The country, recently thrown into acute political turmoil following the capture of its long-standing authoritarian president by U.S. forces, holds the world’s largest proven oil reserves. U.S. President Trump has openly highlighted the country’s oil potential and is encouraging U.S. oil companies to return. Yet beyond the political narrative, the feasibility of such ambitions remains highly uncertain. Some major oil companies, including ExxonMobil, remain openly skeptical about re-entering Venezuela. Assessing the country’s real potential therefore requires a sober examination of its resource base, crude quality, infrastructure condition, and investment requirements. To clarify these points, we contacted experts at Rystad Energy and GlobalData.
In a hurry? Here are the key notes to know:
- Huge reserves, weak output: Venezuela holds the world’s largest oil reserves, but production has collapsed to below 1 million bpd due to sanctions, underinvestment, governance failures, and infrastructure decay.
- Challenging economics: Extra-heavy crude, high operating costs, degraded pipelines, refineries, and storage systems keep Venezuelan oil structurally discounted and difficult to scale competitively.
- Long and costly recovery: Reaching 3 million bpd would require around $180 billion in investment and decades of work, with meaningful growth unlikely before the 2030s; Chevron remains the only near-term upside.
- Politics drive outcomes: Sanctions, legal uncertainty, and investor distrust—highlighted by Exxon calling Venezuela “uninvestable”—remain the key barriers to any oil sector revival.
It has now become inevitable to talk about Oil & Gas without addressing Venezuela. The country, which has been in acute political turmoil since the capture of Nicolas Maduro by U.S. forces 10 days ago, holds the world’s largest proven oil reserves (303 billion barrels, 17% of global reserves). This endowment has long made Venezuela particularly attractive to Washington. President Trump has made little effort to conceal his interest in the country’s oil potential. He reportedly called for as much as $100 billion in investment to revive the sector.
Beyond the political narrative, however, a closer examination of the country’s oil infrastructure, crude characteristics, and operational constraints is required to assess what portion of this potential could realistically be developed, by whom, and on what timeline.
To that end, we contacted Paul Hasselbrinck, Senior Energy Analyst at GlobalData, and Artem Abramov, Head of Oil & Gas Research at Rystad Energy.
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What Is the Strategic Context of Venezuelan Oil?
Reserves
According to the U.S. Energy Information Administration, Venezuela holds the world’s largest proven crude oil reserves, with approximately 303 billion barrels. This represents roughly 17 % of global reserves, surpassing long-time holders such as OPEC leader Saudi Arabia.
These reserves are concentrated mainly in the Orinoco Belt, located in the central and eastern part of Venezuela. It stretches from west to east over a length of approximately 600 kilometers and lies on the northern bank of the Orinoco River. It mainly covers the states of Anzoátegui, Monagas, and Guárico.
If in geological terms, Venezuela is not resource-constrained, operationally, however, the picture is very different.
Production Trends
Despite this geological abundance and massive reserves, Venezuela’s actual production remains a fraction of its potential. The EIA reports that Venezuela accounted for only about 0.8% of global crude oil production in 2023.
Rystad Energy notes that production peaked in the 1970s at around 3.5 million barrels per day (bpd). This represented more than 7% of global output at the time. But the oil crisis of 1973 immediately shaved 1 million bpd off supply. And output declined steadily from the 1990s onward (falling below 2 million bpd during the 2010s).
By 2024, production hovered below 1 million bpd, less than 1% of global supply. Importantly, Rystad Energy highlights that even before the recent U.S. military intervention, market consensus already pointed to a declining production outlook for 2026–2030.
Paul Hasselbrinck, Senior Energy Analyst at GlobalData underscores the structural nature of this decline:
“Despite a vast legacy infrastructure, the lack of project developments across the oil value chain is plain evidence of the lackluster state of the industry. According to GlobalData’s Oil & Gas Projects database, only one of seven ongoing projects is under construction—the Puerto de la Cruz refinery expansion—which itself has faced massive delays and down-sizing since its FID in 2012.”
He adds that the gap between reserves and production is driven by a combination of factors:
“Constraints stem from the Orinoco Belt’s extra-heavy crude, decaying midstream infrastructure, shortages of chemicals and machinery, severe labor shortages, and the corrupt governance of PDVSA, compounded by sanctions, capital scarcity, and the broader macro-political environment.”
Who Are The Oil Companies Present in Venezuela?
Venezuela’s state company, Petróleos de Venezuela S.A. (PDVSA) was created in 1976 and initially maintained strong relationships with Western oil majors. With international investment, Venezuelan production recovered to just over 3 million bpd by the late 1990s. However, worsening economic conditions and inequality paved the way for Hugo Chávez’s election in 1998.
