The federal government alone manages 32,758 oil and gas leases covering 22.2 million acres, according to a 2026 Federal Register filing. Add in the millions of private acres across Texas, the Gulf Coast, and other basins, and you get a system that touches thousands of landowners every year.
Many mineral owners — and plenty of new investors — sign or evaluate these agreements without fully understanding the clauses, timelines, and payment structures that determine whether the deal pays off. This guide breaks down how oil and gas leases actually work, from the first offer to the monthly royalty check.
Key Takeaways
- A lease grants exploration and production rights in exchange for bonus and royalty payments; the landowner retains mineral ownership.
- Leases move from a primary term into a secondary term once production holds the lease.
- Royalty rates commonly range from 12.5% to 25%, and nearly every clause is negotiable.
- Accredited investors can gain passive exposure to lease-backed development and production through equity in upstream projects.
What Is an Oil and Gas Lease?
An oil and gas lease is a contract where a mineral owner (the lessor) grants an energy company (the lessee) the right to explore, drill, and produce hydrocarbons in exchange for compensation. In legal terms, it is a deed or conveyance of less than the full fee simple interest in the minerals—not a full sale.
Why lease instead of buy outright? Drilling is speculative and capital-intensive. Leasing lets a company access acreage while sharing risk with the mineral owner, who gets paid whether or not the well ever produces a barrel.
A lease is not a transfer of mineral ownership. It only grants usage and production rights for a defined period. Once that period ends without production, the rights revert fully back to the landowner.
Common variations include:
- Paid-up leases — no periodic delay-rental payments required during the primary term
- Top leases — a new lease layered on land that already has an existing lease, often speculative
- Surface vs. subsurface rights — separately negotiated depending on what the lessee actually needs access to
How Does an Oil and Gas Lease Work?
A lease moves through a defined lifecycle: from first contact with a landowner to either expiration or decades of ongoing production.
Initiation
A landman or company representative identifies promising acreage using geologic and title research, then approaches the mineral owner with an offer. This stage is manual and relationship-driven. Title verification has to happen before any payment changes hands.
Common bottlenecks include:
- Unclear or outdated ownership records
- Heirship disputes among multiple family members
- Landowners who are simply reluctant to sign
Core Operation (Primary Term)
During the primary term — commonly 3-5 years, according to the Texas A&M Real Estate Research Center — the lessee has the right, but not the obligation, to drill. In exchange, they pay an upfront bonus payment.
Operationally, this stage includes seismic testing, permitting, drilling, and completion work. If production begins before the primary term expires, the lease converts to the secondary term. If it does not, the lease lapses.
Regulation and Control Mechanisms
Two clauses do most of the heavy lifting here:
Habendum clause — sets the primary term length and defines the secondary term as lasting "so long as oil and gas is produced in paying quantities"
Pugh clause — limits how much acreage stays held by production from a single well, preventing an operator from locking up an entire lease with one small well
Shut-in royalty provisions — keep a lease alive when a well can produce but is not yet connected to a pipeline, allowing a shut-in royalty instead of lease loss
Shut-in durations are often capped — sometimes up to 10 years total or two additional one-year periods, according to Holland & Hart's analysis.
Together, these clauses stop operators from sitting on non-producing acreage indefinitely. Once production clears that bar, the lease shifts into its long-term phase.
Output (Secondary Term)
Once production begins in "paying quantities," the lease automatically rolls into the secondary term — active for as long as production continues. In Texas, courts apply a two-part test from Clifton v. Koontz: revenue must exceed operating costs, and a reasonably prudent operator would keep the well running for profit.
This is where royalty payments become a monthly reality for the mineral owner. Consistent production sustains those royalties for both sides until the well no longer produces in paying quantities and the lease ends.
Key Lease Clauses and Payment Terms to Know
Every lease has a granting clause that spells out exactly what rights transfer: oil, gas, other minerals, and often the specific depths involved. Everything else in the lease flows from that scope.
