Optimizing Well Costs Through Effective Use of Authorization for Expenditure (AFE)

1. Introduction

The Authorization for Expenditure (AFE) is one of the most important financial control tools in upstream oil and gas operations. Beyond being a budgeting and approval requirement, a well-structured AFE enables transparent planning, disciplined cost control, and continuous improvement across the drilling portfolio. When prepared using accurate benchmarks, standardized formats, phase-level breakdowns, and integrated planning, the AFE can be a strategic cost-management tool.

When used effectively, AFEs help operators:

Establish near-accurate cost expectations
Track and investigate variances
Improve contracting and supply chain strategy
Strengthen partner confidence and governance
Optimize performance and cost outcomes on future wells

This document consolidates recognized industry practices, benchmarking insights, and field experience to serve as a practical guide for drilling and project teams.

2. Building an Effective AFE

2.1 Accurate, Transparent Estimates

A reliable AFE starts with realistic, evidence-based assumptions that reflect current market conditions and actual operational performance.

Use up-to-date benchmark data from internal well cost systems, recent offset wells, and regional peer performance to establish a credible baseline.
Obtain current, written vendor quotations for major services, such as rigs, cementing, directional drilling, logging, mud services, and tubular running to minimize pricing uncertainty.
Incorporate practical downtime assumptions that reflect known risks such as weather exposure, logistics delays, wellbore stability challenges, and the typical range of NPT events observed in the area.
Clearly document all underlying assumptions, including rig day rates, materials pricing, fuel assumptions, exchange rates, service availability, and any escalation factors.
Avoid using broad, unjustified contingencies or “padding.” Excessive buffers obscure actual risks, weaken planning discipline, and reduce accountability for performance improvements.

Accurate inputs and transparent assumptions form the foundation for an AFE that can withstand internal review and operational scrutiny.

2.2 Standardization for Repeatability

For wells with similar designs or recurring field development programs, maintain a standardized AFE master template that includes:

Typical rig spreads and associated service configurations
Proven, optimized well designs
Validated service rates and contract terms
Historical performance metrics and NPT trends

Standardization drives consistency, shortens the estimate-generation cycle, and provides a strong baseline for vendor negotiations and continuous improvement. It also ensures that lessons learned from previous campaigns are captured and embedded in the next well’s cost model.

2.3 Phase-Level Cost Breakdown

Break the AFE down by hole section or major operational phase, and within each phase, itemize costs under standardized categories such as:

Rig time and services
Directional drilling and MWD/LWD
Drilling fluids and solids control
Bits and BHAs
Casing and tubulars
Cementing services and materials
Logistics and transportation
Rentals and third-party equipment
Completion or testing services (if applicable)

A granular phase-level breakdown supports:

Real-time visibility into cost overruns during execution
Rapid identification of inefficiencies or unexpected events
Robust post-well reviews with clear links between operational decisions and cost impacts
More accurate forecasting and progressive improvement in future AFEs

This approach ensures that both operations and finance teams are aligned around how and where costs are generated.

2.4 Controllable vs. Non-Controllable Costs

Categorize AFE inputs as controllable or non-controllable to sharpen focus on areas where operational teams can influence outcomes.

Controllable costs include:

Drilling performance and rate-of-penetration optimization
Bit and BHA selection and run strategy
Logistics and supply chain efficiency
Optimization of service utilization
Effective management of NPT and operational risks

Non-controllable costs include:

Tangible equipment and materials required for the well based on approved design specifications (e.g., casing, wellhead, tubing, liner equipment)
Regulatory fees and government-mandated charges
Statutory taxes and royalties
Insurance requirements
Region-specific surcharges or premiums

By directing improvement efforts toward controllable cost drivers, operators can achieve great cost-efficiency gains.

2.5 Rig and Contract Strategy

Rig contracting strategy and service procurement have a major influence on overall well cost.

Negotiate clear terms for mobilization/demobilization, standby rates, performance-based incentives, and penalties where appropriate.
Consider incentive/dayrate hybrids to align contractor performance with well objectives.
Use longer-term contracts or campaign-based contracting when operational stability allows, as this often secures more favorable pricing and reduces mobilization costs.
Evaluate integrated service packages (e.g., DD + MWD/LWD + motors) to reduce interface complexity, streamline execution, and improve performance accountability.

A thoughtful contracting strategy ensures tighter cost control and more predictable operational outcomes.

2.6 Integrated Planning (Procurement + Operations + Finance)

AFE development must be a collaborative process that brings procurement, operations, finance, and supply chain together early.

Key considerations include:

Currency exposure and exchange-rate assumptions
Insurance and certification requirements
Tariffs, customs duties, and tax implications
Vendor lead times, material availability, and supply bottlenecks
Contract maturity, renewal options, and alternative sourcing strategies

Early cross-functional alignment helps avoid late-stage surprises, minimizes procurement-driven delays, and ensures that the AFE reflects realistic commercial and logistical constraints.

