How is oil and gas royalty income calculated?

Royalty income = (daily production × wells × 365 days) × price per unit × your royalty decimal × (1 − tax rate). Your royalty decimal is (net mineral acres ÷ spacing unit acres) × your lease royalty rate. Severance and ad valorem taxes are deducted by the operator before your check is issued.

What are net mineral acres (NMA)?

Net mineral acres reflect your actual ownership in the mineral estate after accounting for fractional interests. If you inherit half of an 80-acre tract's minerals, you own 40 NMA. NMA is the standard unit for valuing and trading mineral interests — active Oklahoma plays commonly trade between $1,000 and $15,000+ per NMA.

What is a royalty decimal?

Your royalty decimal is your precise fractional share of a well's production value: (net mineral acres ÷ gross acres in the spacing unit) × your lease royalty rate. It appears on your division order. For example, 80 NMA in a 640-acre unit with a 3/16 royalty = 0.0234375.

What is the Oklahoma severance tax rate on oil and gas?

Oklahoma's gross production tax is 5% for a well's first 36 months of production, then 7% thereafter (HB 1010xx, 2018). The operator deducts this from royalty payments before issuing your check. Stripper wells and certain enhanced recovery projects may qualify for reduced rates.

What is a fair royalty rate in Oklahoma?

In active Oklahoma plays (2024–2025): 1/8 (12.5%) is the statutory minimum and generally below market; 3/16 (18.75%) is common but increasingly below market in the SCOOP/STACK; 1/5 (20%) is the emerging standard in competitive areas; 1/4 (25%) is a strong rate achievable where multiple operators compete for acreage.

Should I take a lease bonus or wait for royalties?

A lease bonus is a one-time payment per net mineral acre; royalties pay for the life of production. Compare the bonus to projected royalty income over the lease's primary term — if a well is drilled, royalty income from a single horizontal well usually exceeds a typical bonus within the first year or two. If no well is ever drilled, the bonus is all you receive.

Free · Oklahoma SCOOP/STACK · Works anywhere in the US

Know What Your Minerals Are Worth — Before You Sign Anything

Model royalty income, evaluate lease offers, and understand your mineral rights value in minutes. Built for Oklahoma mineral owners and the professionals who work with them.

Run Your Estimate ↓

About

Royalty income math
shouldn't be a black box

When a landman calls with a lease offer, most mineral owners have no quick way to evaluate it. The bonus sounds like a real number — but is it good? What would the royalty actually be worth over the life of a well? Most people sign without knowing, because the math has always lived inside an operator's spreadsheet.

MineralCalc puts that math in your hands. Enter your acreage and lease terms, and the tool builds a full income model: projected monthly royalty income, a year-by-year decline schedule, a sensitivity table across price and royalty scenarios, and a direct comparison between the bonus offer and long-term production value.

Built for Oklahoma mineral owners, landmen, and O&G professionals — the math works the same anywhere in the US. Every formula is visible, every assumption is adjustable, and every calculation is yours to share.

Not a substitute for a licensed landman, petroleum engineer, or O&G attorney — but a solid foundation for better conversations and better decisions.

Creator

Alex Gerardi

Energy Management — University of Oklahoma
Land & Mineral Acquisitions

MineralCalc started from a gap I saw working in Oklahoma land and mineral acquisition — mineral owners don't have access to the same modeling tools that operators and buyers use every day. My energy management background at OU and hands-on experience on the acquisition side of the business shaped how it's built: accurate decline math, real market context, and a clean interface anyone can use. It's free because information asymmetry in mineral rights already favors the operator enough.

Creator Portfolio ↗ LinkedIn ↗ alexogerardi@gmail.com

What this tool covers

Net royalty income with exponential decline curves
NPV — net present value of your full royalty stream
Severance and ad valorem tax deductions
Post-production deduction modeling
Price scenario sensitivity (bear / base / bull)
Royalty rate comparison across 1/8 – 1/4
Lease bonus vs. long-term royalty analysis
Shareable URLs and professional PDF export
Coming Soon Lease PDF Analyzer — upload your lease for instant plain-English term analysis →

MineralCalc — Royalty Income Estimate

Generated · mineralcalc · For estimation purposes only. Not financial or legal advice.

