Many oil and gas leases in Pennsylvania contain a royalty clause known as a “market enhancement” clause. These clauses generally prohibit deductions unless the driller can demonstrate certain conditions. Drillers, however, routinely ignore these conditions and simply argue that everything they do to the gas enhances the value of the gas stream and results in better pricing. But when we take a closer look as to what is really happening, a troubling picture emerges.
For example, let’s assume that in 2012 the O’Donnell family signs an oil and gas lease with XYZ Drilling for their 700 acre farm in Lycoming County, Pennsylvania. The lease provides for a 20% royalty and contains a “market enhancement” royalty clause (the “MEC Clause”). The MEC Clause prohibits the deduction of any costs that are incurred transforming the gas into marketable form. Once the gas is in “marketable form”, the MEC Clause allows XYZ Drilling to deduct certain costs if those costs actually enhance the value of the gas and result in XYZ Drilling obtaining a better price for the O’Donnells’ gas.
XYZ Drilling drilled a single well on the O’Donnells’ property and named it the O’Donnell #1H Well. Because the O’Donnells’ property was large, it was not included in a drilling unit, so royalties from the O’Donnell #1H Well were only paid to the O’Donnells.
The O’Donnells believed that the MEC Clause was beneficial to them. They were told during the lease negotiations that no costs would be deducted unless XYZ Drilling obtained higher pricing by moving the gas to distant markets. The O’Donnells believed that it was fair for them to shoulder some of the costs of attaining a better price, because that meant a higher royalty for them.
Month after month, the O’Donnells receive royalty statements from XYZ Drilling for the O’Donnell #1H Well that contain deductions for post-production activities such as gathering, processing and transportation. When the O’Donnells call XYZ Drilling to ask for an explanation about these deductions, XYZ Drilling tells them that the deductions are proper because those activities enhance the value of the gas and result in a better price. The O’Donnells ask what the value of the gas was before these activities were performed, but XYZ Drilling declines to provide any details.
Instead, XYZ Drilling simply states that the Pennsylvania Supreme Court’s decision in Kilmer v. Elexco Land Services confirmed that these deductions enhanced value and that the deductions are legal and proper. The O’Donnells point out that the royalty clause at issue in Kilmer is much different that the MEC Clause in their lease and that, under the MEC Clause, XYZ Drilling has an obligation to show an actual enhancement in value before any costs can be deducted. Remarkably, XYZ Drilling responds by saying that Kilmer allows drillers to use the so-called “net-back method” regardless of the lease language.
The O’Donnell’s royalty statement for the O’Donnell #1H Well provides as follows:
As this royalty statement indicates, the reported value of the O’Donnells’ royalty without any deductions was $50,000. There were $22,600 worth of post-production costs deducted, which results in a net royalty of $27,400. According to XYZ Drilling, these post-production activities enhanced the value of the gas and enabled XYZ Drilling to obtain a “better price”. But, XYZ Drilling never actually shows how the purported $2.50 per unit was, and is, a “better” price than the other prices that were available. Nor does XYZ Drilling show how the $22,600 in purported costs resulted in XYZ Drilling getting the “better” price of $2.50 per unit. XYZ Drilling’s sole justification for the purported deductions is the Pennsylvania Supreme Court’s decision in Kilmer v. Elexco Land Services, 990 A.2d 1147 (Pa. Super. 2010). As detailed below, XYZ Drilling’s reliance on Kilmer is misplaced and is inconsistent with the mechanics of the MEC Clause.
In Kilmer v. Elexco Land Services, the oil and gas industry promoted royalty calculation via the “net-back” method. The Pennsylvania Supreme Court remarked that the goal of the “net-back method” “is to determine the value of the gas when it leaves the ground (hereinafter ‘at the wellhead) by deducting from the sales price the costs of getting the natural gas from the wellhead to the market.” Kilmer, 990 A.2d at 1149. The oil and gas industry urged that this calculation works “. . . 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.” Id. at 1154.
The “net-back method”, also known as the “work back” method, was described by commentator Byron C. Keeling as follows:
“The workback method rests on the theory that because oil and gas has greater value at a downstream sales location than at the wellhead, the lessee may determine the value of its production at the wellhead by “working backward” from the enhanced downstream sales price for its production–i.e., by subtracting from the downstream sales price the post-production costs that the lessee incurred to enhance the value of its production for sale in a downstream market. These post-production costs may include transportation, gathering, compression, treatment, and marketing costs. Thus, if a lessee sold its crude oil production at a downstream location for $80 a barrel after incurring $20 a barrel in post-production costs, the workback method would permit the lessee to calculate its royalty payments on the basis of a price or value at the wellhead of $60 a barrel.”
In the New Era of Oil and Gas Royalty Accounting: Drafting A Royalty Clause That Actually Says What the Parties Intend It to Mean, 69 Baylor L. Rev. 516, 532 (2017). Of course, this is all premised on the hypothesis that the gas always has a “greater value” downstream of the “wellhead” and that every cost incurred downstream from the wellhead automatically adds value. These assumptions are simply not true.
