Donna Thornton made sure to include a no-cost provision in her contract with Chesapeake Energy Corp. (CHK) that let the driller harvest natural gas beneath 2.5 acres of her property in Louisiana.
Thinking she had excluded production and marketing expenses and would therefore secure higher royalty payments, the Texas accountant said she was shocked when she confirmed in July that the second-biggest U.S. gas producer was passing costs on to her. For Thornton and thousands more owners of mineral rights in the U.S., “no-costs” in drilling leases has taken on new meaning.
As gas prices were heading toward a 10-year low in April, Chesapeake began reinterpreting in its favor thousands of contracts with landowners from Pennsylvania to Texas that own the 1 trillion cubic feet of gas the company produced last year, according to interviews and documents reviewed by Bloomberg. Chesapeake, arguing that other contract language allows for cost deductions, is fighting more than a dozen lawsuits.
“I don’t want to sound like I’m a bitter, disgruntled royalty owner, but this isn’t fair,” Thornton said. “Don’t do sneaky tricks. If it belongs to the royalty owners, it belongs to the royalty owners.”
While Thornton hasn’t sued, saying she is dissuaded by the potential hassle and cost, other property owners have taken Oklahoma City-based Chesapeake to court in states including Texas, Arkansas, Oklahoma, Louisiana and Kansas alleging underpayment of royalties. The lawsuits include at least eight cases brought so far this year, two of which were filed as class actions seeking to represent multiple royalty owners.
Legal battles over royalty payments on oil and gas production are as old as the industry itself, said Anthony Sabino, a law professor at St. John’s University in New York who specializes in complex litigation and oil-and-gas law. Producers such as Chesapeake have been motivated to minimize royalty payments as profits have been pinched by falling gas prices that remain 30 percent lower than two years ago.
Litigation may increase as lower gas prices — and royalty checks — lead landowners to scrutinize their contract terms and any deductions to cover the cost to bring gas to market, said Dana Kirk, a Houston-based attorney who has represented dozens of royalty owners.
“The tide goes in and out, depending on the overall economy and the specific economic prospects of the parties,” Sabino said. “Companies that are under heavy financial stress are more likely to push the envelope. Even the most honest companies, when prices and profits are dropping, will look to save money.”
Chesapeake lost about $9 billion in market value in the past year. Chief Executive Officer Aubrey McClendon was stripped of his chairman’s title in June amid investigations into conflicts of interest between his personal financial dealings and his management duties. Michael Kehs, a company spokesman, declined to comment on the investigations.
Chesapeake follows all state laws and contractual lease terms in compensating leaseholders, and the company has paid more in lease bonuses and royalties than any other exploration and production company, Kehs said in an e-mail message. The company, which reported $12.4 billion in revenue last year, has paid $25 billion in royalties and lease bonuses to landowners in the past 12 years, Kehs said. It has contracts to drill on more than 15 million acres in the U.S.
“The current price environment for natural gas is challenging for producers and royalty owners alike,” Kehs said. “When natural gas prices move higher, royalty owners should receive higher royalties.”
Gas producers have taken different approaches to expense deductions, at times abiding by no-cost provisions, and in other cases contending the provisions are nullified by other language in the contract, or by state law.
Chesapeake argued successfully this year to a Louisiana federal court that a provision to pay royalties on “market value” of the gas allowed it to deduct costs. The U.S. Court of Appeals in Cincinnati in February 2011 found that Kentucky state law stipulating royalties to be paid on an “at the well” price also includes costs, upholding the dismissal of claims by Kentucky royalty owners who had argued otherwise.
Marathon Oil Corp. (MRO) last year agreed to pay $40 million to settle a lawsuit brought by Oklahoma royalty owners who claimed the company underpaid royalties, in part by making improper deductions. Marathon denied any liability or wrongdoing, according to the settlement agreement.
London-based BP Plc (BP/)’s American unit won an appeals court decision last month reversing a $13 million jury verdict on underpayment claims awarded to New Mexico royalty owners in 2011.
The disputes usually come down to the sophistication of the contracts, which varies widely, said Sabino.