Royalty Estimator

Income Calculator

📄 Have a lease? Upload it and skip the manual entry — Coming Soon

Report Name / Tract Description (optional — appears in PDF header)

Try an example:

Mineral Interest

Gross Acres / Spacing Unit Size

Total acreage of the drilling unit your minerals fall within. Most Oklahoma horizontal wells use 640-acre units. This is the denominator in your royalty decimal.How do I find this? →

Must be a positive number.

Net Mineral Acres (NMA)

Your actual owned mineral acres after accounting for fractional interests in the chain of title. Must be ≤ gross acres. Example: you own 1/2 of an 80-acre tract = 40 NMA.What is NMA? →

NMA must be > 0 and ≤ gross acres.

Royalty Rate

Fraction of gross production you receive cost-free under your lease. Common: 1/8 (older), 3/16–1/5 (standard), 1/4 (premium). Negotiated at lease signing.

Enter a value between 0.01 and 99.99.

Royalty rates in Oklahoma vary by play, operator, and how much competition exists for your acreage.

General benchmarks for active Oklahoma plays (2024–2025):

1/8 (12.5%) — Minimum statutory rate. Common in older leases and low-activity areas. Generally considered unfavorable for mineral owners in active plays.
3/16 (18.75%) — Previously standard. Still common but increasingly considered below market in the SCOOP/STACK.
1/5 (20%) — Emerging standard in competitive areas.
1/4 (25%) — Strong rate. Achievable in active plays with multiple operators competing for acreage.
3/8 (37.5%) or higher — Rare. Typically only in extremely competitive leasing situations or for large acreage positions with significant negotiating leverage.

Rule of thumb: if an operator is actively leasing your area, you likely have negotiating power. The difference between 1/8 and 1/4 royalty on a single well can be worth tens of thousands of dollars over the life of production.

Consult a licensed landman or oil and gas attorney before signing any lease.

Number of Producing Wells

Active wells producing from your mineral acreage. Enter 1 if unknown — most Oklahoma horizontal units start with a single well. Each additional well multiplies your income proportionally.How do I find this? →

Enter 1–20 wells.

Production

Commodity

Oil is measured in barrels (BBL). Natural gas in thousand cubic feet (MCF). Select based on your well's primary product.

Estimated Production per Well

Initial daily production rate (IP) when the well first comes online. Oklahoma SCOOP/STACK horizontals typically start 500–1,500 BOE/day. This is your starting rate — all production declines from here.How do I find this? →

Must be a positive number.

Production Decline Rate (Annual)

Annual rate at which production decreases. Shale wells decline 40–70% in Year 1, then flatten to 10–25%/yr. Use the calculator tabs below or enter manually.How does decline work? →

25%

Method

IP Rate BOE/day

Prod. at 12 Months BOE/day

Decline rates for Oklahoma SCOOP/STACK horizontal wells typically range from 40–70% in Year 1, flattening to 15–25% in later years. This calculator uses exponential decline — actual wells often follow hyperbolic decline in early years.

Month Prod. BOE/day Month Prod. BOE/day

Month 1

Month 4

Month 2

Month 5

Month 3

Month 6

Enter at least 2 months of production data to calculate decline rate.

Years to Model

Projection horizon in years. Most royalty valuations use 10–20 years. Wells can produce 30+ years at reduced rates — longer models capture tail production value.

10 yrs

Discount Rate (for NPV)

Rate used to discount future royalty income to present-day value. Mineral buyers typically use 10–15%. Higher rate = lower NPV.What is NPV? →

10%

NPV discounts your full royalty stream to present value — how mineral buyers price acquisitions.

Price & Taxes

Current Commodity Price

Base price per unit. Oil: $/BBL (WTI spot, typically $65–90). Gas: $/MCF (Henry Hub, typically $2–4). Your actual realized price may vary from the posted benchmark.

Live Prices ↗

Must be a positive number.

