If you own mineral rights and you're trying to figure out what they're worth, the single most important factor — more than location, more than acreage, more than anything else — is whether those rights are currently producing oil or gas. That one distinction can mean the difference between receiving a check for $50,000 and receiving one for $500,000 for the exact same number of acres.
This article will walk you through exactly how production status affects value, why non-producing rights aren't worthless (and in some cases are worth quite a lot), and how to think about what your specific rights might be worth depending on where they're located. By the end, you'll have a realistic framework for evaluating your situation — not a vague sense that "it depends."
We'll use real numbers and real examples from states like Texas, Oklahoma, Louisiana, and others where mineral rights change hands every day. These aren't hypotheticals. They're based on how buyers actually price mineral rights in today's market.
Why Producing Rights Are Worth More — And By How Much
Producing mineral rights are rights tied to a well that is actively pulling oil or gas out of the ground and generating royalty income for you right now. A royalty is your share of the revenue from that production, paid to you monthly by the company operating the well. The standard royalty rate in most states is somewhere between 12.5% (one-eighth) and 25% of gross production revenue, though Texas and Oklahoma leases negotiated in the last decade often carry royalties of 20% to 25%.
When a buyer looks at producing mineral rights, they're essentially buying a stream of income — similar to buying a rental property that already has a paying tenant. They can look at your royalty check history, estimate how long the well will keep producing, and calculate what that income stream is worth to them today. That process is called discounted cash flow analysis, and it gives buyers a concrete number to work from.
In practical terms, producing mineral rights in a strong basin typically sell for 4 to 6 times their annual royalty income, sometimes more. If you're receiving $2,000 per month in royalties — $24,000 per year — your rights might sell for $96,000 to $144,000. In a hot play like the Permian Basin in West Texas or the SCOOP/STACK in Oklahoma, that multiple can stretch to 7 or 8 times annual income because buyers are betting on future development on adjacent acreage. In 2023 and 2024, we've seen Midland Basin mineral rights sell for 8 to 10 times annual royalty income when the acreage had active development potential.
Non-producing rights, by contrast, don't have that income history to anchor the price. That makes them harder to value — and that uncertainty gets priced in.
Non-Producing Rights Still Have Real Value — Here's Why
Non-producing mineral rights are rights where no well is currently active on your acreage. Maybe there was a well decades ago that has since been plugged and abandoned. Maybe the land was never drilled at all. Maybe you're under lease — meaning an oil company has paid you a bonus to hold the right to drill — but they haven't spudded (started drilling) a well yet.
Here's what most mineral owners don't realize: non-producing rights can still be worth significant money, and in some cases, they're worth more per acre than their producing neighbors because buyers are pricing in future upside.
The key driver is geology and location. If your non-producing acres sit above a known, productive formation — say, the Haynesville Shale in northwest Louisiana or the Marcellus Shale in Pennsylvania or West Virginia — buyers know that rock is there. They know it produces. They're willing to pay for the option that someone will drill it.
In the Haynesville play in DeSoto, Red River, and Sabine parishes in Louisiana, non-producing mineral rights in the core of the play have sold for $2,000 to $5,000 per net mineral acre in recent years, driven by the surge in natural gas demand tied to LNG export terminals on the Gulf Coast. In the DJ Basin in Colorado (Weld and Adams counties), non-producing rights in the core Niobrara/Codell window have sold for $1,500 to $3,500 per net mineral acre. These are real transactions.
In contrast, non-producing rights in a basin with no active drilling program and no near-term development prospects might fetch $50 to $200 per acre — sometimes less. Location is everything.
How Proximity to Active Drilling Changes the Price
If you own non-producing mineral rights, the most important thing you can do right now — before you talk to any buyer — is find out what's happening within a mile or two of your land.
Oil and gas development doesn't happen randomly. Companies lease up large blocks of acreage, then drill in a systematic pattern. Modern horizontal wells — the kind drilled in Texas, Oklahoma, North Dakota, and most other major states today — can extend two miles or more in a single direction. That means a well drilled on your neighbor's property might actually be pulling oil or gas from beneath your land. This is called drainage, and it's one reason mineral owners should pay attention to what's happening nearby.
