Over the last few years, the narrative around Trinidad’s gas supply has been focused on what’s missing, with gas production declining, fields depleting and Dragon perpetually on the horizon. It’s been a story of a widening gap.
That narrative is still true, but if you look at what is being built, drilled, sanctioned, and legislated right now, a different story may be emerging.
Before getting into the projects being developed, it’s worth mentioning the demand that is already waiting for this gas as the numbers are sobering.
Point Lisas has seen a wave of curtailments and shutdowns in recent years, driven primarily by inadequate gas feedstock. At various points, a significant proportion of T&T’s ammonia and methanol production capacity has been idle or running well below design rates, with multiple major producers either shutting down or striking short-term gas supply deals just to keep operations going. The situation has been fluid, with some operators securing new gas contracts and restarting capacity while others remain offline or constrained. The broad pattern, however, remains clear: an industrial estate built on the promise of affordable, reliable gas has been struggling to get enough of it.
Atlantic LNG has also felt the impact. The facility has been running with three of its four trains since Train 1 was mothballed due to gas shortages, and even those three trains have been operating below capacity.
Against this demand backdrop, let’s now take a look at the supply picture.
What’s already in the system
Two significant projects achieved first gas in 2025 and deserve acknowledgment before we look at what is coming next.
In April 2025, bpTT’s Cypre field came online. A subsea tieback to the Juniper platform with seven wells, Cypre delivers around 250 mmscfd at peak. It came in roughly 2.5 years from final investment decision, which is about as efficiently as you can execute an offshore tieback in this part of the world. As I covered in an earlier piece on what it actually takes to develop a gas field from discovery to first gas (link here), that execution timeline is genuinely impressive.
A month later, in May 2025, Mento—the 50/50 joint venture between EOG Resources (Operator) and bpTT—produced first gas. Both Cypre and Mento are now contributing to T&T’s production numbers.
The 2027 cluster
The Trinidad energy industry is anxiously awaiting 2027. There are four projects either under active construction or being drilled, all targeting first gas in 2027.
Ginger (bpTT): bpTT took final investment decision on Ginger in March 2025. Four subsea wells tied back to the Mahogany B platform, about 50 miles off the southeast coast, with peak production capacity around 370mmscfd. Drilling is continuing through 2026.
Aphrodite (Shell): Shell sanctioned Aphrodite in June 2025. A single subsea tieback routed through the Dolphin platform in Shell’s East Coast Marine Area, targeting around 107 mmscfd at peak.
Coconut (bpTT/EOG): Another bpTT/EOG joint venture under a similar structure to the Mento arrangement.
Manatee (Shell): Shell took final investment decision on Manatee in July 2024. The field holds an estimated 2.7 trillion cubic feet of gas reserves and since sanctioning, Shell has upgraded the pipeline from a 24-inch to a 32-inch pipeline increasing capacity from 700 mmscfd to 1,000 mmscfd. This capacity upgrade suggests increased confidence in the project’s long-term potential.
When you put Ginger, Aphrodite, Coconut, and Manatee together, you have a meaningful volume of new gas coming into the system within the next 18 months. Note that these projects likely require a ramp up period and thus may not deliver peak rates in 2027.
The legislation that could unlock more
On top of the active development projects, there is a piece of legislation that has not received as much attention as it deserves.
The Finance Bill passed in June 2026 updated the Petroleum Act and Petroleum Taxes Act to introduce targeted fiscal incentives for what the law now defines as marginal marine gas fields, specifically offshore shallow-water fields with recoverable gas resources of 300 bcf or less.
Under the previous legislative regime, many of these smaller fields were economically challenging to develop. The new legislation reduces the royalty rate on certified marginal marine gas fields. To qualify as marginal, a field must be officially certified by the Minister of Energy, demonstrate an IRR below 15% as a standalone project, and have commenced production after January 1, 2026.
These fields are not individually large volumes, but they are cumulative, and represent gas that would otherwise stay in the ground permanently. For mature areas where existing infrastructure is sitting nearby at low utilisation, that is a meaningful incentive. Let’s keep a close eye on how these changes actually incentivise field development.
The cross-border picture
Dragon and Loran both involve Venezuelan gas that could flow to Trinidad. Dragon sits entirely in Venezuelan waters with plans to pipe production to Shell’s existing Hibiscus platform, while Loran is the Venezuelan side of the same geological reservoir that Shell is already developing as Manatee in Trinidad’s waters. In both cases, the gas is Venezuelan and the politics have been complex. However, the opportunity is significant.
I wrote a detailed piece on Dragon’s development pathway in March 2026 with the core message being that political resolution is not the same as gas in pipe. The timeline from licensing to first gas runs through commercial negotiations, detailed engineering, procurement, drilling, and commissioning. Even with good political conditions, first gas in a realistic scenario takes several years from the moment things get moving in earnest.
