ASC 932, formally titled Extractive Activities—Oil and Gas, is the Financial Accounting Standards Board’s authoritative standard for how oil and gas producers account for the costs of finding and producing reserves. It governs every phase of upstream operations, from acquiring mineral rights through final production, and its rules decide whether billions of dollars in exploration spending land on the balance sheet as assets or on the income statement as immediate expenses. Because geological uncertainty makes oil and gas fundamentally different from manufacturing or retail, ASC 932 imposes specialized frameworks that don’t exist elsewhere in GAAP.
What ASC 932 Covers
The standard applies to any entity engaged in oil and gas producing activities, and it reaches both SEC filers and private companies that prepare GAAP financial statements. It covers four operational phases: acquiring mineral rights, exploring for reserves, developing discovered reserves for production, and producing and selling the resource.1U.S. Securities & Exchange Commission. Codification of Staff Accounting Bulletins – Topic 12: Oil and Gas Producing Activities
One scope detail trips up practitioners early. Mineral rights and leases to explore for oil, gas, and similar nonregenerative resources are specifically excluded from the lease accounting rules in ASC 842. That exclusion covers the intangible right to explore for the resource and the right to use the land containing it. Equipment used in exploration, such as a drilling rig leased from a third party, does fall under ASC 842. And when a land arrangement bundles mineral rights with surface use for an unrelated purpose, the mineral rights follow ASC 932 while the surface component may constitute a separate lease under ASC 842.
The Two Accounting Methods
Every oil and gas entity must adopt one of two methods and apply it consistently across all oil and gas operations: Successful Efforts (SE) or Full Cost (FC). The choice shapes nearly every financial metric the company reports, from total assets to earnings volatility.1U.S. Securities & Exchange Commission. Codification of Staff Accounting Bulletins – Topic 12: Oil and Gas Producing Activities
The core difference is philosophical. Successful Efforts treats each well or project as a separate bet: if the bet fails, the cost is expensed. Full Cost treats the entire exploration program as one integrated effort, capitalizing every dollar spent searching for reserves on the theory that dry holes are an unavoidable cost of finding the productive ones.
Switching methods is possible but heavily scrutinized. The SEC has indicated that moving from Full Cost to Successful Efforts does not require a preferability letter, reflecting the staff’s long-standing view that SE produces more decision-useful financial statements. Moving from SE to FC faces a higher justification burden. In practice, switches are rare because they require restating prior periods and can significantly reshape reported financial results.
How Successful Efforts Works
The SE method capitalizes only costs directly tied to discovering or developing proved reserves. Spending that doesn’t lead to a successful outcome flows through the income statement immediately. This approach generally produces lower reported asset balances and more volatile quarterly earnings.
Acquisition Costs
The initial investment to secure mineral rights, including lease bonuses, option payments, and brokerage fees, is capitalized when paid. These costs form the cost basis for a specific lease or property. If the property is later determined to have no commercial potential, the capitalized acquisition cost is impaired and written off.
Exploration Costs
Exploration costs are split based on outcome. The costs of drilling an exploratory well that discovers proved reserves are capitalized as part of the property’s asset base, including drilling, completing, and equipping the well. When an exploratory well turns up dry, the entire cost is expensed immediately.2QEP Resources Annual Report 2011. Successful Efforts Accounting for Gas and Oil Operations
Geological and geophysical costs, meaning the surveys and studies done before any drilling begins, are also expensed as incurred.2QEP Resources Annual Report 2011. Successful Efforts Accounting for Gas and Oil Operations A company might spend millions on seismic studies that inform its drilling decisions, and all of that spending hits the income statement regardless of whether the subsequent well produces.
Suspended Exploratory Wells
Not every exploratory well can be classified as a success or failure the moment drilling ends. Sometimes a well finds hydrocarbons but the company needs time to assess whether the quantities justify commercial development. ASC 932 allows these wells to remain capitalized on a suspended basis, but only if two conditions are met: the well found enough reserves to justify completing it as a producing well, and the company is making sufficient progress assessing the reserves and the economic viability of the project.3SEC. Accounting for Suspended Exploratory Wells
If either condition fails, or if the company learns something that raises substantial doubt about viability, the well is treated as impaired and its costs are charged to expense, net of salvage value. This is a judgment-heavy area that auditors watch closely. The standard sets no fixed time limit, but the longer a well remains suspended without progress toward development, the harder it becomes to justify continued capitalization.
