How to Read an Oil & Gas Reserves Report

A Reserve Number Is an Economic Claim, Not a Geological One

The barrels are in the rock either way. A reserve report says something narrower: that at a stated price, with stated costs, on stated equipment, a company can get a given volume out and sell it at a profit. Change the price and the volume changes without a single molecule moving. That is why a bigger reserve base is not automatically a better one, and why two producers quoting the same headline number can be worth very different amounts.

What separates them sits under the headline: what it costs to develop the undrilled portion, how fast the developed portion declines, and what price the whole thing was booked at. The volume estimates themselves come from decline curve analysis, which turns a well’s production history into an estimated ultimate recovery, or EUR.

This guide covers how reserves are classified, how the American and Canadian rulebooks differ, the ratios worth tracking, and the footnotes where the caveats hide.

The PRMS Framework: Universal Language

The Petroleum Resources Management System (PRMS) is the international standard for classifying oil and gas resources. It is published jointly by the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists, and Society of Petroleum Evaluation Engineers.

PRMS first sorts volumes by whether a project is commercial. Reserves are volumes from projects the company has committed to develop. Contingent resources are discovered but not yet commercial, usually waiting on a price, a pipeline or a permit. Prospective resources are undiscovered. Only the first category belongs in a reserve report.

Reserves are then split three ways by confidence, and the categories stack:

Proved Reserves (1P)

Proved reserves are quantities that geoscience and engineering data show, with reasonable certainty, can be economically produced under existing conditions. Where an evaluator works probabilistically, “reasonable certainty” is set at a 90% chance the actual recovery equals or exceeds the booked figure.

Key characteristics:

• Based on actual drilling, production history, and detailed geological mapping
• High confidence in geology (core samples, logs, pressure data)
• Economically producible at the rulebook’s price (a 12-month trailing average under SEC rules, a forecast price under Canadian ones)
• Undrilled locations qualify only where they directly offset a proved spacing unit, unless proven technology supports going further out

Examples:

• Producing wells with 3+ years of production history
• Adjacent areas to producing fields with similar geology and economics
• Shut-in wells with capability to produce (even if temporarily closed)

Proved reserves split by production status:

• Proved Developed (PD): Capable of production from existing wells/infrastructure
• Proved Undeveloped (PUD): Requires additional wells/facilities to produce

Probable Reserves, and What 2P Means

Probable reserves are the volumes beyond proved that are more likely than not to be recovered. Add them to proved and you get 2P, the figure set so there is a 50% chance actual recovery comes in at or above it. 2P is the industry’s working number in technical reports, Canadian filings and most analyst NAVs. US filings are built on 1P, so anyone comparing a Canadian producer’s 2P with a US producer’s proved reserves is comparing two different confidence levels.

Key characteristics:

• Less developed than proved; may lack drilling data or require technology demonstration
• Typically contiguous to proved reserves or in analogous geology
• Requires planned capital investment for drilling or subsurface development
• Higher risk of economic non-viability if prices decline or costs rise

Examples:

• Undrilled but mapped structures offset by producing wells
• Zones below or above proved accumulations
• Areas where additional seismic confirms extensions

2P = proved + probable. The label describes the sum, not the probable increment on its own.

Possible Reserves, and What 3P Means

Possible reserves are the volumes beyond probable, recoverable only if things go better than expected. Add all three and you get 3P, set so there is a 10% chance of recovering that much or more. It is the optimistic end of the range and is disclosed sparingly.

Key characteristics:

• High technical or commercial risk
• Depends on favourable geology, prices or recovery outcomes rather than the expected case
• Often used in optionality discussions rather than reserve accounting

3P = proved + probable + possible. Treat a company quoting 3P in a headline as quoting its best case.

SEC vs. NI 51-101 Standards: Two Different Rules

SEC Standards (USA)

SEC-regulated E&Ps follow Regulation S-X, Rule 4-10 (17 CFR 210.4-10, the definitions) and Regulation S-K, Subpart 1200 (what has to be disclosed). Both took their current form in the SEC’s 2009 modernisation, which first bit in the annual reports filed in early 2010. Key features:

Pricing rule: Reserves are booked at the unweighted 12-month average of first-day-of-the-month prices. It is a backward-looking average, so reserve volumes lag the market by up to a year in either direction.

