If you've received an offer to buy your mineral rights — or you're thinking about selling — the first question most people ask is: how do I know if this number is any good? That's exactly the right question, and most people never get a straight answer to it.
This article will give you real benchmarks. You'll learn how mineral rights are priced, what dollar-per-acre ranges actually look like in states like Texas, Oklahoma, and Louisiana, how buyers calculate offers based on your royalty income, and what warning signs tell you to walk away from a deal. By the time you finish reading, you'll have enough knowledge to evaluate any offer you receive — or to go out and find a better one.
Nothing here is designed to push you toward selling. Some people are better off holding. But if you do decide to sell, you deserve to know what fair looks like.
How Mineral Rights Are Priced: The Two Methods Buyers Use
Buyers use two main approaches to value mineral rights, and understanding both will help you immediately.
The first method is dollar per acre ($/acre). This is the most common approach when mineral rights are non-producing — meaning there's no active well generating royalty income on your property. The buyer is essentially paying for the potential that something will be drilled in the future. In this case, price depends heavily on location, the basin (the underground rock formation where oil and gas are found), current activity from drilling companies nearby, and how much acreage you own.
The second method is a price multiple on royalty income, sometimes called a royalty multiple or expressed as a multiple of monthly income. This applies when you're already receiving royalty checks — payments from an oil and gas company for the right to produce minerals from your land. If you're getting $500 a month in royalties, a buyer might offer you 40 to 60 times that monthly amount, or $20,000 to $30,000. We'll break down exactly what those multiples should look like by region shortly.
Some offers blend both methods, especially if there's one producing well but several hundred undeveloped acres that could be drilled later. A good offer will account for both.
Dollar-Per-Acre Ranges by Basin and State
These numbers are real market ranges based on recent transactions. They shift with oil prices, drilling activity, and what the major operators are doing in a given area, so treat these as benchmarks rather than guarantees — but they're close enough to tell you whether an offer is in the ballpark.
Permian Basin (West Texas and New Mexico): This is the most active oil basin in North America right now. Producing mineral rights in the core of the Midland Basin or Delaware Basin routinely trade for $15,000 to $50,000 per net mineral acre, with hot spots in Lea and Eddy counties (New Mexico) or Midland and Martin counties (Texas) pushing even higher. Non-producing acreage in the Permian can still fetch $2,000 to $8,000 per acre depending on proximity to active drilling.
Eagle Ford Shale (South Texas): A mature but still-active shale play. Producing minerals in the oil window (counties like DeWitt, Karnes, and Gonzales) trade for $10,000 to $30,000 per acre. Non-producing acreage further from the core might be $500 to $2,500 per acre.
Haynesville Shale (Northwest Louisiana and East Texas): A natural gas play that has seen renewed interest as gas prices have recovered. Producing minerals in parishes like DeSoto and Caddo in Louisiana typically trade for $5,000 to $15,000 per acre. Non-producing acreage in the core can still bring $1,000 to $4,000.
SCOOP/STACK (Oklahoma): These overlapping plays in central Oklahoma cover counties like Grady, Garvin, Kingfisher, and Blaine. Producing acreage in the SCOOP (South Central Oklahoma Oil Province) trades for $8,000 to $25,000 per acre in the core. Non-producing acreage is more variable — $500 to $3,000 is a reasonable range, with outliers in both directions.
Anadarko Basin (Western Oklahoma and Texas Panhandle): Older, more conventional production. Prices are lower here. Producing minerals might trade for $3,000 to $10,000 per acre. Non-producing land in lower-activity areas might bring only $200 to $800.
Williston Basin / Bakken (North Dakota and Montana): A big oil play that's matured considerably. Producing minerals in the Bakken core (Williams, McKenzie, Mountrail counties in North Dakota) trade for $8,000 to $20,000 per acre. Non-producing acreage is $500 to $3,000 depending on offset well activity.
