Learn
A little clarity for your next decision.
Loading your learning library…
Investor WorkspaceWelcome, there!Log Out
Investor WorkspaceA little clarity for your next decision.
By Jerry Baker
A working interest shares the costs and revenue of an oil or gas operation, while a royalty interest generally receives a share of production without paying drilling and production costs. That difference affects cash needs, control, risk, and tax treatment. Before choosing either, compare the actual rights and obligations rather than the projected distribution alone.
If you are used to rental real estate, your first question may be how much income an investment could produce. With oil and gas interests, I would add another question right away: what might I have to pay after I invest?
A working interest can require money for drilling, repairs, ongoing operations, and other agreed costs. A royalty usually avoids those direct costs. Yet it still depends on someone operating the property well enough to produce income. Neither structure removes the need to understand the asset.
The IRS oil and gas audit guide describes a working interest as the operating side of mineral ownership and a royalty as a nonoperating share. The guide is useful background, but it expressly is not an official statement of law. The conveyance, contracts, and operative tax rules must support the final analysis. [1]
This article compares the two types of interest. It does not recommend a well, operator, offering, or tax election. Its examples use invented numbers so the difference between revenue and costs is easier to see.
A working interest gives its owner an operating interest in an oil or gas property. It often arises through a lease. The owner bears a stated share of costs and receives revenue after the royalty burdens that apply to that interest.
The working-interest owner and the operator need not be the same person. The operator may run the site, hire vendors, maintain records, and send bills. Other owners can share the economic results without directing each day's work.
That makes “nonoperated working interest” a useful phrase. It means someone else operates the property. It does not mean the owner has no bills, no duties, or no exposure to an operating problem.
For a concrete state-specific example, the Railroad Commission of Texas explains that a working-interest owner remains responsible for paying or causing royalties to be paid under the lease, even when that owner is not the operator. An agreement may have the operator or purchaser make those payments on the owner's behalf. Do not assume that explanation resolves duties in every state. [2]
Ask which agreement sets your share of each cost. The percentage may differ for one project, one well, or one phase of development. If a sponsor carries some costs at first, find out when that arrangement ends and what you must fund afterward.
A royalty interest generally gives its owner a share of production or sale proceeds without a share of drilling and production costs. The payment may come from rights kept by a mineral owner or from a separate conveyance.
That is narrower than owning every mineral right. For example, a nonparticipating royalty owner may have no right to sign a lease or collect the lease bonus. In Texas, the Supreme Court has explained how the royalty right can be separated from other mineral rights. The deed and local law determine what was transferred. [3]
A royalty owner should still review permitted deductions. Taxes and certain post-production charges may reduce the check. Investment-level management fees can be separate again. “No drilling bill” is a clearer statement than “no expenses,” if the documents support it.
Also check the interest's life. A continuing royalty attached to the mineral estate differs from an override tied to a particular lease. A right that ends after a set amount has been paid requires another analysis. Do not treat every document using the word royalty as the same asset.
| Issue | Working interest | Royalty interest |
|---|---|---|
| Revenue share | Receives its share after royalty burdens. | Receives the share defined in its deed or lease. |
| Drilling and production bills | Generally bears an agreed share. | Generally does not bear these costs directly. |
| Decision-making | Rights depend on the operating agreement and ownership position. | Often has little control over drilling or operations. |
| Need for extra cash | May arise from budgets, repairs, or new work. | Review the investment agreement; no automatic promise of zero further obligations. |
| Key number to verify | Both the cost share and the net revenue share. | The royalty fraction, allocation, and permitted deductions. |
| Main tax question | How expenses, loss limits, depletion, and recapture apply. | How royalty income, depletion, basis, and later gain apply. |
This comparison describes typical features. A contract can create extra limits or burdens. Have counsel explain any term that changes the cost or payment share rather than relying on this table to settle it.
Working interest, often shown as WI, commonly describes the share of costs an owner bears. Net revenue interest, or NRI, describes the share of production revenue the owner receives after royalty burdens. Both figures belong in the same review.
Assume an investor has a 10% working interest. The property has a 20% landowner royalty and no other royalty burdens. For this simplified example, the investor's net revenue interest is 10% × 80%, or 8%.
If monthly gross sales are $100,000, that 8% share produces $8,000 of revenue before the investor's operating costs and other charges. If total operating costs are $40,000, the investor's 10% cost share is $4,000. The remaining amount is $4,000 before taxes, fees, reserves, and other items excluded from this example.
Notice the mismatch: the investor receives 8% of revenue but pays 10% of costs. Applying 10% to both would overstate the revenue. Applying 8% to both would understate the cost burden.
