Key Factors in Mineral Rights Pricing<\/h2><\/h2><\/div>Let\u2019s start with a few basics: below is a list of some key factors considered by the mineral rights buyers who you\u2019re looking to sell to.<\/p>\n
\n- The Basin<\/strong>\u2014i.e. Permian<\/a>, Delaware, Eagle Ford, etc. The Permian as a whole, which includes the Delaware, is the most productive basin<\/a> in the world\u2014and if Texas as a whole were a nation, it would be near the top in both oil and natural gas production. Minerals buyers in major producing basins\u2014where there are extensive support systems and pipelines in place\u2014will actively compete there, paying more than they will for minerals in basins with less production and infrastructure.<\/li>\n
- Who Is the Operator<\/strong>\u2014Companies with large leases may pay differently from those with smaller ones; and some with a more aggressive drilling plan may pay more than those focused on capital discipline\u2014meaning paying dividends to investors\u2014instead of drilling.<\/li>\n
- Number of Wells Already Drilled<\/strong>\u2014The presence of existing wells means nearby production is proven and at least somewhat predictable for the buyer, reducing risk and possibly increasing what they are willing to pay you.<\/li>\n
- Number of Wells Yet to be Drilled<\/strong>\u2014If the producer is planning to drill more wells in an existing field, this can boost the price of your royalties because buyers expect them to pay off.<\/li>\n
- Production from Nearby Wells<\/strong>\u2014Similar to number of wells already drilled.<\/li>\n
- Decline Curve for Existing Wells<\/strong>\u2014Shale wells, the current focus of almost all oil companies, produce the vast majority of their oil in the first two years, while vertical wells may maintain much of their production level for decades. So if your minerals involve mostly older shale wells, their value will be lower than where there is current\/future drilling.<\/li>\n
- Nearby Pipeline Infrastructure<\/strong>\u2014Three main things come from a well: oil, natural gas, and water, and all must have somewhere to go (known as takeaway capacity) for the minerals to have value. Natural gas is currently the most challenged of the three, but takeaway capacity for any of the three depends on your minerals\u2019 location.<\/li>\n
- Oil and Gas Pricing<\/strong><\/a>\u2014Driving seasons, supply\/demand, pipeline availability, world events, and other variables affect this locally and worldwide.<\/li>\n
- Royalty Rate<\/strong>\u2014This is your percentage of the sales price of the produced minerals on your lease, typically 12.5%-25%. This affects the price buyers will offer.<\/li>\n
- Active Permits\u2014<\/strong>When permits are active, the paperwork is in place for drilling to begin. That speeds up the drilling process, which can cause buyers to bid higher.<\/li>\n
- Expired Permits\u2014<\/strong>If permits for your area have expired, the renewal process could delay drilling and production of your minerals, reducing the buyer\u2019s bid. Or it could mean producers have decided there are no minerals to be profitably produced at current prices, so there might never be production in that area. In that case mineral rights bids could be low or non-existent.<\/li>\n
- Surrounding Permit Activity\u2014<\/strong>If your minerals are in a newly permitted area the value may be lower because production there hasn\u2019t been proven. Where there are existing permits and activity buyers usually pay more.<\/li>\n
- Surrounding Rig Activity<\/strong>\u2014Rig activity leads to production, leading to profits for minerals buyers, increasing what they may pay for your minerals. Less rig activity may mean producers feel there are few or no more prospects to be drilled.<\/li>\n
- Many other factors are also in operation.<\/li>\n<\/ul>\n
That\u2019s an overview of the big picture. Now let\u2019s examine some processes buyers use to evaluate minerals.<\/p>\n<\/div>
Ways Buyers Evaluate Minerals, and Why Offers Vary<\/h2><\/h2><\/div>Even when there is active drilling and production near your minerals, it\u2019s more complicated than simply learning what a neighbor\u2019s minerals are worth. Here are some reasons why.<\/p>\n
Let\u2019s say you have mineral rights with a 12.5% lease, and there are eight horizontal wells on your land. Meanwhile, your neighbor has a 25% lease but it contains only one vertical well from 1950. A couple of months ago a major operator started drilling ten new wells on their section.<\/p>\n
Even though you\u2019re just next door, your mineral rights might be worth $1,000 per acre, while your neighbor\u2019s could be $30,000 or more per acre. The difference would likely be based on factors like activity and lease terms.<\/p>\n
