Articles Posted in Post-Production Costs

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A federal judge in Dallas has ruled that Chesapeake cannot deduct post-production costs on the Plaintiffs’ leases covering lands in Tarrant and Johnson Counties, in the Barnett shale.  The order can be viewed here: Winscott – Order on MSJs 

The case is Trinity Valley School, et al. vs. Chesapeake Operating, Inc., et al., No. 3:13-CV-08082-K, in the US District Court for the Northern District of Texas, Judge Ed Winscott presiding. The order, although a partial summary judgment, appears to resolve Chesapeake’s claim of right to deduct post-production costs. Plaintiffs include Ed Bass, the Harris Methodist Southwest Hospital and Texas Health Presbyterian Hospital Dallas. The language construed in the leases varies, but all of the leases contain language dealing with sales to an affiliate.

As I have discussed before, Chesapeake sells its gas at the well to its affiliate Chesapeake Energy Marketing (CEMI). The price on which Chesapeake pays royalties is based on the weighted average price CEMI receives for the gas less gathering and transportation costs incurred by CEMI and a CEMI marketing fee.

The Bass leases at issue allowed deduction of post-production costs only if

(i) charged at arms-length by an entity unafilliated with Lessee; (ii) actually incurred by Lessee for the purpose of making the oil and gas produced hereunder ready for sale or use or to move such production to market; and (iii) incurred by Lessee at a location off of the Leased Premises …

The Court agreed with the Basses that, under Chesapeake’s marketing scheme, its sales of gas failed to meet any of these three requirements. The costs were charged by CEMI, an affiliate by an entity unafilliated with Chesapeake; the costs were not “actually incurred by Lessee,” because Chesapeake sold the gas at the well to CEMI, which incurred the charges; and the costs were not incurred “at a location off of the Leased Premises” because Chesapeake sold the gas at the well, where the charges were incurred.

Chesapeake found itself in the awkward position of arguing that the costs that were actual third-party transportation costs, as opposed to CEMI’s fees, were really “incurred” by Chesapeake, even though it created the scheme of selling at the well to its affiliate and its affiliated incurred the costs. It argued that the meaning of the lease “turns on the meaning of ‘incur’.” (Reminds me of Bill Clinton.)

The leases provide that, if Chesapeake sells to an affiliate, the royalties shall be based on the average of the two highest prices for gas being paid by purchasers in Tarrant County. The Plaintiffs said that this should, at least, be the weighted average price (WASP) for which CEMI sold their gas, without deductions for post-production costs. Chesapeake cried unfair; that price was for sales at locations remote from the wells, after post-production costs had been incurred. The price, Chesapeake argued, should be based on the value of the gas at the well.  The Court disagreed. “Because the market value is determined by a reference price, rather than a value at a geographical point, and WASP qualifies as a reference price, the Court finds that the WASP establishes a minimum price for the market value inquiry.”

In this case, Chesapeake’s sales to its own affiliate have come back to haunt it. Had Chesapeake sold its gas in the normal manner rather than through its affiliate, it would have been entitled to deduct legitimate third-party costs from the Plaintiffs’ royalty.

 

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Chesapeake is spending a lot of money on lawyers.

Dan McDonald, a Fort Worth attorney, has filed some 250 cases against Chesapeake contending that it is underpaying its royalty owners. Companies affiliated with former House of Representatives Speaker Tom Craddick have now been added to McDonald’s client list. So many cases have been filed against it in Texas that Chesapeake asked the cases to be granted multidistrict litigation status, so that one judge could control pretrial discovery and motions and settings. Two judges have been appointed for that purpose, one for McDonald’s cases and another for cases brought by other attorneys. Chesapeake is settling cases as fast as it can.

