Post-Production Deductions and Affiliate Sales: A Potential Minefield for Unwary Operators
Chesapeake has not had a good run in the courts lately. It has been hammered over the last year with lawsuits brought by mineral lessors alleging that the natural gas giant has swindled them out of millions of dollars in royalty payments. And the plaintiffs in these cases are winning--or settling out of court for what are widely speculated to be handsome paydays--in droves. Chesapeake's legal woes should serve as a wake-up call to operators that a one-size-fits-all approach to calculating royalties is a recipe for disaster.
Needless to say, not all oil-and-gas leases are substantively identical merely because their core elements--for example, the royalty percentage, the bonus per acre, or the length of their primary terms--are the same. Particularly when faced with sophisticated mineral owners represented by savvy counsel, operators may be laboring under far more onerous terms than those provided for in standard forms. Leases negotiated by institutional mineral owners and other large-tract landowners are virtually always custom-made contracts that include an array of aggressively lessor-friendly clauses that can be ignored only at great peril. This is a lesson that Chesapeake learned the hard way after a federal judge in Dallas ruled against the Oklahoma-based operator in a hard-hitting summary judgment opinion that ultimately prompted a settlement that, while confidential, is rumored to approach $9 million.
The case, Trinity Valley School v. Chesapeake Operating, Inc., No. 13-CV-08082 (N.D. Tex.), was spearheaded by Ft. Worth billionaire Ed Bass, who, along with some twenty other plaintiffs, accused Chesapeake of systematically underpaying royalties in a (not particularly well-camouflaged) arrangement with its affiliate, Chesapeake Energy Marketing ("CEM"), which buys Chesapeake's gas at the well. Chesapeake paid royalties to Bass and his co-plaintiffs that were calculated based on the weighted average that CEM received for the gas, but only after backing out CEM's own marketing fees as well as the gathering and transportation costs incurred by CEM.
Critically, however, the plaintiffs' leases permitted Chesapeake to deduct post-production expenses only if they were:
- charged at arms-length by an entity unaffiliated with Lessee;
- actually incurred by Lessee for the purpose of making the oil and gas produced ... ready for sale or use or to move such production to market; and
- incurred by Lessee at a location off of the Leased Premises.
The District Court held that Chesapeake failed all three tests: the charges were assessed by CEM, a Chesapeake affiliate; the expenses were not “actually incurred by Lessee” since it was CEM, rather than Chesapeake itself, which incurred the charges; and the costs were not incurred “at a location off of the Leased Premises” because Chesapeake sold the gas to CEM at the wellhead. Owing to the Court's summary judgment ruling, the trial of the case would as a practical matter have been an exercise not in determining whether Chesapeake would pay, but instead in deciding how much it would pay; and so, unsurprisingly, the case was resolved before opening arguments.
The moral of the story is that operators--which have become accustomed to deducting post-production expenses as a matter of course and to doing business with their affiliated entities without regard for the ramifications--must take a more intentional approach to the manner in which they structure mineral leases in the first place and, after the leases are signed, they need to carefully orchestrate their post-production activities in such a way that maximizes their revenues under the often nuanced terms of leases that have been cleverly drafted by enterprising lawyers for well-heeled landowners.
