Last week, I suggested that Trinidad and Tobago revisit its Natural Gas Master Plan. There were two reasons for this. The first is that the document itself is past the planning horizon of 2014-2024 and the second is that the assumptions made back then no longer resemble our current reality.
As mentioned last week there is a distinction between reserves and deliverability. Over the past decade, we were unable to move sufficient quantities of gas from beneath the seabed through the pipelines to satisfy Atlantic LNG, Point Lisas and electricity generation.
While over the medium term, this dynamic is evolving positively, the following bears repeating from last week because it is still relevant in the short term. In 2015, T&T produced approximately 3.84 billion cubic feet of natural gas per day. The Master Plan developed by Poten and Partners, was constructed around roughly 3.85 billion, even though the downstream portfolio could consume more than 4.2 billion. There was a structural capacity issue from the beginning.
Production averaged 2.541 billion cubic feet per day in 2025. Calculated from the Ministry of Energy’s monthly figures, the average during the first quarter of 2026 was approximately 2.425 billion. We are therefore allocating gas with about 1.4 billion cubic feet per day less than in 2015. This represents a decline of nearly 37 per cent.
In 2025, LNG used an average 1.116 billion cubic feet per day. Ammonia and methanol each used approximately 440 million, while power generation used 263 million. Those four uses absorbed about 96 per cent of the natural gas recorded as utilised.
Allocation is therefore not an abstract policy exercise. Gas supplied to one user cannot be supplied to another. A price below the value available from the next best use represents an economic subsidy, whether or not that subsidy appears in the national budget. Spreading unreliable volumes across too many plants may also create less value than supplying fewer, more efficient plants reliably.
In this environment, allowing industrial gas prices to reflect scarcity, reliability and the opportunity cost of use elsewhere is economically appropriate, even when the adjustment is unpopular.
Electricity must be treated differently. Reliable power is an essential public service before it becomes a commercial bidder for gas. Once essential requirements are secured, each industrial user should be reviewed to establish how its claim on the remaining gas produces the greatest national benefit.
Best use
Poten found that ammonia had generated the greatest benefit to T&T per unit of gas over the decade ending in 2014, with methanol moving above it in 2017. LNG lagged both.
This is sometimes interpreted as evidence that ammonia is inherently a better use of gas than LNG. It was not.
Poten concluded that LNG had performed poorly because of the commercial and marketing arrangements under which it was sold. Many Atlantic contracts referenced United States gas prices even after shale gas had depressed Henry Hub and the United States ceased to be the relevant market for much of our LNG. Cargoes reached higher priced destinations without the corresponding value flowing fully back to Trinidad and Tobago.
“Transfer pricing” is often used loosely in this debate. Poten identified the contract structure, reference markets and division of marketing value along the LNG chain. Whatever label is applied, the national problem was that significant value generated from our gas was being captured elsewhere.
Change those arrangements and the ranking can change. Poten expressly concluded that LNG could have performed at least as well as ammonia under different terms and could become the most attractive monetisation option when the old agreements expire.
The Train 1 negotiations completed in 2018 represented the first major adjustment. The agreed free-on-board pricing formula referenced one third Brent, one third the Japan Korea Marker and one third the United Kingdom’s National Balancing Point rather than Henry Hub. During the wider restructuring negotiations, Government stated that the new formulae would be market reflective and patterned on this approach.
The final restructuring agreement was signed in December 2023. Trains 2 and 3 entered the new commercial structure on October 1, 2024, and Train 4 is scheduled to enter on May 2, 2027. NGC acquired a 5.7 per cent interest in the Trains 2 and 3 phase, rising to 10 per cent when Train 4 joins. Its projected LNG offtake entitlement is expected to increase from approximately three conventional cargoes to almost 20 by 2027.
Unitisation allows the Atlantic trains to be operated with greater flexibility and efficiency. It also gives the State, through NGC, a larger equity position, more access to processing capacity and cargoes, greater opportunity to earn marketing income and pricing exposure intended to reflect international LNG and oil markets more appropriately. NGC shipped its first two cargoes from Trains 2 and 3 under the restructured arrangements in November and December 2024.
Atlantic may therefore have moved from being one of the lesser rewarding major uses of gas under the arrangements Poten examined to being the strongest commercial use of incremental supply today.
I use the word “may” because the public record isn’t as clear as it should be so this is a best estimate and if someone steps forward to prove this assumption incorrect then we are better off for it. That is the whole point of the argument to review the Master Plan.
US changes
While our LNG economics were changing, so too was the competitive environment facing Point Lisas. The United States Energy Information Administration expects marketed American natural gas production to average a record 122.5 billion cubic feet per day in 2026, compared with 118.5 billion in 2025. Its August forecast placed the Henry Hub spot price at an average US$2.87 per million British thermal units during the third quarter, reflecting robust production, reduced LNG feedgas demand and high storage.
Henry Hub is a wholesale benchmark rather than the delivered price paid by every American factory. There are regional price differences to consider. Even so, it illustrates the scale, liquidity and gas cost environment available to North American industry.
Recognize that natural gas is not merely fuel for ammonia, urea and methanol. It is a principal raw material. Ammonia producers use natural gas as both chemical feedstock and fuel. Urea is subsequently made from ammonia and carbon dioxide. If you read US listed company filings as I often do, you will know that plants in the US have access to abundant, competitively priced gas through pipelines connected to major trading hubs. A North American producer can therefore purchase reliable gas within a vast continental network and sell into a globally priced commodity market.
Point Lisas was built on a version of that value proposition. Trinidad and Tobago had abundant gas, established plants and proximity to a United States market requiring imports. Shale reversed the relationship. The United States acquired the gas advantage while our replacement molecules became progressively more difficult and expensive to deliver.
We are not totally uncompetitive in this space. Sunk capital, plant efficiency, integration, established logistics, and experienced workers can preserve important advantages. But it does mean that Point Lisas can no longer compete in the same manner as was the case fifteen years ago.
The evidence is visible. Nutrien completed a controlled shutdown of its Trinidad nitrogen operation in October 2025, citing port restrictions and a lack of reliable and economic natural gas. Methanex idled Atlas in September 2024 when its legacy gas agreement expired. In June 2026, it decided to indefinitely idle Titan after it and NGC could not agree on a commercially acceptable pricing arrangement, although NGC stated that gas volume was not the issue.
The cases are not identical, but the message is difficult to avoid. Keeping a plant standing is not the same as keeping it competitive. Preserving every historical plant cannot be the objective of T&T’s national gas policy. You would expect a former Energy Minister to understand this last point, yet his public commentary belies such insight. That is concerning because it creates “noise” that was once deemed “unpatriotic”.
The most efficient ammonia and methanol plants may justify firm gas allocations because their existing set up can still create national value. However, a country dependent on gas should not compound that vulnerability by focusing on one or two major industries. The objective should be a deliberately constructed portfolio in which every use earns its place.
Point Lisas may no longer compete primarily as a cheap feedstock location. But it possesses something potentially as valuable: ports, pipelines, power, industrial land, skilled people and major assets that other jurisdictions would need years and billions of dollars to reproduce.
We will discuss that in more detail next week.
Ian Narine is a financial consultant who understands that portfolio allocation is the bedrock of good investment returns. Please send your comments to ian@iannarine.com.
