Post-Maduro: Reserves ≠ Supply

16/01/2026

Canada vs. Venezuela post-Maduro: Reserves ≠ Supply

The US-led arrest and transfer of Nicolás Maduro on January 3^rd has reignited talk that Venezuela could quickly re-emerge as a major oil power. On paper, the country’s resource base is staggering: ~303 billion barrels of proven reserves, the largest in the world, compared with Canada’s ~163 billion barrels (predominantly oil sands). But oil markets run on reliable, deliverable barrel not resources in the ground. By that measure, major structural constraints still position Canada as the U.S.’s most dependable heavy-crude supplier for the foreseeable future.

Production and Infrastructure Comparison

CanSands routinely pumps export volumes of ~4.1 mbpd to the United States through a deeply integrated pipeline and midstream network. Venezuela’s reality is far less stable. Even at the higher end of recent estimates, production in late 2025 was roughly ~900,000 to 1.1 million bpd, with exports constrained by diluent shortages and external restrictions.

A critical difference is infrastructure condition. Much of Venezuela’s state oil company (PDVSA) network – pipelines, upgrading capacity, and refineries – has aged for decades with limited reinvestment. The result is a system that may have enormous potential but requires substantial rehabilitation before it can consistently deliver high volumes.

Sanctions relief will likely be gradual and not a flood of oil ... even assuming a transition government and a shift in U.S. policy, the near-term outcome is more likely to be incremental gains than an overnight surge. In many outlooks from major banks and energy consultancies, the first-year increase is framed as something like ~100,000–200,000 bpd, with the potential to reach ~1.3–1.5 million bpd over the next 18–24 months under favourable assumptions.

Importantly, some “early growth” may not represent net-new global supply. It could instead simply come from redirecting barrels that were previously flowing to other buyers (e.g., China) into more open or higher-value markets.

A long term multi-billion-dollar rebuild is the real bottleneck.

Returning Venezuela to historic peaks of ~3.0-3.5 mbpd would be a major reconstruction project. Estimates from academic and industry analysts commonly put the requirement in the range of $80–110+ billion over roughly 6–10 years to achieve a meaningful ramp (for example, ~2.0–2.5 million bpd sometime in the early 2030s).

Capital is only part of the issue. International oil companies are also watching for resolution of outstanding disputes from prior nationalisations (often discussed as ~$10 billion-scale arbitration overhangs) and – more importantly – clear evidence of durable legal and contractual stability. Decades of underinvestment and asset degradation can’t be reversed on a short political timetable.

An increase in heavy crude production is an underappreciated advantage for Canada.

Many U.S. Gulf Coast refineries are optimised for heavy, sour crude. Historically, that ecosystem has depended on suppliers like Canada, and at times Venezuela and Mexico.

If heavy supply remains tight for long enough, refiners could be pushed toward expensive reconfiguration to run more light shale oil. A structural shift that could reduce long-term demand for CanSands barrels. Paradoxically, a credible multi-year return of Venezuelan heavy supply would help keep Gulf Coast refiners committed to heavy feeds, preserving the heavy-crude configuration that Canada benefits from today.

In that framework, Canada will likely continue to serve as the low-risk “base load” supplier, even if Venezuela becomes a higher-beta swing supplier later on.

Venezuela’s upside is real, and post-Maduro optimism may ultimately prove justified, but the country still IS a high-risk, capital-intensive, multi-year rebuild story. Canada, by contrast, has embedded certainty: large volumes, integrated infrastructure, and significantly lower geopolitical disruption risk. Over the next couple of years, the balance of probability still supports Canada as the dominant and most reliable heavy-crude partner for the U.S., while Venezuela remains a longer-dated optionality trade.