Price Scenario

Adjust the base price by a scenario multiplier for stress testing. Bear = pessimistic, Bull = optimistic. Custom lets you enter any effective price directly.

Producing State

Select your state to auto-fill the correct severance tax rate. Rates shown are standard statutory rates — verify with your state tax authority as exemptions and incentives may apply.

View sources ↗

Selecting a state auto-fills the severance rate below — you can still edit it manually.

Severance Tax Rate (%) auto-filled

State tax on production at the wellhead. Deducted by the operator before your check is issued. Exemptions for new horizontal wells may reduce your effective rate.Rates by state & exemptions →

New well — 5% for first 36 months, then 7% (HB 1010xx, 2018)

Years 1–3 of the projection are taxed at 5%; years 4+ at 7%. Uncheck for wells already past 36 months of production.

Exemptions for stripper wells and enhanced recovery may further reduce your effective rate.

Ad Valorem Tax Rate (%)

County property tax on production value. Oklahoma averages ~0.5% of gross. Varies by county and state. Often deducted from royalty by the operator before you receive payment.

Post-Production Deductions (gathering, compression, processing)

Some leases allow operators to deduct gathering, compression, and processing costs before calculating your royalty — reducing your check by 5–25%. Depends entirely on your lease language.What to look for in your lease →

Deduction Rate

15%

National average is approximately 10–20% depending on lease language and location.

Live Results LIVE

⚠ Post-production deductions applied — check your lease language.

Monthly Royalty Income (Net)

—

Year 1 peak rate, after all taxes — declines each year

Annual Income (Year 1 Peak)

—

Before decline

10-Year Cumulative

—

Avg Annual Income (w/ Decline)

—

Decline-adjusted average

NPV (10% discount)

—

Present value of royalty stream

Royalty Decimal—

Net Revenue Interest (NRI)—

Effective Price Used—

Monthly Gross Revenue (Well)—

Monthly Gross Royalty—

Effective Tax Rate—

Estimated Mineral Value if Sold

—

Market shorthand: 3×–5× Year 1 annual income. For a discount-rate valuation, see NPV above.

Enter values above to see the live formula.

Received a royalty check? Enter the amount to verify your decimal matches your lease terms. Uses all inputs from the calculator above — make sure the price matches your check stub.

My royalty check was $ this month

Scenario Analysis

Sensitivity Tables

Price vs. Royalty Rate — Annual Net Royalty Income

Rows: price ± your entered base | Columns: royalty fractions | Amber border = your current inputs

Year-by-Year Production Decline Schedule

Exponential decline model based on your inputs. All figures in net royalty dollars after taxes.

Year	Daily Production	Gross Royalty	Net Royalty	Cumulative Net	Income Bar

Annual Net Royalty — Year by Year

Decision Tool

Lease Bonus Comparison

If a landman offers you a cash bonus to sign a lease, how does it stack up against keeping your minerals unleased and waiting for royalty income? Enter the offered bonus below — the comparison updates automatically using your royalty inputs above.

Bonus Offer

Offered Bonus ($/NMA)

One-time upfront cash payment per net mineral acre for signing an O&G lease. Current market in active OK plays: $500–$5,000+/NMA. Varies by county, operator, and acreage position.

Lease Primary Term (Years)

How long the operator has to begin drilling before the lease expires (no production = lease terminates). Typical: 3–5 years in active plays. Shorter term = more favorable to mineral owner.

Using 40 NMA and 1/8 royalty from the calculator above. Adjust those fields to update this comparison.

Bonus vs. Hold Analysis LIVE

Total Bonus Check

—

Equivalent royalty months (Yr 1 rate)—

Equivalent royalty years (Yr 1 rate)—

Bonus as % of 10-yr projected income—

Annual royalty income per NMA—

Royalty income during primary term—

Total package — bonus + 10-yr royalty—

Enter a bonus offer to see the comparison.

