The Oil and Gas Addendum

The processing of natural gas requires a constant and reliable energy source. Critical operations such as compression, separation and dehydration cannot be conducted unless the driller has “fuel” to power the underlying equipment and machinery. At some well pad sites, the driller will divert a portion of the raw gas stream produced by the well to those operations and then use the raw gas as the power source. Alternatively, the driller may contract for such processing services with a third-party provider and allow the third-party to “use” the raw gas as fuel. In either scenario, the gas is never sold or marketed and is instead consumed as fuel as part of the well pad operations. No royalty is ever paid on these diverted volumes of fuel gas. Is the driller obligated to calculate and pay a royalty on such volumes? The answer often depends on the precise language in the parties’ oil and gas lease.  See, Is Deducting Fuel Costs Authorized by Your Lease (October 22, 2022).   A recent decision by the Federal District Court in Pecos, Texas addressed this troubling question and ruled that royalties may not be owed on such volumes. The District Court exacerbated this conclusion by also ruling that certain post-production costs incurred by a third-party could reduce the sales price upon which the landowner’s royalty was based. Not good news for landowners.

 At issue in H.L. Hawkins, Jr., Inc. v. Capitan Energy Inc.  (Western District of Texas, No. 22-CV-0020, August 10, 2023), was a 2011 oil and gas lease encumbering 646 acres in Culberson County, Texas (the “2011 Lease”). The 2011 Lease obligated the driller to pay a royalty of 25% of the “gross proceeds” received by lessee on the sale of all hydrocarbons “recovered, separated, produced or saved” from the leased premises. Paragraph 3(c) of the 2011 Lease further provided that the 25% royalty was to be calculated without deductions:

(e). Royalty to be Free of Expenses. Lessor’s royalty shall not bear or be charged with, directly or indirectly, any cost or expense incurred by Lessee, including without limitation, for exploring, drilling, testing, completing, equipping, storing, separating, dehydrating, transporting, compressing, treating, gathering, or otherwise rendering marketable or marketing products, and no such deduction or reduction shall be made from the royalties payable to Lessor hereunder, provided, however, that Lessor’s interest shall bear its proportionate share of severance taxes and other taxes assessed against its interest or its share of production.

In the spring of 2019, Hawkins conducted an audit of the royalties being calculated under the 2011 Lease. The audit revealed a number of underpayments and improper deductions. In March 2022, Capitan Energy Inc. (“Capitan”) responded to the audit findings and refused to make any corrective payments to Hawkins. In June 2022, Hawkins filed suit alleging a material breach of the 2011 Lease.

 Hawkins asserted that Capitan breached the 2011 Lease in two ways: i) by “indirectly” deducting transportation and other processing costs from the production royalty; and ii) by failing to pay any royalty on those volumes of gas flared or diverted for fuel use. Hawkins’ audit discovered that the price in Capitan’s third-party sales contract was adjusted downward to account for the post-production costs allegedly incurred by the third-party buyer. In other words, the actual sales price received by Capitan was reduced by the buyer’s downstream costs. Hawkins’ royalty was then calculated on this reduced price. By basing the royalty on this reduced price, Hawkins argued that Capitan was “indirectly” burdening the royalty with post-production costs in violation of Paragraph 3(e).

Hawkins further argued that Paragraph 3(b) in the 2011 Lease required Capitan to calculate and pay a royalty on all volumes of gas, including those volumes diverted for fuel use or flaring. Paragraph 3(b) provided as follows:

Lessee shall pay the Lessor one-Fourth (1/4) of the gross proceeds received by Lessee for all gas (including substances contained in such gas) recovered, separated, produced or saved from or on the leased premises and sold by Lessee in an arms’ length transaction; provided, however in the event gas is not sold under an arms’ length transaction, Lessor’s royalty on such gas (including substances contained in such gas) shall be calculated by using the highest price paid or offered for gas of comparable quality in the general area where produced and when run;

Hawkins contended that Paragraph 3(b) recognized two types of triggering events: gas being sold in an arm’s length transaction or gas not being sold in an arm’s length transaction. Under Hawkins’ interpretation, gas being diverted for fuel use or flaring qualified as gas not being sold in an arm’s length transaction.  Such gas was used, not sold. Hawkins argued that a royalty was therefore owed on the diverted volumes under the second clause of Paragraph 3(b).

