What Are Oil and Gas Royalties? A Plain-English Guide

Oil and gas royalties are payments a mineral owner receives from the sale of oil and gas produced from their land, without paying to drill or run the wells. In 2025, the Permian region alone produced 48% of all U.S. crude oil, according to the U.S. Energy Information Administration, which is why so many royalty portfolios hold interests there.

Key takeaways

• A royalty is a share of the money from oil and gas sold from a property. The royalty owner does not pay drilling or operating costs.
• Your check equals production times price times your decimal interest, minus severance taxes and, in some cases, post-production deductions.
• Royalty income rises and falls with oil and gas prices, the natural decline of each well, and whether operators keep drilling new wells.
• Under the 2020 Treasury regulations, mineral rights can count as real property for a 1031 exchange when state law treats them as real property. Confirm your situation with a CPA and attorney.
• Royalty programs built for 1031 exchanges usually hold many interests across several basins, run by third-party operators.
• Royalties carry real risk. Income can drop sharply, distributions are not guaranteed, the investment is illiquid, and you can lose your entire investment.

What are oil and gas royalties, in plain English?

Let me start with a simple picture.

Imagine you own a piece of land in West Texas. Deep under that land, there may be oil and natural gas. You don't want to drill a well yourself. Drilling one modern well can cost millions of dollars. It takes special crews, special equipment, and years of know-how.

So you sign a lease with an oil company. The company that drills and runs the well is called the operator. The operator pays all the costs to drill, finish, and run the well. In return, the operator keeps most of the money from the oil and gas it sells.

You keep a slice. That slice is your royalty. It is a percentage of the value of the oil and gas produced from your land. The lease spells out the percentage. You might see one-eighth (12.5%), three-sixteenths (18.75%), one-fifth (20%), or one-quarter (25%), depending on where and when the lease was signed.

Here is the key idea. The royalty owner gets paid from the top. You don't send the operator a check when a well needs repairs. You don't pay the drilling bill. You receive a share of the revenue. In many cases, you also pay your share of state production taxes, and sometimes some costs to get the oil and gas to market. I'll explain those below.

I'm Jerry Baker, founder of Baker 1031 Investments. My team and I help real estate investors build 1031 exchange plans. Over the last few years, more of the investors I talk with have asked about oil and gas royalties. Some royalty programs are now offered as replacement property for a 1031 exchange. So I wrote this guide to explain, in plain English, what royalties are, how they pay, what can go wrong, and who they may fit.

A quick note before we dig in. This guide is education, not tax or legal advice. Every exchange is different. Please confirm any decision with your CPA, your attorney, and your qualified intermediary. A qualified intermediary (QI) is the independent company that holds your sale money during a 1031 exchange so you never touch it.

Who are the people involved in an oil and gas royalty?

Before we compare interest types, it helps to know the players. There are usually four.

The mineral owner. This person or company owns the rights to the oil, gas, and other minerals under a piece of land. Sometimes the same person owns the surface too. Often they don't. In many states, the mineral rights can be split off and sold separately from the surface. That is called a "severed" mineral estate.

The operator. This is the oil and gas company that drills the wells and runs them day to day. It hires the crews, pays the bills, sells the oil and gas, and sends out royalty checks.

The working interest owners. These are the people or companies that pay the costs of drilling and running the wells. The operator is usually one of them. They take on the costs and keep most of the revenue.

The royalty owners. These are the people or entities that receive a share of revenue without paying the costs of drilling or running the wells.

One more term you'll see a lot is unit. Modern wells often drain oil and gas from under many tracts of land. State regulators usually let operators group those tracts into a single "unit" (sometimes called a spacing unit or pooled unit). Each owner in the unit gets paid based on how much of the unit they own. That will matter when we get to the math.

Mineral rights vs. royalty interests vs. working interests vs. overriding royalties

People often use these words as if they mean the same thing. They don't. Each one gives you different rights, different costs, and a different risk profile.

Here is a short definition of each.

Mineral rights (mineral interest). This is ownership of the oil, gas, and minerals in the ground. A mineral owner can usually sign leases, receive lease bonus payments, and keep a royalty. The mineral interest lasts until it is sold. It does not end when a lease ends.

Royalty interest. This is the right to a share of production revenue, free of drilling and operating costs. A royalty interest usually comes from mineral ownership. Some royalty interests are "non-participating." That means the owner gets the royalty but can't sign leases or receive bonus payments.

Working interest. This is the right to drill and produce, along with the duty to pay the costs. A working interest owner pays its share of drilling and operating expenses. It keeps the share of revenue left after the royalties are paid.

