How to invest in Venezuela oil: a guide for companies (2026)

For companies considering market entry, start by choosing a role: operator or partner, oilfield service or equipment supplier, or strategic investor. The right route depends on the local vehicle, the contract, sanctions clearance and how the project will be paid. This analysis separates those operating routes from buying public shares or distressed debt, which offer different kinds of exposure.

There is no simple retail route. In practice there are four: operate or partner with PDVSA through a company domiciled in Venezuela, supply services and equipment to operators, buy shares of listed companies with Venezuelan projects, or trade defaulted Venezuelan and PDVSA debt in the secondary market. Each needs sanctions clearance, and most are not suited to individual investors.

Will oil companies invest in Venezuela?

Some already are. Chevron and Eni signed expansion agreements on September 2, 2026, and Continental Resources signed a non-binding memorandum on September 16. Shell and Repsol signed agreements earlier this year. ExxonMobil is reported to be in talks, and ConocoPhillips is holding back. The main risks are fiscal terms, legal stability and shifting US sanctions.

The reform of the Hydrocarbons Law in January 2026 opened the door, and who has walked through it depends on how much political and fiscal risk each company can carry. Here is where the main players stand as of September 19, 2026.

• Chevron. Signed new agreements on September 2, 2026. Plans to invest more than $7 billion over five years through its joint ventures with PDVSA and additional Orinoco Belt acreage. It never fully left the country.
• Eni. Signed further agreements on September 2, after an April agreement on the Junín-5 heavy oil block. Also shares a Venezuelan joint venture with Repsol.
• Continental Resources. Signed a non-binding memorandum with PDVSA on September 16 to operate and develop the Ayacucho 2 area in the Orinoco.
• Denarius Holding Group. Announced on September 16 a long-term investment in the CEMA field in Anzoátegui, through its Venezuelan partner Minerosol Group C.A., which signed a 20-year CPPH with PDVSA. Figures come from the company's own press release.
• SLB and Hunt Oil. Signed deals with Venezuela in August 2026, according to the country's oil minister.
• North American Blue Energy Partners. Part of an agreement announced around August 28 covering 17 oilfields, about a fifth of the country's reserves. The White House cites up to $100 billion of investment, and reports say Washington and Caracas describe its duration differently.
• ExxonMobil. In talks, according to Reuters (September 16). Interested in the Petromonagas project and areas in the neighboring Carabobo block. No public commitment; its CEO called Venezuela “uninvestable” in January.
• ConocoPhillips. Has not returned. Said any decision must weigh stability and rule of law and include a way to recover debt owed from past expropriations.

The large service companies are coming back. SLB is preparing to reactivate up to 15 rigs already in the country, with as many as four back in service before the end of 2026, depending on contracts with producers. Halliburton, which left Venezuela in 2020, said in April that it is negotiating commercial terms with customers. Baker Hughes keeps a presence as an equipment supplier and, according to one report, is among the engineering partners in Shell's agreements for Carito and Pirital.

Operators are moving too. Shell obtained a license in June for the first phase of the Loran gas field and signed agreements for the Carito and Pirital production units in Monagas. Repsol is advancing at Cardón IV, together with Eni, and signed a memorandum in June to assess a new area southeast of Lake Maracaibo, known as Horcón. Maurel & Prom keeps operating Urdaneta Oeste through its 40% stake in Petroregional del Lago, and says its teams are ready for a new development phase once regulatory and commercial conditions allow.

Why the largest companies are cautious. Three issues keep coming up in the reporting: fiscal terms that some executives consider too heavy, doubts about whether PDVSA can guarantee legal and fiscal stability, and unpaid claims from earlier nationalizations. See the risks below.

How big is the prize? Output is currently around 1.1 to 1.2 million barrels per day, and US Energy Secretary Chris Wright has said it could reach 2 million by the end of the decade. Rystad Energy estimated in January that more than doubling production would take until about 2030 and cost roughly $110 billion. Large reserves and real production are separated by years and heavy capital.

How the opening unfolded in 2026

Two layers had to move: Venezuelan law and US sanctions licenses. Both changed repeatedly this year.