Discount rate: 10%, fixed, for the standardised measure of discounted future net cash flows in the 10-K. Companies use whatever rate they like internally, but the filed table is 10% or nothing. Its pre-tax cousin, PV-10, gets its own treatment in PV-10 vs NAV.

Reporting: Only proved reserves are required. Probable and possible may be disclosed voluntarily, which the 2009 rules permitted for the first time, but almost nobody does.

The five-year PUD rule: an undrilled location can carry proved undeveloped reserves only if the company has adopted a development plan scheduling it to be drilled within five years, unless specific circumstances justify longer. This is a hard constraint, not a guideline, and it is the single most common reason a US producer’s booked reserves understate its inventory.

NI 51-101 Standards (Canada)

Canadian-regulated E&Ps follow National Instrument 51-101 (Canadian Securities Administrators). Three differences matter:

Pricing rule: Forecast prices and costs, not a historical average. The evaluator uses a forward price outlook that has to sit within the range other reputable evaluators are publishing at the same date. Reserves therefore respond to a change in the expected future, not to what has already happened.

Discount rates: net present value disclosed at 0%, 5%, 10%, 15% and 20%, both before and after tax. The reader gets the whole sensitivity ladder rather than a single point.

Reporting: proved and proved-plus-probable are both required, with developed and undeveloped split out; possible is permitted. And the reserves data must be reported on by an independent qualified reserves evaluator. There is no SEC equivalent of that last requirement: a US filer may use its own engineers and commission a third-party audit or not.

Why the Two Sets of Numbers Move Differently

Both rulebooks are artificial, in opposite directions. The SEC’s trailing average is a mirror: after a price crash it can hold reserves up for most of a year, and after a rally it holds them down. Canadian forecast pricing tracks the evaluator’s view of the forward curve, so it reprices as soon as the outlook changes rather than waiting for twelve months of history to roll through.

The practical consequence is that a US and a Canadian producer with identical assets can report different reserves in the same December, and neither is misreporting. Before comparing them, find out which price each was booked at. It is disclosed, and it is usually the largest single difference between the two figures.

Reserve Categories: Developed vs. Undeveloped

Proved Developed (PD)

Proved Developed reserves are capable of production from existing wells and facilities. Often split further:

• Proved Developed Producing (PDP): Currently producing
• Proved Developed Non-Producing: Shut-in but capable of production (e.g., Gulf of Mexico wells curtailed due to storms)

PD reserves are the “safest” category: they represent near-term, low-risk production.

Proved Undeveloped (PUD)

Proved Undeveloped reserves require additional wells, facilities, or major workovers to produce. They are where growth projections come from, and they carry the execution risk that goes with it.

Key PUD metrics:

• PUD as % of proved: High ratios (>30–40%) suggest significant future drilling; lower ratios suggest mature assets
• PUD conversion timeline: How many PUD reserves are expected to convert to PDP in next 1–3 years?
• PUD drilling count: How many wells needed to convert reserves?

Red flag: a company carrying 500 MMBOE of PUD but drilling five wells a year, each converting 10 MMBOE, is clearing 50 MMBOE a year. That is a ten-year programme against a five-year rule. Either the drilling pace rises or roughly half those reserves come off the books, and the second outcome shows up as a negative revision rather than an announcement.

How to test the conversion pace: the five-year rule implies roughly a fifth of the PUD balance converting each year, so compare the PUD that actually moved into the developed column against the PUD balance a year earlier. A company running well under a fifth is either drilling slower than it booked or booking faster than it drills, and both eventually resolve the same way. Price downturns, capital discipline and rig availability all slow conversion, which is why the ratio is worth tracking through a cycle rather than judging in one year.

Reserve Life Index (RLI) and Reserve Replacement Ratio (RRR)

Reserve Life Index

Reserve Life Index = Proved Reserves / Annual Production

A company with 500 MMBOE proved reserves and 50 MMBOE annual production has: RLI = 500 / 50 = 10 years

RLI indicates how long a company can produce at current rates without finding or acquiring additional reserves.

Rough interpretations:

• RLI > 12 years: long-life assets, typically conventional, offshore or oil sands
• RLI = 8–12 years: needs steady drilling to hold the base flat
• RLI < 5 years: short-life base; the company is only as good as next year’s capital programme
• A falling RLI trend: replacement lagging depletion, and more informative than the level

Read the level against the asset type before calling it good or bad. A shale producer runs a structurally low RLI because shale wells give up most of their volume early, and the five-year PUD rule caps how much future drilling it is allowed to book. An oil sands operator can carry thirty years because the asset barely declines. Comparing the two on RLI alone tells you which rock they own, not which company is better run.

