Related Articles
Forward article link
Share PDF with colleagues

Shale forces rethink in Trinidad and Tobago gas market

The Caribbean producer could have suffered more than most with the rise of US shale output. While it has adapted in the short term, to secure its place in the new-look global gas market, Trinidad and Tobago must develop a new, long-term strategy

Trinidad and Tobago’s economy is powered by natural gas. The industry accounts for about half the country’s GDP, generates nearly two-thirds of the government’s revenues, attracts most of its foreign investment and lines the sovereign wealth fund. The country’s decision to export its gas has served it well, making it one of the wealthiest nations in the Caribbean.

But the surge in US shale-gas production, a wave of new liquefied natural gas (LNG) export projects around the world and major gas discoveries offshore east Africa and elsewhere have ushered in a new era for the gas sector. The assumptions upon which Trinidad and Tobago’s industry were based no longer apply, forcing the country to rethink its energy strategy to ensure its future.

Atlantic LNG, the 3 million tonnes per year (t/y) production train and export terminal, started operations in 1999 and is the heart of Trinidad and Tobago’s gas industry. The project, the first LNG export terminal in the Atlantic basin, was developed to be a niche supplier to the northeast US. 

But the project - now owned by a consortium that includes BP, BG Group, Repsol, state-run NGC Trinidad and Tobago and the China Investment Corporation - quickly outgrew its modest origins. Further gas discoveries by BP and BG Group, as well as the prospect of rapidly rising demand in the US and Europe prompted the plant’s expansion. Atlantic LNG’s 3.3m t/y second train, started production in 2002 and train three, also with capacity of 3.3m t/y, started production the following year. A 5.2m t/y fourth train started deliveries in 2006, bringing the plant up to its current capacity of 14.8m t/y.

At the time, the project’s future looked certain. The US Energy Information Administration (EIA) forecast in its 2006 Long-Term Energy Outlook that US LNG imports were set to rise rapidly, from 710bn cf in 2005 to 3.05 trillion cf in 2015 before rising to 4.36 trillion cf in 2030. If you could produce LNG, it was assumed, the US would buy it. Trinidad and Tobago’s location and record as a reliable supplier to the US put it in a strong position to capitalise on the US’s seemingly insatiable LNG demand. The Atlantic LNG consortium planned to continue its expansion, carrying out feasibility studies for potential fifth and sixth trains.

Less than a decade later, the future is anything but certain. As recently as 2004, Trinidad and Tobago sent 463.68bn cf of LNG to the US, 95% of its total LNG exports. But the surge in US domestic shale-gas production has caused a collapse in the country’s LNG demand; making the forecasts from a few years ago look hopelessly misguided. The LNG import terminals that dot the US Gulf Coast and eastern seaboard now sit mostly idle, or are being converted to export terminals. In 2011, Trinidad and Tobago sent just 129bn cf of LNG to the US, around 20% of its exports, and that figure is falling fast. “We expect US demand for our LNG to eventually fall to zero,” Trinidad and Tobago’s energy minister Kevin Ramnarine told the American Gas Association in a presentation in October last year.

Crisis management

So far the country has weathered this potential crisis better than expected. The key has been Trinidad and Tobago’s success at finding find new markets. Atlantic LNG sent gas to just three countries - the US, Spain and the Dominican Republic -  in 2000, its first full year of operations. “People believe the collapse of the Henry Hub price is killing [Trinidad and Tobago]. It’s not killing Atlantic. Why? Three to four years ago, 80% of Atlantic’s LNG was sold to the US. Today, it’s less than 20%. We sell to China. We sell to Japan, Argentina, Spain, to over 20 countries,” Atlantic LNG chief executive Nigel Darlow said in a speech in November.

Lower demand from the US has, in fact, been something of a blessing, allowing Trinidad and Tobago to seek higher-priced deals from energy-hungry customers in Asia and South America. The US supply gut has depressed gas prices. Trinidad and Tobago earned as much as $12.90 per thousand cf (‘000/cf) for LNG shipments to the US when natural gas prices spiked in the summer of 2008, according to EIA data. By October 2012, that had fallen to $3.28/’000 cf.

As US prices have fallen, though, Asian and Latin American prices have risen. Asia spot prices have traded between $13/’000 cf and $18/’000 cf over the last year as Japanese demand surged since the Fukushima disaster forced the country to shut in its nuclear power generation capacity. Rising demand for LNG in Argentina and Brazil, meanwhile, has kept prices in Latin America between $11/’000 cf and $15/’000 cf in the same period. During the last quarter of 2012, Trinidad and Tobago earned between $10.30/’000 cf and $12.25/’000 cf for its LNG, according to Argus data, far higher than if it was still wholly reliant on the US.

These higher prices have helped offset lower exports over past two years. LNG exports fell by 15% from 2010 to 2011, from 720bn cf to 623bn cf, according to government data. And the slide continued into the first half of 2012. LNG production in  the first six months of 2012 was down 4.9% from the same period in 2011.

The government blames operational problems for the fall in available gas supply. BP, which produces about 55% of the country’s gas, has shut in some of its Trinidad and Tobago production as part of a post-Macondo safety and operations review.. Production, while still back at pre-maintenance levels, bounced back somewhat in the second half of 2012, as BP brought a number of wells back on stream. Government data showed LNG production for July-November up 9% from the previous year, and production for the year looked set to post a modest gain over 2011. Nevertheless, BP’s maintenance programme is expected to constrain output into 2014.

The global gas market’s broad direction bodes well for Trinidad and Tobago. Natural gas is seen by many as a fuel of the future – it is abundant, generally cheaper and more reliable than renewable energy and cleaner-burning than oil and coal. The International Energy Agency (IEA) forecasts global natural gas demand to grow by nearly 50% by 2035, from around 120 trillion cf in 2012 to 177 trillion cf. That is a big opportunity for Trinidad and Tobago.

