Introduction
A reserve report is an essential technical document behind an oil and gas investment. It covers subsurface geology, well data, and price assumptions to estimate recoverable volumes and their projected cash flows. Those estimates are also what influence company valuations, capital budgets, and acquisition decisions. However, a reserve report is not a guarantee of future revenue. The headline reserve figure matters, but investors should also ask what portion is produced today, how much capital is left to be spent, and what assumptions support the valuation.
What Oil and Gas Reserves Mean
Oil and gas reserves are the estimated volumes expected to be economically recoverable from known reservoirs within defined development projects. They are much narrower than resources, which may include potential volumes that need more drilling, technology, infrastructure, or stronger economics before they qualify as reserves.
A reserve report typically includes reserve volumes by category, production forecasts, price and cost assumptions, future development spending, discounted cash-flow values, and a reconciliation showing how estimates changed during the year. For U.S. reporting, proved reserves are volumes supported by geological and engineering data that can be estimated with reasonable certainty to be economically producible under existing conditions. A company may control a large resource base without being able to classify all of it as proved reserves.
Image Credit: Pexels
How Do Oil and Gas Reserves Reports Classify Reserve Categories?
Reserve reports are divided into three categories described under the Petroleum Resources Management System framework:
- Proved reserves, or 1P, have at least a 90% probability of being met or exceeded under the assumptions used in the estimate.
- Probable reserves, or 2P when combined with proved reserves, have at least a 50% probability of being met or exceeded.
- Possible reserves, or 3P when combined with proved and probable reserves, have at least a 10% probability of being met or exceeded.
The categories not only describe how much oil or gas may be in the ground, but the confidence level that volumes can be recovered commercially through a defined project. U.S. issuers are required to disclose proved reserves in SEC filings and may also disclose probable and possible reserves. This differs from Canadian reporting under NI 51-101 which provides proved and proved-plus-probable reserve data, and requires an independent qualified reserves evaluator or auditor. As a result, a Canadian company’s 2P figure should not be compared directly with a U.S. company’s proved reserve total.
Developed and Undeveloped Reserves Change the Investment Case
Within proved reserves, the split between developed and undeveloped volumes is more important than the headline total.
- Proved developed producing reserves (PDP) come from wells that are already producing. They are the closest to current production and cash flow, despite their output possibly declining over time.
- Proved developed non-producing reserves (PDNP) relate to wells or facilities that are capable of producing, but are temporarily shut in or have yet to be cleared for work.
- Proved undeveloped reserves (PUDs) require new wells, recompletions, or other major expenditures before production can begin.
Image Credit: Pexels
A company with 70% PDP reserves would have a very different profile from one with 70% PUDs. Although the second company may have a longer growth runway, that potential depends on capital availability, permits, service costs, drilling results, and execution. The SEC rules also place an important limit on PUDs. A company generally needs an adopted development plan that schedules drilling within five years, unless specific circumstances would support a longer timeline. Therefore, investors should consider comparing the PUD inventory with the capital budget, and confirm whether management has consistently converted undeveloped locations into producing wells.
How To Read an Oil and Gas Reserves Report Reconciliation?
Reserve volumes change every year. Production reduces reserves as oil and gas are sold. Multiple factors such as drilling, acquisitions, extensions, discoveries, improved recovery results, price movements, and cost changes can add or remove volumes. The reserve reconciliation table explains these movements as it separates additions caused by drilling success from any changes caused by revised estimates or acquisitions.
Pay close attention to:
- Revisions of prior estimates: Negative revisions may signal weaker well performance, rising costs, or less favorable prices.
- Extensions and discoveries: These can show whether or not the company is adding value through its drilling program.
- Purchases and sales: Reserve growth through acquisitions should be separated from reserves added through the company’s own drilling and development.
- Production: A company needs to have enough additions to replace what it produces if it wants to maintain its reserve base.
Annual U.S. proved-reserve data also shows how much reserve totals can move due to production, revisions, discoveries, and transactions. While a reserve replacement ratio may look healthy after a major acquisition, that doesn’t necessarily prove that the underlying drilling program is fully working.
How Do Price Assumptions and PV-10 Affect Reserve Valuation?
Reserve estimates are economic estimates. They depend on commodity prices, operating costs, transportation charges, taxes, future development capital, and the timing of production. Production forecasts matter just as much as price assumptions. If wells decline faster than expected, both recoverable volumes and the timing of projected cash flows can change.
For SEC-based proved reserve estimates, companies generally use a 12-month unweighted average of the first-day-of-the-month price for each month before the reporting date, unless prices are set by contract. This creates proper consistency in reporting, but it also means the estimate may differ from the numbers in a company’s internal price deck, real time spot prices, or even the forward curve.
What Is PV-10 in Oil and Gas Reserves Reports?
This is where investors will often see PV-10, which refers to the present value of estimated future net cash flows from proved reserves discounted at 10%, before income taxes. Engineers forecast future production, apply the required commodity-price assumptions, subtract operating and development costs, and then discount those projected net cash flows back to the valuation date at 10%. It gives investors a common way to compare reserve-based cash-flow estimates across companies.
What Are the Limitations of PV-10 Valuation?
However, PV-10 has its limits. It’s extremely sensitive to assumed prices, development costs, production timing, and discount rate. It also leaves out several factors that affect equity value, including the company’s hedge book, corporate overhead, debt structure, midstream commitments, and regulatory exposure. Apply PV-10 as a useful comparison tool, but not a market value or a complete equity valuation.
How To Check & Evaluate Reserve Report Quality and Development Plans?
Reserve estimates are generally updated annually and prepared or overseen by qualified technical professionals. Depending on the reporting framework and company, the estimates may be prepared internally, audited by an outside firm, or independently evaluated by a petroleum engineering consultant. While an independent review can provide another level of scrutiny, it cannot remove reservoir uncertainty or make an unrealistic development plan achievable.
Check the effective date, the engineering firm’s scope of work, price and cost assumptions, and whether the company has changed its methodology from the prior year. Then cross check the data in the reserve report with its listed production guidance, capital spending, debt maturities, and infrastructure access. Ultimately, a strong reserve base can only create value when the company can fund the development plan and produce the volumes at an acceptable cost.
Conclusion
Reserve reports are built on estimates, but they provide a standardized, auditable view of what an operator expects to recover under specific assumptions. They are useful since they input both technical and financial claims into one documented framework. The best investment isn’t always the largest reserve total. Investors should look at the proportionate mix of PDP and PUD reserves, the quality of reserve additions, the cost and timing of development, the direction of revisions, and management’s record of turning plans into production and cash flow. It is important to allow the engineering and capital allocation discipline to show up in the numbers.
FAQs
What is the difference between reserves and resources?
Resources include oil and gas volumes that may be recoverable in the future, but still need more technical work or commercial development before it can start production. Reserves are a narrower category supported by geological and engineering evidence, with recovery expected under stated operating and economic conditions.
Are proved reserves guaranteed to be produced?
No, proved reserves carry the highest confidence level but they still remain as estimates. Commodity prices, operating costs, reservoir performance, equipment reliability, permits, drilling execution, and access to pipelines or processing facilities can all affect its future production.
Why are proved undeveloped reserves important?
PUDs represent the potential production that has not yet been funded or developed. Investors should assess the required capital, planned drilling schedule, development timeline, and the company’s track record of converting undeveloped reserves into producing wells.