Now assume a further 2% overriding royalty burdens the whole working interest. Total royalty burdens become 22%. Under these assumed terms, the investor's NRI falls to 10% × 78%, or 7.8%. Its cost share remains 10%. On $100,000 of sales, revenue becomes $7,800 and the simplified remainder becomes $3,800.
Real agreements may allocate burdens differently. The point is to reconcile both percentages with the documents. A one-line ownership figure is not enough.
Consider a royalty owner with a fixed 2% share of gross sales and no direct drilling or production-cost obligation. At $100,000 of gross monthly sales, that royalty is $2,000 before any applicable taxes and other permitted deductions.
Compare that with the working-interest owner in the first example: 10% of costs, 8% of revenue, and $4,000 remaining after the assumed operating bill. The working interest produces more cash in that month, but those dollar amounts do not tell us which is a better investment. We have not specified either purchase price.
Now let sales fall to $60,000 while operating costs stay at $40,000. The working-interest owner's revenue is $4,800. Its cost share stays $4,000, leaving $800 under our simplified assumptions. The 2% royalty produces $1,200 before its applicable deductions.
The working-interest remainder fell 80%, from $4,000 to $800. The royalty amount fell 40%, from $2,000 to $1,200. That difference shows how costs can magnify a revenue decline. It does not mean costs always stay fixed or that a royalty cannot lose value.
If the property then requires a $200,000 repair, the assumed 10% cost share is $20,000. Ask whether that amount can be billed to the owner, paid from reserves, or deducted from future proceeds. Do not assume the existing monthly check sets the maximum possible loss.
A drilling proposal may include an authorization for expenditure, often called an AFE. Treat that as a cost estimate and approval document whose legal effect depends on the agreement. Ask whether it sets a binding cap, how overruns are handled, and whether extra work needs a new approval.
For an existing well, request recent bills and the next budget. Separate routine expenses from work intended to extend the well's life. Find out whether the projected distribution is shown before or after a cash reserve for that work.
Ask what happens if you do not fund an approved project. Depending on the agreement, you might face a penalty, lose access to some revenue, or have your interest affected. Those are contract questions; a projected yield will not answer them.
A useful review has three columns: money required at closing, money that may be required later, and the source available to pay it. Keep the third column realistic. Expected distributions are not cash already in the bank.
Also ask how joint bills are checked. Who reviews vendor charges? Can you inspect records? Is there a deadline to dispute an invoice? Who approves work performed by a company related to the operator? These questions help you understand the controls around spending.
Being a working-interest owner does not automatically give you a veto over each decision. Review the voting thresholds, emergency powers, operator-removal terms, and procedures for a proposed new well. Your percentage may be too small to determine the outcome.
A royalty owner's concern is different. The owner may have no direct drilling bill but also no right to require the operator to drill on a preferred schedule. A forecast that depends on future wells needs a clear explanation of who controls that plan.
Ask for separate income forecasts for wells already producing and for future development. Then ask what happens if the second group is delayed or never completed. A lease map full of possible drilling locations is not the same thing as paid-for producing wells.
Operator experience matters, but a strong name does not settle the terms. Review who can sell the interest, change operations, borrow against assets, or retain cash. If the answer is in a contract, have someone point to the actual clause.
Cost sharing and legal liability overlap, but they are not identical. An agreed 10% share of a budget does not by itself describe every claim that could arise. Ask counsel to review the ownership structure, guarantees, indemnities, insurance, and applicable law.
Pay special attention to plugging, abandonment, and cleanup obligations. Request an estimate of the remaining work, the assumptions behind it, and the party expected to pay. If another party promises to pay, consider that party's financial ability as well as the contract.
For a royalty purchase, confirm that the documents do not add obligations that conflict with the simple royalty description. For either structure, ask what duties survive a sale. A buyer's agreement to assume costs should be reviewed rather than treated as an automatic release of the seller.
The right comparison is not “working interests are dangerous; royalties are safe.” It is which risks you bear, which risks someone else bears, and which risks still affect your income even when you do not receive the bill.
Federal regulations allow an election for qualifying intangible drilling and development costs incurred by an owner of working or operating rights. The rules distinguish those costs from equipment and other capital items. Buying a royalty interest does not give its owner the operator's drilling-cost deduction merely because a well is being drilled. [4]
Do not assume a quoted percentage of the purchase price is immediately deductible. Ask the tax adviser to review which costs were actually incurred, who incurred them, when they are taken into account, and how the investment is held.
Depletion is another issue. It generally requires an economic interest in the minerals in place, with further rules governing the method and amount. Both an operating interest and a royalty can raise depletion questions. A connection to energy revenue alone does not establish the deduction. [5]
Keep tax savings out of the cash-flow line. A deduction may reduce taxable income, but it does not reimburse a failed well dollar for dollar. Its value also depends on whether the taxpayer can use it in the relevant year.
