Estimate royalties based on company investment

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.

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.

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.