As the NGL market has grown dramatically over recent years, producers have begun to focus more closely on whether they are required to pay royalties to their lessors on the NGLs (natural gas liquids, including ethane, propane, normal butane, isobutene, natural gasoline and other liquids) derived from their gas production. Since the rights of royalty owners and the obligations of lessees are generally governed by the royalty provisions contained in a lease, in order to determine whether a lessee is required to pay royalties either on (a) unprocessed natural gas before it is stripped of NGLs or (b) all of the processed natural gas, including residue gas and NGLs, producers should first look to the language of the underlying lease to answer the question.
However, many leases are silent on whether a lessor is required to make payment on the proceeds received from the sale of, or the market value of, NGLs. Where a lease is silent on whether royalties should include the proceeds or market value of NGLs, the lessee’s obligation to pay royalties on NGLs often turns on how the term “natural gas” is defined in the lease, and where undefined, whether the applicable court would deem the term “natural gas” to include all components of natural gas, including NGLs. Recent decisions appear to support the proposition that the term “natural gas” includes all of its component parts, including NGLs. For example, in Occidental Permian v. French, 2012 WL 5351131 (Tex.App.-Eastland) (2012), the Court of Appeal of Texas, Eastland held that the sales value of a natural gas stream after the bulk of the carbon dioxide had been stripped was not a proper basis for determining the market value of such gas, as such sales value was not based on all components of the natural gas stream. Broad definitions of the term “natural gas” are also supported by Exxon Mobil Corporation v. Wyoming, 219 P.3d 128, 145 (2009) in which the Supreme Court of Wyoming held that “methane, carbon dioxide, and sulfur are all…included within the definition of natural gas,” and Enervest Operating, LLC v. Sebastian Mining, LLC, 676 F.3d 1144, 1147 (2012), in which the United States Court of Appeals for the Eighth Circuit held that “CBM falls squarely within the definition of natural gas, a ‘gas issuing from the earth’s crust through natural openings or bored wells’ especially a combustible mixture of methane and other hydrocarbons.” Thus, to the extent a lessee is required to pay royalties on “natural gas,” recent decisions appear to support lessors’ claims that they are entitled to payment of royalties in a manner that accounts for all of the components of natural gas, including NGLs. If such lessees fail to make royalty payments based on the proceeds or market value of NGLs processed from their gas production, such lessees run the risk of substantial penalties and lease termination claims. Accordingly, producers must give special care to a review of their existing leases and to a review of the royalty provisions in any leases prior to acquiring such leases in any E&P purchase and sale transaction.
In addition, to the extent the US gas export market becomes more robust over the coming years, how courts ultimately define the term “natural gas” could create significant controversies for producers. Many gas royalty clauses are proceeds based, providing that the lessor is entitled to a percentage of the “gross proceeds a Lessee receives . . . for the first sale to a person who is a non-Affiliate.” Thus, if a foreign purchaser pays a substantial premium to the current U.S. market price for exported gas and NGLs processed abroad, lessors may argue that their royalty payments should be calculated as a percentage of the amount paid for the gas and NGLs by the foreign purchaser, and possibly without regard to liquefying, transporting and regasifying costs, thus potentially making the U.S. gas export market uneconomic for producers with onerous or ambiguous gas royalty clauses, and without carefully structured gas purchase and sale arrangements in place.