Articles Posted in Post-Production Costs

Chesapeake has asked the Texas Supreme Court to hear its appeal of Chesapeake v. Hyder, decided by the San Antonio Court of Appeals in March of this year. The Supreme Court has asked the parties to file briefs on the merits, and Chesapeake filed its brief last week. Although the Court has not yet agreed to hear the case, its request for briefs is an indication that the Court may do so.

I wrote about the Hyder case when it was decided last March. Since then, the U.S. Court of Appeals for the 5th Circuit has decided two other Chesapeake cases, Chesapeake v. Potts and Chesapeake v. Warren, ruling in Chesapeake’s favor in both cases. All three cases involve deduction of post-production costs from royalties. Multiple cases have been filed against Chesapeake challenging its post-production-costs deductions, because of its aggressive method of calculating those costs. In all three cases, Chesapeake relies heavily on a Texas Supreme Court case decided in 1996, Heritage Resources v. NationsBank. The Texas Supreme Court has not discussed its opinion in Heritage since it was decided. Hyder may be its opportunity to do so.

The oil and gas lease in Hyder provides that “the royalty reserved herein by Lessors shall be free and clear of all production and post-production costs and expenses.” It also states that “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.” The Court of Appeals held that the lease prohibited Chesapeake from deducting transportation costs.

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.

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.

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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