Last week, the Fourth Court of Appeals in San Antonio issued its opinion in Chesapeake v. Hyder.pdf, on gas royalties owed to the Hyder family for production in Johnson and Tarrant Counties, in the Barnett Shale. The court upheld a judgment against Chesapeake for more than a million dollars, including $250,000 in attorneys’ fees. The result is not surprising considering the language in the lease, but the case is interesting because it reveals Chesapeake’s structure for marketing of gas in the Barnett Shale, obviously designed to reduce its gas royalty obligations.
The principal issue on appeal was whether Chesapeake could reduce the Hyders’ royalty by the amount of transportation costs paid by Chesapeake to unrelated pipeline companies. The trial court and court of appeals held that it could not. As I have written before (here, here and here), deductibility of post-production costs is a continuing issue for gas royalty payments in Texas. Prior Supreme Court cases have held that such costs are deductible under most standard gas royalty clauses.
The Hyders’ royalty clause was not a standard lessee-form lease. It provided:
Lessee covenants and agrees to pay Lessor the following royalty: … (b) for natural gas, including casinghead gas and other gaseous substances produced from the Leased Premises and sold or used on or off the Leased Premises, twenty-five percent (25%) of the price actually received by Lessee for such gas. Lessee shall not sell hydrocarbons to entities owned in whole or in part by Lessee or to entities affiliated with Lessee in any way, without the express written consent of Lessors. The royalty reserved herein by Lessors shall be free and clear of all production and post-production costs and expenses, including but not limited to, production, gathering, separating, storing, dehydrating, compressing, transporting, processing, treating, marketing, delivering, or any other costs and expenses incurred between the wellhead and Lessee’s point of delivery or sale of such share to a third party. … In no event shall the volume of gas used to calculate Lessors’ royalty be reduced for gas used by Lessee as fuel for lease operations or for compression or dehydration of gas. … Lessors and Lessee agree that the holding in the case of Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms and provision of this Lease.
Chesapeake has different affiliated companies, each of which has a different role in the process of production, gathering, marketing and sale of its gas. The owner of the lease is Chesapeake Exploration, LLC. Chesapeake Operating, Inc., drills and operates the wells and pays the royalty. Chesapeake Energy Marketing, Inc., buys the gas from Chesapeake Operating (as agent for Chesapeake Exploration). Chesapeake Midstream Partners, LP gathers the gas from the leases and delivers it to pipelines owned and operated by unrelated parties. Those pipelines in turn deliver the gas to purchasers, who pay Chesapeake Energy Marketing, Inc. Confused yet? It gets better.
Chesapeake’s royalties are based on a weighted-average sales price for all gas that passes through the gathering system and sold to third parties: total proceeds received divided by total gas sold equals the weighted average sales price, or “WASP”. The contract between Chesapeake Operating and Chesapeake Energy Marketing provides that the price paid to Chesapeake Operating is the price received by Marketing for the sale of the gas to third parties, less all costs incurred by Marketing to get the gas to the ultimate purchaser – both the gathering costs charged by Chesapeake Midstream Partners and the pipeline fees charged to transport the gas to the ultimate buyer – plus a “marketing fee” of 3% paid to Marketing. For most royalty owners, Chesapeake pays royalty on this net price, after deducting all post-production costs, including the gathering fees charged by Midstream Partners and the marketing fee charged by Marketing.
But the Hyders’ lease prohibited Chesapeake from selling gas to an affiliate without the Hyders’ consent, which it never obtained. So Chesapeake agreed that its royalty should be based on its weighted average sales price, without deduction of fees charged by Marketing or Midstream Partners. But Chesapeake claimed that it could deduct the pipeline transportation costs charged by unaffiliated pipelines to transport the gas to the ultimate buyer. This issue became the principal dispute in the case. The trial court and court of appeals agreed that such costs could not be deducted. “Free and clear of all costs” means just what it says, said the courts.
Another interesting issue in the case was whether Chesapeake must pay royalty on gas “lost and unaccounted for.” The facts showed that not all gas produced from the Hyder lease was sold:
– some gas was used by Chesapeake as “gas lift” gas, — that is, reinjected down the wellbore to assist in production from the well.
– some gas was used as fuel for compression and dehydration of gas produced from the lease – “lease-use gas.”
– some gas was lost and unaccounted for between the wellhead and the point of delivery to the ultimate purchaser. This gas is lost through leaks in the gathering and transportation system.
Chesapeake agreed that the lease required it to pay royalty on all gas “produced and sold or used ….” It agreed that gas used as fuel for compression and dehydration was gas “used”. But Chesapeake argued that it did not have to pay royalty on gas lost and unaccounted for. That gas was neither sold nor used. On this point, the trial court and court of appeals agreed with Chesapeake. “Gas lost or unaccounted for is neither sold nor used.” (The parties agreed that no royalty was owed on gas-lift gas.)
The Hyder lease also had a special provision allowing the lessee to locate wells on the leased premises drilled horizontally onto adjacent lands. For such well locations, the lessee agreed to pay to the Hyders a “cost-free” overriding royalty. Chesapeake claimed that it could deduct post-production costs in calculating the Hyders’ overriding royalty. The trial court and the court of appeals disagreed; “cost-free” means free of all costs, including post-production costs.
One of the remarkable things about this case is that Chesapeake argued in the trial and on appeal that it should not have to pay royalty on gas lost and unaccounted for because the only “price received” by Chesapeake was the price paid for the sale of the gas to non-affiliated third parties. In fact, Chesapeake obtained a finding from the trial court to that effect. Chesapeake’s attorneys showed that the first “buyer” of the gas, Chesapeake Energy Marketing, never received any money from the sale of the gas and never paid any money to Chesapeake Operating, the seller, or Chesapeake Exploration, the owner, even though the gas sales contract for the “first sale” of the gas was between Chesapeake Operating and Chesapeake Energy Marketing. It appears to me that Chesapeake was in effect admitting that its marketing arrangement with its affiliate Chesapeake Marketing was a sham.
Another interesting fact revealed in the Hyders’ briefs is that, between 2005 and 2011, Chesapeake changed the way it calculated the Hyders’ royalty four times. Initially, it calculated the Hyders’ royalty based on the total wellhead volume, using the WASP. Then it began paying only on the volumes sold to unrelated third parties, less third-party transportation costs. Then it stopped deducting transportation costs and paid based on the well-head volume times the WASP. Then it began paying on the volumes sold to third parties, less third-party transportation charges.
It is my experience that Chesapeake does not show any post-production-cost deductions on its check details and refuses to provide that information to royalty owners unless the royalty owner is granted the right to audit its royalties in his/her oil and gas lease–and even then it sometimes refuses. Trying to determine whether a royalty owner is being unlawfully charged post-production costs is very difficult. Trying to collect those charges, even with very good lease language like the Hyders’, is expensive and time-consuming, as the Hyders have learned.