Fixed Costs, Variable Outcomes: Why Cost Assumptions Matter in Reserves Reporting

In reserves reporting, one constant holds true: reserves must be "economically producible." The revenues they generate must exceed the costs of production. Yet, the approach to modeling operating costs in reserves reports varies, and those variations can significantly impact both reserve estimates and their associated value. For users of reserves reports, this underscores the importance of understanding the nuances of cost treatment.

Defining the Ground Rules

The Petroleum Resources Management System (PRMS) permits changes to future costs over time, aligning with its emphasis on realistic cash flows. However, the Securities Exchange Commission’s (SEC's) reserves reporting rules mandates constant pricing and cost assumptions. Most practitioners interpret this to mean a constant cost structure, which has led to widespread use of two common methods for modeling operating costs: the "fixed" cost approach and the "fixed plus variable" method.

The Devil in the Details

The so-called "fixed" method, perhaps better described as the "well variable" method, assumes that as wells reach their economic limit, they are shut in, eliminating their associated revenues and costs. While this method adheres to SEC guidelines, it has a limitation: it assumes that shutting in a well will reduce operating expenses. However, in reality, significant costs may be field-level and persist regardless of well count. For example, labor costs typically remain unchanged until there are substantial reductions in active wells.

To address this, evaluators often add a production-based variable component, tying costs to fluid production rates. Wells producing more fluid typically incur higher lifting costs due to increased utility, chemical, and disposal expenses. However, even this refinement can fall short of capturing the true cost dynamics in many fields.

Implications for Reserves and Value

In practice, reserve reports based on the "well variable" method may result in wells reaching their economic limit earlier than they should, leading to conservative reserves estimates but optimistic value estimates. Wells operating today may be deemed “uneconomic” simply due to cost allocation methods rather than actual operating conditions.

Transactional analyses often highlight these discrepancies by relying on reports that were prepared under SEC standards, predicting a lower well count over time (and perhaps even from the first forecast month) compared to current and expected operations.

Better Cost Modeling for Better Decisions

One way to address these issues is by applying a group economic limit, treating the field as a single project. This approach extends production timelines for wells calculated as "uneconomic", resulting in higher reserve estimates but lower overall value, as the field-level costs allocated to the wells are retained. Another (and essentially equivalent) approach is using a true fixed cost model, independent of well count, paired with production-variable costs. While these approaches require more detailed analysis, they provide a more accurate representation of future costs and cash flows.

The Takeaway

Understanding how operating costs are modeled in reserves reports is not just a technical exercise—it directly influences reserves estimates and their derived value. For investors, operators, and other users, digging deeper into the underlying assumptions is essential. Reserves must be economically producible, but a clear-eyed view of costs is necessary to ensure decisions are grounded in reality.

By examining the treatment of costs—whether as fixed, variable, or some hybrid—users can better assess the accuracy of reserve forecasts, gauge their suitability for a particular purpose and make more informed decisions about the assets in question.

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Sources

1. Petroleum Resources Management System, Society of Petroleum Engineers, et. al., November 2011.
2. Final Rule: Modernization of Oil and Gas Reporting, US Securities and Exchange Commission, effective January 1, 2010.