Operators across the nation are scrutinizing their leases in a wide-spread effort to navigate historic low oil prices, takeaway curtailment, storage shortages, issues introduced by the COVID-19 pandemic, and a host of associated issues.
These circumstances present a variety of complex lease maintenance issues. Most leases obtained during the shale boom are in their secondary terms, held either by production in paying quantities, shut-in provisions, an operations clause, or continuous development provisions. Each of these introduce a unique analysis, and each is susceptible to significant strategic challenges in the face of low commodity prices along with transportation and storage issues.
Below, we briefly explore twelve issues that may be encountered by lessees in Texas while navigating these unique challenges.
Issue 1: Lease by Lease Analysis
While checklists and general rules may be helpful, when it comes to analyzing lease maintenance issues there is no-one-size-fits-all solution. Over the last several years, Texas courts have repeatedly held that leases are not interpreted merely by application of general rules, but rather by an individualized interpretation of specific lease language.
In addition, the recent Texas Supreme Court case, Murphy v. Adams illustrates that fact-specific “surrounding circumstances” evidence can sometimes lead to deviations from the industry’s customary understanding of a given word or phrase. In that case, due to admissible “surrounding circumstances” evidence, the phrase “offset well” did not refer to a well that would actually protect from drainage, but instead referred to a well drilled anywhere on the leased premises.
Many modern leases contain custom definitions for words or phrases like “operations,” “drilling,” or “reworking.” Similarly, some modern leases contain provisions governing the evaluation of production in paying quantities and offset obligations. Those custom definitions and provisions generally control, further underscoring the need for a case-by-case analysis.
Issue 2: Continuous Development Obligations
Many leases granted over the last decade are currently held in their entirety by a continuous development provision. These provisions vary widely in specifying when and how a lease may be held by continuous development, such as when a well is “completed” or “abandoned,” when the next well is “commenced,” and what type of drilling rigs or preparatory operations suffice. In addition, some provisions allow for “banking” of time saved between wells, and recent cases demonstrate the complexities those calculations can introduce.
Lessees seeking to slow down capital expenditures yet continue to maintain continuous development operations through this downturn should carefully examine their leases to ensure that such contractual deadlines are not missed.
Issue 3: Retained Acreage/Separate Lease Clause
Many companies will inevitably suspend certain continuous development programs. When continuous development ceases, this generally triggers a retained acreage provision that provides for an automatic termination of some portion of leased acreage.
Retained acreage provisions widely vary and, as illustrated by recent Texas Supreme Court precedent, small changes in wording can lead to drastically different results in terms of the quantity of acreage retained and released. Additionally, some provisions call for a one-time termination, while others call for partial terminations on a “rolling” basis.
Retained acreage clauses are often paired with a “separate lease” clause, generally providing that, after the end of both the primary term and continuous development, each remaining production unit must be held by its own production and/or operations. Lessees considering shutting in some wells should evaluate whether production or operations on remaining wells will be sufficient to hold the shut-in production units.
Issue 4: Production in Paying Quantities
Most leases provide that, after the primary term, a lease continues as long as there is “production in paying quantities.” To determine whether there is “production in paying quantities” Texas courts apply a two-pronged test. Under the first prong, the court will determine whether the well is making any profit, no matter how small.2 Simple math reflects that reduced oil prices can negatively impact this test.
Under the second prong, a court determines “whether or not under all the relevant circumstances a reasonably prudent operator would, for the purpose of making a profit and not merely for speculation, continue to operate a well in the manner in which the well in question was operated.” If this downturn is prolonged, some lessors may argue certain leases are being held out of speculation.
The Texas Supreme Court recently emphasized that these tests must be analyzed over a reasonable period of time, to be determined by the jury. Therefore, if reduced commodity prices are only temporary, lessees will likely argue that arithmetic and prudent operator tests should both be analyzed over a longer period of time that factors in a period of higher prices – whether before or after the current downturn.
