An oil and gas lease is a contract between you, the mineral owner, and an operator, the company that wants to drill. It is dense by design, written in a legal register that often obscures what is actually being agreed to.
You do not need to become a petroleum landman to read a lease competently. You do need to know where to focus. Here is an overview of the sections that carry the most weight, written in plain English.
The parties
The first thing any lease establishes is who is signing. You will see your name as the “Lessor” and the operator’s name as the “Lessee.” Sometimes the Lessee is a large operator you will recognize. Sometimes it is a landman acting on behalf of a larger company who will later assign the lease. This is normal, but worth knowing.
If the lease names an entity you have never heard of, that does not necessarily mean anything is wrong. Leases are frequently assigned from smaller intermediaries to larger operators after execution. But it is a good reason to read the rest of the document carefully.
The granting clause
This is the sentence or paragraph that says what you are actually granting. In most leases it reads something like “Lessor hereby grants, leases, and lets unto Lessee the following described lands…” followed by a legal description.
Two things to look at carefully:
The legal description itself. This is the set of township, range, section, and sometimes more granular references that define which tract the lease covers. If you own minerals in multiple tracts, make sure the description captures only what you intend to lease, and all of what you intend to lease. Errors here are difficult to fix later.
The depths or formations covered. Some leases are silent on this, meaning they cover all depths. Others specify particular formations, or depths above or below a certain level. If your tract sits over multiple producing zones, the difference matters.
The primary term
The primary term is how long the operator has to start drilling before the lease expires. A three-year primary term means the operator has three years from the effective date to either drill a well or take some other defined action to hold the lease. If they do neither, the lease typically expires and you are unleased again.
Shorter primary terms are generally more favorable to mineral owners, because they create pressure on the operator to either act or let the minerals go. Longer primary terms give the operator more flexibility. Five years is not uncommon. Three years is also common. Shorter than three is less common but does appear in more competitive areas.
The royalty
This is the percentage of production revenue you receive as the mineral owner. In most modern leases, this is expressed as a fraction, such as one-eighth, three-sixteenths, one-fifth, or one-quarter.
The royalty fraction matters a great deal over the life of a productive well. Its value does not just come from the number itself but also from what the lease says about deductions. A royalty that appears higher on paper may still earn less than one that appears lower, if the higher one allows more post-production costs to be deducted before you are paid.
Which brings us to…
The deduction clause
This is arguably the most important paragraph in any modern oil and gas lease and the one that creates the most confusion.
Once oil or gas leaves the wellhead, it has to be processed, compressed, transported, and often treated before it can be sold. Those activities cost money. The question is who pays.
Some leases say your royalty is calculated on the gross value at the wellhead with no deductions allowed. Others allow the operator to deduct post-production costs before calculating your royalty share. Still others use language that sounds protective but has been interpreted by courts to allow broad deductions.
Language like “cost-free royalty,” “no deductions,” “gross proceeds,” and “market enhancement” has specific legal meanings that vary by state. If your lease contains anything about deductions, understanding the specific language used is important. Attorneys who work with oil and gas leases see this language every day. An hour of their time reviewing a draft lease can meaningfully affect your income for years.
Pooling and unitization
Most modern leases include a provision that allows the operator to combine your tract with adjacent tracts to form a larger drilling unit. This is called pooling or unitization.
Pooling is often necessary. Horizontal wells drilled today frequently span multiple sections, and without pooling, operators could not develop them efficiently. But the specific terms matter. Large pooling provisions (like 1,280 acres or even larger) give the operator broad flexibility. Tighter pooling provisions restrict how much acreage can be combined.
The relevant question is usually not whether to allow pooling, which is effectively unavoidable in most modern basins, but how much acreage can be pooled and under what conditions.
Continuation and Pugh clauses
After the primary term ends, the lease continues for as long as the operator is producing from the tract. That is the general rule, but there are variations worth knowing.
A Pugh clause determines what happens to the parts of your tract that are not being developed. Without a Pugh clause, a well drilled on one small portion of your tract can hold the entire mineral interest indefinitely, even if other portions could have been developed separately by a different operator. A Pugh clause releases the undeveloped portions back to you after the primary term.
Horizontal Pugh clauses do the same thing for depths and formations. If the operator drills only one formation, the other formations are released after the primary term.
Pugh clauses are not always included in first-draft leases from operators. They are often added through negotiation.
Surface use and damages
If you are also the surface owner (which is not always the case in states with split estate), the lease governs how the operator can use the surface. This covers things like pad locations, roads, and water.
Surface damages payments compensate the surface owner for the impact of operations. These are separate from the mineral royalty and vary widely by state, lease, and operator.
If you are not the surface owner, these provisions matter less to you, but they still affect the relationship between your operator and the surface owner, which can shape how smoothly operations go.
Bonus payment
The bonus is a one-time payment the operator makes to you at the time the lease is signed, in exchange for the right to develop during the primary term. It is typically quoted per net mineral acre and varies dramatically by basin, timing, and negotiation leverage.
The bonus is usually the most visible number in any lease discussion, but it is not always the most consequential. A lease with a modest bonus and favorable royalty and deduction terms may be worth far more over the life of a well than a lease with a large bonus and unfavorable ongoing terms.
The takeaway
A lease is a long-term contract, often lasting a decade or more if the well produces. The time spent understanding it at the outset is almost always worth it.
If you have a lease draft in hand and are not sure what to focus on, or if you have a lease that has been in effect for years and you are now wondering what it actually says, we are happy to walk through the specifics with you.