The Oil and Gas Addendum

Many Pennsylvania landowners have leases with “market enhancement” royalty clauses. These clauses typically prohibit the deduction of any post-production costs that are incurred transforming the raw gas or oil into marketable form. Once the hydrocarbons are in marketable form, these clauses generally allow a driller to deduct further costs only if those costs actually enhance the value of the oil and gas. All too often, drillers ignore the language and deduct all “post-production costs” from the landowner’s royalty based on the drillers’ incorrect assumption that gas is “marketable” at the wellhead.  See, Is the Value of Your Gas Really Being Enhanced? (July 2022). Given this assumption, the drillers further argue that all costs after that point are deductible under any “market enhancement” clause.  The genesis of “market enhancement” clauses can be traced to what are known as “first marketable product” jurisdictions – Colorado, Kansas, Oklahoma and West Virginia.  These jurisdictions put greater significance on the “implied duty to market” and generally require the driller to bear all costs necessary to achieve a marketable product.  In other words, no costs can be deducted unless and until the raw hydrocarbons are in marketable form. A recent decision by the federal district court in Colorado has injected unnecessary confusion and ambiguity into this settled principle. As discussed below, landowners with “market enhancement” clauses should carefully monitor the Boulter, et al. v. Noble Energy, Inc. matter as the controversial opinion is now on appeal before the Tenth Circuit.

At issue in Boulter, et al. v. Noble Energy, Inc. were two oil and gas leases entered into in 1981 concerning approximately 270 acres in Weld County, Colorado (the “Subject Leases”). The Subject Leases had the same oil royalty clause which provided as follows:

“[T]o deliver to the credit of the lessor, free of cost, in the pipeline to which the lessee may connect its wells, the equal 15% part of all oil produced and saved from the leased premises, as royalty, or at lessee’s election, to pay the lessor for such royalty the market price prevailing that day the oil is run into the pipeline, or in storage tanks.”

Noble acquired the Subject Leases in 2014 and began operating and producing the 168 wells (the “Lease Wells”) located on the Leased Premises. All of the oil produced by the Lease Wells was collected and gathered by third-party trucking companies who charged Noble “trucking fees” to transport the oil from the Lease Wells to a terminal located in Platteville, Colorado. Once at the Platteville terminal, the oil would enter two transmission pipelines (the Saddlehorn Pipeline or the White Cliffs Pipeline) which moved the oil from the Platteville terminal to a refinery in Cushing, Oklahoma (the “Cushing Refinery”). The oil was then sold to third-parties at the Cushing Refinery using the posted NYMEX index price.

Under the terms of Noble’s agreements with Saddlehorn and White Cliffs, both operators charged Noble a “tariff” to move the oil through each pipeline.  Noble in turn deducted the tariffs incurred under the Saddlehorn and White Cliffs gathering agreements from Boulter’s oil royalty. Noble also deducted the costs associated with “unloading” the oil from the trucks at the Platteville terminal as well as the “pumpover” charges incurred to distribute the oil from the Saddlehorn and White Cliffs pipelines to the storage tanks at the Cushing Refinery.  Boulter objected to these deductions and brought suit in March 2024.

In his suit, Boulter argued that the plain language of the Subject Leases did not authorize the deduction of any costs incurred moving the oil from the Lease Wells to the Platteville terminal or from the Platteville terminal to the Cushing Refinery. Alternatively, he argued that to the extent the Subject Leases were “silent” on the allocation or deduction of post-production costs, then the “implied duty to market” was implicated and, under Colorado law, Noble was solely responsible for the cost of transporting the oil to the first commercial marketplace (i.e. the Cushing Refinery). Boulter’s claim essentially relied upon the seminal decision of the Colorado Supreme Court in Rogers v. Westerman Farm Co., 29 P.3d 887 (Col. 2001). In Rogers, the Colorado Supreme Court addressed the scope and effect of the “implied duty to market” and explained that:

“[A]bsent express lease provisions addressing the allocation of costs, the lessee’s duty to market requires that the lessee bear the expenses incurred in obtaining a marketable product. Thus, the expense of getting the product to a marketable condition and location are borne by the lessee. . .” (emphasis added)

Given the precedent of Rogers, Boulter contended that the oil was not “marketable” until it reached the Cushing Refinery.  See, Kansas Court Rules that Gas Is Not Marketable Until It Reaches Interstate Pipeline (August 2020). As such, all costs incurred moving the oil from the Lease Wells to the Cushing Refinery should not be deducted under Colorado law.[1]   

In response, Noble manufactured a novel defense that essentially added unwritten terms to the royalty clause.  Noble argued that the “plain language” of the Subject Leases did, in fact, allow Noble to deduct all post-production costs. As detailed below, Noble’s tortured interpretation of the royalty clause was, and is, convoluted and confusing.

Noble’s entire argument was premised on the notion that the royalty valuation point was “at the wellhead”. The Subject Leases, however, do not contain any reference to the wellhead and do not identify the wellhead as the valuation point.  Recognizing this factual dead-end, Noble instead created a mythical valuation point by relying on the first sentence of the royalty clause: “[f]ree of cost, in the pipeline to which [Noble] may connect its wells.” (emphasis added).