In 2006, Chávez mandated that all Orinoco Belt projects be converted into joint ventures with PDVSA holding at least a 60% stake.
Chevron was among the few companies to accept these terms. The company has remained active as a minority partner through both the Chávez and Maduro eras.
TotalEnergies and Equinor initially complied but exited their Petrocedeno operations in 2021.
ExxonMobil and ConocoPhillips refused the new terms altogether, leading to the nationalization of their assets. This episode continues to shape investor perceptions of political risk.
What Is the Nature of Venezuelan Crude and Why Does It Matter?
Extra-heavy Crude Characteristics
Most of Venezuela’s proven reserves consist of heavy and extra-heavy sour crude. This includes most of Chevron’s roughly 150,000 bpd operations in the country and nearly all volumes produced in the Orinoco Belt.
These crudes typically have low API gravities, very high viscosity, and elevated sulfur and metal content. These physical properties make this crude costly to produce, difficult to transport through pipelines without blending with lighter diluents, and challenging for many refineries to process efficiently
But for Paul Hasselbrinck, these are not challenges unknown to the industry:
“This crude profile is very similar to Canadian oil sands in Alberta, primed for bitumen, and similar to Colombia’s heavy crude from the Llanos basin, albeit more viscous. While the break-even prices for Colombian and Canadian crude, and generally for heavy oil, are notably higher, Venezuela’s current cost structure yields a much higher break-even point despite its devalued currency, owing purely to operational inefficiencies.”
Processing and Market Implications
Let’s see in detail. Heavier crudes are harder to extract and refine and yield lower value products. In practice, Venezuelan crude must either be blended with imported diluents (such as naphtha or condensates) to make it pipeline-compatible, or upgraded through complex hydroprocessing units to produce a synthetic crude. Both options significantly increase capital and operating costs and require technical expertise that historically came from international oil companies.
Due to these constraints, Venezuelan crude often trades at a persistent discount on international markets relative to comparable benchmarks. This structural discount has weighed heavily on the country’s ability to attract new investment, says Mr. Hasselbrinck:
“Generally, lighter crudes are therefore sold at a higher price point, with historical gaps between grades ranging from $2 to $10 per barrel. However, each is affected by supply & demand dynamics, and increased heavy refining capacity and US shale light crude boom have narrowed this gap in recent years. Importantly, large global powers such as the US, China and India have the most extensive heavy crude refining capacities. In fact, more than two-thirds of US refining capacity is optimized for heavy crude, the chief reason why the U.S. still relies on oil imports despite the surge in production over the past two decades.”
What Is the Current State of Venezuela’s Oil Infrastructure?
Decades of underinvestment have degraded Venezuela’s entire oil system.
Extraction Facilities
The Orinoco Belt requires artificial lift systems, thermal recovery techniques, and reliable access to diluents. Decades of underinvestment and unreliable power have left many wells degraded, reducing efficiency and raising production costs.
Transport Network
Downstream of production, Venezuela operates a pipeline network comprising roughly 25 major pipelines. They have a theoretical capacity of around 9 million bpd and a total length of approximately 3,400 kilometers. In reality, much of this network dates back more than five decades. Corrosion, leaks, pump failures, and insufficient maintenance have significantly reduced effective throughput and increased environmental risks.
Terminals and Export Facilities
Export infrastructure is concentrated in a small number of marine terminals. Around 90% of exports historically passed through the José terminal. There are additional facilities at Amuay Bay, Puerto La Cruz, and Puerto Miranda. The concentration of export routing creates chokepoints; disruptions or blockades quickly translate into export curtailments. The Guardian reported that recent U.S. enforcement actions, including tanker seizures and blockades, have constrained flows further.
Refining Capacity
Venezuela’s refineries once ranked among the world’s largest, but effective capacity has fallen below 300,000 b/d due to equipment decay, lack of spare parts, and frequent accidents. As a result, as reported by Statista, the country has occasionally imported refined products despite its crude abundance.
Storage and Logistics
Storage constraints further limit operational flexibility. Tank farms are frequently saturated, forcing production shut-ins or the use of floating storage. According to multiple industry sources, including Reuters, this bottleneck has directly constrained export volumes even when upstream production briefly recovered.
What Are the Structural Constraints on Recovery?
Sanctions History
U.S. sanctions targeting Venezuela’s oil industry were progressively tightened from 2017 onward, culminating in a comprehensive oil export embargo in January 2019. This sharply curtailed legal sales to U.S. refineries and limited access to financing and technology. Even as limited licenses were granted later (e.g., to Chevron), the sanctions regime has been a persistent structural constraint on investment and production growth.