Issue 5: Minimum Royalties
Some leases require payment of “minimum royalties.” With the drop in oil prices, coupled with the inability of some operators to market all of their production, lessees may need to evaluate whether royalty payments drop below a threshold that would require payment of minimum royalties. While failure to make minimum royalty payments may merely provide the lessor with a breach of lease claim, some clauses also provide the lessor with the option to terminate the lease.
Issue 6: Force Majeure
A flurry of recent social media posts have contemplated that COVID-19 and/or the market downturn may give rise to reliance on force majeure provisions. Force majeure provisions introduce a large variety of potential issues. The next few paragraphs merely introduce a few.
One significant issue is whether the event or condition at issue meets the definition of “force majeure” under the lease. Many force majeure provisions provide a specific list of events or conditions that qualify, as well as catchall language. These lists and catch-all phrases vary widely and must be analyzed on a case-by-case basis. Some commentators have pondered whether COVID-19 could be considered an “Act of God” – a phrase sometimes listed in force majeure provisions.
Another critical issue is determining whether the lease requires the event or condition to be unforeseeable or preventable. In the recent case TEC Olmos v. Conocophillips, the First Court of Appeals in Houston held that an economic downturn did not qualify as a force majeure event under the particular clause at issue in that case because (1) an economic downturn was not one of the specific events listed in the provision, and (2) an economic downturn did not fall under the “catchall” because the catch-all required a showing that the event was unforeseeable. The court concluded that the lessee “did not and cannot” prove that an economic downturn is unforeseeable because “fluctuations in the oil and gas market are foreseeable as a matter of law.” One may ask, is the current downturn, paired with a global pandemic, unique enough to call for a different conclusion?
whether the force majeure provision suspends both obligations and conditions in the lease. Generally, lessees are not under an obligation to maintain a lease. However, many force majeure provisions only mention the suspension of obligations. In those circumstances, a force majeure provision may not suspend conditions which are necessary to maintain the lease.
Issue 7: Shut-in Royalties
With oil prices recently dipping into historic negative territory, some lessees may be evaluating whether it is prudent to shut-in some or all wells in certain leases or fields. Care should be taken in evaluating shut-in provisions. Being a matter of contract, shut-in provisions widely vary. Common variables include (i) the specific circumstances triggering the shut-in royalty clause, (ii) when and how the payments must be tendered, and (iii) the consequence of failing to make timely payments.
A failure to timely and properly pay a shut-in payment, or shutting in a well that does qualify under a specific shut-in provision, can result in lease termination. The shutting in of oil wells in response to these unprecedented times raises numerous potential questions. For instance, while shut-in provisions traditionally only contemplate shut-in gas wells, many also cover oil wells. In addition, many provisions require a “lack of market,” or similar condition. Whether depressed markets or curtailed takeaway capacity qualify under a specific shut-in provision should be carefully evaluated.
Issue 8: Regulatory Orders
With the decrease in prices and the threat of limited storage capacity, some are looking for the Texas Railroad Commission to intervene. In March of 2020, Pioneer Natural Resources filed a petition with the Commission, requesting the re-institution of market demand prorationing limits, with the aim of curtailing State and global supply. Based on the petition, the requested prorationing limits would apply to some operators, but not all, depending on their production levels. At the time this article was written, the Commission has declined to take that action.
In New Mexico, on the other hand, the New Mexico State Land Office announced emergency rulemaking to give relief to the oil and gas industry by allowing wells to be shut-in on certain leases covering state-owned minerals. Oklahoma seems to be headed in the same direction.
Regulatory action, while impactful, may or may not help lessees perpetuate their leases. While many force majeure clauses specifically make reference to regulatory orders, Texas courts have been hesitant to find that regulatory action triggers force majeure provisions when the effects of the regulatory order on the lease could have been avoided by the lessee. For instance, in Red River Resources, the court held that a Railroad Commission severance order “does not constitute a force majeure event when compliance with the regulation violated was within the reasonable control of the lessee.” “The RRC has the authority to order a well shut-in due to the lessee’s failure to comply with its regulations. To accomplish this, the RRC issues severance orders.” The court stated that a severance order “will only qualify as a force majeure event when compliance with the RRC regulation violated was outside the control of the lessee.