More importantly, if an operator (the company running drilling operations in your area) has been actively drilling within a mile or two of your acreage, the odds that they'll get to your land go up significantly. Buyers price that probability in.
Here's a concrete example. Say you own 80 net mineral acres in McKenzie County, North Dakota — one of the most active counties in the Bakken Shale. If there are three producing wells within a half-mile of your land and the operator has permits filed for two more, a buyer might pay $4,000 to $6,000 per acre for your non-producing rights because development looks very likely in the next 12 to 36 months. The same 80 acres in a county with no recent drilling activity might bring $500 to $800 per acre.
To find out what's happening near your land, you can check your state's oil and gas commission website. Every major producing state has one:
- Texas: Railroad Commission of Texas (rrc.texas.gov)
- Oklahoma: Oklahoma Corporation Commission (occeweb.com)
- North Dakota: North Dakota Industrial Commission (dmr.nd.gov)
- Louisiana: Louisiana Department of Natural Resources (dnr.louisiana.gov)
- New Mexico: Oil Conservation Division (emnrd.nm.gov)
- Colorado: Colorado Oil and Gas Conservation Commission (cogcc.colorado.gov)
You can search by county and section-township-range (the legal land description on your deed) to see nearby well activity. It takes some patience, but it's worth doing before you talk to anyone about selling.
The Lease Bonus vs. Royalty Income Distinction Matters When Selling
Some mineral owners confuse lease bonus payments with royalty income. Understanding the difference matters when you're thinking about value.
A lease bonus is a one-time payment you receive when you sign an oil and gas lease — it's essentially the company paying for the right to drill on your land for a set period (usually 3 to 5 years). A typical lease bonus in an active area might run $500 to $3,000 per acre. You get that money whether or not they ever drill a well. If they don't drill, the lease expires and you can lease again.
Royalty income is what you receive monthly once a well is producing. It comes off the top of gross revenue (before the company deducts operating costs, in most states, though some leases allow post-production deductions — a detail worth knowing before you sign anything).
When you sell your mineral rights, you're selling both: the right to receive future lease bonuses and the right to receive future royalty income. Buyers care most about the royalty income potential, but active lease status — especially if you're currently under lease with a large operator — can increase your sale price because it signals that a real company has already made a financial bet on your acreage.
If you're under lease right now in a place like the Eagle Ford Shale in South Texas (Karnes, DeWitt, or La Salle counties), that lease itself is a signal to buyers. The bonus you already received was likely $1,000 to $2,500 per acre for core acreage, and the fact that a company paid that means they believe in the geology. That context can support a higher asking price.
State-by-State Realities: Where You Stand Matters
Mineral rights values are highly local. Here's an honest look at where different states stand right now, with rough value ranges for non-producing rights in active areas versus quieter ones.
Texas remains the highest-value state overall. Permian Basin (Midland and Delaware sub-basins) non-producing rights in Loving, Reeves, or Lea County (New Mexico side) can bring $5,000 to $15,000 per acre in the core. Eagle Ford non-producing acreage in the oil window runs $1,500 to $4,000 per acre. Outside active plays, you might see $100 to $500 per acre.
Oklahoma has seen a resurgence in the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher counties) plays. Non-producing rights in Kingfisher or Canadian County core areas have sold for $1,500 to $3,500 per acre. Eastern Oklahoma and the Panhandle are much more modest — often $200 to $800 per acre.
Louisiana is driven by the Haynesville right now because of LNG demand. Non-producing rights in the core Haynesville counties (DeSoto, Sabine, Red River) have been brisk. Outside the Haynesville, Tuscaloosa Marine Shale acreage in south Louisiana is emerging but slower to develop — values are lower and more speculative.
North Dakota Bakken rights in McKenzie, Williams, Mountrail, and Dunn counties remain strong. Non-producing acreage in those core counties brings $3,000 to $7,000 per acre. Eastern North Dakota or non-Bakken areas are much lower.
