Oil and gas law is the body of property, contract, and regulatory rules that decides who owns the hydrocarbons under a piece of land, how those resources can be leased and extracted, and what financial, environmental, and cleanup obligations follow. It is largely state law for onshore private-land operations and federal law for public lands and offshore drilling, which means the specific answer to almost any question depends on where the well sits.
Who Owns the Oil and Gas Underground
In the United States, a landowner can separate the rights to the surface from the rights to the minerals below it. Once that separation happens, through a mineral deed or a reservation clause in a transfer, you have a split estate: one party owns the surface, another owns the minerals. Each interest is its own piece of real property. It can be sold, leased, inherited, or taxed on its own.
The mineral estate is generally treated as the dominant estate. The mineral owner has an implied right to use the surface to the extent reasonably necessary to reach the resources below, because without some ability to enter, build roads, and set equipment, the mineral interest would be worthless.1Bureau of Land Management. Leasing and Development of Split Estate That dominance is not unlimited. Operators are expected to show reasonable regard for the surface owner’s existing uses.
When the two interests collide, many courts apply the accommodation doctrine. If a mineral developer can extract the resource using an alternative method that avoids destroying the surface owner’s existing use, the developer is expected to use it. The surface owner does not get a veto, but the operator does have to look for less disruptive options when they exist and are economically feasible.
The Rule of Capture and Correlative Rights
The rule of capture is one of the oldest doctrines in the field. Oil and gas are treated like fugitive resources: if you produce them from a well on your own property, they belong to you, even if some of them migrated from beneath a neighbor’s land. The neighbor’s remedy is not a trespass suit. It is to drill their own well.
Left alone, that rule rewards speed above everything else and encourages operators to drain reservoirs faster than they should. The doctrine of correlative rights pushes the other way. Each owner sharing a common reservoir must exercise the right to produce without unreasonably harming the formation itself. An operator who ruins reservoir pressure, drills recklessly, or produces purely to drain a neighbor out of spite can face liability. Modern conservation rules on well spacing and production limits grew directly out of the tension between these two ideas.
How an Oil and Gas Lease Works
The primary legal vehicle for development on private land is the oil and gas lease. It is both a contract and a conveyance of a real property interest. The landowner (lessor) grants the operator (lessee) the right to explore for, extract, and sell hydrocarbons from the leased acreage. Three clauses do most of the economic work.
The Habendum (Term) Clause
This clause controls how long the lease lasts. It sets a primary term, a fixed number of years during which the operator must begin drilling. One to five years is common on private leases in proven areas; frontier areas can still see longer terms. Federal onshore leases carry a fixed primary term of ten years set by statute.2Office of the Law Revision Counsel. 30 USC 226 – Lease of Oil and Gas Land
If the operator achieves production before the primary term ends, the lease rolls into its secondary term and stays in effect as long as the well produces “in paying quantities.” That phrase has a specific legal meaning. Revenue from production must exceed ongoing operating costs, even if the operator never recoups the original drilling investment. If production drops below that line and stays there, the lease can terminate.
The Royalty Clause
The royalty clause sets the landowner’s financial share. For decades, the standard private-land royalty was one-eighth, or 12.5 percent of gross production. In active drilling regions, landowners now routinely negotiate higher rates. Federal onshore leases require a royalty of at least 12.5 percent of the value of production removed or sold.2Office of the Law Revision Counsel. 30 USC 226 – Lease of Oil and Gas Land That minimum has shifted recently at the federal level, with the One Big Beautiful Bill Act returning the floor to 12.5 percent for new federal leases after an earlier increase.3Bureau of Land Management. Interior Advances Energy Dominance Through One Big Beautiful Bill Act The landowner’s royalty is cost-free. The lessor pays no share of drilling or operating expenses.
Implied Covenants
Even when a lease says nothing about an operator’s obligations beyond royalties, courts read in a set of implied promises based on what a reasonably prudent operator would do.
- Reasonable development. After a discovery, the operator must drill enough additional wells to adequately develop the acreage, not sit on a single producing well indefinitely.
