The oil and gas markets have suffered historically low prices in recent weeks. On March 30, 2020, the price of West Texas Intermediate crude oil closed at $20.09 per barrel, the lowest since February 2002. And in the last six months, the price of Henry Hub gas has fallen by more than 30 percent, and more than 40 percent since its recent peak on November 5, 2019 at $2.89 per MMBtu.
For many operators, these prices are economically prohibitive—it may make more business sense to shut-in a well or look for other relief until the pricing environment improves. But operators should proceed with caution when considering such measures, as their legal viability will depend on the jurisdiction, the specific lease language, and the relevant factual circumstances.
Whether a lease will permit a lessee to shut-in all of the wells located on the lands covered by the lease, or pooled therewith, because of depressed market conditions, yet maintain the lease in effect by paying shut-in royalties, will depend upon the particular language of the lease’s shut-in royalty clause. There is no industry standard shut-in royalty clause, and the language of these clauses widely varies.
As a gating question, operators will need to consider whether the well is capable of producing in paying quantities. Even where the shut-in royalty clause is silent about production in paying quantities, most courts will imply a requirement that the well be capable of “producing in paying quantities” at the time of shut-in for an operator to invoke the shut-in royalty clause. “Paying quantities” is generally understood to mean a profit in excess of certain operating expenses, however, the costs to be included in the calculation of operating expenses and the length of time over which “production in paying quantities” is to be measured, are fact intensive and vary by state. Note also that in the absence of express lease language, a strict application of this principle may prevent a lessee from invoking the shut-in royalty clause where a well has been drilled but not yet completed, or a recently completed well has increasing—but not yet profitable—production. While this may seem like a logical requirement, the states are divided on this question: some equate “production” with actual production and sales, while others hold the term to mean “capable of producing in paying quantities” and do not require sales of the product.
A second threshold consideration is determining whether the shut-in royalty clause has a triggering event. Certain shut-in royalty clauses provide for a payment of shut-in royalties while there is a gas well on the premise, “but gas is not being sold or used,” other clauses have a more specific reference to the reason for shutting-in the well. These can include, among other things, lack of market, force majeure, executive orders, or government restrictions.
Take, for example, a shut-in royalty clause that allows a shut-in “if . . . oil or gas be discovered on said land which cannot be profitably produced for lack of a market at the well or wells.” The term “lack of a market” could be interpreted as lack of an acceptable or economically rational market. Historically, an available gas market was often limited to only a single potential purchaser. Today, in many basins, it is more common to see multiple purchasers, including even multiple midstream providers. Thus, depending on the specific lease language and the particular geographic market, an operator who decides to shut-in a well because of low commodity prices may find it more difficult to argue that no market exists.
Even for shut-in royalty clauses that do not include a “lack of market” provision, some courts may still require the lessee to prove that no market exists. Where a lessee claimed “it would not be able to recover its costs of repair” given the limited and depressed market, the Kansas Supreme Court found that even a “limited” and uneconomical market did not allow the lessee to invoke the shut-in royalty clauses.
Continued payment of shut-in royalties that allow for a well to be shut-in for a lack of market by a force majeure, or another triggering event such as a government issued order, may be a viable way to keep the lease alive until a market becomes available.
The shut-in royalty clause may also contain certain limitations to which the lessee must adhere. For example, many leases limit the applicability of the shut-in royalty clause to wells producing only gas, and therefore wells producing oil or a combination of both oil and gas may not qualify. There is no clear authority on what constitutes a “gas well” or an “oil well,” thus reference to state specific statutory or regulatory provisions is necessary. In addition, the shut-in royalty clause in a lease of more recent vintage may expressly limit the length of time that the lease may be extended solely by virtue of the shut-in royalty clause. If so, at the end of the specified time period, the well must be returned to production or the lease must be maintained in effect by some means other than the shut-in royalty clause.
Even separate from a shut-in royalty clause, a lease may offer other options to cease production without resulting in termination of the lease. Some leases may have a “price trigger,” such as a clause that states that if, in the event oil or gas prices fall below a certain threshold, a lessee may be excused from continuing unprofitable production. Such clauses are conceptually related to the common law defense of commercial impracticability to nonperformance of a contract: because of factors outside of the control of the lessee, it is no longer practicable to produce under the circumstances. Some leases may also provide for alternative “triggering” events, such as force majeure, that allow for a lessee to extend the term of a lease. A lessee should make a careful examination of these clauses, as well as the law of the governing jurisdiction. For a more detailed analysis of force majeure and impracticality, see this recent DGS Legal Alert.
DGS attorneys are applying their best-in-market energy expertise to counsel clients through these issues, as they have in previous downturns in oil and gas pricing.
Please contact a DGS partner if we can assist you in any way.
 See, e.g., Rogers v. Osborn, 261 S.W.2d 311 (1953).
 Compare Freeman v. Magnolia Petroleum Co., 171 S.W.2d 339 (Tex. 1943), with Pack v. Santa Fe Minerals, 869 P.2d 323 (Okla. 1994).
 Martin & Kramer, 3 Williams & Meyers Oil and Gas Law, § 632.4.
 Tucker v. Hugoton Energy Corp., 855 P.2d 929, 936 (Kan. 1993).
 McDowell v. PG&E Res. Co., 658 So.2d 779 (La. App. 1995).