Venezuela Oil And Gas Market Size & Share Analysis - Growth Trends And Forecast (2025 - 2030)

Venezuela Oil And Gas Market Trends and Insights

Vast Proven Extra-Heavy & Offshore Reserves

An estimated 300 billion barrels of proven crude oil and 196 trillion cubic feet of natural gas underpin long-term supply potential.^{[1]U.S. Geological Survey, “Assessment of Undiscovered Resources, Orinoco Oil Belt Province,” usgs.gov} Development remains concentrated in the Orinoco Belt, where API gravity averages 7-10 degrees and steam-assisted gravity drainage trials lift recovery factors by up to 10 percentage points. Renewed interest in the Querecual Formation could extend play fairways toward Trinidad, Guyana, and Suriname, opening multi-asset portfolios for integrated majors.

Conditional U.S.-Licence Windows & Selective Sanction Relief

After General Licence 44 lapsed in April 2024, Washington adopted case-by-case authorizations that privilege incumbents such as Chevron, Schlumberger, and Baker Hughes.^{[2]U.S. Treasury, “Venezuela Sanctions Licenses & Guidance,” ustreasury.gov} Licensed operators export crude directly to the U.S. Gulf Coast, swap diluent cargoes, and repatriate debt payments, providing a competitive moat. New entrants face protracted compliance vetting and political linkage to Venezuelan electoral milestones, which lengthen deal cycles and deter Asian upstream bidders.

High Global Heavy-Crude Price Differentials

The Merey-Brent discount widened to USD 22 per barrel in March 2025 but narrowed to USD 15 once OPEC+ cut medium-sour output, enhancing netbacks for Venezuelan cargoes at coker-equipped refineries in Texas, Shandong, and Gujarat. The structural spread mitigates spot price volatility; during market tightness, discounts compress more quickly than benchmark gains, thereby cushioning revenue.

New BP-NGC / Shell Offshore Gas Licences (Cocuina-Manakin, Dragon)

Shell’s Dragon and BP-NGC’s Cocuina-Manakin aim for a combined plateau of 850 million cubic feet per day by 2028, enough to displace diesel-fired power and re-inject gas for heavy-oil lifting. Both operators demand multi-year U.S. waivers before sanctioning final investment decisions, underscoring licence risk as a gating item for Venezuelan offshore expansion.

Re-tightening U.S. Sanctions & Secondary Tariffs on Buyers

Washington reinstated crude-sales restrictions in mid-2024, compelling traders to re-flag tankers and reroute cargoes through Asia. Shipping insurers now demand premium surcharges of 30-40% for Venezuelan liftings, crowding out smaller refiners. Secondary enforcement chills European spot purchases despite refinery demand for heavy feedstock.

Chronic Under-Investment & Ageing Infrastructure

The average age of field equipment has surpassed 32 years, compared to a global mean of 18 years, driving recurrent fires at the José Antonio Anzoátegui upgraders and three pipeline ruptures along the Eastern Duct in 2024-2025.^{[3]Petróleos de Venezuela S.A., “Annual Operational Statistics 2024,” pdvsa.com} Capital expenditure cuts of 15% in PDVSA’s 2025 budget exacerbate deferred maintenance backlogs.

Segment Analysis

By Sector: Upstream Dominance Drives Market Structure

The upstream segment held an 83.0% market share in Venezuela's oil and gas market in 2024, accounting for USD 1.55 billion within the overall market size, and is projected to grow at a 3.1% CAGR through 2030. Cost-effective work-overs, sand-control programs, and CCS-assisted steam cycles underpin incremental barrel additions that offset natural declines. Midstream pipelines handle approximately 1.1 million barrels per day of liquids, but average 68% utilization due to leak-related downtime. Downstream refining averaged 134,000 barrels per day in 2024, far below the 1.3 million barrels per day nameplate capacity, underscoring deferred turnarounds and catalyst shortages.

