Oil and gas reserves and resource quantification

Based on Wikipedia: Oil and gas reserves and resource quantification

Imagine you're an investor trying to decide whether to sink millions into an oil company. The company tells you they've found oil underground. Great! But how much oil? How sure are they it's actually there? And can they actually get it out profitably?

These questions sit at the heart of oil and gas reserves reporting—a complex accounting system that tries to put numbers on something you can't see, touch, or measure directly. It's geology meets finance, and the stakes are enormous.

The Fundamental Distinction: Resources vs. Reserves

In everyday language, we might use "resources" and "reserves" interchangeably. In the oil industry, they mean completely different things.

Resources are oil and gas that might be underground. Could be a lot. Could be nothing. You've got some geological clues—maybe seismic data suggesting promising rock formations—but you haven't drilled yet. Or maybe you have drilled, found oil, but the economics don't work at current prices.

Reserves, by contrast, are the real deal. This is oil and gas from known fields that you can profitably extract with today's technology and today's prices. You've drilled. You've tested. You've done the math. You have approved development plans. This oil is going into somebody's gas tank within five years.

Here's why this matters: reserves go on a company's balance sheet as assets. They determine the company's stock price, its ability to borrow money, its very survival. Resources? Those are more like dreams—interesting for internal planning, but not something you can take to the bank.

The Uncertainty Problem

Even after you've drilled and confirmed oil exists, you face a measurement problem unlike almost any other industry. A car manufacturer knows exactly how many cars are in the factory. An oil company is trying to estimate how much liquid is trapped in tiny pores within rock formations thousands of feet underground, spread across hundreds or thousands of acres.

You can't see it. You can't count it. You can only infer it from indirect measurements and sophisticated calculations.

So the industry created a probabilistic classification system. Instead of saying "we have exactly 500 million barrels," companies express uncertainty through three categories.

Proven Reserves: The Conservative Estimate

Also called "One P" or "P Ninety" reserves, these represent the most conservative estimate. Industry rules require 90 percent certainty that you'll produce at least this much oil. In other words, there's only a 10 percent chance you'll produce less than the proven reserves number.

Proven reserves split into two subcategories. Proven developed reserves can be extracted with existing wells and equipment—you just keep pumping with what you've already built. Proven undeveloped reserves require additional capital investment, like drilling new wells, but the oil is definitely there and definitely profitable to extract.

Until 2010, the United States Securities and Exchange Commission (SEC)—the agency regulating stock markets—only allowed companies to report proven reserves to investors. This was the only number that could go in official filings. The logic was simple: don't let companies inflate their asset values with wishful thinking.

Probable Reserves: The Middle Ground

Probable reserves are additional oil and gas that's likely there, but with less certainty than proven reserves. When you add proven plus probable together, you get "Two P" reserves, corresponding to "P Fifty"—meaning there's a 50 percent chance you'll produce at least this much.

Notice the probability keeps dropping. P Ninety means 90 percent confident. P Fifty means 50 percent confident—a coin flip.

Possible Reserves: The Optimistic Case

Possible reserves are even more speculative. Maybe there's oil in adjacent rock formations you haven't fully characterized. Maybe future technology will let you extract more. Maybe geological interpretations are more optimistic than conservative.

Add proven plus probable plus possible together and you get "Three P" reserves, corresponding to "P Ten"—only a 10 percent chance you'll produce this much or more. Which means there's a 90 percent chance you'll produce less than the Three P estimate.

Most companies calculate Two P and Three P numbers for internal planning but don't publish them. Since 2010, the SEC allows companies to optionally disclose these figures, but many don't bother. The numbers are too squishy, too open to manipulation.

Beyond Reserves: The Resource Categories

Below reserves on the certainty scale sit two additional categories that don't make it onto balance sheets but still influence company strategy and investor perception.

Contingent Resources

These are discovered accumulations—you've drilled, you've found oil—but development isn't commercially viable yet. Maybe oil prices are too low. Maybe the political situation is unstable. Maybe the technology to extract this particular type of oil hasn't been perfected.

Something needs to change before contingent resources become reserves. The oil is real, but the path to profitability isn't clear yet.

Prospective Resources

This is oil and gas that hasn't been discovered at all. Pure geological inference. You've studied the rock formations, run seismic surveys, built sophisticated computer models. Your geologists think there's oil in a particular location. But until you drill and hit pay dirt, it's entirely speculative.

Prospective resources carry the highest uncertainty and the highest risk. The chance of success—the probability the oil actually exists—might be anywhere from 5 percent to 30 percent for a typical exploration well.

Oil in Place vs. Recoverable Oil

Here's another crucial distinction that trips up non-specialists: not all the oil underground can be extracted.

Geologists estimate the total amount of oil or gas in a reservoir—called "stock tank oil initially in place" (STOIIP) or "gas initially in place" (GIIP). But only a fraction of that can actually be brought to surface with current technology and economics.

The ratio between oil in place and recoverable oil is called the recovery factor. For a typical conventional oil reservoir, the recovery factor might be 20 to 40 percent. Meaning if there's 1 billion barrels in the ground, you might only extract 200 to 400 million barrels.