The political conditions have improved meaningfully. Following developments in Venezuela in January 2026, the new interim government has been considerably more open to energy investment. Shell received a new OFAC licence in October 2025. Shell’s CEO Wael Sawan said at CERAWeek in March 2026 that the company could greenlight up to two Venezuelan projects this year if fiscal and legal frameworks come together. A final investment decision on Dragon could come by end of 2026, and Trinidad’s energy minister has said he hopes to see first gas in Q4 2027 at around 350 mmscfd.
More recently, just days before I write this, Venezuela granted Shell a licence for the Loran field, the Venezuelan side of the cross-border Loran-Manatee reservoir. Loran holds an estimated 7.3 trillion cubic feet of gas. Combined with Manatee’s 2.7 trillion cubic feet on the Trinidad side, the integrated cross-border system represents roughly ten trillion cubic feet. That is a different order of magnitude from anything else in the near-term development portfolio. If Dragon and Loran both progress, the supply picture starts to look transformational.
I remain cautiously honest about the timelines. The complex politics are better than they were, mainly following the change in Venezuela’s political leadership in January 2026, but I expect the road ahead to be bumpy at best. OFAC licensing, commercial negotiations, mandatory US company participation requirements, and the sheer complexity of cross-border development all sit between where we are today, and production. MOUs are not the same as gas-in-pipe. However, progress is real and Shell is extremely competent at complex energy developments.
The longer bets
Calypso, operated by Woodside Energy with bpTT holding a 30% stake, is a deepwater gas field sitting around 220 kilometres off the coast of Trinidad in 2,100 metres of water. The field holds confirmed reserves of 3.5 trillion cubic feet. Commercial terms between Woodside and the Government were agreed in February 2025, and the project is expected to move toward a final investment decision by end of 2026, with first gas realistically around 2031 at peak production of 700 mmscfd. This is the big deepwater prize that could sustain T&T’s gas economy into the next decade.
Then there is ExxonMobil’s TTUD-1 block. A Production Sharing Contract was signed in August 2025, with 3D seismic survey starting in January 2026, covering an ultra-deepwater block of more than 7,000 square kilometres off the east coast in water depths exceeding 2,000 metres. Survey completion is targeted for July 2026, after which data interpretation begins and potentially two exploration wells follow. If there is a commercial discovery, we are realistically talking first gas well into the 2030s. This could be a valuable exploration bet, not a near-term supply solution. ExxonMobil’s track record in the neighbouring Guyana basin, where their Stabroek block has yielded over 11 billion barrels of recoverable resources, means their interest in Trinidad’s geology is noteworthy.
There remain some challenges…
The picture above is genuinely optimistic relative to where T&T was in supply conversations two or three years ago. Optimism without honesty, however, is just good PR.
Gas price economics remain complicated. The upstream requires gas prices that justify deepwater and complex development costs. The downstream players, as I have explored in earlier pieces on Point Lisas economics, have price ceilings that limit what they can pay for gas. There is not a lot of deal space here, and agreeing to pricing that works for both parties will decide which projects get built and which potentially stall.
Execution capacity is a real constraint. Drilling rigs, pipelay vessels, fabrication yards, environmental permitting processes, and skilled contractors are all finite resources. One or two projects at a time is manageable. Six or seven running concurrently is challenging at best.
The cross-border projects carry specific risks that the domestic ones do not. The complexity of Dragon and Loran has been reduced but has not gone away.
And Calypso, the biggest single prize in the medium-term portfolio, still needs to clear a final investment decision in an environment where deepwater economics remain challenging and Woodside is actively simplifying its global portfolio.
What this all means
The supply activity I have described in this article should be thought of in the context of the idled plants and curtailed production. Atlantic LNG and the Point Lisas plants have the infrastructure, the workforce, and the global customer relationships to be competitive. What they require now is a steady supply of suitably priced gas volumes.
The projects coming in 2027 start to address that. The marginal-field legislation makes previously stranded smaller volumes more viable. The cross-border picture, following the change in Venezuela’s political leadership, has improved in ways that would have seemed unlikely 18 months ago. Calypso and ExxonMobil’s deepwater block represent a credible pipeline beyond that.
However, we shouldn’t get complacent. Projects get sanctioned but gas-in-pipe is something else entirely, as I have written about at length elsewhere. The idled plants at Point Lisas did not all shut down overnight, and they will not all restart overnight either. That is worth saying clearly, and without the spin that tends to cloud PR announcements.
The fundamentals are moving in the right direction. Let’s remain cautiously optimistic about what the future brings to the local energy sector.
Jason Chatoor is an independent global energy consultat and co-founder of lowcarbonconsultantsltd.com