A mineral rights deal sells or leases the right to the oil, gas and other resources under a piece of land. Most start with a landman. A landman looks up who owns the minerals and works out a lease. The lease pays the owner a bonus up front plus a royalty. A royalty is a share of the money from what the well produces, and it most often runs from 12.5% to 25%. Owners can also sell their minerals outright to buyers who price them on expected output.
The United States is one of the few countries where private citizens can own the minerals under their land. That creates a large, busy market. Here is how it works, who the main players are and how analysts decide what an interest is worth.
Who Owns What Under the Ground
In most U.S. states, the rights to the surface and the rights to the minerals can be owned apart. When they are split, the land owner and the mineral owner can be different people, firms or even governments. The Bureau of Land Management calls this a split estate. It is common across the Rocky Mountain West. Part of the reason is a 1916 homestead law. That law let settlers claim land while the federal government kept the minerals.
Private owners lead in many oil and gas regions. One academic study looked at onshore oil and gas income in the lower 48 states in 2012. It found that about 77% came from privately owned minerals. That paid private royalty owners about $22 billion that year. The National Association of Royalty Owners says some 12 million Americans get oil and gas royalties.
The four interests worth knowing
- Mineral interest. Full ownership of the minerals. The owner can lease them, sell them or pass them to heirs.
- Royalty interest. A share of the money from production. The owner does not pay drilling or operating costs.
- Non-participating royalty interest (NPRI). A royalty without the right to work out leases or collect a lease bonus.
- Overriding royalty interest (ORRI). A royalty cut out of the operator’s working interest. It ends when the lease it rests on ends.
What a Landman Does
Landmen sit between energy firms and the people who own minerals. The American Association of Professional Landmen calls them the public-facing side of an exploration and production team. Company landmen work out leases and clear title. Independent field landmen dig through county courthouse records to find owners. Some owners got small interests from family decades ago and may not know they own them. Land consultants add deeper checks on larger deals.
Title work is the slow, careful core of the job. A single drilling unit can include dozens of owners. Each one holds a small share. Every one must be found and either leased or accounted for before a well can be drilled. Business Insiders has profiled a land services broker behind more than $150 million in acquisitions across the Great Plains. His work is a reminder that much of this happens in courthouses and at kitchen tables long before a rig shows up.
Inside an Oil and Gas Lease
A lease gives an operator the right to explore and produce for a set time. Mississippi State University Extension lays out the standard terms owners will see.
- Lease bonus. A one-time payment per mineral acre at signing. The owner keeps it whether or not a well is ever drilled.
- Primary term. Most often three to five years. If the operator does not drill and produce in that time, the lease ends.
- Held by production. Once a well produces enough to pay, the lease goes on as long as the well keeps producing.
- Royalty. The owner’s share of the money from production. Over the life of a well, it matters far more than the bonus.
- Shut-in royalty. A payment that keeps the lease alive while a well is shut for a time.
Royalty rates have gone up in the most hotly contested basins. A one-eighth royalty, or 12.5%, was the old standard. It is still the legal floor in some states, such as Pennsylvania. Caddo Minerals, a mineral buyer, studied leases recorded from 2023 to 2025. It found median royalties of 25% in the Permian’s Midland and Delaware basins. The median was 20% in the Anadarko, Eagle Ford and Haynesville. It was about 17% in the Bakken. Costs taken out after production can cut what owners get. So the fine print matters as much as the headline rate.
Why Minerals Have Become a Big Business
Record output has made owning minerals worth more. The U.S. Energy Information Administration says domestic crude output averaged a record 13.6 million barrels per day in 2025. The Permian Basin made about 48% of that total.
Large buyers have rolled up mineral and royalty interests into public companies. The biggest recent deal was Viper Energy’s purchase of Sitio Royalties. It was announced in June 2025 at about $4.1 billion including debt and closed that August. The combined firm holds about 85,700 net royalty acres in the Permian. Other public players, such as Kimbell Royalty Partners and Black Stone Minerals, have kept buying through 2026.
How Analysts Value Mineral and Energy Assets
Mineral interests are valued on the cash they are expected to bring in. Analysts start by sorting reserves by how sure they are.
- Proved developed producing (PDP). Wells that already produce. This is the most valuable and least risky group.
- Proved developed non-producing. A well has been drilled, but it is not producing yet.
- Proved undeveloped (PUD). Reserves that need new wells. Buyers mark these down more for risk.
- Probable and possible. Less certain resources. Buyers often pay for them only in hot bidding.
Public companies report PV-10, the present value of future net revenue discounted at 10%. They use SEC pricing rules based on a 12-month average of prices. Analysts who cover operating companies also compare enterprise value to EBITDAX. That is a cash flow measure that leaves out the cost of exploring. Most of the gap between what a buyer offers and what an owner hopes to get comes from three things. They are price guesses, how fast wells decline and how busy operators are.
That way of looking at assets is a core skill for analysts who cover energy, utilities and adjacent sectors. In those fields, small changes in price or output forecasts can move values sharply. More coverage of the sector sits in the energy and finance sections.
Tips for Owners Weighing an Offer
- Confirm just what you own and in which tracts before you start talks.
- Compare the royalty rate and the wording on cost deductions, not just the bonus.
- Get more than one offer if you are thinking of selling.
- Ask whether there are active drilling permits nearby. They can raise value.
- Have an oil and gas lawyer review any lease or sale deal.
Frequently Asked Questions
What is a typical royalty rate on an oil and gas lease?
In the past it was 12.5%. In today’s busiest basins, 20% to 25% is common. Older or quieter areas often lease closer to 18.75%.
What is the difference between mineral rights and royalty rights?
Mineral rights include the power to lease and collect bonuses. A royalty interest only pays a share of the money from production.
Should I sell my mineral rights?
It depends on your need for cash, how well you handle price swings and the drilling outlook for your area. Owners who sell trade future royalty income for a lump sum today.
The Bottom Line
Mineral rights deals blend old-school title research with modern financial analysis. Owners who know lease terms, royalty rates and the basics of value can bargain from a stronger place. Investors who know the land side avoid costly title surprises.
