Pennsylvania’s Guaranteed Minimum Royalty Act and the Volume Question

As data centers, cryptocurrency mining operations, and other energy-intensive technologies proliferate, colocating that infrastructure with natural gas wells can be beneficial to the gas drillers and to the power consumers. The large volumes of natural gas can provide a dependable fuel-source for power-hungry facilities like data centers and crypto mining, while the presence of those facilities creates new buyers for the drillers that are producing and selling natural gas.

The colocation of data centers and cryptocurrency mining facilities with gas wells can result in a situation where natural gas never leaves a well pad or leased property. Gas can be extracted and consumed on-site in generators providing power for these facilities. In theory, this set-up should benefit royalty owners. Increased demand from new energy consumers can result in higher pricing and more production activity. That, in turn, may lead to more leasing.

But this framework also highlights a lingering question about how royalty owners are paid. Consider a lease that provides for a 20% royalty on gas "marketed and used off the premises." If all produced gas is consumed on-site, how much royalty is owed? The rate is 20%, but the royalty owner receives 20% of what? If no gas is "marketed and used off the premises," the volume subject to royalty is zero. Twenty percent of zero is zero. That does not seem right.

When evaluating landowners' entitlement to royalties, the focus naturally turns to Pennsylvania's Guaranteed Minimum Royalty Act (the "GMRA"). The GMRA states that:

A lease or other such agreement conveying the right to remove or recover oil, natural gas or gas of any other designation from the lessor to the lessee shall not be valid if the lease does not guarantee the lessor 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. § 33.3. Despite this requirement, many leases do not provide for a royalty on all produced oil and gas. Instead, most leases apply the royalty to oil or gas that leaves the property. In the example above, a royalty clause that applies to gas "marketed and used off the premises" would seemingly not obligate a driller to pay a royalty on gas that was produced and consumed on-site by a cryptocurrency mining operation.

The absurdities that arise when common royalty language is applied to colocation of gas wells and power infrastructure highlight a flaw in Pennsylvania's royalty framework. The GMRA is a validity statute. It is not an insurance policy or a gap-filler that rewrites lease terms when scenarios seem to shortchange landowners. If a lease satisfies the GMRA requirements, the lease is valid under that statute. If a lease does not meet the GMRA requirements, it is invalid.

But nearly a half-century after the GMRA was enacted, and over 15 years since the Pennsylvania Supreme Court's seminal decision in Kilmer v. Elexco Land Services, Inc., 990 A.2d 1147 (Pa. 2010), it still is not clear "what" lease provisions satisfy the GMRA. The reason for that uncertainty is straightforward. In the royalty arena, there has been great emphasis on value, and very little emphasis on volume.

The Valuation Framework

For decades, royalty litigation has focused on valuation - where to measure the value of gas, what costs may be deducted, and how to calculate what gas is worth at the wellhead. The issue in many royalty cases has been about valuation of gas that was sold - not how to determine what volume the royalty should be based on.

An influential case shaping the royalty valuation approach was Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996). There, the Texas Supreme Court addressed a royalty clause which required payment based on "market value at the well" for gas that was "sold off the leased premises." Id. at 121. The royalty owner argued that an addendum provision prohibiting deductions for "processing, cost of dehydration, compression, transportation, or other matter to market such gas" meant that post-production costs could not reduce the royalty. Id.

The Texas Supreme Court disagreed. It held that "[t]he terms 'royalty' and 'market value at the well' have well accepted meanings in the oil and gas industry," and that the no-deductions clause was "surplusage as a matter of law." Id. at 122–23. Justice Owen's concurrence explained why: the concept of "deductions" from "market value at the well" is purportedly "circular" because "[t]he value of gas 'at the well' represents its value in the marketplace at any given point of sale, less the reasonable cost to get the gas to that point of sale." Id. at 130 (Owen, J., concurring). "[L]ogic and economics tell us that there are no marketing costs to 'deduct' from value at the wellhead." Id.

Heritage Resources exemplified the framework that would dominate royalty litigation: disputes about where to value gas, what costs to deduct, and "where" the point of royalty valuation was located. More broadly, the volume question - what gas is subject to the royalty - has largely been an afterthought in a royalty calculation methodology that purports to describe where volumes of gas originate for royalty purposes - the "wellhead".

The Net-Back Method

Central to a common valuation framework is the "net-back" method of calculating royalties which purports to calculate a "wellhead" value of the gas. Under the "net-back" approach, royalties are computed by taking the price received at a downstream point of sale and deducting the post-production costs incurred to get the gas from the wellhead to that point of sale. The result is the alleged "wellhead value" - what the gas was theoretically worth at the "wellhead", the moment that the gas exited the ground.

The "net-back" method relates to the alleged value of gas at the "wellhead", not the volume of gas that existed "at the wellhead". To determine a royalty at the "wellhead", the "net-back" method starts with gas that reaches the point of sale and then works backward on costs. Gas that never reaches the downstream point sale does not factor into the "net-back" calculation. That can result in volumes of gas that came out of the ground being excluded from a royalty valuation.

