Post-Production Costs

Published on: August 7, 2014

Two Wins for Chesapeake in 5th Circuit

The 5th Circuit Court of Appeals in New Orleans has ruled for Chesapeake in two cases, holding that it can deduct post-production costs from gas royalties. Potts v. Chesapeake Exploration, No. 13-10601, and Warren v. Chesapeake Exploration, No. 13-10619. Both cases were decided by the same three judges, and both opinions were written by Judge Priscilla R. Owen. In both cases, Judge Owen relied on the Texas Supreme Court case of Heritage Resources v. NationsBank, 939 S.W.2d 118 (Tex. 1996). Judge Owen was on the Texas Supreme Court when Heritage v. NationsBank was decided, and she wrote an opinion in that case. Judge Owen cites her own opinion in Heritage as the principal precedent for her opinions in Potts and Warren.

The Potts and Warren cases were tried in federal district court. Because Chesapeake’s home office is in Oklahoma, it has the right to remove suits filed against it in Texas to federal court. Federal courts have “diversity” jurisdiction over cases between citizens of different states. In diversity cases, federal courts must follow the law of the states. No federal law is involved. So, in deciding Potts and Warren, the 5th Circuit judges were attempting to predict what a Texas court would do, following prior precedent from Texas courts — in this case, Heritage v. NationsBank.

Heritage v. NationsBank is a seminal case in oil and gas law, some would say infamous. The question in Heritage was whether Heritage, the lessee, could deduct transportation costs for gas from royalties owed to NationsBank. NationsBank’s lease provided that royalties on gas would be “the market value at the well of 1/5 of the gas so sold or used, … provided, however, that there shall be no deductions from the value of the Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation or other matter to market such gas.” The Texas Supreme Court held that Heritage could deduct transportation costs from NationsBank’s royalty. In her concurring opinion, Justice Owen said that the no-deductions proviso on NationsBank’s lease was “circular” and “meaningless”:

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Published on: March 11, 2014

Chesapeake v. Hyder – Royalty Owner Wins Gas Royalty Dispute

By John McFarland

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:

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Published on: November 25, 2013

Chesapeake and Post-Production Costs

By John McFarland

Lawsuits against Chesapeake Exploration for wrongfully deducting post-production costs from its gas royalty payments are hitting a boiling-point. Suits are being pursued against the company in every jurisdiction where it operates, including Texas, Arkansas, Lousiana, Kansas, Ohio, West Virginia, Oklahoma and Pennsylvania. Chesapeake has recently been much more aggressive in deducting post-production costs. In the Barnett Shale in North Texas, its post-production cost deductions have been as much as $.70 to $1.00 per mcf, and with such low gas prices, some royalty owners’ payments have been halved by such deductions. Chesapeake’s royalty payments in North Texas have reportedly been on a net price of as little as eleven cents per mcf, and as little as 11% of the price other producers have based their royalty payments on. A recent Bloomberg article summarizes Chesapeake’s royalty payment practices.

Chesapeake has settled some claims, including large royalty owner claims in Pennsylvania. Chesapeake’s marketing practices in Pennsylvania mirror those it uses in the Barnett Shale. Last year, Chesapeake settled a claim brought by the Dallas-Fort Worth Airport for underpayment of royalties for $5 million. The Bass family in Fort Worth recently sued the company for wrongfully deducting post-production costs.

Chesapeake’s tactics for how it calculates its royalties cannot be understood without knowing something about how Texas courts have addressed deductibility of post-production costs. I have previously written three posts on this topic that can be seen here, here and here.

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Published on: October 15, 2010

Chesapeake Sued in Oklahoma For Underpayment of Royalties in Barnett Shale Wells

By John McFarland

A royalty owner in the Barnett Shale has sued Chesapeake in Oklahoma federal court for failure to properly pay royalties. The suit, Robyn Coffey vs. Chesapeake Exploration, L.L.C. and Chesapeake Operating, Inc., Civil Action No. CIV-10-1054-C, was filed on September 27 in the U.S. District Court for the Western District of Oklahoma, in Oklahoma City. A copy of the complaint can be viewed here: Coffey v Chesapeake.pdf The plaintiff seeks to bring the case on behalf of all royalty owners in the Barnett Shale formation, as a class action.

