If you've been quoted a price for your mineral rights — or if you're just starting to think about selling — you've probably wondered whether that number is fair. Most mineral owners have no easy way to check. The acre count on your deed doesn't tell you much by itself. A mineral acre in the Permian Basin of West Texas can be worth ten times more than a mineral acre in a played-out field in eastern Kansas, even if the paperwork looks identical.
This article walks through the six factors that actually drive mineral rights value. By the time you finish reading, you'll understand why two neighbors with the same number of acres can get very different offers — and you'll know what questions to ask before you sign anything.
Where Your Minerals Are Located — and Why It Matters More Than Anything Else
The single biggest driver of mineral value is location, specifically which geological basin your acreage sits in. A basin is a large underground depression where oil and gas have accumulated over millions of years. Some basins are prolific. Others have been mostly tapped out, or were never that productive to begin with.
Here's a real-world comparison. Mineral rights in the Midland Basin (the eastern half of the Permian Basin in West Texas) are currently trading at $10,000 to $25,000 per net mineral acre for producing properties in the core of the play. Move two counties east into the Permian's shelf, and that same acreage might fetch $3,000 to $6,000. Cross the state line into eastern New Mexico's portion of the Delaware Basin (the western half of the Permian), and you're back in high-value territory — $8,000 to $20,000 per acre in places like Eddy and Lea Counties.
In Oklahoma, the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) plays drove mineral values up significantly between 2014 and 2019. Core SCOOP acreage in Grady and Stephens Counties was trading at $5,000 to $15,000 per acre at the peak. Today, with oil prices more stable and some of that acreage fully drilled, values have settled, but active areas still command strong prices.
Louisiana mineral owners should know that the Haynesville Shale in the northwest corner of the state — parishes like DeSoto, Red River, and Caddo — is one of the most active natural gas plays in the country right now. With LNG (liquefied natural gas) export demand rising, Haynesville acreage has gotten meaningful attention from buyers. Values in the core of that play have ranged from $2,500 to $8,000 per acre depending on lease status and proximity to active drilling.
If you don't know which basin your minerals are in, look up your county on a state geological survey website, or simply call a minerals buyer and ask. Any reputable buyer will tell you immediately.
What You're Sitting On: Oil vs. Gas vs. NGL
The type of hydrocarbon your acreage produces — or is likely to produce — matters a great deal. Oil (crude) trades globally and commands a higher price per unit of energy than natural gas. Natural gas is cheaper, harder to transport, and more sensitive to regional supply and demand. NGLs (natural gas liquids, such as propane, butane, and ethane) fall somewhere in between and are often a significant revenue source in "wet gas" plays.
Right now, West Texas Intermediate crude oil is trading around $80 per barrel (as of mid-2024). Natural gas at Henry Hub — the main U.S. pricing benchmark — has been depressed, trading around $2.00 to $2.50 per MMBtu (million British thermal units). That's a meaningful headwind for gas-heavy mineral owners.
What this means practically: if your minerals are in a gas-heavy basin like the Marcellus Shale in Pennsylvania or West Virginia, or the Barnett Shale in North Texas, values are softer right now than they were in 2022 when gas prices spiked above $8. If you're in a predominantly oil basin like the Permian or the Bakken in North Dakota and Montana, the commodity price environment is more favorable.
North Dakota's Bakken is worth specific mention. Mineral values in Mountrail, McKenzie, and Williams Counties remain strong — typically $8,000 to $18,000 per acre for producing tracts — because the Bakken produces oil with associated gas, and operators have gotten efficient at completing wells there. Montana's portion of the Bakken (primarily in Richland and Roosevelt Counties) tends to be less active, with values running lower, often $2,000 to $6,000 per acre.
In Colorado's DJ Basin (Denver-Julesburg Basin), Weld County has been one of the most active drilling areas in the country. Mineral values there for producing acreage have ranged from $4,000 to $12,000 per acre. The basin produces a mix of oil and gas, which has helped insulate it somewhat from the gas price slump.
