Why Is The Driller Deducting Post-Production Costs My Lease Doesn’t Allow? Kilmer V. Elexco Land Services: A Decade Later
You own a 175 acre farm in Washington County. In 2014, you signed an oil and gas lease with XYZ Gas Company. The royalty clause, which you specifically negotiated, states that you are entitled to a royalty of seventeen percent (17%) of the “proceeds” received by XYZ Gas from the sale of your hydrocarbons. The clause makes no mention of any deductions or valuing the royalty “at the wellhead.” Prior to signing the lease in 2014, you told the landman that you would not sign any lease unless it was a “gross royalty”. The landman assured you that XYZ Gas would not deduct any post-production costs. Last week, you received your first royalty statement. Much to your dismay, XYZ Gas deducted compression, gathering and transportation costs from your royalty. How can XYZ Gas deduct costs from your royalty given the clause you negotiated? You are frustrated, angry and confused. How is this possible? Throughout Pennsylvania, drillers typically give a one-word answer to such questions: Kilmer.
Ten years ago the Pennsylvania Supreme Court’s issued its controversial decision in Kilmer v. Elexco Land Services Inc., 990 A.2d 1147 (Pa. 2010). Drillers have argued over the last decade that Kilmer granted them an automatic and universal right to deduct post-production costs – even when the underlying lease says nothing about deductions. Kilmer created no such right and the opinion has been wrongfully extended far beyond the narrow issue that was actually before the Supreme Court. Over the last ten years, drillers have nonetheless used Kilmer as justification for deductions that should never have been taken or authorized. These authors submit that it is time to re-think and re-evaluate the scope of the Kilmer opinion before it causes more damage and harm to Pennsylvania royalty owners.
What was Kilmer about?
The Kilmer saga arises out of an oil and gas lease signed in 2007 concerning acreage in Susquehanna County. The royalty clause in the underlying lease specifically described how the royalty would be calculated and paid:
Royalty Payment. For all Oil and Gas Substances that are produced and sold from the leased premises. Lessor shall receive as its royalty one eighth (1/8th) of the sales proceeds actually received by Lessee from the sale of such production, less this same percentage share of all Post Production Costs, as defined below, and this same percentage share of all production, severance and ad valorem taxes. As used in this provision, Post Production Costs shall mean (i) all losses of produced volumes (whether by use as fuel, line loss, flaring, venting or otherwise) and (ii) 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. For royalty calculation purposes, Lessee shall never be required to adjust the sales proceeds to account for the purchaser’s costs or charges downstream from the point of sale.
Kilmer at 1150. The driller was producing gas and paid royalties, using the “net-back” calculation method, which the Pennsylvania Supreme Court defined as “one-eighth of the sale price of the gas minus one-eighth of the post-production costs of bringing the gas to market.” Id. at 1149.
Believing that the driller’s royalty calculation violated state law, the landowners brought suit, seeking a declaratory judgment that the “net-back” accounting method violated the Pennsylvania Guaranteed Minimum Royalty Act (“GMRA”). Id. at 1149. It is important to note that the landowners were not challenging the deductions per se- rather they were arguing that because the underlying royalty clause authorized the deduction of post-production costs, the net royalty would be below 12.5% and therefore the lease itself violated the GMRA. The GMRA mandates that all leases pay “at least one-eighth royalty of all oil, natural gas or gas of other designations removed or recovered from the subject real property.” 58 P.S. § 33.1. Although the GMRA used the term “royalty”, it did not define it. The Pennsylvania Supreme Court concluded its task in Kilmer was to determine and give effect to the General Assembly’s intent when it enacted the GMRA.
The Supreme Court recognized that the GMRA was enacted in a much different gas sales marketplace. When the GMRA came into effect, the sale of gas was largely regulated and pipeline companies generally did not operate as “common carriers” that moved others’ gas as they do today. Instead, the drillers themselves often sold the gas at the actual wells. Id. at 1155. When the GMRA was enacted, the point of sale for the gas and the point of royalty valuation was the same- both occurred at or near the wellhead.
