What net revenue interest is and where the number comes from
Net revenue interest is the decimal fraction of a well's revenue that belongs to you. It is the number printed on your division order, usually to eight decimal places, and every dollar you ever receive from that well is gross revenue multiplied by it.
It is built from three factors. First, your share of the unit: net mineral acres divided by unit acres. If you own 40 net mineral acres in a 640-acre section, you own 0.0625 of the unit. Second, your lease royalty rate: the fraction the lease reserves to you rather than to the operator, historically 1/8 and now more often 3/16, 1/5 or 1/4. Third, a participation factor, which is 100% for most units but applies where the pooling order allocates on productive acres or lateral length rather than surface acreage.
Multiply the three and you have the NRI. A 40-acre interest in a 640-acre unit at 3/16 gives 0.0625 × 0.1875 = 0.01171875. That is a little over one percent of the well, and it is a large interest by mineral-owner standards.
Note carefully what net mineral acres means, because it is where most errors start. It is not the size of the surface tract. If you own an undivided one-quarter of the minerals under a 160-acre tract, you own 40 net mineral acres, not 160. Division order analysts calculate this from the chain of title, and a mismatch between your figure and theirs almost always traces to a fractional interest somewhere in the deed history.
Turning the interest into a check
Start with gross well revenue: oil barrels times the realised oil price, plus gas Mcf times the realised gas price, plus NGL barrels times the NGL price. Realised means what the operator actually received at the point of sale, after quality and transport differentials — a crude with a low API gravity sells below the benchmark, and gas sold into a constrained basin sells below the hub.
Multiply by your NRI to get your gross share. Then two things come off.
Post-production deductions are the costs of getting the product from the wellhead to a marketable condition and location: gathering, compression, dehydration, treating, processing and marketing. Whether they may be charged against a royalty owner's share is a matter of lease language and of state law, and the two regimes differ sharply. Some states follow a marketable-product rule that requires the lessee to bear the cost of making the product marketable; others allow deductions unless the lease forbids them. This is the single most litigated line on a royalty statement.
Severance or production tax is a state tax on the value of hydrocarbons removed from the ground. Rates differ by state, by product and sometimes by well type, and many states offer reduced rates for stripper wells, enhanced recovery or new horizontal completions. It is normally computed on the taxable value of your share after allowable deductions, which is the order this calculator uses.
What is not deducted matters just as much. A royalty interest bears no drilling cost, no completion cost and no lease operating expense — that is the defining difference from a working interest. If your statement shows operating costs charged against your share, either you hold a working interest rather than a royalty, or something is wrong.
Worked example: 40 net acres in a 640-acre unit at 3/16
You own 40 net mineral acres in a 640-acre unit, leased at a 3/16 royalty with no special allocation. For the production month, the well made 3,000 bbl of oil at $72.00, 12,000 Mcf of gas at $2.85 and 400 bbl of NGL at $22.00. The lease permits post-production deductions, which run 12%, and the state severance rate is 5%.
- Share of the unit. 40 ÷ 640 = 0.0625.
- Net revenue interest. 0.0625 × 0.1875 = 0.01171875.
- Gross well revenue. Oil 3,000 × 72 = $216,000. Gas 12,000 × 2.85 = $34,200. NGL 400 × 22 = $8,800. Total $259,000.
- Your gross share. 259,000 × 0.01171875 = $3,034.69.
- Post-production deductions. 12% of 3,034.6875 = $364.16, leaving a taxable value of $2,670.53.
- Severance tax. 5% of 2,670.525 = $133.53.
- Net check. 2,670.525 − 133.526 = $2,537.00.
- Annualised. 2,536.99875 × 12 = $30,443.99, if volumes and prices held flat for a year.
Two sanity checks are worth doing every time. First, your share of the oil volume should be 3,000 × 0.01171875 = 35.15625 bbl, and your statement should show that number beside the oil line. If it shows a different volume, the disagreement is in the interest, not in the price. Second, deductions and tax together took 1 − 2,536.99875 ÷ 3,034.6875 = 16.40% of your gross share, so you received about 83.6 cents of every gross dollar attributable to your interest. Track that percentage month to month; a sudden move in it usually means a change in how the operator is allocating post-production costs, not a change in the well.
Notice the leverage in the arithmetic. A $10 move in the oil price changes gross revenue by 3,000 × 10 = $30,000 and your net check by 30,000 × 0.01171875 × 0.88 × 0.95 = $293.90. Price moves flow straight through, undamped, in exactly that proportion.
Reconciling this against your actual check stub
Work down the statement in the same order. The interest decimal should match your NRI exactly — if it does not, the dispute is about title or unit acreage and no amount of price checking will resolve it. Then confirm your volume share against gross well volumes, which most state regulators publish; that comparison catches allocation errors that a revenue-only check cannot.