In response, Capitan argued that the text of Paragraph 3(e) was clear and unequivocal: the prohibition on deductions only applied to those costs actually incurred by Capitan. Because the purported transportation and processing costs were not “incurred” by Capitan, the prohibition in Paragraph 3(e) did not apply.  Capitan further argued that the reduced sales price caused by the pricing formula in the third-party sales contract was not an “indirect” charge against Hawkins’ royalty.  Rather, the reduced price simply reflected the bargained-for exchange between Capitan and the third-party.  According to Capitan, the fact that the eventual sales price was reduced by subtracting out the downstream costs incurred by the third-party was simply immaterial.  Hawkins was still being paid a royalty based on the gross proceeds received at the point-of-sale.  As we have written before, a similar version of this troubling argument has been advanced by drillers in other jurisdictions.  See, Ohio Court Rules that Driller Did Not Breach Lessee By Deducting Post-Production Costs Incurred By Affiliate. (May 5, 2020).  Finally, Capitan argued that Hawkins was not entitled to a royalty on the diverted volumes of fuel gas or flared gas: a royalty is only owed if gas is actually “sold.”  Since flared gas and fuel gas were never sold, no royalty obligation ever arose under Paragraph 3(b) of the 2011 Lease.

In the early summer of 2023, the parties filed cross-motions for summary judgment.  On August 10, 2023, the District Court entered an order granting in part and denying in part both motions.  The District Court’s opinion is a mixed bag for landowners.

The District Court concluded that the reduced sales price was not an indirect deduction.  Critical to the District Court‘s reasoning was the fact that there was no evidence that Capitan actually “incurred” any post-production costs.  On the contrary, the evidence demonstrated the Capitan merely experienced a reduction in revenue which is not the same as an expense or cost:

“[B]ut decreasing revenue through taking a lower price is different from incurring an expense.  And, critically, this accounting technique – which Hawkins has not alleged is fraudulent – does not violate the Lease’s plain language.”

In short, the District Court ruled that the Capitan did not breach the 2011 Lease when the pricing formula in the third-party sales contract accounted for downstream costs incurred by the buyer.  Without much discussion or analysis, the District Court simply brushed aside Hawkins’ argument that the reduced sales price was an “indirect” deduction. 

 Conversely, the District Court partially granted Hawkins’ motion on the fuel/flared gas claim.  The District Court agreed with Hawkins that the diverted volumes of fuel gas and flared gas constituted gas “not sold”.  The District Court correctly observed that the “phrase ‘gas not sold in an arm’s length transaction’ would therefore cover every circumstance where gas is not sold in an arm’s length transaction – the sweetheart deals with affiliates and gas not sold.”  In theory, this conclusion triggered the royalty obligation under Paragraph 3(b).  But, that was not the end of the analysis.  The 2011 Lease also contained a “free use” clause which allowed Capitan to use gas as fuel.  Paragraph 6(c) of the 2011 Lease gave Capitan the right “to have free use of oil, gas and water from the leased premises . . . for all operations hereunder.”  As we have written before, these clauses can exclude volumes of fuel gas from the royalty obligation.  See, Texas Federal Court Rules No Royalty Due on Gas Used to Fuel Off-Lease Operations (March 30, 2022).  This clause, the District Court opined, carved out the diverted volume of fuel gas from the royalty obligation.  As such, although a royalty may be owed on flared gas, no royalty was owed on the volume of gas diverted for fuel.

The author submits the District Court’s reasoning is flawed.  The term “indirectly” in Paragraph 3(e) has to mean something.  If the pricing formula in the third-party sales contract is not an indirect deduction, what else can that term mean?  When else would it apply?  It is submitted that the Hawkins opinion inconsistent with the Texas Supreme Court’s recent decision in Devon Energy Production Company LP v. Sheppard, 668 S.W. 3d 332 (Tex. 2023).  In Devon Energy, the Texas Supreme Court opined that a lease’s “prohibition on ‘indirectly’ charging the royalty with post-production costs could only refer to the buyer’s post-sale expenditures because all other pre-sale expenditures – whether incurred directly or indirectly by the producer – are already included in gross proceeds.”  See, Texas Supreme Court Rules That Post-Sale Costs Must be Added Back to Gross Proceeds Calculation (April 27, 2023).  The author maintains that the same logic should have applied to Paragraph 3(e).  The phrase “directly or indirectly” in Paragraph 3(e) should be read to modify the word “incurred”.  In other words, costs directly or indirectly “incurred” by Capitan cannot be deducted.  It is submitted that such a construction makes more sense, is consistent with Devon Energy and is faithful to the overall intent of Paragraph 3(e).

The issue of whether a driller must pay a royalty on fuel gas has not yet been directly addressed by the Pennsylvania courts. This issue is likely to emerge in the months ahead as another source of tension between Pennsylvania landowners and drillers as the practice of using leasehold gas for fuel becomes more prevalent and widespread throughout the Marcellus Shale region. In the meantime, landowners should carefully review their leases and the specific language in the underlying royalty clause. If the clause conditions payment of a royalty on all gas “produced” or “used” from the leasehold, a colorable argument could be made that the driller may owe a royalty on any gas diverted for fuel usage downstream from the well meter. This obligation, however, could be limited or negated if the lease contains a “free use” clause. In any event, all landowners should be aware of this fuel gas issue and should regularly review their lease and their corresponding royalty statements. If you have an oil and gas lease and you are unsure whether your royalties are being properly calculated, please call Robert J. Burnett at 412-288-2221.