That\u2019s why there\u2019s no average price per acre for mineral rights. Every situation is unique. Your lease agreement terms, your lease royalty percentage, your ownership type<\/a>, etc. all make a difference in the average price per acre for mineral rights.<\/p>\n<\/div><\/div><\/div><\/div><\/div><\/div>![](\"https:\/\/www.usmineralexchange.com\/blog\/wp-content\/uploads\/2020\/08\/CTA_2_2.png\")
<\/a><\/span><\/div>![](\"https:\/\/www.usmineralexchange.com\/blog\/wp-content\/uploads\/2020\/08\/CTA_mobile.png\")
<\/a><\/span><\/div><\/div><\/div><\/div><\/div><\/div>\n<\/div><\/div><\/div><\/div><\/p>\nGross Acres vs Net Acres<\/h3>\n
<\/h3><\/span><\/div><\/div><\/div>\nOne key detail in mineral values involves the difference between gross acres<\/strong> and net acres<\/strong>.<\/p>\nGross acres<\/strong> measures the physical location of your ownership. You\u2019ll see these on your deed or lease\u2014usually as round numbers like 40, 80, or 160 acres. That\u2019s where many owners assume they own more than they actually do.<\/p>\nBut when it comes to calculating value<\/strong>, all that matters is your net mineral acres<\/strong>\u2014your actual ownership portion of those gross acres. That number is rarely listed clearly, and can be tricky to figure out, but here are some key factors.<\/p>\nTo determine your net mineral acres, you\u2019ll need revenue statements or a division order\/payment document, and you might need some experienced help to understand the often technical language.<\/p>\n<\/p>\n
<\/p>\nHow Mineral Buyers Use Net Royalty Acres to Compare Values<\/h3>\n
<\/h3><\/span><\/div><\/div><\/div>\nIf you\u2019ve encountered the term \u201croyalty acre<\/strong>\u201d or \u201cnet royalty acre<\/strong>,\u201d it can be confusing. Here\u2019s what those are about:<\/p>\nMineral buyers<\/a> use net royalty acres to make \u201capples to apples\u201d comparisons. It helps them evaluate deals consistently in the fact of varying lease terms.<\/p>\nIt all comes down to your lease rate<\/strong>\u2014specifically, the royalty percentage in your lease.<\/p>\nHere is a simple explanation:<\/p>\n
1 net mineral acre leased at 12.5% = 1 net royalty acre<\/strong><\/p>\n1 net mineral acre leased at 25% = 2 net royalty acres<\/strong><\/p>\nThe difference you see there is because a 25% lease pays double the royalty rate of a 12.5% lease. To a buyer it\u2019s worth twice as much royalty-wise.<\/p>\n
Net royalty acres let buyers calculate how much income interest they\u2019re really buying, regardless of lease differences. It\u2019s a quick way to compare different owners in the same area\u2014even on the same well.<\/p>\n<\/div>
<\/div><\/div><\/div><\/div><\/div>Location, Location, Location<\/h2><\/h2><\/div>The major producing basins, unsurprisingly, are usually where minerals are of the highest value. Buyers<\/a> in active Texas<\/a> basins may pay more than for minerals in lower production areas such as Wyoming. In high production areas, there is abundant drilling activity as producers expand not only in acreage but in depth. The Permian, for example, has many layers of productive zones stacked under the surface, some of which still have less-tapped zones, allowing them to continue to increase production.<\/p>\nExample 1: Core vs Edge Areas (Permian\/Texas)<\/strong>
\nEven within the same basin, values can vary widely. A mineral interest in a highly production county like Midland or Martin have very few locations that are not attractive to buyers.\u00a0 In contrast, interests on the edges of other counties may be less attractive due to thinner rock and less consistent production results, which can reduce how aggressive buyers price them.<\/h4>\nExample 2: Operator Quality<\/strong>
\nEven within the same county, value can vary depending upon the operator. A well operated by a large active company with a history of consistent drilling and strong performance may attract stronger offers than a similar interest under a smaller operator with limited activity or less drilling success<\/h4>\nExample 3: Producing vs Undeveloped<\/strong>
\nTwo properties in the same county can be valued very differently depending on development status. A producing property with established wells provides more predictable cash flow, while an undeveloped property may be valued based on its future potential.\u00a0 That potential can vary widely depending upon location and operator quality which may lead to greater offer price variation.<\/h4>\n<\/div><\/div><\/div><\/div><\/div><\/div>
