Venezuela can restore heavy crude flows to the U.S. Gulf Coast, but debt, failing infrastructure and political control will keep it from replacing Iranian exports at scale.
The recovery and its limit
In less than two years, Venezuela has moved from sanctions-induced near-pariah status to a central swing producer in Washington’s post-Iran-war energy strategy. Crude output now hovers around 1.1–1.2 million barrels per day (bpd), its highest level since 2019 and roughly 17–20 percent above the 2025 average. Exports have climbed to about 1.16 million bpd, and the United States absorbed close to 800,000 bpd in July 2026, making it Venezuela’s dominant customer and turning a China-centred trade back towards the Gulf Coast. Chevron is the only U.S. supermajor with a large position on the ground, producing roughly 270,000–280,000 bpd through its joint ventures and committing more than 7 billion dollars over five years to raise that volume towards 600,000 bpd, about half of Venezuela’s current national output.
American oil giants can invest in parts of this recovery, but Venezuelan barrels cannot cover the sudden collapse in Iranian exports under the U.S. naval blockade. Iran had rebuilt exports to about 1.5–1.7 million bpd in 2025 and early 2026, almost all of it bound for China, before the renewed blockade cut them by 1.2–1.4 million bpd to a range of 200,000–300,000 bpd. Venezuela has added roughly 700,000–800,000 bpd since 2020, enough to matter in a tight market and yet still short of the lost Iranian supply, while decaying infrastructure, power shortages and an unresolved sovereign and PDVSA debt burden of 150–170 billion dollars constrain further growth. Washington has an opening, but stable capacity will take years and remain exposed to legal and political reversals.
Venezuelan production in 2026
After collapsing to about 392,000 bpd at the nadir of the 2020 crisis, Venezuelan crude production has climbed steadily, with OPEC secondary sources and commercial trackers placing mid‑2026 output around 1.1–1.2 million bpd. Trading Economics, using OPEC data, reports 1.2 million bpd in July 2026, up from 1.187 million bpd in June and far above the 2025 average of roughly 941,000 bpd. The Oxford Institute for Energy Studies notes that quarterly production rose from about 943,000 bpd in the fourth quarter of 2025 to 1.059 million bpd in the second quarter of 2026, a 12.3 percent increase that put Venezuela at roughly 4 percent of total OPEC crude output and about 1 percent of world supply.
Ship-tracking data cited by Reuters show that production reached around 1.18 million bpd in May 2026, the highest level in seven years, before moving within a 1.0–1.2 million bpd band through mid-year. Caracas claims higher numbers, with officials citing 1.23–1.25 million bpd and setting a target of 1.37 million bpd by the end of 2026, but those figures come from PDVSA rather than transparent field-level data. Inventories, condensate accounting and temporary withdrawals from storage can inflate monthly figures. Venezuela has doubled production from the 2020 trough and yet still produces less than half the 2.3–2.5 million bpd it achieved in the mid-2000s.
The U.S. pivot back to Venezuelan crude
Export destinations have shifted faster than production. Venezuelan exports averaged around 1.16–1.2 million bpd from May through July 2026, modestly exceeding production as PDVSA drained storage and floating inventories built during the sanctions years. Roughly two-thirds of those barrels now head to the United States. Reuters reported that U.S.-bound exports rose from 284,000 bpd in January to about 786,000 bpd in July, their highest level since early 2019. Weekly U.S. Energy Information Administration data put imports at 743,000 bpd in early August, after several weeks between 660,000 and 740,000 bpd. Taken together, EIA data and company disclosures place U.S. imports at 65–70 percent of Venezuela’s production and the vast majority of its exports.
The shift relieves U.S. Gulf Coast refiners. Many complex refineries in Texas and Louisiana were built to process heavy, high-sulphur grades from Venezuela and Mexico, using coking and hydrocracking units to convert low-value residual fuel into diesel and petrol. The Trump administration’s 2019 sanctions on PDVSA forced them towards Canadian heavy crude, Colombian and Mexican barrels, and medium-sour grades that could approximate Venezuelan Merey 16. The closure of the Strait of Hormuz during the Iran war then cut significant volumes from Saudi Arabia, Iraq and Kuwait. Discounted Venezuelan heavy crude restores 700,000–800,000 bpd of a feedstock these refineries already know how to process.