“You’ll see 75-page royalty agreements and other royalty deals that are written on the back of an envelope,” he said.
Royalties are a share of proceeds from the sale of oil and gas, paid to owners of mineral rights. Payments are based on state laws and the terms outlined in contracts, which vary from lease to lease. As hundreds of thousands of U.S. landowners were approached about leasing their mineral rights during the past decade’s boom in U.S. shale field production, how expenses were handled became a key point of negotiation.
Deducting costs for processing, transporting and marketing gas before royalties are calculated can reduce the amount producers owe by 25 percent to 50 percent. About one in five landowners in Texas have signed contracts specifying that producers pay them based on a price before those costs are deducted, said Tom Hazlewood, an appraiser of royalty leases whose business reviews hundreds of properties annually for tax purposes.
For the same gas from the same well under the same contract terms, Thornton, the Texas accountant, says she has been paid about 25 percent more for her gas by Plains Exploration & Production Co. (PXP), which in 2008 bought a 20 percent stake in Chesapeake’s acreage in the Louisiana Haynesville shale formation.
The two companies pay her in separate checks, and she said she discovered the cost deductions when Plains paid her back for expenses it had been subtracting since 2010. Chesapeake has not refunded any costs, she said. Hance Myers, a Plains spokesman, declined to comment.
In August 2011, when gas prices had fallen 14 percent from the year earlier and were sliding toward a 10-year intraday low of $1.902 in April, Chesapeake notified royalty owners in North Texas that it would begin deducting costs from royalties.
The decision came after Chesapeake partnered with Total SA (FP) in 2010 in a $2.25 billion deal that gave the French oil company a 25 percent stake in Chesapeake’s wells in the region. Chesapeake reviewed lease terms after Total said it wanted to deduct costs, Henry Hood, Chesapeake’s general counsel, told the Fort Worth Star-Telegram newspaper in an Aug. 10, 2011 story.
On Jan. 24, Chesapeake notified landowners in Pennsylvania of its intent to deduct costs, citing a March 2010 state supreme court ruling that confirmed deductions were allowed.
The costs range from 70 cents to $1 per 1,000 cubic feet of gas produced, Hood told the Fort Worth, Texas, newspaper. Coupled with lower gas prices, the deductions mean some royalty owners have seen their payments slashed by more than 90 percent this year, with Chesapeake paying as little as 11 percent of the price paid by rival energy producers, more than two dozen leaseholders in Texas and Louisiana said in lawsuits and interviews.
Chesapeake has paid royalties in North Texas based on a gas price as low as 11 cents per million cubic feet, eight or nine times less than producers including Devon Energy Corp. (DVN) and EOG Resources Inc. (EOG), Hazlewood, the tax appraiser, and other royalty owners said.
In one of the largest lawsuits Chesapeake is fighting, about 3,000 Kansas royalty owners accuse Chesapeake of deducting costs in violation of lease agreements and state law. The suit was certified as a class action in federal court in Wichita, Kansas, in 2011 allowing well owners to pursue claims against Chesapeake as a group. A nonjury trial is set for April.
Past verdicts and settlements in royalty disputes indicate a wide range of outcomes, even when royalty owners win. In 2007, a class of West Virginia royalty owners won a $404 million jury verdict against Columbia Natural Resources, which Chesapeake purchased after the lawsuit was filed. Chesapeake paid about $40 million of the ultimate $380 million settlement, while a prior owner paid the rest. In 2001, Chesapeake paid $3.4 million to settle a class action brought by Virginia royalty owners claiming the company made improper deductions.
The record in class actions is mixed. While Chesapeake settled the Virginia case and owners in Kansas won the right to sue as a group, the company has won dismissals of proposed class actions in Kentucky, Ohio and New York. The Ohio and New York cases are on appeal.
Plaintiffs are seeking to pursue their claims for underpayment of royalties as class actions in at least four other lawsuits — two in Arkansas, one each in Oklahoma and Louisiana.
In a case brought by Magnolia Point Minerals LLC, which owns mineral rights on land in the Haynesville formation in western Louisiana, the court backed Chesapeake’s interpretation that a contract allowed cost deductions despite a clause forbidding them.