- Protection against drainage. If a well on neighboring land is pulling oil or gas from beneath the leased tract, the operator must take reasonable steps to protect the lessor, typically by drilling an offset well. The duty applies only when a protective well would have a reasonable expectation of turning a profit.
- Marketing. The operator must diligently seek a buyer and cannot simply shut in a well while available markets go unexplored.
Breach of an implied covenant can lead to lease cancellation or damages, so these are real obligations and not aspirational language.
Who Gets Paid: Types of Production Interests
Revenue from a well flows through several distinct interests, each with its own rights and cost obligations.
- Royalty interest. A share of production free of drilling and operating costs. The original landowner typically holds this and gets paid regardless of whether the project is profitable overall for the operator.
- Working interest. The operator’s interest, carrying the full financial burden of drilling, completing, and maintaining the well. Working interest owners pay for rigs, labor, equipment, and environmental compliance. They receive whatever revenue remains after royalties.
- Overriding royalty interest. A cost-free interest carved out of the working interest, often used to compensate geologists, landmen, or others who helped assemble the deal. It expires when the underlying lease ends.
- Non-participating royalty interest. A share of production revenue without the executive rights a full mineral owner has. The holder cannot negotiate or sign leases, does not receive bonus or rental payments, and has no say in development.
The split between cost-bearing and cost-free interests matters enormously. A working interest owner who drills a dry hole absorbs the entire loss. A royalty owner risks nothing but also has no control over the pace or method of development.
Who Regulates Drilling
State and federal agencies regulate nearly every phase of oil and gas development, and the regulatory picture depends on where the operation sits.
State Conservation Rules
Each oil-producing state has an agency charged with preventing waste and protecting the correlative rights of mineral owners. These agencies set well-spacing rules that dictate how far apart wells must be and how much acreage each one must cover. Spacing maintains underground pressure, maximizes recoverable oil, and prevents operators from drilling unnecessary wells that damage the reservoir.
When a drilling unit includes tracts owned by different parties and one refuses to participate, most states authorize compulsory pooling. That mechanism forces the holdout’s acreage into the unit so a single owner cannot block development of an entire reservoir. Roughly 40 states have some form of compulsory pooling statute. The holdout still gets compensated, with the specific terms varying by jurisdiction. Unitization is a related but broader tool, used to manage an entire reservoir as one coordinated operation, which matters most for secondary and tertiary recovery projects like water flooding or carbon dioxide injection.
Federal Lands and Offshore
Drilling on federal public lands requires a lease from the Bureau of Land Management under the Mineral Leasing Act and the National Environmental Policy Act. NEPA requires agencies to evaluate environmental effects before approving drilling, either through a full environmental impact statement for major projects or an environmental assessment for smaller ones. Congress has also authorized categorical exclusions for repeat drilling on previously developed sites.4Bureau of Land Management. NEPA
Offshore, the jurisdictional line between state and federal authority sits at three nautical miles from the coastline for most states. Texas, Florida’s Gulf coast, and Puerto Rico are exceptions, with state jurisdiction extending to nine nautical miles.5Bureau of Ocean Energy Management. Outer Continental Shelf Beyond those lines lies the Outer Continental Shelf, where the federal government holds exclusive leasing authority under the Outer Continental Shelf Lands Act. Federal law and the Constitution apply to the OCS seabed, along with the civil and criminal laws of the adjacent state to the extent they do not conflict with federal law.6Office of the Law Revision Counsel. 43 USC Chapter 29 Subchapter III – Outer Continental Shelf Lands
Environmental Rules Operators Face
Environmental compliance is one of the costliest parts of operating a well. Several federal statutes create overlapping layers of obligation.
