T&T Patriots
The natural gas downstream petrochemical sector in Trinidad and Tobago(T&T) once hailed as a model to emulate for countries eager to develop their natural gas resources has now found itself in a survival mode. The sector is dealing with a confluence of challenges:
* There is ongoing uncertainty in consistently receiving an adequate natural gas supply;
* There are challenges with the renewal of natural gas contracts related to the duration of the contracts;
* Changes to key terms/conditions in the contract and increases in prices; and
* There are strong headwinds in the traditional US and European ammonia, methanol, urea and steel markets due to CBAM , tariffs and anti-dumping challenges.
The external markets are beginning to recognize and comment on the cracks that have developed in T&T’s natural gas downstream sector.
The latest edition of the international commodity market publication, Argus Ammonia, for February 2026 states the following: – “Producers in Trinidad have received gas contracts for higher prices for a one-year term only, according to a producer in the country. The contracts also suggested reduced gas supply. The reduced supply and shorter term make operations difficult for producers in the country without multiyear visibility to plan major maintenance.”
It is now clear that the shutdown of Nutrien in October 2025 was a harbinger to the challenges facing this important sector.
Recent announcements of the significant increase in the price of natural gas from the National Gas Company (NGC) to the light industrial consumers (LIC) and to Phoenix Park Gas Processors Ltd give an indication of where the floor price is settling, and it seems to be aroud about US$5.30 per mmbtu with provisions for annual escalation.
The US benchmark Henry Hub price was US$5.27 per MMBTU last month, which is a peak, driven by extreme colder temperatures across the US and expected increases in heating demand. On Friday, natural gas at Henry Hub was US$3.22 per mmbtu and prices are expected in the spring and summer to recede to the typical values of under US$3.50 per mmbtu.
When T&T’s natural gas price is compared against normally expected prices in the US, it is clear to see that we have fallen in terms of competitiveness.
All the international downstream companies in T&T now have significant similar production facilities in the US due to the low natural gas price, abundant supply, and access to in-country markets. That risk mitigation action has been extremely important for international petrochemical producers to assure a competitive cost of production.
The downstream petrochemical industry in T&T is clearly on a slippery slope. The big question is whether the T&T energy policy and the actions of the NGC will serve to add friction and prevent a slide or to further lubricate the slippery slope and accelerate the slide.
Gas value chain
The natural gas value chain in T&T starts with exploration and production of natural gas, followed by the transportation and sale of the natural gas to downstream facilities to produce LNG, steel, ammonia, methanol, urea, propane, butane, and natural gasoline which are exported and for electrical power generation.
Natural gas in much smaller quantities goes to LIC downstream customers for manufacturing and other industries for example bricks, beer, absorption chillers for cooling buildings, crematoriums, bakeries etc.
Each entity along the natural gas value chain makes investments, takes risks, and expects to get a return on investment commensurate with those risks. The value chain survives once entities along the value chain achieve an acceptable return on their investment for their investors/shareholders considering the risks.
In the early stages of T&T’s natural gas industry in the mid-1970’s the upstream companies were sitting on significant proven reserves of natural gas with no markets. Their risk in producing the gas was low and their cost of production was low. The big risk at that time was in developing the infrastructure and the markets in T&T for the natural gas.
The Government of T&T (GORTT) with a vision of what was possible established the NGC and National Energy Company (NEC) and through those entities established infrastructure and markets for natural gas beyond Federation Chemicals, which was relatively small.
There were significant GORTT investments in pipeline infrastructure to transport the gas from offshore and across island to a newly developed Point Lisas Industrial Estate which was equipped with natural gas electrical power generation capacity and processing plants at Fertrin for ammonia production, TTMC1 and UCTT, which were for methanol and urea production respectively.
There was significant risk in developing the downstream industry and consequently the expected return had to be high to attract investors. GORTT had a pivotal role in de-risking the downstream sector that eventually blossomed and exploded in the 1990s and 2000s to substantially what it is today.
