Valuing Oil and Gas Interests

Oil and gas properties don’t get valued like most businesses, and treating them like a typical company is a quick way to get it wrong. The value comes from a depleting, physical resource with uncertain future production and profitability. And the value in a reserve report, however official it looks, is not fair market value or fair value.

It starts with the reserve report, not the financials

For most businesses, historical financial statements are the starting point. For an oil and gas interest, the starting point is the reserve report, an engineering estimate of how much oil or gas is actually economically recoverable, and how confident anyone can be about it. Reserves get sorted into categories based on that confidence level:

• +Proved developed producing (PDP): wells already drilled and currently producing, the most reliable category
• +Proved developed non-producing (PDNP): reserves in wells that exist but aren’t currently flowing, often shut-in or behind-pipe, expected to be recovered but requiring more work first
• +Proved undeveloped (PUD): reserves that are proved to exist but require new drilling or major capital investment to bring online
• +Probable and possible reserves: categories with progressively less certainty

A wise engineer explained this to me early in my career, and it’s stuck with me ever since. Proved developed reserves are the fish already in the boat: you’ve weighed it, you can see it, you’re eating it tonight. Proved undeveloped is the fish on your hook, still in the water. You’re fairly confident, but it’s not in the boat yet. Probable is a fish you saw in the lake yesterday. Possible is a fish somebody told you might be in there. Each category carries value, but it’s not the same, and mixing them up is exactly how the fish’s size gets overstated.

Behind those categories is a production forecast. Most wells produce the most early in their life and then decline over time, at rates that vary with the reservoir and how the well was drilled and completed. For producing wells, engineers fit a decline curve to the well’s history to estimate how much it will produce over its life, called its estimated ultimate recovery (EUR). For undrilled locations, they rely on type curves from similar nearby wells. That forecast is an estimate with a range around it, not a certainty.

Reserve report value is not fair market value or fair value

This may be the most important point in this article. Reserve reports usually show a dollar value, often called PV-10: the projected cash flows from the reserves, discounted at 10%. Because an engineer signed it, it’s easy to treat it as what the interest is worth. It isn’t. A reserve report value isn’t fair market value, and it isn’t fair value. It’s a standardized calculation built for things like SEC disclosure and bank lending, and it follows rules a real buyer wouldn’t.

Here’s where a reserve report value parts ways with what the interest would actually sell for:

• +Prescribed pricing: SEC or lender pricing, not a buyer’s price outlook on the valuation date
• +A fixed 10% discount rate: a reporting convention, not a market return
• +Unrisked totals: producing and undrilled reserves often added together as if equally certain
• +Missing pieces: usually pre-tax, and often leaves out corporate overhead, probable and possible reserves, and acreage value
• +The interest itself: no discounts for lack of control or marketability on a minority or fractional interest

Fair market value and fair value both ask what the interest would sell for between informed, unpressured parties, using market assumptions about price, risk, and return. A reserve report value can land above or below that number. It’s an essential input, not a conclusion of value.

Asset-level vs. entity-level: two different questions

It’s easy to treat “valuing the oil and gas” and “valuing the company that owns it” as the same exercise. They’re related, but not identical.

Valuing the assets themselves (the reserves, the wells, or a package of properties) usually relies on a discounted cash flow of the property’s future production, or on comparable asset transactions.

Valuing the company is a broader question. Some operators keep replacing what they produce through drilling and acquisitions and can be valued more like an ongoing business. Others are running off a fixed set of reserves, and the analysis has to reflect that wind-down instead of assuming the business goes on forever. Company-level work may also rely on net asset value or guideline public-company multiples.

Knowing which question you’re actually answering changes which methods even apply.

Working interest vs. royalty interest changes the whole approach

These two interest types aren’t just different economically. They usually call for different valuation methods.

A working interest owner pays their share of drilling and operating costs and receives a share of production revenue, but the two shares usually aren’t the same. Under a lease with a 20% royalty, a 100% working interest owner pays all the costs but keeps 80% of the revenue, called an 80% net revenue interest. Working interests are usually valued with a discounted cash flow that runs from gross revenue down through royalties, production taxes, operating costs, and drilling capital to free cash flow, with taxes handled consistently with the discount rate. It should also include the eventual cost to plug and abandon the wells.

