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 gas into marketable form. Once the gas is in marketable form, these clauses generally allow a driller to deduct further costs only if those costs actually enhance the value of the gas. All too often, drillers ignore this 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.  Given this assumption, the drillers further argue that all costs after that point are deductible under a “market enhancement” clause. The Pennsylvania Superior Court’s recent decision in Dressler Family, LP v. PennEnergy Resources, LLC, 276 A.3d 729 (Pa. Super. Ct. 2022), together with the Pennsylvania Supreme Court’s decision in Kilmer v. Elexco Land Services, Inc., 990 A.2d 1147 (Pa. 2010) should put drillers’ argument to rest.

In Dressler Family, the driller deducted post-production costs even though the parties’ lease did not expressly authorize deductions.  In fact, the parties’ lease required the royalty to be calculated on the “gross proceeds” received. The driller ignored this language and instead argued that it was entitled to deduct post-production costs because Kilmer purportedly authorized the use of the “net-back method” of royalty calculation, which involves deducting post-production costs incurred between the wellhead and the downstream sales point. The trial court agreed with the driller but the Superior Court reversed, which is good news for royalty owners because it makes clear that the actual terms of a lease must be given effect and not pushed aside based on a “one size fits all” standard.

A notable part of the Superior Court’s opinion in Dressler Family is the statement that the driller “. . . maintains the oil and gas industry has evolved such that there is generally no market to sell natural gas at the wellhead.” Dressler Family, LP, 276 A.3d at 740. This is a critical observation that undermines the central premise of the drillers’ defense in royalty disputes.

A frequent narrative asserted by drillers is that gas is marketable at the wellhead and that all costs incurred downstream from the wellhead necessarily enhance the value of the raw gas. This is not accurate.  In the Marcellus Shale region, gas is rarely sold at the wellhead as there is generally no competitive market at that location.  Most shale gas is sold on the interstate pipeline network.  Given the lack of any true marketplace at the wellhead, an argument can be made that the gas is not marketable until the driller moves that gas to the actual marketplace (i.e., the interstate pipeline network).  See, Pummill v. Hancock Exploration, LLC, 414 P.3d 1268 (Okla. Ctr. App. 2018) (gas not in marketable form until it reaches the intended market for that gas); Cooper Clark Foundation v. Oxy USA, Inc., 469 P.3d 1266 (Kansas Ct. App. 2020) (“[T]he concept of marketability is tied to the market for the gas”). If there is no market to sell gas at the wellhead, then the gas is not “marketable” at that location. Drillers must incur costs to make the gas marketable by physically moving the gas to the marketplace and placing the gas in a condition that is acceptable at that marketplace. The costs of moving gas in a gathering system and undertaking dehydration/processing activities are all associated with making the gas “marketable” when there is no market at the wellhead.

Surprisingly, this is not a new concept in Pennsylvania oil and gas law. However, it is a point that does not get the attention that it deserves. The drillers’ concession about marketability in Dressler Family is similar to the primary argument advanced by the drillers over a decade ago in Kilmer. In that case, the oil and gas lease in question called for a one-eighth (12.5%) royalty and expressly allowed the deduction of “all costs actually incurred by Lessee from and after the wellhead to the point of sale, including, without limitation, all gathering, dehydration, compression, treatment, processing, marketing, and transportation costs incurred in connection with the sale of such production.” Kilmer at 1150.

The Pennsylvania Supreme Court was asked to determine whether the Kilmer lease violated Pennsylvania’s Guaranteed Minimum Royalty Act (the “GMRA”). The GMRA provides that:

A lease or other such agreement conveying the right to remove or recover oil, natural gas or gas of any other designation from lessor to lessee shall not be valid if such lease does not guarantee the lessor at least one-eighth of all oil, natural gas or gas of other designations removed or recovered from the subject real property.

58 P.S. 33. The Kilmer court correctly reasoned that its decision in the case would be driven by the definition of “royalty” in the GMRA statute.

The Supreme Court reflected on the drillers’ suggested definition of royalty and observed that:

The Gas Companies note that there are two basic ways to receive a royalty—either as a portion of the actual product (“in-kind”) or the monetary equivalent. While theoretically possible, the Gas Companies acknowledge that it is generally impractical for a landowner to take a natural gas royalty in-kind, at least when the gas is removed at the wellhead, because that would require the landowner to perform extensive post-production activities that are necessary to process the gas into a usable and thus marketable product. Therefore, to calculate the price of the 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. As mentioned, this calculation is often referred to in the industry as the “net-back” method of calculating royalties.

Kilmer, 990 A.2d at 1154 (emphasis added). This was, and remains, a significant concession by drillers regarding the question of marketability.

To be clear, the drillers in Kilmer argued that post-production costs are associated with “. . . turning the gas into a marketable commodity” to obtain a “. . . value-added price received at the point of sale”. Kilmer, 990 A.2d at 1154. Therefore, if post-production costs are associated with turning gas into a “marketable commodity” at the downstream point of sale, then the gas is necessarily not a “marketable commodity” until those post-production activities (i.e., dehydration, processing, gathering, etc.) are performed.

The Kilmer court incorrectly assumed that the activities to turn gas into a marketable commodity automatically and universally add value. They do not. As noted, there is no market for gas at the well in Pennsylvania. See, Dressler Family, LP, 276 A.3d at 740. In the absence of a genuine market at the well, there is no value for gas at that location. Drillers must therefore incur costs after gas is produced to turn the gas into a marketable commodity. See, Kilmer, 990 A.2d at 1154. Those costs associated with the getting the gas tothe marketplace and in a form that can be bought and sold in the marketplace are all activities that make the gas “marketable”. They create value – they do not add value.

This is not to say that all post-production cost deductions run afoul of typical “market enhancement” clauses. There can be instances when drillers decide to move gas from one marketplace location to another, more lucrative marketplace location for minimal cost. But, based on the drillers’ concessions in Dressler Family and Kilmer, there is not an automatic enhancement of gas value simply by moving the gas from the wellhead to the prevailing commercial marketplace (i.e., the interstate pipeline network).

The takeaway is this: Pennsylvania landowners with “market enhancement” clauses should be mindful and wary of any deductions associated with the movement of gas (i.e., gathering or transportation charges).  Unless the driller can provide facts and evidence demonstrating that such costs changed or improved the content and quality of the raw gas, an argument can be made that such costs are not really enhancement costs- they are simply necessary costs that must be incurred in order to actually sell the gas.  As such, they should not be deductible.  See, Mittelstraedt v. Santa Fe Minerals, 954 P.2d 1203 (Okla. 1998) (“…the lessee may not deduct from royalty payments the costs of gathering, transportation, compression, dehydration or blending if those costs are required to create a marketable product…”); Cooper Clark, supra. (“[W]hen the parties have agreed that the gas will be sold in the interstate market, the gas company cannot deduct expenses required to make the gas marketable for that interstate market”). It is submitted that there is a valid and legitimate distinction between a true enhancement cost versus an operational cost. Unfortunately, drillers in Pennsylvania routinely ignore this distinction and consider each and every cost an enhancement that can be deducted. 

Even if the purported cost somehow enhanced the value of the gas, it can only be deducted if that particular cost resulted in the driller getting a better price for the gas. This means that the sales price at the distant location must be better (i.e., higher) than if the gas was simply sold closer to home with minimal movement costs. Landowners should carefully review their royalty statements and pay particular attention to the commodity prices reflected in their statements. If these prices are consistently below nearby index prices but the costs to move the gas remain the same, it is difficult to justify how these movement costs are resulting in better pricing.