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Permalink Reply by Skip Peel - Mineral Consultant on April 23, 2025 at 7:37

Niel, not that I am aware of.  There was some talk about estimated royalty based on bonus in the first year of the Haynesville Shale.  Over that year bonuses went from $250 an acre to $30,000 an acre and then down to $2500 an acre.  Some of the minerals leased turned out to be sub-economic and were discarded.  Chesapeake leased over 300,000 acres across LA and E TX in the north end of the fairway. They couldn't sell them to another company and had to write it off as a total loss.

Although it will always be a rough estimate, the better approach is to look at the production volumes of recently completed wells in close proximity, the number of future wells and make calculations based on the royalty fraction in the lease, any no cost language and the forward strip of Henry Hub natural gas prices.

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Permalink Reply by Hale Yayuh on April 25, 2025 at 5:00

Something that people need to understand is that a very large percentage of the factors going into how much a company receives back (if anything) are uncertain. The oil biz is rife with uncertainty. You could have everything perfect (as it can be) going into drilling and they hit what mother nature put there and it's crappy rock. This is less so in these days of drilling shale as opposed to conventional (old days mostly) reservoirs but it still happens.

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Permalink Reply by Jesse Joyner on April 25, 2025 at 5:21

True. You know your stuff, Hale.

But even with ubiquitous shale drilling, a fault can screw things up, as can a flub on a frack per the wireline going snafu. It's sorta rare, yet the unexpected can occur. A couple of years back, an operator drilled two wells (on our land) from one pad. One well completed and went into production. No problem. But its sister well had a wireline problem. Zero royalty. Stuff happens.

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Permalink Reply by Ryan Howrish on April 25, 2025 at 5:55

The short answer is yes companies run full-field development economics, including land acquisition costs, before investing any capital (large or small).  Part of the economic evaluation includes an estimate of the royalties to be paid because they have to assume (or calcualte) their net revenue interest in every well included in the development model.  Depending on the size of the development area, the company may use a single type curve (to estimate future volumes) or have multiple type curves for smaller areas within the full development area. This is generally done by the reservoir engineers at the company.  Publicly traded companies are required to conduct reserve evaluations, including undeveloped locations, every year and submit the year-end report to the SEC.  As pointed out in a previous response, geologic features such as faults are incorporated into the economic models and impact either the productivity of wells near faults or the number of wells that can be developed in faulted areas.

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Permalink Reply by Skip Peel - Mineral Consultant on April 25, 2025 at 5:58

Thanks, Ryan.  An explanation for non-industry members on net royalty interest/net revenue interest would be appreciated.

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Permalink Reply by Ryan Howrish on April 25, 2025 at 8:24

Sure - that's a good idea.  I'll put something small together and share it in this thread.

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Permalink Reply by Skip Peel - Mineral Consultant on April 25, 2025 at 8:52

Thanks.  A number of energy media articles mention NRI and acronyms stump a lot of the members.  It is a good definition for them to know.

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Permalink Reply by Ryan Howrish on Monday

Below is a brief summary of interest definitions and a sample cash flow calculation.  Every operator will have some form of a full development plan that accounts for their entire lease position. This is how future drilling inventory is managed and evaluated.

• Gross Revenue: The total revenue (100%) generated from the sale of oil and gas produced from a well before any deductions.

• Working Interest (WI): Held by operators who drill and manage the wells. With 100% working interest, operators pay 100% of capital expenditures (drilling and completion costs) and operating costs. They bear all risks of additional expenses during all phases of development. If the lease or leases in a unit do not allow the operator to pass on post-production costs, the operator bears that expense at 100%. If the lease does allow the operator to pass on post-production costs, the mineral owners pay their proportionate share of these expenses.

• Operator Net Revenue Interest (NRI): The percentage of revenue that an operator is entitled to after accounting for their royalty burden. Simplistically; Working Interest - Royalty Burden = Net Revenue Interest

• Mineral Owner Net Revenue Interest / Decimal Interest: the percentage of revenue from a producing oil and gas well or unit that a mineral owner is entitled to receive as royalty payments. It represents the owner's proportionate share of the total production revenue, expressed as a percentage or decimal.

Sample Cash Flow Calculation from an Operator’s Perspective
• Gross Revenue = $1,000,000
• Royalty Burden = $250,000
• Operator Net Revenue = Gross Revenue - Royalty Burden = $750,000
▪ Operating Expenses = $200,000
▪ Post-Production Costs (assume a no-cost lease) = $250,000
▪ Operator Severance Tax = $50,000 (mineral owners are responsible for paying their proportionate share of severance taxes)
• Net Operating Income = Net Revenue - All Expenses = $750,000 - $200,000 - $250,000 - $50,000 = $250,000
• Before Tax Cash Flow = Net Operating Income - Capital Expenditures

Operating companies calculate their income and cash flow statements monthly.

If anyone has any questions, let me know.

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Permalink Reply by Skip Peel - Mineral Consultant on Monday

Thanks, Ryan.  Good synopsis.

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Permalink Reply by Niel Loeb on Monday

Is there not an industry formula for Royalty Burden based on total expenditures?  I envision an example from an industry study saying something like “Of the money an oil and gas company spends on research, acquisition, and operations, they should expect to pay out an average of 2.38% in royalties.”

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Permalink Reply by Ryan Howrish on Monday

In almost 30 years of working primarily for operators in the oil and gas industry across North America, I have never seen an estimation of future royalties like the example you provided.

The royalty burden and royalties payable are not directly tied to the total expenditures of a company.  The royalties are tied to the volume of hydrocarbons produced and the price received for each product (revenue).  Every company also has different cost structures.  It is hard to look at just total expenditures (capital investment + expenses) and calculate the estimated royalty payments.  

This plot shows the distribution of individual well costs in the Haynesville by operator over the past 5 years.  The difference in well costs can be attributed to many things like the area of the play, the operator, faulted areas vs. non-faulted areas, deep wells in the South of the play vs. shallower wells in the North.  Many factors influence the well costs but none tie directly to the total expenditure of a company.

https://wellcost.hdpetroleumevaluations.com/

If you want to get a high-level estimate of the royalties a company will pay in the future, you can view the financials in a publicly traded company's Form 10k or 10Q SEC filing.  The example below from Expand Energy shows the estimated value of their producing and proved non-producing (future development wells) to be $13.7 billion dollars.  If you assume an average NRI of 78.5% (or whatever you think is a good number), you can estimate the royalties by dividing the net revenue number by the estimated NRI ($13.7 billion / 78.5%) to estimate the gross revenue and the multiply the gross revenue by the estimated royalty burden of 22.5%.  In this case, that works out to $3.9 billion.  There is a development plan with many assumptions behind the estimated net revenue value provided, but this would provide a more reasonable estimate of future royalties compared to trying to estimate royalty payments based on just future capital.  Every publicly traded company will have a listing of all of their SEC filings on their website.  Most likely in the "Investor" section.

https://investors.expandenergy.com/financial-information/sec-filing...

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