A royalty owner receives a share of revenue with no obligation to pay drilling or operating costs. It isn’t completely cost-free. Royalty owners usually still pay their share of production and property taxes, and depending on the lease language and state law, post-production costs like gathering, processing, and transportation can be deducted from their royalty payments. That simpler profile suits a more direct income approach, and publicly traded royalty trusts and mineral companies can act as benchmarks for the discount rate.

Mineral interests are a little different from royalties. A mineral owner usually also has the right to lease the minerals and collect a signing bonus, which matters for unleased acreage, where much of the value sits in what an operator would pay to lease it. Overriding royalties are carved out of the working interest and usually end when the lease does.

Mixing up which interest you’re valuing, and applying the wrong method as a result, is an easy way for the analysis to go wrong.

How the discounted cash flow actually gets risked

Reserve categories carry different confidence levels, so a straight discounted cash flow isn’t enough on its own. PUD reserves are meaningfully less certain than PDP reserves, and that’s usually handled with a reserve adjustment factor (a haircut by category) or a higher discount rate for riskier categories. A property that’s mostly producing needs a much lighter haircut than one that depends on future drilling. Just don’t consider the same risk twice. If the haircut covers reserve risk, the discount rate shouldn’t charge for it again. The Society of Petroleum Evaluation Engineers’ annual survey of evaluators, covering price outlooks, costs, discount rates, and risk adjustments, is a useful cross-check.

Commodity price assumptions matter just as much. Oil and gas prices are volatile and outside any operator’s control, so the analysis usually uses futures pricing for the near term and a defensible long-term outlook after that, rather than one optimistic number. Prices should also reflect where the product is actually sold, since local prices can run well below benchmarks like WTI or Henry Hub.

Multiples used in the market approach

When market data is used, oil and gas multiples look different from a typical business’s revenue or EBITDA multiples, because they’re built around the physical asset rather than the income statement alone:

• +Value per unit of proved reserves (often expressed per barrel of oil equivalent), useful for comparing properties with meaningful proved reserves
• +Value per unit of daily production, useful when comparing operating scale across properties
• +EV/EBITDAX, a version of the familiar EBITDA multiple adjusted to add back exploration costs, which keeps the comparison consistent between companies using different accounting methods for those costs
• +Value per acre, most relevant for undeveloped or early-stage acreage without meaningful production yet

Selecting the right multiple, and the right guideline companies or transactions to derive it from, depends heavily on matching reserve mix, geology, and development stage as closely as possible.

In practice, the income and market approaches are often considered together. The discounted cash flow captures the specific property’s production, costs, and risk, and the market approach shows whether that answer lines up with what buyers are actually paying. When the two point to a similar range, the value is much easier to defend.

Purpose matters

The purpose of the valuation shapes the answer. Estate and gift tax work generally uses fair market value. Financial reporting after an acquisition uses fair value. A transaction looks at what a particular buyer would pay. Minerals and royalties often pass through families in fractional pieces, which may warrant discounts for lack of control and marketability. A reserve report value doesn’t meet any of these standards on its own. Your CPA or estate attorney can help confirm which one applies.

This article is a general overview for educational purposes only and is not tax, legal, accounting, or investment advice. Every plan is different, so talk with your advisors before making decisions. If you don’t have the right team in place, get in touch, and we can help you build one.

The bottom line

Whether you’re evaluating an acquisition, selling a property or interest, valuing mineral or royalty interests, or trying to understand what a producing property is actually worth, the same discipline applies. A defensible valuation starts with credible reserve and engineering data. It treats the reserve report’s value as an input, not as fair market value or fair value. It correctly classifies the type of interest. It applies the risking and methodology that fits both the reserve category and the interest type. Treated like a standard operating business, the number won’t hold up. Built around the physical, depleting reality of the asset, it will. That is the work we do.

ProDelta Advisors values oil and gas properties, working interests, and mineral and royalty interests for owners, families, investors, and their advisors.