Proved and Probable Reserves
Executive Summary
Key Takeaways
- ✓ Reserves are classified as proved (1P), proved plus probable (2P), or proved plus probable plus possible (3P), each representing a progressively lower level of certainty about recoverable volumes.
- ✓ Proved reserves are estimated with reasonable certainty to be commercially recoverable under existing economic and operating conditions, the highest-confidence category.
- ✓ Which reserve category is appropriate depends on the model's purpose, reserve-based lending facilities typically size the borrowing base against proved reserves alone, while internal planning sometimes uses 2P volumes for a fuller resource picture.
- ✓ Using a higher-certainty category's methodology to justify a lower-certainty category's volumes, or vice versa, materially distorts the reliability of the resulting valuation or financing analysis.
Definition¶
Proved (1P), proved plus probable (2P), and proved plus probable plus possible (3P) reserves are the standard classification system for the certainty of estimated recoverable hydrocarbon volumes, set out in the Petroleum Resources Management System.
The Three Categories¶
Proved reserves. Estimated with reasonable certainty to be commercially recoverable under existing economic and operating conditions, the highest-confidence category.
Probable reserves. Less certain than proved, but more likely than not to be recovered.
Possible reserves. Less likely than probable to be recovered, the lowest-confidence category typically included in reserve reporting.
2P combines proved and probable; 3P adds possible reserves to that total.
Why Category Choice Matters to Modelling¶
Which category is appropriate depends on the model's purpose. A reserve-based lending facility typically sizes its borrowing base against proved reserves alone, reflecting the lender's need for a high-confidence volume basis, while internal planning models sometimes incorporate 2P volumes for a fuller picture of the resource. Using a lower-certainty category's volumes to justify a higher-confidence purpose, sizing a lending borrowing base against 3P reserves, for example, materially overstates what the underlying resource actually supports, addressed in full in Upstream Financial Models.
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Frequently Asked Questions
What are proved, probable and possible reserves?
Proved (1P) reserves are estimated with reasonable certainty to be commercially recoverable under existing conditions. Probable reserves are less certain than proved but more likely than not to be recovered. Possible reserves are less likely than probable to be recovered. 2P combines proved and probable; 3P adds possible reserves to that total.
Why does reserve category matter for financial modelling?
Because different modelling purposes require different levels of certainty, a reserve-based lending borrowing base is typically sized against proved reserves alone, while internal planning analysis sometimes incorporates 2P volumes for a fuller resource picture, and applying the wrong category to a given purpose materially distorts the result.
Who sets the standard for reserve classification?
The Petroleum Resources Management System (PRMS), jointly maintained by the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers, is the principal international reserve and resource classification standard.
What happens if a model uses 2P or 3P reserves where a lending facility requires proved reserves?
It overstates the volumes and value that should support the borrowing base, since probable and possible reserves carry materially lower certainty than proved reserves and are not the basis a reserve-based lending facility is typically sized against.
References
- Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists, Society of Petroleum Evaluation Engineers — Petroleum Resources Management System (PRMS 2018)
- U.S. Securities and Exchange Commission — Modernization of Oil and Gas Reporting (17 CFR Part 210, Rule 4-10)
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Oil & Gas Financial Modelling
Oil and gas financial modelling is the practice of building financial models across the four structurally distinct segments of the hydrocarbon value chain, upstream exploration and production, midstream transport and processing, downstream refining and petrochemicals, and LNG, each governed by different revenue mechanics, contract structures and risk drivers. This page is the hub for the Knowledge Centre's oil and gas financial modelling content: industry structure and segment definitions, the financial KPIs the sector is measured against, the investment lifecycle from exploration through decommissioning, and how this domain builds toward asset and project-level models, commercial and investment analysis, and governance and assurance practice as it expands.
Upstream Financial Models
Upstream financial models project revenue and debt capacity from a depleting reserve base using a production decline curve rather than a steady-state or growth volume forecast common to most other industries. This guide sets out how upstream models are structured around exploration and production economics, reserve categories, decline mechanics, fiscal terms, and the reserve-based lending structures that finance the segment, the foundational technical grounding this domain's asset-level and commercial analysis content builds on.
Reserve-Based Lending
Reserve-based lending (RBL) is the dominant financing structure for upstream oil and gas assets, tying the available borrowing base to the discounted value of proved reserves under a bank-defined price deck, redetermined periodically, typically semi-annually, against updated reserve and price estimates. The financial model supporting an RBL facility must replicate the lender's specific borrowing base methodology precisely, since an approximated version will not match the actual facility mechanics.
Reserve Replacement Ratio
Reserve replacement ratio is the ratio of reserves added, through discovery, extension or acquisition, to reserves produced in a given period. A ratio above 100% indicates a company is adding reserves faster than it depletes them; below 100% indicates its reserve base is shrinking. It should always be read alongside finding and development cost, since a strong ratio achieved at disproportionately high cost is not equivalent to sustainable, economic reserve growth.