An oil and gas lease is held by production when the operator extracts oil or gas before the lease’s fixed primary term runs out, which flips the lease into a secondary term that lasts indefinitely as long as production continues. The calendar deadline in the lease disappears. In its place sits a single ongoing condition: keep producing, and the lease stays alive; stop producing, and it can end.
That arrangement is written into almost every mineral lease in the country. It gives operators the security to invest in wells and pipelines, and it gives landowners a steady royalty stream. It also creates predictable fights when wells slow down, go offline, or sit idle while the operator holds onto the acreage.
Where the Rule Comes From: The Habendum Clause
Every oil and gas lease contains a habendum clause that splits the contract into two periods. The primary term is a fixed window, commonly three to five years, during which the operator must either begin drilling or keep the lease alive through other means, such as paying annual delay rentals. Miss a delay rental payment during the primary term and the lease can terminate automatically, with no chance to fix the mistake afterward.
The secondary term has no set end date. It lasts “as long thereafter as oil or gas is produced.” That phrase is what held-by-production status rests on. Once the operator achieves production before the primary term expires, delay rentals stop and the lease lives or dies based on whether the well keeps producing.
Getting into the secondary term requires more than moving a rig onto the property. The operator generally has to commence actual drilling and pursue it diligently, reaching at least one formation recognized in the area as potentially productive. Testing, completing, or equipping a well also counts. For a horizontal well drilled from an off-lease surface location into the leased formation, drilling is considered to have commenced on the lease when the bit starts turning at the off-lease site.1eCFR. 43 CFR Part 3100 – Oil and Gas Leasing
Production in Paying Quantities
Having a well on the property is not enough. To hold a lease during the secondary term, the well must produce “in paying quantities,” a legal standard courts have fleshed out over decades. The leading formulation comes from the Texas Supreme Court’s decision in Clifton v. Koontz, and most oil-producing states follow some version of its two-part test.2Justia Law. Clifton v Koontz
The first part is arithmetic. Does revenue from the well exceed operating expenses over a reasonable stretch of time? If the well turns even a small profit after operating costs, it satisfies this prong. The calculation deliberately excludes the original drilling investment. Nobody expects a marginal well to repay its upfront cost; the question is whether day-to-day operations are in the black. Lifting costs that count against the well typically include labor, electricity, pump operation, repairs, supplies, transportation to market, and royalties owed to the landowner. Courts have also generally held that depreciation on equipment actively used in production counts as a lifting expense.
The second part is the prudent operator test. Even if the math works, a court asks whether a reasonable operator would keep running this well for a profit rather than holding the lease for speculation. Judges look at reservoir depletion, commodity prices, how neighboring wells are performing, and whether the operator is genuinely trying to extract resources. This is where most lease-termination fights actually play out, because a marginal well can pass the math test while clearly serving no purpose other than holding acreage.
What Happens When Production Stops
Production interruptions are inevitable. Pumps break, pipelines go down, buyers vanish. Several contractual and legal doctrines determine whether a gap in production kills the lease.
Cessation of Production Clauses
Most modern leases include a cessation of production clause giving the operator a defined window, commonly 60 days, to resume production or begin reworking operations after a well goes offline. Without this clause, even a brief mechanical failure could terminate the lease. Where the lease specifies a timeframe, courts enforce it strictly: if the operator does not act within the window, the lease expires regardless of whether the delay was reasonable.
Federal offshore leases run on a longer regulatory clock. If production stops and the operator does not resume extraction, begin drilling or reworking, or receive a formal suspension within 180 days, the Bureau of Safety and Environmental Enforcement may determine the lease has expired by its own terms.3Bureau of Safety and Environmental Enforcement. NTL No. 2003-N04 – Extension of Lease Terms by Production in Paying Quantities
The Temporary Cessation Doctrine
When a lease has no specific cessation clause, courts in many states apply the temporary cessation doctrine. The question is whether a reasonably prudent operator would view the stoppage as temporary. There is no universal timeframe; the answer depends on what caused the shutdown, how long the well has been offline, and how diligently the operator is working to restore production. A well down two weeks for a compressor failure looks very different from one that has not pumped in a year with no repair efforts underway. If the lease contains a specific time limit, that contractual provision generally controls, and courts will not extend it under the doctrine.
Shut-In Royalty Clauses
A shut-in royalty clause addresses a narrower problem: the well can produce but has no buyer for the gas. Rather than forcing the operator to flare gas or lose the lease, the clause lets the operator make a cash payment to the landowner as a substitute for actual production. These payments are typically modest, often a few dollars per acre per year.4Mississippi College Law Review. Who Gets Paid When? The Timing and Obligation of Shut-in Gas Royalty Payments The clause only works when the well is genuinely capable of producing in paying quantities, and timing matters: failing to make the payment on the date specified in the lease can forfeit the lease entirely.