From this background, the Kilmer court remarked that “we can assume that the General Assembly intended . . . that the royalty should be calculated at the wellhead and at the point of sale.” Id. “Given the current state of the industry where the wellhead and the point of sale are not the same, we are required to interpret which valuation point is most consistent with the language of the statute. This requires us to define royalty.” Id. The Supreme Court ultimately concluded that “consistent with our rules of statutory interpretation, we hold that the GMRA should be read to permit the calculation of royalties at the wellhead, as provided by the net-back method in the Lease.” Id. at 1158. By its own language, the holding of Kilmer was and is limited to the narrow question of whether a driller can take deductions and reduce the landowner’s net royalty below the statutory minimum without violating the GMRA. Nothing else was before the Court and nothing else was decided. Nonetheless, drillers have since argued that Kilmer gives them broad and unlimited discretion to deduct post-production costs anytime they want. That is simply untrue.
So, what is wrong with Kilmer?
Separate and distinct from the concern over how Kilmer has been wrongfully expanded, there are a number of foundational flaws in the Kilmer opinion itself. These flaws are all based on the Supreme Court’s mistaken view that the “net-back” calculation method provides the value of gas at the actual well. It does not.
- The Myth of the “Net-Back” Method
Kilmer was a statutory construction case, so it meant that the Pennsylvania Supreme Court had to give effect to the GMRA based on the intentions of the General Assembly at the time that the law was enacted ( i.e. 1979). Although the Supreme Court observed that the marketplace for gas sales changed radically between the GMRA’s enactment in the late 1970’s and the time when Kilmer was decided in 2010, the Kilmer panel overcomplicated the analysis and appears to have confused the issues.
The Supreme Court opined that the gas royalty was a share of the value of the gas at a particular location. Kilmer at 1157. The Merriam-Webster dictionary defines “value” as “the monetary worth of something”. At the time the GMRA was enacted, the commercial marketplace priced and valued the driller’s gas at the actual wellhead where it was sold to a counterparty. So, under the GMRA, the lessor received at least one-eighth ( i.e, 12.5%) of the value of the gas at the time and place of the sale in the dominant commercial marketplace. This context is important- at the time the GMRA was enacted, gas was sold at the wellhead. So, the minimum royalty guarantee under the GMRA was originally tied to the actual point of sale- the wellhead.
Today, gas pricing has moved away from the wellhead and is based on interstate pipeline locations. Throughout the Marcellus region, gas is rarely, if ever, sold at the actual wellhead. The well-known “Henry Hub”, a popular pricing index, is a physical pipeline location in Louisiana. There are many more hubs and trading locations on interstate pipelines throughout the country where many buyers and sellers come together to transact. Publications like the Platts Inside FERC Gas Market Report and Gas Daily provide pricing data provided by market participants at the various locations on interstate pipelines where gas is bought and sold. There is no “index” for individual wellheads because gas is simply not sold at those locations.
Since the modern commercial marketplace “values” gas on the interstate pipeline system, that is location where the Supreme Court should have concluded the GMRA mandates the minimum royalty of twelve and a half percent (12.5%). The designation of that valuation point would have been entirely consistent with original logic and rationale of the GMRA- valuing the royalty where the gas is actually sold. Because the Supreme Court observed that a “royalty” is the landowner’s share of the value of the gas, it necessarily must be based on an established value of the gas – which nowadays is determined on the interstate pipeline system.
The Kilmer panel lost sight of this and focused on the physical location of the wellhead. So, instead of viewing the wellhead as the location of the commercial marketplace where the value of gas was established at the time the GMRA was enacted, the Supreme Court erroneously concluded that the physical wellhead was and is a point of significance in and of itself. The likely reason for this was the drillers’ suggestion that the “net-back” royalty method could yield a “wellhead” value of gas, which appears to have caused the panel to believe that it could recreate the way gas was sold in the past. That was clear error.
The “net-back” royalty valuation method does not deliver a “wellhead” value for the simple reason that the commercial marketplace does not price gas at individual wellheads. The “net-back” method is simply a derivative calculation that takes sales values obtained downstream of the well and subtracts the intervening post-production costs incurred as the gas is moved downstream to the final sales location. While the gas industry promotes this as the value of gas at the actual wellhead, that is simply inaccurate. The “wellhead” value derived by the “net-back” royalty calculation method is only the solution to a simple yet unnecessary math equation. It does not represent – or take the place of – the actual value arrived at between a willing buyer and a willing seller on the interstate pipeline system. If there is no value at the wellhead because there is no commercial marketplace there, the mere use of the “net back” method does not automatically create one. As such, the authors submit that the “net back” method itself is simply a myth perpetrated by drillers- it does not reflect the true value of the gas.
- The Kilmer panel’s faulty rationale
The Kilmer panel relied on a number of rationales in support of its conclusion that the GMRA requires drillers to pay a royalty based on the derivative “net back” calculation. As detailed below, these rationales are unpersuasive and erroneous.