International partners anchor upstream gains. Chevron's four ventures pumped 200,000 barrels per day in 2025, Repsol's mixed asset produced 20,000 barrels of oil and 40 million cubic feet of gas per day, while Eni's Junín-5 maintained 50,000 barrels per day despite upgrader constraints. Midstream spending prioritizes leak detection and fiber-optic monitoring to cut spill incidents by 30% before 2028. Downstream upgrades focus on vacuum distillation and delayed coking revamps to improve product yields and comply with the IMO 2020 sulfur rules, but financing gaps persist, given USD 3.6 billion rehabilitation cost estimates.

Note: Segment shares of all individual segments available upon report purchase

By Location: Onshore Operations Anchor Current Activity

Onshore fields captured 87.8% Venezuela's oil and gas market share in 2024 and produced 930,000 barrels per day of liquids, whereas offshore output stood at 130,000 barrels per day. The onshore dominance results from legacy surface networks, available rigs, and shorter drilling lead times. However, offshore shows the highest growth, with a 5.1% CAGR forecast that could raise gas supply to 1.2 billion cubic feet per day by 2030.

The Orinoco Belt's four strategic blocks—Boyacá, Junín, Ayacucho, and Carabobo—drive onshore momentum via steam-generation plants and dilution facilities. Meanwhile, the Plataforma Deltana and Blanquilla-Tortuga offshore areas remain lightly explored, with only six wells having been drilled since 2015. New 2D seismic, covering 50,000 kilometers, was completed in April 2025 and has promoted licensing interest from Shell, Equinor, and Woodside Energy. Cross-border gas evacuation to Trinidad's Atlantic LNG offers early monetization, lowering break-even costs to USD 3.10 per MMBtu compared to USD 4.60 for stand-alone Venezuelan LNG.

By Service: Construction Leads Infrastructure Rehabilitation

Construction represented 60.5% of the 2024 service value pool, equating to USD 410 million within the Venezuela oil and gas market size. Scope centers on well-pad expansions, upgrader flare-gas recovery units, and pipeline sleeve replacements. Maintenance and turnaround services are projected to grow at the fastest rate of 4.5% CAGR through 2030, driven by mandatory integrity checks following the Muscar gas complex fire.

Schlumberger, Baker Hughes, Halliburton, and Weatherford continue under General Licence 8M, executing coiled-tubing stimulations, ESP retrofits, and digital twins for surface facilities.^{[4]Japan Oil Gas and Metals National Corporation, “Service Firms in Venezuela Under OFAC Licence 8M,” jogmec.go.jp} Predictive analytics trim unscheduled downtime 12% year-on-year in pilot assets, highlighting a pivot from reactive to preventive maintenance. Decommissioning remains nascent but could unlock USD 140 million annual spend after 2028 as mature Maracaibo wells reach economic limit.

Note: Segment shares of all individual segments available upon report purchase

Geography Analysis

Eastern Venezuela hosts 74% of proven reserves and 65% of active wells, yet relies on 1,200-kilometer pipelines that experienced three spill events in 2024. The region’s 2025 output averages 730,000 barrels per day and is expected to rise to 810,000 barrels per day by 2030, contingent upon stable diluent flows. Western Zulia contributes 200,000 barrels per day but declines at a rate of 6% annually, despite implementing water-flood programs, underscoring its maturity.

Caribbean offshore acreage emerges as a growth pole following Shell’s 30-year Dragon field licence and BP-NGC’s Cocuina-Manakin deal that straddles the maritime boundary with Trinidad. First gas is slated for 2026, feeding Trinidad’s Atlantic LNG Train 1 and freeing 120 MW of Venezuelan power currently generated on diesel. Upstream risk is lower relative to Orinoco heavy oil because offshore gas benefits from lighter reservoirs, lower lifting costs, and regional LNG demand.

Trade flows have re-oriented eastward. In 2024, China absorbed 68% of crude exports, India 13%, and the U.S. 23% under Chevron’s licence shipments. Longer voyages raise freight costs, but firm Asian demand for heavy feed consolidates baseline export volumes. Spain and Italy marginally resume offtake under EU humanitarian exemptions, receiving 4% of barrels. Meanwhile, Caribbean neighbors import Venezuelan LPG and naphtha swaps, anchoring regional integration prospects.