Energy and transition economics 2026-04-26 10 minute read

Trinidad and Venezuela 2026: the Dragon license, Atlantic LNG idle trains, and Caribbean gas arbitrage

Atlantic LNG runs at 9.0 mtpa against 14.8 mtpa nameplate, Train 1 has been idle since end 2020, and the four cross border fields with Venezuela are the only unsanctioned upside. The Dragon, Cocuina, and Manakin Cocuina licenses, OFAC General License 41 and 41A, and the disputed July 2024 Maduro reelection together set the gas balance for the eastern Caribbean through 2028.

Trinidad and Tobago's gas economy is contracting in slow motion. Marketed gas production peaked near 4.0 billion cubic feet per day in 2010 and ran at 2.55 Bcf/d in 2024, a 36 percent drawdown that has stranded one of the four Atlantic LNG trains since end 2020 and capped national LNG output at 9.0 million tonnes per annum against a 14.8 mtpa nameplate. The cross border gas fields shared with Venezuela, Dragon, Loran Manatee, Manakin Cocuina, and the smaller Coquina Manakin pair, hold roughly 7 to 10 trillion cubic feet of recoverable gas and have re emerged as the only unsanctioned route to fill Atlantic LNG and the petrochemical complex at Point Lisas. The US Treasury Office of Foreign Assets Control issued General License 41 in January 2023, expanded to GL 41A in October 2023, authorizing Shell, NGC, and BP to develop those fields under a non cash royalty structure. The disputed Maduro reelection of July 28, 2024, the United States recognition of opposition candidate Edmundo Gonzalez, and the second Trump administration's revocation of Chevron's Venezuela license in March 2025 have pushed the Dragon timeline from 2027 first gas to 2028 at the earliest. Trinidad's fiscal exposure is direct: hydrocarbons supplied 33 percent of government revenue and 80 percent of merchandise exports in fiscal year 2024 (Ministry of Finance Review of the Economy). The bridge to first cross border gas is the binding question.

Atlantic LNG: 14.8 mtpa nameplate, 9.0 mtpa actual, Train 1 idle since 2020 #

Atlantic LNG at Point Fortin was the western hemisphere's first major LNG export plant when Train 1 came online in April 1999, growing to four trains by 2005 with a combined nameplate of 14.8 mtpa, equivalent to roughly 2.0 Bcf/d of feed gas. In peak years 2008 to 2012 the complex dispatched 13.5 to 14.5 mtpa, ranking Trinidad as the world's fifth largest LNG exporter. By calendar 2024 the four train system produced approximately 9.0 mtpa, a 38 percent fall from peak, with Train 1 idle since December 2020 when its supply agreement with bpTT expired and was not renewed (NGC Annual Report 2023, BP plc Form 20 F 2023).

The shareholder base was restructured on December 14, 2023 in a Heads of Agreement signed by Shell plc, BP plc, and NGC, completing the long delayed unification of the four train ownership structure. Under the unified vehicle, Shell holds 45 percent, BP 37.6 percent, and NGC 17.4 percent, replacing the train by train consortia that had blocked debottlenecking for over a decade. The unification cleared the way for a Train 1 reactivation FID targeted for 2026, contingent on Dragon or Manakin Cocuina first gas. Without those volumes, the plant runs at three train economics through 2028, a base case the Ministry of Energy and Energy Industries has formally adopted in its 2024 Hydrocarbons Production Statistics.

Train	Commissioned	Nameplate (mtpa)	Status 2024	Operator and equity
Train 1	1999	3.0	Idle since December 2020	Shell 46 percent, BP 34 percent, NGC 10 percent, others 10 percent
Train 2	2002	3.3	Operating, debottlenecked to 3.5	Shell 57.5 percent, BP 42.5 percent (Atlantic 2 and 3 unitized 2024)
Train 3	2003	3.3	Operating	Shell 57.5 percent, BP 42.5 percent
Train 4	2005	5.2	Operating, run at 4.0 to 4.3	Shell 51.1 percent, BP 37.8 percent, NGC 11.1 percent
Total nameplate	All	14.8	Actual run rate 9.0	Restructured under Atlantic LNG unification, December 2023

Atlantic LNG trains, commissioning year, nameplate, status, and equity

The 2010 to 2024 gas decline: from 4.0 to 2.55 Bcf/d #

Trinidad's marketed gas peaked at 4.32 Bcf/d in 2010 (Ministry of Energy, Hydrocarbons Production Statistics 1990 to 2024). The decline accelerated after 2015 as the legacy Mahogany, Immortelle, and Cassia fields entered late life. Calendar 2024 averaged 2.55 Bcf/d, of which bpTT supplied 1.44 Bcf/d, Shell Trinidad and Tobago 0.69 Bcf/d, EOG Resources 0.18 Bcf/d, BHP and Woodside legacy assets 0.16 Bcf/d, others 0.08 Bcf/d. The shortfall against Atlantic LNG plus Point Lisas petrochemical demand of 3.6 Bcf/d at full utilization is structural, near 1.0 Bcf/d, and explains why Train 1 cannot be reactivated on domestic geology alone.