Most of the claims against Chesapeake arise from its structure for selling gas. Chesapeake sells its gas at the wellhead to its wholly owned subsidiary Chesapeake Energy Marketing. Chesapeake Energy Marketing arranges for the gathering of the gas and delivery to central sales points, and pays Chesapeake for the gas based on a weighted average price of all sales at those central gathering points, less costs of compression, gathering, treating and transportation, and less a “marketing fee” charged by Chesapeake Energy Marketing. The costs incurred between the wellhead and the point of delivery to the purchaser were formerly incurred by another Chesapeake affiliate, Access Midstream. Chesapeake spun off its gathering systems into a separate company a few years ago, and as part of that deal it guaranteed a minimum rate of return on those gathering systems to the new spin-off company, thereby receiving a premium price in the market for the new company’s shares. Chesapeake pays royalties based on the new price it receives from Chesapeake Energy Marketing, after deduction of post-production costs and marketing fees. McDonald says that these “costs” are “sham sales” and “fraudulent transactions.”

McDonald’s first ten cases against Chesapeake are set for trial early next year. McDonald’s cases are mainly for wells in the Barnett Shale, where Chesapeake has sold a share in its wells to Total, the French energy company. Total is also named as a defendant, and it markets its share of gas in a manner similar to Chesapeake.

Chesapeake recently reported a $4 billion loss and has eliminated its dividend. It recently sued its founder and former CEO Aubrey McClendon for allegedly stealing trade secrets when he was fired by the company.

Chesapeake recently lost an important case in the Texas Supreme Court, Chesapeake v. Hyder, and the opinion in that case has other companies concerned about their ability to deduct post-production costs from royalties. Chesapeake recently filed a motion for rehearing in that case, and amicus briefs urging the court to reconsider its opinion have been filed by Texas Oil & Gas Association, BP, Devon, EOG, Exco, Shell, XTO and others. With low gas prices, the ability to force royalty owners to share in post-production costs can mean the difference between profit and loss for some companies.

 

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The Texas Supreme Court has ruled 5 to 4 that Chesapeake cannot deduct post-production costs from the Hyder family’s gas royalties.

The case in the Supreme Court actually addresses only the Hyders’ overriding royalty. As part of the Hyders’ oil and gas lease, the Hyders agreed that Chesapeake could use their land to drill horizontal wells producing from their neighbors’ land — the surface location on the Hyders’ land, but all of the productive lateral of the well under the neighbor’s property. In exchange, Chesapeake agreed to pay the Hyders a 5% royalty on production from such wells. Because the Hyders have no mineral interest in the lands from which these wells produce, the parties referred to this royalty as an overriding royalty.

The Hyders’ lease contains very specific provisions prohibiting Chesapeake from deducting post-production costs from the Hyders’ royalty on production from their lands. But the lease provision granting the overriding royalty on production from wells bottomed under their neighbors’ property is not so clear. Although Chesapeake originally fought to deduct post-production costs from both the royalties and the overriding royalties, the trial court and court of appeals ruled for the Hyders on all claims, and Chesapeake elected to appeal to the Texas Supreme Court only on the issue of deductibility of post-production costs from the Hyders’ overriding royalty.

The lease provision granting the overriding royalty calls for “a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent (5%) of gross production obtained” from wells bottomed under neighbors’ land.” The lease also provided 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 provisions of this Lease.”

Justice Hecht wrote the majority opinion, joined by Justices Green, Johnson, Boyd and Devine. The parties’ arguments in their briefs and at oral argument focused on what was meant by “cost-free (except only its portion of production taxes).” Chesapeake argued that “cost-free” refers only to production costs. The Hyders argued that an overriding royalty is by definition free of production costs, so “cost-free” must refer to post-production costs. Justice Hecht said that “We disagree with the Hyders that ‘cost-free’ … cannot refer to production costs. … But Chesapeake must show that while the general term ‘cost-free’ does not distinguish between production and post-production costs and thus literally refers to all costs, it nevertheless cannot refer to post-production costs.”