Development and Production Costs
Once proved reserves are identified, the costs of preparing them for production are capitalized. Development costs include drilling and equipping development wells within a proved area, building gathering systems, and constructing production platforms or other surface infrastructure. All development costs are capitalized regardless of outcome, because the geological risk has already been resolved. These capitalized costs become the base for future depletion once production begins.
Production costs, meaning the day-to-day expenses of lifting oil and gas to the surface such as labor, maintenance, and fuel, are expensed as incurred and never capitalized.
Impairment Testing
Impairment under SE operates on two tracks. Unproved properties, where commercial viability hasn’t been established, must be assessed at least annually based on qualitative indicators: whether the lease is approaching expiration, whether drilling plans have been abandoned, or whether new geological data undermines the property’s prospects.
Proved properties follow a two-step recoverability test. First, the property’s carrying amount is compared to its undiscounted future net cash flows. If those undiscounted cash flows fall below the carrying amount, impairment exists.2QEP Resources Annual Report 2011. Successful Efforts Accounting for Gas and Oil Operations The loss is then measured as the difference between the carrying amount and the property’s fair value, typically determined using discounted cash flows. This property-by-property approach means one underperforming field can trigger a write-down even if the overall portfolio is thriving.
How Full Cost Works
The FC method starts from the premise that every dollar spent searching for reserves is a necessary cost of the ones eventually found. All exploration and development costs are capitalized into a single cost pool, whether the specific effort produced results or not. The inclusion of dry hole costs, geological survey costs, and other unsuccessful exploration spending is what fundamentally separates FC from SE and produces a higher reported asset base.
The Country-Level Cost Pool
Under FC, all capitalized costs are aggregated into a single cost center, typically defined at the country level. Acquisition costs, successful and unsuccessful exploratory drilling, development costs, and directly attributable overhead flow into this pool. General and administrative costs, interest, and geological and geophysical costs can also be capitalized to the extent they’re directly related to exploration and development activities.
Costs related to unevaluated properties, where the company hasn’t yet determined whether reserves exist, can be excluded from the amortization base temporarily. This prevents exploration costs from inflating the depletion rate before the company knows whether the properties will contribute reserves to the denominator of the depletion calculation.1U.S. Securities & Exchange Commission. Codification of Staff Accounting Bulletins – Topic 12: Oil and Gas Producing Activities
The Ceiling Test
Because the FC method capitalizes everything, it needs a safety valve to prevent the balance sheet from carrying assets at more than they’re worth. That safety valve is the ceiling test, a mandatory quarterly impairment review that compares the capitalized cost pool to the economic value of the underlying reserves.
The ceiling is the sum of four components:
- Present value of future net revenues from proved reserves, reduced by future operating expenses, development costs, and plugging and abandonment costs, discounted at a flat 10% rate.
- Unevaluated property costs not yet subject to amortization, carried at the lower of cost or fair value.
- Future development costs, subtracted from the calculation to reflect the spending still needed to produce the proved reserves.
- Income tax effects, with estimated future income tax on the net revenues subtracted to arrive at the after-tax ceiling.
The revenue projections use the unweighted arithmetic average of the first-day-of-the-month commodity prices for the prior 12 months, not current spot prices or management forecasts.4SEC. Summary Of Significant Accounting Policies (Policy) This trailing average smooths short-term price spikes but can still produce painful write-downs during prolonged commodity downturns. If the net book value of the cost pool, after accounting for related deferred taxes, exceeds the after-tax ceiling, the company must record an impairment charge for the difference.
Two features of the ceiling test make it especially consequential. Write-downs are permanent; if commodity prices rebound the following quarter, the company cannot reverse a prior impairment. And companies that don’t designate their commodity derivatives as hedging instruments under ASC 815 cannot factor those derivatives into the ceiling calculation, even if the hedges effectively protect cash flows.4SEC. Summary Of Significant Accounting Policies (Policy) This accounting mismatch has forced ceiling-test write-downs at companies that were economically well-hedged but couldn’t reflect that protection in the test.
Depletion and Revenue Recognition
Once exploration and development costs are capitalized under either method, they’re systematically written off as reserves are produced and sold. This process, called depletion, is the oil and gas equivalent of depreciation and uses the unit-of-production method: expense follows output rather than the calendar.
The depletion rate for a period equals the total capitalizable cost base divided by estimated total proved reserves, multiplied by the volume produced and sold. The mechanics are straightforward, but the inputs differ significantly between the two methods.
Under Successful Efforts, depletion is calculated on a field-by-field basis. The cost base for each field includes only the capitalized acquisition, successful exploration, and development costs attributable to that specific property, and the denominator is the proved reserves assigned to that field. A high-cost field with modest reserves carries a much higher per-unit depletion rate than a low-cost field with abundant reserves.
