If you inherited mineral rights from a parent or grandparent, there's a good chance those rights were valued — or dismissed — based on a world that no longer exists. Vertical drilling, which was standard practice for most of the 20th century, could only pull oil and gas from a narrow column of rock directly below the drill bit. Horizontal drilling changed everything. A single well can now run sideways through a rock formation for two miles or more, unlocking reserves that were completely uneconomical to produce twenty years ago.
That shift didn't just change how oil companies operate. It changed what your mineral rights are worth — sometimes dramatically. Rights that sat idle for decades suddenly became valuable. In some cases, people who thought they owned worthless paper discovered they were sitting on assets worth tens or hundreds of thousands of dollars. In other cases, mineral owners who sold early, before operators figured out how productive a formation could be, left significant money on the table.
By the end of this article, you'll understand how horizontal drilling works in plain terms, why it caused mineral rights values to spike in specific states and formations, what "multi-zone rights" means and why it matters if you own minerals, and how to think about what your rights might be worth today — whether you're considering selling or just trying to understand what you have.
What Horizontal Drilling Actually Is (And Why It Matters to You)
For most of oil and gas history, drilling meant going straight down. Engineers would identify a reservoir — an underground layer of porous rock holding oil or gas — drill a vertical hole to reach it, and pump out whatever they could. This worked fine when reservoirs were thick, concentrated, and easy to reach. But many of the most oil-rich formations in the United States are thin, flat layers of rock called shale — sometimes only 50 to 100 feet thick — spread horizontally across hundreds of thousands of acres.
A vertical well through a 100-foot-thick shale layer only contacts 100 feet of the rock. Horizontal drilling changed that equation entirely. After drilling down to the target depth, engineers gradually curve the wellbore — using GPS-guided drill bits — until it's running horizontally through the formation. A well drilled into the Permian Basin in West Texas might now run laterally for 15,000 feet (almost three miles) through the same rock layer. Instead of contacting 100 feet of productive shale, that well contacts 15,000 feet of it.
The economic implications are enormous. Horizontal wells cost more to drill — typically $5 million to $12 million depending on depth and length — but they produce far more oil and gas. That productivity, spread across the same surface footprint as a vertical well, transformed formations that were previously uneconomical into some of the most productive oil fields in the world. The Permian Basin in Texas, the Bakken in North Dakota, the Marcellus in Pennsylvania, the SCOOP and STACK plays in Oklahoma, and the DJ Basin in Colorado all went from modest producers to global energy powerhouses within roughly a decade.
How Valuations Changed — And Where They Changed Most
Before the shale revolution, mineral rights in many areas were valued based on what vertical drilling could produce. A mineral acre (one acre's worth of mineral rights) in a moderately productive area might have sold for $500 to $2,000. By the early 2010s, after horizontal drilling proved out major formations, those same mineral acres in prime locations were selling for $10,000, $20,000, or more. In the core of the Permian Basin, mineral acres have traded above $50,000 in recent years.
The appreciation wasn't uniform — it tracked directly where horizontal drilling proved most productive. Here's how it played out in the states most relevant to you:
Texas saw the most dramatic transformation. The Permian Basin — which covers a massive area of West Texas and southeastern New Mexico — became the most-drilled basin in the world. Mineral owners in Midland, Martin, Howard, and Upton counties saw values multiply ten to thirty times between 2010 and 2020. The Eagle Ford Shale in South Texas (running through counties like Webb, La Salle, Karnes, and DeWitt) created similar appreciation. If your family owned minerals in these counties and the rights sat quiet for decades, that doesn't mean they're still quiet. Operators have been working through those areas systematically.
North Dakota sits largely over the Bakken Shale and the Three Forks formation directly beneath it. Before horizontal drilling, North Dakota was a modest oil state. After, it became the second-largest oil-producing state in the country for a stretch. Mineral acres in Mountrail, McKenzie, Williams, and Dunn counties — the core Bakken counties — went from a few hundred dollars per acre to $3,000–$15,000 per acre and higher in the best areas. Many families who inherited North Dakota farmland had mineral rights attached to the surface deeds and didn't even know it until operators started calling.