• January 3. A US military operation in Caracas removes Nicolás Maduro. Delcy Rodríguez becomes acting president.
• January 29. Venezuela reforms its Hydrocarbons Law. OFAC issues General License 46, allowing limited oil transactions by established US entities.
• Mid-February. OFAC issues General Licenses 49 (contingent contracts) and 50 (resuming operations).
• April. Eni signs an agreement on the Junín-5 block.
• April 21. Halliburton says it is negotiating commercial terms with customers for Venezuela.
• May. Bloomberg reports Exxon and ConocoPhillips are negotiating re-entry while seeking legal and financial safeguards.
• June 11. Shell receives a license for the Loran gas field and signs agreements for Carito and Pirital in Monagas.
• June 17. Repsol signs a memorandum to assess the Horcón area southeast of Lake Maracaibo.
• July 7. The implementing regulation of the Hydrocarbons Law and the tax resolutions are published.
• August 19. SLB says it is preparing to reactivate up to 15 rigs in Venezuela.
• August 27. OFAC issues General License 52B.
• August 28. Washington and Caracas announce an agreement covering 17 oilfields, later detailed as a deal with North American Blue Energy Partners.
• September 2. Chevron, Eni and GE Vernova sign agreements in Caracas.
• September 14. OFAC issues General License 52C, replacing 52B after 18 days.
• September 16. Continental signs its memorandum with PDVSA. Reuters reports Exxon is advancing talks.
• September 16. Denarius Holding Group announces its investment in the CEMA field under a 20-year CPPH with PDVSA, signed by its Venezuelan partner.

How can a company invest in Venezuela oil?

These are the four routes in practice, from the most capital-intensive to the most specialized. None is a shortcut, and each depends on sanctions clearance.

• 1. Operate or partner with PDVSA. Under the reformed law, primary activities can be carried out by the State, by joint ventures with a state majority, or by private companies domiciled in Venezuela through contracts. Joint ventures no longer need prior approval from the National Assembly, and minority partners can take on technical operation and direct marketing with authorization. You need a Venezuelan entity, ministry authorization for acts such as share transfers, and a negotiated contract. Backing a local operator is a variant, and it makes title verification essential. This route needs the most capital and the most legal work.
• 2. Supply services and equipment. This is where many smaller companies are getting in. Reporting from August notes that recent deals have been with service providers and smaller US oil companies, which appear more willing to take the risk. The large service companies are returning, so smaller suppliers will either compete with them or work alongside them. Plan for the national content requirement, the Integrated Hydrocarbons Tax that also reaches specialized petroleum services, and payment risk. We explain these rules in our analysis of the Hydrocarbons Law and its regulation (in Spanish).
• 3. Buy shares of listed companies with Venezuelan projects. Chevron and Eni, which also shares a joint venture with Repsol, have Venezuelan projects. Venezuela is only one part of each business, so the share price will not track Venezuela alone. This is general information, not a recommendation to buy any security.
• 4. Trade Venezuelan and PDVSA debt. Venezuelan and PDVSA bonds are in default. Dealings in certain pre-existing bonds are authorized under OFAC General License 3I, and General License 58, issued on May 5, 2026, authorizes certain services to the Government of Venezuela in connection with a potential debt restructuring. The PDVSA 2020 bond, backed by Citgo shares, has its own license series. Returns depend on a restructuring whose outcome is uncertain, so this route suits specialist institutional investors, not individuals.

A recent example of route 1. On September 16, Denarius Holding Group, a US-incorporated company whose main shareholder is a listed Turkish company, announced an investment in the CEMA field (formerly Petrokariña) in Anzoátegui. Its Venezuelan partner, Minerosol Group C.A., signed a 20-year production participation contract (CPPH) with PDVSA, with a 20-year extension option. According to the company's own press release, the field holds about 100 million barrels of recoverable reserves, the plan calls for about US$400 million in phased investment, and output would rise from about 400 to about 9,870 barrels per day. These figures are the company's claims and have not been independently verified. The case shows how a Venezuelan-domiciled entity, foreign capital and a US-based vehicle can be combined, and that mid-size mature fields are a different market from the Orinoco majors.

Before you commit capital: a six-point check

• Vehicle. Which entity, where, and which authorizations does it need?
• Sanctions. Which license covers your activity, who is your counterparty, and is anyone in the exclusions? A non-US company is neither automatically covered nor excluded, so analyze it case by case.
• Title. Who owns or claims the field or the asset?
• Fiscal model. Model royalty, the Integrated Hydrocarbons Tax and income tax project by project. The regulation sets an aggregate rate that varies by project type.
• Disputes. Which forum and which rules apply, and are they written into the contract?
• Cash-out. How and when do proceeds reach you, given the license payment mechanics?

The main risks

• Sanctions can change fast. General License 52B lasted 18 days before 52C replaced it. Build plans that survive a licence change.
• Fiscal terms. The law sets royalty at up to 30% and an Integrated Hydrocarbons Tax of up to 15% of gross income, and the regulation sets 34% income tax on greenfield projects. ConocoPhillips' CEO has argued that the combined charges could let the state retain as much as 95% of project income.
• Contract stability and arbitration. Bloomberg reported that draft agreements circulated by PDVSA favor the government on arbitration, taxation and cancellation. The law allows mediation and arbitration, but the contract decides how well it protects you.
• Who owns the field. Competing claims over oilfields have already slowed at least one deal, according to Oilprice.com. Verify title before you commit.
• Getting paid. Under the OFAC licenses, payments must pass through a US-controlled Foreign Government Deposit Funds account. Ask how and when your money reaches you.
• Time and infrastructure. Reserves and production are separated by years and heavy capital. Output is roughly 1.1 to 1.2 million barrels per day.
• Political change. Exxon and ConocoPhillips have said they worry about what happens if the political situation changes in Venezuela or the United States.

