To own an oil well, you buy or lease an interest in the well itself or in the minerals beneath the ground, and the kind of interest you pick decides everything that follows: your share of the revenue, whether you pay operating costs, how you’re taxed, and what you owe when the well is finally plugged. Learning how to own oil wells is really learning to tell those interests apart before you sign anything.
Mineral rights in the United States can be severed from the surface and held, sold, and inherited on their own. That’s what makes private ownership possible in the first place. Once you know which type of interest fits your appetite for risk and involvement, the acquisition path, the deed work, the tax treatment, and the environmental exposure all follow from that choice.
The Interests You Can Actually Own
Working Interest
A working interest is the operator’s side of the well. You pay a proportional share of drilling, completion, equipment, and operating costs, and in exchange you receive a larger share of production revenue than passive holders do. If the well is dry or output falls, the bills keep arriving. Working interest owners are also on the hook for regulatory compliance and environmental obligations at the site.
Royalty Interest
A royalty interest pays you a share of gross production with no obligation to fund drilling or operations. Royalties typically run 12.5% to 25%, and can reach roughly a third depending on the lease.1St. Mary’s Law Journal. Fundamentals of Oil and Gas Royalty Calculation Whether that share is paid in oil, in wellhead value, or as a percentage of the actual sale price is written into the royalty clause, and the wording controls how transportation and processing costs eat into your check. Income is steadier than a working interest, but you have no voice in how the well is run.
Overriding Royalty Interest
An overriding royalty is carved out of the working interest rather than reserved from the mineral estate. Geologists, landmen, and other deal participants sometimes take one as compensation. The holder pays no operating costs, but the interest lives only as long as the underlying lease. When the lease expires or the well is abandoned, the override is gone.
Net Revenue Interest
Your net revenue interest is the decimal share of revenue you actually receive after every royalty burden is subtracted from your working interest. Own 50% of a working interest that carries a 20% royalty, and your net revenue interest is 40% (50% of the 80% left after royalty). That decimal is what shows up on your division order and drives every monthly check. Confusing working interest with net revenue interest is one of the more expensive early mistakes because it inflates every cash-flow estimate you make.
How to Acquire an Interest
Buying Mineral Rights Outright
Buying minerals in fee simple gives you ownership of the underground resources regardless of who holds the surface. In much of the country, minerals were severed generations ago, so separate mineral estates are commonly available. Investors watch county deed records and online mineral marketplaces to find sellers. Owning the minerals lets you negotiate a lease with an operator on your own terms, including royalty percentage, bonus, and lease duration.
Federal Lease Sales
The Bureau of Land Management holds competitive online lease sales for oil and gas development on federal lands. A winning bid produces a lease with a primary term of ten years, and it continues past that term for as long as the well produces in paying quantities.2Office of the Law Revision Counsel. 30 USC 226 – Leasing Bidders must be qualified and pay a per-acre bonus plus annual rentals. If drilling doesn’t begin during the primary term, delay rentals keep the lease alive; miss a payment deadline and the lease terminates automatically.
Private Purchases of Existing Interests
You can buy an existing working interest, royalty interest, or mineral estate directly from the current owner. Due diligence carries the deal. Verify the lease is still in force, confirm reported production against state commission records, and review any outstanding obligations. Mature wells give you a known production history and predictable cash flow; undeveloped acreage costs less and carries more risk. Prices move with commodity prices, so comparable sales matter.
Private Offerings and Investor Qualifications
Many oil and gas ventures raise capital through private securities offerings limited to accredited investors. To qualify as an individual, you need either a net worth over $1 million excluding your primary residence, or annual income above $200,000 ($300,000 with a spouse) for each of the prior two years with a reasonable expectation of the same this year.3U.S. Securities and Exchange Commission. Accredited Investors A promoter who never asks whether you meet those thresholds is a promoter to walk away from.
Getting the Paperwork Right
Mineral Deeds Versus Lease Assignments
The right document depends on what’s being transferred. A mineral deed permanently conveys ownership of the underground resources. An assignment of lease transfers your contractual rights under an existing oil and gas lease, including any working interest or override carved from that lease. Using the wrong instrument can cloud title for years.
Either document must include the full legal names of grantor and grantee, a precise legal description of the land using township, range, and section from official surveys, and the exact fractional interest being conveyed. Rounded or vague interest descriptions produce disputes.
Title Search
Run a title search before you sign. A landman traces ownership backward through county records, looking for breaks, conflicting conveyances, and prior mineral reservations. Language like “save and except all oil, gas, and other minerals” or “subject to all prior mineral reservations of record” flags that someone up the chain kept the minerals when they sold the surface. Searches usually cost $500 to $2,000 depending on how many transactions sit in the property’s history. Unresolved liens, incomplete probates, or old reservations can leave you with less than you paid for, or nothing.
