ASC 932 is the FASB standard on Extractive Activities—Oil and Gas, and it sets the rules for how companies account for the costs of acquiring mineral rights, exploring for reserves, developing them, and producing and selling oil and gas. It exists because geological uncertainty makes the economics of finding hydrocarbons fundamentally different from ordinary manufacturing or retail activity, and it determines whether large amounts of exploration spending land on the balance sheet as assets or hit the income statement as immediate expenses. The standard applies to public filers and to private entities preparing GAAP financial statements.
What ASC 932 Covers
The standard reaches 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 Any entity engaged in oil and gas producing activities falls within its scope.
One boundary worth flagging early, because practitioners routinely miss it: 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 and the right to use the land containing the resource. Equipment used in exploration, such as a drilling rig leased from a third party, still falls 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 be 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).1U.S. Securities & Exchange Commission. Codification of Staff Accounting Bulletins – Topic 12: Oil and Gas Producing Activities The choice reshapes nearly every reported metric, from total assets to earnings volatility.
The philosophical split is simple. 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 productive ones. Larger, more diversified companies tend to use SE because they can absorb the volatility from expensing dry holes. Smaller companies often prefer FC because capitalizing all exploration costs produces higher asset balances and smoother earnings in capital-intensive early years.
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, and either switch requires restating prior periods.
How the Successful Efforts Method Works
SE capitalizes only the costs directly tied to discovering or developing proved reserves. Spending that doesn’t lead to a successful outcome flows through the income statement as a period expense. Reported assets tend to be lower and quarterly earnings more volatile, but the tradeoff is a clearer picture of how efficiently exploration dollars convert into productive reserves.
Acquisition Costs
The initial investment to secure mineral rights, including lease bonuses, option payments, and brokerage fees, is capitalized when paid. Those amounts form the cost basis for the specific lease or property. If the property is later judged to have no commercial potential, the capitalized acquisition cost is impaired and written off.
Exploration Costs
Exploration costs split based on outcome. Drilling an exploratory well that discovers proved reserves is capitalized, including drilling, completion, and equipping costs. A dry exploratory well is expensed in full.2QEP Resources Annual Report 2011. Successful Efforts Accounting for Gas and Oil Operations
Geological and geophysical costs, the surveys and studies conducted before drilling begins, are expensed as incurred rather than capitalized.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 what the subsequent well produces.
Suspended Exploratory Wells
Some exploratory wells find hydrocarbons but need further evaluation before the company can decide whether the quantities justify commercial development. ASC 932 allows those wells to remain capitalized on a suspended basis 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 project’s economic viability.3SEC. Accounting for Suspended Exploratory Wells
If either condition fails, or if new information raises substantial doubt about viability, the well is impaired and its costs are charged to expense, net of salvage value. Auditors watch this area closely because companies have an obvious incentive to keep wells suspended rather than book a loss. The standard sets no fixed time limit, but the longer a well remains suspended without progress toward development, the harder continued capitalization becomes to defend.
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, 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 testing under SE runs on two tracks. Unproved properties, where commercial viability isn’t established, must be assessed at least annually using qualitative indicators: whether the lease is approaching expiration, whether drilling plans have been abandoned, or whether new geological data undermines the prospects.
Proved properties follow a two-step recoverability test. The property’s carrying amount is first 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. Because SE tests property by property, one underperforming field can trigger a write-down even when the broader portfolio is thriving.
How the Full Cost Method Works
FC 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 pool, whether the specific effort produced results or not. Dry hole costs, geological survey costs, and other unsuccessful exploration spending all land in the pool, which is what fundamentally separates FC from SE and produces a higher reported asset base.
The Country-Level Cost Pool
Under FC, 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 all 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. Excluding them prevents exploration costs from inflating the depletion rate before the company knows whether those properties will contribute reserves to the denominator.1U.S. Securities & Exchange Commission. Codification of Staff Accounting Bulletins – Topic 12: Oil and Gas Producing Activities
The Ceiling Test
Because FC 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 comparing the capitalized cost pool to the economic value of the underlying reserves.
The ceiling has 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 percent rate.
- The cost of unevaluated properties not yet subject to amortization, carried at the lower of cost or fair value.
