Authority for Expenditure: Definition, AFE, and Well Cost Control

An Authority for Expenditure (AFE) is a formal internal cost authorization document and partner notification mechanism used throughout the oil and gas industry to approve, budget, and track capital or operating expenditures for well operations and related facilities. The AFE is the primary cost-control instrument for drilling, completion, and equipping of a well, presenting a detailed line-item cost estimate that must be reviewed and approved by all working interest partners before operations commence. When a well is drilled jointly under a Joint Operating Agreement (JOA), the operator prepares the AFE and circulates it to non-operating working interest owners for sign-off, committing each party to fund its proportionate share of the estimated costs. AFEs are also prepared for major workovers, recompletions, facility tie-ins, and pipeline construction projects. The term AFE is used almost universally across North America and is widely understood internationally, though equivalent approval documents appear under different names in various regulatory regimes.

Key Takeaways

• An AFE authorizes a specific well or project expenditure before operations begin, establishing the budget baseline against which actual costs are tracked throughout the operation.
• Two primary AFE types exist: the dry-hole AFE covering drilling costs to casing point or total depth, and the completion AFE issued separately if the well encounters commercial shows and a completion is warranted.
• AFE costs are classified as tangible or intangible, a distinction with significant tax consequences under the U.S. Internal Revenue Code and the Canadian Income Tax Act: intangible drilling costs (IDCs) are generally expensed immediately, while tangible costs are capitalized and depreciated.
• The Council of Petroleum Accountants Societies (COPAS) publishes model accounting procedures that govern AFE preparation, overhead charges, and cost-sharing among JOA partners in North America.
• Operators typically have authority to exceed the approved AFE by up to 10 percent without partner re-approval; expenditures projected to exceed that threshold require a supplemental AFE before continuing operations.

How the AFE Process Works

The AFE lifecycle begins in the planning phase, before a well spud or a workover commences. The operator's drilling engineering team constructs the AFE by estimating costs from the well programme: rig day rate multiplied by estimated drilling days, casing programme tonnage and price, logging suite selection, cementing volumes, anticipated completion costs, and surface equipment requirements. Each cost element is entered as a separate line item, and the sum constitutes the total estimated well cost. The operator circulates the AFE package, which includes the AFE form, a well programme summary, a location plat, and sometimes a geological prognosis, to all working interest partners. Under a standard JOA, non-operators are given a defined election period, typically 10 to 30 days, to approve, non-consent, or request revisions. A partner who approves commits to pay its working interest percentage of all authorized costs. A partner who elects to non-consent under a non-consent provision forfeits participation in costs and revenues until the consenting parties recover a penalty multiple (commonly 200 to 400 percent of the non-consenting party's share of costs) from production, after which the non-consenting party's working interest is restored.

Once the required approvals are received, the operator spuds the well. Throughout operations, actual costs are coded against the AFE line items and reported in periodic joint interest billings (JIBs) sent to each non-operator. Cost tracking against the AFE provides ongoing variance analysis and early warning when specific cost components are trending over budget. If total projected costs are expected to exceed the original AFE amount by more than the permitted tolerance (typically 10 percent under most JOAs), the operator is obligated to issue a supplemental AFE before incurring the over-run. Failure to issue a timely supplemental AFE can give non-operators grounds to dispute the over-run charges. After operations conclude, the final cost tally is compared to the original AFE and any supplements to produce an AFE summary, which becomes part of the well file and the company's post-authorization performance record.

For a multi-zone or multi-objective well, the operator may prepare separate AFEs for distinct phases. A dry-hole AFE covers costs from spud to evaluating the primary objective, typically to a casing point set above the objective horizon. If the well encounters a commercial discovery, the operator issues a completion AFE covering the costs of running and perforating production casing, installing a completion string, conducting a hydraulic fracture treatment or other stimulation, and equipping the well for production. Partners who approved the dry-hole AFE receive the completion AFE as a separate election, allowing them to participate in or non-consent the completion independently of their dry-hole election.

AFE Line Items and Cost Structure

A fully detailed well AFE contains dozens of individual line items grouped into logical cost categories. Mobilization and rig costs encompass rig day rates (expressed in dollars per day, in U.S. dollars for North American wells), rig move and mobilization charges, and standby day rates. The casing programme section itemizes the cost per tonne or per foot (per metre) of surface casing, intermediate casing, and production casing, plus associated casing accessories such as centralizers, float equipment, and stage tools. Cementing costs include cement volumes in cubic feet (cubic metres) and unit prices per sack of cement plus additives. Drilling fluid costs cover the base mud system, chemical additives, and solids control equipment rental. Directional drilling costs, if applicable for a horizontal or deviated well, include the motor or rotary steerable system rental and measurement-while-drilling (MWD/LWD) services.

Logging and evaluation costs cover wireline or LWD logging suites, including any array sonic, density-neutron, resistivity, and imaging tools, plus core acquisition and analysis if planned. Wellhead and surface equipment costs are included in the AFE whether or not the well is expected to be completed, because setting a surface wellhead is required regardless of outcome. Completion costs, when included, detail perforation gun systems, hydraulic fracture stimulation (proppant, fluid, pumping service), coiled tubing operations, production tubing, the production packer, and the Christmas tree. Facility and tie-in costs may appear on a separate facility AFE when the production handling infrastructure cost is significant, such as in a new area development where gathering lines, separators, and tanks must be installed.

Tangible versus Intangible Costs

The classification of AFE line items as tangible or intangible is not merely an accounting formality. It drives real after-tax economics. In the United States, Internal Revenue Code Section 263(c) allows operators and working interest owners to elect to expense all intangible drilling costs (IDCs) in the year incurred rather than capitalizing and depreciating them over the productive life of the well. IDCs include all costs that are incidental to and necessary for the drilling of oil and gas wells that in themselves have no salvage value: drilling, cementing services, mud costs, logging and perforating services, formation testing, site preparation, and the cost of labor and fuel for the drilling operation. Tangible costs, by contrast, are items with salvage value and physical substance: casing, tubing, wellhead equipment, pumping units, storage tanks, separators, and production facilities. Tangible costs must be capitalized and depreciated over seven years under MACRS (Modified Accelerated Cost Recovery System) for most oilfield equipment, or depleted using the unit-of-production method for well equipment. For independent producers operating in the U.S., the IDC deduction represents one of the most significant tax preferences available and is often a major driver of investment economics.

In Canada, the analogous distinction is between Canadian Exploration Expenses (CEE) and Canadian Development Expenses (CDE) under the Income Tax Act. CEE (which applies to expenses incurred in searching for oil or gas, including exploratory well drilling costs where no commercial production is found) is 100 percent deductible in the year incurred. CDE (which applies to development well drilling costs and certain well completion costs) is deductible at 30 percent per year on a declining balance basis. Canadian Oil and Gas Property Expenses (COGPE), covering the cost of acquiring resource property rights such as crown leases, are deductible at 10 percent per year on a declining balance. These distinctions are built into the AFE structure used by Canadian operators to facilitate income tax reporting by each working interest participant.