If you've inherited mineral rights or received a division order in the mail, you've probably seen terms like "net revenue interest" and "working interest" and wondered what they actually mean for your situation. These aren't just technical labels — they determine how much money you receive, whether you're on the hook for any costs, and how much your interest is worth if you decide to sell.
By the end of this article, you'll understand the difference between the two, why mineral owners almost always hold one type and not the other, and how these distinctions affect real decisions — like whether to sign a lease, how to read your royalty check, or what to expect if a buyer makes you an offer.
This isn't a law school lecture. It's a practical explanation written for someone who owns rights but didn't spend a career in the oil patch.
What Net Revenue Interest Actually Means
Net Revenue Interest (NRI) is the percentage of revenue from a well that flows to you — after deducting the royalty obligations owed to others, but before deducting operating costs. In plain terms: it's your share of the money that comes out of the ground, without you having to pay for drilling or pumping.
Here's a simple example. Suppose an oil well in the Permian Basin in West Texas produces $100,000 worth of oil in a month. If you hold a 3.125% net revenue interest, your check before taxes is $3,125. You didn't pay a dollar to drill that well, and you won't pay for the pump jacks, saltwater disposal, or the crew maintaining the equipment. That's what makes an NRI attractive — it's a revenue share, not a business partnership.
Where does that percentage come from? It's calculated from two things: how much of the mineral acreage you own, and what royalty rate was negotiated when the land was leased to an operator. If you own 50% of the minerals under a 640-acre section, and the lease carries a 25% royalty, your NRI would be 50% × 25% = 12.5%. That fraction gets further divided if the well drains multiple tracts, which is common in Oklahoma's horizontal well units and Louisiana's Haynesville Shale.
One thing to watch carefully: some leases allow operators to deduct post-production costs — things like compression, transportation, and processing — before calculating your payment. In Pennsylvania's Marcellus Shale and West Virginia, these deductions have been a major source of disputes. In Texas, whether deductions are allowed depends heavily on the specific lease language. If you're reviewing a lease right now, the royalty clause and the deduction language are the two paragraphs that matter most.
What Working Interest Means — and Why It's a Different Animal
Working Interest (WI) is the ownership stake in the actual drilling and operation of a well. If you hold a working interest, you share in the revenue — but you also share in the costs. Drilling costs, completion costs, monthly operating expenses, plugging costs when the well reaches the end of its life. All of it, proportional to your ownership percentage.
In North Dakota's Bakken Shale, drilling a single horizontal well can cost $8 million to $12 million. If you hold a 25% working interest, you're responsible for $2 to $3 million of that before you see a dollar of production revenue. That's the fundamental difference: working interest owners take on financial risk. NRI holders do not.
Working interest owners typically receive a larger percentage of gross revenue to compensate for that risk. On a well with a 25% royalty burden, the working interest owners collectively receive 75% of revenue — but they also pay 100% of the costs. The net revenue interest to a working interest owner is their working interest percentage multiplied by the "net revenue interest factor" (1 minus the total royalty burden). A 50% working interest in a well with a 25% royalty burden yields a net revenue interest of 37.5% — but after operating costs, the actual profit margin can be thin, especially on older wells.
Working interests are common among oil and gas companies, small independent operators, and investors who participate in drilling deals. They're sometimes sold in "working interest programs" marketed to investors. Occasionally, a landowner ends up with a working interest through what's called a "non-participating royalty interest" conversion or through a retained working interest clause in an old deed — something that happens more often than people realize in Oklahoma and Kansas, where mineral ownership chains go back over a century.
If you've inherited mineral rights and aren't sure whether you hold a royalty interest, a working interest, or something else, the deed language and any existing lease are the documents to look at first. A title attorney in your state can clarify this for a few hundred dollars — money well spent before you make any decisions.
Why Mineral Owners Typically Hold Royalty Interests, Not Working Interests
When a landowner leases their mineral rights to an oil company, the lease creates a split. The mineral owner retains a royalty interest — a guaranteed slice of revenue with no cost obligation. The operator (and anyone they bring in as a partner) holds the working interest and bears all the risk.
This structure exists for a straightforward reason: most landowners are not in the business of drilling wells. They own the resource underneath their land, but they don't have the equipment, capital, or technical expertise to extract it. The lease is essentially a deal: the operator gets the right to develop the resource, and the mineral owner gets paid a royalty for granting that right.
Royalty rates vary by state and by negotiation. In Texas, royalties of 20% to 25% are common on new leases in active plays like the Permian and Eagle Ford. In Oklahoma's SCOOP and STACK plays, 18% to 22% is typical. In Louisiana's Haynesville Shale, operators have paid 25% royalties on prime acreage. In Colorado, following the passage of SB 181 in 2019, the regulatory environment changed significantly, but royalty rates themselves are still market-driven, typically 18% to 22% in the DJ Basin.
In states with older production and lower activity — Mississippi, Alabama, Arkansas — royalties on legacy leases may be as low as 12.5% (one-eighth), which was once the industry standard. If you hold rights in one of those states under an old lease at 12.5%, you may have a case for lease renegotiation if and when the lease comes up for renewal.
The key protection a royalty interest gives you: you cannot be assessed for costs. An operator cannot send you a bill. Your downside is zero production — which happens, but it's not the same as losing money you had to put in.
When Someone Might Own a Working Interest (and What to Do About It)
There are a few situations where a mineral owner ends up holding a working interest, sometimes without fully understanding it.
Retained working interest in an old deed. In some states — particularly Oklahoma, Kansas, and parts of Texas — deeds from the early and mid-twentieth century occasionally retained a fractional working interest for the grantor rather than converting it to a royalty. If your family received an interest this way, you may owe ongoing cost contributions on active wells. Check the deed language carefully.
