Trinidad and Tobago analyses downstream and upstream energy segments

The company Atlantic operates the most prominent downstream processing plant in T&T. In economic terms, it represents more than half of the output value of the refining industry. The plant is a four-train gas liquefaction facility located at Point Fortin in the south-west of Trinidad. It is the sixth-largest liquefied natural gas (LNG) production facility in the world, and the largest in the western hemisphere.

The operating company was set up in 1995 as a joint venture between four major oil companies and the government of Trinidad and Tobago. Train 1 began operating in 1999, followed by Trains 2 and 3 in 2003, and then by Train 4 in 2005. Each train is controlled by a separate holding company, composed of various member companies. The four trains use a system known as the Phillips Optimised Cascade Process that cools natural gas in various stages until it ultimately liquefies. Combined daily capacity adds up to 100,000 cu metres of LNG. Output is shipped mainly to South America, Asia and Spain. The facility has two 700-metre jetties that allow LNG tankers with capacity of up to 145,000 cu metres to dock and load.

Shell Holdings

In 2015 the UK’s Shell acquired the assets of BG Atlantic Finance in T&T. By combining the stakes it already directly owned and those it acquired via the takeover of BG, Shell became the single biggest investor in Atlantic. It is the largest single shareholder in trains 2, 3 and 4, and a minority shareholder in Train 1.

This strong presence by Shell led analysts to question whether fears of long-term gas supply shortages were exaggerated. In an interview with The Oil and Gas Year in August 2016, Kevin Ranmarine, the former minister of energy and energy affairs, asked, “If Trinidad and Tobago was running out of gas, why did Shell come into Trinidad so strong? Because they bought out Repsol’s assets in the Atlantic LNG facility three years ago, and now they have bought out BG’s assets.”

Gas supply agreements associated with Atlantic’s operation are set to expire in 2018. The government has said that as part of negotiating new agreements it would like to increase its ownership share in Train 1, which currently stands at 10%.

Exports

In the first half of FY 2015 (the six months to March 2015) Atlantic exported 468.5trn British thermal units (btu) of LNG to 21 different markets. In that time, the top destinations for T&T LNG were Chile (22.4%), Argentina (14.2%) and Brazil (11.9%). Other destinations include the US and Spain.

However, Atlantic is facing increased competitive pressure on its export business. Philip Farfan, a geologist at consultancy PetroCom, told OBG that when T&T started exporting LNG it had a strong position supplying Atlantic Rim markets, particularly the US and Spain. Over time, however, the Atlantic region became much more competitive, particularly with the development of shale gas production in the US. T&T adjusted to some extent by shipping more LNG to South America. The enlargement of the Panama Canal in 2016 also made it easier to ship LNG to markets in the Far East, which tend to pay premium prices for LNG.

Another factor with the potential to bring change is the climate-change scepticism of the new administration of US President Donald Trump, which might lead to an increase in the wellhead flaring of natural gas. In some scenarios this might even be favourable to T&T by reducing oversupply.

Other Processing

The gas that is not sent to Atlantic for liquefaction into LNG is processed by the stateowned National Gas Company (NGC) and its subsidiary Phoenix Park Gas Processors Ltd (PPGPL) for industrial users in T&T. The main customers are methanol and ammonia plants, most of which are located in the Point Lisas Industrial Estate. In 2010-15, 33.2% of the gas was shipped to ammonia plants, 31.9% went to methanol plants, 17.9% went to electric power generation, and 6% was shipped to iron and steel producers. Other uses included cement and urea manufacturing, small consumers and gas processing. PPGPL receives the raw natural gas and extracts propane, butane and natural gasoline before returning the processed gas – largely methane – to the NGC for onward distribution and sale.

