Venezuela’s current role in global oil markets

Venezuela has the largest known crude oil reserves in the world, followed by Saudi Arabia and Iran. Venezuela’s oil production was approximately 0.75-1 million bbl/d in 2025, well below the 1970s level of nearly 4 million bbl/d. We estimate that more than one-fourth of the 2025 production volume was moved by Chevron to its own US Gulf Coast (USGC) operations, and 0.35-0.6 million bbl/d was shipped to mainland China, mainly for independent refiners.

Notably, Venezuelan crude exports are mostly heavy in nature. Sophisticated refiners, mainly in the US, mainland China, and India, process heavy crude to take full advantage of their configurations, maximizing their competitive advantage relative to less complex refineries.

The recent sanctions on Venezuela and Iran targeted heavy barrels, which are increasingly scarce and difficult to replace. The US Gulf Coast and mainland China compete for these barrels because they have the largest deep conversion capacity in the world.

Global supplies of heavy crude have become increasingly constrained in recent years. Historically, the top 3 heavy crude exporters to the US Gulf Coast were Saudi Arabia, Mexico, and Venezuela. Mexican crude production declined significantly, and Saudi Arabia adjusted its upstream production mix toward higher shares of light and medium grades. Other heavy crude producers (Colombia, Ecuador, and Argentina) lack investment or suffer from geological declines.

On 29 January 2026, the US lifted some sanctions on Venezuela, allowing US companies to buy, sell, transport, store, and refine crude oil. However, sanctions on oil production remained in place. Even without these sanctions, Venezuela’s output may rise modestly, but not enough to affect global oil prices in the near term.

Primarily, the US move on Venezuela has had a short-term impact on mainland Chinese refiners who process heavy crude, with restricted flows from Venezuela forcing some to temporarily shift towards medium-quality crudes at lower utilization rates.

In the medium to long term, significant increases in Venezuelan output may feed into deep conversion assets in Asia and the US, potentially reducing consumer product prices. However, massive investment over several years would be required to revive Venezuela’s deteriorated energy infrastructure.  Political, fiscal, and economic stability in the country would be necessary to attract such investment. This is an even harder sell when the global oil market is oversupplied, which was the case when the US intervened in Venezuela. Global economic growth concerns also limit oil demand forecasts. That said, further developments related to the recent escalation between the US and Iran may affect the global outlook enough to influence the investment landscape in Venezuela.

Meanwhile, due to its severely constrained refining system, Venezuela relies on imports of oil products to meet domestic demand. According to the EIA, the country is estimated to be short of approximately 150,000 b/d of oil products. This deficit would have been more significant in 2018-2019 though, as domestic demand plummeted after the pandemic and has not fully recovered.

Venezuela imports naphtha, which is used as a diluent for blending with heavy crude oil, as well as gasoline and diesel. Some unconfirmed reports suggest that these products arrive from either Iran or Russia. A disruption in refined product exports from these countries may open the door for Latin American or US Gulf Coast companies to compete for this market.

Short-term implications of higher Venezuela output

Venezuelan oil production is expected to ramp up slowly, and the impact of added Venezuelan output will likely be modest in the near-term. Additional heavy oil production in the country may displace either Canadian tar sands (similarly heavy volumes) or a broader range of volumes, which OPEC+ would need to accommodate if it wishes to maintain prices. In that context, the heavy-light crude spread would likely widen.

If Venezuelan production increases enough to displace production elsewhere, the reduction in Middle East production would still likely be relatively modest, and the impact on petrochemical feedstock supply would not be significant.

Notably, higher volumes of heavy oil flowing from Venezuela would also require additional naphtha to be blended as a diluent. The diluent naphtha required for blending with heavy Venezuelan crude would likely be sourced primarily from the US. Therefore, if Venezuela’s oil flows are predominantly directed to the US, the balance of “naphtha in, naphtha out” closes within the US itself, without an impact on naphtha markets elsewhere.

