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 or hyperbolic (Arps) decline
  • 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
  • Oklahoma well lookup — real OCC completion rates by section
  • New Lease PDF Analyzer — plain-English term and clause review, in your browser →
Royalty Estimator

Income Calculator

📄 Have a lease? Analyze it and skip the manual entry →
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 leases), 3/16 (legacy standard), 1/5 (emerging 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 (2025–2026):

  • 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.

Enter your section, township, and range. This searches completion records published by the Oklahoma Corporation Commission — actual wells, actual initial test rates.

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
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
Enter at least 2 months of production data to calculate decline rate.
Decline Model
?
Exponential applies a constant annual decline — simple and conservative. Hyperbolic (Arps) matches shale behavior: steep early decline that flattens into a long tail, then switches to a terminal exponential rate. Reserve engineers and mineral buyers typically model horizontal wells hyperbolically.How decline models work →
The slider above sets year-1 decline. Shale b-factors typically run 0.8–1.4. Once the hyperbolic curve flattens to the terminal rate, decline continues exponentially at that rate — the convention used in reserve reports.
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. Cash flows are discounted at end of each year — a conservative convention; mid-year discounting would run ~5% higher at a 10% rate.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.
Default is an Aug 2026 ballpark — check Live Prices for today's benchmark, or use the realized price from your check stub.
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 for your selected commodity — 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 →
Enter a rate between 0 and 25%.
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 / Other Tax Rate (%)
?
County or other production-value taxes beyond severance. Oklahoma's gross production tax is levied in lieu of ad valorem — the 0.095% default is OK's petroleum excise tax, the only other line on an OK check stub. In states like Texas, county appraisal districts tax producing minerals separately (often billed to you annually rather than withheld).
Enter a rate between 0 and 10%.
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.
Estimates only — production, pricing, and lease terms vary significantly. This tool does not constitute financial, legal, or tax advice. Consult a licensed petroleum engineer, landman, or O&G attorney before making mineral rights decisions.

Live Results

⚠ 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 — set the price to your check stub's realized price, enter the well's current production rate (not its IP), and uncheck "New well" if the well is past 36 months so the right severance rate applies.

$ this month
Scenario Analysis

Sensitivity Tables

Price vs. Royalty Rate — Annual Net Royalty Income
Rows: price ± your effective price (scenario applied) | Columns: royalty fractions | Amber border = your current inputs
Year-by-Year Production Decline Schedule
Exponential decline model from your inputs. Net royalty is after taxes and deductions; Gross Royalty is before.
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
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.
FAQ

Common Questions

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.

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.

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.

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.

In active Oklahoma plays (2025–2026): 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.

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.