Venezuela's oil reserves: the license, not the subsoil, sets a barrel's value

On August 31, the White House announced that Venezuelan authorities had granted NABEP, a privately held oil company, hundred-year concessions over seventeen fields "with proven reserves of approximately 65 billion barrels." In the same fact sheet it said the U.S. Department of War was receiving a 35% stake in the company's parent, a holding it described as "representing up to hundreds of billions in value and dividends" for the United States. Six months earlier, in its annual report to the SEC, Chevron had written of its interests in Venezuela, two of them in the heart of the Orinoco Belt: "no proved reserves are recognized."

Both documents are American and both concern the same country. In one, a stake in Venezuelan barrels is worth, according to its owner, up to hundreds of billions; in the other, Chevron's Venezuelan barrels do not count. Between the two, nothing changed underground. What changed is the rule by which each barrel is counted.

That is the question to put to any figure for Venezuela's reserves before any other: not how much oil there is, but who decides how much of that oil counts, and who keeps the difference.

What the subsurface says

First, the subsurface. At the end of 2025, OPEC credited Venezuela with 303.7 billion barrels of proved reserves, ahead of Saudi Arabia. The Venezuelan figure barely moves from year to year, and in that it is no exception: in the same table, Saudi Arabia shows about 267.2 billion in all five years from 2021 to 2025, and Iran 208.6 billion in every one of them. In the 2012 bulletin, Kuwait and the United Arab Emirates repeated their figure in all five years from 2007 to 2011.

Producing little does not shrink it either. Oil that is not extracted stays in the ground.

The Venezuelan figure did make one jump, and PDVSA's papers explain how. Between 2007 and 2011 it went from less than one hundred billion barrels to almost three hundred billion because the extra-heavy crude of the Belt began to be counted. In 2007, the company described the method: the certifying firm measured the original oil in place in each block, and proved reserves came from applying a 20% recovery factor to it, "following the guidelines of Menpet," the Ministry of Energy and Petroleum. With that method, according to PDVSA's 2010 management report, the Magna Reserva Orinoco Project quantified and certified 215 billion barrels and took the nation's reserves to 298 billion. It was not the only revision of those years: in 2010, Iraq raised its own by nearly a quarter.

That 20% sits below what the main independent estimate assumes. In 2009, the U.S. Geological Survey (USGS) set its minimum recovery for the Belt at 15%, the recovery expected from cold production, and worked with a median recovery of 45% and a maximum of 70%. With those assumptions it calculated a mean of 513 billion barrels technically recoverable in the Belt alone. Technically recoverable is not the same as proved, because it takes no account of price or contract. But as far as the subsurface goes, the independent estimate is higher than the official figure for the whole country.

What the official figure lacks is an outside signature on the step from oil in place to reserve. The certifying firms of 2007 measured the volume; the factor that turns it into a reserve was set by the ministry, which also makes the figure official in the Official Gazette, and to get from cold production to that 20%, PDVSA listed among its research tasks in 2010 the "additional recovery schemes" that would guarantee it. In July 2026, the Hydrocarbons Ministry published a manual that, according to its release, replaces two-decade-old rules "to unify the criteria for classifying reserves." The next figure will be the first counted under those rules.

What decides whether a barrel counts

Before the SEC, "proved" demands more than geology. The rule defines proved reserves as oil that can be estimated "with reasonable certainty to be economically producible" under existing economic conditions, operating methods and government regulations, and only until the contracts providing the right to operate expire.

In Venezuela, the regulations that matter are not written only in Caracas.

Chevron explains it in a single paragraph of its annual report. Since 2020 it has recorded its Venezuelan business as investments in which it counts only the cash it receives, with neither production nor reserves included in its results, and in that paragraph it says it has conducted limited activities in the country consistent with authorizations issued by the U.S. government and with its sanctions policy. Its first-quarter 2026 report, which already announces the agreement to expand Petroindependencia, repeats the wording. Chevron's zero comes from an accounting rule under an authorization regime, not from a measurement of the subsurface.

