I was interviewed this week by Tiffany Dowell Lashmet, J.D., Agricultural Law Specialist with the Department of Agricultural Economics at Texas A&M University. Tiffany does lots of education programs for landowners at the Texas A&M AgriLife Research and Extension Center. She has a great blog for anyone involved in agriculture. Tiffany interviewed me about the law relating to deduction of post-production costs from oil and gas royalties. You can listen to Tiffany’s podcast of our interview here.
Last April the Fort Worth Court of Appeals issued its opinion in Bluestone Natural Resources II, LLC v. Randle, No. 02-18-00271-CV, 2019 WL 1716415. The Court decided that, under Randle’s lease, Bluestone could not deduct post-production costs and owed royalty on plant fuel and compressor fuel. Bluestone has petitioned the Supreme Court for review and the Court has asked for briefs on the merits.
Randle’s lease was a printed form with an exhibit. The printed form provided that royalties on gas would be “the market value at the well of one-eighth of the gas so sold or used …” Exhibit A provided that “the language on this Exhibit A supersedes any provisions to the contrary in the printed lease hereof.” One provision in Exhibit A dealt with post-production costs:
Lessee agrees that all royalties accruing under this Lease (including those paid in kind) shall be without deduction, directly or indirectly, 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.
A U.S. District Court in Arkansas decided a case in 2016 that a client sent me, Whisenhunt Investments, LLC v. Exxon Mobil Corp., 2016 WL 7494266, No. 4:13cv00656 JM, Eastern District of Arkansas, Western Division, raising an interesting issue on post-production costs.
Arkansas has forced pooling. The forced pooling statute provides that
One-eighth (1/8) of all gas sold … from any such unit shall be considered royalty gas, and the net proceeds received from the sale thereof shall be distributed to the owners of the marketable title in and to the leasehold royalty and royalty …. Payment of one-eighth (1/8) of the revenue realized from the sale of gas as provided in this section shall fully discharge all obligations of the operator and other working interest owners with respect to the payment of one-eighth (1/8) leasehold royalty or royalty … Nothing contained in this section shall affect the obligations of working interest owners with respect to the payment of royalties, overriding royalties, production payments, or similar interests in excess of the one-eighth (1/8) royalty required to be distributed under this section.
In a short opinion, the Supreme Court of North Dakota decided a case brought by Newfield Exploration against the North Dakota Board of University and School Lands to determine how royalties on gas should be calculated under the State’s leases to Newfield. The case illustrates how post-production costs can sometimes be hidden in “percentage-of-proceeds” or “POP” contracts for the sale of gas. Newfield Exploration Company v. State of North Dakota, No. 2019088, 2019 WL 3024639, decided 7/11/2019.
Newfield sold its gas to Oneok. The opinion describes this contract as follows:
Title to the gas passes to Oneok when it receives the gas from Newfield, but payment to Newfield is delayed until after Oneok processes the gas into a marketable form and sells the marketable gas. The price Oneok pays to Newfield for the gas is calculated based on 70-80% of the amount received by Oneok when Oneok sells the marketable gas. The 20-30% reduction of the price for which the marketable gas is sold accounts for Oneok’s cost to process the gas into a marketable form and profit.
The lease royalty clauses provided:
Lessee agrees to pay lessor the royalty on any gas, produced and marketed, based on gross production or the market value thereof, at the option of the lessor, such value to be based on gross proceeds of sale where such sale constitutes and arm’s length transaction.
All royalties on … gas … shall be payable on an amount equal to the full value of all consideration for such products in whatever form or forms, which directly or indirectly compensates, credits, or benefits lessee. Continue reading →
The Texas Supreme Court has denied motion for rehearing of its opinion in Burlington Resources Oil & Gas Company v. Texas Crude Energy, No. 17-0266. The case addresses deductibility of post-production costs in the context of an overriding royalty. The case may, however, have implications for post-production-cost deductions in oil and gas royalty clauses.
Texas Crude acquired oil and gas leases in Live Oak, Karnes and Bee Counties, and entered into an agreement with Burlington to develop those leases. The parties agreed that any oil and gas lease acquired by either party within the designated area would be part of the development agreement, and that Texas Crude would receive an overriding royalty interest in all leases within the development area. Texas Crude subsequently sued Burlington over various alleged breaches of the development agreement, including the deduction of post-production costs from Texas Crude’s overriding royalties. The parties filed summary judgment motions asking the trial court to construe the language in the assignments of overriding royalty, and the trial court ruled that post-production costs were not deductible. The parties agreed to seek an interlocutory appeal of this issue, which the court granted. The Corpus Christi Court of Appeals agreed to hear the case, and it affirmed the judgment of the trial court. 516 S.W.3d 638. Burlington then appealed to the Texas Supreme Court, which reversed and remanded, holding that the language of the overriding royalty assignments permits deduction of (some?) post-production costs.
The pertinent language of all of the overriding royalty assignments is identical:
The overriding royalty interest share of production shall be delivered to ASSIGNEE or to its credit into the pipeline, tank or other receptacle to which any well or wells on such lands may be connected, free and clear of all royalties and other burdens and all costs and expenses except the taxes thereon or attributable thereto, or ASSIGNOR, at ASSIGNEE’S election, shall pay to ASSIGNEE, for ASSIGNEE’S overriding royalty oil, gas or other minerals, the applicable percentage of the value of the oil, gas or other minerals, as applicable, produced and saved under the leases. “Value”, as used in this Assignment, shall refer to (i) in the event of an arm’s length sale on the leases, the amount realized from such sale of such production and any products thereof, (ii) in the event of an arm’s length sale off of the leases, the amount realized for the sale of such production and any products thereof, and (iii) in all other cases, the market value at the wells.