Pennsylvania is different in character because the major formation there — the Marcellus Shale — is primarily a natural gas play rather than oil. The Marcellus is one of the largest natural gas fields ever discovered in North America. Northeast and north-central Pennsylvania, particularly Susquehanna, Bradford, Lycoming, and Tioga counties, saw mineral values surge. Gas prices are more volatile than oil prices, so values have fluctuated more, but mineral owners in the core Marcellus counties who signed leases in the 2008–2012 period often received signing bonuses of $3,000–$5,000 per acre — money that had been essentially zero before horizontal drilling arrived.
Multi-Zone Rights: Why the Same Acre Can Now Be Worth More Than It Used to Be
One of the most important concepts for mineral rights owners to understand — and one that most people with inherited rights have never heard explained — is "stacked pay" or multi-zone development. This is where the same horizontal drilling technology that unlocked one formation turns out to unlock several.
Here's what this means in practical terms: Below a piece of land, there might be three or four separate rock formations at different depths, each containing oil or gas. In the vertical drilling era, a company might have targeted the deepest, most productive layer and ignored the rest. Horizontal drilling made it economical to develop multiple zones separately. The same surface location can host several wells targeting different formations, and each one requires a separate lease or generates separate royalties.
In the Permian Basin, operators routinely develop the Spraberry, Dean, Wolfcamp A, Wolfcamp B, Wolfcamp C, and Bone Spring formations — six or more distinct targets stacked on top of each other. A mineral owner in Midland County doesn't just own the right to one formation; they typically own all the formations beneath their land (unless a previous owner severed the rights by formation, which does happen and is worth checking). Each formation that gets developed generates a separate royalty stream.
In North Dakota, the Three Forks formation sits directly beneath the Bakken and became a major secondary target as drilling technology improved. Mineral owners who signed early Bakken leases didn't always capture Three Forks rights explicitly, which led to disputes. If you own minerals in North Dakota, it's worth having someone look at your lease language to make sure you're covered for formations other than the one originally targeted.
In Pennsylvania's Marcellus territory, the Utica Shale sits deeper and has been developed as a secondary formation in some areas. The lease terms around which formations are covered, and at what royalty rate, matter considerably.
What this means practically: when someone asks what your mineral rights are worth, the answer now depends not just on where you are geographically, but on how many producible formations sit beneath your land. An acre that was worth $1,000 because of one formation might be worth three or four times that because of three formations — all accessible with horizontal drilling.
Longer Laterals, Bigger Wells, and What They Mean for Royalty Payments
The length of a horizontal well's lateral section — the horizontal part — has gotten dramatically longer over the past decade. In the early days of shale drilling (roughly 2008–2012), a 5,000-foot lateral was considered a long well. Today, 10,000-foot laterals are standard, 15,000-foot laterals are common, and some operators in the Permian Basin are drilling 20,000-foot laterals.
Why does this matter to you as a mineral rights owner? Because longer laterals produce more oil and gas, and they affect how your royalties are calculated — and how many of your acres are held by a single lease.
Most oil and gas leases pay royalties as a percentage of production. Common royalty rates range from 12.5% (one-eighth) on older leases to 20–25% on leases negotiated in competitive areas during high-demand periods. A 20% royalty on a highly productive Permian Basin well producing 1,000 barrels of oil per day (at $70 per barrel) generates $14,000 per day in royalties. Even divided among multiple mineral owners in a pooled spacing unit — the legal area that defines which mineral owners share in a single well's production — that's meaningful income.
Longer laterals also changed which mineral acres get developed. A 15,000-foot lateral running through your property holds your lease (keeps it active) under the standard "held by production" clause, meaning the company doesn't have to renew. If that lateral runs across the property line and into a neighbor's land, it holds both leases. Understanding where a proposed lateral is actually going, and which of your acres it will cross, requires looking at plat maps and sometimes hiring a landman (a professional who specializes in researching and negotiating mineral rights) to review your situation.
