Why Venezuela’s Oil Won’t Matter and Why Heavy Crude Is First Off the Market

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The idea that Venezuela’s oil matters to the United States, to global oil prices, or to the trajectory of decarbonization keeps resurfacing whenever geopolitics intrude into energy discourse. It is usually framed as a latent supply story, a sense that a large reserve base exists somewhere and could be tapped if only politics aligned. That framing is misleading. Even under optimistic political assumptions, Venezuela’s crude does not move prices in a durable way, does not materially improve US energy security, and does not slow or reverse decarbonization. The constraints that matter are structural and physical, not diplomatic. The United States’ return to the Monroe Doctrine, something I assessed about almost a year ago, isn’t changing oil economics.

A persistent error runs through most public discussion of oil policy, especially in political circles. Oil is treated as if it were a single interchangeable commodity. In reality, crude oil exists, coarsely, on a two-axis spectrum defined by density and sulfur content, and refineries are built around narrow slices of that spectrum. Light, sweet crudes flow easily, contain little sulfur, and yield high proportions of gasoline, naphtha, and petrochemical feedstocks. Heavy, sour crudes are dense, sulfur rich, and yield larger fractions of diesel, residual fuels, and asphalt. These differences are not academic. They determine where crude can go, what it can be turned into, and whether it is economic at all. Much of US policy still operates on a 1970s mental model of oil scarcity, when volume mattered more than quality and demand growth was assumed.

Venezuela is often described as having the world’s largest proven oil reserves at around 300 billion barrels, which would represent roughly 17% of the global total and easily exceed the reserves of the United States and Russia, but the simple fact of large reserves masks critical nuances about extraction and market value. Most of this oil is extra-heavy crude concentrated in the Orinoco Belt, buried deep underground and much more viscous and sulfur-rich than the light crude that dominates global trade, so producing it requires blending with lighter hydrocarbons, significant diluent imports, and more complex processing. All of this makes extraction costlier and slower compared with conventional light oil.

Much of the resource is onshore but its depth and physical characteristics mean it is harder to get to than conventional fields, and estimates of technically recoverable volumes vary widely because economic recoverability depends on price, technology, and infrastructure investment. As a result, despite enormous reported reserves Venezuela doesn’t have nearly as much economically recoverable oil except in a world with massive oil demand growth and sustained high prices. That world has already departed, and it’s not coming back.

Venezuela’s modern oil story begins with early twentieth century discoveries that transformed a poor agrarian state into a petrostate almost overnight. Foreign companies developed the fields, revenues flowed quickly, and institutions never caught up to the scale or complexity of the industry that emerged. The country became dependent on oil rents, with political incentives aligned around distribution rather than reinvestment.

When political figures like Trump use phrases like “Venezuela stole our oil,” they are drawing on a simplification of a much longer and more complex history, and one that’s 50 years old. I’m pretty sure Trump couldn’t spell Venezuela 50 years ago, never mind find it on a map, and doubt he could now. In the 20th century, American oil firms such as Creole Petroleum Corporation, a unit linked to Standard Oil of New Jersey, helped open Venezuelan fields and for decades were among the largest foreign investors there, but Venezuelan oil was always legally sovereign Venezuelan resource, not legally “American” oil.

In 1976, Venezuela nationalized its petroleum industry, creating the state-owned company PDVSA and ending the era of foreign control, and later governments pressed deeper national control and changed the terms of foreign partnerships. The election of Hugo Chávez in 1998 marked a decisive shift. Several U.S. companies including ExxonMobil and ConocoPhillips had projects expropriated and later pursued international arbitration for compensation, and Chevron chose to stay under terms agreed with the Venezuelan state. Contemporary political rhetoric that frames this as theft plays into familiar grievances, but under international law natural resources belong to the state where they are located, and the outcome of past expropriations was handled through negotiated settlements and arbitration rather than wholesale seizure of oil stocks.

Under Chavez, PDVSA was subordinated to political goals—eerily similar to the destruction of technical competence in US governmental organizations in the past year—, senior technical staff were removed after labor unrest in the early 2000s, and maintenance and reinvestment were deferred in favor of social spending and regime stability. Oil prices masked the damage for several years, but the underlying decline had begun. When Nicolás Maduro took power in 2013, the deterioration accelerated. Infrastructure decayed, skilled workers left the country, and production fell sharply. Sanctions compounded the decline, but they did not create it. By the early 2020s, Venezuela possessed vast reported reserves but lacked the operational capacity, capital, and workforce to turn those reserves into sustained production.

The reasons Venezuelan crude does not flow at scale today are straightforward. Much of the resource base consists of extra heavy crude that does not move without blending with lighter diluents, which Venezuela must import. Extraction is energy intensive, maintenance heavy, and sensitive to interruptions. Restarting shut in fields is not like turning a valve. It requires continuous investment and stable operations over years. Even stabilizing production would require tens of billions in spending. Raising output materially would require something closer to $100 billion over a decade. That scale of capital must be patient, politically insulated, and confident in long term demand. Even if someone was willing to pay for it, significant increases are a decade away in a world clearly pivoting away from oil and toward renewables and electrification.