Chesapeake made another argument, based on the requirement that the overriding royalty be based on “gross production.” It reasoned that “gross production” meant all gas, measured at the well when produced, so the value of that production must be measured at the wellhead, and any costs incurred thereafter must be shared by the royalty owner. The overriding royalty is expressed as a fraction of “gross production,” a royalty payable in-kind. Chesapeake argued that, if the Hyders elected to separately market their share of the gas, they would have to incur those post-production costs to get the gas to market, so the parties intended that the Hyders should bear those costs if Chesapeake sold the gas and paid the Hyders their 5% share of proceeds.  Hecht disagreed. “The fact that the Hyders might or might not be subject to post-production costs by taking the gas in kind does not suggest that they must be subject to those costs when the royalty is paid in cash.” Hecht concluded that “‘cost-free’ in the overriding royalty provision includes post-production costs.”

Four justices dissented. Justice Brown wrote the dissenting opinion, joined by Justices Willett, Guzman and Lehrmann. The dissenters agreed with Chesapeake that, because the overriding royalty was on “gross production,” the Hyders had to bear post-production costs. They concluded that “Though the overriding royalty may not have been expressed using the familiar market-value-at-the-well language, I read its value as being just that. Cf. Heritage, 939 S.W.2d at 131 (Owen, J., concurring).” Further discussing Heritage, Justice Brown said:

As recognized in Heritage, royalty clauses that purport to modify a royalty valued at the well are inherently problematic. 939 S.W.2d at 130 ((Owen, J., concurring)(“The concept of ‘deductions’ of marketing costs from the value of the gas is meaningless when gas is valued at the well.”). Here, no post-production costs have been incurred at the time of production, and it means nothing to say that the overriding royalty is free of those yet-to-be incurred costs.

In short, Justice Brown gave controlling effect to the “gross production” language, while Justice Hecht gave controlling effect to the “cost-free” language.

Justice Hecht’s opinion is interesting in its discussion of two other lease provisions. Although the case before the court did not encompass whether Chesapeake could deduct post-production costs from the Hyders’ royalty, Justice Hecht discussed the royalty clause. One of the provisions in the royalty clause states that the Hyders’ royalty shall be

free and clear of all production and post-production costs and expenses, including but not limited to, production, gathering, separating, storing, dehydrating, compression, 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.

Remarkably, Justice Hecht considered this language “surplusage”:

The gas royalty in the lease does not bear post-production costs because it is based on the price Chesapeake actually receives for the gas through its affiliate … after post-production costs have been paid. Often referred to as a ‘proceeds lease’, the price-received basis for payment is sufficient in itself to excuse the lessors from bearing post-production costs. And of course, like any other royalty, the gas royalty does not share in production costs. But the royalty provision expressly adds that the gas royalty is ‘free and clear of all production and post-production costs and expenses,’ and then goes further by listing them. This addition has no effect on the meaning of the provision. It might be regarded as emphasizing the cost-free nature of the gas royalty, or as surplusage.

Another provision in the Hyders’ lease disclaimed the holding in Heritage v. NationsBank:

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 provisions of this Lease.

The royalty clause in Heritage  provided that Lessor’s royalty is

1/5 of the market value at the well 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 court in Heritage held that the lessee could deduct transportation costs from the royalty, and that the “no-deductions” proviso was “mere surplusage.”

The Hyders argued that the “Heritage disclaimer” clause in their lease showed the parties’ intent that their overriding royalty should be free of post-production costs. Justice Hecht disagreed:

Heritage Resources does not suggest, much less hold, that a royalty cannot be made free of post-production costs. Heritage Resources holds only that the effect of a lease is governed by a fair reading of its text. A disclaimer of that holding, like the one in this case, cannot free a royalty of post-production costs when the text of the lease itself does not do so. Here, the lease text clearly frees the gas royalty of post-production costs, and reasonably interpreted, we conclude, does the same for the overriding royalty. The disclaimer of Heritage Resources’ holding does not influence our conclusion.