Overriding royalty interest (ORRI). This is a royalty carved out of the working interest, not out of the minerals. It is cost-free like a regular royalty. But it usually lasts only as long as the lease it is tied to. When the lease ends, the overriding royalty usually ends too.

Here is how they compare side by side.

When I talk about "royalty programs" later in this article, I mean programs that hold mineral and royalty interests. They do not hold working interests. That is a big deal. A working interest owner can get a bill for a new well or a costly repair. A royalty owner does not.

How is a royalty payment calculated?

This is the part most people find confusing at first. It is really just multiplication. Let me walk through the pieces.

Net revenue interest

Every well has a pie of revenue. The net revenue interest (NRI) is your slice of that pie, written as a decimal.

For a working interest owner, the NRI is the share of revenue left after all royalties come off the top. For a royalty owner, the NRI is simply the royalty share of the revenue.

Decimal interest

Your decimal interest is the exact number the operator uses to cut your check. It shows up on a document called a division order. A division order is a form the operator sends that lists your share of a well. It asks you to confirm it before payments start.

For a royalty owner in a unit, the decimal interest usually works like this:

Decimal interest = (net mineral acres you own ÷ total acres in the unit) × royalty rate in your lease

A net mineral acre is one acre of full mineral ownership. If you own half the minerals under 100 acres, you own 50 net mineral acres.

You'll also hear the term net royalty acre. It is a way to put royalty interests with different royalty rates on the same scale, so buyers can compare them. Different buyers and sellers define it in slightly different ways, so always ask how a seller defines it.

The basic formula

Once you know your decimal interest, the monthly check works like this:

Royalty check = (volume sold × price) × decimal interest − severance taxes − any allowed post-production deductions

Let me define the last two pieces.

Severance taxes are state taxes on oil and gas pulled out of the ground. Most producing states charge them. The rate depends on the state and the product. The operator usually takes your share of the tax out before it pays you.

Post-production deductions are costs to get oil and gas from the wellhead to a buyer. Examples include gathering, compressing, treating, and transporting gas. Whether these costs can be taken out of a royalty check depends on the wording of the lease and on state law. Some leases say "no deductions." Others allow them. Courts in different states have reached different answers. This is one reason I always want to see the lease terms, or at least a summary of them, before I'm comfortable with a royalty offering.

A simple worked example

Here is a made-up example with simple numbers. It is only meant to show how the math works.

Say you own 10 net mineral acres inside a 640-acre unit. Your lease gives you a 20% royalty (one-fifth).

Step 1: Find your decimal interest.

10 ÷ 640 = 0.015625

0.015625 × 0.20 = 0.003125

That is your decimal interest. It means you receive 0.3125% of the revenue from wells in that unit.

Step 2: Find the gross value of production for the month.

Say the wells in the unit sell 6,000 barrels of oil this month. Say the operator receives $70 per barrel.

6,000 × $70 = $420,000 of gross revenue

Step 3: Multiply by your decimal interest.

$420,000 × 0.003125 = $1,312.50

Step 4: Subtract severance taxes.

Say the state's severance tax is 5%. This is a round number I picked for the example. Real rates vary by state and product.

$1,312.50 × 5% = $65.63

$1,312.50 − $65.63 = $1,246.87

Step 5: Subtract any allowed post-production deductions.

Say your lease allows deductions, and your share is $40 this month.

$1,246.87 − $40 = $1,206.87

So your check for that month would be about $1,207.

Now look at what happens if things change. All other numbers stay the same.

(The last column assumes the same 5% tax and $40 of deductions, rounded.)

This table is the whole story of royalty income in one place. Your share of the wells doesn't change. But your check can swing a lot from month to month because price and volume both move.

What a royalty statement looks like

Each month, or each payment cycle, the operator sends a check stub or revenue statement. It usually lists:

• The well or unit name
• The production month (often two or three months before the payment date)
• The product (oil, gas, or natural gas liquids)
• Volume sold and the price received
• Your decimal interest
• Your gross share
• Taxes and any deductions
• Your net payment

Notice the production month. Royalty payments usually lag behind production. Oil sold in January might show up on a statement in March or later. New owners often wait months for their first check while the operator sets up their account. Many states set rules for how fast operators must pay. Those rules differ from state to state.

What drives oil and gas royalty income?

Four things drive almost all of the change in a royalty check. I want you to understand each one before you ever put money into royalties.

1. Oil and gas prices

Royalty income moves with commodity prices. A commodity is a raw material, like oil or natural gas, that trades on a market. Prices for both change daily. They can move a lot in a short time.

Oil prices respond to world events: global demand, production decisions by large oil-producing countries, wars, sanctions, and recessions. Natural gas prices respond more to U.S. weather, storage levels, pipeline space, and exports of liquefied natural gas (LNG).

