7 Factors that Influence
the Value of Mineral Rights
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Valuing Mineral Rights
There are two ways to value mineral rights. The first method is to use a multiple of the royalty revenue, which is usually 3-5 years. The value is adjusted up or down based on a variety of factors. The second method is a complex calculation estimating potential future royalty revenue based on a variety of assumptions. While the second method became popular during the shale revolution, it is falling out of favor as buyers realize they may never get a return on their investment.
Regardless of the valuation method, the following factors influence the value of mineral rights:
Regardless of the valuation method, the following factors influence the value of mineral rights:
Minerals in the hottest shale plays are more valuable than those in older fields with conventional wells.
Producing minerals are generally worth more than non-producing minerals because they are generating revenue.
When oil and gas prices drop, revenue drops, and sometimes operators are unable to continue operations.
Highly productive wells (and off-set wells) can increase the value of your minerals.
Leases may be fully developed, or there may be room to drill additional wells and take advantage of the initial production.
A small number of operators are unethical, and their reputation automatically devalues your minerals.
Leases may be fully developed, or there may be room to drill additional wells and take advantage of the initial production.
Mineral Rights Value
Rule of Thumb
As a rule of thumb, producing mineral rights are typically valued as a multiple of revenue - usually 3-5 years. For example, a royalty interest generating $100 in monthly revenue would be valued somewhere between $3,000 and $5,000, depending on the type of interest, location, production, lease terms, commodity price, and operator. Non-producing minerals are typically valued as the number of net mineral acres (NMA) you own multiplied by the typical lease bonus rate. In some areas, there is a "market rate" for buying mineral non-producing rights.
The value of mineral rights is somewhat subjective, and each company will value the same property a bit differently. Some buyers are looking for minerals in a specific area, while others are location-agnostic and care more about the return on their investment. The best way to determine the value of your mineral rights is to request a quote. Requesting a quote does not obligate you to sell.
Calculate the Value of Your Mineral Rights
Please enter your last three royalty checks to calculate the approximate mineral rights value:
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* This calculator has limited functionality and assumes the well or wells have been producing for more than 18 months. It does not take into account location, production, lease terms, commodity price, operator, or future development potential. Please contact us to get a custom quote on your specific minerals.
1. Location
The most significant factor affecting the value of your mineral rights is the location. Each area has it's own geography, making some sites more desirable than others.
The Permian, Eagle Ford, Haynesville, Bakken, Niobrara, and Marcellus are the most popular and therefore demand the highest prices.
Giant horizontal fracked wells of the Delaware Basin (the deepest part of the Permian) are some of the most valuable mineral rights. These wells generate a massive amount of oil and natural gas and, because there are multiple layers of shale, multiple stacked horizontal wells can be drilled in a given tract of land.
While these wells are prolific, they also have steeper decline curves and shorer economic lives than their conventional (vertical) counterparts.
Both are valuable, but there is a massive difference in the value of mineral rights in the Delaware Basin vs. the Panhandle of Texas. Permian valuations will typically far exceed those in conventional oil fields.
For a while, the SCOOP and STACK plays in Oklahoma were expected to be the Permian Jr. Exploration and production (E&P) companies rushed to Oklahoma to lease-up land and drill horizontal wells. Ultimately, the complex geology resulted in disappointing wells. Now, a lot of companies are selling out of their positions and looking for opportunities to get into the Midland and Delaware Basins of the Permian.
The location also dictates the royalty percentage. For example, in Texas, the standard royalty is 25% but, it's common to see royalties range from 12.5% to about 16% in other areas - especially in older leases.
The Permian, Eagle Ford, Haynesville, Bakken, Niobrara, and Marcellus are the most popular and therefore demand the highest prices.
Giant horizontal fracked wells of the Delaware Basin (the deepest part of the Permian) are some of the most valuable mineral rights. These wells generate a massive amount of oil and natural gas and, because there are multiple layers of shale, multiple stacked horizontal wells can be drilled in a given tract of land.
While these wells are prolific, they also have steeper decline curves and shorer economic lives than their conventional (vertical) counterparts.
Both are valuable, but there is a massive difference in the value of mineral rights in the Delaware Basin vs. the Panhandle of Texas. Permian valuations will typically far exceed those in conventional oil fields.
For a while, the SCOOP and STACK plays in Oklahoma were expected to be the Permian Jr. Exploration and production (E&P) companies rushed to Oklahoma to lease-up land and drill horizontal wells. Ultimately, the complex geology resulted in disappointing wells. Now, a lot of companies are selling out of their positions and looking for opportunities to get into the Midland and Delaware Basins of the Permian.
The location also dictates the royalty percentage. For example, in Texas, the standard royalty is 25% but, it's common to see royalties range from 12.5% to about 16% in other areas - especially in older leases.