Someone can hold an investment without doing much work and still have income that is not passive under section 469. That tax label follows its own rules.
A special rule generally excludes a working interest from passive activity treatment when the taxpayer holds it directly or through an entity that does not limit liability. Material participation is not required for that rule. Limits and exceptions apply, including when liability protection changes during the year. [6]
That is not a reason to accept personal liability just to seek a deduction. Have the legal and tax advisers review the same proposed structure. A change that protects the investor may also change the tax analysis.
Royalty income not earned in the ordinary course of a trade or business is generally portfolio income for the passive activity rules. It therefore is not automatically a source against which to use passive rental losses. The IRS also explains that basis, at-risk, and other limits may affect losses. Prior nonpassive working-interest losses can affect the treatment of later income. [7]
I would want the tax projection to show which rules were applied. The phrase “passive income” in a brochure is not enough to decide how income belongs on a return.
When an owner sells natural resource property, section 1254 can turn part of the gain into ordinary income. The calculation considers specified prior deductions and gain, with special rules and exceptions. A forecast that treats all sale gain as long-term capital gain may miss an important cost. [8]
A 1031 exchange raises separate questions. Current rules cover qualifying real property, including relevant interests in unsevered minerals. That does not mean all equipment, payment rights, or entity interests included in an oil and gas deal qualify. Classify each asset and the structure actually being transferred. [9]
Even in an otherwise qualifying exchange, special natural resource recapture rules can require ordinary income when the replacement includes property outside that category. Taking no cash does not necessarily avoid the issue. Ask for that analysis before deciding what to buy next. [10]
Also consider the practical exit. Who could buy the interest? Would consent be needed? What records would a buyer request? A projected sale price is only an assumption until a willing buyer can review and fund the purchase.
For each investment, I would want the same basic set of facts: price, ownership type, cost share, revenue share, current production, future spending, fees, and exit limits. Add a clear list of matters still under review.
Then run a few simple stresses. Lower the sales price. Reduce volume. Delay new drilling. Raise the repair budget. Test these changes both one at a time and together. The purpose is to see which assumption does the most work in the projected return.
Check the people as well as the spreadsheet. The SEC's private oil and gas alert highlights conflicts, large fees, weak claims, loss risk, and limited liquidity. Ask what independent review was done and how related-party transactions were assessed. Do not treat registration or a tax deduction as a quality guarantee. [11]
A working interest may suit someone willing and able to fund operating risk. A royalty may reduce direct cost duties but still produce uneven income and hard-to-sell ownership. The better choice depends on the actual terms and on what the investor needs the money to do.
No. Another party can serve as operator while you own a nonoperated working interest. You may still bear costs and other duties under the documents and applicable law. Review voting rights, billing procedures, and the operator's authority before assuming that a hands-off role means a limited financial commitment.
WI commonly identifies the share of costs; NRI identifies the share of revenue after royalty burdens. In a simple example, a 10% WI with a 20% royalty burden produces an 8% NRI. Actual agreements may contain other burdens or special allocations, so reconcile both figures with the ownership records.
Yes. Lower production or prices can reduce the payment. Downtime, permitted deductions, and payment delays can also affect it. Avoiding direct drilling bills does not guarantee a stable check. Compare the production history and forecast with the amount of income you need for living expenses.
No. The special passive activity rule depends in part on how the interest is held and liability is limited. Other loss limits can still apply. Your tax adviser must review the costs, ownership structure, and your return. Do not use a broad tax claim as a substitute for that review. [6] [7]
Buying a royalty does not transfer the operator's drilling deductions to you. The drilling-cost rules address qualifying costs and working or operating rights. A royalty owner may have a depletion deduction under separate rules, but the amount and eligibility require their own analysis. [4] [5]
Not simply because you receive it without working at the well. Royalties outside the ordinary course of a trade or business generally are portfolio income under the passive activity rules. That distinction matters when considering whether passive losses can offset the income. Ask your CPA how your specific ownership is treated. [7]
No. Review the exact property interest, duration, tax ownership, and use, along with the exchange steps. Equipment, limited payment rights, or an entity interest may require a different answer from a direct real property interest. Special recapture rules also need review, even if the property otherwise qualifies.
Request the conveyance, lease, ownership schedule, operating agreement if relevant, production history, recent bills, budgets, fees, and projected cash flow. Ask for the independent review and any known title issues. Have the tax and legal advisers review the same documents so the investment's economics and obligations are understood together.
Educational information, not an offer or a personal tax, legal, or investment recommendation. Examples are hypothetical and omit stated adjustments. Tax treatment depends on your facts and current law. Review your transaction with your CPA, attorney, and qualified intermediary. Real estate investments can lose value and may be illiquid.
Enter your approved email to explore investments, save your shortlist, and keep learning.