Next look at the deduction line as a percentage of your gross share rather than as a dollar amount. Dollars move with price and volume; the percentage should be relatively stable, and a step change in it is the signal worth chasing. Gas is where deductions bite hardest, because the path from wellhead to sales meter is longer and more expensive than for oil.
Expect the check to fall over time. A shale well typically declines steeply in its first two years before flattening, so a first-year royalty is a poor guide to a tenth-year one. Do not annualise a strong month and treat the result as income; the calculator's annualised figure assumes flat volumes and prices precisely so that you can see how unrealistic that assumption is.
Finally, treat the tax line as an estimate. Severance rates vary by state, by product and by well category, and exemptions for low-producing or newly completed wells are common. The rate on your statement is the authoritative one; the rate you enter here is your model of it.
Net revenue interest by acreage share and lease royalty
| Lease royalty | 10 of 640 acres (0.015625) | 20 of 640 (0.03125) | 40 of 640 (0.0625) | 80 of 640 (0.125) | 160 of 640 (0.25) |
|---|---|---|---|---|---|
| 1/8 (12.5%) | 0.00195313 | 0.00390625 | 0.00781250 | 0.01562500 | 0.03125000 |
| 3/16 (18.75%) | 0.00292969 | 0.00585938 | 0.01171875 | 0.02343750 | 0.04687500 |
| 1/5 (20%) | 0.00312500 | 0.00625000 | 0.01250000 | 0.02500000 | 0.05000000 |
| 1/4 (25%) | 0.00390625 | 0.00781250 | 0.01562500 | 0.03125000 | 0.06250000 |
| 3/8 (37.5%) | 0.00585938 | 0.01171875 | 0.02343750 | 0.04687500 | 0.09375000 |
Every cell is the acreage decimal in the column heading multiplied by the royalty rate in the row, rounded to eight decimal places — the same precision a division order uses.
Mistakes that make a royalty estimate wrong
- Using gross tract acres instead of net mineral acres. An undivided quarter interest under 160 acres is 40 net mineral acres. Getting this wrong scales the whole answer by the fractional interest.
- Using the wrong unit size. Horizontal units are frequently 640 or 1,280 acres and are set by the pooling order, not by the section lines. Read the unit designation.
- Confusing royalty interest with working interest. A royalty bears no drilling or operating cost; a working interest bears its share of everything.
- Applying benchmark prices. Realised wellhead prices sit below benchmark quotes by the quality and transport differential, and for gas the gap can be large.
- Mixing Mcf and MMBtu. Gas statements sometimes price per MMBtu and report volume in Mcf. For rich gas the two differ by more than ten percent.
- Assuming deductions are allowed. Whether post-production costs may be charged to a royalty owner depends on the lease and on state law, and it is the most contested line on the statement.
- Annualising a single month. New wells decline steeply, so twelve times a first-year month overstates the following year materially.
This is an estimate, not tax or legal advice
Royalty ownership carries real legal and tax consequences that this calculator does not model: depletion allowance, state and federal income tax withholding on non-resident owners, suspense accounts where title is unclear, and the interplay between lease language and state marketable-product doctrine. The figures here are for checking an operator's arithmetic and for planning. Before you act on a division order, a lease amendment or a sale of minerals, take the documents to an oil and gas attorney and a CPA who works with mineral owners.
Where the monthly check fits into the value of the minerals
A single month's check is a snapshot. What a mineral interest is worth is the present value of every future check, and getting from one to the other requires two things this calculator does not do: a decline forecast and a discount rate.
The decline forecast matters more than most owners expect. Unconventional wells fall steeply in the first eighteen to twenty-four months and then flatten into a long, shallow tail, so the shape of the curve — not just its starting point — determines most of the value. Once you have a monthly forecast, discounting it is standard finance: the net present value calculator turns a stream of expected checks into a value today, and the internal rate of return calculator tells you what return an offered purchase price implies.
Price assumptions deserve as much care as volume ones. The oil price sensitivity chart above shows the pass-through is linear and undamped, which cuts both ways: your check rises and falls in exact proportion to the realised price, and the realised price depends on crude quality as well as on the benchmark. The API gravity calculator covers the gravity adjustment that sits behind many crude purchase contracts.
If you sell, remember the tax side. Mineral sale proceeds are generally treated as a disposition of a capital asset, and the calculation of gain depends on your basis — see the capital gains tax calculator for the general mechanics, and take the specific treatment to a CPA. Royalty income itself is ordinary income, reported on a 1099-MISC, and is eligible for the percentage depletion deduction in most cases.