If you've inherited mineral rights or been approached by an oil company asking you to sign a lease, you've probably run into a document full of terms that sound like a foreign language. Words like "Pugh clause," "shut-in royalty," and "Mother Hubbard clause" aren't explained anywhere in the lease itself — you're just expected to sign.
That's a problem, because the terms in an oil and gas lease determine how much money you'll make, how long the company can hold your land, and whether you'll ever be free to negotiate with someone else. A landowner in Texas who signs a lease with a 1/8 royalty instead of 1/5 could lose tens of thousands of dollars over the life of a well. The difference between a lease with a Pugh clause and one without could mean your land is tied up for decades.
This article explains nine of the most important lease terms in plain language. By the time you finish reading, you'll know what each term means, what's negotiable, and what to watch out for — whether you're deciding whether to sign a lease, renew one, or sell your mineral rights entirely.
The Primary Term: How Long They Have to Drill
The primary term is the fixed period of time — usually two to five years — during which an oil or gas company has the right to drill on your land. Think of it like a clock. The company pays you a bonus (an upfront cash payment) to start the clock, and they have until the clock runs out to actually drill a well.
In Texas and Oklahoma, primary terms of three to five years are common in active plays like the Permian Basin or the Anadarko. In Pennsylvania and West Virginia, where Marcellus Shale activity has slowed in some areas, you may see companies pushing for five-year terms. In North Dakota's Bakken region, two- to three-year primary terms are more typical because operators there move faster.
What matters most: if no well is drilled and producing by the end of the primary term, the lease expires and your mineral rights revert back to you — free and clear. That's the rule. The problem is that many leases contain provisions that extend the primary term automatically under certain conditions, and most landowners don't notice until it's too late.
When you're reviewing a lease, look at the primary term and then immediately look for language about extensions. Some leases allow the company to extend the primary term by one or two years simply by paying an additional delay rental — a small annual fee. That fee might be $5 per acre in a slow market. If they have 200 acres under lease, they can lock up your land for an extra year for $1,000. That's a low price for them and a real cost to you.
What to negotiate: Push for the shortest primary term you can get — two years in active areas. Require that any extension be at a substantially higher per-acre rate than the original bonus, not a token delay rental.
The Secondary Term: What "Held by Production" Really Means
Once a well is drilled and producing, the lease enters what's called the secondary term — and this is where things can get complicated. A lease in its secondary term is described as held by production (HBP), meaning the company has the right to hold your lease indefinitely as long as there is any production from a well on your land.
The word "any" is doing a lot of work in that sentence. In many states, a well producing just a few barrels of oil per day — or even less — qualifies as "producing in paying quantities," which is the legal standard used to determine whether a lease remains in effect. In Louisiana, courts have interpreted this standard somewhat more strictly than in Texas, where operators have occasionally held leases on wells producing almost nothing. In Oklahoma, there have been disputes where marginal wells produced barely enough revenue to cover operating costs, yet the lease was considered HBP.
This matters enormously if you're thinking about selling your mineral rights. A lease that is HBP with a producing well is worth less than unleased minerals or minerals under a lease that's about to expire — because the buyer is inheriting whatever terms are in that lease, including the royalty rate and any unfavorable clauses. Knowing whether your minerals are HBP, and under what terms, is the first thing any serious buyer will want to know.
What to negotiate: Include a clause specifying a minimum monthly production volume to qualify as "producing in paying quantities." Some Texas landowners negotiate a floor of 25 to 50 barrels per month. Below that, the lease expires regardless of what's coming out of the ground.
The Royalty Clause: Where Your Money Comes From
The royalty is your share of the revenue from oil and gas produced on your land. It's expressed as a fraction or percentage — 1/8 (12.5%), 3/16 (18.75%), 1/5 (20%), or higher. This is the most important number in your lease.
The difference between a 1/8 and a 1/5 royalty on a productive well is significant. If a well produces $500,000 worth of oil in a year, a 1/8 royalty earns you $62,500. A 1/5 royalty earns you $100,000. Over ten years, that's a $375,000 difference on a single well. Landowners in strong markets — the Permian Basin in West Texas, the DJ Basin in Colorado, the Williston Basin in North Dakota — routinely negotiate 20% to 25% royalties. If someone is offering you 12.5%, that's the floor, not the standard.