Also, the price the operator actually receives is often different from the headline price you see in the news. Local pipeline limits, gas quality, and distance to market can push the local price below the national benchmark. That difference is sometimes called a basis differential.

The point is simple. Royalty owners don't control price. And nobody can tell you reliably where prices will be in five years.

2. Production decline curves

Every oil and gas well produces the most at the start. Then output falls over time as pressure in the rock drops. A chart of that drop is called a decline curve.

Shale wells in particular tend to decline fast in their early years, then flatten into a slower, longer tail. Engineers build "type curves" to estimate how a group of similar wells will decline. Those estimates are useful. They are also only estimates. Real wells can do better or worse.

The EIA described this effect for whole regions. In a 2015 report, it wrote that in each major shale region, "production from new wells is not large enough to offset production declines from existing, legacy wells" (EIA, Today in Energy). In plain English, if operators stop drilling, total production from a region falls. The same is true for your royalty portfolio.

Here is a hypothetical illustration. Say a new well makes 1,000 barrels in its first month. If its output fell by a large share in year one, and by smaller amounts each year after, your income from that one well would shrink quickly at first and then more slowly. That pattern is normal. It is not a sign that something broke. But it means a royalty is a depleting asset. Unless new wells are drilled, income from a fixed set of wells tends to go down over time.

3. New drilling by operators

This is the factor that can offset decline. When an operator drills new wells on acreage where you own royalties, you can get paid on those new wells too. You don't pay for them. This is one of the main attractions of owning royalties under active operators.

But here's the catch. The operator decides whether to drill, when to drill, and how many wells to drill. You don't. Operators make those decisions based on oil and gas prices, their budgets, their other acreage, and what their own investors want. If prices fall, many operators slow down. If an operator has better rock somewhere else, it may drill there first.

When I review a royalty program, I want to know how much of the projected income comes from wells already producing and how much depends on future drilling. Income from wells already producing is easier to measure. Income from wells that haven't been drilled yet is a forecast.

4. The basin

A basin is a large geologic area where oil and gas collect in the rock. Different basins have different rock, different products, different costs, and different access to markets. Where your royalties sit matters a lot.

Here are three basins you'll see often in royalty programs, with context from the EIA.

The Permian Basin (West Texas and southeastern New Mexico). The EIA reports that in 2025 the Permian "produced more crude oil than any other region," accounting for 48% of total U.S. crude oil production. Production there grew by 280,000 barrels per day to 6.6 million barrels per day (EIA). The Permian is mostly oil, with a lot of associated natural gas.

The Haynesville Shale (East Texas and North Louisiana). This is mainly a natural gas play. The EIA reports that Haynesville production averaged 14.9 billion cubic feet per day in 2025, 4% more than the 2024 average. It also notes the formation is between 10,500 and 13,500 feet deep (EIA). Deep wells cost more to drill, so operators there tend to be sensitive to gas prices.

The Anadarko Basin (mainly western Oklahoma, and parts of the Texas Panhandle and Kansas). This is an older basin with both oil and gas. It has a long drilling history and a large number of existing wells.

Owning royalties across more than one basin can spread out some risks. For example, an oil-heavy basin and a gas-heavy basin may not move the same way at the same time. But spreading out does not remove risk. Both oil and gas prices can fall together.

Can oil and gas royalties qualify for a 1031 exchange?

They can, depending on the interest and on state law. Let me explain why, and then explain the limits.

The basic 1031 rule

A 1031 exchange lets you sell investment real estate and buy other investment real estate without paying capital gains tax right away. The tax is deferred, not erased. The rule comes from Section 1031 of the Internal Revenue Code.

The statute says that "no gain or loss shall be recognized on the exchange of real property held for productive use" in a trade or business or for investment, if it is exchanged "solely for real property of like kind" (26 U.S.C. §1031). Since 2018, only real property qualifies. Equipment, vehicles, and other personal property no longer do.

The statute also sets two deadlines. You must identify your replacement property within 45 days after you sell. You must receive it within 180 days after you sell (or by your tax return due date, if that comes sooner).

What "like-kind" means

"Like-kind" is broader than most people think. The Treasury regulation says the words "have reference to the nature or character of the property and not to its grade or quality." It also says it doesn't matter whether real estate "is improved or unimproved" (26 CFR 1.1031(a)-1).

So, in general, real property can be exchanged for other real property. An apartment building can be exchanged for raw land. Raw land can be exchanged for a warehouse. The question for royalties is whether a mineral or royalty interest counts as real property.