The dissent also discussed Heritage.  Justice Brown notes that, unlike the gas royalty clause, the oil royalty clause in the Hyder lease provides for payment based on the “market value at the well” of the oil, just as in Heritage.  Justice Brown questions Justice Hecht’s conclusion that the “Heritage disclaimer” in the Hyders’ lease should have no effect even as applied to the oil royalty clause: “The disclaimer could be interpreted as a belt-and-suspenders attempt to ensure the ‘free and clear’ language is given effect despite its conflict with the oil royalty’s market-value-at-the-well definition.” In other words, the Heritage disclaimer might not be “surplusage.” But the four dissenting justices would nevertheless in effect follow Heritage. They would give effect to the “gross production” language in the overriding royalty clause, and would hold that this term is equivalent to the “at the well” clause in the Heritage royalty provision; and they would then hold that, because the overriding royalty is to be valued “at the well,” the language making the overriding royalty “cost-free” is, under Heritage, surplusage.

So, what should royalty owners and their counsel take from these opinions?

This firm filed an amicus brief in Hyder on behalf of the Texas Land and Mineral Owners’ Association and the National Association of Royalty Owners-Texas, in which we urged the court to clarify how royalty clauses should be construed in relation to post-production costs, and how much, if at all, the court’s prior decision in Heritage v. NationsBank should be relied on as precedent. Unfortunately, this case does not provide much guidance. Justice Hecht does note in a footnote that, on rehearing in Heritage, the court re-aligned itself, and one justice recused himself. The result, not mentioned in the footnote, is that the court was evenly divided on whether the Court’s original opinion was correct. And Justice Hecht’s opinion does say that “Heritage Resources holds only that the effect of a lease is governed by a fair reading of its text.” Perhaps this is Justice Hecht’s way of saying that Heritage has little precedential value where the text of the royalty clause differs from that in Heritage. But the continued power of Heritage is reflected in the fact that four justices dissented and would hold that Heritage requires a reading of the Hyder overriding royalty clause that would allow Chesapeake to deduct post-production costs, despite its “cost-free” language.

One lesson royalty owners and their lawyers should take away from Hyder: a “Heritage disclaimer” clause in a lease, without more, will not insulate the royalty owner from post-production costs.

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Last November, the Texas General Land Office lost its appeal in Commissioner v. SandRidge Energy, Inc., in the El Paso Court of Appeals. For the first time, a court has ruled that a lessee can deduct post-production costs under the Texas General Land Office’s Relinquishment Act lease form, citing Heritage Resources v. NationsBank, 939 S.W.2d 118 (Tex. 1996).

The case actually involves several oil and gas leases owned by SandRidge in Pecos County, some covering lands owned by private parties, some covering Relinquishment Act lands. (The State owns the minerals under Relinquishment Act land; the surface owner is agent for the state in granting oil and gas leases, for which the surface owner receives ½ of bonuses and royalties. The lease must be approved by the GLO and be on the approved GLO lease form.) The most interesting part of the case is the court’s interpretation of the GLO’s Relinquishment Act lease form. There are somewhere between 6.4 million and 7.4 million acres of Relinquishment Act lands in Texas, principally in West Texas, in and around the Permian Basin.

SandRidge’s wells on the leases in dispute produce mostly carbon dioxide, mixed with some natural gas. Originally, SandRidge paid the GLO royalties on its sales of natural gas and carbon dioxide. More recently, SandRidge made an agreement with Oxy USA; SandRidge built a plant, the Century Plant, to extract the CO2 from SandRidge’s gas. Oxy owns and operates the plant and gets the CO2 extracted; SandRidge gets the natural gas. Oxy doesn’t charge SandRidge for separating the gas from the CO2. Oxy uses the CO2 in secondary recovery projects. The plant reportedly cost a billion dollars.

When the Century Plant was up and running, SandRidge stopped paying royalties on CO2 under its Relinquishment Act leases. The State sued, and the parties filed motions for partial summary judgment. The trial court ruled in favor of SandRidge.

The GLO relied on the following provisions of the Relinquishment Act leases:

4(B).  NON PROCESSED GAS. Royalty on any gas (including flared gas), which is defined as all hydrocarbons and gaseous substances not defined as oil in subparagraph (A) above, produced from any well on said land (except as provided herein with respect to gas processed in a plant for the extraction of gasoline, liquid hydrocarbons or other products) shall be 25% part of the gross production or the market value thereof, at the option of the owner of the soil or the Commissioner of the General Land Office, such value to be based on the highest market price paid or offered for gas of comparable quality in the general area where produced and when run, or the gross price paid or offered to the producer, whichever is the greater ….