Reserve Replacement Ratio

RRR = (Net Reserve Additions) / Annual Production

Net additions include:

• New discoveries, from drilling
• Extensions, where an existing field turns out to be bigger than mapped
• Improved recovery, where a technique lifts what a known reservoir will give up
• Revisions, positive or negative, from price moves, cost moves or well performance
• Acquisitions and divestitures, where reserves change hands

Watch how a company defines its own ratio. Excluding acquisitions and divestitures gives the drill-bit RRR, which measures whether the business can create reserves; including them lets a company buy its way to 100% for a year. Both are legitimate, and the difference between them is worth reading against F&D costs, because replacing reserves at a cost above the netback replaces volume while destroying value.

Rough targets:

• RRR > 100%: replacing more than it produces
• RRR = 75–100%: slowly depleting
• RRR < 75%: reserves shrinking faster than they are being replenished

A worked example:

• Opening reserves: 1,000 MMBOE
• Production: 100 MMBOE
• Discoveries and extensions: +80 MMBOE
• Revisions: −20 MMBOE
• Divestitures: −5 MMBOE
• Net additions: 80 − 20 − 5 = 55 MMBOE
• RRR = 55 / 100 = 55%

Run that for a decade with production held at 100 MMBOE and the base loses 45 MMBOE a year: 1,000 falls to 550, a 45% decline. In practice production would fall too, which softens the arithmetic and hides the problem for longer.

Critical Footnotes and Fine Print

Most investors skim the reserve table and ignore the footnotes. The footnotes are where the real information lives:

Economic Limit Assumptions

Footnotes disclose the economic cutoff (minimum production rate above which the well is economic). As commodity prices fall, economic limits rise, reducing reserve volumes.

Example: “Based on a 12-month average price of $85/bbl and abandonment costs of $1M per well, the economic limit is 10 BOE/day. PUD reserves assume drilling within 5 years.”

Why it matters: at a lower price the same well needs a higher rate to cover its operating cost, so the cut-off rises and the tail years at the bottom of the decline curve fall out of the reserve. Nothing changes underground. The reservoir keeps whatever the economics no longer justify lifting.

Contingencies and Approved Plan of Development

The SEC rule requires an adopted development plan behind every PUD booking, so the footnote language is a fair test of how real that plan is. “Expects to drill PUD wells in due course” is weaker than “board-approved three-year development programme with a $200 million budget”.

Red flag: PUD reserves with no dated, funded plan behind them. They were booked against a five-year clock that is already running.

Pressure Maintenance and Injection Programmes

For certain reserves (especially in secondary recovery fields), production depends on water injection or pressure maintenance projects. Footnotes should disclose:

• Whether injection facilities are in place
• Remaining capacity
• Any regulatory or operational issues

Red flag: “Pressure maintenance may be required” suggests the reserves aren’t yet proven economically feasible at current conditions.

Royalty and Government Take

Two different things get called government take, and only one of them changes the volume.

Royalties are taken in barrels. A landowner or a state entitled to 20% of production owns those barrels, so the company books 80. US and Canadian filers report reserves net of royalty for this reason, and a production-sharing contract does something similar through cost oil and profit oil splits.

• Gross field reserves: 100 MMBOE
• Royalty share: 20%
• Net-to-company reserves: 80 MMBOE

Income tax is taken in money. It reduces the value of the reserves, not the volume, which is why the SEC’s standardised measure is struck after tax while the reserve table above it is not. Adding a 35% tax rate to a 20% royalty and deducting 55% from the barrel count double-counts, and it is an easy mistake to make from a footnote that lumps the two together.

Exchange Rate Assumptions

For companies operating outside the US, costs are incurred in local currency while oil sells in dollars, so the reported value of the reserves moves with the exchange rate even when nothing operational changes.

Worth checking: a Canadian producer’s evaluation assumes CAD/USD of 0.75. At 0.70 the barrels still sell for the same dollars while the Canadian cost of lifting them falls about 7% in dollar terms, so the same volumes are worth a little more with nothing changed underground. A stronger Canadian dollar squeezes the margin the other way.

