Risk & Due Diligence

Geological Risk — Dry Holes and Resource Risk

Every well drilled into the earth carries geological uncertainty. Even with modern seismic imaging and decades of regional production data, the subsurface cannot be known with certainty until the bit reaches the target formation. A "dry hole" is a well that encounters no commercially viable hydrocarbons and must be plugged and abandoned. In a dry hole scenario, working interest owners lose their entire drilling investment. Even wells that encounter hydrocarbons may not produce at commercially viable rates if the reservoir is tighter, thinner, or more heterogeneous than predicted. Geological risk is highest in exploratory ("wildcat") wells and lower in development wells drilled adjacent to proven production.

Mechanical & Operational Risk

Drilling is a technically complex industrial operation, and mechanical problems can add significant cost or render a well uneconomic. Common mechanical risks include stuck pipe (the drill string becomes lodged in the wellbore), lost circulation (drilling fluid escapes into the formation), wellbore integrity failures, and equipment failures at the surface. After completion, production operations carry risks such as rod pump failures, paraffin buildup, corrosion, sand production, and compressor outages. A competent operator with experienced field personnel and a disciplined maintenance program can mitigate — but not eliminate — mechanical and operational risk.

Price & Market Risk

Oil and natural gas are globally traded commodities whose prices fluctuate based on supply, demand, geopolitical events, weather, and macroeconomic conditions. A project that is highly profitable at $80/bbl WTI may be marginally economic or uneconomic at $50/bbl. Participants should evaluate projects across a range of price scenarios, not just current market prices. Gas prices (Henry Hub) are often even more volatile than oil prices. In addition to price risk, basis differentials — the difference between benchmark prices and the actual price received at the wellhead — can vary significantly by region and pipeline access. Hedging strategies can reduce price exposure but add their own complexity and cost.

Operator Risk — Evaluating Track Record and Financials

The operator controls all day-to-day decisions: drilling contractor selection, well design, completion design, cost management, and production operations. A poorly performing operator can turn an otherwise sound geological prospect into a money-losing project. When evaluating an operator, key questions include: What is their drilling track record in this basin? Do their historical AFEs match actual costs? Are they financially stable enough to cover their share of costs without calling on working interest owners for emergency cash calls? Is their back-office capable of producing accurate, timely revenue and JIB statements? Do they have a history of regulatory violations or environmental incidents? Participant due diligence on the operator is as important as geological due diligence.

Reading an Authorization for Expenditure (AFE)

An Authorization for Expenditure (AFE) is the budget document an operator presents to working interest owners before a major expenditure — typically the drilling and completion of a new well. The AFE itemizes estimated costs by category: drilling days and day rates, casing and tubulars, cementing, logging, completion (perforating, fracturing, etc.), equipment, and overhead. It states the total estimated gross well cost and each participant's proportionate share based on their working interest. The AFE is not a fixed-price contract; actual costs can exceed the estimate. Review the AFE critically: Are the day rates and service costs consistent with current market conditions? Is there a contingency budget? How does the estimated cost compare to the operator's historical AFE accuracy?

• Drilling costs: rig day rates × estimated drilling days, plus directional drilling services
• Casing program: surface, intermediate, and production casing, plus cementing
• Completion costs: perforating, fracturing fluid and sand, wireline, wellhead equipment
• Facilities & flowline: tanks, separators, meters, and connection to gathering
• Overhead & supervision: operator's administrative overhead, often a fixed percentage
• Contingency: a reserve for unexpected costs, typically 10–15% of the subtotal

Red Flags & Common Pitfalls

Experience in the oil and gas industry reveals recurring warning signs that deserve extra scrutiny from potential participants.

• Guaranteed returns: No legitimate operator can guarantee production or returns. Hydrocarbons are a depleting natural resource with inherent uncertainty.
• Pressure to decide quickly: High-quality operators do not need to create artificial urgency. Time pressure is a sales tactic, not a legitimate operational constraint.
• Lack of verifiable track record: If an operator cannot provide a documented history of actual wells drilled, costs incurred, and production achieved, that is a significant concern.
• Unusually high working interest spreads: If the operator is selling working interests at a significant markup to their own cost, understand what you are paying for and why.
• Vague or incomplete operating agreements: The operating agreement governs your rights as a non-operator. An operator reluctant to provide a complete, industry-standard agreement is a red flag.
• No independent reserve estimate: For larger investments, a third-party reserve report from a qualified petroleum engineer provides an independent view of the prospect's potential.