However, if increased heavy oil availability from Venezuela results in more heavy oil being processed in Asia, naphtha supply in the region should increase, potentially reducing demand for Middle Eastern feedstocks. Asian refiners may also increasingly shift to Venezuelan crude in the current geopolitical context, to reduce risk through supply diversification beyond the Middle East, also avoiding the Strait of Hormuz via the Atlantic route.

If Asian refineries source greater amounts of Venezuelan oil, there may be some “spare” naphtha supply in the Middle East and increased interest in condensate cracking in the region. Nevertheless, naphtha and condensate exports to Asia are expected to remain economically favorable compared to local conversion for petrochemical exports, especially under current market conditions.

Sustained, significantly higher Venezuela output

In case Venezuela’s crude oil output significantly exceeds current levels and remains elevated in the long term, supply from other sources would be displaced. Additional naphtha might need to be sourced not only from the US but also from other regions, such as the Middle East.

Notably, heavy oil diluent demand in this scenario would be substantial and may require directing condensate and light naphtha away from petrochemicals. Additional naphtha demand to dilute Venezuelan oil could make condensates-based petrochemicals production more difficult to justify from a cost perspective.

If Venezuela significantly increases its heavy oil exports to Asia, Asia will require less petrochemical feedstock imports from the Middle East. Even then, there may still not be an incentive for Middle Eastern petrochemical producers to process the feedstocks that were previously routed to Asia.

Refinery-petrochemical integration has been on the rise in the Middle East as cracking naphtha generates a much broader portfolio than ethylene cracking, including aromatics and propylene. However, if the Asian crude mix becomes heavier, higher naphtha-as-diluent demand in Venezuela coupled with lower light naphtha output in Asia compared with processing lighter crude would imply a tighter global naphtha supply, driving price increases. If this occurs, naphtha-based cracking costs and naphtha-ethane price differentials would both increase, benefiting Middle Eastern ethane-based crackers and improving their competitiveness in the global cost curve. Persisting global overcapacity across most petrochemical commodities would make export-oriented condensate cracking in the Middle East less profitable than directly exporting feedstocks.

Ultimately, we will see a reshuffling of petrochemical feedstock flows. The extent of this reshuffling will depend on the share of heavy crude oil output compared to global total crude output, as well as its geographic origin and refining locations. Diluents ultimately end up where the crude is refined. However, petrochemical feedstock sources could be reorganized, becoming less tied to gas or oil production (e.g. US, Middle East) and more connected to regions hosting the bulk of heavy oil refining operations, such as Asia.

Long-term, given Venezuela’s level of reserves, the scale of its fully realized supply could be very substantial, potentially displacing some Middle Eastern oil production. This could lead to limitations in Middle Eastern oil production and petrochemical feedstock supply, potentially restricting the scope for future investment within the region.

2026 supply shocks could reshape oil markets

As of 13 March, oil markets have yet to see the full impact of multiple supply shocks this year. The US-Iran conflict escalation and resulting heightened tensions affecting key maritime routes such as the Strait of Hormuz, in addition to reduced flows through the Bab el-Mandeb Strait and the Suez Canal since late-2023, are creating worldwide supply chain shocks. This has had a much more visible effect on short-term oil and gas and petrochemical feedstocks markets than the US intervention in Venezuela earlier this year.

So far, the impact of the US-Iran conflict on energy and chemical markets appears largely short-term: logistical constraints around Middle Eastern supply routes have restricted exports with mounting consequences for global oil and gas markets in particular, limiting refining and petrochemical operations locally and globally. If regular export flows resume soon, the impact on global energy markets and petrochemical operations would be short-lived, and typical market conditions would eventually return. However, the effects of such disruptions go well beyond supply chain pressures, including macroeconomic and food security risks. The consequences of the conflict will become more prominent the longer the war lasts, potentially visibly affecting both supply and demand for chemical markets globally.

It would be even more consequential if conflict escalation damages production or export infrastructure in the Middle East. In this scenario, global oil and petrochemical feedstocks supply may experience longer lasting effects, depending on the scale of affected supply. Such long-term implications could go beyond sustained higher energy and chemicals pricing, possibly even influencing investment decisions – not only within the Middle East but also for oil producing countries elsewhere, including Venezuela.