Why so low? Oil is trapped in microscopic pores in rock. Even with advanced techniques like water flooding (pumping water into the reservoir to push oil toward wells) or gas injection, most of the oil stays stubbornly stuck in place.

When a company reports reserves, they should be reporting recoverable volumes, not oil in place. A company claiming "1 billion barrels of reserves" when they mean "1 billion barrels in place with a 25 percent recovery factor" is inflating their assets by a factor of four. This is why strict definitions and external auditing matter.

How Do You Actually Calculate This?

Three main approaches exist, used at different stages of resource maturity.

Analogs: The Educated Guess

In frontier areas with no existing production, analysts look for similar geology elsewhere. If you're exploring offshore Mozambique and the rock formations look similar to offshore Brazil, you might use Brazilian field data as a substitute to estimate potential volumes.

This is called the "yet to find" method. It's conceptual, very uncertain, but often the only tool available before any drilling happens.

Volumetric Methods: The Rock Physics Approach

Once you have some actual data from wells, you can calculate volumes using rock physics. The fundamental equation is:

Recoverable Volume = Gross Rock Volume × Net to Gross × Porosity × Oil Saturation × Recovery Factor ÷ Formation Volume Factor

Let's unpack this. Gross rock volume is the total size of the reservoir—how many cubic feet of rock might contain oil. Net to gross is the fraction that's actually reservoir-quality rock versus impermeable shale or other non-productive layers. Porosity is the percentage of void space in the rock—how much of the rock is holes that can hold fluid. Oil saturation is what fraction of those pore spaces contains oil versus water. Recovery factor we covered above. The formation volume factor accounts for the difference between oil volume underground (at high pressure and temperature) versus at surface conditions.

Each of these parameters comes with uncertainty. In a probabilistic calculation, you'd assign a range to each parameter—say porosity might be 15 to 25 percent—and run thousands of Monte Carlo simulations to generate a probability distribution of outcomes.

Performance-Based Methods: Watching What Actually Happens

Once wells start producing, you have actual production data. Engineers can analyze flow rates over time, pressure decline curves, and water breakthrough (when wells start producing more water than oil, a sign of reservoir depletion) to refine volume estimates.

This is the most accurate method but only becomes available after years of production. And even then, the estimates keep evolving. Most early reserve estimates are conservative and grow over time as companies drill more wells and understand the reservoir better.

The Global Reporting Framework

For decades, different countries and companies used different definitions and methodologies, making comparisons nearly impossible. Was one company's "proven reserves" equivalent to another's?

In 2007, a coalition of professional societies—the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), Society of Petroleum Evaluation Engineers (SPEE), and Society of Economic Geologists (SEG)—developed a unified framework called the Petroleum Resources Management System (PRMS), updated in 2018.

The PRMS provides consistent definitions for all the categories we've discussed: proven/probable/possible reserves, contingent resources, prospective resources. It specifies how to classify uncertainty, how to handle risk, what constitutes an "approved development plan."

Most international oil companies now follow PRMS guidelines. The SEC uses a similar framework with some differences for companies listed on United States stock exchanges.

But here's the catch: many national oil companies—the state-owned giants like Saudi Aramco, Kuwait Petroleum Corporation, or Petróleos de Venezuela—don't publish detailed reserves data with independent verification. They announce numbers, but outsiders can't verify the methodology or assumptions. This creates enormous uncertainty about global oil supplies.

Why This All Matters

Reserves reporting isn't just accounting minutiae. These numbers drive:

• Investment decisions: Where should oil companies spend billions on new drilling?
• Stock prices: A company's market value depends heavily on its proven reserves
• National energy security: Countries plan energy policy based on domestic reserves estimates
• Global supply forecasts: When will we run out of oil? Depends entirely on how you categorize and count reserves versus resources
• Climate policy: If proven reserves exceed what we can burn while limiting warming to 1.5 degrees Celsius, some of those "assets" may become stranded

The difference between proven reserves and total resources in place can be an order of magnitude. Global proven oil reserves are roughly 1.7 trillion barrels. But estimates of total oil resources—including unproven, undiscovered, and unconventional sources—run to 6 trillion barrels or more.

Which number you use determines whether we're running out of oil in 50 years or 200 years. It determines whether oil companies are good investments or stranded asset risks. It shapes the entire energy transition debate.

The Human Element

For all the sophisticated math and standardized frameworks, reserves estimation remains partly art, partly science. Geologists and engineers interpret incomplete data. They make assumptions about future oil prices, future technology, future political stability.

Conservative engineers produce low estimates. Optimistic ones produce high estimates. Company culture matters—is management rewarded for growing the reserves number, or for accurately predicting production?

This is why major companies hire independent consultants to audit their reserves. It's why the SEC can demand confidential verification. It's why reserves reporting scandals—companies that overstated their assets—have destroyed shareholder value and landed executives in legal trouble.

At its core, reserves quantification is an attempt to put financial precision on geological uncertainty. The system works reasonably well for proven reserves at established fields. It gets progressively shakier as you move to probable, possible, contingent, and prospective categories.

But the oil industry has no choice but to try. You can't invest billions without some framework for estimating what you'll get in return. The question isn't whether the numbers are perfectly accurate—they never will be. The question is whether they're consistently calculated and honestly reported.

That's the difference between a functioning energy market and an investor catastrophe.