Let\u2019s start with a few basics: below is a list of some key factors considered by the mineral rights buyers who you\u2019re looking to sell to.<\/p>\n
- \n
- The Basin<\/strong>\u2014i.e. Permian<\/a>, Delaware, Eagle Ford, etc. The Permian as a whole, which includes the Delaware, is the most productive basin<\/a> in the world\u2014and if Texas as a whole were a nation, it would be near the top in both oil and natural gas production. Minerals buyers in major producing basins\u2014where there are extensive support systems and pipelines in place\u2014will actively compete there, paying more than they will for minerals in basins with less production and infrastructure.<\/li>\n
- Who Is the Operator<\/strong>\u2014Companies with large leases may pay differently from those with smaller ones; and some with a more aggressive drilling plan may pay more than those focused on capital discipline\u2014meaning paying dividends to investors\u2014instead of drilling.<\/li>\n
- Number of Wells Already Drilled<\/strong>\u2014The presence of existing wells means nearby production is proven and at least somewhat predictable for the buyer, reducing risk and possibly increasing what they are willing to pay you.<\/li>\n
- Number of Wells Yet to be Drilled<\/strong>\u2014If the producer is planning to drill more wells in an existing field, this can boost the price of your royalties because buyers expect them to pay off.<\/li>\n
- Production from Nearby Wells<\/strong>\u2014Similar to number of wells already drilled.<\/li>\n
- Decline Curve for Existing Wells<\/strong>\u2014Shale wells, the current focus of almost all oil companies, produce the vast majority of their oil in the first two years, while vertical wells may maintain much of their production level for decades. So if your minerals involve mostly older shale wells, their value will be lower than where there is current\/future drilling.<\/li>\n
- Nearby Pipeline Infrastructure<\/strong>\u2014Three main things come from a well: oil, natural gas, and water, and all must have somewhere to go (known as takeaway capacity) for the minerals to have value. Natural gas is currently the most challenged of the three, but takeaway capacity for any of the three depends on your minerals\u2019 location.<\/li>\n
- Oil and Gas Pricing<\/strong><\/a>\u2014Driving seasons, supply\/demand, pipeline availability, world events, and other variables affect this locally and worldwide.<\/li>\n
- Royalty Rate<\/strong>\u2014This is your percentage of the sales price of the produced minerals on your lease, typically 12.5%-25%. This affects the price buyers will offer.<\/li>\n
- Active Permits\u2014<\/strong>When permits are active, the paperwork is in place for drilling to begin. That speeds up the drilling process, which can cause buyers to bid higher.<\/li>\n
- Expired Permits\u2014<\/strong>If permits for your area have expired, the renewal process could delay drilling and production of your minerals, reducing the buyer\u2019s bid. Or it could mean producers have decided there are no minerals to be profitably produced at current prices, so there might never be production in that area. In that case mineral rights bids could be low or non-existent.<\/li>\n
- Surrounding Permit Activity\u2014<\/strong>If your minerals are in a newly permitted area the value may be lower because production there hasn\u2019t been proven. Where there are existing permits and activity buyers usually pay more.<\/li>\n
- Surrounding Rig Activity<\/strong>\u2014Rig activity leads to production, leading to profits for minerals buyers, increasing what they may pay for your minerals. Less rig activity may mean producers feel there are few or no more prospects to be drilled.<\/li>\n
- Many other factors are also in operation.<\/li>\n<\/ul>\n
That\u2019s an overview of the big picture. Now let\u2019s examine some processes buyers use to evaluate minerals.<\/p>\n<\/div>
Ways Buyers Evaluate Minerals, and Why Offers Vary<\/h2><\/h2><\/div>
Even when there is active drilling and production near your minerals, it\u2019s more complicated than simply learning what a neighbor\u2019s minerals are worth. Here are some reasons why.<\/p>\n
Let\u2019s say you have mineral rights with a 12.5% lease, and there are eight horizontal wells on your land. Meanwhile, your neighbor has a 25% lease but it contains only one vertical well from 1950. A couple of months ago a major operator started drilling ten new wells on their section.<\/p>\n
Even though you\u2019re just next door, your mineral rights might be worth $1,000 per acre, while your neighbor\u2019s could be $30,000 or more per acre. The difference would likely be based on factors like activity and lease terms.<\/p>\n