 7.  NO DEDUCTIONS. Lessee agrees that all royalties accruing under this lease (including those paid in kind) shall be without deduction for the cost of producing, gathering, storing, separating, treating, dehydrating, compressing, processing, transporting, and otherwise making the oil, gas and other products hereunder ready for sale or use. Lessee agrees to compute and pay royalties on the gross value received, including any reimbursements for severance taxes and production related costs.

 The State argued that SandRidge was paying for the cost of treating the natural gas by giving the CO2 to Oxy, and that this cost is not deductible under the Relinquishment Act lease form. SandRidge argued that the cost of treating the gas is deductible, based on Heritage v. NationsBank.  In Heritage, the Texas Supreme Court held that, where a lease provides for royalties based on “market value at the well,” a lessee may deduct post-production costs even if the lease prohibits such deductions. According to the Court, “from SandRidge’s perspective, Heritage stands for the principle that a market value at the well clause trumps any other provision that conflicts with it.” SandRidge argued that the paragraph 4(B) of the Relinquishment Act lease is in effect a market-value-at-the-well royalty provision. The El Paso Court of Appeals agreed. It said that the clause provides for royalties based on the wellhead measurement of gas volume. “The royalty is therefore owed on the substance so measured: raw gas, including all of its components. ‘When there is a wellhead measurement, payment is due for gas in its natural state, not on the liquid hydrocarbons which are later extracted.’ ConocoPhillips Co. v. Incline Energy, Inc., 198 S.W.3d 377, 381 (Tex.App.–Eastland 2006, pet denied)(citing Carter v. Exxon Corp., 842 S.W.2d 393 (Tex.App.–Eastland 1992, writ denied)).”

To my knowledge, this is the first appellate decision applying the Heritage rationale to a royalty clause that does not contain “market-value-at-the-well” language.

The GLO intends to appeal to the Texas Supreme Court. The Supreme Court has already agreed to hear Chesapeake’s appeal in the Hyder case, which also implicates Heritage.

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A team of lawyers in Pennsylvania has filed an anti-trust suit against Chesapeake and Williams Partners (Formerly Access Midstream Partners) alleging that they conspired to restrain trade in the market for gas gathering services in and around Bradford County, Pennsylvania. The plaintiffs also sued Anadarko, Statoil, and Mitsui, all of whom own interests in Chesapeake’s leases. The suit alleges violation of the oil and gas leases granted by the plaintiffs, violations of ant-trust law, and violation of the Racketeer Influenced and Corrupt Organizations Act (RICO). A copy of the complaint, filed in federal court in Pennsylvania, can be found here.

The team of lawyers who filed this suit have their own website, “Marcellus Royalty Action.” They say that their approach differs from other suits against Chesapeake in that they will not seek class action status, they intend to pursue discovery before negotiating settlements, and they will sue all working interest owners responsible for royalty payments.

Royalty owner suits against Chesapeake have become a growth industry for attorneys. Recently, Chesapeake requested that multiple royalty owner suits against it in the Barnett Shale region of Texas be assigned to a pretrial court for consolidated and coordinated pretrial proceedings.  (Defendants Joint Motion for Transfer and Request for Stay) The request says that more than 3,200 landowners have filed 97 separate suits in Johnson, Tarrant and Dallas Counties alleging that Chesapeake and Total E&P, USA, Inc. (Chesapeake’s working interest partner in the Barnett Shale) have charged excessive post-production costs. This request results primarily from multiple suits filed by the McDonald Law Firm. See http://royaltyripoff.com/.  McDonald has said he does not oppose Chesapeake’s request.

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As I have written, Chesapeake has asked the Texas Supreme Court to reverse the San Antonio Court of Appeals’ decision in Chesapeake v. Hyder. The court of appeals ruled that Chesapeake could not deduct post-production costs from the Hyders’ royalty.