What the 2020 regulations say about natural deposits

In 2020, the Treasury Department issued final regulations that define "real property" for 1031 exchanges. You can find them at 26 CFR 1.1031(a)-3.

The regulation says that unsevered natural products of land, including "mines; wells; and other natural deposits, generally are treated as real property." It also says they "cease to be real property when they are severed, extracted, or removed from the land." In other words, oil still in the ground can be real property. A barrel of oil sitting in a tank is not.

The regulation also has a state-law test. Property can count as real property if, on the date it is transferred, it is classified as real property under the law of the state or local jurisdiction where it is located.

The official explanation that came with the final rules is called the preamble, published as Treasury Decision 9935. It discusses mineral extraction rights directly. It says that under the final regulations, "the mineral rights and timber cutting rights are real property" if they are real property under state or local law. That was a change from the proposed version of the rules, which could have left some mineral rights out.

Why "it depends" is the honest answer

Here's where I slow down with every investor. Whether a specific interest qualifies depends on several things:

• The type of interest. A mineral interest or a perpetual royalty is different from a short-lived interest. An overriding royalty that ends when a lease ends may be treated differently. A production payment that ends after a set dollar amount is different again.
• State law. Each state decides how it classifies mineral and royalty interests. Texas, Oklahoma, Louisiana, and New Mexico each have their own property law.
• The legal structure. How you hold the interest matters. If you hold it through an entity, the type of entity and how it is taxed matters.
• Your relinquished property. Your old property must also be real property held for investment or business use.

So please don't take "royalties can qualify" as "my royalty will qualify." Confirm it with a CPA and a real estate or tax attorney before you commit. Ask the sponsor for its tax opinion or legal analysis on 1031 eligibility. Then have your own advisors read it. A sponsor is the company that puts together the investment, buys the assets, and manages the program.

How are royalty programs for 1031 exchanges structured?

Most investors doing a 1031 exchange don't want to buy small royalty interests one at a time. Doing it yourself means title work in several states, reading old deeds, chasing division orders, and hoping you got a fair price. That is hard to do inside a 45-day window.

So some sponsors build royalty programs designed to be 1031 replacement property. The details vary a lot from program to program. Here is the general shape of the ones I've reviewed.

The owner of record: an LLC or a DST

The program usually sets up a holding entity to own the royalty interests. Two common choices are:

• A Delaware statutory trust (DST). A DST is a trust under Delaware law that can hold title to real property for many investors. In Revenue Ruling 2004-86, the IRS concluded that a taxpayer may exchange real property for an interest in a DST that meets certain rules, and treated the investor as owning an interest in the underlying property. DSTs come with strict limits on what the trustee can do, such as limits on new investment and new borrowing.
• An LLC (limited liability company). Some programs use an LLC structure instead. How the LLC is set up and taxed matters. In general, an ownership interest in an entity taxed as a partnership is not itself real property for a 1031 exchange. So programs that use an LLC need a structure that lets each investor be treated as owning real property directly. This is exactly the kind of detail your CPA and attorney need to review.

A portfolio of interests across basins

Instead of one well, the program usually holds many royalty interests in many wells. Often the interests sit in more than one basin. For example, one program might mix oil-weighted acreage in the Permian with gas-weighted acreage in the Haynesville. Another might mix the Permian with the Anadarko Basin.

The goal is to spread out the risk of any single well, any single operator, or any single basin. That spreading out has limits, which I cover in the risk section.

An effective date for income

Royalty programs usually set an effective date. That's the date from which the program, and therefore the investors, are entitled to production revenue. Production before that date belongs to the seller. Production after it belongs to the program.

Because of the payment lag I mentioned earlier, there is usually a gap between the effective date and when cash actually arrives. Read the offering documents to learn when distributions are expected to start, how often they're paid, and how the effective date was set.

Third-party operators run the wells

The program doesn't drill or run wells. Independent oil and gas companies do. Those companies are the operators. They decide where and when to drill, pay all the drilling and operating costs, sell the oil and gas, and send royalty payments to the program. The program then pays distributions to investors, after its own costs and fees.

No drilling or operating costs for owners

Because the program holds royalty interests, not working interests, the owners don't pay drilling costs or operating costs. There are no cash calls for new wells or repairs. Owners still bear their share of severance taxes, any allowed post-production deductions, and the program's management and administrative fees. All of these reduce what's left to distribute.

Who usually can invest

Most of these programs are private placements offered under Regulation D. In most cases they're for accredited investors only. Under SEC rules, an individual can qualify with earned income above $200,000 (or $300,000 with a spouse or spousal equivalent) in each of the past two years, with a reasonable expectation of the same this year. Or an individual can qualify with net worth over $1 million, not counting the primary residence (Investor.gov).