	Canada	Venezuela
Current production	~5.0 mbd total	~0.9–1.1 mbd (at best)
Exports to the U.S.	~4.1 mbd	Limited pre-transition; possible redirection ahead
Near-term upside (1–2 years)	Stable	+100k to +500k bpd (optimistic range)
Infrastructure condition	Modern/integrated	Significant decay: major reinvestment needed
“Full recovery” cost/time	Routine sustaining capital	~$80–110B+ (on the magnitude of CanSands early sunken costs)

Crude/(°API)	Sulphur content (%)	Grade	Sweet/Sour	Comments
WTI ~40° API	~0.24–0.4% sulphur	Light	Sweet	A benchmark U.S. crude; well refined for gasoline/diesel.
Brent ~38° API	~0.37% sulphur	Light	Sweet	Global benchmark for Atlantic‐basin crude.
Merey 16 Venezuelan Heavy ~16° API	~2.5 sulphur	Heavy	Sour	Venezuelan heavy benchmark; typically deep cut refiner feed
Hamaca Blend (Venezuela) ~26° API	~1.5% sulphur	Medium	Sour	Upgraded heavy crude; more refinery friendly but still sour.
WCS – Western Canadian Select ~20.5° API	~3% sulphur	Heavy	Sour	Canada’s heavy crude benchmark.
Canadian Synthetic Crude Oil (SCO) ~30° API	~0.13% sulphur	Medium	Sweet	Upgraded from bitumen; refiners pay a premium for SCO. Typically prices close to WTI.

Midstream - Diluent is the Binding Constraint

For both Canada and Venezuela, the “make-or-break” midstream issue is diluent.

Venezuela has limited domestic light barrels, so it has repeatedly relied on imported condensate/diluent to sustain heavy-blend exports. In 2021-2022, for example, Iranian condensate swap arrangements helped support production of Merey (Venezuela’s key heavy export blend).

This blending strategy parallels Canadian dilbit, with one crucial difference: Canada produces meaningful volumes of light hydrocarbons domestically, while Venezuela often must import them.

That dependency has real economic consequences. In low price environments, the Merey margin can approach zero once diluent costs are included [2]. Shortages of diluent have directly limited Venezuelan output in the past 6 months, a constraint that could ease materially if Venezuela regained broader access to U.S. diluent flows under a sanctions-free arrangement.

Venezuela’s Orinoco heavy oil must travel from inland fields to coast. A network of pipelines moves oil north to Caribbean ports (e.g. the Jose terminal). Blended Merey 16 can be piped, but often still requires heating facilities at loading terminals to prevent viscosity issues.

When U.S. Gulf refiners processed Venezuelan crude (pre-2019 sanctions), the logistics were shorter (Caribbean to USGC). Now, with fewer options, PDVSA often prices Merey at a steep discount to entice buyers (last traded in June 2025 at ~$16/bbl discount to Brent weighted average).

Post-2019, U.S. sanctions removed Venezuelan oil from the U.S. Gulf; those refineries replaced it partly with Canadian heavy and other sources. Merey thus primarily goes to Asia, where refineries with sufficient complexity such as Reliance’s Jamnagar refinery - one of the most complex in the world (NCI 21) can process it fully into light products. This would make a suitable exit for Canadian feedstock via the transmountain pipeline should Venezuela eventually replace Canada in the US gulf coast.

Canada is also exposed - because oil sands logistics are sensitive to condensate availability. Canada’s petroleum system is deeply integrated with the United States, and reduced U.S. exports of relevant light barrels (including condensate used as diluent) would be a structural risk.

Canada imported 402M bpd from the US in 2024, constituting 78% of total Canadian crude imports and there has been a lot of debate in Canada on building new domestic refineries to boost export capacity and decrease US reliance. Canadian SCO typically prices near WTI, and in a future where heavy crude is plentiful thanks to Venezuela, light-heavy differentials will be wide and translate to larger profits for those operating upgraders (all whilst decreasing reliance on US diluent).

Steam Assisted Gravity Drainage (SAGD) for Venezuela

The Orinoco Oil Belt contains the world’s largest known accumulation of extra-heavy oil (8–12° API bitumen). This resource was long considered technically challenging: a 1936 well by Standard Oil produced ~1,000 barrels/day from the Orinoco area but was soon abandoned due to the difficulty of extracting the ultra-heavy crude. Serious development began after nationalisation in the late 1970s. Methods were focused on “cold production” techniques, using horizontal wells with artificial lift (often progressing cavity pumps) and diluent injection (naphtha or light oil) to reduce viscosity.