Since 2011 operations in the downstream processing plants have been affected by gas supply shortfalls. These curtailments, particularly when not known in advance, have forced temporary closures of ammonia and methanol plants for unscheduled maintenance work. The impact of curtailments has been mixed. Methanol output was unaffected in 2013 despite some unscheduled maintenance activity, but declined in 2014 and recovered marginally in 2015. Ammonia production, on the other hand, was impacted in 2013 but recovered in 2014. Both ammonia and methanol were negatively affected in 2016.

New Plans

Expansion of the country’s petrochemicals industry has been under discussion for a number of years, and is currently in the construction phase. The upgrade involves a $1bn investment in a facility to produce methanol and dimethyl ether (DME) at the Union Industrial Estate in La Brea, in southern Trinidad. Output is planned at 1m tonnes of methanol and 100,000 tonnes of DME per annum.

Methanol is used as an input for a number of other petrochemicals and demand tends to follow the general GDP cycle. Methanol can also be used as a clean-burning fuel, with demand expected to increase, particularly in China. DME has a wide variety of industrial applications, including in sprays, solvents and coolants, and it too can be used as a fuel in a mix with liquid petroleum gas. The plant is being built by Caribbean Gas Chemical, a consortium formed by Mitsubishi Gas Chemical (26.25%), Mitsubishi Corporation (26.25%), the NGC (20%) and local conglomerate Massy Holdings (10%). A project development agreement was finalised in April 2015 and construction of the plant began in September of that year. Completion is expected in late 2018 or 2019.

The agreement covering the operation of the plant has been the subject of some renegotiation. According to press reports there were concerns over potential liabilities of the parties in the event of shortfalls in gas deliveries. Concerns about supply were also brought into sharp focus in March 2017, when Methanol Holdings elected to close two of its five methanol plants due to ongoing gas supply shortages and a failure to reach a satisfactory solution in negotiations with the NGC.

Continuing Supply

Maintaining the supply of gas to the country’s downstream processing plants is considered a high sector priority. Gerry Brooks, chairman of the NGC, said that he is not ruling out the possibility of importing gas to cover the supply deficit if needed. Answering journalists’ questions in February 2017, he did not comment on where the gas might be imported from, but said that with gas prices expected to stay low until 2020 at least, there might be various sources of supply worthy of investigation.

Dominic Rampersad, president of PPGPL, outlined some of the wider strategic choices facing the industry. He told OBG that one of the biggest shifts in the downstream gas sector had been the move from a seller’s to a buyer’s market in the Atlantic Rim countries. This was caused by the rapid increase in US shale gas production – the US was becoming a net exporter of gas – and the widening of the Panama Canal to accommodate gas tankers. Two years ago Saudi Arabia said that shale producers would not be able to make a profit when oil prices fell below $75 per barrel. “But somehow they are operating below $50 a barrel,” Rampersad said, emphasising the ability of US producers to increase their efficiency and competitiveness.

Being Flexible

In his analysis, this means T&T needs to build up and price a range of options to improve its overall negotiating position. Given the country’s gas shortages, one option might be to take advantage of the buyers’ market and import needed gas. This would be viable if the gas could land at Point Lisas at a price that would allow downstream companies to process it and make a reasonable margin. “Cost curves are trending down around the world, so we cannot allow ours to trend upwards,” Rampersad told OBG.

He recognised that another option would be to further incentivise upstream gas producers operating in T&T, but he said the government would need to adopt a strong negotiating position. “As a country we need to build options. We have domestic supplies; we have cross-border supplies such as the Loran-Manatee field on the offshore border with Venezuela; we have across-the-border supplies such as the Dragon field in Venezuelan waters; and we have regional supplies such as shale gas imports,” Rampersad said. While incentivising upstream production is an option, the country needs to maintain negotiating leverage in its relationship with oil majors. This is done, for example, by assessing the costs and benefits of granting tax incentives upstream versus the costs and benefits of alternatives, such as importing shale gas. “We need to say to those upstream, ‘If you can get the price to this, we can do business,’ instead of them dictating the price at which they want to do business,” he said.