In response to the US military operation in Venezuela and the capture of Nicolas Maduro, we are sharing a special deep-dive analysis on what it would take to lift the country’s oil output back to 3 million bpd. Please read the full report below.
Authors:
Artem Abramov, Head of Oil and Gas Research
Aditya Ravi, SVP, Oil and Gas Research
Radhika Bansal, VP, Oil and Gas Research
Here is Rystad Energy’s special market update:
Much has been said in the last 48 hours about the short-term oil market implications of the US military operation that led to the capture of Nicolas Maduro, former leader of Venezuela. With US President Donald Trump setting out a vision of American oil companies investing billions to revive the Venezuelan oil industry, we turn our attention to a comprehensive ‘what if’ analysis to understand the potential investment that would be needed to bring Venezuelan oil production back to 3 million barrels per day (bpd), a level the country last achieved in the late 1990s.
Rystad Energy believes that around $53 billion of oil and gas upstream and infrastructure investment is needed over the next 15 years just to keep Venezuela’s crude oil production flat at 1.1 million bpd. Moreover, we estimate that only 300,000 bpd of additional supply can be restored within the next 2-3 years with limited incremental spending. Going beyond 1.4 million bpd level is possible but would require a stable investment of $8-9 billion per year from 2026 to 2040, on top of ‘hold-flat’ capital requirements. Venezuelan crude oil production could then recover to 2 million bpd by 2032 and to 3 million bpd by 2040. While 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. 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.
Historical context and where the industry stands today
The last fifty years of Venezuela’s oil history have been anything but plain sailing. In the period after the Second World War, the country established itself as one of the largest oil exporters ‒ at some points, the largest ‒ with crude oil production peaking at around 3.5 million bpd in 1970. The oil crisis of 1973 immediately shaved 1 million bpd off supply and set the scene for the first round of oil industry nationalization and the creation of Petróleos de Venezuela S.A. (PDVSA) in 1976 under the presidency of Carlos Andres Perez. In the first two decades of PDVSA’s existence, the company developed healthy business relationships with western majors, and with international investment was able to rebuild production to a peak just north of 3 million bpd in the late 1990s.
At the same time, Venezuela was facing gradual deterioration of commodity market fundamentals and a rapid increase in economic inequality, accompanied by the loss of public confidence in its political system. These developments provided solid ground for leftist Hugo Chavez’s success in presidential elections of 1998. While the first few years of Chavez presidency were largely business as usual for domestic oil operations, in 2006 he issued a decree requiring all foreign companies to convert their projects in the Orinoco belt to give PDVSA an ownership share of at least 60%. Chevron was one of the very few companies to accept the new terms and maintained its activity in the country as a minority operator throughout the Chavez and Maduro presidencies. TotalEnergies and Equinor initially accepted the terms on their Petrocedeno operations but exited in 2021. ExxonMobil and ConocoPhillips, significant operators in Venezuela when the decree was issued, both refused the new terms, leading to the seizure and nationalization of their assets. The companies were successful in international arbitration cases but have never been compensated by the Venezuelan state.
A combination of oil market downturns in 2015-2016 and 2020, combined with US sanctions, sent Venezuela’s oil production into freefall, reaching a bottom of around 580,000 bpd in 2020. Production has climbed back slowly since 2021 and surpassed 1 million bpd last year, though a new round of US sanctions and a blockade reversed the trend towards the end of the year. A declining outlook for 2026-2030, even prior to the US military operation, has been largely reinstated as a market consensus.
Venezuela today is known for its heavy and sour crude grades, with API<22 accounting for nearly 70% of total supply. This includes most of Chevron’s roughly 150,000 bpd operations in the country and nearly all volumes produced in the Orinoco Belt. In the 1990s and early 2000s, heavy grades accounted for only 30-40% of supply. Heavy grades are of particular relevance for the US Gulf and selected Chinese refineries, which has lent Venezuela’s heavy oil supply some resilience amid sanctions and the recent market downturn.