Magnolia Point complained that Chesapeake pays less on a Louisiana lease than the company’s partner, a subsidiary of Houston-based Plains Exploration & Production Co. called PXP Louisiana that has a 20 percent stake. Under the same contract, PXP hasn’t been deducting production costs and Chesapeake has, Magnolia said.
U.S. District Judge S. Maurice Hicks Jr. in Shreveport, Louisiana, agreed that a provision to base royalty payments on the “market value at the well” allows the deduction of costs despite the no-cost clause.
The term market value at the well “stands for the proposition that post-production costs are to be taken out of production payments,” Hicks said in his July 30 ruling. Costs after determining market value at the well can’t be deducted, he said.
David Taggart, Magnolia’s lawyer, said he was reviewing the decision to determine the effect on the case.
PXP’s decision not to deduct costs doesn’t mean that Chesapeake is wrong to do so, Nicole Duarte, a Chesapeake lawyer, argued at a hearing April 12 in the lawsuit.
Chesapeake has been more willing to fight for its own interpretation of contracts than some other companies, Duarte said.
“There are a lot of decisions involved in whether or not you’re going to take on a fight for your interpretation,” Duarte told the court. “Chesapeake’s an 80 percent interest holder in this lease and has the biggest interest across the Haynesville Shale of anyone. So Chesapeake is probably more willing to take on the fights to get its interpretation recognized.”
What other companies pay in royalties may not be relevant or admissible in trials, the U.S. Court of Appeals in Denver ruled in July, reversing a $13 million jury verdict against BP America Production Co. in a class action brought by New Mexico royalty owners.
Evidence that ConocoPhillips didn’t take deductions shouldn’t have been admitted, the appeals court said in ordering a new trial. ConocoPhillips’ “royalty practices had no bearing” on BP’s obligations.
Ms. Dragonslaya, are you an unleased mineral owner?
She would have to be, Ben.
Ben---is there any difference in "market price at well head" and the "Net Price" after gas delivered at final point of sale at gross price-all the transportation pipeline,compression, and other cost to prepare gas to sell resulting in the final "net price" operator receives and then calculates royalty payment. This does not get into the subject of affiliates who may own the pipelines, trucks, or whatever that operator selling gas below market non-bid price at "the well head" . The affiliate or in other cases the Broker is buying gas at the "Well Head" so for royalty calculation Net and Gross is one in the same. Is this one way the operator is getting around the Royalty Free Clause that has "market price at well head" in clause? What most royalty owner had alway thought if Royalty Free they were to receive the Gross price at final point of sale. CHK must be selling gas to their affilate at the well head at below market without any other Broker Bids therefore that their Gross/Net and NO deductions.
To follow up on adubu's questions... Where exactly is the "well head?" I've also seen lease language that talks about the "mouth of the well." Is that the same?
Adubu/Henry, in general Adubu you are correct. The wellhead or mouth of the well is the christmas tree, and so "market price at well head" is what it says. The question becomes, how do you determine market price that exists at a particular wellhead? In Texas, it is determined by the comparable sales method (looking at other similar sales in the same field), but if there are no such similar sales, then using the net-back method off the downstream price. The courts have sort of screwed this up a little in allowing net-back to be used even when there are comparable sales, and more often than not, lessees use the net-back approach. In Louisiana, the net back approach is used. So yes, the market price at the well and net price will be identical. For the lessee, such as CHK, who is to pay royalty based on market value or amount realized at the wellhead if sold on the lease premises, the net-back method will be used and the net price will also be the lessee's gross price. So adding the phrase "gross proceeds determined at the mouth of the well" or similar clause, will not typically change the result. The best avenue for royalty owners in LA to pursue claims for underpayment even in the face of the lessee working around the cost-free royalty clause, is breach of the implied covenant to obtain the best price possible, which allows the royalty owner to point to other prices obtained by other operators in the field, and/or other post-production costs charged for similar services in the field, to show that the lessee has failed ot obtain the best price possible under the law. In Texas, such a claim is no longer possible in "market value" leases, but only in "amount realized" or "proceeds" leases. LA has not gone that route. . . .yet.