What is the average price per acre for mineral rights? We get this question all the time. And the answer is always: it depends.
Average acre prices are calculated based on analyzing many factors. In addition, there are also a variety of approaches that one might take to determine the proper valuation.
In this post, we will discuss the most common strategy for calculating average price per acre. It can be complex, but we will try to simplify for you. Let’s jump in.
Table of contents
The Income Approach
The short answer is that the income approach, used to value oil and gas mineral interests, is a complex process with multiple steps and considerations.
Mineral rights represent income-producing property. So, the commonly accepted method of valuing oil and gas interests is the income approach, similar to the technique used to evaluate commercial real estate. This method will estimate the present value of the property’s future cash flows that the oil and gas mineral interests are expected to generate.
Estimating the expected production
The first step in the income approach is estimating the expected oil and gas production. Expected production is calculated by looking at the sum of expected future production from:
(1) Wells that are already producing (sometimes also called “Proven Developed Producing” or “PDP”); and
(2) Wells that are expected to start producing in the future.
Historical production data will provide a reliable basis for predicting future production from PDP wells. Despite some variation from well to well, with enough historical data, predicting future production with reasonable accuracy is relatively straightforward. This is critical to determining the average price per acre for mineral rights.
For wells that are not yet producing or have not been producing long enough to make reasonably accurate predictions, it’s much harder to determine the expected future production. Doing so involves analyzing operator spacing data, any geological data, specific drilling reports, the performance of nearby wells, etc.
However, the real clarity comes only when the final permits are filed and the drilling commences. Until then, you can’t be sure how many wells there will even be. This process can be imprecise because there are so many variables, making these milestones of utmost importance.
Calculate the cash flows
The second step is to calculate the anticipated cash flows on expected production. Mineral owners aren’t generally paid a fraction of the oil and gas produced. They are paid a fraction of the revenue from the actual sale of the oil and gas.
This means figuring out not only:
- What it will produce; but
- When it will produce it; and
- What the regional price of oil and gas will be at the time. This can involve a lot of guesswork, especially for non-producing wells.
Will the well come online in the next several months? Maybe it will go online in a few years? What will the price of oil or gas be at that time?
Apply the discount rate
The third and final step is to apply the discount rate. This rate measures the investor’s time value of money, representing the anticipated return an investor would receive from an alternative investment with a similar risk profile.
Discounting the expected cash flows using the net present value calculation is common. That’s because money today is worth more than money in the future because of inflation and the opportunity cost of not having that money to invest elsewhere.
Net present value is a financial framework to measure the value of an investment in today’s dollars. It considers the expected future cash flows from the investment and discounts them back to their present value based on the time value of money. This helps when analyzing average price per acre for mineral rights.
Division of Interest (“DOI”) in those wells
Finally you must calculate your division of interest (“DOI”) in those wells. Division of Interest (DOI) is used in the oil and gas industry to describe a fractional ownership interest in a well. That’s a function of:
- How many acres do you own in the pooling/spacing unit that well is allocated to?
- How much is allocated to that unit?
- Your lease royalty.
Assuming the wells are producing (or soon will be), the operator’s division order with your DOI is a crucial document. If you don’t have it, you must calculate your division of interest yourself.
These orders typically detail the property’s legal description, the owner’s names, and the decimal interest each owner is entitled to receive. However, it is essential to note that division orders are not permanent contracts; they can be adjusted as ownership changes or production levels fluctuate.
For this reason, it is absolutely crucial that mineral rights owners thoroughly review and comprehend the contents of a division order before signing. Any inaccuracies in the document could lead to improper payments or even legal disputes, underscoring the importance of this step.
Under the division order, the operator pays 2% of the proceeds from selling oil and gas to the payee after deducting certain expenses. Division orders outline the agreed-upon interest division and the method for dividing the payments, which is why they are called “division” orders.
Can I Refuse to Sign a Division Order? It’s important to understand that as a mineral rights owner in Texas, you have the right to refuse to sign a division order that does not conform to the statute (Texas Natural Resources Code sec. 91.402). The operator cannot withhold payment from you solely on the grounds of not signing such a division order.
What if it Contains Non-Standard Provisions? In Texas, if an owner does not sign a division order because it contains provisions other than those provided in the statute, the operator may not withhold payment solely on those grounds.
If they refuse to pay you unless you sign a non-confirming division order, you should consult an attorney about the best next steps. This process is in place to protect your rights as a mineral owner, giving you the confidence to stand up for your rights.
Let’s look at an example
Here’s an example of how NPV works. Suppose you have an investment opportunity likely to generate $1,000 in cash flow in the first year.
You use a discount rate of 10%. The present value of that future cash flow would be $909.09 (i.e., $1,000 / (1 + 0.10)^1). The specific discount rate depends on what other investment opportunities are available to you at the time and along with any prevailing market conditions.
So after you have estimated your production, considered extraction timing and commodity prices, using that to calculate the discounted cash flows, you will now know the value of the well. You must then do that same calculation for all of the wells.
Finally, multiply the number you got from steps (1)-(3) by the fraction in step (4). That’s the income approach.