The country’s first challenge will be to ensure that it has sufficient reserves to continue as a major gas exporter. The trend, though, is worrying. Since the country became a gas exporter in 1999, reserves have fallen by a third, from 21.1 trillion cf to 14.1 trillion cf, according to BP data. Very little exploration took place over the last decade. The government did not aggressively promote new acreage and  industry complained that fiscal terms on offer were not attractive enough for riskier deep-water exploration.

But there are signs the country may be turning a corner. After disappointing deep-water licensing rounds in 2006 and 2010, the 2012 round was a resounding success. The auction attracted bids from deep-pocketed players, including BHP Billiton, BG Group, Centrica, Cairn Energy, Kosmos Energy and Socar. BHP Billiton swept the board, winning all four deep-water blocks on offer. The Australian company will spend at least $546.82 million dollars on first-phase exploration, including a 5,330 square km  3-D seismic survey and at least six exploration wells.

Key to the round’s success, said consultancy Wood Mackenzie, was the government’s decision to raise the cost recovery ceiling from 60% to 80%, removing some of the risk from frontier deep-water exploration. The country also lowered the Petroleum Profit Tax from 50% to 35% for deep-water projects.

BP’s recent Savonette discovery, the largest in nearly a decade, shows there could be much more gas offshore. The British supermajor says Savonette’s gas-in-place is around 2 trillion cf, enough to potentially boost reserves by a quarter.

To encourage further exploration, Trinidad and Tobago  will have to ensure secure long-term markets are available for its gas. Atlantic LNG’s supply contracts start to expire in 2018. Negotiations for future contracts need to get under way shortly. 

Asia is a major opportunity for Trinidad and Tobago. The region is expected to account for much of the growth in gas import demand and prices are high. The widening of the Panama Canal, expected to be completed in 2014 or 2015, will improve the economics and logistics of shipping gas to Asia.

But Trinidad and Tobago will face stiff competition as LNG exporters around the world are also targeting Asian markets. Australia is targeting north Asian markets, with about $200bn beinginvested in export capacity. Huge investments are also expected in East Africa, western Canada and the US Gulf Coast to ship gas to Asia. Shipping costs from Australia, Canada and East Africa are far cheaper than those from the Caribbean. It costs about $1.25/’000 cf to ship gas from Australia to Japan, according to industry estimates. From Trinidad and Tobago to Japan, shipping costs rise to more than $4/’000 cf.

Low cost

Atlantic LNG does have the advantage of a lower cost base. The plant was built when LNG capacity construction costs were much lower than they are now. Atlantic LNG cost about $400 per tonne of annual capacity. Most new Australian projects are on track to cost at least three times that. Atlantic LNG, then, could undercut those new projects on price. It could also be in a position to offer non oil-linked contracts, which Asian buyers are keen to sign, but most sellers say they cannot afford. This could cost Atlantic LNG some revenue, but it would secure the country’s place in the world’s fastest growing market.

Trinidad and Tobago is also looking south to Argentina and Brazil. Both countries have seen their demand soar in recent years and have added new floating regasification capacity to help meet this.  The long-term import demand outlook, though, is far less certain. Brazil has large untapped deep-water gas reserves and state-run Petrobras has stepped up efforts to explore the country’s onshore gas potential. Argentina, meanwhile, is thought to hold the world’s third largest shale-gas reserves. Exploration and development of those reserves has been slow, but the country hopes to be self-sufficient for gas within the next several years. Moreover, both countries import gas via pipeline from Bolivia, which, for both political and commercial reasons, they are likely to prioritise over LNG imports.

Trinidad and Tobago is also looking closer to home. The country already sends gas to the Dominican Republic and Puerto Rico, and with Jamaica and others looking to add LNG regasification capacity, new markets around the Caribbean are opening up. Gasfin, a company that develops mid-size LNG plants, has signed a Memorandum of Understanding with the government to build a $400m 500,000 t/y plant aimed at supplying Caribbean markets. As yet, Gasfin does not appear to have secured any feedstock or supply deals for the plant.

The government could also push ahead with the proposed Eastern Caribbean Gas Pipeline project. The pipe was first proposed in 2002, but has been slow to make progress, despite feasibility studies showing the project could be commercially and technically viable.  The first phase of the pipeline would connect Trinidad and Tobago’s gasfields with Barbados, and a subsequent phase would extend it  to  Saint Lucia, Martinique, Dominica and Guadeloupe.

UK firm Centrica has an innovative solution for the estimated 600bn-1.3 trillion tf  of gas it found at Block 22. Rather than feed the gas to Atlantic LNG, which is fully utilised, or pipe it to regional markets, Centrica has decided to set up a small-scale compressed natural gas (CNG) export terminal, which will ship CNG to local markets.

Finally, Trinidad and Tobago is likely to try to boost domestic utilisation of its gas. The country currently consumes around 40% of its gas production, which is used for electricity generation as well as petrochemicals feedstock. An important step in expanding its domestic use will be progress on a proposal by China’s Sinopec and Saudi Arabia’s Sabic to invest more than $5bn in a methanol plant. Few details of the project have been announced, but in investment terms it would be one of the largest industrial projects ever developed in the country.

Also in this section
Zama oil find targets 2020 FID
17 January 2020
Upgraded resource estimate from Mexican field boosts hopes of a financial decision, but a serious potential roadblock remains
PNZ patch-up raises offshore gas hopes
17 January 2020
Belated reconciliation over acreage shared with Saudi Arabia offers relief for Kuwait's flagging oil expansion efforts
Russian oil hits another peak
16 January 2020
The country’s 2019 production reached a further post-Soviet high, marking another year Moscow fell short of cuts promised to its Opec partners