The battle over post-production costs
Nicole M. Duarte and Krystal P. Scott, Jones Walker LLP, Houston
The term "post-production costs" is a seemingly dull phrase that has captured national attention, and rightly so. Though otherwise largely unique, shale gas plays across the United States face the same question with respect to post-production costs: Who pays for them? With hundreds of lawsuits now filed on the issue, billions of dollars—and some say the future of shale gas in the US—are riding on an answer.
What are post-production costs?
The basic concept of post-production costs is generally accepted in industry. In short, producers typically bear all costs of exploring for and producing gas. Gas is "produced" when it is reduced to possession—or breaks the earth's surface--at the wellhead. Post-production costs are costs incurred by a mineral lessee subsequent to production to treat and transport the gas to a downstream sale location. These costs include such things as gathering, marketing, compression, fuel, processing, treating, transportation, taxes, and dehydration. These expenditures add value to the natural gas from its state at the wellhead up to a sale point further downstream.
The rise in litigation over post-production costs
Two decades ago, producers sold natural gas to pipeline companies at the wellhead. These pipeline companies then incurred the post-production costs related to processing the gas into a so-called marketable condition. But in 1992, the Federal Energy Regulatory Commission (FERC) issued Order No. 636. This deregulation required the unbundling of transportation costs from sales and required common carriage to producers. As a result, producers now often retain ownership of the gas beyond the wellhead and have become responsible for arranging (through both affiliates and unrelated entities) the post-production activities required to "sweeten" and transport the gas to sell it farther downstream for a higher price.
At the well
Significant disputes and litigation have arisen from this change in process related to who should bear the expense of post-production costs. The overarching dispute arising from deregulation deals with the valuation of gas for purposes of royalty calculation. Though they widely vary, mineral leases often provide for royalty valuation for gas sold at the wellhead based on the amount realized (or actual price received) for the sale, while gas sold away from the wellhead is valued based on the market value of the gas at the well.
This latter royalty benchmark commonly involves the use of the "work back" method in which the post-production costs of getting the gas to a downstream market are deducted or adjusted from the final sales price, yielding the net number on which royalty is based. This "work back" method requires lessees to determine which of the post-production costs are deducted or adjusted to arrive at the royalty price. Even with form leases using the common "market value at the well" and "amount realized" language, the process of royalty valuation varies widely among gas-producing jurisdictions.
The majority of gas-producing jurisdictions abide by the "at the well" rule. Under this rule, a lessee does not bear the costs of marketing production by itself. Thus, any costs incurred by a lessee after the gas reaches the wellhead are shared proportionately by the lessor and lessee under an "at the well" lease. Gas-producing states that follow this rule include California, Kentucky, Louisiana, Mississippi, Michigan, New Mexico, North Dakota, Pennsylvania, and Texas.
The minority of gas-producing states hold that a lessee's implied duty to market production requires a lessee to bear the full cost of any steps necessary to transform the gas into a marketable condition. Thus, the lessee may deduct a portion of its costs from the value of production only after the production has been placed into a marketable condition.
"Marketable condition" in this context may refer simply to the quality of the gas – i.e., whether the gas in in the physical condition in which it is acceptable to be purchased in a commercial marketplace, regardless of whether a purchaser exists at the precise location of that gas. Or "marketable condition" can also include a location component, meaning that the gas must be in the requisite physical condition and located in an area in which a commercial marketplace exists. States adopting some version of the "marketable product" rule include Colorado, Kansas, Oklahoma, and West Virginia.
Other hot issues
The issue of who bears the post-production costs under an "at the well" royalty clause is not the only issue that has arisen in the post-deregulation natural gas world. Another such issue involves the common practice of using affiliated companies to undertake post-production activities. In areas of the country with rapidly expanding production, lessees face a continuously growing network of geographically scattered production facilities. When coupled with a lessee's duty to market the gas produced, lessees are left with the unenviable choice of either shutting in producing wells (at great monetary loss to both royalty owners and lessees) or expending vast amounts of capital to create the infrastructure needed to bring the gas to market. Many lessees have chosen the latter, utilizing affiliated companies to perform the post-production activities necessary to treat and transport gas to a downstream sale location.
Despite the fact that these "midstream" activities previously undertaken by the pipeline companies involve risks that are qualitatively and quantitatively different from the risks of production born by the lessee under a mineral lease, lessors wary of the possibility of self-dealing may contend that royalty owners should not bear any share of post-production costs charged by these affiliated companies to the lessee.
Yet another issue that has arisen involves the use of lease provisions intended to alter the way in which royalty is calculated under a "market value at the well" or "amount realized" royalty provision. Particularly in jurisdictions in which the courts follow the "at the well" rule, it is not uncommon for lessors to seek to include in the lease a "no cost" provision of some sort that purports to prevent the deduction of some or all post-production costs from the lessor's royalty.
In many cases, the "market value at the well" or "amount realized" royalty benchmarks are left in the lease, but a "no cost" provision is added to the lease, often in a lease rider or addendum. The question becomes whether, and to what extent, the "no cost" provision changes the calculation of royalties under the "market value at the well" or "amount realized" royalty benchmarks.
In Texas, the state with the most developed jurisprudence on this issue, the courts have held generally that the "no cost" clauses at issue are not sufficient to alter the ordinarily applicable royalty benchmarks, with the result that the lessor is still required to bear its pro rata share of post-production costs. However, in one Louisiana federal case, the court found certain "no cost" language was sufficient to supersede and modify the "at the well" language of the lease such that the lessee was required to bear all post-production costs. The common thread in these cases the thorough analysis of the specific and distinct lease language involved to reach a conclusion.
Conclusion
As mineral law scholar Professor David Pierce has recognized, "[w]hen compensation under a contract is based upon a set percentage of the value of something, there will be a tendency by each party to either minimize or maximize the value." The issue of the "deductibility" of post-production costs in the calculation of mineral royalties is the proof of this theorem, as lessors and lessees continue to duke it out over the many issues – the meaning of the "at the well" language, affiliate issues, and the effect of "no cost" provisions – that have arisen in the post-deregulation natural gas sphere. Given the massive quantity of money at issue as the result of the ongoing shale plays, these disputes are unlikely to fade away any time soon.
About the authors
Nicole M. Duarte and Krystal P. Scott are partners in the Business and Commercial Litigation Practice Group in the Houston office of Jones Walker LLP, where they focus their practices on litigation matters for energy-industry clients and handle a variety of royalty-related disputes. Duarte represents clients in the areas of oil and gas litigation, water law, environmental law, toxic torts, complex litigation, and class actions, and also maintains an appellate practice.
Scott represents both onshore and offshore energy clients with a focus on complex contractual disputes, transportation, gathering, and marketing disputes, lease maintenance and operations disputes, and disputes involving error, fraud, and fraudulent transfer claims.