- Misconstrued Section 33.1
The GMRA requires a royalty to be “at least one-eighth royalty of all oil, natural gas or gas of other designations removed or recovered from the subject real property.” 58 P.S. § 33.1 According to the Kilmer panel, upon the suggestion of the drillers, the location where gas was removed or recovered from real property was the wellhead, where the gas was severed from the land. But, that is not the only approach.
The “removed or recovered from the subject real property” language in the GMRA can also be read to require that the royalty be paid on the volume of gas that is actually transported off the property where the well is located. If, as these authors submit, the royalty is a fraction of the value of gas at the time and place of a sale based on pricing from the commercial marketplace, then it makes sense that the royalty be based on the volume of gas that was actually sold, i.e. that was removed and recovered from the property.
- The “in kind” red herring
The Kilmer panel found it significant that the GMRA applied to both oil and gas. The Court reasoned that while it was unusual for gas royalties to be taken “in-kind”, oil can be taken “in kind” by the lessor. The Supreme Court concluded that the General Assembly “would not intend to create a situation where one landowner would receive a dramatically increased royalty when the product is valued at the point of sale when the neighbor who took the royalty in-kind would have a reduced royalty based on the wellhead value.” This conclusion is erroneous.
First, the Court itself notes that there is no history of a gas royalty being taken “in-kind” and that it is impractical to do so. No landowner is taking a share of the gas “in-kind” at the wellhead. Therefore, there was no reason for the Kilmer panel to have been concerned about “in-kind” royalties in the first place. Second, the concern about “in-kind” royalties is rooted in the fact that oil can be taken “in-kind”, but the Kilmer opinion does not discuss the fundamental pricing distinction between oil and gas.
Natural gas that is bought and sold on interstate pipelines is a fungible commodity. Pipelines have gas quality standards that essentially means there is no difference in the gas molecules placed in the interstate pipeline network in Louisiana from gas those molecules placed into the pipeline in Pennsylvania. On the other hand, oil is not a fungible product. There are different grades of oil and the product is priced on its quality. So, if a royalty owner takes their Pennsylvania Grade Crude Oil in-kind at a well in McKean County, the value of that gas is not generally going to be much different than the value the driller receives from the refiner.
- The false premise of differing sales
The Kilmer panel was apparently worried about the prospect differing royalties being paid to neighboring property owners if one property owner’s gas was sold at a different location and different degree of processing than the other neighbor’s. The Kilmer court remarked that “[t]he use of 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. This is inaccurate on two fronts.
First, under the Supreme Court’s own explanation of a gas royalty, the pantheon of post-production costs are not “value-adding”. To “add value”, one must have an initial, known value to start from. Moving gas from the well and placing it in a form to enter the interstate pipelines is not adding value; it is getting the gas to the marketplace location to obtain a value. The costs a banana company incurs to ship bananas from Honduras to the United States are not associated with “adding value” to the bananas. Rather, they are costs of getting the bananas to the market that will value the bananas in the first place. Concepts of moving a product to the market for sale cannot and should not be considered costs of adding value, but drillers do this all the time.
Second, the Kilmer court wholly misunderstood how gas is actually sold. The opinion appears to hearken back to the days of regulated pricing at the wellhead. But, regardless of whether one uses the net-back method to calculate the royalty or another method, there is no guarantee that two neighboring landowners, whose gas is produced by different drillers, would ever receive the same commodity price for their respective gas.
Suppose Jane Doe and Peter Jones are neighbors who each have a gas well on their property. SmallCo produces Jane Doe’s gas and Conglomerate Company produces from the Peter Jones property. Conglomerate Company has leveraged its large size to negotiate favorable gas gathering contract rates to get the gas from the well to the interstate pipeline and is a shipper on interstate pipelines, moving its tremendous volumes of gas from the Jones property and thousands of others. On the other hand, SmallCo contracted with a midstream company to build a gathering system to connect its few wells with the interstate pipeline network, but SmallCo is paying a very high price for gas gathering. SmallCo is also not a shipper on the interstate pipeline network, so it sells its gas to a marketing company at the interconnection between its gathering system and the interstate pipeline network.