But the fraction isn't the only thing that matters. You also need to know whether your royalty is gross or net — and this is where many landowners get a surprise on their first royalty check.
A gross royalty means you receive your percentage of revenue before any deductions. A net royalty (sometimes called a "proceeds" royalty with deductions) means the company first subtracts costs for gathering, transporting, processing, and compressing the gas before calculating your share. In natural gas-heavy states like Pennsylvania, West Virginia, Ohio, and Wyoming, these post-production cost deductions can eat 20% to 40% of the gross value of the gas before your royalty is calculated. A landowner in the Marcellus Shale who thinks they're getting a 20% royalty may actually be netting 12% to 14% after deductions are applied.
Louisiana law is more protective of landowners here than most states — Louisiana courts have generally held that royalty owners are not responsible for post-production costs unless the lease explicitly states otherwise. Texas law is more ambiguous, and the specific lease language controls. In New Mexico, Pennsylvania, and Wyoming, you need to be especially careful because operators there have historically applied aggressive deductions.
What to negotiate: Insist on a "no deductions" or "at the wellhead" royalty clause that explicitly prohibits post-production cost deductions. If the company won't agree to that, negotiate for a cost cap — something like "deductions shall not exceed 5% of gross revenues."
Shut-In Royalties, Pooling, and the Clauses That Control Your Land
Shut-In Royalty
A shut-in royalty is a small payment an oil or gas company makes to keep your lease alive when a well has been drilled but isn't actively producing — usually because there's no pipeline connection yet or the market price is too low to justify production. Think of it as a placeholder payment.
The problem: shut-in royalties are often set at a rate that was written decades ago — $1 per acre per year is not uncommon in older leases. An operator can pay you $200 a year on a 200-acre lease and keep that lease alive for years while the well sits idle. If you see a shut-in royalty provision in your lease, make sure it has a time limit (two years maximum is reasonable) and that the per-acre rate is meaningful — at least $10 to $25 per acre in today's market.
Pooling Clause
Pooling (also called unitization in some contexts) allows an operator to combine your mineral acreage with acreage from neighboring properties to form a single unit, usually for the purpose of drilling one well that draws from all the pooled acreage. Your royalty is then calculated based on your proportional share of the total unit.
This sounds reasonable, but without limits it can work against you. If your 20 acres are pooled into a 640-acre unit, you now own 3.125% of the unit's production — even though the well might be sitting directly on your property. That means if the well produces $1 million worth of oil, and you have a 20% royalty, you receive 20% of $1 million times 3.125%, or $6,250. Without pooling, that same well on your 20 acres would pay you $200,000.
Most states allow some form of compulsory pooling by statute, so you can't always avoid it — but you can limit it. In Texas, compulsory pooling doesn't apply in the same way it does in Oklahoma, where the Oklahoma Corporation Commission can force pooling over a landowner's objection. In Louisiana, the Office of Conservation administers a similar process. In states where compulsory pooling exists, negotiating voluntary pooling terms in the lease is still valuable because it lets you set the unit size limit.
What to negotiate: Limit voluntary pooling in the lease to units of no more than 640 acres for oil and 1,280 acres for gas (or smaller if the geology allows it). Require that you be notified in writing before your acreage is pooled.
Pugh Clause
The Pugh clause (named after a Louisiana attorney, Lawrence Pugh, who developed it in the 1940s) is one of the most valuable protections a landowner can get in a lease — and many standard leases don't include it.
Here's the problem it solves: without a Pugh clause, if an operator drills one well anywhere on your 500-acre lease and that well is producing, the entire 500 acres is held by production. The company can hold hundreds of acres they never intend to drill, indefinitely, based on one marginal well in one corner of your land.
A Pugh clause breaks the lease into parts. It says that only the land actually included in a producing unit is held by the lease after the primary term. The rest of your acreage — the land outside the producing unit — expires at the end of the primary term and reverts to you.
In Louisiana, where Lawrence Pugh practiced, many standard leases include some version of this clause. In Texas, it is not implied by law and must be explicitly negotiated. In Oklahoma, West Virginia, and Colorado, the same is true — you have to ask for it. If you're sitting across the table from a land man (a company representative who negotiates leases) in Midland, Texas, and you ask for a Pugh clause, they'll know exactly what you're talking about. They may push back, but it's a legitimate ask.