Clean Water Act
The Clean Water Act is the main federal law on water pollution from oil and gas operations. It regulates discharges of pollutants into navigable waters, including produced water and drilling fluids.7Environmental Protection Agency. Clean Water Act (CWA) Compliance Monitoring Violations carry civil penalties set by statute at up to $25,000 per day per violation, with inflation adjustments pushing the actual figure higher.8Office of the Law Revision Counsel. 33 USC 1319 – Enforcement Oil spills trigger a separate penalty framework under the same statute, with per-barrel penalties that climb sharply when a spill results from gross negligence or willful misconduct.9Office of the Law Revision Counsel. 33 USC 1321 – Oil and Hazardous Substance Liability
Safe Drinking Water Act and Hydraulic Fracturing
The Safe Drinking Water Act protects underground sources of drinking water through the Underground Injection Control program, which normally regulates anything placing fluids underground. Hydraulic fracturing received a broad carveout. The Energy Policy Act of 2005 amended the definition of “underground injection” to exclude fluids and propping agents used in fracturing operations tied to oil, gas, or geothermal production. The one exception: if an operator uses diesel fuel as a fracturing fluid, the exemption does not apply.10Congress.gov. Hydraulic Fracturing and Safe Drinking Water Act Regulatory Issues In practice, most fracturing is regulated by state agencies rather than the EPA.
NEPA and the Endangered Species Act
Federal land operations also go through NEPA review before drilling permits are approved. The Endangered Species Act adds another layer, requiring federal agencies to ensure their actions, including lease approvals, do not jeopardize endangered species or destroy critical habitat. These reviews can delay or block operations in sensitive areas, though exemption mechanisms exist for projects deemed critical to national interests.
How Oil and Gas Income Is Taxed
Oil and gas investments carry a distinctive tax profile with deductions that do not exist elsewhere.
When a landowner signs a lease, the operator typically pays an upfront bonus, often a dollar figure per acre. That bonus is ordinary income reported on Schedule E and is not subject to self-employment tax. Ongoing royalty payments are also ordinary income, offset in part by the depletion allowance below.
Independent producers and royalty owners can claim a percentage depletion deduction equal to 15 percent of gross income from an oil or gas property.11Office of the Law Revision Counsel. 26 USC 613A – Limitations on Percentage Depletion in Case of Oil and Gas Wells The deduction cannot exceed 65 percent of taxable income from the property in any given year, but disallowed amounts carry forward. Unlike cost depletion, which stops once you recover your investment, percentage depletion can continue for the life of the well. Major integrated oil companies are not eligible and must use cost depletion instead.
Working interest owners can elect to deduct intangible drilling and development costs in the year they are incurred, rather than capitalizing and depreciating them over time.12Office of the Law Revision Counsel. 26 USC 263 – Capital Expenditures Intangible drilling costs cover everything spent on drilling that has no salvage value: labor, fuel, chemicals, hauling, and similar items. They typically run 70 to 80 percent of total well costs, which makes the deduction extremely valuable.
Most oil-producing states also impose a severance tax on the value of hydrocarbons extracted inside their borders. Rates vary widely, from roughly 2 percent to 10 percent or more of gross production value, with some states taxing net value instead. Producers pay the tax, but it effectively reduces revenue available for royalty payments and working interest returns. Some states offer reduced rates or exemptions for new wells, low-producing wells, or enhanced recovery.
Plugging Wells and the Orphaned Well Problem
Every well eventually stops producing, and the operator is legally responsible for plugging it, removing surface equipment, and restoring the site. State rules and federal regulations for public lands require operators to cement the wellbore shut so fluids cannot migrate between underground formations or reach the surface.13Bureau of Land Management. Orphaned Well Identification, Prioritization, and Plugging and Reclamation
When an operator goes bankrupt or disappears, the well becomes “orphaned”: no financially responsible party is left to pay for plugging. The United States has hundreds of thousands of documented orphaned wells, many leaking methane or contaminating groundwater. The Infrastructure Investment and Jobs Act authorized $4.7 billion to identify, plug, and remediate orphaned sites through federal, state, and tribal programs.14Office of the Law Revision Counsel. 42 USC 15907 – Orphaned Well Site Plugging, Remediation, and Restoration
To keep more wells from reaching that state, regulators require operators to post financial assurance, usually a surety bond, before drilling. Bond amounts vary widely by state and well type, from a few thousand dollars for a single shallow well to blanket bonds covering an operator’s entire portfolio. Critics have long said bond amounts are far below actual plugging costs, which can run into the hundreds of thousands of dollars for deep or offshore wells. The gap between required bonds and real-world cleanup costs is one of the most persistent problems in oil and gas regulation.15U.S. Department of the Interior. Orphaned Wells