How does a 1031 exchange into oil and gas royalties work, step by step?

Here is the general process I walk investors through. Your timeline may differ, so work with your qualified intermediary from day one.

Step 1: Set up your exchange before you close your sale

Hire a qualified intermediary before your relinquished property closes. The QI must hold the sale money. If the money lands in your bank account, the exchange generally fails.

Step 2: Talk with your CPA about your goals and your gain

Know your expected gain, your debt payoff, and how much you need to reinvest to defer all of the tax. In a 1031 exchange, you generally need to reinvest all the cash and replace the debt (with new debt or extra cash) to defer all of the gain. Ask your CPA how royalties would fit your overall tax picture, including depletion.

Step 3: Learn the basics of the royalty program

Read the private placement memorandum. A private placement memorandum (PPM) is the long legal document that describes the offering, the sponsor, the fees, and the risks. Look for the basin mix, the operators, the split between producing wells and future drilling, the effective date, the fees, and the risk factors.

Step 4: Get your advisors' view on 1031 eligibility

Ask for the sponsor's legal analysis on 1031 eligibility. Have your attorney or CPA review it against the state laws that apply. This step matters more for royalties than for a typical apartment DST, because the property type is less common.

Step 5: Identify within 45 days

Send your identification in writing to your QI within 45 days of your sale. Many investors identify more than one property in case one sells out. Royalty programs, like DSTs, can close to new money without much notice.

Step 6: Sign the documents and fund

Complete the subscription documents. Your QI sends the funds directly to the sponsor. My team and I coordinate the paperwork with the sponsor and the qualified intermediary. Because the interests in these programs are usually already acquired, closing can often happen in a few business days once paperwork, funding, and approvals are complete.

Step 7: Close within 180 days and report it

You must receive the replacement property within 180 days of your sale. At tax time, your CPA reports the exchange on IRS Form 8824, which is used "to report each exchange of business or investment property" for like-kind property.

Step 8: Track your statements

Keep every distribution notice, tax report, and annual update. Watch for changes in operators, drilling activity, and production. Keep your CPA in the loop each year.

Royalty interests vs. owning a rental property

Many of the investors I work with have owned rentals for decades. So here's how royalties compare with owning a rental directly. This is a general comparison, not a recommendation either way.

The big trade-off is control versus hands-off ownership. A rental gives you control and a lot of work. A royalty program takes away the work but also takes away control. And it swaps rental-market risk for commodity and production risk.

What is depletion, and how does it affect taxes?

When you own a rental, you take depreciation. That's a yearly tax deduction for the wear and tear on the building. Royalty owners have something similar called depletion.

Depletion reflects the idea that every barrel of oil produced is a barrel you no longer own in the ground. The tax code says there "shall be allowed as a deduction in computing taxable income a reasonable allowance for depletion" for oil and gas wells and other natural deposits (26 U.S.C. §611).

There are two methods.

Cost depletion. You recover your cost basis in the property over time, in proportion to how much of the estimated reserves are produced and sold each year.

Percentage depletion. You deduct a set percentage of your gross income from the property. For independent producers and royalty owners, the tax code sets the rate at 15% (26 U.S.C. §613A). There are limits. It applies only up to a daily quantity of production (1,000 barrels of oil, or the gas equivalent at 6,000 cubic feet per barrel). And the deduction can't exceed 65% of your taxable income for the year, figured before certain items.

An IRS fact sheet notes that "there are two ways of figuring the depletion deduction: cost depletion and percentage depletion," and that a mineral interest owner must use the method that gives the larger deduction (IRS, Tips on Reporting Natural Resource Income). That page is an archived 2013 fact sheet, so ask your CPA about current rules. The same page says most taxpayers report royalty payments on Schedule E.

How depletion interacts with a 1031 exchange

When you exchange into royalties, your tax basis generally carries over from your old property. That carryover basis affects how much cost depletion you can take. Depletion rules, recapture rules on a later sale, and how they interact with your exchange are technical. This is one area where you really want a CPA who has worked with oil and gas clients.

A simple hypothetical shows why depletion matters. Say your share of royalty income is $10,000 in a year. If percentage depletion applied in full at 15%, the deduction would be $1,500. That could lower the taxable part of that income to $8,500, before other items. Your actual result depends on your basis, your other income, the limits, and the method that gives the larger deduction. Please don't use this example to plan your taxes.

What are the risks of oil and gas royalties?

I want to be very direct here. Royalties are not a bond. They are not a savings account. The income can change a lot, and you can lose money. Here are the main risks I talk through with every investor.