The effects of sanctions also restricted access to Western technology, specialized equipment, and international financing, forcing reliance on intermediated and sometimes sub-optimal suppliers. Even where sanctions waivers are granted, the uncertainty surrounding their continuity suppresses long-term capital commitments
Aging Infrastructure, Human Capital Flight, Environmental Concerns
Key assets—pipelines, pumping stations, refineries, power systems—are beyond design life, with billions needed merely to restore 1990s production levels.
Widespread departure of experienced engineers, technicians, and maintenance professionals has eroded operational capability at PDVSA and in key service sectors.
Chronic neglect (frequent leaks, spills, and fires) has increased environmental and safety risks, further deterring investment.
What Would It Take to Return to 3 Million bpd?
With Venezuela’s oil sector severely degraded after decades of underinvestment, the question is no longer whether the country has sufficient reserves—but whether production can be rebuilt in a technically and economically viable way.
Skepticism From the Industry
As President Donald Trump promotes a vision of massive U.S. investment to revive Venezuelan oil output, industry stakeholders are now asking what such a recovery would actually require in terms of capital, equipment, infrastructure, and execution capacity.
During a recent meeting at the White House with top executives from U.S. oil companies, industry leaders did not rush to signal their wish to return to Venezuela. ExxonMobil CEO Darren Woods was particularly explicit, stating:
“We have had our assets seized there twice, and you can imagine that re-entering for a third time would require some pretty significant changes from what we’ve historically seen and from the current situation. Today, it’s uninvestable.”
These remarks reportedly displeased President Trump, who responded yesterday by warning ExxonMobil that it could be kept out of Venezuela altogether.
Rystad Energy has modeled a detailed “back to 3 million bpd” scenario, offering valuable insights into the scale, timing, and industrial implications of a potential recovery.
Scenario #1: Holding Production Flat: A Capital-Intensive Baseline
According to Rystad Energy, maintaining Venezuela’s current crude oil production—around 1.1 million barrels per day—would already require approximately $53 billion in upstream and infrastructure investment over the next 15 years. This spending would largely be directed toward well interventions and artificial lift systems, maintenance of existing surface facilities, power supply stabilization and pipeline and terminal repairs. But even under this baseline scenario, Venezuela’s oil industry would remain highly capital- and equipment-intensive, with limited room for output growth.
Moreover, adds Artem Abramov, Head of Oil and Gas Research at Rystad Energy,
“We estimate that only 300,000 bpd of additional supply can be restored within the next 2-3 years with limited incremental spending.”
Scenario #2: Scaling Up: From 1.4 to 3 Million bpd
Going beyond 1.4 million bpd would require a fundamentally different investment profile. Rystad Energy estimates that achieving sustained growth would demand $8–9 billion per year from 2026 to 2040, on top of “hold-flat” capital expenditure.
Under this scenario, production could reach 2 million bpd by 2032. And a return to 3 million bpd would only be feasible by… 2040!
“The total oil and gas capex required over the 2026-2040 period to reach that target is estimated at $183 billion, with cumulative service purchases of an estimated $156 billion, after internal E&P operator spending is removed.”
While Rystad believes some of this investment can be financed organically by national oil company PDVSA, at least $30-35 billion of international capital would need to be committed in the next 2-3 years to make a 3 million bpd-by-2040 scenario plausible.
Aging Infrastructure: The First Industrial Bottleneck
Infrastructure rehabilitation emerges as the single most critical prerequisite. Rystad Energy estimates that more than $65 billion would be required solely to repair, upgrade, and rebuild Venezuela’s aging oil infrastructure:
“Notably, this $65 billion infrastructure spend on repairs, upgrades, and rebuilds is a mandatory prerequisite for a stable 3 million bpd flow, even before we consider the greenfield and brownfield investments needed to increase field output to this level.”
For industrial suppliers, this phase represents the earliest and most equipment-intensive wave of potential activity.
Realistic Timelines: Why a Venezuelan Recovery Will Be Slow
Even under the most optimistic political assumptions, Venezuela’s oil recovery is constrained by execution realities. Any credible restart strategy must first focus on stabilizing existing operations, rehabilitating critical transport, storage, and export infrastructure, and securing reliable access to diluents and upgrading technology. Just as importantly, the sector would require clear, durable legal and fiscal frameworks capable of attracting long-term international capital and technical partnerships.
