Trinidad and Tobago’s energy sector faces another difficult year before a potentially significant recovery in natural gas supply from 2027, energy economist andbusiness strategy consultant Gregory McGuire told Business Guardian on Tuesday.
McGuire’s reading of the energy data points to a genuine basis for the Government’s expectation of better gas availability in 2027, with several major upstream projects already sanctioned and targeting first gas.
But McGuire’s assessment is not a prediction of an easy recovery. The country is entering the 2027 fiscal year after losing major petrochemical operations, weaker gas production, reduced export earnings and significant employment losses. Several potential sources of future gas also carry commercial, geopolitical or development risks.
His central argument is that the 2027 improvement is credible, but conditional.
“When a government promises better days are coming, scepticism is the natural response, especially when the years in between are painful,” McGuire observed.
He pointed to the closure of major Point Lisas operations as evidence of the difficult position facing the economy.
Nutrien began shutting its Point Lisas nitrogen operations on October 23, 2025, putting about 1,600 jobs at risk. Methanex then idled its Titan methanol plant in June 2026 after its existing gas contract could not be renewed. That affected more than 100 jobs.
McGuire calculates that the two companies represented an estimated 135–154 million cubic feet per day (mmcf/d) of gas demand, equivalent to roughly 7 per cent of national supply.
The demand reduction provides some relief for the users still operating, but McGuire cautioned against interpreting it as evidence that the underlying gas shortage has been resolved.
“It is easing pressure on the remaining supply, but reflecting lost industry, not a solved shortage,” McGuire explained.
Gas production, the expert highlighted, has fallen from roughly 4.0 billion cubic feet per day (Bcf/d) in 2010 to about 2.6 Bcf/d today.
Domestic utilisation has also contracted, falling from 3.5 Bcf/d in 2015 to 2.4 Bcf/d in 2024. LNG consumption, historically the largest gas user, has roughly halved from 2 Bcf/d to 1 Bcf/d.
Ammonia utilisation has declined by 20 per cent, while methanol utilisation has fallen by 5 per cent.
The projects behind 2027
The most convincing evidence for a 2027 improvement lies in projects that have already moved beyond speculation.
McGuire identifies Shell’s Manatee and bpTT’s Ginger developments as the two most important near-term additions.
Manatee received final investment approval in July 2024 and is targeting first gas in 2027. McGuire puts its peak production at about 604 mmcf/d, with estimated resources of 2.7 trillion cubic feet.
Ginger reached FID in April 2025 and is also targeting first gas in 2027, with peak production estimated at 360 mmcf/d.
Coconut, a 50:50 BPTT-EOG development, received FID in August 2024 and is also targeting a 2027 start, although its production capacity has not been disclosed.
McGuire calculates that Manatee and Ginger alone could deliver close to 1 Bcf/d at peak.
That is significant against the estimated 1.5–1.6 Bcf/d required to operate Atlantic LNG Trains 2, 3 and 4 at nameplate capacity. Train 1 has already been decommissioned.
The calculation, he said, becomes more complicated if domestic industry returns.
Also the expert indicated that the restarted Nutrien and Methanex would once again compete for gas, while Pinnacle Steel and Vanadium’s proposed revival of the idle Point Lisas steel plant would create another demand source.
The steel project carries a proposed US$250 million investment, with first production targeted for late 2027.
McGuire therefore does not expect the three sanctioned projects alone to restore the country to its 2019, pre-pandemic level of gas utilisation.
His analysis points to Dragon, Loran and further exploration success as additional pieces that would be needed if T&T is to rebuild its previous industrial capacity.
Perenco’s consolidation of Woodside’s and bpTT’s mature fields is producing more than 400 mmcf/d, representing about 15 per cent of national output. Touchstone’s Cascadura operation is producing about 16.5 mmcf/d, with output rising.
McGuire regards both as important contributors to the existing production base, but not as equivalent to new upstream developments bringing additional gas into the system.
The International Monetary Fund’s projections provide another piece of evidence supporting the 2027 inflection point.
The IMF expects energy output to contract by 4.5 per cent in 2026, following a 0.5 per cent contraction in 2025, before GDP growth in the sector accelerates to 3 per cent in 2027 and averages 3.5 per cent in 2028 and 2029.
McGuire draws particular attention to the IMF’s linkage between the expected acceleration and projects such as Manatee coming online.
