The Oil and Gas Addendum

On August 5, 2021, Rep. Eric Davanzo (R-Westmorland County) introduced HB 1763. The bill seeks to clarify Pennsylvania oil and gas law by defining the term “royalty”. It is important to emphasize that HB 1763 does not ban or outlaw the practice of deducting post-production costs. The bill simply explains what a “royalty” is under Pennsylvania law. Opponents of HB 1763 argue that the bill is unconstitutional because it changes existing oil and gas leases. It does not. That argument lacks merit and operates merely as a distraction to the fundamental purpose of the legislation which is to eliminate an ambiguity in Pennsylvania oil and gas law.

Remarkably, Pennsylvania law does not define the term “royalty”. In 2010, the Pennsylvania Supreme Court in Kilmer v. Elexco Land Services, 990 A.2d 1147 (Pa. 2010) recognized this omission and noted that such a definition should be developed and implemented by the General Assembly, not the courts. The Supreme Court observed that:

“[W]e note that the General Assembly is the branch of government best suited to weigh the public policies underlying the determination of the proper point of royalty valuation in the deregulated gas industry. However, until the General Assembly acts to specify the point of valuation, we must interpret the statute as written, prior to deregulation.”

Kilmer, 990 A.2d at 1158. HB 1763 follows this directive and provides much needed clarity and certainty as to what constitutes a “royalty” under Pennsylvania oil and gas law.

The text of HB 1763 is straight-forward and simple. It correctly defines and sets the “royalty” as being a property interest based on the proceeds received at the point-of-sale:

“Royalty.” The lessor’s ownership interest in the gross proceeds generated at the first arm’s-length point of sale of oil, natural gas or gas of other designations to a third-party purchaser unaffiliated with the lessee or, to the extent the underlying lease allows the lessor to take the lessor’s royalty in kind, the lessor’s ownership interest in the oil, natural gas or gas of other designations at the same location, but from which ownership interest is excluded the costs of development and drilling and all postproduction expenses directly or indirectly incurred or paid by the lessee between the wellhead and the point of sale.

In order to appreciate the scope and significance of HB 1763, a brief review of the typical oil and gas royalty clause is warranted. The ideal royalty clause should contain three (3) distinct and independent components: the royalty fraction (e.g., 12.5% or 16%), ii) the “yardstick” (e.g., the market value, proceeds or price) and iii) the location for measuring the yardstick (e.g., at the wellhead or the point-of-sale). See, BlueStone Natural Resources II LLC v. Randle, (620 S.W. 3d 380 (Tex.2021). Unfortunately, many oil and gas leases in Pennsylvania do not contain all three components. They often omit the second or third component or sometimes both. Regardless of whether the omission was by design or simply neglect, the absence of any one of these components can and does inject unnecessary confusion and uncertainty into the calculation of the landowner’s production royalty.

For example, some royalty clauses contain language stating that the landowner “shall be paid a royalty of 13%”. Other clauses provide that the landowner is entitled to a “royalty of 16.5% of value of the gas sold” or “17% of the gross sales price from the sale at the well head.” These clauses are inherently ambiguous and subject to differing interpretation. This is where HB 1763 comes into play. Before we examine how HB 1763 will operate, let us briefly examine the second (i.e., the “yardstick”) and third (i.e., measurement location) components of an ideal royalty clause.

The yardstick component provides guidance as to the source of the royalty. There are typically two yardsticks which are utilized in modern oil and gas leases: the market value of the gas or the actual proceeds received from the sale of gas. The Texas Supreme Court further described the two “yardsticks” as follows:

“Proceeds” or “amount realized” clauses required measurement of the royalty based on the amount the lessee in fact receives under its sales contract for the gas. Union Pac. Res. [Grp.] v. Hankins, 111 S.W.3d 69, 72 (Tex. 2003) (citing Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368, 372 (Tex. 2001)). By contrast, a “market value” or “market price” clause requires payment of royalties based on the prevailing market price for gas in the vicinity at the time of sale, irrespective of the actual sale price. Yzaguirre, 53 S.W.3d at 372. The market price may or may not be reflective of the price the operator actually obtains for the gas. Id. At 372-73.

Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008).

