Estimate Your Mineral Royalty Income

Royalty income is your share of gross production revenue — paid to you without deduction for drilling or operating costs (unless your lease contains post-production deduction clauses).

The core formula: Monthly Net Royalty = (Production/day × Wells × 30) × Price × Royalty Decimal × (1 − Tax Rate)

Your royalty decimal is the key number: it represents the exact fraction of all production value you receive. It combines your mineral ownership percentage (NMA ÷ Gross Acres) with your lease royalty rate. A royalty decimal of 0.03125 means you receive 3.125¢ of every dollar of gross well revenue.

Severance and ad valorem taxes are then deducted to arrive at your net royalty — the amount you actually receive on your royalty check.

Net Mineral Acres reflect your actual ownership in the mineral estate after accounting for fractional interests throughout the chain of title.

Example: You inherit 1/2 of your grandmother's 80-acre tract → you own 40 NMA. Even though the land surface is 80 acres, you receive royalties as if you owned only 40 acres of the minerals.

NMA is always ≤ the gross surface or spacing unit acreage. When evaluating mineral purchases, price per NMA (commonly $1,000–$15,000+/NMA in active plays like the SCOOP/STACK) is the standard valuation metric.

Your NMA is documented in your title opinion or mineral deed. If unknown, a licensed landman can calculate it from the chain of title using the Duhig Rule and other title doctrines.

Oklahoma levies a Gross Production Tax (GPT) on oil and gas at the wellhead, administered by the Oklahoma Tax Commission (OTC):

• Oil: 7% of gross value (reduced to 0.5% for first 36 months on new horizontal wells under certain conditions)
• Gas: 7% of gross value (first year exempt for new horizontal wells)

The operator deducts this from your royalty payment before issuing your check. Different states have different rates: Texas 4.6% oil / 7.5% gas; Wyoming 6% flat; North Dakota 5%; Colorado 2–5%.

This calculator applies your entered severance rate uniformly across all projection years for simplicity.

All wells decline in production over time. This tool uses exponential decline: Production in Year N = IP × (1 − Annual Decline Rate)^N−1. This applies a constant percentage decline each year.

Shale/horizontal wells in Oklahoma's SCOOP and STACK plays typically show steep early declines (40–70% Year 1) followed by a flatter "tail" phase lasting decades. A 25% annual average is a common conservative long-term assumption.

Hyperbolic decline (not used here) is more accurate for early shale performance — it applies a decreasing decline rate over time, resulting in higher near-term income. Exponential is more conservative and easier to audit.

The Oklahoma Corporation Commission (OCC) publishes well production records at wellrecords.occ.ok.gov — use actual well history to calibrate your decline assumptions.

This is an estimation tool only. Actual royalty income depends on many real-world factors not captured here:

• Post-production cost deductions (gathering, compression, processing) can reduce royalties 5–25% — depends on lease language
• Actual well decline differs from the assumed exponential model
• Commodity prices are volatile — 30%+ swings over 12 months are common
• Lease terms (including deduction clauses, shut-in provisions) vary widely
• Complex title, partial interests, and multiple operators create real-world complexity
• Shut-ins, mechanical failures, and regulatory holds affect production timing
• This tool does not account for lease bonuses, delay rentals, or income taxes

Consult a licensed landman, petroleum engineer, or oil and gas attorney before making lease, sale, or investment decisions.