Capital markets are not willing to provide that. This is not about environmental signaling. It is about risk adjusted returns. Global oil demand growth has slowed and is expected to flatten and decline over the investment horizon required to rebuild Venezuela’s industry. Oil majors prefer short cycle projects or distributions to shareholders. Financial institutions avoid jurisdictions with histories of expropriation and contract instability unless governments provide guarantees and backstops. Venezuela offers long cycle risk layered on top of political uncertainty in a market that no longer promises growth.

Any capital that could plausibly be raised for Venezuelan oil projects would come at an exceptionally high cost because investors price in political instability, contract uncertainty, sanctions risk, and long project timelines. In stable jurisdictions, large upstream oil projects are typically evaluated with discount rates or weighted average costs of capital in the range of roughly 8% to 12%, with many companies using around 10% as a baseline, but in high-risk environments those rates rise sharply once country and sovereign risk premiums are added.

For jurisdictions like Venezuela, where expropriation risk, currency risk, and regulatory volatility are material, required returns are more realistically in the 15% to 25% range, and sometimes higher, which makes long-cycle projects with multi-year buildouts and uncertain demand fail internal hurdle rates. At those costs of capital, final investment decisions are deferred or abandoned unless risks are shifted away from private investors. In practical terms, that means any serious attempt to revive Venezuelan oil production at scale would require explicit government guarantees or backstopping to lower the effective cost of capital, because private markets are unwilling to finance such projects on commercially viable terms.

No private company will invest in Venezuela’s oil infrastructure with their own money. Wall St. will charge up to 25%, so no companies will go forward because they can’t make money. That’s why Trump is now saying that Americans are supposed to pay to get Venezuela’s oil flowing less sluggishly.

Recent trends in capital flows reinforce the idea that fossil fuels are no longer the central magnet for investment that they once were. Data shows that financing from the largest Wall Street banks for oil, gas, and coal projects has dropped sharply, with overall fossil fuel lending down about 25% in the first seven months of 2025 compared with the previous year, reflecting a retreat of traditional financiers even as some banks step back from formal net zero pledges.

At the same time, investment patterns at the global level point to a shifting allocation of resources, with the International Energy Agency reporting that total investment in clean energy technologies, grid infrastructure, electrification, and related areas is set to be roughly double the amount going into oil, gas, and coal in 2025, and that clean energy investment has more than doubled over the past decade even as fossil fuel investment has flattened. This redeployment of capital toward renewables and electrification, and away from conventional upstream oil and gas, underscores a broader reassessment of the long-term returns of fossil fuel assets relative to the expanding markets for electricity-based technologies and fuels.

The United States does not need Venezuelan oil to meet its energy needs. The US is the world’s largest oil producer and exports large volumes of crude. The constraint it faces is not volume but mismatch. Shale production delivers light, sweet crude in abundance. Venezuelan crude is heavy and sour. Adding Venezuelan supply would not solve domestic bottlenecks or lower prices in a durable way. At best it would displace other heavy crudes at a limited number of refineries already configured to handle them.

Understanding this requires a brief look at US refining and export policy. After the oil shocks of the 1970s, the United States banned crude oil exports in 1975 to protect domestic supply. At the time, US production was declining and imports dominated. That policy lingered long after its rationale faded. When shale production surged in the late 2000s and early 2010s, the US found itself awash in light crude that inland refineries could not absorb. Prices diverged, distortions grew, and in 2015 the export ban was lifted. Since then, US light crude has flowed to global markets that value it, while US refineries continue to import grades they were built to process.

From the 1980s through the early 2000s, US refiners made large investments to handle heavy, sour crude from Venezuela, Mexico, and Canada. They installed cokers, hydrocrackers, and desulfurization units to turn discounted heavy barrels into high value products. These refineries are complex, capital intensive, and rigid. They consume large amounts of hydrogen—the largest demand sector on earth—and energy, and they are optimized for diesel and residual products. Light crude refineries are simpler and more flexible. They yield more naphtha, which feeds petrochemicals, and they align better with a world where fuel demand is no longer growing but petrochemical and plastic demand is stable or growing. That segment is also a small segment of total oil demand, with fuel dominating massively.

Heavy crude refineries are now on the wrong side of demand. Diesel demand is shrinking, and California offers an early signal of where this goes. Gasoline demand there has been falling for years as electric vehicles spread. Diesel followed later. Renewable diesel masked the decline in fossil diesel volumes for a time, but electrification of freight will erode demand for both. Heavy crude yields a stubborn product slate. When local demand falls, refiners export surplus diesel at thinner margins or cut runs. Over time, closures follow. California’s refinery shutdowns are not regulatory anomalies. They are market signals.