For him, that provides external validation for the view that 2027 could represent a material change in the country’s economic trajectory.
The supply risks
McGuire’s confidence in the 2027 outlook comes with an important qualification: projects can fail to reach production even after receiving final investment decisions.
The shelving of Shell’s Aphrodite development this week is the latest example.
Aphrodite received FID in June 2025 and was planned to deliver approximately 107 mmcf/d. Shell shelved the project after failing to agree commercial gas-sales terms with NGC.
McGuire considers Aphrodite relatively small compared with Manatee and Ginger, meaning its removal does not fundamentally undermine the broader 2027 outlook.
However, the development demonstrates the gap between sanctioning a project and actually delivering gas to the domestic market.
“A final investment decision does not guarantee delivery,” McGuire cautioned.
For McGuire, the Aphrodite experience also puts greater emphasis on the commercial terms governing new gas developments.
He identified geology and NGC’s pricing decisions as factors that can materially influence whether future supply reaches the market.
Longer-term exploration opportunities carry an even greater degree of uncertainty.
ExxonMobil’s deepwater programme on Block TTUD-1, east of Trinidad, covers more than 2,700 square miles in waters deeper than 6,500 feet. Up to US$21.7 billion has been proposed for the programme, with seismic results expected by the end of August 2026.
McGuire is reluctant to build those volumes into the near-term supply outlook because no discovery has yet been announced.
BP’s move to take full ownership of the Calypso block has created expectations about its potential, but McGuire points to the project’s early-stage status. There is no disclosed reserve estimate, development plan or FID.
He places both Calypso and TTUD-1 firmly in the country’s longer-term energy strategy rather than the immediate 2027–2030 supply equation.
Venezuela’s big question
Venezuelan gas represents potentially substantial upside, but McGuire warns that T&T cannot automatically claim those resources as part of its future domestic supply.
Dragon, operated by Shell, contains an estimated 3.5–4.2 Tcf, while Loran is estimated at 4 Tcf.
Both projects have faced licensing complications. Shell secured a two-year US Office of Foreign Assets Control (OFAC) licence for Dragon in October 2025, while General Licences 49 and 50 issued in February 2026 cleared Venezuelan operations involving Shell, BP, Chevron, Eni and Repsol.
McGuire sees the latest Loran arrangement as particularly significant.
In August 2026, Venezuela awarded the Loran Phase 2 development licence to a BP-led consortium involving UAE-based XRG and Qatar’s UCC.
NGC is not part of that consortium
McGuire contrasts this with the Cocuina-Manakin arrangement, where BP and NGC are partners.
That difference could influence where Loran’s gas ultimately goes.
Without NGC in the consortium, McGuire argues, there is less structural certainty that the gas will be routed through Trinidad and Tobago.
Alternative monetisation routes, including floating LNG, could become more attractive if they offer faster development or stronger commercial returns.
“Venezuelan gas is real, licensed upside down, but not guaranteed to Trinidad,” McGuire maintained.
That makes Venezuela an important part of the country’s long-term energy conversation, but not a volume that should be inserted automatically into the 2027 supply forecast.
The economic test
The ultimate test of the energy recovery will be its impact beyond production statistics.
McGuire identifies GDP, Government revenue, foreign exchange and jobs as the four key measures.
Energy’s direct share of GDP is projected to decline from 22.5 per cent in 2024 to about 20.7 per cent in 2026.
Government revenue has been more resilient, with energy revenue accounting for 9.9 per cent of GDP in 2025 and projected at 10.2 per cent in 2026. Higher energy prices have partly cushioned the effect of lower production volumes.
Foreign exchange presents a more serious concern.
McGuire estimates that the Nutrien and Methanex closures alone represent between US$500 million and US$700 million a year in lost export earnings.
That represents a structural loss to the current account, and he sees no convincing evidence yet that future gas reallocation will fully replace those earnings.
The approximately 1,600 jobs affected by Nutrien and more than 100 at Methanex he outlined represent immediate losses, while the new upstream projects are likely to generate hundreds rather than thousands of permanent operating jobs.
McGuire therefore expects the economic benefits of a 2027 energy recovery to become visible first through GDP, Government revenue and foreign exchange.
That creates a more complicated picture of what a turnaround will actually feel like for households and businesses.
For McGuire, the data supports the view that T&T has a credible route out of the current gas downturn, but not a guarantee of a return to the country’s previous energy position.