That\u2019s why there\u2019s no average price per acre for mineral rights. Every situation is unique. Your lease agreement terms, your lease royalty percentage, your ownership type<\/a>, etc. all make a difference in the average price per acre for mineral rights.<\/p>\n<\/div>
<\/div><\/div><\/div><\/div><\/div><\/a><\/span><\/div><\/a><\/span><\/div><\/div><\/div><\/div><\/div><\/div>\n<\/div><\/div><\/div><\/div><\/p>\n
Gross Acres vs Net Acres<\/h3>\n
<\/h3><\/span>
<\/div><\/div><\/div>\nOne key detail in mineral values involves the difference between gross acres<\/strong> and net acres<\/strong>.<\/p>\n
Gross acres<\/strong> measures the physical location of your ownership. You\u2019ll see these on your deed or lease\u2014usually as round numbers like 40, 80, or 160 acres. That\u2019s where many owners assume they own more than they actually do.<\/p>\n
But when it comes to calculating value<\/strong>, all that matters is your net mineral acres<\/strong>\u2014your actual ownership portion of those gross acres. That number is rarely listed clearly, and can be tricky to figure out, but here are some key factors.<\/p>\n
To determine your net mineral acres, you\u2019ll need revenue statements or a division order\/payment document, and you might need some experienced help to understand the often technical language.<\/p>\n<\/p>\n
<\/p>\n
How Mineral Buyers Use Net Royalty Acres to Compare Values<\/h3>\n
<\/h3><\/span>
<\/div><\/div><\/div>\nIf you\u2019ve encountered the term \u201croyalty acre<\/strong>\u201d or \u201cnet royalty acre<\/strong>,\u201d it can be confusing. Here\u2019s what those are about:<\/p>\n
Mineral buyers<\/a> use net royalty acres to make \u201capples to apples\u201d comparisons. It helps them evaluate deals consistently in the fact of varying lease terms.<\/p>\n
It all comes down to your lease rate<\/strong>\u2014specifically, the royalty percentage in your lease.<\/p>\n
Here is a simple explanation:<\/p>\n
1 net mineral acre leased at 12.5% = 1 net royalty acre<\/strong><\/p>\n
1 net mineral acre leased at 25% = 2 net royalty acres<\/strong><\/p>\n
The difference you see there is because a 25% lease pays double the royalty rate of a 12.5% lease. To a buyer it\u2019s worth twice as much royalty-wise.<\/p>\n
Net royalty acres let buyers calculate how much income interest they\u2019re really buying, regardless of lease differences. It\u2019s a quick way to compare different owners in the same area\u2014even on the same well.<\/p>\n<\/div>
<\/div><\/div><\/div><\/div><\/div>Location, Location, Location<\/h2><\/h2><\/div>
The major producing basins, unsurprisingly, are usually where minerals are of the highest value. Buyers<\/a> in active Texas<\/a> basins may pay more than for minerals in lower production areas such as Wyoming. In high production areas, there is abundant drilling activity as producers expand not only in acreage but in depth. The Permian, for example, has many layers of productive zones stacked under the surface, some of which still have less-tapped zones, allowing them to continue to increase production.<\/p>\n
Example 1: Core vs Edge Areas (Permian\/Texas)<\/strong>
\nEven within the same basin, values can vary widely. A mineral interest in a highly production county like Midland or Martin have very few locations that are not attractive to buyers.\u00a0 In contrast, interests on the edges of other counties may be less attractive due to thinner rock and less consistent production results, which can reduce how aggressive buyers price them.<\/h4>\nExample 2: Operator Quality<\/strong>
\nEven within the same county, value can vary depending upon the operator. A well operated by a large active company with a history of consistent drilling and strong performance may attract stronger offers than a similar interest under a smaller operator with limited activity or less drilling success<\/h4>\nExample 3: Producing vs Undeveloped<\/strong>
\nTwo properties in the same county can be valued very differently depending on development status. A producing property with established wells provides more predictable cash flow, while an undeveloped property may be valued based on its future potential.\u00a0 That potential can vary widely depending upon location and operator quality which may lead to greater offer price variation.<\/h4>\n<\/div><\/div><\/div><\/div><\/div><\/div> - Who Is the Operator<\/strong>\u2014Companies with large leases may pay differently from those with smaller ones; and some with a more aggressive drilling plan may pay more than those focused on capital discipline\u2014meaning paying dividends to investors\u2014instead of drilling.<\/li>\n
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