The 303-billion-barrel constraint
Venezuela’s appeal begins with its geology. OPEC puts its proven crude oil reserves at roughly 303 billion barrels, about 17 percent of the global total and more than five times U.S. reserves. Most lie in the Orinoco Belt, a 55,000-square-kilometre strip in eastern Venezuela containing extra-heavy crude with American Petroleum Institute (API) gravity typically between 8 and 14 degrees and a sulphur content of 4–5 percent, similar to Canada’s oil sands. U.S. Geological Survey assessments put the belt’s oil in place at 900–1,400 billion barrels and estimate that existing technology could recover 380–650 billion barrels, although price-dependent reserve accounting classifies only a fraction as proved.
Investors care about the distance between proved reserves on a statistical table and bankable reserves that can be produced under Venezuela’s fiscal, legal and infrastructure constraints. Most of the 303 billion barrels are heavy or extra-heavy crude. Their production requires capital-intensive wells, steam injection or other enhanced recovery, a continuous supply of diluent and upgrading capacity, and the oil trades at a discount of 7–10 dollars per barrel to benchmarks such as West Texas Intermediate. Rystad’s 2020 cost curves put Orinoco project breakevens at around 49 dollars per barrel, above many conventional fields but viable when oil trades between 70 and 90 dollars. Institutions and capital set the production ceiling.
The limits of a quick ramp-up
The recovery to roughly 1.1–1.2 million bpd has come largely from reactivating existing fields, repairing surface facilities, arranging diluent imports and swaps, and making incremental investments in joint ventures with Chevron, Repsol and smaller independent producers. The project pipeline contains at least 16 active oil developments, most of them brownfield and with the largest by value controlled by PDVSA. Venezuela has reservoirs and yet its degraded power grid, pipelines, ports and skilled workforce limit how much oil can reach a tanker.
Restoring production to its historical level of around 3 million bpd would require 100–250 billion dollars of investment and at least a decade of rehabilitation, according to scenarios developed by KAPSARC and Rystad and cited by BloombergNEF. Those studies estimate that production would struggle to exceed 1.5 million bpd by 2030 even if Washington lifted every sanction, with further gains dependent on greenfield development and heavy-oil upgrading infrastructure. The Texas Tribune, citing Enverus modelling, reported that production could plateau around 1.15 million bpd by 2027 without much larger capital inflows, pushing the next substantial increase into the early 2030s. The cheaper gains available since 2022 are nearing exhaustion while structural capacity has barely expanded.
PDVSA’s debt overhang
Venezuela and PDVSA defaulted on their external bonds in late 2017 and remain in arrears. Their external liabilities total 150–170 billion dollars: roughly 60 billion dollars in defaulted sovereign and PDVSA bonds, about 25 billion dollars in accumulated interest, 15–25 billion dollars in bilateral loans led by China and Russia, arbitration awards worth around 20 billion dollars, and supplier and infrastructure claims. IMF estimates put those obligations at roughly 180–200 percent of Venezuela’s 2025 GDP, the highest sovereign debt burden in Latin America by that measure.
In May 2026, the transitional government launched what it called a “formal, integral and ordered” restructuring of sovereign and PDVSA debt. It hired Centerview Partners as financial adviser and Hogan Lovells as legal counsel, then told creditors it would present a macroeconomic and debt-sustainability framework. The U.S. Treasury issued a licence permitting the advisory work without lifting sanctions, while the IMF and World Bank resumed engagement after seven years. With liabilities equal to 180–200 percent of GDP, a sustainable settlement would require a principal haircut of at least 50 percent, longer maturities and exit yields in the low double digits, leaving PDVSA with less operating cash for capital expenditure.
PDVSA would serve as the majors’ joint-venture partner while its future cash flows remain exposed to bondholders and holders of arbitration awards. Citgo and other overseas assets already sit behind a queue of claimants, including ConocoPhillips and ExxonMobil, which secured multibillion-dollar ICSID and ICC awards over the 2007 expropriations. New investment could improve PDVSA’s cash generation and yet immediately revive disputes over which creditor has the right to seize it.
