Oil and Gas Accounting: A Primer for Bankers

Introduction

Diamondback Energy, one of the largest oil producers in the Permian Basin, recorded a $3.7 billion impairment in 2025 without selling a barrel at a loss. Under the full cost method it uses, the book value of its oil and gas properties may not exceed a ceiling based on the discounted value of its proved reserves at average prices for the previous twelve months. As oil prices fell during 2025, the twelve-month average oil price used in its reserve calculations dropped from $76.15 a barrel at the end of 2024 to $64.99 at the end of 2025, so the ceiling fell below the book value and the excess was written off, as its 2025 annual report explains. A producer using the other method, successful efforts, would have tested the same properties differently and might have recorded no charge at all.

Oil and gas accounting differs from most industries in three ways: how the cost of finding reserves is treated, how that cost is expensed as the reserves are produced, and how the value of the reserves themselves is disclosed. Each affects the figures bankers use, and the energy guide covers each in depth.

Finding oil is expensive and uncertain. A company may drill several dry wells for each successful one. US generally accepted accounting principles (GAAP), in Accounting Standards Codification (ASC) Topic 932, allow two approaches to these costs.

Under successful efforts, exploration costs are capitalized only when they lead to proved reserves, while the costs of acquiring properties and of development drilling, even a dry development well, are capitalized. Geological and geophysical costs are expensed as incurred, and the cost of exploratory wells that find no commercial reserves is written off as dry hole expense. ExxonMobil, which uses this method, expensed about $1.0 billion of exploration costs including dry holes in 2025, according to its annual report on Form 10-K. Under the full cost method, all costs of acquiring, exploring and developing properties within a country are capitalized in a single pool, including dry holes and geological costs, and depleted together. Diamondback capitalized all such costs, including about $102 million of internal costs in 2025.

Full cost method

An accounting method for oil and gas producers under which all costs of acquiring, exploring for and developing reserves in a country, including unsuccessful wells, are capitalized in a cost pool and depleted on a units-of-production basis. The capitalized costs are subject to a quarterly ceiling test, and any excess over the ceiling is expensed and cannot be reversed.

The methods produce different earnings for the same activity. A successful efforts company reports lower earnings in years of heavy exploration and higher assets only for the wells that work; a full cost company reports smoother earnings and a larger asset base, but higher depletion later and exposure to ceiling test write-downs when prices fall. The comparison is set out in the energy guide's article on full cost vs successful efforts.

Capitalized costs are expensed through depletion on a units-of-production basis: the cost base is divided by the proved reserves to give a rate per barrel of oil equivalent, which is charged for each unit produced. Diamondback's depletion rate rose from $12.60 to $14.60 per barrel of oil equivalent in 2025, and its depletion expense from $2.8 billion to $4.9 billion, mostly because of higher production but partly because acquisitions added properties at higher cost per barrel. The mechanics, including the distinction between proved developed and total proved reserves in the calculation, are covered in the energy guide's article on units-of-production depletion.

Depletion links the income statement to the reserve estimates. A downward revision of reserves raises the depletion rate and lowers future earnings without any change in production; acquisitions at prices above the existing cost base raise it too. Depletion per barrel is therefore one of the first figures to compare across producers, alongside lease operating expenses, production taxes and transportation costs per barrel.

The two methods also test impairment differently. Full cost companies apply the quarterly ceiling test required by the Securities and Exchange Commission (SEC) in Rule 4-10 of Regulation S-X: the capitalized cost pool, net of accumulated depletion and deferred taxes, may not exceed the present value of future net revenues from proved reserves, discounted at 10% and calculated at the average first-day-of-the-month price for the previous twelve months, adjusted for unproved property costs and related tax effects. Any excess is expensed immediately and cannot be reversed if prices recover. Because the test uses trailing average prices, write-downs tend to follow a fall in oil prices by several quarters: Diamondback warned that a further material charge was reasonably likely, and its first-quarter 2026 report recorded another $1.4 billion.

Successful efforts companies test their properties under the general impairment rules of ASC 360, grouped by field, first comparing carrying amounts with undiscounted cash flows using management's own price forecasts, and writing down to fair value only if the carrying amount is not recoverable. The test is less mechanical and less sensitive to short-term price moves, which is why full cost companies tend to report impairments more often and more promptly. The energy guide covers both, in ceiling test impairments and successful efforts impairments.

The balance sheet carries reserves at cost, which may bear little relation to their value. The supplementary disclosures required by SEC rules and ASC 932 fill the gap: reserve quantities by category and the changes in them during the year, the costs incurred in acquiring, exploring and developing properties, and the standardized measure of discounted future net cash flows from proved reserves. The standardized measure applies the same trailing average prices and a 10% discount rate to every company, after estimated future costs and income taxes, so it is comparable across producers even though it is not a market value.

Diamondback's disclosure shows the calculation:

Bankers use a pre-tax version, PV-10 (the present value at a 10% discount rate), more often than the after-tax standardized measure, because it is comparable across companies with different tax positions. Both depend on SEC prices that may be far from the forward curve, so they are reference points rather than valuations; the energy guide's article on PV-10 and the standardized measure explains how they are adjusted.

Because accounting methods differ, producers are compared on measures that remove them. EBITDAX adds exploration expense back to EBITDA (earnings before interest, taxes, depreciation and amortization), so that a successful efforts company's dry hole costs do not depress its cash earnings relative to a full cost peer. Valuation multiples set enterprise value against EBITDAX, production in barrels of oil equivalent per day and proved reserves, and equity value is compared with net asset values built from the company's own reserve reports and price assumptions. Credit analysis adds reserve-based lending, in which a bank's borrowing base is set by the value of the reserves.

Other accounting topics recur in the sector: asset retirement obligations for plugging wells and restoring sites, covered in asset retirement obligations; commodity derivatives, which many producers hold without hedge accounting so that their fair value changes run through earnings, covered in derivatives and hedge accounting; and the purchase price allocations of the sector's large acquisitions, which assign most of the price to properties rather than goodwill. Together with the methods above, they explain why an oil producer's reported earnings are a poor guide to its value and why the sector relies so heavily on its own metrics.