Reserves, Oil & Gas Glossary

What Are Reserves?

Reserves are the estimated quantities of oil, natural gas, and natural gas liquids that are anticipated to be commercially recoverable from known accumulations from a given date forward under existing economic conditions, operating methods, and government regulations — classified as proved (1P), proved plus probable (2P), or proved plus probable plus possible (3P) under the SPE Petroleum Resources Management System — and represent the fundamental measure of an oil and gas company's asset value, underpinning stock market valuation, debt covenants, royalty calculations, and national resource accounting from Alberta to Abu Dhabi.

Key Takeaways

The SPE-PRMS (Petroleum Resources Management System), jointly published by the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists, and Society of Petroleum Evaluation Engineers, is the global industry standard for reserve classification and reporting — providing consistent definitions used by regulators, investors, and national oil companies worldwide.
Proved reserves (1P) have a "reasonable certainty" standard — at least 90% probability of recovery under existing economic and operating conditions; probable reserves (2P minus 1P) have at least 50% probability; possible reserves (3P minus 2P) have at least 10% probability, with the increments representing successively lower confidence levels.
The SEC's Rule 4-10 (Regulation S-X) governs proved reserve disclosures for US-listed companies: reserves must be estimated using 12-month average trailing commodity prices, and proved undeveloped reserves (PUDs) must have a specific development plan with a project to drill within 5 years.
Canada's NI 51-101 (Standards of Disclosure for Oil and Gas Activities) governs reserve disclosures for TSX-listed companies, requiring annual independent reserve evaluations and disclosure of gross and net reserves at 1P, 2P, and 3P levels with NPV at multiple discount rates.
The difference between reserves and resources is commercial certainty: reserves are commercially recoverable today under current conditions; contingent resources require further development, delineation, or improved economics before they meet the commerciality threshold for reserve classification.

How Reserves Are Estimated

Reserve estimation uses three primary methods: volumetric analysis (estimating in-place volume from reservoir geometry and rock/fluid properties, then applying a recovery factor), decline curve analysis (extrapolating historical production rate trends to an economic abandonment rate), and reservoir simulation (numerical modelling of fluid flow through a 3D geological model calibrated to pressure and production data). For most producing wells, decline curve analysis provides the primary estimate with volumetric methods as a sanity check. For early-stage fields with limited production history, volumetric methods dominate; for mature fields with complex recovery mechanisms, reservoir simulation is used.

Reserve estimates are classified by evidence quality: proved developed producing (PDP) reserves have the highest certainty — they are behind pipe and actively producing; proved developed non-producing (PDNP) reserves are behind pipe but shut-in or waiting on completion; proved undeveloped (PUD) reserves require future well drilling or completion but are supported by well performance or geological control from adjacent wells. The classification distinction matters for valuation: PDP reserves trade at higher multiples per barrel than PUD reserves because the development capital has already been spent and the production certainty is higher.

Reserve Reporting Across International Jurisdictions

In Canada, NI 51-101 requires all TSX-listed oil and gas companies to file an Annual Information Form (AIF) containing a full reserve evaluation prepared or audited by an independent Qualified Reserves Evaluator (QRE) or Qualified Reserves Auditor (QRA) as defined by the Canadian Oil and Gas Evaluation Handbook (COGEH). The AIF discloses gross and net reserves by category (1P, 2P, 3P), finding and development costs, reserve life index, and NPV at 5%, 10%, 15%, and 20% discount rates. AER Directive 065 governs individual pool establishment and reserve declarations in Alberta; the AER maintains the Alberta reserve database and uses declared reserves for royalty administration and resource management. Companies including Canadian Natural Resources, Cenovus, and Suncor disclose reserves annually under NI 51-101.

In the United States, SEC Rule 4-10 governs proved reserve disclosures; all registrants with US-listed securities must comply, and reserve reports are filed annually as part of the 10-K. The SEC's 2009 modernisation rules updated the price-deck requirement (from single-day year-end price to 12-month trailing average), allowed probabilistic reserve estimation for proved undeveloped reserves, and expanded the categories of technologies acceptable for reserve estimation to include 3D seismic, log analysis, and core analysis. BSEE tracks OCS production and receives reserve reports for offshore lease administration. In Norway, Sodir publishes an annual National Resource Account compiling reserves and resources by field across the Norwegian Continental Shelf using SPE-PRMS-equivalent classifications; Johan Sverdrup's 2P reserves were estimated at 2.7 billion barrels oil equivalent at field sanction in 2015. In Australia, ASX-listed oil and gas companies disclose reserves under the JORC Code (Joint Ore Reserves Committee Code), which is Australia's equivalent of SPE-PRMS for mineral and petroleum reporting; NOPSEMA's petroleum production reporting framework tracks production against reserve declarations for offshore fields. In the Middle East, Saudi Aramco published reserve disclosures in its 2019 IPO prospectus following SEC guidelines, declaring 268 billion barrels of proved reserves — the largest proved reserve declaration by a single company in history, subject to independent certification by DeGolyer and MacNaughton and Gaffney Cline and Associates.