Lease Status and What's Happening on Your Land Right Now
Mineral rights exist in a few different states, and each one commands a different price.
Unleased and undrilled minerals are the most speculative. You own the rights, but nobody is paying you anything, and there's no guarantee anyone ever will. Buyers will price these based on whether nearby acreage is being actively leased and drilled. In a hot play, unleased minerals can still attract strong offers. In a quiet area, they may be worth very little.
Leased but undrilled minerals mean an oil company has paid you a bonus and is holding your acreage under a lease — typically for 3 to 5 years — while they decide whether to drill. The lease bonus you received was a one-time payment. If the company drills, you'll receive a royalty (a percentage of revenue from the well, typically 18% to 25%). If they don't drill before the lease expires, the lease terminates. Buyers will pay more for leased acreage if the operator is known to be actively drilling in the area.
Producing minerals are the most straightforward to value. You're already receiving royalty checks. Buyers look at your average monthly income, apply a multiplier (often 4 to 6 years' worth of annual income for conventional production, sometimes higher for newer wells), and that becomes their offer. For example, if you're receiving $1,500 per month in royalties, a buyer might offer $72,000 to $108,000 for those rights (4 to 6 years × $18,000 annual income). That's a simplified calculation — actual offers depend on everything else in this article — but it gives you a starting framework.
One important note: if your minerals are in suspense — meaning a check is owed to you but hasn't been sent because the operator can't locate you, or there's a title dispute — that's fixable, and a good buyer can sometimes help you resolve it before or during a transaction.
Production History and What the Wells Tell You
If there are producing wells on your acreage, their production history is the most concrete data point a buyer has. Production data is public record in most states and is available through state oil and gas commission databases.
A well that started producing 500 barrels of oil per day two years ago and is now producing 350 barrels per day is declining — but declining at a predictable rate that buyers can model. A well that started at 50 barrels per day and is still producing 45 barrels per day ten years later is a steady, low-risk income stream. Both have value, but for different reasons.
Decline rate matters a lot. Shale wells — like those in the Permian, Bakken, Eagle Ford in South Texas, or Haynesville — decline steeply in the first two years (sometimes 60% to 70%), then flatten out. Conventional wells in places like the Anadarko Basin in Kansas and Oklahoma, or the older fields in Mississippi and Alabama, tend to decline more slowly. Slow-decline conventional production is often undervalued by sellers who think newer = better.
In Wyoming, for example, many mineral owners in the Powder River Basin or the Green River Basin have conventional production that has been steady for decades. That consistency has real value that sometimes gets overlooked.
If you have royalty statements, pull out the last 12 to 24 months and look for trends. Is your monthly check growing, shrinking, or steady? That trend line is a significant part of what a buyer is paying for.
Who Is Drilling on Your Acreage — Operator Quality
Not all oil companies are equal, and it matters who holds the lease on your minerals. A major operator with strong capital, proven technical capability, and an active drilling program in your area is worth more to you than a small independent that may be land-banking acreage with no immediate plans to drill.
In the Permian Basin, operators like Pioneer Natural Resources (now part of ExxonMobil), Diamondback Energy, and Coterra Energy have strong reputations and active drilling programs. Minerals under their leases, or in their primary operating areas, are viewed as lower-risk by buyers because the likelihood of future development is higher.
In the Eagle Ford Shale in South Texas — counties like Webb, La Salle, McMullen, and DeWitt — operators like EOG Resources and ConocoPhillips have been consistently active. Minerals in those areas carry a premium because you have confidence the wells will keep getting drilled.
Conversely, if your minerals are leased to a company you've never heard of, and they've been sitting on the lease for three years without drilling, that's a yellow flag. It doesn't mean the minerals are worthless — it may mean the operator is waiting for commodity prices to improve — but a buyer will price that uncertainty into their offer.
For mineral owners in states like Arkansas (Fayetteville Shale) or Mississippi (Tuscaloosa Marine Shale), operator activity has been limited in recent years. Those minerals still have value, but buyers will be conservative until activity picks back up.