The Texas Land & Mineral Owners’ Association and the National Association of Royalty Owners – Texas have filed an amicus brief in Hyder supporting the Hyders’ case. The brief can be viewed here. Final Amicus_Brief_Chesapeake_v__Hyder.pdf It was authored by my firm and by Raul Gonzalez, who was a member of the Texas Supreme Court when the court decided Heritage v. NationsBank, the case relied on by Chesapeake as authority for its deduction of post-production costs.

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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.

The Court of Appeals opinion has an interesting discussion of Chesapeake’s structure for marketing and selling 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.

A recent investigative report by Pro Publica describes how Chesapeake spun off its subsidiary, Chesapeake Midstream Partners (which became Access Midstream), in the process raising $4.76 billion.  According to the report, Chesapeake sold its network of gathering lines in Pennsylvania, Ohio, Louisiana, Texas and the Midwest to Access, and entered into an agreement with Access for Access to gather and transport Chesapeake’s gas. Over a ten-year period, Chesapeake pledged by this contract to pay Access enough in fees to repay Access’s purchase price plus a 15 percent return on the investment. The agreement also provides for Access to pay Chesapeake for use of certain Chesapeake equipment. According to the report, the result of these transactions was to greatly increase Chesapeake’s cost of gathering its gas, to an average of 85 cents per mcf. That gathering cost greatly increased the deductions on Chesapeake’s royalty owners’ checks. In effect, it could be argued that Chesapeake has monetized some of its gas reserves by locking itself into a long-term gathering agreement with Access, in exchange for a $4.76 billion payment from Access, and in the process created an inflated gathering charge which can be passed on to its royalty owners.

In June, attorneys in Pennsylvania filed suit against Chesapeake, seeking certification of a class action on behalf of Pennsylvania royalty owners, alleging that the system used by Chesapeake for marketing its gas constitutes a violation of the Racketeer Influenced and Corrupt Organizations Act, or RICO. (Complaint can be viewed here.) The lawsuit claims that  “defendants, under the guise of Chesapeake’s subsidiaries’ agreements with lessors, exploited deductions language from the lease agreements to, among other things, shift repayment of Chesapeake’s off-balance sheet loan from Access Midstream to the lessors.”

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Last month I wrote about two cases recently decided by the U.S. Court of Appeals for the 5th Circuit in which Chesapeake defeated royalty owners’ efforts to prevent it from reducing their royalties by deducting post-production costs. One of those cases is Potts v. Chesapeake. The plaintiffs in that case have asked the Court of Appeals to reconsider its appeal “en banc,” meaning that it has asked the other judges on the court to grant its petition for rehearing and reconsider the decision of the three-judge panel who decided the case. Plaintiffs’ Petition for Rehearing may be viewed here:  Potts Petition for Rehearing En Banc.pdf

Yesterday, our firm filed a friend-of-the-court brief in the Potts case, on behalf of the Texas Land and Mineral Owners Association and the National Association of Royalty Owners – Texas, asking the Court to grant the plaintiff’s motion for rehearing and either consider the case en banc or refer the question to the Texas Supreme Court for its consideration. A copy of our brief may be viewed here:  Potts v. CHK Amicus Brief.pdf

Meanwhile, in Pennsylvania, suit has been filed against Chesapeake claiming that its conduct in selling gas to its affiliate company at prices well below market, and then selling its affiliate company for a substantial profit, constituted fraud on its royalty owners in violation of the Racketeer Influenced and Corrupt Organizations Act, known as RICO.  That petition can be viewed here:  Suessenbach v. Chesapeake.pdf

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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”:

There is little doubt that at least some of the parties to these agreements subjectively intended the phrase at issue to have meaning. However, the use of the words “deductions from the value of Lessor’s royalty” is circular in light of this and other courts’ interpretation of “market value at the well.” The concept of “deductions” of marketing costs from the value of the gas is meaningless when gas is valued at the well.