ExxonMobil, ConocoPhillips and the cost of expropriation
Hugo Chávez’s 2007 nationalisation still governs the investment decision. ConocoPhillips obtained an ICSID award of about 8.7 billion dollars in 2019 for the expropriation of its Petrozuata and Hamaca heavy-oil projects and the offshore Corocoro field. Venezuela failed to annul the award in January 2025, and annual interest of 5.5 percent has pushed the liability above 11 billion dollars. Courts in the United States and other jurisdictions have recognised the award, while enforcement proceedings led to the auction of PDV Holding, Citgo’s parent, with ConocoPhillips among the senior creditors entitled to the proceeds.
ExxonMobil’s dispute over the Cerro Negro project followed a similar course. An ICSID tribunal awarded the company about 1.6 billion dollars in 2014, and a partial annulment and subsequent payments still left 1.3–1.6 billion dollars outstanding. Both companies have pursued enforcement in several jurisdictions and treated Venezuelan-linked assets as sources of recovery. The losses were substantial, and the decade spent chasing payment told U.S. majors what a Venezuelan contract could be worth after politics intervened.
The 2026 political transition and the Trump administration’s oil framework try to contain that legacy. Executive actions have placed Venezuelan oil revenue under U.S. supervision, routed proceeds into U.S.-controlled accounts and signalled that some of the money will satisfy American companies’ claims. New production-sharing agreements and joint ventures carry stronger protections and arbitration clauses and are being sold as legally separate from the expropriated projects. Investors will test those protections with small commitments long before they treat Venezuela as a normal jurisdiction.
The Trump-Venezuela deal
In August 2026, President Trump announced what he framed as an extraordinary agreement granting U.S. interests majority control over more than 65 billion barrels of Venezuelan proven reserves across 17 fields in the Orinoco Belt and Lake Maracaibo. Under the announced terms, a new private operator, North American Blue Energy Partners, will hold 100-year concessions over those fields, with an effective U.S. stake of 55 percent through equity and purchase rights. Venezuela projects that the arrangement could attract around 100 billion dollars in private investment and generate more than 200 billion dollars in tax revenue over time. Analysts at 24/7 Wall St. calculate that if U.S. companies can effectively access those reserves, U.S.-controlled proven reserves would rise to about 111 billion barrels, or 7.1 percent of the global total, placing the United States alongside the United Arab Emirates.
Chevron plans to invest more than 7 billion dollars through its existing joint ventures and expand into additional Orinoco acreage. The company currently produces around 270,000–280,000 bpd in Venezuela and, according to its chief financial officer and public releases, targets roughly 420,000 bpd by 2028 and about 600,000 bpd within five years. If realised, that expansion would make Venezuela one of Chevron’s largest upstream positions and anchor the wider U.S.-Venezuela energy relationship.
Other American majors would receive privileged access to low-cost heavy barrels that can be blended with U.S. light shale crude into exportable medium-sour grades similar to Russia’s Urals and sold to European refiners replacing Russian supply. They would also accept a 100-year concession negotiated after a military-backed change of government, with the Pentagon reportedly receiving a share of the profits. The oil may be commercially useful, and yet no board can pretend that such an arrangement is insulated from the next election or diplomatic rupture.
The economics of Venezuelan heavy crude
Venezuelan heavy crude fits the requirements of U.S. Gulf Coast refineries. Rystad describes Merey 16, one of Venezuela’s benchmark blends, as an extra-heavy, high-sulphur grade that yields a medium-sour blend close to Russian Urals when mixed with about 60 percent U.S. light shale crude. The resulting oil has API gravity of around 31–32 degrees and sulphur content near 1.5 percent. U.S. producers can therefore combine a domestic surplus of light oil with imported Venezuelan heavy crude and sell the blend to American and European refineries that previously relied on Russian and Middle Eastern grades.