Glossary & Methodology

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 × 365 days) × Price × Royalty Decimal × (1 − Tax Rate) ÷ 12 months

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). The current structure was set by HB 1010xx (2018):

• New wells: 5% of gross value for the first 36 months of production
• After 36 months: 7% of gross value for the remaining life of the well

Before 2018, the incentive rate for new wells was 2% (and 1% before 2015) — the legislature raised it to 5% to fund teacher pay raises. Stripper wells and certain enhanced recovery projects may qualify for lower rates.

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 ~10% combined; Colorado 2–5%.

When Oklahoma is selected with the "new well" option checked, this calculator applies the tiered structure automatically: years 1–3 of the projection at 5%, years 4+ at 7%. For other states, your entered rate is applied uniformly across all years.

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.

Your monthly royalty check comes with a detail stub (sometimes called a revenue statement). Understanding it lets you verify you're being paid correctly.

Key line items to find:

• Well name / API number — identifies which well the payment is for. Cross-reference with OCC records at wellrecords.occ.ok.gov to verify it's actually producing.
• Decimal interest — your precise ownership fraction. Should match your division order. Calculate independently: (NMA ÷ Gross Acres) × Royalty Rate. Any discrepancy means you may be underpaid.
• Gross production / Gross value — total production from the well and its price. Divide your payment by this to back-calculate your implied decimal and compare.
• Deductions — any post-production costs deducted before your royalty is calculated. Check against your lease language. "At the wellhead" leases should have none.
• Severance tax — should match the applicable state rate (Oklahoma: 5% for the well's first 36 months, 7% after). Operators sometimes apply the wrong rate.
• Interest code / Product code — identifies oil (01), gas (04), or NGLs (05). Separate payment lines for each product stream.

If your calculated decimal doesn't match what's on the stub, contact the operator's revenue accounting department in writing and request a corrected division order. You may be entitled to back-pay.

You don't need to guess at production numbers — real well data is publicly available.

OCC Well Records (primary source)
Go to wellrecords.occ.ok.gov. Search by section, township, and range (found on your deed or lease) or by API number if you have it. You'll find monthly production reports showing actual BOE/day output going back to the well's first production date.

From your royalty check stub
Your check stub lists the well name and volume of production attributed to your interest. Divide your gross royalty by your royalty decimal to back-calculate the well's gross production for that month.

FracFocus.org
Shows completion data (lateral length, proppant volume, fluid volume) for horizontally completed wells. Longer laterals and more proppant generally correlate with higher IP rates.

Operator investor presentations
Devon, Continental, Ovintiv, and other public operators publish quarterly earnings presentations with average IP rates by area. These are useful for setting expectations on new wells before production is reported.

If a well is new and has no production history, Oklahoma SCOOP/STACK horizontals typically start at 500–1,500 BOE/day. 500 is a reasonable conservative starting point.

Your spacing unit is the acreage block designated by the OCC for a specific well or group of wells. Your gross acres field should reflect this unit — not the total surface area of your tract.

From your division order
The division order sent by the operator before your first royalty check will state the well name, the spacing unit description (e.g. "Section 14, T12N, R5W"), and the total unit acreage.

From OCC spacing orders
At occ.ok.gov, search the OCC docket records for spacing orders in your section. The spacing order establishes the legal drilling unit and its acreage. Most Oklahoma SCOOP/STACK horizontal units are 640 acres (one full section).

From your lease
Your lease will describe the lands covered using section/township/range legal descriptions. If multiple sections are pooled into one unit, add the acreages together for gross acres.

Rule of thumb
Modern Oklahoma horizontal wells: 640-acre units are most common. Some operators use 1,280-acre (two-section) units for longer laterals. Older vertical wells may have 40–160 acre units.

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.

NMA — Net Mineral Acres

Your actual owned mineral acres after accounting for fractional interests throughout the chain of title.

NRI — Net Revenue Interest

The exact fraction of gross production revenue you receive. For royalty owners, NRI equals the royalty decimal.

WI — Working Interest

Ownership share that bears a proportionate cost of drilling and operations. Higher revenue potential but cost-bearing obligation.

RI — Royalty Interest

Ownership share that receives royalties free of drilling and operating costs. Mineral owners under a lease hold a royalty interest.