The “net-back” method is no saving grace to eliminate pricing disparities. Jane Doe is going to receive a royalty payment on a different value of gas than Peter Jones because the inputs downstream of the wells that are used to calculate their “net-back” royalties are different. If Conglomerate Company sells its gas for $2.25 per MMBTU but incurs $.56 per MMBTU of costs to sell the gas, the result is a $1.69 per MMBTU “net” figure using the “net-back” method. If SmallCo sells its gas for $2.05 per MMBTU but incurs $.68 per MMBTU in costs to sell that gas, that yields a derived, $1.37 per MMBTU “net” figure using the “net-back” royalty calculation method. The “net back” method does not eliminate or mitigate these pricing disparities.
Absent regulated pricing at the wellhead or a commercial marketplace that determines pricing at the actual well (versus wellhead pricing being a derived, calculated figure based on downstream prices), there is no guarantee that neighboring property owners will ever receive the same value of gas. In fact, there should be no requirement of uniform pricing. Given the significant impact that differing fees for gas gathering and processing play in “net-back” royalty calculations, it may be more likely that the “net-back” royalty calculation method would yield more significantly different royalty valuation than simply using the pricing in the commercial marketplace on the interstate pipeline.
Did the Kilmer court undermine its own holding?
These authors believe that the Kilmer court’s conclusion undermined the rationale it expressed in support of a derivative calculation method. The Supreme Court broadly proclaimed that “[a]ccordingly, consistent with our rules of statutory interpretation, we hold that the GMRA should be read to permit the calculation of royalties at the wellhead, as provided by the net-back method in the Lease, and thus, affirm the trial court’s grant of summary judgment to the Gas Companies.” Kilmer at 1158. The problem with this conclusion is the broad definition of post-production costs in the underlying lease itself.
The lease at issue in Kilmer defined “post-production costs” to include, among other things, “all losses of produced volumes (whether by use as fuel, line loss, flaring, venting or otherwise)”. Kilmer at 1150. Venting, flaring and line loss do not add value to the gas. In fact, they do the exact opposite – dissipate volumes that will never be sold. Even if one accepts drillers’ argument that post-production costs are value adding activities, this shows the dangers in broadly accepting a proposition that all post-production costs are, in and of themselves, “value adding”.
Since the Kilmer court was focused on the value of the gas at the physical wellhead and it agreed with the drillers’ suggestion that a royalty is a share of the gas that is produced from the ground, then the Kilmer panel should have held that the GMRA required the royalty to be based on the value of the entire volume of gas that was actually produced at the wellhead. But, the Court did not do this. Remarkably, the Court concluded that the GMRA sanctioned the royalty calculation in the underlying lease, which expressly allowed the driller to avoid paying for volumes that were produced – but did not go to market. The royalty provision in the Kilmer lease is directly at-odds with the reasoning expressed in the decision about why the wellhead was the point of royalty valuation. This significantly undermines the entire decision.
Where do we go from here?
Although ten years have passed since Kilmer was decided, the decision still impacts and shapes the relationship between landowners and drillers. The Pennsylvania Supreme Court’s flawed reasoning has been wrongfully and dangerously expanded beyond the narrow issue that was actually before the court ( i.e. application of the GMRA). Many drillers now contend that Kilmer has re-written every oil and gas lease in the Commonwealth and that Kilmer allows them to deduct post-production costs regardless of the actual lease language. Nothing can be further from the truth. In reality, the Kilmer opinion did not authorize or expand the ability to deduct post-production costs and did not re-write or change any leases. Nonetheless, the “net-back” method is continually (and wrongfully) used to calculate royalties under the auspices of the “Kilmer Rule”. But, no such rule exists.
The Kilmer decision and its strained (and flawed) reasoning shows why it is necessary for courts, royalty owners and drillers to evaluate each lease based on the actual terms of that particular oil and gas lease. The idea that Kilmer created a “one size fits all” approach to post-production costs was correctly rejected by the federal district court in Marburger v. XTO Energy ( No. 15-190, W.D. Pa. January 26 2016) and the authors submit that the rationale espoused by the Marburger opinion should guide future courts when confronted with the fallacy of a “Kilmer Rule” argument. The Marburger court rejected XTO’s effort to superimpose the “Kilmer Rule” onto each and every lease holding that “[X]TO has failed to show that Kilmer forecloses ( a deduction challenge) when the leases do not specify the method for calculating royalties…” If the relationship between the landowner and the driller is governed by the lease contract, then the lease contract alone should dictate how the royalty is calculated and paid. If you are a landowner, take a look at your lease and your royalty statement. If post-production costs are being deducted and the lease does not authorize or allow those deductions, an improper and expansive reading of Kilmer may be the reason.