Now fast forward to mid-2010s and 2020s, the risk along the value chain has significantly changed. All the easy to find and develop lower risk gas has been depleted and what remains is more challenging and riskier development opportunities notwithstanding substantial improvements in exploration/finding technologies.
The net result is higher exploration, development and production costs for natural gas. The upstream exploration and production activity has therefore become more costly and riskier and that risk has been partially mitigated through the investment in LNG facilities which allow some upstream producers to directly market their gas internationally.
The petrochemical and steel downstream investors are facing the challenges mentioned earlier and are now in the higher risk category. The risk profile of the middle portion of the value chain for transportation, aggregation and sale has not substantially changed since the 1990s and 2000s.
A general principle of risk matching reward along the value chain seems to be a sound approach. Higher risk requiring higher rewards and lower risks lower rewards.
Today’s realities
Current actions of GORTT clearly indicate a continuing policy of attracting and facilitating upstream investment which is of critical importance to sustaining the natural gas industry. What is not clear is, what is GORTT’s downstream policy?
With limited information available, one could conclude from public information that the policy is to maximize the returns to T&T through extracting maximum returns from the sale of natural gas. That is a laudable goal for the citizens of Trinidad and Tobago. However, there are risks associated with such a policy. Let us never forget the parable of the goose and the golden eggs. How far are we willing to go to get those golden eggs? Are we willing to take the risk of killing the goose?
To illustrate the point of how precarious things currently are it could be helpful to understand the current economics of a T&T methanol plant. A
typical modern methanol plant requires 36 mmbtu of natural gas to produce one metric tonne of methanol. This is the natural gas required at optimum plant conditions i.e., receiving a consistent supply at its name plate capacity and with the plant running very smoothly with minimal unplanned outages.
Historically in the NGC natural gas contracts, there was a natural gas floor price, which was the lowest price that a downstream petrochemical customer would pay the NGC for gas received. NGC’s floor price corresponds to a floor FOB price on the commodity produced.
NGC had a pricing formula whereby the natural gas price would increase above its floor price when the methanol FOB price rises above its floor price. In that pricing formula there was downside protection for a methanol producer and upside opportunity for NGC through increases in natural gas prices when the FOB commodity price increases above its floor price.
The contractual FOB floor price of the commodity was set at a value that was unlikely the commodity price would fall below.
At the current NGC stated price of US$5.30/mmbtu, which is assumed to be a floor price, the natural gas cost is US$190.8 (36 X 5.30) per metric tonne of methanol produced.
The other significant cost of producing methanol is the normal operating and maintenance costs which for locations like T&T is around US$40 per metric tonne. Then there are major maintenance costs also known as turnaround costs which occur every four years on average and when amortised on an annual basis can be between US$10 and US$15 per metric tonne. Then there is the shipping cost for getting the product to market, which for the US market is roughly US$30 to US$35 per metric tonne and to Europe market is around US$50 per metric tonne.
Adding up all those costs, the cash cost for producing and getting methanol to market is US$270.8 to US$295.8 per metric tonne. This assumes no debt repayment costs on the facilities and almost perfect operations. If a facility has debt on 70 per cent of the total installed costs for its methanol facility, then the debt repayment could be US$30 to US$40 per metric tonne over the term of the loan assuming an interest rate of 6 per cent.
One needs to compare this total cash cost against market prices to get an understanding of likely profit before taxes. A good source of information on 10-year historical methanol market prices can be gleaned from a review of the 2024 Methanex annual report. From that Report the 10-year (2015-2024) average realized value was US$352 per metric tonne and for three of those 10 years, it was below US$295 per metric tonne.
Methanex is recognized as the current global leader and best in class marketer of water-borne methanol. The total cash cost of producing methanol in T&T at the new floor price for natural gas is US$270.8 to US$295.8 per metric tonne and if the average realized selling price is US$352 per metric tonne, then the cash margin is US$56.20 to US$81.20 per metric tonne.
T&T Patriots is a pseudonym for an executive who spent decades in T&T’s downstearm sector. He writes about additional risks of petrochemical production in T&T in next Sunday’s Business Guardian.