What to negotiate: Get a Pugh clause. It should operate both horizontally (by surface area) and vertically (by depth) so that a company drilling one formation doesn't hold your entire mineral column forever.
Mother Hubbard Clause
The Mother Hubbard clause (sometimes called a "cover-all" clause) is a provision that attempts to capture any small strips of land adjacent to your described property that may have been missed due to surveying errors or ambiguous legal descriptions. A typical version says something like: "This lease also covers any strips or parcels of land adjacent to or surrounding the above-described tract in which Lessor has an interest."
For most landowners, this clause has minimal impact. But if you own land with a disputed boundary or an irregular survey, a Mother Hubbard clause could inadvertently include land you intended to keep unleased — or land that's part of a separate deal you're negotiating. It's also been used aggressively by some operators to capture mineral interests that legitimately belong to neighboring properties.
What to negotiate: Ask to have the Mother Hubbard clause removed entirely, or at minimum limit it to strips of land less than one acre in size that are "incidental to and not separately described" in the lease.
What You Can Actually Negotiate — and When to Walk Away
Many landowners assume that the lease form they're handed is take-it-or-leave-it. It isn't. Oil and gas leases are negotiated contracts, and the company's standard form is a starting point written entirely in their favor.
The terms most commonly negotiable, in roughly descending order of how hard companies will fight to keep them:
- Royalty rate and deductions — This is the big one. Most operators will negotiate the royalty rate in an active market. Fewer will readily agree to eliminate post-production cost deductions, but it's worth the fight.
- Primary term length — In a hot market, you have leverage. In a slow market, less so, but you can still push for a shorter term or higher delay rentals for extensions.
- Pugh clause — Often negotiable, though some large operators have standard forms that resist it.
- Pooling unit size limits — Usually negotiable with some pushback.
- Shut-in royalty rate and time limit — Often overlooked but usually not hard to negotiate.
- Mother Hubbard clause — Rarely a dealbreaker for the operator to remove or limit.
If a company tells you their form is non-negotiable, that's a negotiating tactic, not a fact. If they truly won't budge on royalty rates and deductions in a market where other operators are offering better terms, that's information worth having. It may mean the deal isn't worth taking, or it may mean you'd be better off selling your mineral rights outright rather than leasing.
Selling your mineral rights isn't the right choice for everyone — if you have a strong lease in an active area, leasing and collecting royalties over time can yield more total value than a lump-sum sale. But if your minerals are in a slower area, if you're older and less interested in waiting years for a well to be drilled, or if you've inherited rights in multiple states and want to simplify your estate, selling can make very good financial sense. The key is knowing what your minerals are actually worth before you decide anything.
Before You Sign Anything, Do This
If someone has approached you about leasing your minerals, you have more time than you think. Land men work with deadlines, but those deadlines are often artificial. A "this offer expires Friday" ultimatum is almost never real.
Here's what to do before signing:
First, get a copy of any existing lease if your minerals are already leased. You're entitled to it. If you don't have one, the county courthouse where the land is located — the county clerk's office in Texas, the register of deeds in West Virginia, the recorder of deeds in Pennsylvania — will have a recorded copy.
Second, read the royalty clause carefully and do the math. Take the offered royalty rate, apply it to a realistic production estimate for wells in that area (your state's oil and gas commission website publishes production data by county and well), and calculate what you'd actually receive over five and ten years.
Third, if you're being offered a bonus payment to sign a lease, compare it to what mineral rights in your area are actually selling for. In some parts of the Permian Basin, mineral rights trade for $10,000 to $30,000 per net mineral acre. If someone is offering you a $500-per-acre lease bonus, you're not being paid for the value of your minerals — you're being paid for temporary access to them.
If you'd like to understand what your mineral rights are worth — whether you're thinking about leasing or selling — reach out to us. A real person will call you back, typically within one business day. There's no obligation, no pressure, and no cost. We'll ask you some basic questions about your acreage, look up what we can about your minerals, and give you an honest picture of where things stand. That's a reasonable first step no matter what you ultimately decide to do.