wellhead, but the gas is actually sold downstream, then, in that instance, the driller may utilize the netback method to deduct the intervening processing and movement costs to arrive at a wellhead value. Conversely, if the royalty valuation point is at the point-of-sale, there is no need to work backwards to the wellhead and no costs need to be deducted. In practice, the second “yardstick” (i.e., proceeds) is usually measured at the point-of-sale. See, Bluestone Natural Resources, supra. (“[W]hen proceeds are valued in gross…the valuation point is necessarily the point-of-sale because that is where the gross is realized or received.”). Confusion can arise when the royalty clause inadvertently contains language which purports to measure the second “yardstick” at the wellhead.
The royalty clause in Coastal Forest utilized the second “yardstick”. The royalty was to be measured on the “gross sales price received by the lessee.” In theory, this should have precluded the deduction of any post-production costs. See, Bluestone Natural Resources, supra. (“…an ‘amount realized’ clause, standing alone, creates a royalty interest that is free of post-production costs”). However, instead of identifying the royalty valuation point as being the point-of-sale, the royalty clause inexplicably referenced the wellhead as a potential valuation location. This reference created an inherent ambiguity.
On May 11, 2021, Judge Stickman of the Western District ignored this ambiguity and entered an order granting Chevron’s Motion and dismissing the Complaint. Judge Stickman was persuaded by Chevron’s “form over substance” argument and held that:
“[T]he contract here unquestionably calls for the calculation of royalties at the wellhead. Under Kilmer, at the wellhead language means that the net-back method maybe used for calculation.”
The author submits that this was clear error. While Kilmer did authorize use of the netback method, it did not create a universal rule that allows deductions under each and every lease. Moreover, a royalty clause that identifies the “yardstick” as being the “gross sales price” is at odds with “at the wellhead” language. As the Texas Supreme Court once observed, “there is an inherent, irreconcilable conflict between ‘gross proceeds’ and ‘at the wellhead’ in arriving at the value of gas”. See, Judice v. Mewbourne Oil Co., 939 S.W.3d 133 (Tex. 1996) The Texas Supreme Court has further opined that such a conflict renders the royalty clause ambiguous on its face. See, Bluestone Natural Resources, supra (“…the joinder of the terms ‘gross proceeds’ and ‘at the wellhead’ gives rise to an inherent conflict that renders a royalty clause ambiguous”). It is well-settled that the existence of contractual ambiguity precludes the entry of a motion to dismiss. See, Canters Deli v. Freedompay, Inc., 460 F.Supp.3d 560 (E.D. Pa. 2020) (“[A]scertaining the correct interpretation requires inquiry into extrinsic evidence and, as such, is not appropriate for resolution on a motion to dismiss…). Such ambiguity creates a factual question that must be resolved by the jury. See, Welding Engineers v. NFM/Welding Engineers, 352 F.Supp.3d 416 (E.D. Pa. 2016) (“[W]hen a term is deemed ambiguous, its interpretation is a question for the jury”). Given this ambiguity in the royalty clause, Chevron’s Motion should not have been granted.
It is unclear what the parties intended by this royalty clause. On one hand, they selected a “yardstick” that forecloses the deduction of post-production costs. On the other, they selected a valuation point that invites use of the netback method. The District Court should have denied the Motion and given the landowner the opportunity to create a factual record as to what the parties actually intended when the royalty clause was originally negotiated and drafted. Nonetheless, the take away from Coastal Forest Resources is clear: avoid any reference to the wellhead if the intent is to provide a cost-free royalty based on the proceeds realized or received.