The plaintiff alleges that Chesapeake “employs a scheme” to reduce royalty payments by selling the gas to its wholly owned subsidiaries at a price “substantially less than either the market value at well or the amount actually received by Chesapeake Operating.”

The royalty clause in the plaintiff”s oil and gas lease is unusual. It provides for payment of royalties based on the “market value at the point of sale,” but not less than “the actual amount realized by the Lessee.” The clause says that all royalty paid to the lessor “shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation.” Most gas royalty clauses provide that gas royalties will be based on “the amount realized by Lessee, computed at the mouth of the well,” or similar language.

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Published on: February 23, 2009

Post-Production Costs in Texas-Part III: Yturria v. Kerr-McGee

By John McFarland

Last week, in Post-Production Costs in Texas-Part II, I discussed the Texas Supreme Court’s decision in Heritage Resources v. NationsBank regarding the deductibility of post-production costs from lessor’s royalties under an oil and gas lease. Justice Priscilla Owen (now a judge on the U.S. Court of Appeals for the Fifth Circuit) filed a concurring opinion in Heritage in which she said that “it is important to note that we are construing specific language in specific oil and gas leases. Parties to a lease may allocate costs, including post-production or marketing costs, as they choose.” Justice Owen’s conclusion was put to the test in Yturria v. Kerr-McGee Oil & Gas Onshore, LLC, decided by the U.S. 5th Circuit Court of Appeals on September 8, 2008.

My firm represented the royalty owners in Yturria v. Kerr McGee, and I was the author of two of the oil and gas leases construed in that case. As the court points out, these were not “standard” oil and gas leases. They contained detailed provisions as to how royalties were to be calculated and paid. The language was crafted as part of the settlement of earlier litigation with Kerr McGee over royalty payments, and at the time the language was agreed to there were existing wells on the leases that produced substantial quantities of gas. The Kerr-McGee gas was processed before sale under a processing agreement between Kerr-McGee and the processor, Enterprise.; The processing agreement required that Enterprise pay Kerr McGee for 80% of the natural gas liquids extracted from the gas, based on posted prices, less a “T & F Fee” for the costs of transportation and fractionation of the liquids. The issue in the case was whether the royalty owners should bear their royalty share of the T & F Fees charged by Enterprise. The trial court and the court of appeals both ruled in favor of the royalty owners, holding that, under the particular language of the leases, the T & Fees could not be deducted from the lessors’ royalty.

The leases provided that Kerr-McGee would pay a royalty on natural gas liquids (called “plant products” in the leases) equal to “1/4th of 75% of all plant products, or revenue derived therefrom, attributable to gas produced by Lessee from the leased premises (whether or not Lessee’s processing agreement entitles it to a greater or lesser percentage).” The leases also provided that “Lessor’s royalty shall never bear, either directly or indirectly, any part of the costs or expenses of production, gathering, dehydration, compression, transportation (except transportation by truck), manufacture, processing, treatment or marketing of the oil or gas from the leased premises.” The court of appeals agreed with the royalty owners that the “revenue derived” from plant products was the gross revenue based on the price set forth in the Enterprise-Kerr-McGee processing agreement, before deduction of the T & F Fees.