Recording
After both parties sign and a notary acknowledges the deed, record it with the county clerk or recorder of deeds. Recording puts the world on notice and protects your ownership against later claims. Fees are generally under $50 plus a small per-page charge. Delay is dangerous: until it’s on the public record, your interest can be defeated by someone who records first.
Division Orders
Once your deed is recorded, notify the operator and request a division order. That document tells the operator the exact decimal share of revenue to send you and sets the effective date, payment timing, and minimum payout threshold. No division order, no check. If there’s any ambiguity about ownership, revenue goes into a suspense account instead. Title disputes, incomplete probate, missing tax forms, and misspelled names all trigger suspense, and money can sit there for months. Clean, complete documentation with the initial request is the shortest path around it.
Federal Filings
Transfers involving a BLM-managed lease must be filed with the appropriate BLM State Office. For fiscal year 2026, the filing fee for an assignment or transfer of record title or operating rights is $120, and overriding royalty transfers cost $15; BLM adjusts these annually.4Bureau of Land Management. Fixed Filing Fees The transfer takes legal effect under state law on the date in the deed, not the date BLM processes it, but prompt filing keeps BLM records current.5Bureau of Land Management. Transfers of Interest State oil and gas commissions may have their own notification rules, especially for working interest owners who must keep bonding and contact information current.
What Ownership Does to Your Tax Return
Oil and gas interests get tax treatment that changes the economics in ways most investments can’t match. Working interest owners see the biggest benefits, but royalty holders get some as well.
Intangible Drilling Costs
Working interest owners can elect to deduct intangible drilling and development costs in the year they’re paid or incurred rather than capitalize them over the life of the well.6Office of the Law Revision Counsel. 26 USC 263 – Capital Expenditures Intangibles include labor, chemicals, mud, grading, and other costs that leave no salvage value, and they often run 60% to 80% of total drilling cost. The upfront deduction can be substantial.
Percentage Depletion
Independent producers and royalty owners can claim a percentage depletion allowance equal to 15% of gross income from the property, capped at 65% of taxable income.7Office of the Law Revision Counsel. 26 USC 613A – Limitations on Percentage Depletion in Case of Oil and Gas Wells Unlike cost depletion, percentage depletion can exceed your original investment in the property, which is unusual in the tax code. Major integrated oil companies are excluded; the benefit is reserved for smaller independents and royalty owners.
The Passive Loss Carve-Out
Passive activity losses generally can’t offset active income, but working interests get a specific exception. Losses from a working interest are not treated as passive activity losses so long as you hold the interest directly or through an entity that doesn’t limit your personal liability.8Office of the Law Revision Counsel. 26 USC 469 – Passive Activity Losses and Credits Limited Material participation isn’t required. A first-year drilling loss can offset wages or business income. Hold the same interest through an LLC or limited partnership that shields you from liability and the carve-out disappears.
Royalty Reporting
Operators report royalty payments of $10 or more in Box 2 of Form 1099-MISC.9IRS. Instructions for Forms 1099-MISC and 1099-NEC The amount reported is gross royalties before severance taxes or other withholding. You report the income on your federal return and claim depletion and other deductions separately. State severance taxes vary widely and are usually withheld at source.
What You Owe When the Well Stops Producing
A working interest carries environmental obligations that outlast the well’s productive life. Under federal law, current owners and operators face strict, joint and several liability for cleaning up hazardous substance contamination, even without any role in causing the release.10Office of the Law Revision Counsel. 42 USC 9607 – Liability The EPA can pursue any single owner for the full cleanup cost regardless of proportional share. In oilfield operations, produced water, drilling fluid, and surface spills all put this liability in play.
Every well must eventually be plugged and its surface restored. On federal leases, BLM holds the responsible party liable from the moment the well is drilled until reclamation is complete, and selling your interest doesn’t release you: if you transfer, you remain liable for plugging wells that existed at the time of the transfer.11Bureau of Land Management. Protecting Taxpayers and Communities from Orphaned Oil and Gas Wells on Public Lands Operators who don’t plug their wells land on a noncompliance list and can’t obtain new leases until they clear it.
Plugging costs vary with depth, location, and condition. Median cost runs roughly $20,000 for plugging alone and about $76,000 with surface reclamation included. BLM requires surety bonds to backstop these obligations. As of 2024, the minimum bond for an individual federal lease is $150,000, and statewide bonds must be at least $500,000.12Bureau of Land Management. Oil and Gas Bonding State bonding on private lands is separate and varies, but the principle carries: regulators want money set aside to close the well. Promotional materials tend to skim past this piece, and it’s where underfunded investors get into real trouble.