Force Majeure Clauses
Force majeure clauses excuse performance when events beyond the operator’s control prevent production, such as hurricanes, floods, or government-ordered shutdowns. Courts interpret these clauses narrowly, limited to whatever events the lease specifically lists. A drop in oil prices or a general economic downturn does not qualify as force majeure unless the lease explicitly says so, and almost none do. Financial hardship alone does not excuse the obligation to produce.
How Much Land Does One Well Actually Hold?
One of the biggest surprises for landowners is how much acreage a single well can tie up. Two concepts control the geographic scope: pooling and the Pugh clause.
Pooling combines multiple tracts or mineral interests into a single drilling unit. The general rule is that production anywhere on a pooled unit counts as production on every tract in the unit. If your 40-acre parcel is pooled into a 640-acre spacing unit and the well sits on someone else’s land half a mile away, that well still holds your lease by production. Without additional protections, a single well on a large pooled unit can hold thousands of acres across multiple leases indefinitely, even if most of that acreage will never be developed.
Pugh clauses are the landowner’s main defense. They limit held-by-production status to the specific acreage or depth included in a producing unit, releasing everything else at the end of the primary term.5Texas Tech University Institutional Repository. Oil and Gas Leases and Pooling: A Look Back and a Peek Ahead Landowners started negotiating them in the 1940s precisely because operators were using single wells on pooled units to lock up undeveloped acreage.
These clauses come in two varieties. One type releases surface acreage outside the drilling unit. The other releases formations above or below the producing zone, so a well producing at 5,000 feet does not hold rights to a deeper shale formation at 10,000 feet. Industry labels for these two types are inconsistent across states and even across individual drafters, so the reliable approach is to read the actual lease language rather than trust the label. In active shale plays, depth-based clauses have become especially valuable: without one, an operator holding a shallow conventional well can block anyone else from developing a deep horizontal target beneath the same surface.
Challenging a Lease You Think Is Dead
Landowners who believe a lease is no longer valid have two main legal paths. A lease cancellation suit asks the court to declare the lease terminated because the operator failed to meet its obligations, usually by falling below paying quantities or violating a specific lease provision. A quiet title action resolves competing claims to the mineral estate, which becomes necessary when an expired lease still appears in the public records and clouds the landowner’s title.
Either route puts the burden on the facts. Operators will produce monthly run statements, maintenance invoices, and revenue records to show the well remains financially viable. The landowner needs their own analysis of those numbers, ideally prepared by a petroleum engineer or accountant familiar with the paying-quantities framework. Disputes over marginal wells often turn on how the accounting is done: which months are included, whether depreciation counts, and how seasonal price swings are treated over the evaluation period.
Documentation matters, and starting early matters more. If royalty checks have been shrinking or arriving late, keep records. If the well site looks abandoned, photograph it. Courts evaluate operator diligence, and a pattern of neglect over months or years is far more persuasive than a snapshot of one bad quarter.
When the Lease Finally Ends
Whether a lease ends by expiration, voluntary surrender, or court order, someone has to plug the wells and restore the surface. On federal land, the Bureau of Land Management holds the operator responsible from the moment the well is drilled until it is plugged and the land is reclaimed. Transferring a lease to another company does not let the original operator off the hook; liability for wells that existed at the time of transfer follows the original lessee.6Bureau of Land Management. Protecting Taxpayers and Communities from Orphaned Oil and Gas Wells on Public Lands
Plugging costs are not trivial. Estimates range from roughly $20,000 for a shallow, straightforward well to over $90,000 for deeper or more complex sites, with problematic wells exceeding $160,000. The BLM requires operators to post reclamation bonds as a safeguard. Under a recent final rule, the minimum is $150,000 for an individual lease bond and $500,000 for a statewide bond.7Bureau of Land Management. BLM Final Onshore Oil and Gas Leasing Rule – Bonding Factsheet Operators who fail to plug and reclaim their wells land on a federal noncompliance list that bars them from obtaining new leases until they fulfill their obligations.
Surface restoration rules vary by state. Some jurisdictions recognize an implied obligation to restore the surface after production ceases, while others, including major producing states, have rejected that doctrine and require the duty to be written into the lease. If you want guaranteed surface restoration, insist on an express reclamation clause in the lease. Do not assume the law will supply one.