If you own mineral rights — whether you inherited them from a grandparent or bought land decades ago without thinking much about what was underneath — you've probably received letters, phone calls, or lease offers that felt like they were written in a foreign language. Terms like "net revenue interest" and "pugh clause" get thrown around as if everyone knows what they mean. Most people don't, and the companies sending those letters know it.
This guide covers 20-plus terms you'll encounter as a mineral owner, explained in plain English. By the time you finish reading, you'll understand what you actually own, how royalties are calculated, what your lease really says, and what it means to sell. That knowledge matters whether you decide to lease, hold, or sell your mineral rights — because you can't make a good decision about something you don't understand.
We'll also weave in real numbers and state-specific details — Texas, Oklahoma, Louisiana, and others — because mineral rights law and taxation vary significantly depending on where your acreage sits.
What You Actually Own: Mineral Rights and the Different Kinds of Interests
Mineral rights are the legal ownership of the oil, gas, and other resources found beneath the surface of a piece of land. They are separate from surface rights, which cover what's on top of the ground — the house, the farm, the timber. In many parts of the country, especially across Texas, Oklahoma, and Louisiana, mineral rights were "severed" from surface rights generations ago. That's why you might own minerals under land that someone else farms or lives on.
Owning mineral rights doesn't mean you're pumping oil. It means you have the legal right to receive payment when someone else does.
Royalty interest is the most common form of ownership for people in your position. If you own a royalty interest, you receive a percentage of the revenue generated from oil and gas production on your property — without paying any of the costs to drill or operate the well. The royalty rate is set in your lease agreement. In Texas and Oklahoma, standard lease royalties historically ran 1/8 (12.5%), but in active plays like the Permian Basin or the SCOOP/STACK in Oklahoma, landowners have negotiated royalties of 20% to 25% in recent years. In Louisiana's Haynesville Shale, 20% to 22% is common.
Working interest is very different. If you own a working interest, you share in both the revenue and the costs — drilling, completion, operating expenses. Working interest owners take on real financial risk. Most mineral owners inherited a royalty interest, not a working interest, so if you've never received a bill from an operator, you almost certainly own a royalty interest. If you're not sure, check the original deed or lease paperwork.
Overriding royalty interest (ORRI) is a royalty carved out of the working interest. It's typically created by the landman or broker who negotiated the lease — they keep a small slice of production, say 1% to 3%, as compensation. An ORRI doesn't come out of your royalty; it comes out of the working interest owner's share. ORRIs are common, but they expire when the lease they're attached to expires.
Net revenue interest (NRI) is the actual percentage of production revenue that any given party receives after all royalties and other burdens are accounted for. If you own a 20% royalty on 100 acres and your acreage is pooled into a 640-acre unit, your NRI isn't 20% — it's 20% multiplied by your proportionate share of the unit (100/640), which equals about 3.125%. Understanding your NRI is essential for evaluating what your mineral rights are actually worth, because that's the number that drives everything.
Your Lease: The Document That Controls Everything (For Now)
When an oil company wants to drill on your land, they can't just show up. First, they lease your mineral rights. A mineral lease is a contract that grants the operator the right to drill in exchange for a bonus payment and royalties. Once you sign a lease, that document controls your income, your rights, and your options — sometimes for decades. Read it carefully, or have a mineral rights attorney review it before signing.
Here are the key lease terms you need to know:
Lease bonus is the upfront cash payment you receive when you sign the lease, before any well is drilled. It's typically paid per net mineral acre. In hot areas like the Delaware Basin in West Texas or the Midland Basin, bonuses have run $3,000 to $10,000 per acre in recent years. In slower areas or older plays, you might see $50 to $500 per acre. The bonus is taxable income in the year you receive it.
Primary term is the initial period the lease is valid — usually three to five years. During this time, the operator must either drill a well or the lease expires. If they don't drill and don't pay to extend, you get your mineral rights back, unencumbered.
Delay rental is a payment the operator can make to extend the lease for another year without drilling. These clauses were standard in older leases, though they're less common in newer ones. If your lease has a delay rental clause, the operator has to either drill, pay the rental, or let the lease expire.