Reading by profile

• Operator or strategic investor. The reform gives you more ways in and more written protection, but the largest companies are still negotiating fiscal terms and stability guarantees. Model each project separately and settle your sanctions position before you negotiate.
• Service provider. This is where entry is fastest. Plan for national content rules, the Integrated Hydrocarbons Tax on specialized services and payment risk, and arrive with a local partner.
• Financial investor. There is no clean way to buy “Venezuela oil.” Listed producers give partial exposure and debt is specialist territory. Treat any position as high risk and take professional advice.

Sources

• Reuters via EnergyNow, “SLB, Formentera working to activate drilling rigs in Venezuela, executives say,” August 19, 2026.
• Reuters via BOE Report, “Oilfield service firm Halliburton is discussing commercial terms with customers for Venezuela operations,” April 21, 2026.
• EFE via Infobae and MercoPress, coverage of the Shell license for the Loran field and the Carito and Pirital agreements, June 11-12, 2026.
• Repsol press release, “Repsol signs agreement to explore and develop a new oil area in Venezuela,” June 17, 2026.
• Maurel & Prom, “Update on Venezuela” (February 2026) and Half Year 2026 Results (August 2026).
• Denarius Holding Group Inc., press release via PR Newswire, September 17, 2026.
• Al Jazeera, “US's Chevron, Italy's Eni to expand oil projects in Venezuela,” September 3, 2026.
• France 24, “US oversees signing of 'billions' in deals between Venezuela and Chevron, ENI, GE,” September 2, 2026.
• Reuters, “Exxon advances talks to return to Venezuela's Orinoco Belt, sources say,” September 16, 2026.
• Bloomberg, report on Exxon executives' talks in Caracas, September 16, 2026.
• Bloomberg via World Oil, “ExxonMobil, ConocoPhillips negotiate possible Venezuela comeback,” May 26, 2026.
• Oilprice.com via Yahoo Finance, “Venezuela's Oil Revival Is Slower Than the U.S. Hoped,” August 24, 2026.
• Fortune, coverage of the White House meeting with oil executives, January 9, 2026 (includes Rystad Energy estimates).
• bne IntelliNews via MarketScreener, coverage of ConocoPhillips and Exxon positions, May 2026.
• Energy News Beat and Rio Times, coverage of the September 2, 2026 signings and the NABEP agreement.
• US Treasury, OFAC, Venezuela-related sanctions page and general licenses (46, 49, 50, 52B, 52C, 58).
• Gaceta Oficial Extraordinaria N° 6.978 (January 29, 2026), reform of the Organic Hydrocarbons Law; Decree N° 5.381, Gaceta Oficial Extraordinaria N° 7.052 (July 7, 2026).

Check official texts and the current status of each OFAC license before making decisions.

Frequently asked questions

Can foreign companies invest in Venezuelan oil? Yes, through the reformed hydrocarbons law. Private companies domiciled in Venezuela can operate primary activities by contract, so foreign capital enters through Venezuelan vehicles and joint ventures. Whether a specific foreign company can transact depends on US sanctions: OFAC licenses are narrow and exclude entities linked to Russia, Iran, North Korea, China and Cuba.

How can an oilfield service company enter Venezuela? Supplying equipment or specialized services to operators is a separate route from holding an interest in an oilfield. Before contracting, assess the local counterparty, applicable sanctions authorization, national content rules, tax treatment and how payments will be received.

Are US sanctions on Venezuela lifted? No. Sanctions on PDVSA remain in place. OFAC general licenses authorize specific activities under conditions, and they change quickly: General License 52C, issued on September 14, 2026, replaced 52B, issued on August 27.

Which oil companies are investing in Venezuela now? Chevron and Eni have signed expansion agreements, Continental Resources has signed a non-binding memorandum with PDVSA, Denarius Holding Group announced a 20-year production participation contract for the CEMA field, and SLB and Hunt Oil signed deals in August. Shell holds a license for the Loran gas field, and Repsol and Maurel & Prom keep operating. North American Blue Energy Partners holds a separate agreement covering 17 fields. ExxonMobil is in talks but has made no public commitment.

Is Venezuelan oil a good investment? No one can answer that in general. Venezuela holds the world's largest proven reserves, but production is roughly 1.1 to 1.2 million barrels per day, and raising it takes years and large amounts of capital. The risks are high and specific to each route. This article is not investment advice.

How much would it cost to raise Venezuela's oil production? Rystad Energy estimated in January 2026 that more than doubling production would take until about 2030 and cost around $110 billion, while returning to 2000 levels would take well over a decade and about $185 billion.