In Europe, diesel consumption has been declining for several years as tighter emissions standards, urban access restrictions, and fleet turnover steadily remove diesel cars and trucks from the road, while efficiency gains and logistics optimization reduce fuel use even where electrification is slower. Refiners have felt this directly through weaker diesel margins and reduced utilization, especially for facilities optimized around heavy crude slates.

In China, diesel demand grew through the early 2020s but plateaued around 2023 and has since shown signs of decline, driven by a combination of slowing construction activity, industrial electrification, and rapid changes in heavy transport. Battery electric heavy trucks have moved from niche deployments to a material share of new sales in just a few years, supported by falling battery costs, large scale charging and battery swapping networks, and clear policy backing, while battery powered inland vessels are beginning to displace diesel in river transport and short haul shipping. These shifts are already large enough to show up in national fuel statistics, reinforcing that peak diesel in China is not a distant forecast but an emerging reality in the world’s largest heavy transport market. While China has been the biggest buyer of Venezuelan crude, that’s only 4% of China’s consumption, it’s mostly used for diesel, and China’s diesel demand is going away.

In a flat or declining oil market, the highest cost and least flexible barrels, like Venezuela’s are the first to be cut. Heavy crude fits that description. Canada’s oil sands production shares these characteristics. Western Canadian Select is heavy and sour, competing for the same shrinking pool of complex refineries as Venezuelan crude. Differences in governance do not change market outcomes. Canada exports most of its heavy crude, 95% to 97%, to the United States because it lacks sufficient domestic refining capacity. Those exports depend on stable trade relations and long pipeline networks feeding Midwest and Gulf Coast refineries.

Even if Venezuelan crude were to return to the market in greater volumes, it would not meaningfully displace Canadian oil outside a narrow slice of the US Gulf Coast. The largest and most structurally important destination for Canadian crude is the US Midwest, where refineries are directly connected to Alberta by large, dedicated pipeline systems and depend on steady flows of heavy and medium crude that cannot be backfilled from coastal imports. Venezuelan oil arrives by tanker and can only be processed at a limited number of Gulf Coast refineries equipped with deep water ports and deep conversion capacity, with no practical pipeline routes to move that crude north into the Midwest at scale. As a result, any increase in Venezuelan supply would primarily reshuffle which heavy barrels compete for existing Gulf Coast refinery slots, potentially displacing some Canadian volumes there at the margin, but it would not undermine Canada’s dominant position in the Midwest or materially alter continental crude flows. That doesn’t remotely mean Canada’s production has a secure market position, of course.

Trade fragmentation and rising geopolitical tension increase the fragility of this system. Heavy crude depends on long, politically exposed supply chains. Disruptions do not need to be permanent to matter. Uncertainty alone raises costs and lowers utilization. Light crude adapts more easily. Heavy crude does not. Even if Venezuelan exports were fully unlocked, the crude would be geographically trapped. It would land almost exclusively at Gulf Coast refineries with coking capacity. There is no meaningful pathway to move it inland to the Midwest. It would displace other heavy barrels, not expand overall throughput.

In hindsight, the failure of US refiners to pivot toward greater light crude flexibility and petrochemical integration looks like a strategic misstep. At the time, the investments they made were rational responses to the world they saw. Shale persisted longer than expected, demand growth slowed sooner, and trade became more fragmented. Converting refineries is expensive and risky. Closing them is cheaper. The system is shrinking rather than adapting.

Political actions often ignore these realities. Energy decisions are framed around symbolism, confrontation, or short term fiscal advantage for key players rather than crude quality, refinery physics, and capital behavior. That does not change outcomes. It doesn’t matter to crude oil economics that Maduro’s mockery of Trump and dancing have infuriated Trump for years, a strong candidate for why Trump could be talked doing exactly what he said America no longer would do. Venezuela’s oil does not matter at scale because it cannot be brought to market quickly, cheaply, or in the quantities imagined. The United States does not need it. Trump doesn’t understand any of that, and neither do most of the people around him. Likely Chris Wright knows it as an oil and gas professional, but he also knows how to ensure the companies he’s close to will get fiscal advantage from the situation.

Canada’s heavy crude faces the same structural decline. In a world of falling fuel demand, light crudes and petrochemical feedstocks retain value. Heavy crudes are first off the market, not because of politics, but because of how the system actually works.

To go back to the thesis, America’s illegal abduction of the elected ruler and spouse of a foreign country on their sovereign soil will have no impact on decarbonization, Venezuela’s oil flowing again or Canada’s oil continuing to have a market. It’s theater, theater with a side helping of dead civilians and regime change. It will turn into another US quagmire because it was carried out thoughtlessly, rashly and without any thought for the day after. Now, just as in Iraq and Afghanistan, America will be making up how it deals with Venezuela post-Maduro, each day another abject lesson for the history books.