Commodity price risk

Oil and gas prices can fall fast and stay low for a long time. When they do, royalty income falls with them. Your share of the wells doesn't change, but each barrel or each cubic foot is worth less.

Production decline

As I explained above, wells produce less over time. If operators don't drill new wells, income from a fixed set of wells tends to shrink year after year. A program can lose value even in a good price environment if production falls faster than expected.

Operator decisions

You don't decide whether wells get drilled. Operators do. They can slow drilling, shift money to other areas, delay completing wells, or even shut in wells when prices are low. An operator can also run into financial trouble. If an operator goes bankrupt, payments can be delayed or disputed.

Concentration

Some portfolios lean heavily on a single basin, a single operator, or a single product. For example, a portfolio that is mostly natural gas depends heavily on gas prices. A portfolio where a few wells produce most of the revenue depends heavily on those wells. Ask how much income comes from the top few wells and the top few operators.

Environmental and regulatory risk

Oil and gas development is regulated by states and the federal government. Rules on drilling, flaring, water disposal, permits, and emissions can change. New rules can raise operators' costs or slow drilling. Accidents, spills, or earthquakes linked to wastewater disposal can lead to new restrictions in a region.

Title and lease risk

Royalty interests depend on old deeds, leases, and probate records. Errors in title can lead to disputes over who owns what. Lease terms on post-production deductions can lead to smaller checks than expected.

Reserve estimate risk

The value of a royalty program depends heavily on engineers' estimates of how much oil and gas is in the ground and how fast it will come out. Those estimates can be wrong. Ask who prepared the reserve report, whether it was independent, and how recent it is.

Illiquidity

Royalty programs held for a 1031 exchange are generally illiquid. There's usually no public market for your interest. You should expect to hold it until the sponsor sells the assets or the program ends, which could be many years. You may not be able to get your money out early, or only at a big discount.

Limited control

You won't vote on daily decisions. The sponsor manages the program. The operators manage the wells. In a DST structure, the trustee's powers are also limited by design.

No guaranteed distributions

Distributions are not guaranteed. They can be reduced or stopped. Projected income in an offering is a projection, not a promise.

Loss of your entire investment

You can lose some or all of your investment. The SEC's Office of Investor Education and Advocacy put it plainly in its alert on private oil and gas offerings: "You should be aware that you could lose your entire investment." The same alert warns that private offerings "may involve a high degree of risk" and "typically have less liquidity, which means you might have to hold your investment indefinitely" (Investor.gov).

Tax risk

The 1031 treatment of a specific interest could be challenged. Depletion rules and limits could change. A failed exchange could mean you owe the tax you meant to defer. Work with your own CPA and attorney.

Fraud risk

Oil and gas has a long history of scams. The SEC alert lists red flags, including pressure sales tactics like a "limited" or "once-in-a-lifetime" opportunity, and very high promised returns. It also says that "if you aren't given anything in writing, then you should be very skeptical." Always check the person selling you an investment on FINRA BrokerCheck, which shows a broker's work history, licenses, and any recorded disciplinary actions.

Mistakes to avoid

Here are the mistakes I see most often, or that I'd most want to help an investor avoid.

1. Confusing a royalty with a working interest. If you're asked to pay for drilling, you're not buying a royalty. Working interests can come with cash calls and much larger losses. Read the documents carefully.

2. Assuming every royalty interest qualifies for a 1031 exchange. The answer depends on the interest type, state law, and the structure. Get a written analysis and have your own advisors review it.

3. Treating today's income as permanent. Royalty income declines unless new wells are drilled. Look at the decline assumptions in the offering, not just the first-year numbers.

4. Ignoring the price assumptions. Ask what oil and gas prices the projections assume. Ask what happens to income if prices are 25% lower. If the offering doesn't show a downside case, ask for one.

5. Not asking how much income depends on future drilling. A program built mostly on wells that already produce is different from one that depends on wells that haven't been drilled yet.

6. Overlooking fees. Sponsor fees, acquisition costs, and ongoing management fees all reduce your income. Make sure you understand every fee in the PPM.

7. Putting too much of your exchange into one asset type. Royalties can be one piece of a broader plan. Many of the investors I work with split their exchange across several replacement properties, such as multifamily, industrial, or net lease, so one sector doesn't drive the whole result.

8. Missing the 45-day deadline while you research. Royalties take more time to understand than a typical apartment building. Start learning before you sell, not after.

9. Forgetting about liquidity needs. Don't put money into a royalty program that you might need in the next several years. You may not be able to sell.

10. Skipping the background check. Look up the broker on BrokerCheck. Research the sponsor's history. Ask about the operators' track records.

