The Oil and Gas Addendum

As the Marcellus Shale development enters its seventeenth year, drillers are becoming more creative and aggressive in their effort to avoid express lease language that was drafted to prohibit or restrict the deduction of post-production costs. Many landowners sought to insulate their royalties from such deductions by negotiating royalty clauses which either expressly or implicitly designated the royalty valuation point as being at the point-of-sale, as opposed to the well-head. The effect of this subtle yet critical distinction was to preclude application of the so-called “net back” method. Under this method, drillers may deduct costs incurred between the well-head and the downstream point-of-sale. Conversely, when the point-of-sale is designated as the royalty valuation point, drillers are, in theory, prohibited from deducting those intervening costs. This is typically accomplished by drafting a royalty clause which states that the royalty will be valued and calculated on the “price paid” to the driller or the “proceeds received” by the driller. Drillers, however, have tried for years to ignore these explicit clauses by remarkably arguing that deductions are always permissible regardless of the language set forth in the parties’ oil and gas lease. A recent case from the Texas Supreme Court should signal an end to this charade.  In BlueStone Natural Resources v. Walker Murray, et al (No 19-0469, March 12, 2021), the Texas Supreme Court unequivocally ruled that a gross proceeds clause means no deductions.

The landowners in BlueStone owned several thousand acres in Hood and Somerwell counties in western Texas. In 2003, they entered into thirteen (13) identical oil and gas leases with Quicksilver Resources Inc (the “2003 Leases”).  Paragraph 3 of the 2003 Leases contained the lessee’s standard royalty clause which stated that the royalties were to be based on “the market value at the well of 1/8th of the gas sold or used…” (the “Base Lease Royalty Clause”).  Attached to the 2003 Leases was an addendum which contained two critical clauses.  The first clause, which is typical of most addendums, clarified that the addendum terms would control over the pre-printed lease terms:

“[I]t is understood and agreed by all parties that the language on this addendum supersedes any provisions to the contrary in the printed lease hereof…”

The addendum also contained a royalty clause.  Paragraph 26 of the addendum provided as follows:

“LESSEE AGREES THAT all royalties accruing under this Lease (including those paid in kind) shall be without deduction, directly or indirectly, for the cost of producing, gathering, storing, separating, treating, dehydrating, compressing, processing, transporting, and otherwise making the oil, gas[,] and other products hereunder ready for sale or use.  Lessee agrees to compute and pay royalties on the gross value received, including any reimbursements for severance taxes and production related costs.”

For over a decade, the original lessee did not deduct any post-production costs from the landowners’ royalties.  In 2016, BlueStone Natural Resources, LLC (“BlueStone”) acquired the 2003 Leases and immediately began to deduct post-production costs.  Within two years, BlueStone deducted approximately $1.5 million from the landowners’ royalties.  The landowners then brought suit in Hood County, Texas asserting that no deductions were authorized or permitted under the 2003 Leases because Paragraph 26 required the royalty to be based on the “gross value received”.  The trial court agreed and granted the landowners’ motion for summary judgment.  BlueStone appealed to the Texas Court of Appeals in August 2018.

The threshold issue on appeal was whether the Base Lease Royalty Clause and Paragraph 26 were “contrary” to one another so as to trigger the addendum’s Superseding Clause.  If the two clauses were inconsistent and could not be read together, then Paragraph 26 would control.

In April 2019, the Court of Appeals affirmed and concluded that the Base Lease Royalty Clause and Paragraph 26 could not be harmonized.  Because Paragraph 26 valued the royalty at the point-of-sale, the Court of Appeals held that BlueStone could not “net-back” the post-production costs.  BlueStone then appealed to the Texas Supreme Court.

On appeal before the Texas Supreme Court, BlueStone again argued that there was no inherent conflict between the Base Lease Royalty Clause and Paragraph 26. According to BlueStone, the Base Lease Royalty Clause and Paragraph 26 each defined a separate and distinct component of the production royalty: the Base Lease Royalty Clause set the royalty valuation point at the wellhead while Paragraph 26 merely identified the royalty valuation method (i.e. gross proceeds). BlueStone further argued that since Paragraph 26 did not alter or modify the valuation point, there was no conflict between the two clauses. BlueStone suggested that the two clauses can and should be read together. Under BlueStone’s interpretation, the landowners were to be paid a royalty based on the “gross proceeds” valued at the wellhead. Since the valuation point remained at the wellhead, BlueStone contended that utilization of the net-back method was proper and that the Court of Appeals erred when it concluded that BlueStone breached the 2003 Leases when it deducted post-production costs.