Kilmer's Volumetric Logic

In Kilmer, the Pennsylvania Supreme Court interpreted the GMRA to permit the "net-back" method of royalty calculation. Since the GMRA specifically identifies oil or gas that is “removed or recovered”, the Court's analysis substantially involved identifying that point. The Court concluded that this point is the wellhead, where the gas comes to the surface. Id. at 1157-58. Because the GMRA's reference point is the wellhead, the reasoning is that costs incurred after gas exits the ground are "post-production" costs that can be deducted without running afoul of the statute. The Court held that the GMRA "should be read to permit the calculation of royalties at the wellhead, as provided by the net-back method." Id. at 1158.

The physical location where the GMRA tests the validity of a lease has significant implications. If GMRA compliance is determined at the physical wellhead, then a lease must guarantee the lessor at least one-eighth of all of the volumes of gas that exit the ground at that location to be GMRA compliant. But the “net-back” method of royalty calculation does not account for all of those volumes. It only accounts for gas that eventually reaches a downstream sale. Volumes that exist at the wellhead but never reach that point of sale, such as gas used as fuel, lost in transit, or flared—disappear from the royalty calculation entirely. Those volumes are not part of the calculus at all, even though they were removed or recovered from the ground.

An additional complication is the internal tension in the Kilmer decision. Although the Supreme Court sanctioned the "net-back" method of valuing royalties, much of the logic that drove the Court's conclusion was based on volumetric considerations. Particularly compelling to the Kilmer court was the concept of a royalty being taken "in kind." The Kilmer Court observed that ". . . royalties in the industry can be taken in-kind," meaning the landowner could theoretically receive a physical share of production rather than a cash payment. Id. at 1157. While taking gas royalties in-kind is "unusual and impractical," the GMRA applies to both oil and gas, and "oil royalties can certainly be so taken." Id.

A royalty that is taken in-kind is necessarily volumetric. If the lessor is entitled to one-eighth of the physical oil and gas, that one-eighth must be measured at some point. That is the physical wellhead. The fact that most Pennsylvania leases are "proceeds leases", which calculate the royalty based on sale proceeds rather than in-kind shares, does not change this analysis. The GMRA does not distinguish by lease type. 58 P.S. 33.3.

Another motivating point for the Kilmer court identifying the wellhead as the point of GMRA compliance was the distinction between "production costs" and "post-production costs." Production costs are "the expenses of getting gas to the point it exits the ground." Post-production costs are "expenditures from when the gas exits the ground until it is sold." Kilmer, 990 A.2d at 1149 n.2. This structure has been applied in subsequent cases to determine which costs may be charged against the royalty interest.

But post-production costs are costs — expenditures of money. The Kilmer lease, however, defined "Post Production Costs" to include something that is not a cost at all. The lease provided that the lessor's royalty share would be reduced by "(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." Id. at 1150.

Item (ii) in the Kilmer lease is a cost. Item (i) in the Kilmer lease is not a cost. "Losses of produced volumes" are not expenditures. They are volume exclusions. Gas used as fuel, lost in transit, or flared is not a "cost" that can be "deducted" from a royalty calculation. It is a volume of gas that has been removed from the royalty calculus entirely. That a lease calls these volumetric losses a “cost” does not mean that is actually the case.

Yet the Kilmer Court determined that the lease complied with the GMRA, even though that lease explicitly excluded volumes of gas that were "removed or recovered" from the ground. The Court's rationale on this front was never developed. If the point of GMRA compliance is the wellhead - as Kilmer holds - then a lease cannot be valid if it does not guarantee at least a one-eighth royalty on all gas that exits the ground at that point. Gas used as fuel was removed or recovered at the wellhead. Gas lost to leakage was removed or recovered at the wellhead. Gas that was flared was removed or recovered at the wellhead. All of those volumes of gas exited the ground. The GMRA requires a royalty on "all" gas "removed or recovered." A lease that excludes these volumes does not satisfy that statutory requirement - regardless of how those exclusions are labeled.

Hall and the Unasked Question

Several years after Kilmer was decided, the Superior Court addressed a gas lease royalty question. In Hall v. CNX Gas Co., 137 A.3d 597 (Pa. Super. Ct. 2016), the Superior Court examined a lease which required a royalty on gas "sold or used beyond the well." Id. at 601. The royalty owners argued they were owed royalties on gas lost or used before the point of sale. The Superior Court disagreed, holding that "[g]as lost or used on the way to the point of sale is simply not part of the royalty computation." Id. at 604.

Notably, Hall was a contract interpretation case. A GMRA was originally asserted, but it was withdrawn. Id. at 600, n.4. The Superior Court interpreted the lease language as written - the lessee paid a royalty only on the gas that was sold or used beyond the well - not volumes of gas that were lost along the way to the point of sale. Because there was no remaining GMRA claim, the Hall court had no occasion to ask whether that lease language satisfied the GMRA's requirement that a lease guarantee royalty on "all" gas "removed or recovered."