Held by production (HBP) is one of the most important concepts in mineral rights. Once a well starts producing, your lease is "held" as long as production continues — even if it's just a trickle. There's no expiration date. Leases that are held by production on older wells with very low production can tie up your minerals for years or decades, preventing you from signing a new lease at better terms. This is a significant issue for mineral owners in places like the Anadarko Basin in Oklahoma, the Permian Basin in Texas, and in parts of Louisiana's Cotton Valley play.
Pugh clause (pronounced like "pyoo") is a lease provision that prevents production on one part of your acreage from holding the entire lease. Without a Pugh clause, if a well is drilled on 40 acres of your 200-acre tract, that one well holds all 200 acres. With a Pugh clause, only the acreage actually included in the producing unit is held — the rest reverts to you at the end of the primary term. Always try to negotiate a Pugh clause into any new lease. In Texas and Oklahoma, they're common but not automatic.
Division order is the document you receive after a well begins producing and before you receive your first royalty check. It sets out the exact decimal interest you'll be paid — your NRI for that specific well. Read it carefully. Errors in division orders are not rare, and if you sign one with a mistake, you may be accepting a lower payment than you're owed. You have the right to request a title opinion and supporting documentation before signing. In Texas, operators must pay interest on royalties that are delayed more than 120 days past the first production month.
Pooling, Units, and What Happens When Your Land Is Combined With Others
Modern oil and gas wells — especially horizontal wells — often need to draw from a large area to be economically viable. A single horizontal well might require 640 acres or more. If your tract is only 40 acres, the operator needs to combine it with neighboring tracts. That process is called pooling (also called unitization in some contexts), and it significantly affects your royalty payment.
Pooling is the combining of multiple tracts into a single drilling unit. Once pooled, all mineral owners in the unit share the production from the well in proportion to their acreage. If you own 40 acres in a 640-acre unit, you receive 40/640 — or 6.25% — of the unit's production revenue, multiplied by your royalty rate. Most modern leases include a pooling clause that gives the operator the right to pool your acreage without your individual approval each time. Pay attention to what your pooling clause allows — some are broad, some are limited by acreage size.
Force pooling (also called compulsory pooling) is when a state government requires you to participate in a drilling unit even if you haven't signed a lease or don't want to participate. Most oil and gas states have force pooling laws, but they vary significantly. In Oklahoma, force pooling is common and well-established. In North Dakota, the Industrial Commission can force pool non-consenting owners, who then receive their royalty share but don't share in well costs until the operator recoups a risk penalty (typically 150% to 200% of the drilling cost). In Texas, there is no statewide force pooling for oil — operators must get voluntary agreement. In Louisiana, the Office of Conservation can establish drilling units and force pool unleased interests.
Unitization refers to combining an entire reservoir — sometimes across multiple lease agreements and ownership groups — into a single operating unit to maximize recovery and prevent waste. It's broader than pooling and more common in places like Alaska (Prudhoe Bay operates as a giant unit) and California. If your acreage is unitized, your checks may come from a unit operator you've never dealt with directly.
If you're ever told your acreage is being pooled or unitized, ask for the unit plat — a map showing the unit boundaries — so you can confirm your acreage is correctly included. Acreage disputes at this stage can cost you significant money.
Taxes on Mineral Rights: What You'll Pay and When
Mineral rights income is taxable at both the federal and state level, and there are also property taxes to think about. Here's what you need to know.
Severance tax is a state tax on oil and gas production, taken at the wellhead before you ever receive your royalty check. The operator withholds it and remits it to the state — you'll see it as a deduction on your royalty check stub. Rates vary by state and by product:
- Texas: 4.6% on oil, 7.5% on gas
- Oklahoma: typically 7% on oil and gas (with some incentive rate reductions in early production)
- Louisiana: 12.5% on oil, varies on gas
- New Mexico: 3.75% on oil, 4% on gas (approximate)
- North Dakota: around 5% plus an oil extraction tax of 5%
- Wyoming: 6% on oil and gas
- West Virginia: 5% on oil, 5% on gas
If your royalty stub doesn't show a severance tax deduction, ask your operator why. In some cases, incentive programs reduce or eliminate severance tax for the first months of production.