In order to address the artificial distinction advanced by BlueStone, the Texas Supreme Court analyzed the differences between a market value royalty and a proceeds royalty. The panel observed that the Base Lease Royalty Clause utilized a “market value” approach to royalty valuation. The court noted that there a generally two ways to ascertain and calculate the market value of the gas at a designated location:  i) comparable sales or ii) the net-back 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 net-back method developed as the preferred alternative. Under this method, the value of the gas at the wellhead is calculated by taking the downstream point-of -sale and subtracting the processing 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 net-back method allows a driller to calculate the value of the gas at the wellhead by subtracting the intervening processing costs.  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”). Both methods assume that the royalty valuation point is at the wellhead, even though the actual point-of-sale is further downstream.

The BlueStone panel observed that this method generally allows the driller to deduct post-production costs from the royalty calculation.  See, Burlington Resources Oil & Gas v. Texas Crude Energy, 573 S.W.3d 198 (Tex. 2019) (“…when the parties specify an ‘at the wellhead’ valuation point, the royalty holder must share in post-production costs…”); Judice v. Mewbourne Oil Co., 939 S.W.2d 133 (Tex. 1996) (noting that the phrase ‘market value at the well’ means the “value at the well, net of any value added by compressing the gas after it leaves the wellhead”); Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 118 (Tex. 1997) (“[t]his method involves subtracting reasonable post-production marketing costs from the market value at the point-of-sale”).  As such, the BlueStone court determined that the Base Lease Royalty Clause itself theoretically authorized deductions, which would result in a net royalty to the landowners.  The court then examined Paragraph 26 to ascertain whether that clause altered the royalty valuation methodology set forth in the Base Lease Royalty Clause.

Unlike the Base Lease Royalty Clause, the court observed that Paragraph 26 was a “proceeds clause”.  Specifically, the court put great weight on the second sentence of Paragraph 26 which clearly stipulated that the royalty was to be calculated “on the gross value received” by the lessee.  Because Paragraph 26 based the royalty on the amount received by the lessee, the BlueStone court opined that Paragraph 26 was best characterized as a “proceeds clause”.  Under this approach, the royalty is valued at the point-of-sale and not the wellhead.  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, 573 S.W.3d at 204.  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…”). The BlueStone court concluded that a “proceeds clause”, like Paragraph 26, forecloses application of the net-back method and typically results in the landowner receiving a cost free royalty.

Given the strikingly different valuation methodologies set forth in each clause, the panel determined that there was, in fact, a conflict between the two clauses.  The court noted that a clause “requiring computation based on “gross value received” inherently conflicts with a computation based on value received at the mouth of the well.” As such, the BlueStone court held that the Superseding Clause in the addendum was triggered and Paragraph 26 governed the calculation of royalties.

Because Paragraph 26 valued the royalty at the point-of-sale, the court held that BlueStone could not “net-back” the post-production costs.  Consequently, BlueStone’s practice of deducting such costs constituted a material breach of the 2003 Leases.  Given this conclusion, the panel affirmed the entry of summary judgment in favor of the landowners: “[T]he lower courts correctly concluded that the lessee’s deduction of post-production costs was improper because the mineral lease explicitly resolves the conflict in favor of the gross-proceeds calculation.”

Although not binding on Pennsylvania courts, the BlueStone decision is encouraging news for landowners here in Pennsylvania.  The author submits that the BlueStone panel reached the correct decision:  the parties specifically negotiated a clause which based the royalty on the amount “received” by the lessee.  When the royalty valuation point is at the point-of-sale, there is no legal basis to utilize or apply the net-back method.  The BlueStone court correctly rejected the lessee’s attempt to re-define the royalty valuation point under the 2003 Leases as being at the wellhead.  If you have a royalty clause that bases the royalty calculation on the “proceeds received” or the “amount realized,” you should carefully and regularly monitor your royalty statements since a persuasive argument can be made that no deductions are authorized or permitted under such clauses.