Historical investment
Using the data from our global upstream database, UCube, we analyzed historical oil and gas project capex in 2025 in real US dollar terms. Unsurprisingly, as production experienced significant swings, investment was also volatile over the last 50 years. The most striking observation is that as little as $81 billion of cumulative capex ‒ about $4 billion per year ‒ was sufficient in the 1980-1999 period to push crude production from 1.5 million bpd to more than 3 million bpd. As ‘hold-flat’ capital requirements grew and service costs experienced significant inflation, twice as much, or between $7 billion and $8 billion per year, was needed in 2000-2014 to maintain the 3 million bpd level. To be precise, true ‘hold-flat’ capital requirements were closer to $6 billion per year in that period, but there was non-negligible exploration and development spending that never paid off and was effectively written off after the adoption of the Venezuelan Organic Hydrocarbons Law in 2009.
Investment collapsed after the Covid-19 downturn and start of the sanctions period to an average $1.6 billion per year in 2020-2024. The modest production recovery since 2021 was mainly delivered by creative workover and low-cost flow management strategies, which became possible thanks to the unnaturally steep production decline of 2014-2020, which left some room for the reactivation of shut-in volumes. Nevertheless, this strategy is not sustainable in the long term, and we estimate that more than $65 billion of investment in aging infrastructure alone is in order if the country hopes to return to 3 million bpd in production. 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.
What it will take to return to 3 million bpd
Rystad Energy’s base case scenario from December 2025 assumes continuous sanctions and blockade. In this status quo environment, Venezuela’s crude oil production is set to decline gradually from 1.1 million bpd currently to 700,000 bpd in 2040. While we maintain our base case call for now, we may consider another scenario in which international oil companies develop full confidence in a stable investment climate and are offered reasonable incentives to commit capital to Venezuela’s oil sector. In the current market environment, it is hard to imagine what kind of measures could trigger this ‘full confidence’ sentiment, but a complete revamp of local governance and legal frameworks in Venezuela, accompanied by US government guarantees and support, along with a potential restructuring of PDVSA and changes to the Organic Hydrocarbon Law, will be necessary to trigger initial interest. Even then, it remains unclear how further geopolitical risk and the ongoing ExxonMobil and ConocoPhillips legal disputes would influence investment appetite. Nevertheless, there is a realistic technical pathway towards 3 million bpd supply level, hereafter referenced as the ‘Back to 3 million bpd’ scenario.
Based on our assessment and expected project timelines, it could take around 15 years to get back to 3 million bpd, so production can return to late 1990s levels by 2040 if the new investment cycle starts as early as 2026. We estimate that up to 300,000-350,000 bpd can be restored within less than three years, but more significant investment with longer lead times is needed to grow beyond 1.4 million bpd. In our Back to 3 million bpd scenario, Venezuela reaches output of 2 million bpd in 2032 and 3 million bpd in 2040.
Using our project-level cost data from the UCube database, sequencing investment decisions by project economics and simplicity of execution, and including estimated midstream, upgrader, and other non-upstream facility spending, we conclude that the amount of capital needed for the Back to 3 million bpd scenario is enormous. First, we note that despite the opex-heavy nature of Venezuelan heavy oil projects, our base case, where production declines by more than 300,000 bpd in the next 15 years, still requires $36 billion of cumulative oil and gas investment in 2026-2040, or $2.4 billion per year, which we believe can be organically financed by PDVSA. To maintain production at 1.1 million bpd, $17 billion of additional capex is needed in the next 15 years. Rosneft’s recently approved Boqueron and Perija 15-year extensions, with 27,000 bpd per $1 billion brownfield investment spread over 15 years, is a representative benchmark project in this group in terms of cost, although the group average is closer to 23,500 bpd per $1 billion over a 15-year period.
There is an opportunity to bring production back to 1.4 million bpd in less than 24 months through a combination of workovers, infrastructure repair, and selected short-cycle upstream investment. The total capex to unlock this rebound is estimated at $14 billion, with some additional incremental opex spending needed. The industry can extract an additional 250,000-300,000 bpd from existing wells with limited capex-free or low-capex interventions, with the most economic re-drills in areas where little infrastructure repair is needed.