According to Noble, this clause obligated Noble to deliver oil “free of cost” only to the location on the leased premises where Noble “may” connect the Lease Wells to a pipeline. Costs incurred downstream from this location were not subject to this prohibition. Why? Noble postulated that since this purported connection point was at or near the wellhead, Noble insisted that this language was equivalent to the “at the wellhead” language found in other leases. As I have written before, this language can have legal significance. See, Pennsylvania Superior Court Rules That Royalty Clause Referencing Both ‘Gross Proceeds’ and ‘At the Well’ Was Ambiguous (May 2022). By designating the wellhead as the royalty valuation point, Noble could then utilize the net-back method to calculate a fictional wellhead price. The net-back method is an accounting tool that, when applicable, allows a driller to deduct costs incurred between the wellhead and the downstream point-of-sale (i.e. the Cushing Refinery). See, Potts v. Chesapeake Exploration LLC, 760 F.3d 470 (5^th Cir. 2014) (noting that the net-back method allows the driller to deduct “post-production costs incurred between the wellhead and a downstream point” so as to arrive at a “market value at the well”). But, in order to avail itself of the net-back method, Noble had to convince the court that the Subject Leases valued the royalty “at the wellhead.” Noble did this by magically creating a royalty valuation point at the purported pipeline connection point.

Noble had another hurdle to overcome. In order to avoid Rogers and the “implied duty to market”, Noble had to engage in an additional sleight of hand. Under Colorado law, if a royalty provision lacks specific language allocating post-production costs, it is deemed “silent” and the lessee must bear all costs incurred obtaining a marketable product.  See, Patterson v. BP Am. Production Co., 360 P.3d 211 (Col. App. 2015) (if lease is silent then the “implied covenant to market must be considered in determining the rights and obligations of the parties”). Although the Subject Leases never even mentioned the phrase “at the wellhead”, Noble argued that the phrase “in the pipeline” actually meant that same thing. Noble’s interpretation essentially asked the trial court to re-write the royalty clause and add a new term.  Noble’s sleight of hand was not unprecedented. The Texas Supreme Court implicitly encouraged such an interpretation of similar language in Engler Energy v. Bluestone Natural Resources, 639 S.W.3d 682 (Tex. 2022). I issued a stark warning about the troubling nature of the Engler Energy decision several years ago. See, Texas Supreme Court Issues Troubling Decisions in Royalty Dispute (March 2022).  Ironically, the Colorado Supreme Court in Rogers previously concluded that a royalty clause that contains “at the wellhead” language and nothing else is legally insufficient to re-allocate post-production costs. See, Rogers v. Westerman Farm Co., 29 P.3d at 902 (“. . . we decline to hold here that transportation costs are deductible from royalty payments as a matter of law when a lease includes ‘at the well’ language”). Nonetheless, Noble was not deterred and argued that the Subject Leases were not “silent” because of the passing reference to “in the pipeline”.

On January 30, 2026, the District Court granted Noble’s motion for summary judgment and dismissed Boulter’s Complaint.  The author submits that the District Court fumbled the ball here. The District Court adopted Noble’s tortured interpretation of the royalty clause and essentially ignored the holding of Rogers. The District Court’s casual and unpersuasive rejection of Rogers and the “implied duty to market” perhaps reflected a basic misunderstanding of oil and gas law.  Inexplicitly, the District Court opined that the “the royalty in this case is not monetary payments, it is oil”.  And based on that misunderstanding of the royalty clause, the District Court held that Rogers was simply inapplicable. This fundamental error warrants careful appellate review.  Accordingly, Boulter appealed the decision to the United States Court of Appeals for the Tenth Circuit on February 6, 2026.

Although Boulter, et al. v. Noble Energy, Inc. is not binding on Pennsylvania courts, the author believes drillers will argue with more confidence that the phrase “in the pipeline” has the same magical qualities as the proverbial “at the wellhead” language.  This is unfortunate and incorrect.  And the impact on landowner royalties could be significant. Under the flawed logic of the District Court, drillers can arguably deduct all costs incurred downstream from the meter at the pipeline interconnect, which is almost always at or near the wellhead.  This means the cost to move and gather the hydrocarbons from the wellhead to an off-site facility and then to further move the hydrocarbons to distant sales points can all be deducted under the auspices of the so-called net-back method.  Even when the underlying lease never mentions or suggests the wellhead as the royalty valuation point. This is not what the parties intended when they agreed to value the royalty “free of cost in the pipeline”. As such, Pennsylvania courts should reject the logic and rationale of the Boulter, et al. v. Noble Energy, Inc. and instead focus on the actual intent of the parties.

[1] By virtue of the Colorado Supreme Court’s decision in Garman v. Conoco, 886 P.2d 652 (Col. 1994), Colorado became the third “first marketable product” jurisdiction after Kansas and Oklahoma.