- Future development costs, subtracted from the calculation to reflect spending still needed to produce the proved reserves.
- The estimated future income tax on the net revenues, subtracted to arrive at the after-tax ceiling.
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) The trailing average smooths short-term price spikes but can still produce painful write-downs during prolonged downturns. If the net book value of the cost pool, after related deferred taxes, exceeds the after-tax ceiling, the company records an impairment for the difference.
Two features make the ceiling test particularly consequential. Write-downs are permanent; if 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) That mismatch has forced write-downs at companies that were economically well-hedged but couldn’t reflect that protection in the test.
Depletion and Revenue
Once exploration and development costs are capitalized under either method, they’re written off as reserves are produced and sold. This process, depletion, is the oil and gas equivalent of depreciation. It uses the unit-of-production method, so expense follows output rather than the calendar.
The depletion rate for a period equals the capitalizable cost base divided by estimated total proved reserves, multiplied by the volume produced and sold. The mechanics are consistent; the inputs differ sharply between methods.
Under Successful Efforts, depletion is calculated field by field. The cost base for each field includes only its capitalized acquisition, successful exploration, and development costs. The denominator is the proved reserves assigned to that field. A high-cost field with modest reserves carries a much higher per-unit 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. That produces a blended, company-wide rate that averages out cost differences between properties. It’s simpler to administer but masks the economics of individual fields.
Revenue, Royalties, and Production Taxes
Revenue from oil and gas sales is recognized under ASC 606, the general revenue standard. Revenue is recorded when control of the product transfers to the buyer, typically when 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 producing company 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.
Royalties owed to the mineral owner are either deducted from gross revenue or recorded as a cost of production, depending on the contract terms. Under the entitlement method, a company recognizes revenue only for its net working interest share of production after royalty and overriding royalty burdens. Production taxes, sometimes called severance taxes, are levied by state governments on the market value or volume of extracted resources and are treated either as a reduction of revenue or as an operating expense. Rates and structures vary by state.
Asset Retirement Obligations
Oil and gas companies 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 decommissioning costs as a liability, called an asset retirement obligation, when the obligation is first incurred rather than when the work is performed.
The ARO liability is measured at fair value. In practice, that means estimating the future decommissioning cost, adjusting for inflation, and discounting the result to present value using a credit-adjusted discount rate. The company simultaneously capitalizes an equal amount as an asset retirement cost, adding it to the carrying value of the related property. That capitalized cost is then depleted along with the rest of the property’s cost base over the productive life.6SEC. Accounting for Asset Retirement Obligations
Each period, the ARO liability grows through accretion expense, representing the time value of money unwinding the discount as the retirement date approaches. 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 revise ARO estimates periodically for changes in expected costs, timing, or discount rates. For Full Cost companies, ARO-related amounts factor into both the cost pool and the ceiling test, so underestimating obligations can distort the depletion rate and the impairment result.
Joint Interest Accounting
Most oil and gas properties are developed through joint ventures or co-ownership rather than by a single company acting alone. In a typical arrangement, one party is 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 incurred costs and each participant’s allocated share. Costs and revenues split by working interest percentage. Each participant records its own share of acquisition, exploration, development, and production costs on its own books, applying its chosen method (SE or FC) independently of the operator.
Revenue often flows directly from the purchaser to each working interest owner rather than through the operator. When that happens, each owner recognizes its share of production revenue independently. When the operator handles revenue distribution, it accounts to each participant through the joint interest billing. The operating agreement governing the arrangement is the key document, because it determines cost allocation, dispute resolution, and which operational decisions require non-operator consent.
Required Disclosures
ASC 932 mandates a set of supplemental disclosures in the notes to the financial statements, regardless of method. Those disclosures exist to give investors a standardized basis for comparing companies that may have chosen different accounting policies.
- A clear statement of whether the entity uses Successful Efforts or Full Cost.
- Total capitalized oil and gas property costs, broken out by acquisition, exploration, and development.
- A schedule of costs incurred during each reporting period for acquisition, exploration, and development activities. FC companies still must present this schedule, 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, by geographic area, 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 percent 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, then 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 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 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.