DJ Basin / Wattenberg Field (Colorado and Wyoming): Weld County, Colorado is the core here. Producing minerals range from $8,000 to $18,000 per acre. Wyoming acreage in less active areas of the basin is lower.
Appalachian Basin (Pennsylvania, Ohio, West Virginia): Mostly natural gas — the Marcellus and Utica shales. Producing royalties in the core of the Marcellus (northeast Pennsylvania, West Virginia) trade at lower multiples than oil plays, often reflecting $3,000 to $10,000 per acre. Ohio Utica is more variable and generally lower.
Midcontinent / other states (Kansas, Mississippi, Alabama, Arkansas, Utah, California, Alaska): These are harder to generalize. Kansas has conventional production that trades cheaply — often $500 to $3,000 per acre. Mississippi and Alabama have some legacy conventional production. California mineral rights are complex due to regulatory issues. Alaska is highly case-specific. If you own minerals in these states, you'll need a more individualized assessment, but the methods are the same.
One thing worth noting: net mineral acres (NMA) is not the same as surface acres. If you own a 1/4 mineral interest in 40 acres, you own 10 net mineral acres. Buyers price per NMA, so always know your exact ownership fraction before you evaluate any offer.
How Royalty Multiples Work — and What's Fair
If you're receiving royalty payments, buyers will almost always use a monthly income multiple to value your interest. Here's how it works in plain terms.
Let's say you own a 1/8 royalty interest (12.5%) in a well and you're currently receiving $800 per month. A buyer will look at that income stream and ask: how long is this well likely to produce, what direction are energy prices heading, and how much risk am I taking on? Their answer to those questions determines what multiple they'll offer.
In practice, fair market multiples for producing mineral rights run between 36 and 72 times monthly income, with most deals landing between 48 and 60 months. That means:
- $800/month × 48 = $38,400
- $800/month × 60 = $48,000
If someone offers you 24 times monthly income (two years of payments), that is a low offer. If they offer 72 or more, you're being treated fairly or better. If you're in a high-value basin like the Permian or SCOOP core and you have undeveloped acreage alongside your producing well, a good buyer should also pay a premium for that upside.
A few things affect where in that range you should land:
- Decline rate: Oil and gas wells produce less over time. A new well declining fast will get a lower multiple than a stable, older well.
- Commodity: Oil royalties typically get higher multiples than gas royalties, because oil prices are more globally stable. Gas prices have been more volatile.
- Basin: Permian and SCOOP minerals command higher multiples than Appalachian or Anadarko Basin minerals, all else equal.
- Operator quality: If a major company like Pioneer, EOG, or Devon is operating your well, buyers feel more confident and may pay more. Smaller operators get slightly lower multiples.
One thing buyers will sometimes do is cherry-pick your best months as the baseline income number. Ask them: are you using a 12-month average, or a single recent month? A 12-month trailing average is fairer, especially if production has been declining.
How to Benchmark Any Offer You Receive
You don't need to be an expert to sanity-check a number. Here's a straightforward process.
Step 1: Know exactly what you own. Pull out your deed or the probate documents if you inherited these minerals. Find the county and state, the section/township/range legal description if you have it, and your ownership percentage. If you're unsure, a title company in the county where the minerals are located can help.
Step 2: Check whether there's a producing well. You can look this up for free in most states. Texas uses the Texas Railroad Commission website (rrc.texas.gov). Oklahoma has the Oklahoma Corporation Commission (occeweb.com). Louisiana has the Louisiana DNR (dnr.louisiana.gov). North Dakota has the NDIC. Most state databases let you search by county and section. If you see active wells near or on your land, that matters enormously to value.
Step 3: Calculate the implied multiple. If you're receiving royalties, divide the offer by your monthly income. A $45,000 offer on $900/month in royalties implies a 50× multiple. That's reasonable. A $21,600 offer on the same income implies a 24× multiple. That's low.