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Published on: February 16, 2009

Post-Production Costs in Texas – Part II

By John McFarland

Last week I introduced the term “post-production costs” and attempted to explain what those costs are and how oil companies account for such costs in calculating royalties. I said that Texas courts have construed the standard gas royalty clause to allow oil companies to deduct post-production costs from royalties. The Texas Supreme Court had occasion in 1996, in Heritage Resources, Inc. v. NationsBank, to address the deductibility of post-production costs. NationsBank (now Bank of America) was named trustee of trusts created under the will of David Tramell. NationsBank signed oil and gas leases covering lands owned by those trusts, and Heritage Resources drilled gas wells on the leases. Heritage deducted transportation costs from the royalties it paid to the trusts, and NationsBank sued to recover those deductions, based on the following language in its leases:

The royalties to be paid Lessor are …

;on gas, .. the market value at the well of 1/5 of the gas so sold or used, … provided, however, that there shall be no deductions from the value of the Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation or other matter to market such gas.

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Published on: February 9, 2009

Deductibility of Post-Production Costs in Texas Oil and Gas Leases

By John McFarland

Mineral owners in Texas have learned that their leases should provide for a “cost-free” royalty. By this, they generally understand that the lease should prohibit the lessee from deducting any costs from their royalty. Herein, then, are some ruminations about what lawyers and oil companies refer to as “post-production costs.”

The problem of post-production costs generally arises only in relation to gas production. The typical oil and gas lease provides that the royalty on gas shall be a specified fraction of “the market value at the well”, or of the “amount realized at the well,” or the “net proceeds at the mouth of the well.” The phrase “at the well,” as interpreted by Texas courts, has a highly specialized meaning. It means that the lessee, in calculating the royalty, can deduct any costs incurred to make the gas marketable and to get the gas to the point of sale. (I’ll bet most mineral owners don’t realize that when they sign a lease.) Such costs are referred to as “post-production costs” because they are incurred after the gas is produced but before it is sold, and they can be quite significant.

Suppose the following facts: ABC Oil Company drills the Jones #1 gas well on the Jones farm. ABC has a lease from Jones that provides for payment of a 1/4th royalty on the “amount realized at the mouth of the well.” The Jones #1 gas as it comes from the ground contains quantities of water, hydrogen sulfide and other impurities that have to be removed before the gas can be sold to a pipeline. Also, the gas itself is actually a mixture of several different hydrocarbon gases – methane, ethane, butane and propane. Although most natural gas is methane — the same gas you burn in your stove — some natural gas contains significant quantities of “heavier” gases such as ethane, butane and propane. If there are enough of those other gases, they must be separated from the methane before the methane can be sold to a pipeline, because the heavier gases tend to condense into a liquid in the pipeline and cause problems with the pipeline’s transmission system. The heavier gases can be sold as separate products. They generally have a higher value per unit volume than methane because they have a higher heating value. That is, they produce more heat per unit volume when they are burned as fuel.

So ABC Oil Company installs separators and treaters on the Jones lease to remove the water and hydrogen sulfide from the gas. The cost of such treatment is $.10 per mcf. ABC also contracts with XYZ Processing Company to “process” the gas to remove the heavier hydrocarbons. Its agreement with XYZ Processing Company provides that XYZ gets to keep 25% of the heavier gases as its fee for processing the gas from the Jones #1 well. ABC also enters into a contract with Big Inch Pipeline Company to transport the methane to Commercial Plastics Company for $.05 per mcf, and ABC enters into a contract to sell the gas to Commercial Plastics Company for $5.00 per mcf. Finally, ABC agrees to sell its 75% of the heavier gases to NGL Purchasing Company for $7.00 per mcf.

In its first month of production, the Jones #1 produces 100,000 mcf of gas. 1,000 mcf of that gas is used as fuel to run the treaters to remove the water and hydrogen sulfide. After the remaining gas is treated and processed, it becomes 90,000 mcf of methane and 9,000 mcf of heavier gases. ABC gets back the 90,000 mcf of methane, which it sells to Commercial Plastics for $450,000, and it gets back 75% of the 9,000 mcf of heavier gases, which it sells to NGL Purchasing Company for $47,250. ABC Oil Company thus receives $450,000 for the methane and $47,250 for the heavier gases, for a total of $497,250.

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