Varnado, Pharis: Navigating the Royalties Legal Landscape

Litigation related to unconventional oil and gas plays steadily increased during the shale revolution. The subject of significant disputes in recent years: the calculation and payment of oil and gas royalties to interest owners.

To be sure, economic, political and societal pressures have expanded potential liabilities across the energy industry. Consequently, it has become more important than ever for producers to understand the current royalty litigation landscape. 

While it is not uncommon for newer form leases—and manuscript leases in the Eagle Ford—to require “add backs” of embedded post-production costs or expressly provide for royalties on extracted refined NGL, many active oil and gas leases do not address these topics, which has led to significant litigation and questions about oil and gas royalty class certifiability.

‘Add Backs’ of embedded costs

Of late, one of the most common claims brought by royalty owners complaining of alleged improper payments center on “add backs.” By way of these claims, royalty owners demand that producers pay royalties based on the sales price they receive plus any embedded costs that were a component of the sales price.

“Add back” claims raise serious concerns for E&P companies in a global energy market where oil or gas may be sold at prices determined under a complex formula which utilizes European and/or Asian published indexes and includes various adjustments for downstream Asian and European transportation charges. Royalty owners with oil and gas leases that do not allow for deductions of post-production costs may argue that the cost components for Asian and European transportation are hidden post-production deductions that E&P companies must add back to sales prices prior to calculating royalties. 

Last year, the Texas Supreme Court directly addressed the “add back” issue in Devon Energy v. Sheppard. In that case, the Sheppard oil and gas lease contained a “bespoke” royalty provision that required the lessee to add back costs that were a component of the sales price. On that basis, the court ruled that post-production costs identified in the contractual formula that determined the sales price had to be added to the price prior to calculating Sheppard’s royalties. 

Of note, the Sheppard decision has limited application to other royalty cases, as it was based on one-of-a-kind “add back” language in the Sheppard lease that would not apply to standard royalty provisions. At least in Texas, producers can breathe a sigh of relief that “add back” claims under leases with standard royalty provisions are unlikely to succeed.

NGL royalty calculations under gas royalty clauses

Another trigger for litigation these days is the calculation of royalties on NGL. Unlike dry gas, “wet” gas requires significant processing and fractionation to separate and refine NGL products from the gas stream. These post-production activities take place downstream from the wellhead at processing plants and fractionation facilities. After NGL are extracted from the gas stream, the residue gas and NGL products are separately marketed and sold, generating two distinct revenue streams.

Traditional oil and gas leases provide for the payment of royalties on oil and gas but are silent as to NGL. Courts have interpreted the term “natural gas” to include its component parts—read, NGL, which means producers must pay royalties in a manner that compensate royalty owners for both gas and NGL. But the question of how to calculate and pay royalties on NGL is the subject of hotly contested litigation in jurisdictions with substantial wet gas production. That a lease may be silent in terms of NGL does not end the inquiry, but only raises additional questions about the basis and location for valuation.

This can be rather consequential. Class actions can turn relatively small disputes over NGL royalty payments into multimillion-dollar statewide lawsuits over a producer’s royalty practices. On the plus side for producers, oil and gas leases that only provide for royalties on “gas” but do not provide a separate royalty for NGL are arguably ambiguous and cannot be certified as a class action under the Federal Rules, as was the case in SWN Production Co. v. Kellam.

No doubt about it, a greater variance in oil and gas lease terms, higher volume of leases and more complicated allocations have created new challenges for producers in the administration of royalty payments. As such, it is critical for energy companies to implement strategies to defend royalty practices and mitigate the risk of class certification.

Lauren Varnado is the managing partner of the Houston office of Michelman & Robinson, a national law firm based in Los Angeles. Jessica Pharis is an associate at M&R and member of the firm’s energy practice group.