3. Using AFEs for Cost Optimization

3.1 AFE vs. Actual Tracking

During drilling operations, actual costs should be compared against the AFE through a structured, continuously updated variance register. This enables:

Real-time identification of deviations from planned spend, whether driven by rig days, services, materials, or unexpected events.
Root-cause analysis of significant variances to determine whether they were design-related, operational, supply-chain driven, or caused by external factors.
Systematic capture of lessons learned, ensuring each variance informs the next well’s AFE and planning process.
Enhanced transparency for partners and stakeholders, supporting accurate reporting and building trust in the forecasting process.

Consistent AFE-actual tracking is fundamental to institutional learning, allowing organizations to continually refine well design, execution strategies, and cost prediction models.

3.2 Right-Sizing the Contingency

Contingency should be a deliberate, risk-based allowance, not a blanket percentage added to every AFE. Effective contingency management includes:

Risk-based allocation, tied to clearly identified uncertainties such as directional drilling complexity, potential fluid losses, weather exposure, permitting delays, or supply-chain constraints.
Alignment with risk registers and probabilistic analysis, ensuring each allowance corresponds to a realistic operational or commercial exposure.
Reduction of contingency where uncertainty is low, particularly when:
Firm vendor quotes exist for key cost items, reducing commercial variability.
Offset well data demonstrates stable, repeatable performance, indicating lower operational variability.

Under these conditions, uncertainty is low for both price and execution; therefore, a smaller contingency is sufficient and supports stronger cost discipline. Right-sizing contingency improves budgeting accuracy and strengthens partner confidence in the AFE.

4. Special Considerations by Well Type and Environment

4.1 Onshore (Land Wells)

Onshore wells typically offer more predictable operations and lower logistical complexity. Key cost levers include:

Multi-well pad drilling reduces mobilization frequency and improves cycle time.
Shared mobilization and services, such as common mud systems, camps, maintenance, and trucking.
Local supply chain optimization, including regional sourcing of cement, fuel, and drilling fluids.
Simplified logistics, with shorter transport distances and lower dependence on weather-sensitive operations.
Faster equipment turnaround and rig move load optimization, enabling quicker transitions between wells.

These characteristics often translate to lower operational risk and more predictable AFE performance.

4.2 Offshore (Shallow Water)

Shallow-water operations introduce different cost dynamics, primarily driven by marine logistics and rig selection. Key cost considerations include:

Higher vessel and barge requirements, increasing spread rates, and scheduling complexity.
Weather-related downtime, particularly during monsoons or seasonal storms.
The type of rig used, such as a jackup, tender-assist unit, or small semisubmersible, has a major impact on overall well cost.
Standardized wellhead, completion, and tie-in designs can reduce vessel-days and simplify installation activities.

Because shallow-water wells blend marine and drilling operations, coordination among rig, vessel, and logistics planning is critical to controlling costs.

4.3 Deepwater Wells

Deepwater wells are the most capital-intensive due to complex subsea systems, vessel spreads, and high day rates. Cost drivers include:

High floater rig day rates and long mobilization distances.
Large marine logistics requirements, including supply vessels, ROV support, and specialist subsea personnel.
Long-lead-time equipment such as BOPs, marine risers, LMRPs, subsea wellheads, and completion systems.
Station-keeping requirements, including DP3 systems, increase fuel and crew costs.
Intricate subsea operations, from running casing strings with riser tensioners to deploying subsea trees.

Proven optimization levers include:

Standardizing rig classes and subsea equipment, improving efficiency and predictability.
Integrated service packages, reducing interface risks and lowering operational downtime.
Staged or regional logistics hubs, shortening resupply routes and reducing vessel time.
Daily KPI-driven performance monitoring, including ROP, tripping speeds, BOP downtime, marine spread effectiveness, and NPT.

These measures are widely adopted in deepwater basins to manage costs without compromising safety or well objectives.

4.4 Exploration vs. Development Wells

Exploration and development wells have fundamentally different risk profiles and cost structures.

Exploration AFEs typically require:

Higher contingency, due to limited offset data and higher geological and operational uncertainty.
Allowances for sidetracks, data acquisition runs, or appraisal-driven complexity.
Greater flexibility in time and cost estimates because subsurface risks are less defined.

Development AFEs benefit from:

Consistent analog well data, improving predictability and estimate accuracy.
Standardized designs, including casing programs, wellheads, mud systems, and BHA selections.
More reliable supply chain planning, with predictable material usage and service demand.
Lower contingency, reflecting reduced uncertainty and repeatable performance.

This distinction ensures that AFEs appropriately match the risk level and data confidence for each well type.

5. Practical Cost-Reduction Measures

Below are proven strategies widely used by major operators to reduce well costs without compromising safety or well integrity.

Drilling Performance & Engineering

Optimize well design, including casing setting depths, BHA selection, mud-weight profiles, and the decision to use liners versus full casing strings. Design optimization that meets technical requirements reduces materials, trips, and overall well time.
Minimize NPT through strong operational planning and discipline, pre-job risk assessments, hazard identification workshops (HAZIDs), and real-time well monitoring. Reducing NPT has the highest direct impact on final well cost.
Use performance-based or incentive contracts, where contractors share in the value created from efficiency improvements (e.g., footage-based incentives, flat-time reduction bonuses). These models align service provider performance with operator objectives.