Fast Facts

Saudi Aramco's 268 billion barrels of proved reserves (as of 2019) represent approximately 17% of all proved crude oil reserves on Earth — enough to supply the entire world's current oil consumption for over 7 years from a single company's declared reserves. By comparison, the combined proved reserves of ExxonMobil, Shell, Chevron, BP, and TotalEnergies are approximately 65 to 75 billion barrels oil equivalent — less than 30% of Aramco's single-company total.

Proved vs. Probable vs. Possible Reserves

The distinction between 1P, 2P, and 3P reserves reflects confidence in recovery under defined economic conditions. Proved reserves (1P) represent the low-risk, high-confidence estimate: only well-demonstrated production performance, clear geological control from nearby producing wells, or robust reservoir simulation history-matching qualifies. Adding the probable increment (to reach 2P) incorporates reasonable geological extrapolation beyond the area of proved performance, additional reservoir drive mechanisms that may improve recovery, and development upside from infill drilling that is technically feasible but not yet committed. The possible increment (to reach 3P) adds high-case scenarios — better-than-expected reservoir continuity, improved recovery factors, or development options not yet in the formal plan. For most acquisition and divestiture purposes, 2P is the deal-pricing basis; for reserve-based lending (RBL) structures, banks typically lend against a fraction of 1P value.

Tip: When comparing proved reserve estimates between two companies, confirm whether the figures are gross (100% of working interest production) or net (the company's working interest share of production net of royalties). A company with a 75% working interest in a field with 100 million barrels gross has 75 million barrels working interest reserves but only 60 million barrels net reserves after a 20% royalty — a 40% difference from the gross headline number. NI 51-101 requires disclosure of both gross and net reserves; US 10-K filings report net reserves under SEC rules.

Reserves is also known as:

1P / 2P / 3P — the shorthand for proved, proved plus probable, and proved plus probable plus possible reserves; standard notation in SPE-PRMS, NI 51-101, and JORC Code documentation
Proved reserves — the SEC and NI 51-101 term for the highest-confidence reserve category; required disclosure for all listed oil and gas companies
PDP / PDNP / PUD — sub-categories of proved reserves: Proved Developed Producing, Proved Developed Non-Producing, and Proved Undeveloped; used in reserve valuation and RBL lending
Resource base — the broader term including reserves plus contingent and prospective resources; all hydrocarbons that might be recovered under any future technical or economic scenario

Related terms: OOIP, recovery factor, decline curve, NPV, working interest, royalty

Frequently Asked Questions

What is the difference between reserves and resources?

Reserves are discovered hydrocarbon accumulations that are commercially recoverable under current economic and operating conditions — the "bankable" volumes that support company valuations and debt. Resources include all hydrocarbons that might be technically recoverable under any scenario, including contingent resources (discovered but not yet commercial) and prospective resources (undiscovered — exploration upside). The key distinction is commerciality: reserves have a definite development plan and meet the economic threshold today; contingent resources do not yet meet one or both criteria.

How are proved reserves different from probable reserves?

Proved reserves (1P) have at least 90% probability of recovery under existing conditions — they are supported by production history, well-established geological control, or rigorous reservoir simulation. Probable reserves (the 2P minus 1P increment) have at least 50% probability — they include geological extrapolation beyond the proved area, development upside not yet committed, and recovery mechanisms that may perform better than the base case. The proved increment is used for debt covenants and lending; the probable increment is included in acquisition pricing and long-range planning.

Who certifies oil and gas reserves?

In Canada, NI 51-101 requires independent certification by a Qualified Reserves Evaluator (QRE) registered under the applicable provincial securities laws. In the US, companies typically use independent third-party reserve engineering firms (DeGolyer and MacNaughton, Ryder Scott, Netherland Sewell, Cawley Gillespie) or internal qualified petroleum engineers compliant with SEC requirements. In Norway, Sodir's national resource accounts are compiled from operator-submitted data reviewed against production records. Saudi Aramco's IPO reserve certification was performed by DeGolyer and MacNaughton and Gaffney Cline and Associates as independent internationally recognised firms.

Why Reserves Matter in Oil and Gas

Reserves are the currency of the oil and gas industry. They determine company valuations on public markets, underpin reserve-based lending that funds development drilling programmes, govern royalty calculations that determine government revenue in every producing jurisdiction, and drive national energy policy decisions from Ottawa to Riyadh. A company that grows its proved reserves year-over-year — replacing production with new additions through drilling, acquisition, or improved recovery — is creating value. One that fails to replace production is in decline. The discipline of accurate, audited, consistently-applied reserve estimation under NI 51-101, SEC Rule 4-10, and SPE-PRMS is what makes the global oil and gas industry's asset values legible to capital markets — and the integrity of that discipline, enforced by independent reserve evaluators and securities regulators, is one of the foundational governance standards of the upstream sector.

Reserves: Definition, SPE-PRMS Classification, and Reporting Standards