Comparative Metrics: Year-over-Year Analysis

Reserve Additions and Revisions Tracking

One year of reserve data says almost nothing. Five years says a great deal. Here is a producer holding output flat at 40 MMBOE a year:

Year	PD (MMBOE)	PUD (MMBOE)	Total proved	1P RLI
1	250	100	350	8.8
2	260	110	370	9.3
3	245	95	340	8.5
4	230	80	310	7.8
5	220	70	290	7.3

Interpretation: after year 2 both columns fall together, and RLI slides from 9.3 to 7.3. Falling PUD matters more than falling PD, because PUD is the inventory that turns into tomorrow’s production. This company is producing its developed base and not booking enough new drilling behind it, which gives it roughly seven years at the current rate unless the drilling programme picks up or it buys reserves.

Reserve Revisions as a % of Proved Reserves

Track reserve revisions (the change in prior-year reserves due to technical updates, price changes, or operational results):

• Positive revisions (>2%/year): Geology better than expected; improved recovery; favourable price revisions
• Negative revisions (>2%/year): Geology worse than expected; price-driven downgrades; lower recovery than predicted

Persistent negative revisions are a red flag: the company’s estimates are too optimistic.

Auditor Assessments

Independent reserve engineers such as DeGolyer and MacNaughton, Ryder Scott or Sproule sit behind most published reserve figures. First check which job they did. In an evaluation the firm prepares the estimates itself; in an audit the company’s own engineers prepare them and the firm reviews the work. An audit is the weaker of the two, and a company that had neither done is quoting its own homework. Canadian filers must have an independent qualified reserves evaluator report on the data; SEC filers need not.

Scope of Audit

Does the audit cover 100% of proved reserves? Or only a sample? If the audit covers 70% of reserves, the remaining 30% are the company’s own estimates (higher risk).

Key Findings

Look for audit comments on:

• Pressure maintenance: “Facilities in place and functioning” is positive; “proposed but not yet installed” is negative
• Economic limits: Are they reasonable given commodity prices and operating costs?
• Analogy to producing fields: Are PUD reserve estimates based on good analogues?

Red flag in audit report: “Auditor unable to obtain sufficient information to evaluate reserves in Area X; company’s estimates used.”

Common Red Flags in Reserves Reports

1. Declining RRR for 2+ years: Reserve replacement lagging depletion; growth unsustainable
2. Large negative price revisions: Indicates reserves are highly sensitive to commodity prices
3. Rising PUD/Total ratio without conversion: PUD reserves growing while PDP reserves shrink; suggests development delays
4. Vague economic limit language: Unclear at what commodity price reserves become uneconomic
5. No third party involved: the company’s own engineers, neither audited nor independently evaluated
6. Large revisions year-to-year: Suggests previous estimates were poor; erodes confidence in current guidance

Using Reserves in Valuation

A reserve report is an input to a valuation, not a valuation. Turning it into one means putting the barrels on a production schedule, pricing them, taking the costs out and discounting what is left. That is a reserve-based NAV, and it feeds the comparison in NAV vs EV/DACF.

Take 200 MMBOE of proved reserves producing 20 MMBOE in year one and declining 10% a year, at $80/bbl:

Year	Opening reserves (MMBOE)	Production (MMBOE)	Price	Revenue
1	200	20.0	$80	$1.60bn
2	180	18.0	$80	$1.44bn
3	162	16.2	$80	$1.30bn

Costs and development capital come off each row to give cash flow. Discount those at the cost of capital, subtract net debt, divide by the share count, and you have NAV per share.

Now notice what the schedule does not do. Ten years of production at that decline totals about 130 MMBOE, so 70 MMBOE of the original 200 is still sitting on the books at the end. That is why decline rate and reserve life have to be read together: a slow-producing tail on a fast-declining base parks a lot of the volume in years the discount rate values at almost nothing. The regulated version of this calculation is PV-10, run on the SEC’s trailing price at a fixed 10%, and PV-10 vs NAV sets out where the two part company.

The Headline Number Is Never Enough

The proved reserves figure on page one is a starting point, not an answer, and it is the number least worth staring at. What price was it booked at, how much of it is undeveloped, who checked it, and which way has reserve life been moving. A company with 500 MMBOE, 40% of it PUD, a falling RLI and no funded drilling plan is in a completely different position from one with 300 MMBOE of mostly producing wells and twelve years of life, and the second is usually the better business. Bigger reserves are only better if someone can afford to lift them. See the Oil & Gas Sector Primer for how reserves fit the broader E&P picture.