Formation Depth and the Cost of Getting Your Minerals Out
The deeper the target formation, the more expensive it is to drill. Drilling costs directly affect how much a buyer is willing to pay, because higher drilling costs mean the economics are tighter — especially at lower commodity prices.
In the Permian Basin, operators are often drilling multiple stacked formations — the Wolfcamp, Spraberry, Bone Spring — sometimes in a single wellbore. The ability to stack pay zones (multiple oil-bearing layers) is one reason Permian minerals command such high prices. The same surface location can produce oil from four or five different depths.
In contrast, the Tuscaloosa Marine Shale in Louisiana and Mississippi targets a formation at roughly 11,000 to 14,000 feet. That depth makes wells expensive — often $12 to $15 million per well — which is part of why that play has struggled to gain momentum even with good rock.
In Pennsylvania and Ohio's Utica Shale, which sits below the Marcellus, depths run 6,000 to 9,000 feet. The formation is productive, but the combination of current gas prices and drilling costs has slowed activity compared to the peak years of 2011 to 2015.
Shallower formations — like the Red Fork or Skinner sands in Oklahoma, or the Cotton Valley formation in East Texas and Louisiana — can be drilled relatively cheaply (sometimes $1 to $3 million per well), which means the economics work even at lower commodity prices. Don't assume shallow equals lower value.
For mineral owners in California, depth varies dramatically by basin. The San Joaquin Valley has conventional production at moderate depths and is still active, though California's regulatory environment adds cost and uncertainty that buyers factor in. Utah's Uinta Basin has seen renewed interest in its waxy crude, with operators in Duchesne and Uintah Counties becoming more active.
In Alaska, mineral rights are more complex — the state retains most subsurface mineral rights, and private ownership is less common than in the Lower 48. If you believe you have privately owned mineral rights in Alaska, it's worth getting a title opinion from an attorney familiar with Alaska oil and gas law before talking to buyers.
Putting It Together: How a Buyer Actually Calculates an Offer
When a mineral buyer evaluates your acreage, they're not guessing. They're pulling production data from the state commission database, looking at comparable sales in the area, checking which operator holds your lease, reviewing commodity strip prices (the market's forward estimate of future oil and gas prices), and building a model that spits out a number they're willing to pay.
The offer reflects all six factors we've covered: location, commodity type, lease status, production history, operator quality, and formation depth — plus current commodity prices, which serve as a multiplier on everything else. When oil was at $100 per barrel in 2022, offers were inflated. At $75 to $80, they're more measured. At $60, they'd be lower still.
Here's a practical example. Say you own 20 net mineral acres in Grady County, Oklahoma. Your acreage is leased to a mid-size SCOOP operator at a 20% royalty. There's one producing well that's been online for 18 months and paying you about $900 per month, declining slowly. Your royalty income annualizes to roughly $10,800. A buyer might apply a 4.5x multiplier to arrive at a starting value of around $48,600 — but they'd also look at the undeveloped acreage separately. If there are likely locations left to drill, that could add $2,000 to $4,000 per acre for the undeveloped portion, potentially bringing the total offer to $60,000 to $80,000 for the package.
This is an estimate. The actual number depends on the specific well data, the operator's drilling plan, and how competitive the buyer pool is. But this is how the math works.
If you've received an offer already, the most useful thing you can do is get a second one. Offers vary — sometimes significantly — based on how aggressively a buyer wants your specific acreage. If two buyers are both active in your county, you have leverage. If only one is, you don't. Knowing the difference matters.
If you'd like to understand what your minerals might be worth, reach out through this site. A real person — not an automated system — will call you back within one business day. They'll ask you a few questions about your acreage, pull the public production data, and give you an honest assessment of what the market looks like right now. There's no obligation, no pressure, and no cost to you. If the number makes sense for your situation, great. If it doesn't, you'll at least know more than you did before you called.