Key Takeaways
Reserve categories affect oil and gas valuation through differences in certainty of recovery, required capital, and the timing of expected production and cash flows.
PDP reserves generally carry the least development and timing risk, while PDNP and PUD reserves require additional consideration of execution, capital requirements, and timing.
Probable and possible reserves involve greater uncertainty and often rely more heavily on market evidence, including comparable transactions, to support valuation conclusions.
Reserves are the primary source of value for most E&P companies. A reserve report classifies reserves by confidence in recovery and by development status. Together, these reflect the likelihood of recovery, the investment still required, and the expected timing of production.
Confidence in recovery separates proved reserves from probable and possible reserves. Development status separates developed reserves, which are recoverable through existing wells and facilities, from undeveloped reserves, which require new wells or a major expenditure on an existing well. Developed reserves are further divided into producing and non-producing.
Overview of Reserve Categories
For reserves to be included in a reserve report, they must be economically producible. In practical terms, expected production revenues must exceed the associated development and production costs under the price and cost assumptions used in the reserve report. This does not mean the reserves must already be producing. Volumes that are technically recoverable but do not meet the economic threshold are not classified as reserves. Reserve reports prepared under frameworks other than SEC reporting often use different pricing, cost, development, and other assumptions when evaluating economic producibility.
To see how each reserve category affects value, it helps to understand what distinguishes one category from another. Below is a summary focusing on the distinctions most relevant to valuation.
Proved reserves, also called 1P reserves, are estimated quantities of oil and gas that are reasonably certain to be economically recoverable from known reservoirs under the commodity price assumptions used in the reserve report and existing conditions. Proved reserves generally reflect at least a 90% probability of recovery and are divided into three categories based primarily on development and production status: proved developed producing (PDP), proved developed non-producing (PDNP), and proved undeveloped (PUD).
PDP reserves are expected to be recovered through existing wells and equipment that are currently producing.
PDNP reserves are expected to be recovered through existing wells but are not currently producing. They can include shut-in wells and behind-pipe zones.
PUD reserves are expected to be recovered from new wells on undrilled acreage or from existing wells that require a relatively major expenditure. Under SEC rules, an undrilled location generally must be scheduled for drilling within five years under an adopted development plan to be classified as undeveloped reserves.
Probable reserves are additional reserves that are less certain to be recovered than proved reserves. Combined with proved reserves, they are as likely as not to be recovered and are commonly called 2P reserves.
Possible reserves are additional reserves that are less certain to be recovered than probable reserves. The combined estimate of proved, probable, and possible reserves is referred to as 3P reserves. Although probable and possible reserves are often undeveloped in practice, they can also include developed reserves.
Valuation Relevance of Reserve Categories
Moving from PDP toward possible reserves, certainty of recovery declines. In many cases, the capital required to realize production also increases and expected cash flows shift further into the future. An undrilled PUD location carries uncertainty in its initial production (IP) rate and decline profile, which drive recoverable volumes and the timing of cash flows. Probable and possible reserves introduce additional uncertainty regarding recoverability, regardless of development status. Where probable and possible volumes are expected later in a well's or project's life, they are also more exposed to changes in future conditions.
Within each category, value also depends on property-specific factors such as commodity prices and differentials, development and operating costs, infrastructure, lease terms, operating control, and abandonment obligations.
PDP
PDP reserves typically carry the strongest support. Production history, decline trends, realized pricing, and operating costs are observable, which allows cash flow projections to be tied to actual well performance. A discounted cash flow analysis using a market-derived discount rate is generally the primary method, with little or no incremental risk adjustment. The key judgments center on the price deck, operating costs, and decline assumptions.
PDNP: Timing and Execution Risk
PDNP reserves benefit from an existing wellbore, so some of the geologic uncertainty has already been addressed. Value depends primarily on the cost and timing to bring volumes online.
Behind-pipe reserves may not be accessed until a currently producing zone depletes. Shut-in wells may be waiting on a pipeline connection, improved market conditions, or a mechanical repair. In each case, the analysis should model the required expenditure and expected start date, then apply a modest risk adjustment for execution. Understanding why a well is shut in is often the most important diligence question for this category.
PUD: Capital and Development Risk
PUDs are commonly valued using the same discounted cash flow framework as PDP, with drilling and completion capital added and an adjustment for incremental risk. That risk includes well results relative to type curves, capital cost changes, development timing, takeaway capacity, and, for non-operated interests, the operator's capacity and willingness to drill.
This risk is typically addressed through a higher discount rate, known as a risk-adjusted discount rate (RADR), or through a reserve adjustment factor (RAF) applied to the projected cash flows or their present value. When both are used, the analysis should confirm that the same risk is counted only once.
The two methods can produce similar results, although their equivalence depends on the timing of cash flows. Because a RADR penalizes distant cash flows more heavily, the gap between the methods widens as development timing extends.
Probable and Possible: Market Evidence
Probable and possible reserves carry the least certainty, and public data on them is limited because the SEC does not require their disclosure. A risk-adjusted cash flow projection can still be prepared, although the size of the required adjustments makes the result highly sensitive to assumptions. Observed transactions in the market often provide better support. Acreage transactions priced on a dollar-per-net-acre basis, or premiums paid above the value of acquired proved reserves, can indicate what buyers are willing to pay for upside. Comparability remains the challenge. Useful transactions should be close in time, located in the same play, and involve fields of similar maturity. Pricing should also be screened for strategic premiums specific to a particular buyer.
Conclusion
Reserve categories are best understood as reflecting differences in certainty, capital, and timing. Compared to PDP reserves, PDNP and PUD reserves generally warrant explicit adjustments for the capital and risk that stand between them and forecasted production. Probable and possible reserves draw more heavily on market evidence. A credible valuation has supportable assumptions and tests the resulting conclusions against the market. The reserve label identifies the broad risk profile. Value depends on the specific economics behind it.
Mercer Capital has assisted clients with a wide range of valuation needs in the upstream oil and gas industry, across both conventional and unconventional plays in North America and internationally. Contact a Mercer Capital professional to discuss your needs in confidence.