If you own mineral rights in the Delaware Basin — whether in Reeves, Loving, Ward, Pecos, or Winkler County in Texas, or in Eddy or Lea County in New Mexico — you're sitting on some of the most actively drilled acreage in the United States right now. Operators are spending billions of dollars here annually, and the reason comes down to one thing: the rock is exceptionally productive and stacked with multiple pay zones, meaning a single well pad can tap into several different formations at once.
This guide is written for people who own these mineral rights and are trying to decide whether selling makes sense. You don't need an engineering degree to make a good decision, but you do need to understand what your minerals are actually worth, why buyers are willing to pay what they pay, and what the process looks like from your side of the table. By the time you finish reading, you'll know how the Bone Spring and Wolfcamp formations drive value, what a realistic price range looks like today, what questions to ask any buyer, and how taxes work in Texas and New Mexico.
We're going to be direct with you. Some mineral owners should sell. Others shouldn't. The right answer depends on your financial situation, your age, your tax picture, and how much risk you're comfortable with. We'll give you the information you need to figure that out.
What Makes the Delaware Basin Different — and Why It Matters to Your Minerals
The Delaware Basin sits in the western part of the Permian Basin, stretching across far west Texas and southeastern New Mexico. When people talk about Permian Basin production, they're usually talking about two sub-basins: the Midland Basin to the east and the Delaware Basin to the west. Both are prolific. But the Delaware has some distinct characteristics that make it especially attractive to operators — and that directly affects what your mineral rights are worth.
The most important difference is depth and thickness of pay. In the Delaware, operators are targeting multiple formations stacked on top of each other. The Bone Spring formation is actually three separate intervals — called the 1st Bone Spring, 2nd Bone Spring, and 3rd Bone Spring — each of which can be independently drilled with horizontal wells. Below the Bone Spring sits the Wolfcamp formation, which itself has multiple benches (Wolfcamp A, B, and sometimes C and D). Below that, operators are increasingly targeting the Delaware Sand and other zones. In practical terms, this means a single acre of mineral rights in a core Delaware Basin county might be drilled by eight, ten, or even twelve horizontal wells over the coming decades, each one generating royalty income.
By comparison, the Midland Basin has fewer stacked targets in most areas. That stacking is a major reason why Loving County, Texas — one of the least populated counties in the entire country — produces more oil per square mile than almost anywhere else on earth. It's also why buyers are willing to pay top dollar for Delaware Basin minerals.
Key counties to know:
- Reeves County, TX: The workhorse of the Texas Delaware, with massive acreage positions held by operators like ConocoPhillips, Permian Resources, and Coterra Energy.
- Loving County, TX: The highest-intensity drilling county in the Delaware. Very small in size but with exceptional per-acre values.
- Ward County, TX: Strong Bone Spring production with significant ongoing development.
- Pecos County, TX: Larger county with more variable quality — location within the county matters a lot here.
- Winkler County, TX: On the northeastern edge of the Delaware play, with active Bone Spring drilling.
- Eddy County, NM: New Mexico's core Delaware Basin county. Strong Bone Spring and Wolfcamp production, with major operator activity from Devon Energy, Mewbourne Oil, and others.
- Lea County, NM: Borders Eddy to the east. Good activity, though generally considered slightly less core than Eddy County.
If your deed or lease mentions any of these counties, keep reading carefully.
What Your Royalty Interest or Mineral Acres Are Actually Worth
Mineral rights buyers pay based on one primary question: how much cash flow will these minerals generate over time, discounted back to today's value? They look at existing production (if any wells are already producing on your acreage), the likelihood and timing of future drilling, the quality of the rock, and current oil and gas prices.
Here are realistic current ranges for Delaware Basin minerals, as of mid-2025:
Producing minerals (you already have royalties coming in from active wells): These are typically valued at a multiple of your monthly net revenue. In the Delaware Basin, producing minerals in core counties are trading at roughly 40 to 60 times monthly net revenue, sometimes higher if there's significant undeveloped acreage behind it. So if you're receiving $1,500 per month in royalty checks, a buyer might offer $60,000 to $90,000 or more depending on the details.