There were three opinions from the court in Heritage: a majority opinion written by Justice Baker, joined by Chief Justice Phillips, and Justices Cornyn, Enoch and Spector; a concurring opinion by Justice Priscilla Own, joined by Justice Hecht; and a dissenting opinion by Justice Gonzalez, joined by Justice Gregg Abbott.  (Cornyn went on to be Texas’ U.S. Senator; Justice Abbott subsequently became Texas Attorney General and is now running for Texas Governor; Justice Owen was nominated by President Bush to fill the vacancy on the 5th Circuit left by Judge Will Garwood’s retirement in 2001, but she was not confirmed by the Senate until 2005.)

Several amicus briefs were filed in Heritage asking the court to reconsider its decision, but the court refused. Justice Gonzalez, however, wrote an opinion dissenting on motion for rehearing, in which Justices Cornyn, Spector and Abbott joined. It is published at 960 S.W.2d 619. In that opinion, Justice Gonzalez said that the court was evenly divided, 4 to 4, on whether to grant the motion for rehearing. Justice Enoch had recused himself from the case, for reasons not stated, and Justices Cornyn and Spector had changed their minds, now siding with Justice Gonzalez’s dissent. And Justice Phillips had decided to concur in Justice Owen’s opinion rather than join Justice Baker’s original majority opinion. Because a vote of 5 justices is required to grant rehearing, the motion failed. But, said Justice Gonzalez, there was no longer any majority opinion. “Because we are without majority agreement on the reasons supporting the judgment,” he said, “the judgment itself has very limited precedential value and controls only this case.” And, he predicted, “the Court’s error in this case will have far-reaching effects on the oil and gas industry in Texas, as millions of dollars will now be placed in dispute.”  His prediction has proven true.

Of the two cases decided by the 5th Circuit, Potts is the most interesting. The oil and gas lease from Potts to Chesapeake provided that royalties on gas would be “the market value at the point of sale of 1/4 of the gas sold or used.” It also provided:

Notwithstanding anything to the contrary herein contained, all royalty paid to 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.”

Another lease provision said:

Payments of royalties … shall be based on sales of leased substances to unrelated third parties at prices arrived at through arms length negotiations. Royalties to Lessor on leased substances not sold in an arms length transaction shall be determined based on prevailing values at the time in the area.

As I have written before, Chesapeake has created a complex relationship among its affiliate companies. One affiliate, Chesapeake Operating, operates the lease for Chesapeake. Another affiliate, Chesapeake Energy Marketing (CEMI), buys the gas from Chesapeake Operating at the wellhead. CEMI gathers the gas from Chesapeake’s wells and resells it to purchasers at remote points of sale. The price that CEMI pays Chesapeake for the gas is based on the weighted average price of all gas sold at those remote points of sale, less the post-production costs CEMI incurs between the wellhead and the points of sale. Royalties were paid to Potts based on that net price, so that Potts, as royalty owner, was bearing his share of those post-production costs.

Justice Owen’s opinion holds that Chesapeake is entitled to pay Potts royalties net of post-production costs, relying on her own opinion in Heritage v. NationsBank. Potts argued that Heritage was distinguishable, and he pointed to the following sentence from Justice Owen’s opinion in Heritage:

There are any number of ways the parties could have provided that the lessee was to bear all costs of marketing the gas. If they had intended that the royalty owners would receive royalty based on the market value at the point of delivery or sale, they could have said so.

Potts’ lease provides, as Justice Owen had suggested, that his royalty shall be based on the “market value at the point of sale.” But, said Judge Owen, in this case Chesapeake’s sale (to its affiliate CEMI) is at the well, so the “point of sale” is on the lease, and the market value at that point is the price received by Chesapeake from its affiliate, net of post-production costs. “Chesapeake has sold the gas at the wellhead. That is the point of sale at which market value must be calculated under the terms of the lessors’ lease.”

I have seen many lease clauses attempting to prohibit deduction of post-production costs. Some of those clauses include language such as this: “This provision is intended to avoid the result in Heritage v. NationsBank.” I’ve not seen a case construing such a clause. Despite Justice Gonzalez’s insistence that Heritage has very limited precedential value, companies have made the most of it, and lessors continue to try to avoid it.

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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.

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