1. Introduction

Our methodology for valuing petroleum investment opportunities adheres to the Society of Petroleum Engineers’ Petroleum Resource Management System (PRMS), which provides an integrated framework for classifying and estimating recoverable petroleum quantities and associated uncertainties. PRMS enables transparent, consistent, and auditable resource assessments by distinguishing between technical uncertainty (the range of recoverable volumes) and commercial uncertainty (the likelihood of project execution).

2. PRMS Classification and Commerciality.

PRMS organizes petroleum quantities into three primary categories based on project maturity and commercial viability:

• Reserves: Volumes anticipated to be commercially recoverable through development projects that are fully justified and approved.
• Contingent Resources: Volumes potentially recoverable, for which commercial development is not yet confirmed due to one or more contingencies.
• Prospective Resources: Volumes potentially recoverable from undiscovered accumulations following further exploration.

Each category is subdivided by chance of commerciality, reflecting technical progress and economic maturity. Reserves and Contingent Resources are attributable to discovered accumulations (100% discovery chance), so commerciality reduces to the chance of development.

3. Technical Volumes and Uncertainty

For all resource classes, PRMS requires three estimates representing the low, most likely (best), and high recoverable volumes:

• 1P, 2P, 3P for Reserves: Defined respectively as Proved, Proved plus Probable, and Proved plus Probable plus Possible reserves. Estimates may be derived via deterministic or probabilistic (e.g., Monte Carlo simulation) techniques.
• Low–Best–High for Resources: Analogous three-point estimates for Contingent and Prospective Resources.

Uncertainty in estimated volumes arises from subsurface heterogeneity, fluid properties, and modelling assumptions. For mature, producing fields with extensive production history, decline-curve analysis may yield a narrow uncertainty range, justifying convergence of 1P–3P values—provided rigorous documentation of assumptions, sensitivity analyses, and data quality.

4. Economic Assessment and Decision Criteria

Investment decisions integrate technical volume estimates with projected capital expenditure (CAPEX) and operating expenditure (OPEX) profiles for upstream facilities, processing, and transportation infrastructure. Key steps include:

• Cost Forecasting: Estimating CAPEX and OPEX for field development, including drilling, platforms, compression, and pipelines.
• Fiscal Modeling: Applying contractual terms (royalties, taxes, cost recovery) to net cash flows.
• Risk Adjustment: Discounting cash flows to account for time value of money and integrating chance of commerciality for Contingent and Prospective Resources.
• Economic Metrics: Calculating net present value (NPV), internal rate of return (IRR), and payback periods under low–best–high volume scenarios.

A project proceeds to sanction when economic metrics satisfy corporate thresholds under realistic reserve cases (typically 2P) and governance constraints.

5. Project Definition and Lifecycle Flexibility

A PRMS-compliant project may encompass a single accumulation or multiple pools, and can be subdivided or aggregated over time. For example, a full-field development concept may be redefined into a pilot program followed by a phased expansion. Each phase constitutes a separate project with its own resource classification, cost estimate, and commercial assessment.

6. Quantifying Commercial Risk

For Contingent and Prospective Resources, PRMS quantifies commercial uncertainty via the chance of commerciality (CoC), defined as:

                                                                         CoC = P(discovery) × P(development | discovery)

• For discovered accumulations (Reserves, Contingent Resources), P(discovery) = 100%, so CoC = P(development).
• For Prospective Resources, both discovery and development probabilities apply.

Reserves reporting assumes negligible development risk, and CoC is excluded. For Contingent Resources, CoC typically ranges 10–90% and must be explicitly documented.

7. Documentation and Auditability

PRMS emphasizes comprehensive documentation of data sources, assumptions, and methodologies:

• Geological and engineering data inputs (e.g., seismic interpretation, well logs).
• Reservoir simulation or analytical modelling parameters.
• Decline-curve fittings and uncertainty analyses.
• Economic parameters (cost estimates, commodity price forecasts).
• Decision‐gate criteria and approval timelines.

Robust audit trails ensure resource estimates withstand internal governance reviews and external audits.

8. Conclusion

Applying the PRMS framework ensures that investment decisions in petroleum assets are grounded in a systematic assessment of recoverable volumes, quantified uncertainties, and commercial viability. By integrating technical evaluations with economic modelling and risk quantification, our approach delivers transparent, consistent, and defensible assessments that support strategic planning and capital allocation.