If you own mineral rights in the Permian Basin — whether in West Texas or southeastern New Mexico — you're sitting on some of the most actively drilled acreage in the world right now. That's not hype. It's the reason your phone may already be ringing with offers from buyers you've never heard of.
This article will give you a straight look at what your minerals might actually be worth today, what's driving those values, how the two main parts of the Permian differ, and what the near-term outlook looks like. By the time you finish reading, you'll have enough real information to evaluate any offer that comes your way — and to know whether now is a smart time to sell, hold, or ask more questions.
One important note before we start: mineral rights are the ownership of the oil, gas, and other resources underneath a piece of land. They can be owned separately from the surface — and often are, especially with inherited property. If your family received a deed or a probate document listing "mineral rights" or "royalty interest" in Loving, Eddy, Lea, Midland, or any surrounding county, this article is written for you.
The Permian Basin Isn't One Thing — Midland vs. Delaware Sub-Basins
Most people think of the Permian Basin as one big oil field. It's actually made up of two distinct producing areas separated by a central platform, and they behave quite differently from an investor and operator standpoint.
The Midland Basin sits mostly in Texas — counties like Midland, Martin, Howard, Dawson, and Glasscock. It's known for stacked pay zones, meaning drillers can target multiple oil-bearing rock layers from a single well pad. The primary targets are the Spraberry and Wolfcamp formations. Wells here tend to be slightly shallower and have historically been a bit cheaper to drill, which makes them attractive even when oil prices dip.
The Delaware Basin covers the western side and extends significantly into New Mexico — think Reeves, Culberson, and Ward counties in Texas, and Eddy and Lea counties in New Mexico. The Delaware is geologically more complex, with deeper wells and higher drilling costs, but it often delivers exceptional initial production rates. The Bone Spring and Wolfcamp formations are the main targets here. Eddy County, New Mexico in particular has seen some of the highest-activity drilling in the entire country over the past three years.
Why this matters to you: A non-producing mineral acre in core Midland Basin territory might fetch $3,000 to $8,000 today. That same acre in a hot Delaware Basin zip code — say, southern Lea County or central Reeves County — could bring $5,000 to $15,000 or more. Producing royalty interests (minerals that are already generating monthly checks) are valued differently, typically as a multiple of your monthly income — often 4 to 6 years' worth of that income paid to you upfront as a lump sum. Location within the basin is one of the two or three biggest factors in your valuation.
What Drives Permian Mineral Values Right Now
Oil prices are the obvious starting point. West Texas Intermediate crude — the U.S. benchmark price you'll see quoted in the news — has been trading in the $70 to $85 per barrel range through much of 2024. That's a comfortable range for Permian operators. Most major companies here can turn a profit at $45 to $55 per barrel, so at current prices, drilling activity stays strong.
But oil price alone doesn't explain why Permian minerals command a premium over, say, minerals in the Anadarko Basin in Oklahoma or the Bakken in North Dakota. Here's what does:
Operator quality. The Permian is home to the biggest and most efficient oil companies in the country. ExxonMobil — after its $60 billion acquisition of Pioneer Natural Resources in 2024 — now controls a massive position in the Midland Basin. Chevron, ConocoPhillips, Occidental Petroleum, Diamondback Energy, and Devon Energy are all running active drilling programs here. These are companies with the capital and technical expertise to drill longer horizontal wells, use better completion techniques, and squeeze more production out of every acre. When a major operator holds a lease on your minerals, buyers of mineral rights take notice — it reduces risk significantly.
Inventory depth. The Permian has decades of identified drilling locations remaining. Independent reservoir studies consistently show 20 to 40 years of economic drilling inventory in core areas. That long runway makes the Permian a safer long-term bet than basins that are more drilled out.
Infrastructure. Pipelines, processing plants, and takeaway capacity have improved dramatically over the past decade. The Permian no longer has the severe bottlenecks that plagued it in 2018 and 2019, when too much gas was being flared and oil couldn't always reach market at full price. Better infrastructure means your royalties are less likely to be reduced by transportation deductions.
New Mexico specifics: Mineral owners in Eddy and Lea counties have seen particularly strong interest from buyers. New Mexico's state trust lands and the activity of operators like Coterra Energy (formerly Cimarex), Devon, and Matador Resources have kept rigs running at high levels. One thing to be aware of as a New Mexico mineral owner: New Mexico imposes a severance tax — a tax on oil and gas extracted from the ground — that operators sometimes pass through as a deduction on your royalty check. This can reduce your net income by 3 to 8 percent depending on the product and situation. A buyer will factor this in when making an offer, so it's worth understanding before you negotiate.
How Mineral Rights Are Valued — And How to Spot a Low Offer
Buyers of mineral rights are essentially investors. They're calculating how much money your minerals will produce over the next 10 to 30 years, discounting that future income back to today's dollars, and then offering you something less than that — because they need to make a return on their money.
The main variables in that calculation are:
- Whether your minerals are currently producing. If you're getting royalty checks, a buyer can look at your actual income history and project forward. If your minerals are unleased and undrilled, the valuation is more speculative and usually lower.
- Lease terms. If your minerals are under a lease, the royalty rate in that lease matters. A lease with a 25% royalty means you receive a quarter of gross production value. A 20% royalty lease on the same acreage is worth less. Standard Permian royalty rates today run 20% to 25%, though older leases sometimes have rates as low as 12.5%.