West Virginia and Pennsylvania (Marcellus/Utica Shale): Values depend heavily on whether you're in the wet gas or dry gas window and proximity to pipeline infrastructure. Core Marcellus acreage in West Virginia's northern counties (Doddridge, Wetzel, Tyler) can bring $1,500 to $3,000 per acre non-producing. Dry gas areas in Pennsylvania (Susquehanna, Bradford counties) are lower right now because natural gas prices have been softer.
Wyoming (Powder River Basin, Pinedale Anticline): Active development continues. Non-producing rights in Campbell or Converse County can bring $500 to $2,500 per acre depending on target formation.
New Mexico (Permian Basin, San Juan Basin): Southeast New Mexico Permian rights mirror Texas Permian values closely — $4,000 to $12,000 per acre in the core. San Juan Basin is more modest.
Colorado, Montana, Kansas, Ohio, Mississippi, Alabama, Arkansas, Alaska, Utah, California: These states range widely. Colorado DJ Basin is strong in the core. Montana Bakken margins are active. Kansas has legacy conventional production that still trades. California, Utah, and Alaska have unique regulatory and logistical factors that affect value. If you're in one of these states, a serious buyer should be able to give you specific comparable transactions.
One note on taxes: when you sell mineral rights, the proceeds are generally taxed as capital gains at the federal level. Long-term capital gains rates (for rights held more than a year) are 0%, 15%, or 20% depending on your income. Some states — including California, Colorado, and West Virginia — have their own capital gains or income taxes that apply. Texas, Wyoming, and several other states have no state income tax. Talk to a tax professional before you sell, especially if the sale proceeds would push you into a higher bracket.
How to Think About Timing: Should You Sell Now or Wait?
This is the question most mineral owners struggle with, and there's a real answer — not a vague one.
If your rights are currently producing, the best time to sell is when commodity prices (oil and gas prices) are relatively high and when drilling activity near your land is active. Both of those conditions are currently met in most major basins as of mid-2025. Oil is trading in a range that makes Permian, Bakken, and Eagle Ford economics work well. Natural gas prices have recovered from their 2023 lows, making Haynesville and Marcellus economics better.
If your rights are non-producing, timing matters differently. The best time to sell non-producing rights is when a buyer can see active development nearby — permits filed, rigs working, pipelines being laid. That activity tells them their money won't sit idle for years. If drilling activity near your land has slowed or stopped, you may want to wait for the next drilling cycle rather than sell at a low point.
Here's a practical guideline: if you've received a lease offer in the last 12 months, that's a signal that an operator believes your land has near-term value. That's a reasonable time to at least get a sale offer and compare it to what you'd earn from the lease bonus plus potential future royalties. A buyer should be able to model that comparison for you.
One thing to avoid: accepting the first offer you receive without getting at least two or three competing bids. Mineral buyers are not all offering the same price. We've seen cases where a mineral owner in Kingfisher County, Oklahoma received an initial offer of $1,800 per acre and, after getting competing bids, sold for $2,600 per acre. That difference on 100 acres is $80,000.
What Happens When You Reach Out to Us
If you'd like to understand what your mineral rights are worth — whether they're producing or not — here's exactly what happens when you contact us.
A real person, not an automated system, will call you back within one business day. That person has worked in mineral rights acquisitions and can speak specifically to your state and county. The first conversation is entirely informational — we'll ask about your acreage, your current production status if any, and your deed information, and we'll give you a realistic range of what rights like yours have sold for recently. There's no pressure to sell and no commitment required.
If you decide you want a formal offer, we'll prepare one based on current market data and send it to you in writing. You can take it to an attorney, compare it against other offers, or simply keep it on file. Whatever you decide, you'll leave that conversation knowing more about your mineral rights than when you started. That's a good outcome regardless of what you choose to do next.
To get started, fill out the contact form on this page or call us directly. Have your deed or any lease paperwork handy if you can find it — it helps us give you a more specific answer faster. If you don't have it, we can often find the information through public records.