Non-producing minerals (no wells yet, but in an active area): These are priced per net mineral acre (NMA). In Loving and Reeves Counties, non-producing minerals in high-activity areas are trading at roughly $5,000 to $20,000+ per net mineral acre. In Ward and Winkler Counties, expect $2,000 to $8,000 per NMA. In Eddy County, NM, strong acreage is trading at $4,000 to $15,000+ per NMA. Pecos County is more variable — core areas can reach $3,000 to $8,000 per NMA, but outlying areas are worth significantly less.
These numbers move with oil prices. When West Texas Intermediate crude (the benchmark price for Texas oil) is above $75/barrel, buyer appetite is strong and prices push toward the high end of those ranges. Below $65/barrel, you'll see more caution and lower offers.
One thing many mineral owners don't realize: you probably own a fraction of a net mineral acre, not hundreds of acres. If your grandmother owned 1/8 of the mineral rights in a 640-acre section, you own 80 gross mineral acres — but if that interest has been divided among four heirs over two generations, your share might be 10 to 20 net mineral acres. Understanding your actual ownership fraction is the first step before you can evaluate any offer. A reputable buyer will help you calculate this clearly before making an offer. If they won't, that's a red flag.
Pipeline Takeaway and Water: The Operational Risks That Affect Your Royalties
This section gets a little technical, but it matters to your pocketbook, so stay with us.
In the Delaware Basin, two operational challenges affect how much royalty money actually reaches mineral owners: pipeline takeaway capacity and water disposal.
Takeaway capacity means the pipeline infrastructure available to move oil and gas from the wellhead to market. The Delaware Basin has seen enormous drilling activity over the past decade, and at times the pipelines have struggled to keep up. When there isn't enough pipeline capacity, operators may be forced to sell oil at a discount to the benchmark price — sometimes $5 to $10 per barrel below WTI. That discount comes directly out of your royalty check. The good news is that significant pipeline build-out has occurred in the region since 2019, and takeaway constraints are less severe today than they were in 2018-2019. But it remains a factor to watch, particularly in more remote parts of Pecos County.
Water disposal is a bigger issue in the Delaware Basin than in most other shale plays. Horizontal wells in the Bone Spring and Wolfcamp produce enormous volumes of saltwater along with the oil and gas — in some cases, ten barrels of water for every barrel of oil. That water has to be disposed of by injecting it back underground into disposal wells. The cost of water disposal can be significant, and in some lease structures, operators deduct a portion of those costs from royalty payments. If you have an existing lease, reading the cost deduction language carefully (or having an attorney read it) will tell you how much of this cost you're bearing.
For mineral rights sellers, these factors are worth understanding because a sophisticated buyer will be thinking about them when they make you an offer. If you're in an area with known takeaway or water challenges, expect offers to reflect that. It doesn't mean your minerals are worthless — it means the buyer is pricing in operational risk.
Major operators in the Delaware Basin — ConocoPhillips, Permian Resources (formerly Centennial and Colgate), Coterra Energy, Devon Energy, Mewbourne Oil, Occidental Petroleum (Oxy), and Chevron — all have substantial infrastructure investments in the region. Acreage that is held by or adjacent to these major operators generally commands better prices because the likelihood of development is higher and the infrastructure is already in place.
How Taxes Work When You Sell Mineral Rights in Texas and New Mexico
Tax treatment is one of the most important factors in deciding whether and when to sell, and it's one that many mineral owners don't think about until they've already signed something. Here's a straightforward explanation.
Federal capital gains tax: When you sell mineral rights, the proceeds are generally treated as a capital gain (not ordinary income) for federal tax purposes, as long as you've owned the minerals for more than one year. Long-term capital gains rates are 0%, 15%, or 20% depending on your total taxable income. For most mineral owners in their 50s to 70s with moderate income, the rate is 15%. High earners (over $553,850 for married filing jointly in 2024) pay 20%. There's also a 3.8% Net Investment Income Tax that applies if your income exceeds $250,000 (married filing jointly). Your accountant can help you figure out which bracket applies to you.
Your cost basis matters enormously: Your cost basis is what you paid for the minerals — or, if you inherited them, their fair market value at the time of inheritance. If you inherited minerals and the estate went through probate, the basis was "stepped up" to the value at the date of death. This is critical: if your grandmother bought minerals for $500 in 1952 and they're worth $200,000 today, and she left them to you, your basis might be close to $200,000 — meaning you could sell for $200,000 with little or no capital gains tax. Many inherited mineral owners don't realize this. Talk to a CPA before you sell.