2. Producing vs. Non-Producing Mineral Rights
Producing Mineral Rights Value
Producing minerals are mineral rights with an active oil or gas well that is producing economically viable quantities of oil or gas. Royalty interest owners who have producing minerals get monthly (or periodic) royalty checks. Producing minerals are typically valued at a multiple of the monthly royalty payment - usually 30 to 60 months. The Permian Basin and some other shale plays have been valued higher in the last few years, but some of the hype is dying down now.
Producing Minerals Rule of Thumb: Monthly Royalty Income x Multiple (36-48 for horizontals and 48-60 for vertical wells).
Horizontal wells sell for a lower multiple because they generally have steeper decline curves and shorter lifespans.
Producing Minerals Rule of Thumb: Monthly Royalty Income x Multiple (36-48 for horizontals and 48-60 for vertical wells).
Horizontal wells sell for a lower multiple because they generally have steeper decline curves and shorter lifespans.
Non-Producing Mineral Rights Value
Non-producing minerals typically refer to mineral interest in one or more tracts of land that does not have a producing oil or gas well. Because there are no wells, there will be no royalty payments. However, that doesn't mean that non-producing mineral rights are devoid of value.
Again, location comes into play. Non-producing minerals located in the best shale plays will have more value than non-producing minerals in older oil fields or areas without proven reserves. Typically, non-producing minerals are valued based on a multiple of the expected lease bonus.
For example, if the going lease bonus in the county ranges from $100-$500 dollars, you can expect to sell your mineral rights for the lease bonus times the number of net mineral acres (NMA) that you own.
The value of non-producing minerals is usually stated as a price per acre. The price per acre varies, from state to state, county to county, and even within a county.
Non-Producing Minerals Rule of Thumb: Lease Bonus x NMA
What determines if your lease bonus is valued at $100, $500, or somewhere in-between? That depends on where your minerals are located in relation to the drilling activity in the county. The closer you are to active drilling areas, the higher your lease bonus will be. This is reasonably easy to determine by looking at a couple of maps. Here's a quick guide: How to figure out if your minerals are in a hot area.
Non-producing minerals are especially impacted by the recent oil and gas slowdown. This is especially true after the global shutdown for COVID-19 and the collapse of oil prices in April of 2020. Most of the best prospects have at least one wells drilled already.
The best way to know the value of your mineral rights is to request an offer.
Again, location comes into play. Non-producing minerals located in the best shale plays will have more value than non-producing minerals in older oil fields or areas without proven reserves. Typically, non-producing minerals are valued based on a multiple of the expected lease bonus.
For example, if the going lease bonus in the county ranges from $100-$500 dollars, you can expect to sell your mineral rights for the lease bonus times the number of net mineral acres (NMA) that you own.
The value of non-producing minerals is usually stated as a price per acre. The price per acre varies, from state to state, county to county, and even within a county.
Non-Producing Minerals Rule of Thumb: Lease Bonus x NMA
What determines if your lease bonus is valued at $100, $500, or somewhere in-between? That depends on where your minerals are located in relation to the drilling activity in the county. The closer you are to active drilling areas, the higher your lease bonus will be. This is reasonably easy to determine by looking at a couple of maps. Here's a quick guide: How to figure out if your minerals are in a hot area.
Non-producing minerals are especially impacted by the recent oil and gas slowdown. This is especially true after the global shutdown for COVID-19 and the collapse of oil prices in April of 2020. Most of the best prospects have at least one wells drilled already.
The best way to know the value of your mineral rights is to request an offer.
3. Oil & Gas Prices
The price of oil and gas can have a dramatic impact on the value of your mineral rights. When commodity prices are high, both the operator and mineral owners reap the economic benefits.
Lower commodity prices mean less revenue. Significant and long-lasting drops in the price of oil and gas can make it uneconomical to continue operating wells or even drill new wells - especially the expensive fracked horizontal wells.
Prior to the fracking boom, oil as $164 per barrel and gas prices hit $18 per MCF. There was a lot of talk about having reached peak oil. The fracking boom changed all that, causing the pendulum to swing the other direction. Massive horizontal wells recovered incredible amounts of oil and gas, saturating the market and causing the prices to drop.
Low energy prices have been good for the economy as a whole. Natural gas is considered a less environmentally damaging fuel source, acting as a bridge to renewable energy and a more sustainable future.
However, there is also a downside. In the larger shale plays, wells were drilled faster than the infrastructure could be put into place. While oil can be trucked to refineries, the only way to transport natural gas is via pipelines. When there weren't enough pipelines, operators began flaring natural gas.
Even as pipelines come online, there is so much gas that operators (who aren't flaring) are selling it for as low as fifty-cents per MFC! This is not good news for mineral owners. The same well would be producing vastly more revenue if the price of gas were higher. Exporting natural gas may help alleviate this problem - time will tell.