Under Full Cost, the entire country-level cost pool is the numerator and total proved reserves across the cost center form the denominator. This produces a blended, company-wide depletion rate that averages out cost differences between individual properties. The approach is simpler to administer but masks the economics of individual fields.
Revenue from oil and gas sales is recognized under ASC 606. Revenue is recorded when control of the product transfers to the buyer, which typically happens when the oil or gas is lifted and delivered to a purchaser at the wellhead or a designated delivery point.5SEC. Impact of ASC 606 Adoption A key judgment is whether the producer acts as principal or agent for post-wellhead services like gathering, compression, processing, and transportation. If control passes at the wellhead, those downstream costs are netted against revenue rather than reported as separate operating expenses. The classification affects reported revenue and operating costs but not net income.
Asset Retirement Obligations
Oil and gas producers face significant costs at the end of a well’s productive life: plugging the wellbore, removing surface equipment, and restoring the site. ASC 410-20 requires companies to recognize these future decommissioning costs as a liability, called an asset retirement obligation, when the obligation is first incurred rather than when the work is actually performed.
The ARO liability is measured at fair value, which in practice means estimating the future decommissioning cost, adjusting for inflation, and discounting the result back to present value using a credit-adjusted discount rate. At the same time, the company capitalizes an equal amount as an asset retirement cost, adding it to the carrying value of the related oil and gas property. This capitalized cost is then depleted along with the rest of the property’s cost base over its productive life.6SEC. Accounting for Asset Retirement Obligations
Each period, the ARO liability grows through accretion expense, which represents the time value of money unwinding the discount as the retirement date gets closer. Accretion is recorded as an operating cost, not interest expense, even though the mechanics resemble debt accretion.6SEC. Accounting for Asset Retirement Obligations Companies also periodically revise ARO estimates to reflect changes in expected costs, timing, or discount rates. For Full Cost companies, ARO-related costs factor into both the cost pool and the ceiling test, so underestimating decommissioning obligations can distort the depletion rate and impairment results.
Joint Interest Accounting
Most oil and gas properties are developed through joint ventures or co-ownership arrangements rather than by a single company acting alone. In a typical arrangement, one party serves as the operator and manages day-to-day activities, while non-operators hold working interests entitling them to a proportionate share of production and obligating them to bear a proportionate share of costs.
The operator periodically issues a joint interest billing to each non-operator, detailing the costs incurred and each participant’s allocated share. Costs and revenues are usually split in proportion to each owner’s working interest percentage. Each participant records its own share of acquisition, exploration, development, and production costs on its own books, applying its chosen accounting method independently of what the operator uses.
Revenue often flows directly from the purchaser to each working interest owner rather than passing through the operator. When this happens, each owner recognizes its share of production revenue independently. When the operator does handle revenue distribution, it accounts to each participant through the joint interest billing. The operating agreement governing these arrangements is the key document: it determines how costs are allocated, how disputes are resolved, and what operational decisions require consent from non-operators.
Disclosures Required by ASC 932
ASC 932 mandates a set of supplemental disclosures in the notes to the financial statements, regardless of whether the entity uses SE or FC. These disclosures exist to give investors a standardized basis for comparing companies that may have chosen different methods.
The required disclosures include:
- A clear statement of whether the entity uses Successful Efforts or Full Cost.
- The total amount of capitalized oil and gas property costs, broken out by property acquisition, exploration, and development.
- A schedule of costs incurred during each reporting period for acquisition, exploration, and development activities. This schedule is required even for FC companies, despite their policy of capitalizing all costs, because it reveals the composition of spending that would otherwise be invisible inside the cost pool.
- A schedule of proved oil and gas reserve quantities, broken down by geographic area and distinguishing between proved developed and proved undeveloped reserves.
The most complex required disclosure is the Standardized Measure of Discounted Future Net Cash Flows, commonly called the SMOG. It standardizes reserve valuation across the industry by applying the same trailing 12-month average commodity prices and the same 10% discount rate used in the FC ceiling test. The SMOG presents estimated future cash inflows from proved reserves, reduced by future development and production costs and future income taxes, discounted to present value.
Companies must also present a reconciliation showing how the Standardized Measure changed from the beginning to the end of the year. The reconciliation breaks out the effects of new discoveries, reserve revisions, production, price changes, and other factors, giving investors a detailed view of what drove changes in the economic value of the reserves. The SEC has flagged companies for omitting abandonment costs from the SMOG calculation, a common error that understates future development costs and overstates the reported measure.