By blending the heavy oil with lighter streams, Venezuela created exportable products such as the Merey 16 blend at ~16° API, which is similar to Western Canadian Select. Cold production yielded low recovery factors ~8-12% of oil in place but became the dominant method through the 1990s - 2000s. By the 2010s, studies confirmed that thermal EOR could radically increase Orinoco recoveries with SAGD raising recovery to ~50-60% of oil in place, vs. ~10% with cold production. As of 2013 roughly 20% of the Orinoco Belt area was under development via horizontal cold production.

Canada has pioneered enhanced oil recovery (EOR) techniques which were also piloted in Venezuela. Early development of steam injection took place in the Maracaibo basin. Cyclic steam stimulation was piloted in the Santa Barbara field (Monagas) during the 1990s and proved successful in boosting output. PDVSA also experimented with a SAGD pilot in the Tia Juana field.

Historically, Venezuela opted to build upgraders in the Orinoco Belt (projects like PetroPiar, PetroMonagas, PetroCedeno/Sincor) to convert extra-heavy (~8–10° API) into synthetic crudes. For example, the PetroPiar upgrader (Hamaca project) produces a 26° API synthetic crude called Hamaca blend, and PetroCedeno produces a 22° API “Zuata Sweet” crude. These upgraded crudes were typically designed to be sweet enough (sulphur ~0.5–1%) and high API so that U.S. Gulf Coast refineries could take them without a coker. In practice, most refining of Venezuelan crude still involves heavy blending and coking. If heavy crude is priced too high relative to light, refiners will avoid it due to the higher fuel coke yield and hydrogen consumption required.

The Orinoco oil belt is a 600-km long continuous belt of extra-heavy oil deposits (8–12° API bitumen) in four blocks (Boyacá, Junín, Ayacucho and Carabobo). With an estimated 1.2 trillion barrels in place and ~235-300 billion barrels deemed recoverable, it surpasses even Canada’s oil sands in volume. Commercial development began in the late ‘90s via ‘Strategic Associations’ with foreign operators. Four major projects were launched:

• Sincor (PetroCedeno) – Total/Statoil/PDVSA venture, upgrading bitumen to ~30° API synthetic crude.

• PetroZuata – ConocoPhillips/PDVSA, produced Syncrude (~26° API).

• Cerro Negro (PetroMonagas) – ExxonMobil/PDVSA (later taken over by Rosneft/PDVSA), produced diluted extra-heavy (Merey-16 blend).

• Hamaca (PetroPiar) – Chevron/PDVSA (Ameriven), upgrading to ~26–27° API crude.

Whilst hard to pinpoint accurately due to sanctions, Venezuela currently produces ~900,000 bpd from the Orinoco, vs. ~5 million bpd produced in Canada’s oil sands.

Unlike Canada, Venezuela has not yet implemented large-scale thermal recovery; close to 100% of Orinoco output is believed to be primarily via cold production, whereas in Canada only 7.7% of total oil in 2024 was via cold production.

The obvious opportunity… applying Canadian-style thermal EOR to radically increase Venezuelan output.

Technical studies conclude that thermal EOR (SAGD and CSS) is well-suited to the Faja Orinoco, with adaptations for local conditions, experts highlight that the Orinoco’s basal sand reservoirs are thick and laterally extensive – ideal for SAGD – while thinner, less permeable upper layers may instead be suitable for cyclic steam stimulation (CSS).

PDVSA has acknowledged this potential: it initiated SAGD test wells in the Orinoco to evaluate steam injection, and small-scale successes have been reported - one Society of Petroleum Engineers paper cited a SAGD trial achieving ~33-39% recovery in a pilot area vs ~6-9% without steam.

The Boscán field under Chevron saw steam flooding to reduce viscosity, and SAGD pilots were conducted in both the Orinoco and in Lake Maracaibo area heavy fields. These efforts demonstrate that SAGD is a well-known method awaiting full deployment.

That being said, practical challenges must be addressed.

SAGD requires infrastructure … steam generation plants (typically natgas-fired boilers or co-generation units), water treatment/recycling facilities, and insulated flowlines. However, Venezuela’s current energy infrastructure is strained, and the natgas required as fuel for steam is in short supply domestically. New SAGD projects would likely involve building co-generation plants - similarly to Canadian projects where onsite gas-fired power plants supply steam. AECOM helped build a 50,000 bpd SAGD facility with an integrated cogeneration plant in Alberta.