How I review a royalty offering

Royalties are a specialized asset. So I use the same disciplined process I use for every offering, with extra questions that are specific to oil and gas.

My due diligence covers five areas: a broker-dealer review, an investment manager audit, an investment offering review, a real estate assessment, and institutional underwriting. I partner with outside auditors in each area. And I treat due diligence as continuous, not a one-time box to check.

For royalty programs, here are some of the questions I ask:

• What share of the projected income comes from wells already producing?
• Which operators run the wells, and how financially strong are they?
• How much of the income depends on the top five wells? The top two operators?
• What's the mix of oil, natural gas, and natural gas liquids?
• What price assumptions are behind the projections? What happens if prices drop?
• Who prepared the reserve report? Was it an independent engineering firm? How current is it?
• How was the effective date set? When are the first distributions expected?
• What do the leases say about post-production deductions?
• What's the legal structure, and what does the sponsor's counsel say about 1031 eligibility?
• What are all the fees, at the start and every year?
• What's the plan for an exit, and how long might that take?

When I share an offering with an investor, I explain why I'm considering it, what I like about it, and where I have reservations. Then we look at it together, using the questions in my guide to choosing a DST. Some royalty offerings I've reviewed made it into the offerings I currently have available. Others didn't.

Who may oil and gas royalties fit?

Royalties are not right for everyone. Here's how I think about fit. This is general guidance, not a recommendation for you. Your advisors should help you decide.

Royalties may fit an investor who:

• Is an accredited investor doing a 1031 exchange and wants some replacement property outside traditional buildings
• Wants to be hands-off, with no tenants, toilets, or roofs
• Understands that income can rise and fall with commodity prices and can decline over time
• Already owns real estate in sectors like multifamily or industrial and wants to spread exposure into a different kind of real property
• Can hold the investment for many years without needing the money back
• Has a CPA who understands depletion and oil and gas tax reporting

Royalties may not fit an investor who:

• Needs steady, predictable income to pay monthly bills
• Might need to access the money in the next several years
• Isn't comfortable with energy price swings
• Wants control over decisions
• Would be putting most of their net worth into a single program
• Has concerns about investing in fossil fuel production for personal reasons

A good conversation about royalties often starts with a different question: "What role would this play in my whole plan?" For some investors, a small slice of royalties next to their other real property makes sense. For others, it doesn't fit at all. Both answers are fine.

What my data shows

I track every offering on my platform. Here is what my offering records as of October 2026 show, across 76 DST offerings from 38 sponsors.

Energy royalty programs are a small part of the overall market. Net lease offerings make up 15 of 76 offerings, or 20%, and that group includes energy royalty programs. By comparison, multifamily is 31 offerings (41%) and industrial is 18 (24%). Self-storage (5), retail (4), and medical office (3) round out the list. Royalties are a niche, not the main course.

The royalty programs I've reviewed hold portfolios of interests, not single wells. Here are two examples, described generally:

• One portfolio holds 14 royalty properties with 27 producing wells in Oklahoma's Anadarko Basin and Texas's Permian Basin.
• Another holds about 1,277 net royalty acres with interests in more than 200 producing wells. About 90% of its production is natural gas, from the Permian Basin and the Haynesville Shale.

In both cases, third-party operators run the wells. The owner receives a share of production revenue and doesn't pay drilling or operating costs.

Notice the difference between them. The first is a smaller set of wells across an oil-weighted basin and a mixed basin. The second is much wider, with hundreds of wells, but it's heavily weighted to natural gas. That means its income will likely track natural gas prices more than oil prices. These are exactly the kinds of trade-offs I walk through with investors.

Not every offering makes the cut. Of the 76 offerings in my records, 16 are open, 6 have limited availability, 24 are under review, 25 are closed, and 5 are offerings I reviewed and passed on.

Minimums vary. Across all 76 offerings, the median minimum investment is $100,000. Minimums range from $25,000 to $500,000, and 21 offerings (28%) start at $25,000. Royalty programs set their own minimums, so check each one.

Many offerings use no debt. 36 of 76 offerings (47%) are all-cash, with no loan. That matters for 1031 investors who need to replace debt, because an all-cash offering won't help you replace a loan on your old property. Your CPA can help you plan for that.

Frequently asked questions

What is an oil and gas royalty?

An oil and gas royalty is a share of the revenue from oil and gas produced from a property. The royalty owner does not pay drilling or operating costs. The size of the share is set by the lease or the deed.

How much does a royalty owner get paid?

It depends on how much oil and gas is sold, the price, and your decimal interest. The basic math is volume times price times decimal interest, minus severance taxes and any allowed deductions. Payments can change a lot from month to month.

What is the difference between a royalty interest and a working interest?

