A Promise Made Too Soon:

A Promise Made Too Soon:

Venezuela’s Oil Industry’s Cold Restart

Introduction

On January 3rd, 2026, a U.S. task force captured Venezuelan president Nicolas Maduro and his wife, who were brought to the United States to face charges for narco-terrorism. Hours later, U.S. President Donald Trump held a press conference in which he made clear that control over Venezuela’s oil reserves was one of the key objectives of the operation. The country has the world’s largest proven oil reserve, amounting to over 300 billion barrels, around 17% of all global reserves. To put into perspective, the U.S., the world’s largest oil producer today, has a proven reserve of around 46.4 billion barrels as of the end of 2023 (EIA, 2025).

Trump stated that the United States would not bear the costs of revitalizing Venezuela’s oil industry, as this reform would be spearheaded by the big oil companies. This claim, however, seems to lack a basis in the actual perceptions and plans of the big players. On January 9th, a meeting between Trump and major oil executives took place in the White House to discuss Venezuela and its future. During the discussion, ExxonMobil CEO Darren Woods made clear that, for his company, Venezuela is currently “uninvestible” (BBC, 2026). Though his company has a poor record in Venezuela, having had its assets seized twice, his perception is a pragmatic one. Nonetheless, this “uninvestible” assessment isn't simply about past expropriations, but a reading of institutional realities that make a profitable operation impossible.

Venezuela currently faces numerous hurdles on its path to reconstruction, stemming from the country’s institutions and particularities, as well as from ongoing changes and new opportunities in the energy sector. New trends and discoveries are pushing the sector's largest players away from an investment that would require years, billions of dollars, and a high level of risk tolerance to yield any return (Hernández & La Rosa, 2021).

An uninvestible country

In the 1990s, Petróleos de Venezuela S.A. (PDVSA), Venezuela's state-owned oil company, lacked the capital and the infrastructure to explore declining oil fields and develop new projects (Monaldi et al, 2020). To address the situation, the government introduced new types of contracts and tax incentives to attract foreign companies to establish joint ventures with PDVSA and to develop new fields and infrastructure. Total Apertura-related FDI surpassed US$20 billion between 1992 and 2005, doubling Venezuela's oil sector capital expenditure (ibid). Nonetheless, this model was a short-lived one.

Before Chávez, the PDVSA had a high level of autonomy and operated under private commercial law rather than public administrative law. This regime enabled the company to bypass certain bureaucratic and ministerial oversight that could impede its operational capacity. Regardless, after Cháves assumed the presidency, he started to reform the PDVSA. An inflection point came in 2003 when he fired over 18.000 workers after a general strike. From that point, PDVSA leadership became increasingly composed of political allies instead of competent professionals (Jraissati & Jakee, 2022). This significantly diminished the company’s administrative capabilities and performance. By 2015, 40% of PDVSA's oil drills were non-operative due to incompatible equipment acquisitions, logistical failures, and lack of experienced personnel (Monaldi et al, 2020).

From that point on, the sector began to decline, as royalties had been rising since 2001, and in early 2005, the Venezuelan government announced that all strategic associations must convert to mixed enterprises or face expropriation. The new structure required PDVSA to have a minimum 60% equity, an increase from the 30-50% existing, and transferred operational control (Monaldi et al, 2020). Companies such as ExxonMobil and ConocoPhillips refused these terms, invoking their contractual arbitration rights and filing claims arguing the conversion constituted expropriation without adequate compensation. The government’s response in mid 2007 was to seize operational control of the companies’ infrastructure.

The arbitration proceedings that followed took years to resolve. ExxonMobil was ultimately awarded US$1.6 billion in 2014, and ConocoPhillips received US$8.7 billion in 2019 for field expropriations. However, these awards came 7-12 years after the expropriations occurred, and Venezuela’s government has largely refused to pay the billions of dollars that are still to be received by these companies, claiming financial inability (Venezuelanalysis, 2025). Some players, such as Chevron, chose differently, bearing the migration terms under protest and converting their strategic associations into mixed enterprises with reduced equity stakes and surrendered operational control.

Under the memory of such a hostile takeover, any oil company would be wary of investing its money in Venezuela. But they are not thinking about the past as much as the current state of affairs. The ruling party in the government is still the same that took their property, and thought they made a case to reopen the sector to private and foreign companies, but the legal framework has just been reformed. Big moves are yet to be seen, and an impact is yet to be felt. Beyond problems regarding the political risk aspect, Venezuelan oil has some disadvantages that make it unattractive when compared to other prospects.

Much pain for low gain

Venezuela's primary type of crude is classified as extra-heavy. The Orinoco Oil Belt, the largest known oil deposit on the planet, produces even heavier crude at 7–13° API with viscosities comparable in consistency to syrup rather than the water-like fluidity of light crude (Balza & Espinasa, 2015). This viscosity has direct economic consequences, as extra-heavy crude cannot be transported through pipelines or exported without either upgrading or dilution with lighter hydrocarbons. To transform this crude into a synthetic light crude requires technical expertise and infrastructure upgrades. Without functional upgraders, the crude is essentially landlocked (Hernández & La Rosa, 2021). The deterioration of oil facilities following the 2007 nationalizations directly constrained export capacity, as evidenced by production collapsing from 600,000 b/d in 2005 to below 300,000 b/d by 2020 (Roy & Cheatham, 2024).