Stabilizing Operations and Infrastructure
From an operational standpoint, however, timelines remain long. Paul Hasselbrinck from GlobalData, stresses that production growth cannot materialize quickly—even if licenses were granted immediately:
“From the award of a license, optimistic production start dates would take three to five years for new fields, and somewhat less for expansions. The only realistic short-term growth would come from Chevron’s existing license and producing fields, which currently face bottlenecks due to constraints in capital, labor, and machinery availability—assuming sanctions are lifted and foreign investment and skilled workers are allowed to return.”
Even in a favorable scenario where new licenses begin to be issued as early as this year, Hasselbrinck believes that material production growth would only emerge toward the end of the decade, with Venezuelan output unlikely to return to pre-Maduro levels before 2030.
The Role of Greenfield vs. Existing Assets
From an upstream perspective, he argues that the most immediate opportunities lie not in greenfield developments but in enhanced recovery and restoring commercial viability across existing assets:
“Greenfield projects, despite some understanding of the reservoirs, first require the formalization of geological data and appropriate licensing structures before planning approvals and final investment decisions can even be considered.”
Political and Geopolitical Constraints
Beyond technical and commercial hurdles, Hasselbrinck emphasizes that Venezuela’s future role in global energy markets depends on a complex set of political and geopolitical variables—far beyond reservoir quality or capex availability.
“The first question is whether the U.S. involvement in Venezuela will yield in favor of Donald Trump’s outspoken wishes, which notably did not include using Venezuelan crude as a leverage tool, but that it would “be sold all around the world”. Second, is how long we believe it will take before that, and how far he is willing to go if he faces increasing push-back from the Venezuelan regime, and pressure from the international community for any further military actions.”
Prolonged tensions, he warns, could stretch beyond Trump’s current term, undermine domestic political support, and ultimately weaken Washington’s resolve to pursue a Venezuelan oil revival.
A final—and equally critical—unknown is domestic stability:
“How protracted tensions, social discontent with a regime that is composed of virtually the same crowd, will influence how long it takes before sufficient political stability is achieved to undertake the various fiscal, monetary, regulatory, legal and governance reforms needed to provide assurances to oil and gas supermajors that it is safe to invest.”
Global Implications
Even assuming a series of favorable political developments—none of which are likely within the next year—Venezuela would only begin a gradual path toward reviving its oil supply chain. In the short term, Chevron’s existing operating license remains the sole credible source of incremental production. New developments would likely require at least three years after licensing to generate meaningful volumes.
With Venezuela’s production currently a small share of global supply, immediate impacts on prices would likely be modest. However, over time, a gradual rehabilitation could exert downward pressure on heavy crude benchmarks and support shifts in refinery feedstock patterns over time.
While it remains too early to predict how global oil markets would ultimately absorb a Venezuelan recovery, Hasselbrinck notes that in a market already flirting with oversupply—amid weak demand growth and OPEC’s reluctance to deepen cuts—a resurgence of Venezuelan crude would almost certainly add downward pressure to already fragile prices.
As he concludes:
“Addressing any single issue in isolation will not lead to a meaningful increase in output. What Venezuela needs is a clear, coordinated roadmap to overcome decades of systemic neglect across its entire oil supply chain.”
What This Means for Industrial and Service Suppliers
For industrial players, the most compelling insight from Rystad’s analysis lies in the scale and structure of service-sector demand. Indeed, in the 3 million bpd recovery scenario, $156 billion in service purchases would be generated between 2026 and 2040. And the spending profile is heavily infrastructure-driven, notes Artem Abramov:
“The fabrication and construction segment logically ranks first in service-sector outlay, accounting for $41 billion of total purchases. Five other service segments ‒ major equipment, materials and metals, maintenance and mechanical, electrical and instrumentation, and logistics and support ‒ have 15-year market sizes exceeding $10 billion.”
However, Rystad cautions that years of domestic industrial atrophy and a shortage of skilled labor make it unlikely that Venezuela could absorb such a surge in activity quickly. Any rapid ramp-up would likely trigger capacity constraints and inflationary pressures, increasing reliance on international suppliers.
A Market to Watch—Not Yet to Enter
While no immediate boom should be expected, Venezuela represents a long-cycle, infrastructure-heavy opportunity that industrial suppliers, EPC contractors, and equipment manufacturers cannot ignore. As exploration and production sentiment evolves, major service providers are already monitoring developments closely—aware that if political and regulatory conditions align, the scale of the potential supplier market would be among the largest oil-sector rebuilds globally.For now, Venezuela remains less a short-term opportunity than a strategic option on the industrial radar.
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