Heavy crude trades at a discount to light benchmarks. BloombergNEF’s analysis puts unblended Venezuelan heavy about 7–10 dollars per barrel below WTI because it costs more to transport and upgrade. U.S. refiners have already paid for coking and desulphurisation units, so the discount gives them an advantage on feedstock and lets them capture the spread between the cheaper input and global prices for refined products. Majors must compare that return with the capital cost, legal risk and ESG scrutiny of heavy-oil projects in a fragile state, as well as competing investments in U.S. shale, Guyana, Brazil and LNG.
The cost and timing estimates rule out a quick windfall. A Rystad scenario cited by the Guardian put the cost of returning production to 3 million bpd at around 185 billion dollars over 16 years, including 30–35 billion dollars during the next two to three years. KAPSARC’s modelling indicates that even the removal of all sanctions might raise Venezuelan production to only about 1.5 million bpd by 2030. A supermajor’s portfolio committee must therefore weigh a long, politically exposed project against shorter-cycle shale and deep-water investments elsewhere.
The Iranian shortfall
Iran and Venezuela entered 2026 with different production profiles and different customers. Before the current war and blockade, Iran had rebuilt crude and condensate exports to roughly 1.5–1.7 million bpd, with nearly every barrel sold to China at a discount. U.S. Energy Information Administration estimates put Iran’s 2025 export revenue at around 48 billion dollars, based on average volumes of about 1.58 million bpd, of which 99 percent went to China.
The naval blockade and renewed sanctions campaign that began in spring 2026 broke that equilibrium. By May, Vortexa and Kpler reported that Iranian crude exports had fallen to roughly 200,000–300,000 bpd, their lowest level in six years and 70–80 percent below early-year volumes. August loadings of around 220,000–260,000 bpd were more than 80 percent below August 2025, when Iran exported around 1.7 million bpd. The blockade has removed between 1.2 and 1.4 million bpd of Iranian crude from the seaborne market.
Venezuela’s recovery from roughly 392,000 bpd in 2020 to about 1.1–1.2 million bpd in 2026 has added around 700,000–800,000 bpd. A shift of 1–2 percent in supply can move prices, so those barrels matter, and yet they cannot replace pre-war Iranian exports one for one, especially when some have been redirected from China and India instead of added to global supply. Iranian grades also differ in quality, destination and price, which prevents many refineries and trade routes from treating Venezuelan heavy crude as a direct substitute.
A 2023 KAPSARC study modelled the removal of sanctions on both countries and found that Venezuelan production would remain constrained even under optimistic assumptions, while Iran’s latent capacity and lighter grades could reach the market more quickly. Tighter sanctions have widened that asymmetry. Iran has lost export volumes that no producer can recreate quickly, while Venezuela’s infrastructure and capital shortage limit its gains. More Venezuelan oil reaching the United States and fewer Iranian barrels reaching China can soften the imbalance, but the volumes, grades and destinations do not match.
OPEC and China
Venezuela’s shift is taking place as OPEC+ loses market share and room to respond. Reuters estimated that the group produced about 40 percent of the world’s oil in July 2026, down from more than 48 percent before the Iran war, after the United Arab Emirates left OPEC and the war and the Hormuz closure disrupted other producers. Attacks on infrastructure and shipping routes have also reduced spare capacity. Venezuela and Iran therefore exert more influence on marginal prices than their production totals suggest.
China absorbed almost all Iranian exports and much of Venezuela’s sanctioned crude. EIA and trade-monitoring data put China’s share at about 99 percent of Iran’s exports in 2025 and 69 percent of Venezuela’s in 2023. Chinese purchases of Venezuelan crude have since fallen as Washington took control of Venezuelan marketing channels, while the blockade cut Iranian deliveries. China bought about 400 million fewer barrels in 2026 than during the same period a year earlier as domestic demand, refinery runs and product exports adjusted, giving Washington more room to redirect Venezuelan oil to the United States and Europe without provoking an even larger price increase.
Political risk
Venezuela remains politically dangerous for long-term capital. The transitional government under acting president Delcy Rodríguez took office after U.S. forces captured Nicolás Maduro in January 2026, an event that defines every subsequent argument about sovereignty and stability. The government then announced its debt restructuring without committing to the IMF programme that the Fund has said would be necessary for substantial financing. Oil companies are being asked to commit capital across decades while the domestic government, the creditor settlement and Washington’s conditions remain unsettled.
