Authorization for Expenditure (AFE) in Drilling Projects   

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Introduction 

An AFE is the formal capital expenditure approval document used by operators to present a detailed cost estimate to partners, stakeholders, or company management before drilling or well operations begin. The AFE establishes a financial baseline, authorizes budget releases, enables tracking of actual costs vs. plan, and provides transparency and accountability. 

Because drilling (onshore, offshore, deepwater, exploratory, or development) is capital-intensive and fraught with uncertainties, a well-constructed AFE is critical for planning and controlling cost overruns. 

In the following sections, we describe: what an AFE should contain, best-practice structure and format, how leading companies use AFEs, and specific cost-optimization measures. This document, combining standard definitions, industry-recognized structures, and cost-optimization recommendations, can serve as a reference for any drilling professional, regardless of region or well type. 

What an AFE Should Contain — Essential Elements 

A comprehensive AFE should include the following sections and elements: 

1. Project & Well Identification 

• A unique AFE number or reference. This is essential for tracking the AFE and linking to subsequent costs/actuals. 

• Well or project name, location (on-shore/off-shore, field name, geographic basin), type of well (exploration, development, appraisal, workover, abandonment, etc.), phase (pre-drill, drill, complete, abandonment, etc.). 

• Operator and participating partners (working interest holders), with share allocations. This supports partner-level cost sharing and eventual billing. 

2. Scope of Work & Technical / Program Definition 

• A concise description of the work scope, including drilling program, casing/cementing scheme, directional or deviated/horizontal wells (if applicable), completion design, testing, workover, or abandonment plan. This technical baseline gives context to the cost lines. 

• If relevant, include risks and special considerations (e.g., deepwater hazards, environmental constraints, remote logistics) to justify contingencies or special provisions. Good AFE policies integrate risk management into cost planning. 

3. Itemized Cost Breakdown 

This is the core of the AFE, a detailed breakdown of all expected costs. Typical cost categories include: 

• Rig and rig-related costs (rig mobilization, demobilization, day rate, fuel, power, camp/logistics) 

• Drilling operations (drill pipe, drill bits, BHA, directional drilling, mud, any special services, consumables) 

• Casing, tubing, cementing & well-construction materials and services (casing runs, cementing jobs, well-bore completion) 

• Logging, mud logging, formation evaluation, testing, coring, well-test, completion, or stimulation (if applicable) 

• Site preparation, location build (onshore), platform or marine spread, and logistics (offshore), environmental/regulatory / permits/insurance, and other miscellaneous overheads or contingency. 

• Contingency allowance (to cover unforeseen costs: delays, re-drills, non-productive time, etc.). The contingency margin must be clearly stated, with justification provided. 

• Allocation of costs: both “Gross” (100%) and Operator or Company net share (pro-rata working interest) if a joint venture. This allows transparent partner cost-sharing. 

4. Schedule and Cash-Flow Forecast 

• A drilling/completion schedule with key milestones (spud, casing runs, TD, completion, testing, abandonment or handover). 

• A cash-flow forecast: month-by-month (or week-by-week) expected spending to anticipate cash calls and capital commitments. 

• A variance tracking plan: to compare actual spend vs. budget, monitor overruns, and trigger supplementary AFE or corrective actions. Effective policies require variance reporting to handle deviations. 

5. Assumptions, Basis of Estimate & Risk / Contingency Explanation 

• Document all assumptions: rig day-rate, fuel costs, weather downtime, crew availability, rate escalation, material lead times, logistical constraints, and inflation, if applicable. 

• Provide the rationale/basis for each assumption (vendor quotes, historical data, benchmarks). 

• Describe risk factors and contingency strategy (e.g., cost for possible delays, overruns, safety or environmental contingencies). This risk-based approach ensures that the contingency is not arbitrary. 

6. Reviews, Approvals, and Governance 

• Signature blocks for required approvals: operator representative, partner(s), finance, possibly legal / HSE, depending on internal guidelines. 

• Revision history: in case of changes (scope, cost, timeline) a supplemental AFE should be issued and approved. Many operators link AFE rewrites or supplements to certain thresholds (e.g., cost overrun percentage, scope change, or pre-defined triggers). 

• Integration with the company's financial, accounting, and project-management systems for transparency and tracking. Many companies use specialized AFE / project-tracking software for this. 