Similarly, in Schroeder v. Snoga, the San Antonio Court of Appeals held that, because the Railroad Commission’s shut-in order was caused by the lessee’s own violation of Commission rules or regulations, the lessee could not claim the shut-in order was a force majeure event. While the circumstances for each lease can be different, it is important to take into consideration these cases.
Issue 9: Cessation of Production/Continuous Operations Clauses
Most modern oil and gas leases contain “cessation clauses,” which provide that if production were to cease, the lease may be maintained by commencing production, drilling or reworking operations within a certain period of time — often 60 to 90 days. Whether such a clause could provide a basis to cease production during a time of low prices and/or storage constraints will depend on the express terms of the lease.
Most cessation clauses make no reference to the cause of cessation, or broadly refer to cessation “from any cause.” However, it should be noted that in certain cases disputes may arise regarding whether a voluntary cessation of production is permitted under the express language of the provision at issue, particularly where the voluntary cessation is for reasons other than to work on the well or associated facilities.
When there is no express cessation clause, the implied “temporary cessation of production” doctrine (“TCOP”) may apply. However, it is questionable whether a voluntary cessation of production based on reduced prices or reduced transportation or storage capacity would qualify under the TCOP doctrine. The TCOP doctrine has traditionally been applied where the cessation is due to a sudden stoppage of the well or some mechanical breakdown of the equipment, and requires the lessee to exercise diligence to resume production within a reasonable time.
Issue 10: Offset Obligations
Lessees must remain prepared to respond to express or implied offset obligations. In Texas, in order to establish a breach of the implied covenant to protect against drainage a lessor must prove (1) substantial drainage from the leased premises, and (2) a reasonable prudent operator would have acted to prevent the drainage which ordinarily means there is a reasonable expectation of profit from drilling an offset well. Of course, a drilling project is less likely to be profitable during depressed commodity prices than during high prices. In a market with negative commodity prices, perhaps no drilling project can reasonably be expected to produce a profit, though some lessors may see the current market conditions as a temporary condition.
However, it must be noted that many leases contain express offset provisions that do not condition the obligations on an expectation of profit, and some expressly waive the condition altogether. For instance, some express offset provisions provide that if a well is drilled within a certain number of feet from the leased premises, then drainage is “deemed” to exist, triggering an obligation to either drill an offset well, execute a partial release, or pay compensatory royalties.
Issue 11: Volume Commitments and Pipeline Capacity Limitations
Many operators have entered into midstream contracts within minimum volume commitments. Under these agreements, if the operator fails to deliver the agreed-upon volume, the operator may be required to pay shortfall fees or deficiency fees. In the current market, though it may be prudent to temporarily curtail production, in some circumstances this can result in significant volume deficiency fees.
A similar, but opposite, potential issue is reduced takeaway capacity and storage limitations. With the significant reduction in demand caused by COVID-19, storage capacity has all but been reached in some parts of the country.
Issue 12: Potential Impacts on Royalty Calculations
Under many royalty provisions, a lessee is permitted to deduct or “net back” a share of certain post-production expenses when calculating royalties. In some rare cases, deductions can actually result in a negative number, sometimes referred to as a “negative royalty.” While deductions are most commonly discussed in the context of gas royalties, recent Texas Supreme Court precedent has reflected that they can also occur in the context of oil royalties and “into the pipeline” language. While no Texas case has directly addressed the issue, commentators have split on whether Texas law would permit a lessee to charge a lessor with a negative royalty.
Negative royalty calculations can also occur where commodity prices fall to negative numbers. For instance, in West Texas, natural gas prices plunged to negative numbers in 2019. If the lessee is not permitted to flare or otherwise dispose of the negative-value commodity, the lessee may end up paying to have the gas taken away. Now that oil prices, too, reached a negative value in late April of 2020, questions are likely to arise as to how to calculate royalties on oil volumes that have a negative worth.