Step 4: Compare to $/acre. Divide the offer by your net mineral acres. If someone offers you $12,000 for 3 net mineral acres in the Permian Basin, that's $4,000/NMA. Based on current market activity, that's low for a producing interest in an active area. If they're offering $18,000 for 3 NMA, that's $6,000/NMA — still potentially below market depending on where exactly you are.
Step 5: Get a second offer. The single most effective thing you can do to protect yourself is to get two or three offers. Mineral rights buyers compete for good assets. If your minerals are in an active basin, multiple buyers will want them, and competing offers will quickly tell you what the real market looks like. Don't sign anything until you have at least two independent offers.
When to Walk Away from an Offer
Not every offer deserves a counteroffer. Some should just be declined.
Walk away if the buyer pressures you for a quick decision. Any buyer who tells you the offer expires in 48 hours, or who calls you repeatedly after you've said you need time, is not acting in your interest. Legitimate buyers don't rush sellers.
Walk away if the offer is below 30× monthly income with no explanation. Unless your well is in severe decline or there are title problems, a multiple below 30 is not competitive and signals either an inexperienced buyer or one who is counting on you not knowing better.
Walk away if the $/acre is dramatically below basin averages. If you're in Karnes County, Texas, and someone offers you $1,200 per net mineral acre for producing interest, that's not a negotiating starting point — it's an insult. You should be looking at $10,000+ per NMA for good production in that county.
Walk away if the buyer can't explain how they arrived at their number. A credible buyer should be able to tell you: here's the current production data I used, here's the decline curve I applied, here's the commodity price assumption. If they can't do that, they're not a serious buyer.
Walk away if you feel rushed or confused by the paperwork. The deed transferring mineral rights is a legal document. You should have an attorney — ideally one with oil and gas experience — review it before you sign. A buyer who discourages you from getting legal advice is a red flag.
That said, not every situation calls for walking away. If your minerals are non-producing, in a low-activity area, and you're receiving a cash offer that gives you financial flexibility, sometimes selling at a modest number makes sense. The question isn't whether to sell — it's whether this price reflects what you actually have.
Tax Considerations You Should Know Before You Sell
This section doesn't replace a tax advisor, but there are two things every mineral rights seller should understand before they close a deal.
First: the sale of mineral rights is typically taxed as a capital gain, not ordinary income. If you've held the minerals for more than a year (and most inherited mineral rights have been held far longer than that), the proceeds are subject to long-term capital gains rates. In 2024, federal long-term capital gains rates are 0%, 15%, or 20% depending on your total income. This is significantly lower than ordinary income tax rates, which top out at 37%.
Second: your cost basis matters a lot. If you inherited mineral rights, your cost basis is generally the fair market value at the time of inheritance — this is called a stepped-up basis. This means if your grandfather paid nothing for the land in 1950, and the minerals were worth $20,000 when you inherited them in 2005, your cost basis is $20,000. If you sell for $85,000 today, you only pay capital gains on the $65,000 difference, not the full $85,000. This is a significant tax benefit that many people don't realize they have.
State taxes vary. Texas has no state income tax. Oklahoma taxes capital gains as ordinary income at rates up to 4.75%. Louisiana has a flat 3% individual income tax rate. New Mexico taxes capital gains at rates up to 5.9%. North Dakota has a top individual rate of 2.9%. These differences can affect your net proceeds meaningfully, so it's worth a conversation with a CPA before you sign.
If you're planning to reinvest the proceeds into other real estate, ask a tax advisor about a 1031 exchange — in some structures, mineral rights can qualify, which would allow you to defer capital gains entirely.
If you'd like to find out what your mineral rights are actually worth — not a guess, but a number grounded in current market data for your specific county and formation — you're welcome to reach out. When you contact us, a real person with experience in oil and gas transactions calls you back, usually within one business day. There's no obligation, no pressure to sell, and no cost. You tell us what you own and where it is, and we'll give you an honest assessment of fair market value. That information belongs to you whether you sell or not.