Secondary Term

Key Takeaways

• The habendum clause (from the Latin "to have and to hold") is the foundational lease provision defining the secondary term: a typical habendum clause reads "for a term of [3 to 10] years and as long thereafter as oil and gas or either of them is produced from said land or land pooled therewith," with the primary term providing the initial drilling deadline (the lessee must drill a well or pay a delay rental to hold the lease during the primary term) and the secondary term beginning automatically when production is achieved and continuing until production ceases; the habendum clause is the central subject of most oil and gas lease litigation because it defines the conditions under which the lessee retains the lease, and the lease terminates automatically (without lessor action) when those conditions are no longer met -- a principle that is strict in most US jurisdictions (if the lease terminates by its own terms, the lessor need not give notice or take any affirmative action to reclaim the property) but may be subject to equitable doctrines (such as estoppel, waiver, or the temporary cessation of production doctrine) that have been developed by state courts to mitigate the harshest outcomes of strict lease termination.
• "Paying quantities" is the legal standard that determines whether production is sufficient to hold the lease in the secondary term: most courts apply a two-part test that asks first whether the well is producing oil or gas in quantities sufficient for a reasonably prudent operator to continue production (the objective or "profits" test, which compares the gross revenue from the well against the operating costs, with production failing the test if costs consistently exceed revenues), and second whether the production is sufficient when viewed in light of all the facts and circumstances, including the overall economic viability of the lease and the expectations of the parties (a subjective test that considers the potential for improvement, the age of the well, the market conditions, and the operator's conduct); a well that consistently produces revenue exceeding lifting costs but at a very low rate (such as a stripper well producing 2 to 5 bopd in a field where the breakeven is 1 bopd) is generally held to be producing in paying quantities and holds the lease; a well that consistently loses money (operating costs exceed revenue) fails the paying quantities test in most jurisdictions and the lease is at risk of termination if no other lease-perpetuating activity is occurring; courts have split on whether a temporary period of uneconomic production (while the operator attempts to improve production or awaits better prices) constitutes a failure to produce in paying quantities or falls within the temporary cessation doctrine.
• Shut-in royalty provisions (clauses in the lease that allow the lessee to pay a specified royalty in lieu of production to hold the lease when a gas well has been completed and is capable of producing but cannot produce due to lack of pipeline connection or market) are critical tools for holding leases in the secondary term during infrastructure development delays: a standard shut-in royalty clause reads "if at the expiration of the primary term oil is not being produced on said land but lessee has a completed gas well capable of producing gas, lessee may pay shut-in royalty of $[X] per acre per year and this lease shall remain in force as if gas were being produced"; the shut-in royalty rate is specified in the lease (typically $1 to $50 per acre per year in historical leases, sometimes escalating with time or indexed to gas prices in more recent leases) and must be paid timely to the lessor to maintain the lease; the lessee's right to pay shut-in royalty is strictly construed, meaning that the payment must be made in the exact amount and timing specified in the lease (or as modified by subsequent agreement) or the shut-in royalty payment may not be effective to hold the lease; disputes over the sufficiency of shut-in royalty payments (wrong amount, wrong party, wrong timing, wrong formula) are among the most common causes of lease termination disputes in natural gas-producing states including Texas, Oklahoma, Louisiana, and West Virginia.
• The cessation of production clause (also called the continuous operations clause or the cessation of production savings clause) is a lease provision that protects the lessee from automatic lease termination when production ceases temporarily due to mechanical failure, workover operations, pipeline outages, or other operational interruptions that are inherent in oil and gas production: without a cessation clause, a strict reading of the habendum clause would terminate the lease the moment production stops, regardless of how briefly; most modern leases include a cessation clause that allows production to cease for a specified period (typically 60 to 180 days) without lease termination as long as the lessee is diligently pursuing resumption of production, with the lease terminating automatically if production is not restored within the specified period or if the lessee abandons the effort to restore production; some leases distinguish between cessation due to causes beyond the lessee's control (force majeure, pipeline failure, regulatory action) and cessation due to the lessee's own decision to shut in the well (mechanical workover, completion optimization), with different cure periods for each; the interaction between the cessation clause and the shut-in royalty clause is sometimes ambiguous in older leases, creating disputes over whether a shut-in well that cannot be connected to pipeline is "ceasing production" under the cessation clause (which requires diligent restoration efforts) or "shut-in" under the shut-in royalty clause (which allows permanent shut-in with royalty payment).
• Portfolio management of leases in the secondary term requires systematic monitoring of production in paying quantities, shut-in status, cessation periods, and operations that hold the lease, because lapse of any of these holding activities can cause automatic lease termination and loss of the leasehold asset: major oil companies and independents maintain land management departments (also called lease management or land services) dedicated to tracking the secondary-term status of each lease in their portfolio, monitoring well production against the paying quantities standard (typically by comparing monthly production volumes and revenues to operating cost estimates), paying shut-in royalties on schedule for completed-but-not-connected gas wells, and ensuring that workover operations are timely and documented to qualify as lease-perpetuating operations under the cessation clause; the economic value of a lease at risk of termination (a well near the end of its economic life, a shut-in well whose pipeline connection has been delayed, or a temporarily ceased well undergoing extended workover) can justify significant investment in production enhancement (artificial lift installation, acid stimulation, facility repair) to restore production in paying quantities and preserve the secondary term, particularly in leases that hold undeveloped acreage with significant untested potential that would be lost if the lease terminates; the cost of a preventable lease termination -- losing exclusive rights to a productive formation with remaining reserves because the surface lease expired -- can be tens or hundreds of millions of dollars in asset value, far exceeding any remedial cost.