7. Post-Execution / Close-out & Variance Report 

• After the operations, actual costs are collected and compared against the AFE budget. Variances should be documented by cost category with explanations (delay, change, inefficiency, unforeseen events). 

• If the actual cost exceeds the approved AFE, a supplemental AFE should be prepared (where allowed) or a variance report submitted.  

• Summary for partner reporting, cost recovery, internal audit, and lessons learned for future wells. 

 Industry Practices & Standardization 

Common Format & Tools 

• Many operators and service companies use category-coded AFEs, in which cost items are grouped into standard categories (e.g., drilling rig, directional drilling, tubulars, cementing, site construction, logistics, contingency, overhead) with defined codes. This helps integrate with accounting/ERP systems for reporting and invoicing. 

• Some companies use dedicated AFE-management software or modules (often integrated with their well budgeting, accounting, or joint-venture systems) to automate AFE creation, track actuals, and produce variance analysis. 

• Standard AFE templates (e.g., for recurring well types) are widely used to speed up planning and ensure consistency across wells and projects. This also facilitates benchmarking and performance management across wells and assets. 

Governance & Approval Policies 

• AFE policies often define who must approve (operator, partners, finance, legal, HSE), depending on the project's size or risk. 

• Many companies have thresholds or rules for AFE revisions / supplemental AFEs: e.g., if cost deviation exceeds a certain percentage, or if scope changes, or at specific milestones before physical start or before reaching a certain completion percentage. 

• Post-close-out reporting and variance analysis are considered best practices for improving future cost estimates, optimizing cost categories, and managing risk. 

Cost-Optimization and Best-Practice Use of AFE 

An AFE is not just a budgeting tool. If done correctly, it becomes a cost-control and performance-management instrument. Key ways to leverage AFE for cost optimization: 

• Use standardized templates and historical data: For recurring wells (onshore, shallow offshore, deepwater), maintain a “master AFE” with optimized cost allocations and unit rates. This reduces the estimated lead time, ensures consistency, and allows benchmarking. Several service providers and operators use automated AFE templates for speed and consistency. 

• Focus on major cost drivers: By breaking down costs into granular, coded categories, you can identify which activities (rig day rate, mobilization, cementing, casing, directional drilling, non-productive time, contingency) consume the largest share of costs. Target these for cost reduction or efficiency campaigns. 

• Detailed Phase-Level Cost Breakdown: Prepare a comprehensive cost estimate for each hole section or operational phase, such as surface, intermediate, production hole, and completion activities. Break each phase down into standardized cost elements (rig spread rate, drilling services, bits/BHAs, mud, cementing, tubulars, logistics, testing, and contingency). This structured approach improves transparency during execution and allows the team to track actual spending against the plan in real time. Variances can be quickly identified and investigated, supporting faster corrective actions. During post-well analysis, the phase-level breakdown makes it easier to pinpoint overspending trends, understand cost drivers, and implement targeted optimization strategies for future wells. 

• Risk-based contingency and mitigation planning: Instead of applying a flat “buffer percent”, evaluate known risks (weather, remote logistics, technical complexity), assign a realistic contingency for each, and document the justification. This avoids unnecessarily high buffers and improves cost confidence. 

• Regular cost vs. actual tracking and variance analysis: Once drilling commences, track actual spend by cost category vs. AFE budget; analyze variances; implement corrective actions; capture lessons learned, which help refine future AFEs. 

• Integrated cross-functional collaboration: Involve drilling engineers, procurement, finance, legal, and operations early in AFE preparation. This ensures realistic assumptions, firm vendor quotes, procurement lead-times, and compliance with corporate, JV, and regulatory requirements. 

• Leverage digital tools / AFE-management software: Use software that integrates with well-management, accounting, and reporting systems. This reduces manual errors, improves data consistency, enables real-time lookbacks (budget vs actual), and supports faster decision-making. 

Typical Challenges & Common Mistakes — What to Watch Out For 

• Underestimating contingencies and risk exposure, especially on exploratory, deepwater, or complex wells. Flat-percentage contingency without risk quantification often leads to cost overruns. 

• Using overly generic templates or outdated unit rates, which may not reflect current market conditions or logistics costs (mobilization, rig rates, material inflation, rig availability). 

• Poor governance or lack of clarity on the AFE revision policy, leading to partners being surprised by supplementary AFEs mid-job or disputes over cost overruns. 