U.S. policy has moved from broad sanctions to a dense mix of licences, tariffs and security arrangements. A 25 percent tariff threat introduced in 2025 against imports from countries buying Venezuelan oil without U.S. approval remains under legal challenge. OFAC’s general licences for Chevron have swung between wind-down orders and expansion, while the latest version narrowly defines approved counterparties, payment channels and export destinations. American companies enjoy privileged access through executive discretion rather than a durable statute, so every investment decision is also a bet on political continuity in Washington.
What U.S. majors can invest in
Chevron supplies the clearest test of investibility. It operated continuously in Venezuela through sanctions, maintained its relationship with PDVSA, secured tailored OFAC licences and has now committed several billion dollars to expansion. Chevron knows the reservoirs and infrastructure, has sunk capital in the Orinoco Belt, borrows cheaply and can balance a long-dated heavy-oil project against shorter-cycle U.S. shale elsewhere in its portfolio. If the company raises production to 400,000–600,000 bpd at acceptable returns, it will show that a U.S. major can make money under the new regime.
ExxonMobil and ConocoPhillips are still litigating or enforcing awards from the last expropriation. Their boards would have to explain why shareholders should finance a jurisdiction in which earlier investments remain unpaid and exposed to political interference. European majors face additional regulatory and reputational scrutiny over heavy oil, while independents and private equity-backed operators may accept niche projects in the lighter-oil basins of western Venezuela. Whatever their size, every operator must still contend with failing infrastructure, unstable power and competing claims on PDVSA revenue.
Short-cycle, OFAC-licensed brownfield projects can ring-fence revenue and seek recourse in U.S. courts; Chevron’s current programme largely fits that model. Greenfield heavy-oil developments require new upgraders, pipelines and power plants, then remain exposed for decades to domestic politics, OPEC policy and climate regulation. The present opening can support the brownfield work, and yet greenfield investment will wait for Venezuela to establish a durable fiscal and legal regime, conclude a credible debt restructuring and honour its treatment of foreign capital across a change of government.
A partial substitute
Policy advocates in Washington present Venezuelan barrels as a near-term answer to the shutdown of Iranian exports and the wider Hormuz disruption. The volumes allow only a partial offset. Sanctions and the blockade have removed around 1.2–1.4 million bpd of Iranian crude from global export channels since early 2026, with most of the loss concentrated in China’s import portfolio. Venezuela has added around 700,000–800,000 bpd since its 2020 trough, and the Trump-Venezuela deal and Chevron’s expansion could add another 300,000–500,000 bpd during the next five to seven years if the investment arrives and the political terms survive.
The replacement would also alter the quality and destination of supply. Discounted Iranian crude sustained a distinct group of Chinese refining and petrochemical operations, and switching those plants to Russian or Venezuelan grades carries logistical and commercial costs. Venezuelan heavy crude sent to the U.S. Gulf Coast can ease feedstock pressure on American refiners and help finance Venezuela’s reconstruction, and yet it adds little supply for price-sensitive importers in South Asia or Africa. Venezuelan heavy reaches a Gulf Coast coker while the Chinese refinery that lost Iranian crude still needs another feedstock.
The tests ahead
The first test is whether national production can break out of the current 1.1–1.2 million bpd band and hold 1.4–1.5 million bpd without overwhelming the power grid and export infrastructure. Chevron’s joint ventures supply a second measure: actual output must match the company’s target of 50 percent growth by 2028 and approach 600,000 bpd over the longer term. Field results will settle the comparison with the promises made at investor conferences.
The financial test lies in the terms offered to bondholders and arbitration creditors, the IMF’s role, and the treatment of PDVSA cash flows and collateral. New hydrocarbon laws, model contracts and dispute-resolution mechanisms must then survive an electoral cycle. OFAC licences, tariffs and Washington’s posture through the 2028 election will determine whether American access remains a policy choice or becomes a durable framework, while any easing of the Iranian blockade or reopening of Hormuz would change the market before Venezuelan greenfield projects pump their first barrel.