BOE — Barrels of Oil Equivalent

Unit equating 1 barrel of oil = 6 MCF of natural gas by energy content. Used to normalize mixed production streams.

MCF — Thousand Cubic Feet

Standard unit of natural gas volume. 1 MMCF = 1,000 MCF. Gas wells measured in MCF/day or MMCF/day.

Royalty Decimal

Your precise fractional share of production value. Formula: (NMA ÷ Gross Acres) × Royalty Rate. Appears on your division order.

Severance Tax

State tax on oil and gas production at the wellhead (Oklahoma: 5% for a well's first 36 months, then 7%). Deducted from royalty before payment is issued.

Ad Valorem Tax

County property tax assessed on production value, separate from severance tax. Varies significantly by county and state.

Lease Bonus

One-time upfront payment per NMA paid when you sign an O&G lease. Separate from and in addition to ongoing royalty income.

IP Rate — Initial Production

A well's production rate when it first comes online. Reported in BOE/day or MCF/day. The highest rate the well will produce — all production declines from this peak.

Division Order

A document from the operator confirming your ownership decimal and authorizing them to distribute royalties. Review carefully — errors in the decimal interest directly affect your check.

ORRI — Overriding Royalty Interest

A royalty interest carved out of the working interest, not the mineral estate. Expires when the lease expires. Common in landman and broker deals.

Pugh Clause

Lease provision that releases depths or acreage not held by production when the primary term expires. Protects mineral owners from perpetually locking up acreage on a single shallow well.

NPV — Net Present Value

The present-day value of a future stream of royalty payments, discounted at an assumed rate of return. Mineral buyers typically use 10–15% discount rates. Higher discount rate = lower NPV.

API Number

Unique 14-digit identifier assigned to every oil and gas well in the US by the American Petroleum Institute. Used to look up production records, completion reports, and permit history at the OCC.

Spacing Unit

The acreage tract designated by regulators for a single well or group of wells. Oklahoma horizontal units are typically 640 acres for SCOOP/STACK horizontals. Your NMA is measured against this unit.

State Severance Tax Sources

State	Standard Rate	Official Source
Oklahoma	5% first 36 months of production, 7% thereafter (HB 1010xx, 2018) — modeled automatically by this calculator	okpolicy.org ↗
Texas	4.6% oil / 7.5% gas	comptroller.texas.gov ↗
North Dakota	~10% combined (5% gross production + 5% extraction tax)	tax.nd.gov ↗
Wyoming	6.0%	headwaterseconomics.org ↗
New Mexico	6.9% effective combined rate	headwaterseconomics.org ↗
Colorado	2.0% base (tiered by gross income)	coloradonewsline.com ↗
Louisiana	6.5% new wells (post July 2025); 12.5% older wells	weaver.com ↗
West Virginia	5.0%	wvtreasury.gov ↗
Kansas	8.0%	ncsl.org ↗
Utah	3.0%	ncsl.org ↗
Pennsylvania	0% severance (impact fee only)	ncsl.org ↗
Montana	9.0% gas (no oil severance tax)	ncsl.org ↗

Rates shown are standard statutory rates as of 2025. Exemptions for new horizontal wells, stripper wells, and enhanced recovery projects may significantly reduce your effective rate. Always verify current rates with your state tax authority before making financial decisions.

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Know What Your Minerals Are Worth — Before You Sign Anything

Royalty income math
shouldn't be a black box

MineralCalc — Royalty Income Estimate

Income Calculator

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Sensitivity Tables

Lease Bonus Comparison

Glossary & Methodology

Lease Analyzer

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Know What Your Minerals Are Worth — Before You Sign Anything

Royalty income mathshouldn't be a black box

MineralCalc — Royalty Income Estimate

Income Calculator

Live Results LIVE

Sensitivity Tables

Lease Bonus Comparison

Glossary & Methodology

Lease Analyzer

Your lease, translated

Instant Term Extraction

Clause Risk Flagging

Plain-English Summary

Be first to know when it launches

Choose your report format

Royalty income math
shouldn't be a black box