That volume question is important, and it remains unanswered. A lease that contemplates a royalty only on gas that leaves the property does not guarantee a royalty on all gas. How can that satisfy the GMRA under the language of the statute and Kilmer’s implicit logic? If Kilmer is right that the GMRA's reference point is the wellhead, the geographic location and time when the gas is “removed or recovered” from the ground, then a lease must provide for a royalty on all volumes. A lease like that in Hall may guarantee a royalty rate that is higher than the GMRA’s one-eighth requirement, but it does not guarantee a royalty volume.

The GMRA is not merely about the value of gas. It is about the volume of gas to which that value applies. A royalty rate, even a generous one, means nothing if the volume of oil or gas subject to that rate can be reduced to zero. Colocation makes this concrete. If all gas produced from a well is consumed on-site to power a cryptocurrency mining operation or a data center, and the lease stipulates that a royalty is only due on gas that leaves the property, the landowner receives nothing. That result may be consistent with the lease language, but it is difficult to square with a statute that requires a lease to guarantee a royalty on "all" gas "removed or recovered" in order to be valid. And, simply put, it just seems “wrong”.

This presents a problem. Compliance with the GMRA is determined at the point where oil and gas are “removed or recovered from the subject real property”. If the GMRA’s “removed or recovered from the subject real property” requirement means the location where oil and gas come to the surface, as Kilmer found, then leases that contemplate royalties based on gas that is “marketed” or “sold” are presumably not GMRA compliant unless those leases have a “backstop” provision that specifically guarantees at least a one-eighth royalty on all volumes that were produced. Few leases have that proviso.

In this realm, a lease with a higher royalty rate, like 18% or 19%, would likely not be GMRA compliant if the royalty does not apply to all volumes. One could argue that a higher royalty rate applied to a smaller volume of gas can result in a greater amount of money to the lessor than a one-eighth royalty applied to all volumes. That may be true. But the volume of gas subject to the higher royalty rate could be incredibly small, resulting in the lessor receiving less than a one-eighth royalty on all volumes removed or recovered. And, either way, whether a higher royalty rate makes up for the royalty applying to less than all volumes is theoretical. The GMRA requires a lease to guarantee the one-eighth royalty in order to be valid. 58 P.S. § 33.3. That requires more than supposition.

There is not a clear way to reinterpret the GMRA to avoid this issue. Hypothetically, the GMRA’s phrase “removed or recovered from the subject real property” can be reimagined to refer to the four corners of the leasehold property where a well is located. Under that interpretation of the GMRA, a lease can satisfy the GMRA as long as the lease guarantees a royalty on all volumes that leave the actual leasehold itself. This view of the GMRA could make leases that apply royalties to gas “sold from the leased premises” or to gas “marketed from the leased premises” GMRA compliant. But, this interpretation is not a panacea.

Again, consider our colocation situation with a cryptocurrency mining operation on a well pad. Gas can be produced from the ground and consumed within the four corners of that leasehold property. Under the more expansive interpretation of the GMRA “removed or recovered from the leased premises” phrase, a lease could satisfy the GMRA and not require any royalty to be paid on these volumes consumed by a collocated power source. That seems an unrealistic outcome from a statute intended to guarantee a minimum royalty.

This alternative interpretation of the GMRA also becomes problematic for the “net-back” method of royalty calculation. If GMRA compliance is measured when gas physically leaves the four corners of the leasehold, then that would be the point of production. Costs incurred prior to that location would not be considered post-production costs that could theoretically be shared between lessor and lessee. Likely, by the time that gas leaves the property where the well is located, it has entered the gas gathering system, triggering a gas gathering fee. Thus, this broader interpretation of the GMRA may seriously impact “net-back” royalty calculations by transforming certain costs traditionally thought of as “post-production” costs in Pennsylvania into costs of production.  

As briefly suggested above, another counterpoint to a GMRA volumetric focus would be to argue that the GMRA has a limited application to proceeds leases. In those leases, the parties bargained for the royalty to be based on a share of what is actually sold. Thus, the parties deliberately chose not to frame their royalty relationship in terms of volumes. Thus, like in Hall, the lease contract could be interpreted as the parties wrote it. While that may initially seem attractive, the GMRA does not say that leases must guarantee the lessor at least one-eighth of the proceeds of sale. In fact, the GMRA says nothing about proceeds at all. If the GMRA invalidates leases where the parties bargained for less than a one-eighth royalty, there is a strong basis to argue that the statute should also invalidate leases that do not apply to all volumes that come out of the ground.

The ultimate resolution of these issues is beyond the scope of this note. But, it is undeniable that there are tensions between the GMRA text, Kilmer’s interpretation of the GMRA, subsequent decisions like Hall, the text of many Pennsylvania oil and gas leases, and developing colocation scenarios. These issues warrant attention to ensure that oil and gas owners are compensated for the oil and gas that they have leased for development. Increasing colocation of power consumptive operations on well pads may very well provide the impetus for this honest review of this most basic of oil and gas questions – what is the guaranteed minimum royalty required by law?

If you have questions about this note, contact the author, Brendan A. O’Donnell at 412-288-2226 or odonnellba@hh-law.com.