Bonus and Royalty Payments
- Bonus payment: A one-time, non-refundable per-acre payment made whether or not drilling occurs. Commercial mineral brokers report wide basin ranges:
- Permian Basin: $10,000–$30,000+ per net mineral acre
- Eagle Ford (South Texas): $4,000–$12,000
- Haynesville gas: $3,000–$7,000
- Royalty payments: An ongoing share of production revenue, typically 12.5% to 25%, based on basin competition and commodity prices. Unlike the bonus, royalties continue for as long as the well produces.
Surface Use and Pugh Protections
The surface use clause limits how much disruption a lessee can cause on access roads, well pads, and pipeline corridors. The Pugh clause, mentioned earlier, protects acreage not held by an active well from staying tied up indefinitely.
The same framework shows up in live development work. PetroVybe's projects in South Texas and the Gulf Coast Basin, including Lavaca County acreage, operate under these lease structures. For accredited investors, a development partnership can provide indirect exposure to that full cycle, from bonus through secondary-term royalty income.
Tax and Investment Considerations Around Oil and Gas Leases
Bonus and royalty payments are generally treated as ordinary income, reportable in the year received and eligible for depletion deductions under IRC Section 611. Percentage depletion for oil and gas properties can offset up to 100% of taxable income from that specific property, per 26 U.S. Code Section 613.
Working-interest participants (those who bear drilling costs rather than just collecting royalties) have access to a different tool entirely: intangible drilling cost (IDC) deductions under IRC Section 263(c). These let eligible taxpayers deduct most drilling expenses in the year they're paid or incurred, rather than capitalizing them over time.
This distinction matters:
- Royalty owners receive production income but bear no drilling costs, so IDC deductions don't apply to them
- Working-interest owners fund the drilling and can elect to deduct those intangible costs immediately
PetroVybe structures its development partnerships so accredited investors participate as passive partners in multi-well drilling projects, where IDCs typically represent 60-80% of invested capital. Those costs pass through via Schedule K-1, and the deduction can offset active income, including W-2 earnings and capital gains, not just passive income.
PetroVybe reported partners achieving a 94% deduction against active income in 2024 and 91% in 2025, based on the company's own investor data. That outcome depends on working-interest positions tied to real leases and drilling, not royalty-only income.
Conclusion
Understanding a lease's lifecycle, clauses, and payment mechanics turns a confusing legal document into a negotiable business deal. Landowners who know the difference between a habendum clause and a Pugh clause negotiate from a stronger position.
For investors, that same understanding sharpens how you evaluate development opportunities. The leasing fundamentals covered here directly shape return profiles in projects like PetroVybe's South Texas and Gulf Coast basin partnerships.
Frequently Asked Questions
What is the going rate for oil and gas leases?
Bonus and royalty rates vary widely by basin, competitive interest, and current commodity prices. Permian Basin bonuses often run higher than Eagle Ford or Haynesville acreage. Research recent comparable leases in your specific county before signing.
What is the 90% rule in oil and gas leasing?
98.8% of noncompetitive federal leases sold between 2003 and 2009 never produced during their 10-year primary term, per a GAO report summary. Some states also use "90%" language for pooling thresholds.
How long is a typical oil and gas lease?
The primary term usually runs 3-5 years for private and state leases (federal leases often run 10 years). Once production begins in paying quantities, the lease extends into a secondary term that lasts as long as production continues.
What happens if no well is drilled during the primary term?
The lease typically expires automatically, and the mineral owner keeps the bonus payment already received. The mineral owner is then free to negotiate a new lease with the same company or a different one.
Can a mineral owner lease the same acreage to more than one company?
Generally no. Overlapping leases on the same mineral interest aren't permitted unless rights have been legally severed by depth or geologic formation. Attempting to double-lease the same rights typically creates a legal dispute.
Is leasing mineral rights the same as selling them?
No. Leasing retains ownership while granting temporary production rights for a defined term. Selling permanently transfers mineral ownership to the buyer, with no reversion once the transaction closes.