Water sourcing and disposal is another issue: the Orinoco region will require sourcing large water volumes for steam, then treating produced water (which is doable but adds cost).

In addition to SAGD, Cyclic Steam Stimulation (CSS) can be used to target specific Venezuelan reservoirs:

CSS is known as the “huff-and-puff” method where steam is injected in a well, soaked, and the heated oil can be pumped to the surface from the same well.

It has a shorter-term impact per well but can be effective in reservoirs with good vertical permeability. It was successfully used in Venezuela’s Morichal heavy oil field and others on a pilot basis and might suit the upper thinner layers of the Orinoco reservoirs.

Despite the status-quo being cold-extraction, I expect steam-based techniques to dominate future heavy oil projects in Venezuela and consider SAGD particularly attractive because it can achieve quick ramp-up and high recovery.

If you feel there are opportunities in future heavy-crude production/refining both in Canada and Venezuela, the following companies may complement a portfolio as an each-way bet on the sector.

Oilfield Services & Drilling Companies

Schlumberger (SLB)

The world’s largest oilfield services firm has operated in Venezuela since the 1920s and is PDVSA’s biggest service partner historically. It has pioneered directional drilling and well completions used in SAGD projects globally. Even during sanctions, SLB maintained a foothold (under a U.S. license) keeping equipment and some drilling rigs in-country - giving Schlumberger a headstart in winning contracts with PDVSA or its JVs should they stake claims on the oil patch.

Halliburton (HAL)

The 2^nd largest global oilfield service firm. Like SLB, HAL also received sanctions waivers to preserve its Venezuelan assets. Its heavy oil track record includes providing thermal well completions via specialized packers and coiled tubing tools for steam injection wells and sand management for CHOPS (cold heavy oil production with sand) in Canada. Halliburton helped implement a 500-well redevelopment in Lake Maracaibo under a service contract in the 1990s as part of PDVSA’s “Operating Agreements”. While specific contracts are proprietary, Halliburton’s role in Venezuela’s oil comeback is expected to be significant.

Baker Hughes (BKR)

Baker Hughes has unique capabilities in artificial lift (ESP systems) crucial for heavy oil: they manufacture high-temperature electric submersible pumps designed for hot SAGD wells. Baker also provides steam generators (through its NovaLT gas turbines and other process equipment business) which could be used in SAGD facility packages. In Venezuela, Baker Hughes had a significant presence historically, including turbo compressors in PDVSA’s gas projects and directional drilling in Orinoco fields. It too was granted a U.S. license to remain in Venezuela in a limited capacity during sanctions.

Weatherford (WFRD)

While smaller than its peers and having gone through a restructuring, Weatherford’s strongest heavy oil credentials come from Canada where it provides SAGD completion tools and pumping systems. WFRD has historically specialised in production technologies critical for heavy oil and is a leading provider of progressing cavity pumps (PCPs) – a favoured artificial lift method for cold heavy oil production able to handle viscous fluids and sand particularly well. In the Orinoco projects, many wells used Weatherford PCP systems when it was active in Venezuela’s production service contracts pre-2007 and the business has maintained some operations under sanctions waivers. If Venezuela needs to revive thousands of idled wells, Weatherford’s PCP lift systems would likely be in demand at a bare minimum.

Nabors Industries (NBR)

Nabors is the world’s largest land drilling rig contractor, operating the biggest fleet of land rigs globally, including fit-for-purpose pad drilling rigs used in Canadian SAGD operations. SAGD projects require drilling many pairs of long horizontal wells from multi-well pads – a Nabors specialty. In Venezuela, Nabors was the primary drilling contractor for decades (for both PDVSA and joint ventures). Nabors operated rigs in Venezuela up until 2020, due to sanctions and non-payment it finally pulled out, causing the active rig count to hit zero. At its peak in 2014, Venezuela had over 80 active drilling rigs (many of them Nabors-owned) but by 2020 Nabors shut its last rig. Now, with Maduro out, Nabors’ idle rigs are likely to be highly sought after.