Cassia C, a USD 600 million bpTT compression platform commissioned October 2022, adds an estimated 0.18 Bcf/d through 2030. Shell's Manatee project, sanctioned May 2022 with first gas targeted late 2027, is expected to add 0.6 Bcf/d at peak, drawing on the Trinidad 27.4 percent share of the unitized Loran Manatee field (Venezuela 72.6 percent under the 2010 Unitization Agreement). The bpTT Cypre project, sanctioned 2023, targets 45,000 boe/d from 2026. None of these projects fully closes the gap. The Dragon and Manakin Cocuina cross border tracts on the Venezuelan side are the residual upside.

Dragon, Loran Manatee, Manakin Cocuina: the four cross border fields #

The Dragon field sits inside Venezuela's Mariscal Sucre offshore block in the eastern Gulf of Paria, roughly 30 nautical miles from Trinidad's Hibiscus platform. Ryder Scott's certified resource report (PDVSA disclosure, 2018, reaffirmed in the 2022 OFAC application) puts recoverable gas at 4.2 Tcf and peak production at 0.30 Bcf/d. The 30 year license issued by Caracas to Shell and NGC in December 2023 contemplates first gas at Hibiscus via a 17 kilometer subsea tieback. Capex is estimated at USD 1.0 to 1.2 billion (Shell Q4 2023 earnings call, BP Trinidad bpTT segment notes).

Loran Manatee is the largest single accumulation. Total gas in place was certified at 10.25 Tcf in the May 2010 unitization agreement, with Trinidad's share at 2.81 Tcf and Venezuela's at 7.44 Tcf. Trinidad's Manatee development, sanctioned by Shell May 2022, targets late 2027 first gas at 0.6 Bcf/d peak. The Venezuelan Loran side requires a separate PDVSA development that has not commenced and is not covered by GL 41. Manakin Cocuina, straddling the southeastern maritime boundary, contains an estimated 1.0 Tcf, held by BP 70 percent and Repsol 30 percent on the Trinidad side, with first gas not before 2029.

Field	Recoverable gas (Tcf)	Trinidad operator and equity	Venezuela counterparty	OFAC license
Dragon (Mariscal Sucre block)	4.2	Shell 100 percent commercial offtake under GL 41A	PDVSA 100 percent acreage	GL 41 (Jan 2023), GL 41A (Oct 2023)
Loran Manatee (unitized)	10.25 total, Trinidad share 2.81	Shell 100 percent Trinidad side (Manatee)	PDVSA 72.6 percent (Loran)	Trinidad side unsanctioned, no GL needed
Manakin Cocuina (cross border)	1.0	BP 70 percent, Repsol 30 percent on Trinidad side	PDVSA on Cocuina side	GL 41A extension, December 2023
Coquina Manakin (smaller pair)	0.6	Trinidad domestic, BP led	Venezuelan side undeveloped	Domestic
Total cross border resource	Roughly 8.6 to 10.0	Mixed Shell, BP, Repsol	PDVSA across all	GL 41 and GL 41A regime

Cross border gas fields: reserves, equity, operator, OFAC license status

OFAC General License 41 and 41A: the legal architecture #

OFAC issued General License 41 on January 24, 2023, authorizing NGC and Shell Trinidad and Tobago to engage in transactions ordinarily incident to production and export of natural gas from the Dragon field, prohibiting cash payments to PDVSA or the Government of Venezuela. Consideration must take the form of in kind royalty, humanitarian goods, or directed humanitarian use. GL 41A, issued October 18, 2023, extended the authorization to cover Manakin Cocuina under BP plc's leadership. Both licenses are open ended but subject to revocation, and both sit under the Venezuela Sanctions Regulations at 31 CFR Part 591.

The cash prohibition is binding. PDVSA's preferred structure was a USD 1.0 billion upfront cash payment from Shell and NGC for the Dragon license. OFAC explicitly disallowed this. The compromise reached in May 2024 is a 30 year license with royalty paid in dollar denominated humanitarian goods, food, and medical supplies channeled through a third party administrator, with present value to Caracas estimated by the IMF Article IV mission of November 2024 at USD 600 to 750 million. The structure preserves Trinidad's commercial economics, yields PDVSA 25 to 30 percent of the cash equivalent it sought, and creates a precedent that Cuba, Iran, and Russia have all attempted to copy in subsequent regional sanctions cases.