Aside from transportation issues, the oil had extraction hurdles. The lack of thermically enhanced extraction leads to cold production, which reaches a recovery factor of only 5–6% of oil in place in the Orinoco Belt, leaving an estimated 95% of the resource in the ground (Rystad Energy, 2026). To put this in contrast, in Canada, a place that reaches extremely cold temperatures and also possesses oil classified as extra-heavy, routinely achieves over 20% recovery factors through thermal methods (CAPP, 2025). However, they operate under stable institutional frameworks with access to patient capital and technical knowledge. In the end, the facilities and support are what gain the interest of the investors (Manzano & Monaldi, 2008).

While Venezuela already passed new laws and taxation systems, other countries developed more sophisticated and attractive strategies. The new plan would install a royalty rate as high as 30%, tax-cum-royalty of as high as 15%, and new income taxes (King & Spalding, 2026). In South America alone, Venezuela is outclassed in the competition for FDI by its neighbors, such as Argentina, Brazil, and Guyana. Although these three countries face hurdles related to oil extraction, all possess higher average API reserves and more reliable institutions.

For example, Brazil has a consolidated system that tends to investors' needs, which went the opposite way of Venezuela after Chavez. First, it eradicated its government-owned company monopoly in 1997 in order to open space to new players. Shortly after, the government established the independent National Agency of Petroleum (ANP) to administer competitive auctions under concession and production-sharing contract regimes (Hernández & La Rosa, 2021). Furthermore, even though Brazil has one of the largest hydrocarbon endowment systems in the world, it has a progressive tax system, which is profit-based instead of production-based. According to Manzano and Monaldi (2008), income taxes are more progressive than royalties, as the profit tax is at a rate that effectively obliges the host government to partake in expenditures. Each dollar spent reduces taxable income by one dollar, so the operator's net cost is only (1- tax rate) per dollar spent. This fiscal design solves a core problem in high-risk, capital-intensive projects, as it aligns the host government's revenue stream with project success rather than punishing operators (Balza & Espinasa,2015).

In contrast, Guyana entered oil production only in 2019 and rapidly became South America's third-largest producer by 2025. To put the country's appeal in perspective, ExxonMobil and partners have committed over US$60 billion to develop offshore fields, bringing production to 900,000 b/d as of early 2025 with projections reaching 1.7 million b/d by 2030 (ExxonMobil, 2025). The key attractive element lies in the fact that while its initial 2016 production-sharing agreement offered remarkably favorable terms to operators with 2% royalty, 75% cost recovery ceiling, and a 50/50 profit split after costs, the government maintained regulatory consistency and swift permitting timelines (Petroleum Agreement, 2016).

Even unconventional reserves are getting surges in FDI, such as Argentina's Vaca Muerta shale formation, by offering an attractive model. Market reforms introduced in 2023 offered 30-year fiscal stability, capital repatriation guarantees, and fast-track permitting, bringing a production surge to the region. Shale oil now represents 66% of Argentina's total production, as output jumped 30% yearly, reaching over 550.00 b/d by the end of 2025. Vaca Muerta has attractive breakeven costs, averaging US$36-45 per barrel, with lifting costs going as low as US$4.60 per barrel (Brazil Energy Insights, 2025). Additionally, new infrastructure projects are set to upgrade the sector in Argentina. Such as the Oil Sur Pipeline Project, a US$2.5 billion project that started in early 2025, linking Vaca Muerta to a storage facility and port terminal at Punta Colorada, could double Argentina’s oil export capacity by the end of 2026 (Deloitte, 2025).

The road ahead

As it was shown in this paper, Venezuela has a myriad of issues that need to be tackled before it returns to its peak historical capacity. Hernández and La Rosa (2021, pp 12) estimated it would take a continuous investment that could total US$78-120 billion over eight to ten years to increase production to over 2 million barrels per day. They also explain that Orinoco projects would require decade-long contracts with mandatory fiscal review, as Orinoco Belt projects cost US$5.7 billion each and take years to break even. This is due to the necessity to build upgraders to convert extra-heavy crude into transportable syncrude and build new infrastructure. However, a decades-long contract creates obsolescing bargain risk. If oil prices spike, the government sees the company making huge profits and wants to renegotiate.

Beyond internal issues, the energy markets are seeing trends that could undermine investors' willingness to dedicate capital to rebuilding Venezuela. A 2025 report by the International Energy Agency (IEA) states that, though global oil demand is expected to rise until 2030, due to recent market trends, this growth will be slow, and a decline is expected to commence after the end of the decade.

IEA - Executive Summary - Oil (2025) - Average annual oil supply and demand growth in China and the United States, 2015-2030

The adoption of electric cars and high-speed train networks, especially in China, and new environmental regulations are set to disrupt oil demand. Furthermore, investment in clean energy broke records in 2025, reaching US$2.3 trillion, a 8% increase from 2024 (Bloomberg, 2026). This showcases a future where energy is mostly independent from fossil fuels.

This is an unfavorable scenario for Venezuela, whose decade-long reconstruction plan is set in the decade that the energy market is set to change the most. This leads investors to question whether it's worth applying capital, which takes years to start to make a profit, to rebuild an industry that is set to enter its decline. Policy-wise, Caracas should focus on developing relations with other emerging economies that require oil to develop their industries, which are less inclined to turn to clean energy in the near future. The ideal policy for Venezuela would be to further develop its relationship with China, whose companies are already present in the country and whose government is close to the ruling party. This, however, seems to be unlikely, as Washington, the de facto ruler of the country for the time being, would currently seek to reduce Chinese influence on the continent.

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