Eni, which signed in September to operate Junín 5, had noted in March before the SEC that the carrying amounts of its licenses in the Belt had been fully impaired in prior years. When it announced Junín 5, it spoke of thirty-five billion barrels of "certified oil in place," without naming the certifier.

GeoPark, which entered the Bare field, shows how a price was put on a Venezuelan field in 2026. It is paying with just over 42 million of its own shares, and that payment carries an upward adjustment mechanism tied to "potential improvements in the project's contractual conditions" before closing. Bare holds about 15.7 billion barrels of original oil in place and recovers around 4% to 5% of them, according to the company. GeoPark told its investors its reserve base could double with Bare, "subject to confirmation through an independent reserves report," and on October 16 it warned the SEC that its estimates for the field "may change and the change may be material."

In Bare's price, the upward adjustment on offer is tied to the contract.

The only named independent certification of Venezuelan proved reserves we found is Maurel & Prom's. DeGolyer & MacNaughton certified its reserves in the Urdaneta Oeste field at the end of 2025: 148 million barrels of proved plus probable, of which 56.7 million are proved. The company attributes the year's increase to geoscience studies that confirmed zones previously considered unproven. That is its share of one field in Lake Maracaibo, not the country.

When the asset is your own

At that scale, the August fact sheet reads differently. The White House called NABEP's 65 billion barrels proven; the company spoke of "more than 65 billion barrels of P1 reserves," and the Venezuelan government repeats the figure. None of the three documents names a certifier or a method, and the SEC's filing search turns up nothing from NABEP. Sixty-five billion proved barrels would be six times the proved reserves Chevron books worldwide.

The same fact sheet says who else has a share in those barrels. The Department of War receives 35% of NABEP's parent, and the State Department the right to purchase, at production cost, 20% of the off-take from all its current and future fields.

In the books of Chevron, which answers to the SEC, no Venezuelan barrel counts as proved. In the fact sheet for a company in which the U.S. government holds 35%, 65 billion count, with no published certifier. A White House fact sheet is not bound by the SEC rule; a Chevron annual report is. Both ledgers are American, and only one has to prove what it calls proved.

The fact sheet also expects NABEP to pay some $200 billion in royalties and taxes over the first 25 years, revenue it presents as fiscal support for Venezuelan governments. That money has its own rule. Under Executive Order 14373 and OFAC's FAQ 1237, whatever an authorized oil business owes the Venezuelan treasury or PDVSA in royalties, per-barrel levies or national taxes goes into U.S. Treasury accounts, and leaves them when and where the State Department directs, on Venezuela's behalf.

Who keeps the difference

For an investor, the gap between oil in the ground and proved reserves is the gap between a resource and an asset. A field is financed, valued and sold on its proved reserves; resources are paid for at a discount.

In Venezuela, that discount depends less in 2026 on the subsurface than on the contract, the license and the accounting rule. A field that changes hands with those three things in suspense is paid for as a resource. When they change, through a new authorization, a longer contract or a manual that orders the classification, the same barrel can become proved and be worth more. Unless the contract says otherwise, and none of the documents cited here publishes its terms, that difference goes to whoever holds the asset at that moment. The state that granted it collects royalties and taxes on what is produced, along the route Washington sets, and not on what the barrel comes to be worth.

"It is of no use to have our oil reserves underground only so that they appear in a statistic or in an accounting ledger," the acting president said in August, addressing the country on the energy agreement with the United States. This year, the question is in whose ledger.

Four documents would move this account: the first reserves figure counted under the July manual; the name of whoever calculated NABEP's 65 billion, and by what method; the independent reserves report GeoPark expects for Bare; and Chevron's next annual report, which will say whether, under the new authorizations, its Venezuelan barrels count again. Until then, Venezuela's oil stays where it has always been. What is being negotiated is the rule by which it is counted.