Meanwhile, the low price of oil and gas leads to lower royalty checks and ultimately a lower value for your mineral rights.
Lower commodity prices mean less revenue. Significant and long-lasting drops in the price of oil and gas can make it uneconomical to continue operating wells or even drill new wells - especially the expensive fracked horizontal wells.
Prior to the fracking boom, oil as $164 per barrel and gas prices hit $18 per MCF. There was a lot of talk about having reached peak oil. The fracking boom changed all that, causing the pendulum to swing the other direction. Massive horizontal wells recovered incredible amounts of oil and gas, saturating the market and causing the prices to drop.
Low energy prices have been good for the economy as a whole. Natural gas is considered a less environmentally damaging fuel source, acting as a bridge to renewable energy and a more sustainable future.
However, there is also a downside. In the larger shale plays, wells were drilled faster than the infrastructure could be put into place. While oil can be trucked to refineries, the only way to transport natural gas is via pipelines. When there weren't enough pipelines, operators began flaring natural gas.
Even as pipelines come online, there is so much gas that operators (who aren't flaring) are selling it for as low as fifty-cents per MFC! This is not good news for mineral owners. The same well would be producing vastly more revenue if the price of gas were higher. Exporting natural gas may help alleviate this problem - time will tell.
Meanwhile, the low price of oil and gas leads to lower royalty checks and ultimately a lower value for your mineral rights.
4. Well Production
The amount of oil and gas that a well produces directly impacts the value. Generally speaking, more production results in a bigger revenue check.
Notable exceptions might be the flaring of natural gas due to pipeline constraints and highly-fractioned mineral rights where there are hundreds or even thousands of mineral owners for a tract of land.
Wells produce the largest quantity during the first couple of months, but production quickly declines - especially in horizontal wells. Depending on your location, at the end of the first year, your royalty check might be 50% of the initial production. It might even be 10%.
At some point, usually, after two years, the well will "settle" and the curve will decline more slowly.
When considering non-producing minerals, a mineral interest surrounded by successful offset wells will be more valuable than one poor or mediocre offset wells.
Notable exceptions might be the flaring of natural gas due to pipeline constraints and highly-fractioned mineral rights where there are hundreds or even thousands of mineral owners for a tract of land.
Wells produce the largest quantity during the first couple of months, but production quickly declines - especially in horizontal wells. Depending on your location, at the end of the first year, your royalty check might be 50% of the initial production. It might even be 10%.
At some point, usually, after two years, the well will "settle" and the curve will decline more slowly.
When considering non-producing minerals, a mineral interest surrounded by successful offset wells will be more valuable than one poor or mediocre offset wells.
5. Lease Terms
New mineral owners are usually so excited to be offered an oil and gas lease, that they accept the terms without hiring an attorney to negotiate on their behalf. Or, they read a book and try to negotiate on their own. It's always best to seek legal advice before signing an oil and gas lease - The terms of the lease can have a dramatic impact on the value of your mineral rights.
Royalty
When it comes to oil and gas lease terms, the royalty reservation has the biggest impact on the value of mineral rights. In Texas, the standard royalty is 25% (this wasn't always the case, though). Older leases, especially outside of Texas, typically reserve a 12.5% - 16% royalty. As mineral owners have become more savvy and connected, the 25% royalty has gained popularity. Just think - by leasing at 25%, you can make twice what someone leased at 12.5%.
Mother Hubbard Clause
Many mineral owners unknowingly lease a lot more of their mineral rights than the company intends to develop. This can lead to a situation where your mineral rights are held by production (HBP), possibly for decades, by a single well barely producing economical quantities of oil or gas.
Cost-Free Lease
When an oil and gas lease is signed, it typically gives the mineral owner rights to 12.5% - 25% of the revenue, and the operator gets 75% - 87% of the revenue. That's because the operator assumes all of the risks and expenses associated with drilling and operating the well. That's how it usually is. Operators sometimes include costs in a lease, obligating the mineral owner to pay a portion of the operating expenses.
Free Use of Natural Gas
A lot of leases contain language allowing the operator free use of natural gas for the operation of the well. Companies are using this "free" natural gas to run their frack fleets and other aspects of the operation - without paying you for the natural gas.
Note: In the Appalachian states, lease terms are mostly pre-determined so mineral owners have very little negotiating power.
Royalty
When it comes to oil and gas lease terms, the royalty reservation has the biggest impact on the value of mineral rights. In Texas, the standard royalty is 25% (this wasn't always the case, though). Older leases, especially outside of Texas, typically reserve a 12.5% - 16% royalty. As mineral owners have become more savvy and connected, the 25% royalty has gained popularity. Just think - by leasing at 25%, you can make twice what someone leased at 12.5%.