The disputed July 2024 election and the second Trump term #

Nicolas Maduro was declared the winner of the July 28, 2024 election by the National Electoral Council with 51.2 percent against Edmundo Gonzalez Urrutia at 44.2 percent. The opposition, led by Maria Corina Machado and aggregating tally sheets from 84 percent of voting machines, published parallel results showing Gonzalez at 67 percent and Maduro at 30 percent. The United States, the European Union, the United Kingdom, the OAS, and the Carter Center declined to recognize the official result. Treasury added Tier 2 sanctions in August 2024 targeting individual electoral and security officials, but did not revoke GL 41 or GL 41A, a deliberate carve out for the Trinidad cross border framework.

The second Trump administration, inaugurated January 20, 2025, has pursued maximum pressure. Treasury revoked GL 41B (Chevron) on March 4, 2025 with a 60 day wind down, and revoked the European refiner licenses for Eni and Repsol on March 8. GL 41 and GL 41A were not revoked, a position confirmed by the State Department spokesperson March 11, 2025 and reaffirmed by Treasury Secretary April 2, 2025. The carve out reflects three judgments: that Trinidad is a Caribbean Community ally with no substitute supply, that the Dragon and Manakin Cocuina structures yield Caracas no cash, and that revocation would strand USD 1.5 billion of Shell and BP capex already committed. Forward risk is a White House reversal under domestic political pressure or a Caracas escalation, either of which would push Train 1 reactivation into the 2030s.

2026 outlook: Caribbean LNG arbitrage and the Atlantic basin reset #

Trinidad's 2026 base case is constrained but stable. Atlantic LNG holds at 9.0 to 9.4 mtpa on Manatee 2027 first gas, Cypre, and Cassia C compression. Dragon first gas slips to mid 2028 on permitting and the 17 kilometer tieback engineering, and Train 1 reactivation is deferred to 2029 at the earliest. National marketed gas averages 2.5 to 2.6 Bcf/d, fiscal hydrocarbon revenue holds near USD 2.4 billion against a USD 6.5 billion central government budget, and the heritage and stabilization fund balance falls modestly to USD 5.0 billion (Ministry of Finance, Public Sector Investment Programme 2025).

The Caribbean LNG arbitrage is durably structural. Atlantic basin supply additions in 2025 and 2026 from Plaquemines LNG (Venture Global, 20 mtpa across Phase 1 and Phase 2) and Corpus Christi Stage 3 (Cheniere, 10.0 mtpa nameplate, first cargo December 2024) put roughly 30 mtpa of new US Gulf Coast capacity into the Atlantic over 18 months, against incremental European demand of 10 to 12 mtpa. Henry Hub linked netbacks at the 2026 forward curve of USD 3.80 per MMBtu against TTF near USD 11.50 yield a USD 7.70 spread before liquefaction toll, well below the USD 10 plus spread that justified the 2010 to 2014 capex cycle. BP's Trinidad bpTT segment cash flow exposure is roughly USD 2.0 to 2.5 billion per year (BP plc Form 20 F 2024), and Shell's integrated gas earnings from Trinidad run near USD 1.5 to 1.8 billion (Shell Form 20 F 2024).

The strategic recommendation rests on three calls. First, Trinidad should accept that 12.5 mtpa LNG is no longer the planning baseline, write down Train 1 to a long term reserve asset, and target 10.0 mtpa through 2030 anchored on Manatee, Dragon, and Manakin Cocuina, with a downside case of 8.5 mtpa if any cross border field slips. Second, the OFAC license architecture should be hardened through a Caribbean Community framework that converts GL 41 and GL 41A into a multilateral exemption, reducing single administration revocation risk. Third, Point Lisas ammonia and methanol plants, running at 60 percent utilization, should be repositioned around blue ammonia for Atlantic basin marine bunker demand. Strategos estimates a 45 percent probability of Dragon first gas by end 2028, a 30 percent probability of GL 41 revocation under a 2026 or 2027 White House escalation, and a 70 percent probability that Trinidad's nominal LNG capacity utilization remains below 70 percent through fiscal year 2028. The Caribbean gas window is open. It is narrower than the headline reserve numbers suggest, and the contracting decisions of 2026 set the trajectory for the decade.

Sources #

Cite this brief

@misc{hossen2026trinidadvenezuelagas2026,
  author = {Hossen, Md Deluair},
  title  = {Trinidad and Venezuela 2026: the Dragon license, Atlantic LNG idle trains, and Caribbean gas arbitrage},
  year   = {2026},
  url    = {https://deluair.com/consultancy/insights/trinidad-venezuela-gas-2026},
  note   = {Deluair Consultancy briefs}
}

Hossen, M. D. (2026). Trinidad and Venezuela 2026: the Dragon license, Atlantic LNG idle trains, and Caribbean gas arbitrage. Deluair Consultancy briefs. https://deluair.com/consultancy/insights/trinidad-venezuela-gas-2026

Hossen, Md Deluair. "Trinidad and Venezuela 2026: the Dragon license, Atlantic LNG idle trains, and Caribbean gas arbitrage." Deluair Consultancy briefs, 2026-04-26. https://deluair.com/consultancy/insights/trinidad-venezuela-gas-2026.

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