- Net mineral acres. This is the actual amount of mineral ownership you have, accounting for any prior sales or divisions in the family. If your grandmother owned 200 acres but split it four ways among her children, each child has 50 net mineral acres. Buyers pay per net mineral acre, so knowing your exact ownership is essential before any conversation.
- Proximity to active drilling. Minerals within a mile of a recently permitted or drilled horizontal well are worth far more than minerals in a part of the county where no operator has shown interest.
Low offers tend to follow a pattern. You receive an unsolicited letter with a number and a deadline. The number may be real — it's just the lowest number the buyer thinks you'll accept. Deadlines are almost always artificial. A counter-offer or request for a higher number is almost never refused outright if your acreage is genuinely valuable. If a buyer walks away the moment you ask for more, that tells you something.
The best protection is comparison. Get two or three offers before accepting any of them. If you're in Texas, you have no legal obligation to accept the first offer, no matter what language is in the letter. Same in New Mexico. You also have the right to hire a petroleum landman — a professional who works with mineral titles and leases — or a mineral rights attorney to review any purchase agreement before you sign.
The Production Growth Outlook: Why the Permian Keeps Growing
The Energy Information Administration (EIA), which is the U.S. government's energy data agency, has consistently projected the Permian Basin as the single largest source of U.S. oil production growth through at least 2030. In 2023, the Permian produced roughly 5.8 million barrels of oil per day. That's nearly half of all U.S. crude production from one basin.
ExxonMobil's Pioneer acquisition reshuffled the deck in a meaningful way. ExxonMobil has stated publicly it plans to double Permian output to roughly 2 million barrels per day on its own acreage by 2027. Chevron has made similar commitments. These are not small companies making optimistic statements — these are capital allocation decisions backed by engineering studies and board approvals. When the largest companies in the world are deploying their capital here over other basins globally, that's a meaningful signal.
For mineral owners, growing production generally means one of two things: your existing royalties increase as new wells are drilled on your acreage, or — if your minerals are currently undrilled — the probability that a well gets drilled increases over time. Either outcome is positive.
The main risk to this outlook is a sustained drop in oil prices. If WTI crude fell below $50 per barrel and stayed there, drilling activity would slow and mineral values would fall. That's happened before — 2015 and 2020 were brutal years for anyone who sold at the bottom. Most industry analysts don't see a prolonged sub-$50 environment as likely in the near term, given global demand trends and OPEC production management, but it is a real risk worth keeping in mind if you're deciding whether to sell now or wait.
Natural gas is a secondary consideration for most Permian mineral owners, but it matters. Associated gas — gas that comes up with the oil — is a significant byproduct of Permian production. LNG export capacity from the Gulf Coast is expanding, which should support gas prices over the next several years. If you own minerals in a gassier part of the play, like parts of Reeves County, this is relevant to your valuation.
Texas vs. New Mexico: What Mineral Owners in Each State Should Know
Owning minerals in Texas and owning them in New Mexico are similar in many ways but different in a few important ones.
Texas has no state income tax, which is straightforward. Royalty income you receive is subject to federal income tax as ordinary income — the same rate as your wages or pension. Texas does have an oil production tax of 4.6% and a gas production tax of 7.5%, which operators typically pass through as deductions on your royalty statement. Texas mineral rights can be sold with relatively clean title processes, and the state's long history with oil and gas means title companies and attorneys are well-versed in these transactions.
New Mexico has a state income tax that applies to royalty income. The top marginal rate is 5.9% for income above $210,000 (for married filers in 2024), with lower rates for smaller income levels. Additionally, New Mexico's Oil and Gas Severance Tax, Ad Valorem Production Tax, and Conservation Tax can combine to reduce your effective royalty income by 6 to 10 percent compared to what you'd see on paper. If you're a New Mexico mineral owner receiving royalty checks, look carefully at the deduction lines on your check detail — you may be seeing these taken out already. When evaluating a sale offer, the lump sum you receive is not subject to these ongoing deductions, which is one reason some owners prefer selling.
One important legal note for both states: if you inherited your minerals, the ownership may not be clearly documented in your name yet. This is more common than people realize. Before you can sell, the title to your minerals generally needs to reflect current ownership. An attorney familiar with oil and gas estates can help you establish or confirm your title, and the cost is usually modest relative to what the minerals are worth.
Is Now a Good Time to Sell Permian Mineral Rights?
This is the question most people reading this actually want answered. Here is an honest take.
The market for Permian mineral rights is active and well-funded right now. Private equity firms, publicly traded mineral companies like Viper Energy (a Diamondback subsidiary), and individual investors are all competing to acquire acreage. That competition is generally good for sellers — it keeps offers honest and gives you leverage to negotiate.
If you need liquidity, have a specific use for the capital, or simply don't want the administrative burden of managing royalty income and dealing with lease paperwork, selling makes sense in this environment. You're not selling at the bottom. You're selling in a period of strong operator activity, reasonable oil prices, and high buyer demand.
If your minerals are currently producing and your checks are growing — because a new well was recently drilled or an operator has permitted additional locations — waiting six to twelve months to see how production performs can significantly increase what a buyer will pay. Buyers pay more for a proven, growing income stream than for potential.
If you're on the fence, the most useful thing you can do is get a current valuation — not from one buyer, but from two or three independent sources. That gives you a real number to work with and takes the guesswork out of the decision.
If you'd like to talk through your specific situation, reach out through this site. A real person — not an automated system — will call you back within one business day. There is no obligation to sell, no pressure, and no cost for the conversation. Come with your county name, your approximate acreage, and any recent royalty statements you have on hand, and you'll get a straight answer about what your minerals are likely worth in today's market.