There are two methods of determining the market value of gas: i) comparable sales or ii) the netback method. Under the comparable sales method, the value of the gas at the wellhead is calculated by averaging the prices that the driller and other producers have received in the same production field for gas of comparable quality and quantity. Evidence of comparable sales, however, is often difficult to ascertain, so the work-back or netback method developed as the preferred alternative.

Under this work-back or net-back method, the purported value of the gas at the wellhead is calculated by taking the downstream sale price and subtracting the processing and movement costs incurred between the wellhead and the point-of-sale. See, Atlantic Richfield v. State, 262 Cal. Rptr. 683, 688 (Cal. Ctr App. 1989) (noting that the royalty is calculated “by working back from the price of the point-of-sale, deducting the cost of processing and transportation from the wellhead.”) Thus, when there is no actual market for gas at the wellhead or when there is insufficient evidence of comparable sales, the netback method allows a driller to calculate the value of the gas at the wellhead by subtracting the intervening costs between the wellhead and the point of sale. See, Kilmer v. Elexco Land Services, 980 A.2d 1147 (Pa. 2010) (“…we must work backward from the value-added price received at the point-of-sale by deducting the companies’ cost of turning the gas into a marketable commodity”).

The second yardstick measures the royalty on the proceeds actually received by the lessee. The Texas Supreme Court has consistently held that under a “proceeds” clause or an “amounts realized” clause, the landowner is granted “the right to a percentage of the sale proceeds with no adjustment for post-production costs.” See, Burlington Resources v. Texas Crude Energy, LLC., 573 S.W.3d 198 (Tex. 2019); see also, Chesapeake Exploration, LLC v. Hyder, 483 S.W.3d 870, 871 (Tex. 2016) (noting that under a ‘proceeds lease’, the “price-received basis for payment in the lease is sufficient itself to excuse the lessors from bearing post-production costs”); Warren v. Chesapeake Exploration, 759 F.3d 413 (5th Cir. 2014) (stating that an “amount realized” clause, standing alone, will create a royalty interest free of post-production costs); Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 699 (Tex. 2008) (“[P]roceeds clauses requires measurement of the royalty based on the amount the lessee in fact receives under its sales contract for the gas”); Judice v. Mewbourne Oil Co., 939 S.W. 2d 133 (Texas 1996) (“the term gross proceeds means the royalty is to be based on the gross proceeds received…”). So, unlike the market value yardstick, the proceeds yardstick is typically free of post-production costs. Both yardsticks, however, can be impacted by the third and final component: the location where the yardstick is measured. HB 1763 addresses this third component.

The third component of the ideal royalty clause is critical. It establishes the point from which the lessee, if necessary, “works back” to calculate and determine the value of the gas. See, BlueStone Natural Resources, supra. The measurement is typically utilized at either of two locations: at the wellhead or at the point-of-sale. This is commonly known as the royalty valuation point. If the valuation point is designated at the wellhead, but the gas is actually sold downstream, then, in that instance, the driller may utilize the netback method to deduct the intervening processing and movement costs to arrive at a computed wellhead value. Conversely, if the royalty valuation point is at the point-of-sale, there is no need to work backwards to the wellhead and no costs need to be deducted. In practice, the second yardstick (i.e., proceeds) is usually measured at the point-of-sale. See, BlueStone Natural Resources, supra. (“[W]hen proceeds are valued in gross…the valuation point is necessarily the point-of-sale because that is where the gross is realized or received.”). And when the royalty is valued at the point-of-sale, the driller generally cannot deduct the costs incurred between the wellhead and the sales location.

Confusion can arise when the royalty clause inadvertently contains language which purports to measure the proceeds yardstick at the wellhead. HB 1763 will eliminate this confusion and provide guidance to the landowner and driller by designating the royalty valuation point at the point-of-sale. Conversely, if the royalty is based on the “value” of the gas (as opposed to the “proceeds”) and the valuation point is designated as being at the well-head, HB 1763 will not be operative and will not change the parties’ agreement.

In sum, HB 1763 is essentially a “gap filler” – it will provide a clear and objective measurement location if the underlying lease omits such language. It will not change or amend your lease. It will only apply if your lease fails or neglects to define and designate the appropriate royalty valuation point or if your royalty clause contains an inherent and unworkable ambiguity. This is good news for Pennsylvania landowners and drillers.