Operational Efficiency

Implement multi-well pad drilling where applicable to minimize rig moves and reduce mobilization/demobilization costs. Pad drilling significantly improves cycle time in many land drilling programs.
Standardize equipment, procedures, and well designs across a field or development campaign. Standardization improves repeatability, simplifies training, reduces inventory variation, and strengthens procurement leverage with vendors.
Enhance execution planning through detailed stage-by-stage operations programs and pre-spud readiness checks to avoid delays.
Improve equipment and material management by increasing backloading efficiency, reducing the number of loads required during rig moves, and ultimately shortening the well-to-well turnaround time.

Supply Chain & Inventory

Use centralized inventory and materials management to avoid excess rental charges, reduce storage costs, and limit the need for premium freight or last-minute air shipments.
Develop local or regional suppliers where practical to shorten lead times, avoid import constraints, and reduce logistics costs.
Coordinate procurement with drilling schedules to ensure long-lead items such as casing, wellheads, and motors are secured in advance to avoid downtime or rush logistics.

Digital and Analytics

Deploy real-time KPI dashboards covering ROP, tripping speed, NPT categories, logistics usage, and flat-time performance. Transparent KPIs help drive operational accountability.
Use predictive maintenance tools to monitor critical rig equipment (top drives, mud pumps, drawworks) and reduce unplanned failures that lead to costly downtime.
Automate data capture for time tracking, cost performance, and operational efficiency. Automated data reduces reporting errors and accelerates post-well analysis.

6. Accounting & Governance for AFEs

Strong financial governance ensures AFEs remain effective tools for cost control and partner alignment.

6.1 Approval Thresholds

Establish tiered approval levels based on the size, risk, and materiality of the project:

Project / Well Engineer
Drilling Superintendent or Drilling Manager
Asset Manager
Finance Manager / CFO or delegated authority
Partner approvals, where working-interest owners or joint ventures require authorization

AFE revisions should show a clear version history, justification for changes, and updated risk considerations. This helps ensure transparent decision-making and proper spending control.

6.2 AFE Supplements / Revisions

When actual costs are forecast to exceed the approved AFE:

Issue an AFE supplement or revision before the spend is incurred.
Provide a clear breakdown of the cost drivers leading to the overrun (e.g., additional rig days, new equipment requirements, unforeseen conditions).
Obtain all necessary internal approvals and, when applicable, partner approval.
Track supplements independently of the original AFE for auditability, cost-recovery accuracy, and transparent partner reporting.

These practices prevent unauthorized overspending, improve fiscal discipline, and maintain trust across joint ventures.

Conclusion

An AFE is far more than an administrative approval; it is a strategic cost-management tool. When prepared using accurate benchmarks, standardized formats, phase-level breakdowns, and integrated planning, the AFE becomes:

A realistic cost forecast
A performance benchmark
A variance management tool
A lessons-learned repository
A driver of continuous improvement and cost optimization

If used effectively, AFEs significantly strengthen operational discipline, financial efficiency, and well-delivery performance across the drilling campaigns.

References:

IADC (International Association of Drilling Contractors). 2019. Drilling Cost Management Frameworks and Deepwater Well Control Guidelines. IADC Publications.
API (American Petroleum Institute). 2018. Well Construction and Equipment Standards, including API RP 92 Series and API Specification 6A. API Standards.
SPE (Society of Petroleum Engineers). Various Years. Technical Papers on Well Cost Estimation, Probabilistic AFE Methods, and Deepwater Operations Benchmarking. SPE International.
IOGP (International Association of Oil & Gas Producers). 2016. Well Cost Benchmarking and Performance Standards. IOGP Report.
DNV GL. 2017. Deepwater Drilling and Subsea Equipment Recommended Practices. DNV Guidelines.
ABS (American Bureau of Shipping). 2018. Guidance Notes on Deepwater Drilling Operations. ABS Publications.
Shell, Chevron, BP, Equinor. Various Years. Public Operator Case Studies on Cost Management and AFE Governance, presented at SPE/IADC Drilling Conferences.
McKinsey & Company. 2015. How to Achieve a 50% Reduction in Offshore Drilling Costs. McKinsey Insights.
U.S. Energy Information Administration (EIA). 2016. Trends in U.S. Oil and Natural Gas Upstream Costs. EIA Report.
Eagle River Energy Advisors. 2025. AFE Demystified: A Guide for Sellers and Buyers in U.S. Oil & Gas. Eagle River Publication.
Finario. 2023. What Is an AFE: Authorization for Expenditure in Capital Planning. Finario (finario.com).
Oil & Gas Overview. 2023. What Is an AFE (Authorization for Expenditure) in Oil and Gas? OilAndGasOverview.com.
PwC. 2024. Oil & Gas Guide: Country and Capital Considerations. PwC Insights.
Baker Tilly. 2024. Gaining Cost Efficiencies While Increasing Drilling Operations. Baker Tilly Industry Report

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.