The authors contend that moving gas further away does not automatically increase its value. Contrary to the conventional wisdom of the gas industry, there are times when the gas is actually worth more in the vicinity of the actual wellhead instead of moving it far away. As such, the cost of moving the gas to remote locations does not always increase the value of the underlying gas stream. If that were the case, then Texas gas producers would have been shipping large volumes of gas to this region in February 2021 when record cold in Texas caused pricing there to soar. In reality, Texas-produced gas had greater value in Texas than it did in Pennsylvania. Paying any cost to move that gas from Texas to Pennsylvania would not have added or increased any value. In fact, it would have been a cost that drillers incurred to obtain a lower value.
Moreover, if the mere act of moving gas enhances its value, one would have expected Pennsylvania drillers to have moved as much Marcellus Shale gas as possible to distant markets (i.e., Texas) at that time because, as the driller’s narrative goes, the value of gas is always and automatically enhanced by simply moving it further away. This did not happen. The robust market in Texas and the Lower Midwest should have resulted in Pennsylvania landowners seeing higher commodity prices in their royalty statements. This also did not happen. Why? Because moving the gas further away sometimes is more costly than simply selling the gas locally. Whether the remote price is “better” has to take into account the cost of moving that gas to that remote location and the actual market conditions in the vicinity of a well.
That is why drillers must be compelled to demonstrate actual “value enhancement” and “better prices” under market enhancement clauses. As the Kilmer court described, the net-back method of royalty calculation includes charges to move the gas to the market. Kilmer at 1149. The existence of a market is necessary for gas to be marketable. Moving a commodity to the place where it is bought and sold is not adding any value. It is attaining an initial value.
If a driller can show that their gas was in a condition and viable marketplace location where it could have been sold for a certain value, but then incurred additional costs to move that same gas to a different and more remote location in order to get a higher and better price, then those movement costs are arguably enhancement costs that could be deductible under a market enhancement clause. For example, few royalty owners would complain if a driller presented information that it could sell its entire volume of gas in Pittsburgh for $2.09 per unit, but instead incurred $.30 per unit of costs to sell the gas in New York City for $3.00 per unit. But, all too often, the gas industry, like XYZ Drilling in this case, do not have a point of comparison and instead rely on the “net-back method” to show an alleged enhancement and purported better pricing. However, there is no “better price” for landowners under the “net-back” approach, as the O’Donnells’ royalty check shows.
Based on the O’Donnells’ royalty check, XYZ Drilling sold the gas at $2.50 per unit. But, the O’Donnells were not paid based on this $2.50 per unit price. That is the $50,000 “Owner Revenue” that they were not paid. Instead, the O’Donnells actually received $27,400. Using basic cross-multiplication from middle school, it is easy to calculate the per-unit value of gas that the O’Donnells’ royalty was based on:
Under the net-back method, the O’Donnells’ royalty was therefore based on an artificial value of $1.37 per unit. This math is confirmed a different way:
The reason for this is obvious. When gas companies like XYZ Drilling attempt to justify deductions under a market enhancement clause using the “net-back method”, there is no actual comparison being made. There is no initial value at one location which can then be compared to a different but alternative downstream sales location to see if there was a “better price” and whether the product’s “value” was enhanced. An actual comparison is critical in order to ascertain and verify if the costs actually increased the value of the gas by simply moving it to a distant and remote sales location.The result: the O’Donnells’ royalty is exactly the same whether the wellhead value of the gas is used or whether the purported downstream “enhanced” value is used. The “value adding” activities such as gathering, processing and transportation do not increase the O’Donnells’ royalty under the “net-back method”. These so-called “value adding” activities simply do not result in a better price for the O’Donnells.
The “net-back method” does not take into account the value of the gas at other potential sales locations. Instead, it artificially creates a value of the gas “at the wellhead” based on what that same gas is worth several miles downstream, minus intervening post-production costs. This is a one of the critical flaws in Kilmer the belief that the “net-back” method “eliminates the chance that lessors would obtain different royalties on the same quality and quantity of gas coming out of the well depending on when and where in the value added production process the gas was sold.” Kilmer at 1158. Our example from this winter is instructive.
Consider 2 adjoining landowners in Texas. One landowner has a lease with a driller that sold gas for several hundred dollars per unit in that region. That landowner was paid a royalty under the ”net-back” method for gas based on this high price. The neighboring landowner has a lease with a driller that moved all of its gas to New Jersey, based on the belief that moving gas always gets a better value. That landowner gets paid a “net-back:” royalty as well. Both landowners, on adjoining properties, are being paid a wellhead price based on the “net-back” method. But, they are being paid radically different prices. How can wellhead pricing be so different? The reason is because the wellhead price derived from the “net-back” method is artificial and is not an actual price.
Whether gas is sold downstream from the well for $2.50 per unit or $10.00 per unit, the “net-back method” will never result in a “better price” for the O’Donnells’ royalty. The wellhead price will always be the downstream price less costs. That means that the royalty calculation using a wellhead price or using the downstream price, less costs, results in the exact same value. Contrary to what XYZ Drilling told the O’Donnells here, and what the gas industry frequently claims, the “net-back method” does not demonstrate or prove better pricing for landowners by moving gas and incurring costs to do so.
Landowners with market enhancement clauses should carefully review their royalty statements and pay particular attention to the commodity prices reported in their statements. If these prices remain below nearby index prices but the gathering and transportation costs remain the same, it is difficult to justify how these movement costs resulted in better pricing. In such situations, the driller should be required to provide data and documentation demonstrating that the costs actually enhanced the value of the gas and resulted in a better price. As noted above, merely citing the purported “net-back method” is not a viable or legitimate response.