Venezuela in the Headlines (Part 2): How Much Venezuelan Oil Can Really Return in the Short Term?

Trump’s seizure of President Nicolás Maduro has sparked expectations of a rapid revival in Venezuelan oil output. Some analysts are calling this a new “remote‑control” era of Venezuelan governance, where Washington’s leverage over licenses and sanctions, rather than Caracas’ policy ambitions, sets the pace of any oil recovery. In our first article in this three‑part series, we used historical perspective to ground the current headlines. This second article examines likely near-term outcomes for oil markets following Maduro’s removal. These will be shaped less by geology and more by U.S. sanctions policy, investor risk appetite, and the time it takes to stabilize diluent supply and repair critical infrastructure, all starting from today’s roughly 1.0 million barrels per day (b/d) of crude production and constrained refining capacity. In short, the next three years are more likely to bring incremental, uneven change than a flood of new barrels.

What changes (and what does not) in three years

Analysts now see Venezuela’s 2026 oil production holding roughly flat around 1.0 million b/d under current policy, with only modest upside in 2027-28 unless sanctions are relaxed further and new capital flows into upstream and midstream assets.

In that context, the Trump administration’s intervention is unlikely to double Venezuelan output within three years, despite public claims of an 18-month “revolution” in production. Instead, realistic short-term changes look like:

• 2026: A potential increase from 1 to 1.3 million b/d as idled capacity and shut-in wells are carefully restarted and bottlenecks are cleared, provided sanctions carve-outs are broad enough to support sustained activity.
• 2027-2028: Gradual normalization of export programs to the U.S. Gulf Coast and China, with total exports oscillating around or modestly above the 1.5 million b/d range seen in 2025, rather than a step-change to pre-Chávez levels of 3.5 million b/d.

With current global crude oil demand at approximately 104 million b/d, the modest gains in Venezuela production are unlikely to move the consensus outlooks for Brent in the mid-$50 to low $60 per barrel in 2026. Venezuela’s short-term contribution as too small and uncertain to materially shift price decks, though heavier grades could see localized pressure if Venezuelan supply to Asia and the U.S. grows faster than expected.

Sanctions, “quarantine,” and U.S. refiner exposure

Goldman Sachs and others emphasize that Venezuela’s output path in 2026-2028 “will depend on how U.S. sanctions policy evolves,” with ambiguous but modest short-run risks to global prices. President Trump and Secretary of State Rubio have signaled that Washington will maintain a “quarantine” oil embargo to pressure remaining Venezuelan leaders, even as U.S. firms are invited to plan a return.

In practical terms for U.S. refiners:

• Existing Chevron-linked flows to U.S. refineries (roughly 100,000-150,000 b/d in late 2025) are likely to continue or expand modestly under specific licenses, benefiting complex Gulf Coast refineries configured for heavy sour slates.
• Any broader opening for other U.S. refineries could still be constrained by U.S. Treasury Office of Foreign Assets Control (OFAC) licensing, and corporate governance concerns. Therefore, it’s reasonable to anticipate phased entry over the next few years back to the 500,000 b/d levels prior to the U.S. sanctions.
• If Venezuelan heavy crude is diverted from Asia to the U.S. Gulf in the 500,000 b/d range, the incremental flow of Canadian Heavy out of Vancouver, Canada could switch from the U.S. Gulf to Asian markets. This could impact pricing parity for Canadian Heavy barrels and broaden their discount to WTI.

Short-term realities on the ground in Venezuela

From the field perspective, the next three years will likely be dominated by operational triage rather than greenfield growth. PDVSA has ordered shut-ins because onshore storage and floating tanks were full, and heavy-oil wells in the Orinoco Belt do not restart as easily as light-tight wells in the Permian; unsystematic shut-ins can permanently damage production potential. In fact, some of the apparent early‑2026 rebound in Venezuelan exports reflects the rerouting of tens of millions of barrels in floating or onshore storage (barrels previously moving through opaque channels toward China) rather than a step‑change in new production.

Key short-term constraints include:

• Infrastructure and upgraders. Critical upgraders and refineries have been damaged by fires, corrosion, and lack of maintenance, reducing Venezuela’s ability to turn extra-heavy crude into exportable synthetic crude or finished fuels; rebuilding such units is a multi-year exercise, not a three-year quick fix.​
• Human capital and safety. The engineers, operators, and managers who once made PDVSA an efficient operator now largely live abroad, and potential investors worry about employee safety, given past kidnappings, detentions of foreign oil executives, their families, and ongoing security concerns.