• Lack of variance tracking or post-job analysis wastes an opportunity to learn and optimize future wells. 

• Insufficient cross-functional involvement — e.g., procurement or HSE not consulted, leading to unrealistic rates, delays, or compliance issues. 

Recommendations for Drilling Professionals 

1. Develop a standardized AFE template (or master AFE) for each common well type in your portfolio (on-shore, offshore, deepwater, horizontal, vertical, workover). Use coded categories and ensure alignment with accounting / ERP systems. 

2. Maintain a vendor/contractor quote database and a historical cost database to feed into AFEs, so you use realistic, up-to-date rates rather than rough estimates. 

3. Integrate risk assessment and contingency justification into AFE preparation. Treat contingencies not as arbitrary buffers but as a quantified risk-management tool. 

4. Set clear AFE governance rules, including thresholds for supplemental AFEs, partner approvals, and variance reporting. 

5. Use digital or software tools (AFE management, project tracking, cost tracking) to automate, track, and benchmark. This improves transparency, reduces errors, and speeds up decision-making. 

6. After each well, conduct a post-mortem / lessons-learned exercise: compare budget vs actual, analyze variances, identify cost drivers and inefficiencies, and feed findings into your next AFE. 

A well-structured, transparent, and truly realistic AFE is more than just a budget approval document. It is the foundation for cost control, performance management, and continuous improvement in drilling operations. By following industry best practices, operators can better manage capital risk, reduce cost overruns, and achieve operational efficiency. 

References: 

1. Oil & Gas Online, 2024. Authorization for Expenditure (AFE). Oil & Gas Online. Available at: https://www.oilandgasonline.com/doc/authorization-for-expenditure-afe-0001. 

2. TIDJMA, 2024. PM–AFE Glossary Definition. TIDJMA. Available at: https://www.tidjma.tn/en/glossary/pm-afe-/. 

3. New Producers Group, 2019. Reference Manual for New Petroleum Producers. New Producers Group. Available at: https://www.newproducersgroup.online/wp-content/uploads/2020/11/Reference_manual-update_11012019_formatted.pdf. 

4. Eckard Enterprises, 2024. What Is an AFE in an Oil & Gas Investment? Eckard Enterprises. Available at: https://eckardenterprises.com/what-is-an-afe-in-an-oil-gas-investment/. 

5. Zanovoy, 2024. Implementing Authorization for Expenditure Policies in Oil & Gas Companies. Zanovoy. Available at: https://www.zanovoy.com/blog-posts/implementing-authorization-for-expenditure-policies-in-oil-gas-companies. 

6. PwC Indonesia, 2015. Oil and Gas in Indonesia: Investment and Taxation Guide. PwC Indonesia. Available at: https://www.pwc.com/id/en/publications/assets/oil_and_gas_guide_2015.pdf. 

7. Enerpact, 2024. eAFE — Electronic Authorization for Expenditure. Enerpact. Available at: https://enerpact.com/eafe.aspx. 

8. McKinsey & Company, 2015. How to Achieve a 50 Percent Reduction in Offshore Drilling Costs. McKinsey & Company. 

9. U.S. Energy Information Administration (EIA), 2016. Trends in U.S. Oil and Natural Gas Upstream Costs. U.S. EIA. 

10. Eagle River Energy Advisors, 2025. AFE Demystified: A Guide for Sellers and Buyers in U.S. Oil & Gas. Eagle River Energy Advisors. 

11. Finario, 2023. What Is an AFE — Authorization for Expenditure in Capital Planning? Finario. Available at: https://finario.com. 

12. Oil & Gas Overview, 2023. What Is an AFE (Authorization for Expenditure) in Oil and Gas? Oil & Gas Overview. Available at: https://oilandgasoverview.com. 

13. PwC, 2024. Oil & Gas Guide — Country and Capital Considerations. PwC. 

14. Baker Tilly, 2024. Gaining Cost Efficiencies While Increasing Drilling Operations. Baker Tilly. 

Disclaimer: This guide synthesizes and paraphrases industry best practices from referenced sources for educational and field-reference purposes only. It does not reproduce copyrighted material verbatim and is not official company policy or engineering advice. All information belongs to the original authors and publishers who retain full rights. No claim of original authorship is made for referenced concepts, and the document is distributed in good faith for drilling professionals.