If you own minerals, the lease is usually the first real contract you'll ever sign about them — and it sets the terms for everything that follows. A lot of people picture it like renting out a spare room: money comes in, you still own the place. That's close, but the details matter enormously, because a lease temporarily hands over valuable rights and locks in how you'll be paid for years.
What a lease actually is
Legally, an oil & gas lease is a conveyance — it transfers a limited property interest, not just permission to visit. The operator (the lessee) receives the exclusive right to explore, drill, and produce during the term. You (the lessor) keep the underlying mineral interest and the right to be paid. The "strings" are the conditions: pay the bonus, pay the royalty, and actually develop the property, or the grant expires.
That expiration feature is the whole point. A lease is designed to end if the operator sits on it. When it ends, your rights aren't diminished — they revert to you clean, free to lease again.
The lease bonus
The bonus is the up-front, one-time payment for signing. It's almost always quoted per net mineral acre. Say an operator offers $500 per net mineral acre and you own 20 net acres — that's a $10,000 bonus, paid whether or not a well is ever drilled. The bonus is yours to keep and is entirely separate from royalty. In hot areas bonuses climb; in quiet ones they shrink. There's no universal rate, so any figure you hear is illustrative.
The royalty clause
The royalty is your share of production revenue once a well pays out oil or gas. It's expressed as a fraction — you'll see numbers like 1/8, 3/16, or 1/4. Older leases leaned on 1/8; newer leases often negotiate higher. But the fraction is only half the story.
The other half is how the royalty is calculated. A "cost-free" or "gross proceeds" royalty is paid on the full sales value. A royalty subject to post-production costs lets the operator deduct expenses like gathering, compression, processing, and transportation before your share is figured — which can shrink your check meaningfully. Two leases with the same fraction can pay very differently depending on this language. If you want to see how the fraction feeds a real payment, see how oil & gas royalties are calculated.
Primary term vs. secondary term
The clause that controls how long the lease lasts is the habendum clause. It splits the life of the lease into two parts:
- Primary term. A fixed window — often a few years — during which the operator can drill but isn't required to. Say the primary term is three years. If no well is drilled and nothing else keeps the lease alive, it simply expires at the end of that window.
- Secondary term. If the operator establishes production in paying quantities before the primary term runs out, the lease continues into its secondary term — lasting "so long as" the well keeps producing. That's the mechanism behind held by production, and it can extend a lease for decades.
Delay rentals and shut-in royalty
Two older-style clauses still show up. Delay rentals were small annual payments an operator made to keep a lease alive during the primary term without drilling. Today most leases are paid-up, meaning the bonus covers the entire primary term and there's no separate delay rental to track — but you'll still see the term in older forms.
A shut-in royalty covers the case where a well is capable of producing but is temporarily closed in — for example, waiting on a pipeline connection. Rather than let the lease lapse for lack of production, the operator pays a modest shut-in amount that keeps the lease alive as if it were producing, at least for a limited time set by the lease.
Pugh clause and depth severance
Two provisions protect you from a lease that hangs on to more than it's using. A Pugh clause — sometimes called a vertical Pugh clause, because it severs the lease along vertical planes — releases the acreage not included in a producing unit once the primary term ends, so a single well can't tie up your whole tract. A depth severance (or "horizontal Pugh") does the same idea by depth, releasing the geologic zones the operator hasn't developed. Both keep undeveloped rights free to lease to someone else.
What happens at the end of the primary term
When the primary term closes, one of two things happens. If there's production in paying quantities (or a valid shut-in payment, or another savings clause in effect), the lease rolls into its secondary term and continues. If not, the lease terminates automatically and your minerals revert to you, unleased and unburdened — ready to negotiate again. That reverting-back feature is exactly why the fine print on term and continuation clauses is worth reading carefully before you sign.
Frequently asked questions
What is a lease bonus?
A one-time, up-front payment for signing the lease, usually quoted per net mineral acre. You keep it whether or not a well is ever drilled, and it's separate from any future royalty.
What royalty should I expect in an oil and gas lease?
There's no fixed market rate — the fraction is negotiated and varies by area and demand. Just as important as the fraction is whether the royalty is paid cost-free or reduced by post-production costs. Treat any number you hear as illustrative.
How long does an oil and gas lease last?
It runs for a fixed primary term and then ends — unless the operator has established production or otherwise kept it alive under the habendum clause, in which case it continues through its secondary term for as long as production lasts.
Do I still own my minerals after I lease them?
Yes. A lease conveys the right to explore and produce for a time; it doesn't sell your minerals. You stay the owner, collect the bonus and royalty, and if the lease ends without production the rights revert fully to you.
Keep going: learn what "held by production" means, see how royalties are calculated, or read up on mineral rights vs. royalty interest.
Educational information only. This article is not legal, tax, or financial advice. For guidance on your specific situation, consult a licensed professional.