Texas has no state income tax, so Texas mineral sellers only deal with federal taxes.
New Mexico has a state income tax with rates up to 5.9% on income above $210,000 (for married filing jointly as of 2024 rates). Capital gains in New Mexico are taxed as ordinary income at the state level — there's no preferential capital gains rate at the state level in New Mexico. This means New Mexico sellers face a higher combined tax burden than Texas sellers. For a New Mexico resident selling $300,000 in minerals, state tax alone could be $15,000 to $18,000 on top of federal obligations. Factor that into your net proceeds calculation.
1031 exchanges don't apply to mineral rights sales. We mention this because some sellers have been told they can defer taxes using a 1031 exchange (a common real estate tax deferral strategy). Mineral rights are not like-kind to real property under IRS rules, so that strategy doesn't work here. There are some structured installment sale arrangements that can spread your tax liability over multiple years — worth discussing with a CPA if you're selling a large position.
What to Expect When You Talk to a Buyer
If you reach out to a mineral rights buyer, here's what a legitimate process looks like — and what to watch out for.
A reputable buyer will ask for your basic ownership information: the county and state, a copy of your deed or a description of how you inherited the minerals, and any lease agreements you have. They'll use this to research your acreage in public records, look at nearby well activity, and build a valuation. This research typically takes a few days to a week. Then they'll present you with a written offer that shows a price per net mineral acre or a lump sum, along with how they calculated your net mineral acres. You should not be pressured to sign anything immediately.
Questions you should ask any buyer:
- How did you calculate my net mineral acres?
- What comparable sales are you using to justify this price?
- Are there any deductions from the purchase price at closing?
- Who pays closing costs?
- How long does closing typically take?
- Are you buying for your own account or brokering to another buyer?
Be cautious if a buyer pressures you to sign quickly, won't explain how they arrived at their number, or asks you to sign documents before you've had time to review them with an attorney. You are always entitled to have an attorney review any purchase and sale agreement before you sign.
Closing timelines for mineral rights sales in Texas and New Mexico typically run 30 to 60 days from signed purchase agreement to payment. Title curative work — fixing gaps or issues in the ownership chain — can extend this. If there are probate issues, missing heirs, or undivided interest complications (which are common in inherited minerals), expect 60 to 90 days or longer.
Payment is almost always a wire transfer or cashier's check at closing. Reputable buyers do not ask you to pay any fees upfront.
Making the Decision: Should You Sell?
This is the question that actually matters, and we're not going to pretend there's a universal answer. But we can give you a framework.
Selling makes sense if: You need or want liquidity now. You're worried about oil price volatility and want to lock in today's value. You have no heirs who want the minerals. Your minerals are currently non-producing and you're uncertain about the timeline for drilling. You're facing estate planning complexity and want to simplify. Or you have a large enough position that the capital gains tax hit is manageable given your overall financial picture.
Holding makes sense if: You have a strong royalty income stream you depend on. You believe oil prices will be significantly higher in 3 to 5 years. Your heirs want the minerals and would benefit from a stepped-up basis at your death. You have a small interest that would generate a minimal sale price but consistent long-term income. Or you're in a New Mexico tax situation where the combined federal and state tax burden would take a large bite out of your proceeds.
One specific scenario worth flagging: if you own non-producing minerals in a core Delaware Basin county and you have reason to believe drilling is imminent — meaning you've received a lease offer recently, or you know a well has been permitted nearby — selling before production starts means selling before the minerals are fully valued. In that case, waiting until you have a producing well and then selling the producing minerals (with the premium those command) may generate significantly more money. Royalty income for the first 12 to 18 months of a Bone Spring well in Reeves County can be substantial.
The best thing you can do right now is get a no-obligation offer and compare it to what you'd expect to earn if you held. A real number in hand is worth more than any amount of speculation.
If you'd like to find out what your Delaware Basin minerals are worth, reach out through our contact form or call us directly. A real person — not a call center — will get back to you within one business day. We'll ask you a few basic questions about your ownership, pull the public records on your acreage, and give you a written offer with a clear explanation of how we got there. No pressure, no obligation, and you're welcome to have an attorney or family member involved at any point.