Mother Hubbard Clause
Many mineral owners unknowingly lease a lot more of their mineral rights than the company intends to develop. This can lead to a situation where your mineral rights are held by production (HBP), possibly for decades, by a single well barely producing economical quantities of oil or gas.
Cost-Free Lease
When an oil and gas lease is signed, it typically gives the mineral owner rights to 12.5% - 25% of the revenue, and the operator gets 75% - 87% of the revenue. That's because the operator assumes all of the risks and expenses associated with drilling and operating the well. That's how it usually is. Operators sometimes include costs in a lease, obligating the mineral owner to pay a portion of the operating expenses.
Free Use of Natural Gas
A lot of leases contain language allowing the operator free use of natural gas for the operation of the well. Companies are using this "free" natural gas to run their frack fleets and other aspects of the operation - without paying you for the natural gas.
Note: In the Appalachian states, lease terms are mostly pre-determined so mineral owners have very little negotiating power.
6. Operator
It's widely known that some companies are better at drilling and completing successful wells than others. In adjacent tracts of land, two companies might drill similar wells but one may more successful than the other. Some companies are also more agreeable to mineral-owner-friendly lease terms.
The biggest impact the operator has on the mineral owner is how the company deals with deductions. Some operators pass part of the operating expenses onto the mineral owner (whether or not this is allowed in the lease).
Most operators are reasonably ethical. They are trying to run a successful business, follow all the rules, and turn a profit. However, there are some operators widely known for their unethical practices. If your wells are operated by one of these companies (one is particularly infamous), your royalty checks will be a fraction of what they would be under a different operator.
Some mineral buyers will not buy Royalty Interest (MI), Non-Participating Royalty Interest (NPRI) or Overriding Royalty Interest (ORRI) if it is operated by a specific company. Similarly, some buyers will pay more for mineral rights operated by their favorite companies.
The biggest impact the operator has on the mineral owner is how the company deals with deductions. Some operators pass part of the operating expenses onto the mineral owner (whether or not this is allowed in the lease).
Most operators are reasonably ethical. They are trying to run a successful business, follow all the rules, and turn a profit. However, there are some operators widely known for their unethical practices. If your wells are operated by one of these companies (one is particularly infamous), your royalty checks will be a fraction of what they would be under a different operator.
Some mineral buyers will not buy Royalty Interest (MI), Non-Participating Royalty Interest (NPRI) or Overriding Royalty Interest (ORRI) if it is operated by a specific company. Similarly, some buyers will pay more for mineral rights operated by their favorite companies.
7. Lease Development
In the Permian and other shale plays, lease development also factors into the value of mineral rights. In some areas, multiple stacked lateral wells can be drilled in a single tract of land. If the lease if fully developed, that means the maximum number of wells have already been drilled.
This can be a good thing in terms of valuing the mineral rights by using a multiple of production. However, many buyers place a premium on a lease that is not fully developed. The majority of the oil and gas is produced during the first five years of a well's life. When there is room for additional wells, the mineral owner will benefit from the initial production of any new wells.
Solar Development
Occasionally mineral owners are approached by solar farm developers who need to purchase the mineral rights before building the solar farm. We will sometimes buy mineral rights in these situations.
This can be a good thing in terms of valuing the mineral rights by using a multiple of production. However, many buyers place a premium on a lease that is not fully developed. The majority of the oil and gas is produced during the first five years of a well's life. When there is room for additional wells, the mineral owner will benefit from the initial production of any new wells.
Solar Development
Occasionally mineral owners are approached by solar farm developers who need to purchase the mineral rights before building the solar farm. We will sometimes buy mineral rights in these situations.
What We Buy
We want to give you the tools and information to make an informed decision. Selling mineral rights is a big decision and we will be happy to answer your questions and evaluate your mineral interest, royalty interest, non-participating royalty interest, and overriding royalty interest. We even have mineral owners donate their small mineral rights (usually when they can't find anyone to buy them). We don't mind having small and tiny minerals.
Why Sell?
New mineral owners often ask, "How much do mineral rights sell for?" Mineral rights generally sell for 3 to 5 years of royalty payments. Whether the offer is closer to 3 years or five years, depends on a variety of factors such as location, weather the minerals are producing, production history, commodity prices, oil and gas lease terms, operator, and potential for future development. The best way to determine the value of your mineral rights is to get a few quotes.
Why People Sell Their Minerals Rights:
With the price of oil declining and operators practically giving gas away, I decided to sell before the bottom falls out.
I am on a fixed income, and the sale of these minerals will help me secure stable housing. My children will be okay if even if they don't inherit these minerals.
My oil wells have been producing for decades and the reserves are almost depleted. Once the wells are plugged, the value will be significantly lower. I'd rather cash out now.
I inherited mineral rights, but don't want to be involved with fracking and fossil fuels. I would prefer to support renewable energy and do my part to reverse climate change.