Ad valorem tax is a property tax assessed on the value of your mineral rights. This is separate from severance tax and is assessed by county governments, not state governments. In Texas and Oklahoma, ad valorem taxes on producing mineral interests are a real line item — in active counties like Midland County, Texas, or Kingfisher County, Oklahoma, the assessed value of a producing mineral interest can be significant. If you own minerals that are not currently producing, many counties still assess ad valorem taxes based on the estimated value of the rights. Check with your county appraisal district.
Depletion allowance is a federal tax deduction that mineral owners can take to account for the fact that the oil and gas in the ground is a finite resource — once it's produced, it's gone. The IRS allows royalty owners to deduct 15% of their gross royalty income as a depletion expense. This is called percentage depletion, and it's a meaningful benefit. On $50,000 of annual royalty income, that's a $7,500 deduction before you even start itemizing other expenses. Talk to a CPA who works with mineral owners — this is one deduction that's worth understanding.
Capital gains tax applies when you sell mineral rights. If you've owned the minerals for more than one year, the proceeds are generally taxed at long-term capital gains rates — 0%, 15%, or 20% depending on your income. This is usually more favorable than ordinary income tax rates. However, the cost basis on inherited minerals can be complex to calculate. If you inherited mineral rights, your basis is typically the fair market value at the time of the original owner's death, which may be very low for old estates. A tax advisor familiar with mineral rights can help you calculate what you'd actually owe before you make any decisions.
Non-Participating Royalty Interests and Other Ownership Structures You Might Have Inherited
Inherited mineral rights often come with ownership structures that aren't straightforward. Here are a few you may encounter:
Non-participating royalty interest (NPRI) is a royalty interest that receives a share of production revenue but has no right to participate in leasing decisions and no right to the lease bonus. If your deed says you own an NPRI, someone else controls whether and how your minerals get leased, but you still collect a royalty from production. NPRIs are common in older Texas and Oklahoma deeds where mineral rights were split between family members over generations.
Executive right is the right to negotiate and execute a lease on behalf of other mineral owners. If you have the executive right, you control the lease terms — including the royalty rate and bonus. If you don't have the executive right, someone else is making those decisions for your minerals. Knowing which type of interest you own matters a great deal if you're evaluating whether to sell.
Mineral acres vs. royalty acres: When buyers or brokers quote prices for mineral rights, they often quote a price per net mineral acre (NMA). But if you own a fraction of the minerals — say, 50% of the minerals under 100 acres — you own 50 net mineral acres, not 100. Always confirm the exact fraction of mineral ownership before accepting or comparing offers.
Making Sense of Your Royalty Check and What Comes Off the Top
When production revenue flows from the wellhead to your mailbox, a lot can happen along the way. Understanding your royalty check stub is important — mistakes happen, and the numbers can be complex.
Post-production costs are expenses deducted from your royalty check for gathering, compressing, transporting, processing, and marketing the gas after it leaves the wellhead. Whether operators can deduct these costs from your royalty depends on your lease language and your state's law. In Texas, if your lease says your royalty is paid "at the well" or "at the mouth of the well," post-production costs are generally deductible. If it says royalties are free of post-production costs, they're not. In West Virginia, there have been significant legal battles over post-production deductions. Read your lease and your check stub carefully.
Take-in-kind is the right some royalty owners have to receive their share of production as actual oil or gas, rather than cash. Most individual mineral owners receive cash, but this clause appears in some leases and is worth knowing about.
Royalty suspension can happen when a well goes offline for maintenance or workover, or if production falls below a minimum threshold. Some leases specify that royalties are only due on "paying quantities" — meaning the well must generate enough revenue to turn a profit after operating costs. If your checks stop, ask the operator for a written explanation.
If you receive a royalty check and something looks wrong — the volumes seem low, the price per unit is far below market, or a deduction line you don't recognize — you have the right to request a copy of the production records and pricing documentation. Start with a written letter to the operator's revenue accounting department. Keep records of everything.
You now have a working vocabulary for the conversations that matter — with landmen, attorneys, operators, and buyers. That puts you in a much stronger position than most mineral owners who hear these terms for the first time across a negotiating table.
If you're thinking about selling your mineral rights and want to know what they're worth, reach out to us. When you do, a real person — not an automated system — will call you back, usually within one business day. We'll ask you some basic questions about your acreage, look at the production data, and give you a straight answer about what we'd pay. There's no commitment, no pressure, and no fee to find out. You can always say no.