Expert assessments of Venezuela’s dilapidated upstream, upgrading, and midstream systems suggest that returning to former peak output would likely require on the order of a decade of relative stability and many tens of billions of dollars of capital, far beyond the 2026-2028 horizon. In this environment, even with a friendlier posture from Washington toward U.S. oil companies, most operators will likely spend the next few years assessing and investing in small-scale debottlenecking or integrity projects while starting the front-end engineering for larger projects.  Larger investments committing to multi-billion-dollar upgraders or full-field redevelopments will require political certainty, stable safe environments for international employees, and a change in crude oil market fundamentals to provide economic returns.

Diluent and naphtha: the hidden short-term lever

Because so much of Venezuela’s exportable crude slate is ultra-heavy Orinoco oil, near-term export volumes depend heavily on naphtha and other diluents.

Over the next three years:

• If U.S. sanctions loosen selectively, Gulf Coast suppliers can increase naphtha shipments, enabling more Orinoco crude to be blended and exported; in effect, short-term volumes are bounded as much by diluent availability as by reservoir capacity.​
• If Washington keeps the sanctions tight or re-tightens after initial license grants, Venezuela will likely lean more on Russia and China for diluent, but those suppliers face their own logistical and sanctions-risk constraints, likely capping growth.

In practice, how additional Venezuelan crude impacts naphtha balances depends on where the diluent comes from and where the crude ultimately runs. The outcomes are more nuanced than a simple “more Venezuelan barrels equals tighter naphtha.”

• First, the most probable outcome is a U.S. Gulf diluent loop in which naphtha is sourced from the U.S. Gulf Coast and the resulting diluted crude is also processed in U.S. Gulf refineries; in that case, the initial naphtha movement to Venezuela is largely offset by higher naphtha yields when the crude returns, so net regional supply/demand balance is close to neutral.
• Second, a possible but less likely outcome is that naphtha is sourced from the U.S. Gulf while the diluted crude is exported and refined in Asia; here, the naphtha sent as diluent reduces the U.S. Gulf naphtha surplus that would otherwise be exported directly to Asia, and Asian petrochemical demand is effectively backfilled by the diluent embedded in arriving Venezuelan crude rather than separate naphtha cargoes.
• Third, and least likely under the current political climate, is a scenario where Venezuela leans more heavily on internationally sourced diluent (for example Russian or Chinese naphtha); that configuration would tend to increase naphtha length in the refining centers that receive the Venezuelan crude, because the diluent volumes are “imported” from elsewhere rather than drawn down from local surplus.

Taken together, these options suggest that while trade flows and grade differentials could shift, petrochemical feedstock pricing on the U.S. Gulf Coast is unlikely to see a dramatic structural move solely because of additional Venezuelan crude and associated naphtha logistics. The effect is more about where naphtha is moving and how it is packaged (as standalone product versus diluent in crude) than about a step-change in global naphtha tightness.

What this means for Stillwater’s clients

For producers, refiners, traders, and investors, the next three years in Venezuela are about positioning rather than betting on a rapid return to 3+ million b/d. The key short-term questions are: which refiners secure access to incremental Venezuelan heavy barrels; how sanctions and licenses evolve; how diluent logistics are reconfigured; and how much capital large U.S. and international oil companies are willing to risk under a still-fluid political and legal framework.

Stillwater Associates helps clients navigate these uncertainties with asset-level and trade-flow analysis, including:

• Evaluating near-term impacts on individual refineries feed slates and optimization plans. particularly in the U.S. Gulf Coast and heavy-sour-configured plants elsewhere.
• Assessing diluent, naphtha, and product-import dynamics under different sanctions and investment scenarios.​
• Stress-testing crude-slate and pricing assumptions for the 2026-2028 planning window as Venezuelan policy and U.S. strategy evolve.

Organizations that need to understand how Venezuela’s short-term trajectory could affect their supply security, margins, and capital decisions are encouraged to contact Stillwater Associates to explore tailored consulting support on these rapidly developing issues.​