One important caveat here: not all mineral acres benefit equally from longer laterals. Acreage on the far edge of a productive formation, or in counties where the geology isn't as favorable, won't see the same uplift as core acreage. Don't assume that because a neighboring county is booming, your minerals in the adjacent county are equally valuable. Geology doesn't follow county lines.
What Areas Saw the Biggest Appreciation — And What's Still Developing
The formations that saw the sharpest appreciation are the ones where horizontal drilling proved most productive earliest. But the story isn't finished. Some areas are still in relatively early stages of development, which means mineral values haven't fully reflected what's underneath the ground.
In Texas, the Midland Basin side of the Permian has been heavily drilled, but the Delaware Basin — which covers parts of West Texas and southeastern New Mexico — is still in active development, and some portions of it remain under-drilled relative to their ultimate potential. The Eagle Ford is more mature but continues to see activity.
In North Dakota, drilling activity tracks closely with oil prices. When prices dropped in 2015–2016 and again in 2020, activity slowed significantly. It came back as prices recovered. Mineral owners in the Bakken core have seen values recover from those troughs, but North Dakota rights are more sensitive to oil price swings than some other formations because the economics are tighter.
In Pennsylvania, natural gas prices are the key variable. The Marcellus is a world-class gas field, but low U.S. natural gas prices in 2019–2020 suppressed both drilling activity and mineral values. With LNG (liquefied natural gas) export infrastructure growing and domestic demand for gas increasing, many analysts expect Marcellus activity to increase — which would support higher mineral values for Susquehanna, Bradford, and surrounding county owners.
In Oklahoma, the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher counties) plays generated enormous excitement and mineral value appreciation in the 2014–2018 period. Some of that enthusiasm has been tempered by variable well results and operator consolidation, but significant activity continues.
In Colorado, the DJ Basin — centered in Weld County — has been one of the more productive horizontal oil plays in the country. Companies like Civitas Resources, Chevron, and SandRidge have been active there. Mineral values in Weld County have appreciated substantially, though Colorado's regulatory environment for oil and gas has become more restrictive, which introduces some additional uncertainty.
How to Think About What Your Rights Might Be Worth Today
The single most common mistake mineral rights owners make is assuming that because they haven't heard from an oil company in years, their minerals aren't worth anything. That assumption is often wrong. Operators work through acreage systematically, and the sequence in which they contact landowners has more to do with their internal drilling plans than with whether your land has value.
Here's a practical framework for thinking about your situation:
Check whether your minerals are leased or unleased. If they're currently under a lease, you're entitled to royalties if a well is drilled. If they're unleased, you have the ability to negotiate a new lease — or sell the minerals outright. Both options have value.
Look at what's happening within five miles of your land. The Texas Railroad Commission (for Texas minerals), the North Dakota Industrial Commission, the Pennsylvania Department of Environmental Protection, and similar agencies in Oklahoma and Colorado all maintain publicly accessible well databases. If wells have been drilled near your land in the last five years, that's a strong signal your minerals have active value.
Know your royalty rate before you assume anything about value. If you're receiving royalty checks and don't know what percentage rate you're being paid, find your lease document and look for the royalty clause. A 12.5% royalty on a producing well generates half the income that a 25% royalty would. If you're being paid on an old lease with a low royalty rate, selling the minerals outright might generate more money than continuing to receive those checks — depending on your tax situation and how long you'd expect production to continue.
Understand the tax implications before you make any decision. Mineral rights sales are generally treated as capital gains. If you inherited your rights, your cost basis is typically the fair market value at the time of inheritance — which often means your taxable gain is smaller than you might fear. Federal long-term capital gains rates are 0%, 15%, or 20% depending on your income. Some states add their own tax. This is worth a conversation with a CPA who understands mineral rights before you sign anything.
If you'd like to know what your mineral rights might be worth today, reach out to us through this site. A real person — not an automated system — will call you back within one business day. That call is a conversation, not a sales pitch. We'll ask you a few basic questions about where your minerals are located and what you know about them, and we'll give you an honest assessment of whether we think they have significant value and what your options are. There's no commitment required and no pressure to sell. A lot of people just want to understand what they have, and that's a completely reasonable place to start.