A royalty owner gets a share of revenue without paying drilling or operating costs. A working interest owner pays its share of those costs and keeps the revenue left after royalties. Working interests can come with large bills for new wells or repairs.

Can I use oil and gas royalties in a 1031 exchange?

Royalty and mineral interests can qualify as real property for a 1031 exchange, depending on the type of interest and state law. The 2020 Treasury regulations treat unsevered natural deposits, and mineral rights classified as real property under state law, as real property. Confirm your specific situation with a CPA and attorney.

Do royalty payments last forever?

Not in practice. A mineral or royalty interest can last indefinitely, but the income depends on wells that produce less over time. Income usually declines unless operators drill new wells.

Who decides when new wells are drilled?

The operator decides. Royalty owners and royalty programs usually have no say in when or where wells are drilled. Operators base those decisions on prices, budgets, and their other opportunities.

Are oil and gas royalty distributions guaranteed?

No. Distributions are not guaranteed and can be reduced or stopped. Income depends on prices, production, and operator decisions, and you can lose your entire investment.

How are oil and gas royalties taxed?

Royalty income is generally reported as ordinary income, often on Schedule E. Royalty owners may be able to take a depletion deduction, which can lower taxable income. Your CPA can tell you how this works for you.

What is depletion?

Depletion is a tax deduction that reflects the using up of oil and gas reserves as they are produced. There are two methods, cost depletion and percentage depletion. Qualifying royalty owners generally must use whichever gives the larger deduction, subject to limits.

Can I sell my interest in a royalty program early?

Usually not easily. These programs are generally illiquid, and there is often no market for your interest. Plan to hold until the sponsor sells the assets or the program ends.

Do I need to be an accredited investor?

Most royalty programs offered for 1031 exchanges are private placements for accredited investors only. That generally means income above $200,000 ($300,000 with a spouse) or net worth above $1 million, excluding your home.

How do I check whether a royalty offering is legitimate?

Read the private placement memorandum, ask for the reserve report, and check the broker on FINRA BrokerCheck. Be wary of pressure tactics or very high promised returns, which the SEC lists as red flags. Have your attorney and CPA review the documents before you invest.

Sources

• U.S. Energy Information Administration, "U.S. crude oil production rose in 2025, setting new record" (March 31, 2026): https://www.eia.gov/todayinenergy/detail.php?id=67404
• U.S. Energy Information Administration, "U.S. natural gas production reached a new record in 2025" (March 13, 2026): https://www.eia.gov/todayinenergy/detail.php?id=67345
• U.S. Energy Information Administration, "EIA expects near-term decline in natural gas production in major shale regions" (August 26, 2015): https://www.eia.gov/todayinenergy/detail.php?id=22672
• 26 U.S.C. §1031, Exchange of real property held for productive use or investment (Cornell Law School LII): https://www.law.cornell.edu/uscode/text/26/1031
• 26 CFR 1.1031(a)-1, Property held for productive use in trade or business or for investment (Cornell Law School LII): https://www.law.cornell.edu/cfr/text/26/1.1031(a)-1
• 26 CFR 1.1031(a)-3, Definition of real property (Cornell Law School LII): https://www.law.cornell.edu/cfr/text/26/1.1031(a)-3
• IRS, Treasury Decision 9935, Statutory Limitations on Like-Kind Exchanges: https://www.irs.gov/pub/irs-drop/td_9935.pdf
• IRS, Revenue Ruling 2004-86: https://www.irs.gov/pub/irs-drop/rr-04-86.pdf
• IRS, About Form 8824, Like-Kind Exchanges: https://www.irs.gov/forms-pubs/about-form-8824
• IRS, Tips on Reporting Natural Resource Income (FS-2013-6): https://www.irs.gov/newsroom/tips-on-reporting-natural-resource-income
• 26 U.S.C. §611, Allowance of deduction for depletion (Cornell Law School LII): https://www.law.cornell.edu/uscode/text/26/611
• 26 U.S.C. §613A, Limitations on percentage depletion in case of oil and gas wells (Cornell Law School LII): https://www.law.cornell.edu/uscode/text/26/613A
• SEC Office of Investor Education and Advocacy, "Investor Alert: Private Oil and Gas Offerings" (Investor.gov): https://www.investor.gov/additional-resources/news-alerts/alerts-bulletins/investor-alert-private-oil-gas-offerings
• SEC Office of Investor Education and Advocacy, Investor Bulletin on accredited investors (Investor.gov): https://www.investor.gov/introduction-investing/general-resources/news-alerts/alerts-bulletins/investor-bulletins/updated-3
• FINRA BrokerCheck: https://brokercheck.finra.org/