Exceeding 1.4 million bpd will be significantly more challenging and can be split into two phases. We estimate that an additional $41 billion investment is needed to bring crude oil production from 1.4 million to 2 million bpd in the early 2030s and maintain it at that level until 2040. To put this sum in perspective, note that Chevron estimated $2.39 billion in capex would be required over 15 years to increase its Petropiar operations with PDVSA from 110,000 bpd to 150,000 bpd. This expansion project is in fact included in our 2 million bpd by the early 2030s group, despite the more conservative timeline Chevron originally planned amid favorable estimated project economics. If every project from this group was similar to the Petropiar expansion, it would bring the investment required for 1.4 million bpd to 2 million bpd to $36 billion, versus the $41 billion actually required in our estimate. The disconnect between the Petropiar expansion cost and an average project included in this group is driven by the expansion versus greenfield nature of investment (Chevron’s $2.39 billion also covers brownfield investment to offset declines on the original project). The well-maintained infrastructure at Petropiarcontrasts with the repair and modification spend needed to get the rest of Venezuela’s oil industry into growth mode. In other words, Chevron’s Petropiar expansion is adding only 16,700 bpd per $1 billion capex over a 15-year period because investment is spread across the expansion and original phases. Other projects in this group add a similar volume per $1 billion capex because they are significantly more exposed to the areas where pipeline and upgrader repair and rebuilding is needed, adding overhead to upstream capital.
Going beyond 2 million bpd in the 2030s will be even more challenging. We estimate that a staggering $75 billion in additional investments is needed to bring production from 2 million bpd in the early 2030s to 3 million bpd in 2040. There is an additional layer of complexity, as we estimate that with current technologies and service cost levels, around 60% of this investment, or $44 billion, is associated with projects requiring stable market conditions with oil prices above $80 per barrel. With the current global crude market fundamentals, resilient US shale, ample spare OPEC capacity, and robust growth from Guyana and other regions, there is very little room for 2 million bpd of additional capacity from Venezuela until the second half of the 2030s. A more realistic 15-year ceiling for Venezuela oil supply probably lies in the 2-2.5 million bpd range, but potential remains for a longer-term 3 million bpd recovery. Moreover, there is a possibility that the general learning curve and access to modern technology might reduce breakeven prices of these high-cost opportunities in future.
Summing up all these numbers, we end up with $183 billion of oil and gas investment needed over a 15-year period, or $12 billion per year, to bring Venezuela’s crude oil production back to 3 million bpd by 2040. $183 billion is roughly equivalent to one year of North America land upstream oil and gas capex at the current run-rate. The total required capex can be broken into $102 billion of upstream spending and $81 billion for pipelines, upgraders, and other infrastructure. We note that the latter exceeds PDVSA’s own estimate of $58 billion from 2019, mainly due to changes in the USD value between 2019 and 2025, our expectation of additional repair needs emerging towards the second half of the forecast period, and typical capex overruns.
Even if we assume that PDVSA and the national budget can finance maintenance spending of $53 billion, the 2 million bpd growth target would still require some $130 billion, or $8-9 billion per year, of additional investment. In order to make the scenario a possibility, at least 25% of this amount, or around $30-35 billion, would have to be committed in the first two years of the 15-year cycle. This could only be financed by international oil companies, which will consider investments in Venezuela only if they have full confidence in the stability of the country’s systems and its investment climate for international oil and gas players.
Potential opportunities for suppliers
In the Back to 3 million bpd scenario, $183 billion oil and gas capex in 2026-2040 translates into $156 billion of service purchases after internal operator spend is removed. As the spending requirement is infrastructure-heavy, the fabrication and construction segment logically ranks first in service-sector outlay, accounting for $41 billion of total purchases. Years of domestic atrophy and a limited availability of skilled labor make it unlikely that such an increase in the market size could be absorbed in the near term, meaning any potential activity uptick would result in a new inflationary cycle. 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. They are closely followed by rigs and equipment, with 15-year market size of $9 billion, and studies and engineering at $8 billion. While we emphasize that nothing is likely to happen immediately, major service providers will doubtless be monitoring E&P sentiment towards Venezuela operations, with an eye on the many attractive opportunities the potential supplier market size would
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