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    Atlantic LNG [NGW Magazine]


First gas from a pair of new projects had revived Trinidad and Tobago’s LNG export plans, but poor results from a recent infill drilling programme have put Atlantic LNG under pressure again. [NGW Magazine Volume 4, Issue 11]

by: Ryan Stevenson

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Atlantic LNG [NGW Magazine]

The start-up of BPTT’s Angelin field in February was expected to spark a rebound in Trinidad & Tobago’s natural gas sector. This was a boost for Atlantic LNG, which has four trains with capacity adding up to 14.8mn mt/yr, though its exports have been well below that level in recent years.

Any momentum that was building earlier this year has been stymied, however, by recent poor infill drilling results at BPTT’s Cannonball and Cashima fields. This has again put pressure on feedstock supply to the LNG plant and could affect its performance over the coming few years.

Angelin activated

The launch of output from Angelin in the first quarter added to the impetus generated by the production start-up of the Juniper field offshore the Caribbean country in 2017.

Angelin’s peak output is estimated at 17mn m³/day, with Juniper around the same mark at 16.7mn m³/d.

The combined production from the fields helped expedite Trinidad’s climb out of the doldrums after 2014, when production sank and feedstock constraints caused disruption to LNG exports and power generation.

BP’s annual statistical report shows the country’s gas production peaked in 2010 at 43.5bn m³, but a failure to replace depleting reserves and disputes over the exploitation of gas fields in border territories resulted in a chronic decline. Output sank to 40.9bn m³ in 2014 before falling further to a nadir of 33.8bn m³ in 2017, when a degree of stabilisation was achieved, largely from Juniper’s initial contributions.

Angelin is 60 km off the southeast coast of Trinidad in water depth of 65 metres, with gas flowing from the platform at the field to the Serrette hub through a new 21-km pipeline. The start-up was a swift turnaround for BPTT, with the drillship only arriving last autumn, and adds to the 22 new upstream projects the company has brought online in Trinidad in just over three years.

Angelin is BPTT’s next step in fulfilling its long-term development plan in Trinidad which it said could “potentially include up to $8bn of investment in several more major projects over the next 10 years.”

It was anticipated that production from Angelin and Juniper would offer some stability to Atlantic LNG, one of Trinidad’s most important export revenue-earners, and an important provider of liquidity in the North Atlantic trading market. Trinidad exported 12.4mn mt of LNG in 2018, with this figure initially forecast to expand by around 3% in 2019.

Infill fail

The poor results recorded after recent infill drilling in the Cannonball and Cashima fields, however, have raised questions about whether growth can be maintained next year and beyond. “Recent disappointing results from our infill drilling programmes have had a material impact on our forecasted production especially in 2020 and 2021,” bpTT said on May 11. “This means there are challenges to our supply of gas to Train 1 after 2019. BP along with Atlantic and its shareholders are working through options for the future of the train. The other three trains remain unaffected.”

The company said it had anticipated supplying up to 8.5mn m³/d of gas from the fields to Train 1 in 2020 and 2021 under a new sales agreement that has not yet been signed. Negotiations on the new agreement kicked off Anglo-Dutch major Shell and BP in London in April 2018 but still have not come to a conclusion.

BPTT, which is the biggest gas producer in Trinidad with average output of around 59mn m³/d, has said it will look to offset the effect of the lower output from Cannonball and Cashima on its overall production by maximising yields from its existing fields and ramping up output from new ones. But news the company’s output could be 15% lower this year than forecast because of the problems is a blow, even prompting some to speculate that Train 1 might have to be mothballed.

This concern is overstated, believes Elena Nikolova, a Latin America upstream analyst that focuses on Trinidad at Wood Mackenzie, a consultancy.

“It’s hard to see how an entire train would be mothballed based on the result of a single infill well, so it’s important to understand what the results of the campaign were,” she told NGW. “I think there’s probably more going on with the whole Train 1 contract extension negotiations perhaps. Until we see an ultimate end to them it’s hard to say.”

The train received a 20-year tax holiday from the government when it began operations in 1999. With the tax break due to end this year, the economics of the project are under scrutiny in the contract talks, and problems surrounding future feedstock will have turned up the heat on the negotiators.

Dashed hopes

The forecast for the plant in the first quarter of this year had been far more upbeat. It was anticipated that Angelin and other new projects such as Cassia C and Matapal would translate into better utilisation of Atlantic LNG’s capacity.

Cassia C is the third BPTT platform on the Cassia field in the Columbus Basin. The new infrastructure will handle 34mn m³/d of gas, which will be compressed and exported. The Matapal work, meanwhile, will develop gas resources found through the Savannah exploration well, drilled in 2017. First gas from this is due in 2022, with production capacity of 11.3mn m³/d, flowing from a three-well development to the Juniper platform.

Nikolova is upbeat these projects and others will ensure the LNG terminal remains busy. “Our forecast is that there will be increased utilisation capacity at Atlantic LNG over the coming years but it all depends on BPTT and Shell bringing online the major projects they have planned on time.”

She said it was critical new projects such as Cassia C and Matapal come on stream just as the older fields come off their years of peak production. “In Trinidad it’s all about delivering on time and keeping projects on schedule in order to fulfil commitments to both the export and domestic market,” Nikolova said.


Most of Trinidad’s LNG goes to Chile, the US and Europe under long-term contracts. But exports to Chile are now facing heavy competition from Argentina’s shale gas, with unconventional gas output in the US also displacing the need for LNG imports there.

Despite these risks and BPTT’s recent setbacks, the long-term forecast for Trinidad’s gas production remains relatively bullish. Output has been on a steady upward curve for some time, with production expanding by as much as 20.3% in June last year to stand at 108mn m³/d.

The country’s gas is relatively low down on the cost curve, which means it can secure decent margins even when prices are weak, a point noted by Nikolova. “Atlantic LNG is an established plant with low costs – that’s not going to change dramatically – so in that sense it’s still competitive,” she said.

Cross-border developments with Venezuela should also strengthen supply in the longer term. Venezuela announced a deal with Trinidad & Tobago in August 2018, under which gas from its Dragon field would be liquefied and exported from Atlantic LNG. Under the agreement, Trinidad is to purchase 4.25mn m³/d of gas from the Dragon field, offshore Sucre, with the possibility of doubling this in the future. First gas is anticipated in 2020, with work costing $100mn.

And with further contributions from BHP Billiton’s Greater Angostura and EOG Resources’ Sercan developments expected to add to production, Trinidad’s gas output should go up steadily over the course of the next five to ten  years.

Earlier this year, Fitch Ratings forecast output to expand from 37bn m³ in 2018 to around 39bn m³ this year, and then 44bn m³ in 2022, with 45-46bn m³/yr possible in the 2024-28 period. The numbers post-2022 might be down slightly – in the range of 2-3bn m³/yr – on the back of the poorer returns from Cashima and Cannonball.

Nevertheless, output at levels such as those forecast by Fitch would enable LNG exports to expand from 14.9bn m³ in 2018 to 16.6bn m³ this year and to 20bn m³ by 2022, with that level likely to be retained between 2023 and 2028.

Though BPTT’s recent infill drilling results are a setback, their overall impact ought to be limited as the company works through its $8bn investment programme. And the government will hope that progress at new fields will ensure the country does not return to the production lows seen in 2017.