The unanimous decision, opinion by Justice Blacklock, held that the controlling language of the assignments is “delivered to ASSIGNEE or to its credit into the pipeline, tank or other receptacle to which any well or wells on such lands may be connected …” Texas Crude argued that the controlling language was in the definition of “Value”: “the amount realized from such sale of such production and any products thereof.” Texas Crude contended that under the court’s prior opinion in Chesapeake v. Hyder, 483 S.W.3d 870 (2016), a royalty based on the “amount realized,” without more, is free of post-production costs, and that the “into-the-pipeline” language would not be relevant unless Texas Crude elected to take its royalty share of production in kind. Continue reading →
Our firm hosted its 4th land and mineral owner seminar last Friday, and I spoke on deductability of post-production costs from lease royalties in light of the Texas Supreme Court’s decision last year in Chesapeake v. Hyder. My paper on post-production costs may be viewed here: Post-Production Costs after Hyder
The Court of Appeals in Corpus Christi issued its opinion today in Burlington Resources Oil & Gas Company LP v. Texas Crude Energy, LLC, et al. Link to the opinion is here: burlington v texas crude
This is the first case to follow Chesapeake v. Hyder, the Texas Supreme Court’s most recent case addressing deductability of post-production costs from royalty payments.
Like Hyder, the instrument construed in Burlington v. Texas Crude involved an overriding royalty interest. The language construed by the court in Burlington provided that the overriding royalty would be paid on the “amount realized” by the lessee, and said that the overriding royalty would be paid “free and clear of all development, operating, production and other costs.” The Court of Appeals concluded that the Supreme Court’s ruling in Hyder controlled its construction of the language and that Burlington had to pay the overriding royalty without deducting post-production costs.
Royalty owner opposition to Chesapeake is heating up in Pennsylvania.
Chesapeake has sent royalty owners letters saying it has overpaid them by failing to deduct post-production costs and demanding reimbursement. Post-production cost deductions are exceeding revenues on Chesapeake’s royalty checks, resulting in a “negative royalty.” The Commissioners of Bradford County, in the heart of the Marcellus play, have commissioned a video advocating for passage of a bill to require companies to pay a minimum royalty of 1/8th, regardless of the amount of post-production costs. Pennsylvania has a Guaranteed Minimum Royalty Act that requires all leases to contain no less than 1/8th royalty. But the state’s Supreme Court ruled in 2010 that the Act didn’t prevent companies from deducting post-production costs.
Chesapeake has the same problem in Pennsylvania that it had in the Barnett Shale play. In both cases, it made contracts between its affiliated companies to charge high fees for gathering and marketing its gas and then sold those affiliated gathering companies for a substantial premium. It’s now stuck with those very unfavorable post-production costs, and is charging those costs back to the royalty owners.
Chesapeake Energy announced last week that it is selling (giving away?) all of its interest in the Barnett Shale to Saddle Barnett Resources, LLC, a company backed by First Reserve. First Reserve is a global private equity investment firm. The Barnett Shale is the birthplace of the shale revolution in the U.S., and the origin of Chesapeake’s meteoric rise as the premier shale gas producer in the country. A key part of the transaction is Chesapeake’s renegotiation of its gathering agreements with Williams Partners. According to Chesapeake’s press release, renegotiation of the Williams agreements will save Chesapeake $1.9 billion in future midstream and downstream costs. Chesapeake is paying Williams $334 million to get out of the contract, and Saddle Resources is “expected to pay an additional sum.”
The sale covers 215,000 net acres and 2,800 wells producing 65,000 boe per day, 96% of which is natural gas. The deal is projected to save Chesapeake $200 to $300 million annually.
It is difficult to know exactly what this transaction entails without knowing more details, but it looks like Chesapeake is in effect transferring its Barnett leases to Saddle Resources for no consideration, and is in addition paying Williams Partners $334 million to get out of the onerous terms of the gathering/transportation agreement. It also looks like Chesapeake has been operating its Barnett leases at a loss, largely because of the Williams gathering/transportation agreement.
Last week the Texas Supreme Court denied Chesapeake’s motion for rehearing in Chesapeake v. Hyder. The court originally affirmed the lower courts’ opinions in favor of the Hyders, with four justices dissenting. On rehearing, the court’s alignment did not change, but Justice Hecht issued a new opinion for the majority, and Justice Brown issued a new dissenting opinion, joined by Justices Willett, Guzman and Lehrmann.
These new opinions end a long fight between Chesapeake and the Hyders over the deductability of post-production costs from their gas royalties in the Barnett Shale area. Although the leases contain strong language against deduction of post-production costs, Chesapeake argued that, under the precedent of the prior Supreme Court decision of Heritage Resources v. NationsBank, 929 S.W.2d 118 (Tex. 1996), it could deduct post-production costs. Chesapeake lost in the trial court and the court of appeals. The Supreme Court granted Chesapeake’s petition for review but affirmed the decisions below, split 5 to 4. With the denial of Chesapeake’s motion for rehearing, that decision is now final.
The Hyders’ lease allows Chesapeake to drill horizontal wells from surface locations on the Hyders’ property which produce from adjacent lands — in other words, to use the Hyders’ land to produce oil and gas from adjacent properties. As consideration for that right, the Hyder lease grants the Hyders a royalty interest in production from those wells — an “overriding royalty,” carved out of Chesapeake’s working interest in the leases covering those adjacent lands. The Hyder lease provides that the Hyders are granted “a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent of gross production obtained” from such wells. The argument was over the meaning of that language. Chesapeake argued that “cost-free” meant free of production costs; the Hyders argued that “cost-free” means fee of production and post-production costs.
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