Participating in a drilling program. Some mineral owners, especially in North Dakota and Montana where small operators approach landowners directly, are offered the chance to "go non-consent" or "participate" in a well. Participating means contributing your proportional share of drilling costs in exchange for a larger revenue share. This is a legitimate investment strategy, but it requires capital and carries real risk.
Purchasing a working interest directly. Some people buy working interests as investments. This is different from inheriting mineral rights — it's an active investment with active cost obligations.
If you hold a working interest and are receiving joint interest billings (JIBs) — monthly invoices from the operator for your share of costs — that's a sign you're in working interest territory. If those bills are arriving and you're uncertain what you agreed to or whether the charges are legitimate, an oil and gas attorney is your first call, not a buyer.
Holding an unwanted working interest can be a significant burden. In some cases, selling it makes sense even at a discount, because the alternative is ongoing cost liability on a well that may decline in production. In other cases, the interest has real value that a quick sale would undercut. The answer depends on production levels, operating costs, and remaining reserve life — not on any general rule.
How These Interests Are Valued When You're Thinking About Selling
If you're considering selling your mineral rights — whether a royalty interest or a working interest — understanding how buyers calculate value will help you negotiate from an informed position.
For royalty interests, buyers primarily look at current production and recent check stubs. If your interest is currently producing, most buyers will offer somewhere between 3 and 6 years' worth of your current annual royalty income, expressed as a lump sum. The multiplier depends on the commodity (oil vs. gas), the play, the operator's track record, and what's happening with nearby drilling activity. A royalty interest in an active Permian Basin unit with a major operator might trade at a higher multiple than the same monthly payment coming from a declining conventional field in Eastern Ohio.
For example: if you're receiving $800 per month from a West Texas royalty, that's $9,600 per year. At a 4x multiple, a buyer might offer around $38,400. At a 5x multiple, $48,000. These numbers shift based on current oil prices, how many acres you own, and whether there's undeveloped acreage that a buyer believes will be drilled in the next few years.
Undeveloped acreage — minerals you own where no wells have been drilled yet — is harder to value and is often the source of the biggest disagreements between sellers and buyers. Buyers may offer little for it; sellers often believe it's worth a great deal. The truth depends on how close the acreage is to active drilling, whether operators have been leasing in the area, and whether your acreage falls within a productive formation. In the Haynesville Shale in Louisiana, acreage values have risen sharply in recent years due to natural gas demand tied to LNG exports. In some parts of Wyoming and Utah, acreage that looked marginal five years ago has attracted serious interest from operators.
For working interests, valuation is more complex because you're essentially valuing a small business. Buyers look at production, operating costs, the operator's efficiency, reserve life, and plugging liability — the cost of abandoning the well when it's done producing. In states like California and New Mexico, plugging regulations have tightened, and the plugging liability on older wells can significantly reduce the value of a working interest.
Tax Implications You Should Know Before You Decide
This section won't replace a CPA, but it will make sure you're asking the right questions.
Royalty income is taxed as ordinary income at the federal level. If you're receiving $12,000 a year in royalties, that income is added to your adjusted gross income and taxed at your marginal rate. You're also entitled to a depletion deduction — typically 15% of gross royalty income — which reduces the taxable amount. This is one of the few real tax benefits available to mineral owners, and some people don't claim it. Make sure your tax preparer knows you own mineral rights.
Selling mineral rights typically triggers capital gains tax, not ordinary income tax. If you inherited the rights, your cost basis is "stepped up" to the fair market value at the time of inheritance — which often means a lower taxable gain when you sell. If you purchased the rights or received them in some other way, the calculation is different. Long-term capital gains rates (for assets held more than one year) are 0%, 15%, or 20% depending on your income level. For most people in their 50s and 60s who inherited rights decades ago, the stepped-up basis and long-term capital gains treatment together make selling far more tax-efficient than many people expect.
State taxes vary. Texas has no state income tax, so royalty income and sale proceeds are only taxed federally. Oklahoma taxes royalty income as ordinary income at rates up to 4.75% (as of 2024). Louisiana has a top state income tax rate of 4.25%. North Dakota's top rate is 2.5%. Pennsylvania does not tax capital gains separately — it's taxed as ordinary income at a flat 3.07%, which is actually relatively low. West Virginia taxes royalties as ordinary income at rates up to 6.5%.
If you're in a higher tax bracket and considering a large lump-sum sale, ask your CPA about installment sales, which spread the gain — and the tax — over multiple years.
Making a Decision That's Right for You
There is no universal right answer on whether to sell, hold, or lease your mineral rights. But there are better and worse ways to go about figuring it out.
If you're currently receiving royalty checks, pull the last 12 months of stubs, add them up, and understand what you're actually receiving annually. Compare that to what buyers are offering. If you're not currently producing, find out whether your acreage is under an active lease and whether there's drilling activity nearby — your state's oil and gas commission publishes this information online for Texas (Railroad Commission), Oklahoma (OCC), Louisiana (LDNR), North Dakota (NDIC), and every other producing state.
Don't sign anything — a lease, a deed of conveyance, or a division order amendment — without understanding what it says. Division orders in particular are often misread as routine paperwork, but they confirm how your interest is calculated and can affect your payments for years.
If you'd like a straightforward conversation about what your interest might be worth and what the process looks like, reach out to us. When you contact us, a real person — not a form letter, not an automated system — will call you back within one business day. There's no commitment, no pressure, and no cost. We'll ask you a few basic questions about your interest, tell you honestly what we think it might be worth, and let you decide what you want to do with that information. That's it.