Engineering, Procurement & Construction (EPC) Contractors

Implementing SAGD or any upstream project in Venezuela will also require EPC contractors to design and build central processing facilities, steam plants, pipelines, and potentially upgrader modifications. Fluor Corp., AECOM, and Technic stand out to me based on their track records in CanSands.

Fluor Corporation (FLR)

Fluor is one of the world’s largest EPC firms, and it has extensive heavy oil experience. Fluor is a key contractor in Canada’s oil sands, and has been completed projects like Nexen’s Long Lake (an integrated SAGD 72,000 bpd upgrader).

In the 1980s FLR helped build the Cerro Negro heavy oil pilot and did engineering for the Complejo Criogénico de Oriente (gas processing plant). FLR built the Hamaca upgrader’s expansion and did work in the Venezuelan refining sector in the 1990s which is another huge bonus if heavy oil upgrading or refining units need refurbishment and they are chosen given their legacy. FLR explicitly markets its Steam-Assisted Gravity Drainage expertise emphasising that SAGD projects benefit from its modular execution in which entire well-facility modules can be constructed offsite. FLR is also experienced addressing challenges like lowering steam-oil ratios (very important) and integrating carbon-reduction tech. demonstrating it advises beyond construction.

AECOM (ACM)

A global engineering and construction firm (based in the U.S.) with a strong footprint in oil & gas infrastructure. AECOM has a proven track record in SAGD projects and was contracted to provide construction, module fabrication, and pre-commissioning for a major 50,000 bpd SAGD facility in Alberta, including a cogeneration plant for steam generation. AECOM handled well pad construction, water treatment, and even built a desulphurisation unit for the produced oil, delivering a $3.6 billion project on schedule.

The company notes it “has been involved in almost every major oil sands project that [our client] has built in the last decade” – given the proprietary nature of many contracts … this will have to suffice as a testament to its extensive experience. Their breadth covers both greenfield SAGD developments and expansions. AECOM’s expertise in modular construction is a big asset: in remote Venezuelan locales with limited infrastructure, modular design (fabricating equipment skids offsite for quick assembly) can reduce risk. Its status as a U.S.-based, publicly traded company could make it a preferred contractor now U.S.-Venezuela relations are likely to improve.

TechnipFMC (FTI.US or TE.PA)

Technip has long been one of the best-known EPC names in complex refining and upgrading facilities, and its oil sands track record is directly relevant to heavy crude upgrading work. Historically, in Canada, Technip was awarded two major Horizon Oil Sands contracts by CNRL worth about C$1.07 billion, covering both upgrading facilities and a dedicated hydrogen unit - a strong indicator of capability across the core “upgrader” blocks (conversion + hydrogen for hydrotreating/hydroprocessing).

On the execution side, Horizon’s primary upgrading scope included key heavy-oil conversion infrastructure (e.g., diluent recovery and delayed coking as part of the primary upgrading unit), with major construction packages performed for Technip (Technip Italy) by large Canadian industrial contractors - useful evidence that Technip acted as a central EPC integrator coordinating big field/construction teams and supply chains.

The current corporate structure matters for contracting today: in 2021, TechnipFMC completed its separation into two independent, publicly traded companies - TechnipFMC (FTI) and Technip Energies (TE) - so depending on how a project is scoped (upstream vs. downstream EPC), the choice between FMC and Energies will require closer scrutiny.

Important Disclaimer

This article is intended for general information purposes only and reflects the market environment at the time of writing. It does not constitute investment advice, a personal recommendation, or an offer to engage in any trading activity. The content does not take into account individual objectives or circumstances and should not be relied upon as the basis for any investment decision. Past performance is not a reliable indicator of future results. 

Content may have been created by persons who have, have previously had, or may in the future have personal interests in securities or other financial products referred to therein. All conflicts and potential conflicts relating to our business are managed in accordance with our conflicts of interest policy. For more information, please refer to our Summary of Conflicts of Interest Policy. 

For more information and important risk disclosures, please see our Derivative Product Trading Notes and Privacy Policy. AMT Futures Limited is authorised and regulated by the Financial Conduct Authority.