Venezuela has finalized agreements with BP, Shell and other international firms to develop offshore gas fields straddling its maritime border with Trinidad and Tobago, ending years of sanctions-driven isolation that froze the country’s vast gas resources. The deals directly address Trinidad’s urgent feedstock shortfall for its Atlantic LNG complex and could unlock billions of cubic feet per day of stranded Venezuelan supply within reach of existing Caribbean infrastructure. For global gas markets, this marks the most concrete step yet toward reintegrating Latin America’s largest proven reserves into regional and international supply chains.
Sanctions Easing Opens Door to Stranded Border Fields
The MercoPress report confirms that Venezuela’s government has concluded “a series of agreements with international oil companies in recent weeks to develop its offshore gas fields,” specifically naming BP, Shell and Gulf partners operating near the Trinidad and Tobago border. This formulation matters: it signals not a single license but a coordinated framework covering multiple blocks, likely including the Dragon, Loran-Manatee and Perla fields that have sat undeveloped for over a decade despite proven reserves exceeding 15 trillion cubic feet combined.
Since 2019, U.S. secondary sanctions on PDVSA and Venezuela’s financial sector made any equity investment, technology transfer or revenue repatriation by Western majors legally untenable. Trinidad’s NGC and Shell’s local affiliate had negotiated a Dragon field gas supply agreement as early as 2018, but the project stalled when the U.S. Treasury declined to issue a specific license. The current breakthrough suggests the Biden administration – or its successor – has granted the necessary authorizations, likely under the same “License 41” framework that allowed Chevron to resume limited oil operations in 2022. That license required strict revenue escrow, no cash payments to PDVSA, and quarterly reporting; similar conditions almost certainly apply here.
Geographically, the focus on the Trinidad border is deliberate. The Loran-Manatee field straddles the maritime boundary and requires unitization between PDVSA and NGC/Shell. Dragon lies wholly in Venezuelan waters but is 12 kilometers from Trinidad’s Hibiscus platform, connected by a proposed subsea pipeline that Shell and NGC had already engineered. Perla, operated by Repsol and Eni further west, produces but cannot monetize its full capacity without export routes. All three sit within 150 kilometers of Trinidad’s Point Fortin LNG trains, which have run at 60-70% utilization for three years due to domestic gas decline.
Trinidad’s LNG Crisis and the Regional Supply Gap
That points to the immediate commercial driver: Trinidad and Tobago’s Atlantic LNG facility, one of the world’s largest liquefaction complexes with 15 million tonnes per annum nameplate capacity, faces a structural feedstock deficit. Domestic production has fallen from 4.2 bcf/d in 2015 to roughly 2.7 bcf/d in 2024 as mature fields deplete and exploration success rates dropped. NGC has signed short-term supply deals with Shell and BP for cargoes from the U.S. Gulf and West Africa, but landed LNG costs into Point Fortin exceed $10/MMBtu – uneconomic for re-liquefaction compared to piped gas at $3-4/MMBtu.
If Dragon (estimated 4.2 tcf) and Loran-Manatee (10.2 tcf gross) enter development, they could supply 800-1,200 mmcf/d combined within 30-36 months of final investment decision, based on typical subsea tie-back timelines in the Caribbean. That volume would restore Atlantic LNG to 90%+ utilization, securing Trinidad’s position as the Caribbean’s primary gas hub and generating $1.5-2 billion annually in LNG export revenue at current forward curves. For Venezuela, the same gas monetized via Trinidad earns hard currency without building new liquefaction – a critical distinction given PDVSA’s $60+ billion debt overhang and inability to finance greenfield LNG.
By comparison, Mexico’s Zama field unitization took six years from discovery to agreement; the Venezuela-Trinidad maritime treaty was signed in 2014 but never implemented. The speed of this latest move – “recent weeks” per the source – suggests pre-negotiated commercial terms awaiting only political clearance. Shell and BP likely retained technical teams and FEED studies throughout the sanctions period, a pattern seen in Iran after the 2015 JCPOA where Total and Shell reactivated South Pars studies within months.
Who This Affects
- Utility planner (Caribbean/Latin America): Firm Venezuelan gas volumes via Trinidad reduce reliance on spot LNG cargoes for power generation in Puerto Rico, Dominican Republic and Jamaica, where current contracts index to JKM or Henry Hub plus $2-3/MMBtu transport premium.
- LNG portfolio trader: Atlantic LNG’s return to full utilization removes 4-5 million tonnes/year of effective demand from the Atlantic basin spot market, tightening 2026-2028 balances and supporting JKM-TTF spreads.
- Policy analyst (U.S. sanctions/Energy security): The license structure – likely revenue escrow, no PDVSA cash – becomes the template for future Venezuela energy authorizations; monitor whether oil export licenses expand beyond Chevron’s current 200 kbbl/d cap.
- Upstream investor (Majors/Independents): BP and Shell’s return signals risk appetite for sanctioned jurisdictions with clear exit ramps; watch for Equinor, TotalEnergies or Repsol to accelerate Perla Phase 2 and Corocoro gas decisions.
What to Watch Next
- Unitization agreement signing for Loran-Manatee: The 2014 treaty requires a unit operating agreement; its execution timeline (target: Q4 2026) dictates first gas date.
- Dragon pipeline FID and OFAC license publication: Shell/NGC need final investment decision on the 12-km tie-back; the specific license terms (revenue split, audit rights) will reveal U.S. enforcement posture.
- Trinidad fiscal regime adjustment: NGC’s gas purchase price from Dragon/Loran-Manatee must cover Venezuelan fiscal terms plus transport; Trinidad’s 2025 budget assumes $2.50/MMBtu – any gap requires cabinet approval.
- PDVSA operational readiness: After years of underinvestment, PDVSA’s ability to meet drilling schedules, HSE standards and metering transparency will determine whether IOCs book reserves or treat this as tolling-only.
Bottom line: The Venezuela-Trinidad gas corridor is reopening not because geopolitics softened, but because both sides face hard commercial deadlines – Trinidad’s LNG trains need molecules, Venezuela needs dollars, and the majors have the only technology and capital to bridge the gap. The next 90 days of license disclosures and unitization signatures will reveal whether this is a durable framework or a one-off carve-out.
Read the full report at MercoPress
Original source: MercoPress — Energy & Oil (South Atlantic news agency)
Note: facts and figures attributed above to MercoPress — Energy & Oil (South Atlantic news agency) reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
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