Chesapeake Energy Corp. is once again fighting to stave off a class action lawsuit in Pennsylvania as it confronts a growing chorus of those that allege it is improperly deducting post-production costs from royalty payments.
Scout Petroleum, a land-based oil and gas company that has been acquiring rights in Northeast Pennsylvania, is asking the American Arbitration Association to order a full refund of those deductions and requesting that its case against Chesapeake be granted class action status for others that have filed similar claims against the company for paid-up leases.
Earlier this week, Chesapeake filed an injunction seeking to prevent such action in the U.S. District Court for the Middle District of Pennsylvania. The latest actions involving Chesapeake’s leases in the state come as the Pennsylvania Attorney General’s office is reviewing underpayment claims from landowners in the state related to post-production costs (see Shale Daily, March 14).
The review, coupled with support from special interest groups to clarify provisions in Pennsylvania’s Guaranteed Minimum Royalty Act of 1979, has also prompted lawmakers in both chambers of the state’s general assembly to push for legislation that would further protect the royalty interests of landowners (see Shale Daily, April 7).
The issue has provoked growing concerns in the state as natural gas production in the Marcellus Shale has topped 14 Bcf/d. Post-production costs cover marketing and transportation fees, but while the royalties act sets the minimum payment to landowners for production at one-eighth, it does not clarify how royalties should be calculated.
Legislation (HB 1684) is making its way through the Pennsylvania House of Representatives with an amendment that specifies how post-production costs would apply to leases. A backlog of litigation has also complicated royalty payments and opened a rift between disgruntled landowners and some producers.
To make matters worse for Chesapeake, it only recently settled a $7.5 million claim with Pennsylvania landowners over nearly the exact same issue (see Shale Daily, Sept. 4, 2013). It’s also received negative press over similar royalty disputes in places such as Texas and Ohio (see Shale Daily, March 11; May 30, 2013; April 3, 2013).
In an affidavit filed last year with the American Arbitration Association, Douglas Clark, who represented two claimants in that case, said some producers had been inserting a “market enhancement” clause or equivalent “ready for sale or use” clause into their leases since 2007.
Under such language, producers can deduct costs that enhance the value of marketable oil or gas, such as processing or transport. Chesapeake had argued in a reply to Clark’s complaint that because gas at the wellhead is in marketable form, it has a right to pass on the costs its marketing company incurs to landowners. Claimants, meanwhile, have continued to argue that any lease that explicitly or implicitly permits the deduction of post-production costs in the calculation of royalties violates the state’s royalties act.
In a paper published last year by the University of Pittsburgh Law Review, its authors said that since 2008 more than 70 different lawsuits have been filed in state and federal courts involving the royalties act.
While federal judges have denied producers’ motions to dismiss landowners’ claims because they deemed the term “royalty” under the act to be ambiguous, the Pennsylvania Supreme Court, in Kilmer v. Elexco Land Services, sided with producers in 2010. The justices held that the act should be read to permit the calculation of royalties at the wellhead and adopted a definition of the term that allows post-production deductions. That ruling could complicate the landowner’s fight, according to the law review.
As they step up their fight to build public support and lobby lawmakers, organizations such as the Pennsylvania chapter of the National Association of Royalty Owners, have said in recent weeks that legislation must be passed with “clear, concise” language to resolve the issue once and for all.
At the NAPE East business conference in Pittsburgh on Tuesday, several industry executives appeared to sidestep the issue, but they noted how critical marketing and gas prices will be going forward. As more natural gas flows in Pennsylvania, it has put an immense strain on the state’s midstream infrastructure, costing producers at the same time as growing supplies continue to sit on basis and force differentials below Henry Hub for most off-peak months.
“The unfortunate thing is that right now, any new firm transportation is limited, and it’s very expensive,” said Talisman Energy Inc.’s Rick Kessy, vice president of Marcellus delivery. “I was looking at the strip futures market over the last day or so and it would appear that it’s in the $4.50 range out through the end of the year. If you don’t have firm transportation tied up and you’re depending on spot meter sales, it’s pulling you back anywhere from 75 cents to a $1.50, depending on the time of the year.
“So you’re no longer starting with $4.50 gas; you’re really starting with $3.00 or $3.50 gas. In order for companies to make wise [capital expenditure] decisions, it’s a very, very critical issue right now. It also takes on a huge liability on the balance sheet when we’re entering into these 10-year commitments for firm transportation.”
Given the realities of the natural gas market in the Northeast, and the Appalachian Basin’s role in redirecting the flow of natural gas across the country (see Shale Daily, March 12), some at NAPE East said state lawmakers should be considering a mutually beneficial royalty arrangement for landowners and producers. Kenneth Komoroski, an attorney at Morgan, Lewis & Bockius LLP suggested a deal in which producers and landowners equally share post-production costs.
“I don’t think anyone really fully appreciates the magnitude of how the marketing aspect has changed,” said Pennsylvania-native Tom Bartos, CFO of privately-owned Abarta Energy, which has ownership interests in 115 Marcellus Shale wells with major producers. “We now have to find a home for the dry gas, the y-grade and then the ethane takeaway is an issue. The whole gas marketing arena has had a big change over the last couple years because if you don’t have a market, you curtail or shut-in production. It’s much more complicated and much more costly.”
Still, Bartos said landowners were growing more knowledgeable about royalty arrangements and getting savvier in negotiating deals with producers. He added that it was incumbent upon the oil and gas industry to continue dealing with them in a “very ethical way” because “the last thing you want to see in this industry is some bad blood and a bad reputation.”
As a comparison, royalties on federal land are paid based on the point of first sale, with deductions allowed for transportation to get it there, plus processing to take out the natural gas liquids (NGL). Royalties on the sale of the NGLs are also included in the overall sales price. Deductions are not allowed for wellhead activities to put the gas into marketable condition or for gathering costs from the lease or in the field.
Transportation costs on major laterals or mainlines to the point of sale are deductible. Marketing costs are not. There are also caps on the percent of the proceeds. However, a Bureau of Land Management (BLM) spokesperson said federal rules are still evolving and it often works out on a case-by-case basis because of the many caveats in the federal rules, plus differences in contracts and the types and qualities of the gas and its location. States in which the gas is produced receive 50% of the royalties collected on federal lands by BLM.
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