New oil and gas discoveries support energy sector's recovery in Trinidad and Tobago

Hydrocarbons have long been the primary driver of Trinidad and Tobago’s economy. Indeed, T&T is the largest oil and gas producing country in the Caribbean, with the energy sector contributing around 45% to GDP, according to the Ministry of Energy and Energy Industries (MEEI). In addition, the country has a developed upstream petrochemicals industry and is a major exporter of liquefied natural gas (LNG), in addition to ammonia and methanol.

While the sector has faced economic headwinds in the form of falling international prices and increased competition, investment has risen in recent years and a number of new hydrocarbons discoveries have been made. Nevertheless, the sector still faces a number of challenges, notably in its deepwater infrastructure, but also in terms of LNG contracts and a domestic supply shortfall.

Performance & Size

T&T has proven oil reserves of 200m barrels and natural gas deposits totalling 11trn standard cu feet (scf) – which represents 0.2% of the world’s gas reserves. In 2018 T&T exported 12.2m tonnes of LNG, making it the eighth-largest exporter of the commodity worldwide, with a 3.9% share of the international market, according to the International Gas Union (IGU). After more than a century of continual expansion, annual natural gas production began to decline in 2015, before recovering in 2018 to 3.6bn scf per day (scfd), up from 3.35bn scfd in 2017, according to the MEEI. This recovery appears to have been sustained into 2019, with the July 2019 economic bulletin of the Central Bank of T&T stating that the coming on-line of the BP T&T (BPTT)-owned offshore Angelin gas platform in February 2019 has kept natural gas output resilient during the first seven months of the year.

Meanwhile, oil output has been in decline since 2014, with production totalling 23.19m barrels in 2018, or 63,544 barrels per day (bpd), down from 26.21m, or 71,818 bpd in 2017. Nevertheless, the energy sector remains significant, contributing 28% to the government’s total revenue in 2018, according to the Extractive Industries Transparency Initiative (EITI). Furthermore, recent offshore, deepwater gas discoveries, coupled with new oil findings, have buoyed hopes of increasing hydrocarbons production and reducing the country’s gas supply shortfall.

Structure & Oversight

The country’s energy sector has undergone a series of major changes in recent years. Most notably, the state-owned oil and gas company Petrotrin underwent major restructuring in December 2018, and was relaunched as four new entities in a bid to improve efficiency. Furthermore, the country’s largest oil refinery – also called Petrotrin – was closed in November 2018 due to low profitability. It was subsequently announced in September 2019 that the facility would reopen following its sale to an investment group operated by the country’s Oilfield Workers’ Trade Union (OWTU). In November 2019 Norway-headquartered Yara International also announced that it would close its ammonia production facility at Point Lisas. The announcement – which came following a failure to reach an agreement with the National Gas Company (NGC) of T&T to maintain operations – met with pushback from industry representatives and the opposition United National Congress party, with these figures highlighting the potentially negative impact on the country’s downstream sector. The closure of the plant is expected to reduce the country’s total annual ammonia production by 5%.

Positive developments took place in the renewables segment, with the energy multinationals BP and Shell submitting a bid in October 2019 for a government tender for a large-scale solar power project. This move forms part of a broader effort by the government to diversify the country’s currently natural gas-based energy mix, and produce 10% of its electricity from renewable sources by 2021.


While hydrocarbons production has suffered setbacks in recent years, a number of successful exploratory oil and gas projects, alongside government activity aimed at improving efficiency bode well for the sector. In November 2019 BPTT announced a major natural gas discovery at its Ginger exploration well, located east of the Cashima field, approximately 30 km off the south-east coast of Trinidad. The announcement follows two earlier significant discoveries made by the company – which is 70% owned by BP and 30% owned by the Spain-headquartered energy firm Repsol – at its Savannah and Macadamia exploration wells in June 2017. According to a press release from BPTT, the new gas find was made following significant investments in seismic processing and ocean-bottom seismic acquisition technology.

As of January 2020 BPTT had 15 offshore platforms and two onshore processing facilities, making it the largest hydrocarbons producer currently operating in T&T, being responsible for 55% of the nation’s gas production. While launching operations at the new well could help sustain a recovery in the country’s natural gas production over the coming years, industry insiders have highlighted that its deepwater location may mean that the discovery-to-production timescale could be long. Significant investment in the infrastructure of these deepwater sites will therefore be necessary to enable the extraction of these resources.

In a further move that is expected to support the growth of the segment, work is currently under way by BPTT on the Cassia Compression project. The plan combines a number of different exploration and development activities aimed at maximising production from existing fields. The centrepiece of this project in the Cassia C compression platform, which is being constructed 57 km off the south coast of T&T and is earmarked for completion in 2021. The new platform will gather and compress gas from various operational fields in the Greater Cassia Area, creating a low-pressure reserve for export. Upon becoming fully operational, the platform will have a throughput capacity of 1.2bn scfd.

These developments follow an uptick in activity in the country’s oil segment. In August 2019 the Australia-headquartered extractives company BHP – a leading player in T&T’s hydrocarbons sector – announced it would invest $283m to develop the Ruby petroleum project, bringing total investment in the block to $500m. BHP holds a 68.46% stake in the block, while Heritage Petroleum and NGC hold the remaining 20.13% and 11.41%, respectively. The project consists of five production wells, which utilise the latent capacity of the existing processing facilities, and incorporates new ocean-bottom node seismic imaging technology in the existing infrastructure. The project is expected to begin production in 2021 and the field is estimated to hold 13.2m barrels of recoverable oil, along with 274bn scf of natural gas. Furthermore, in mid-December 2019 Canadian company Touchstone Exploration announced a significant crude oil discovery at its Cascadura-1ST1 well in the onshore Ortoire exploration block. The findings are set to boost oil output over the longer term and highlights the ongoing potential for onshore discoveries in T&T. Speaking to international press, Paul R Baay, CEO of Touchstone Exploration, stated, “The results far exceed any pre-drill expectations.”

Gas Master Plan

In 2014 the government launched the Gas Master Plan 2014-24, which established a roadmap for the country’s natural gas sector, aimed at increasing production and reversing the supply shortfall. Kevin Ramnarine, the former minister of energy and energy affairs, said at the time of the plan’s unveiling in September 2015, “Long-term planning and roadmapping for the natural gas sector are critical to the continued growth, development and further prosperity of T&T.” The plan includes the allocation of areas for exploration, the identification of development concepts for deepwater gas, a review of the country’s current contractual arrangements in the upstream segment, as well as gas storage and utilisation, and the optimisation of transmission infrastructure. The plan also aims to re-evaluate the legislative and regulatory framework to increase efficiency in the management of the upstream, transmission and downstream segments, as well as seeking to attract more investment into the gas sector.

The need to increase production has been given a greater impetus since the publication of the Gas Master Plan 2014-24, given both the fall in international oil and gas prices since 2014 and increased competition from the expansion of US shale gas operations. “The Gas Master Plan 2014-24 is even more relevant now than before,” Douglas Boyce, a consultant at T&T-based upstream services provider Intecsea, told OBG. Furthermore, the country’s upstream LNG industry is facing mounting international competition, with worldwide liquefaction capacity having increased by 7% in 2018, according to the IGU. Globally, production is expected to grow by 22% in the years to 2024 as more liquefaction facilities come on-stream. While the majority of these plants are set to be established in the US, LNG capacity is also expanding in Russia and Australia. As a result of these pressures, T&T has been relegated to ninth place worldwide in terms of LNG capacity, which may necessitate a shift in planning.


Indeed, despite a recovery in production volumes in 2018, the country is facing a shortfall between supply and demand. The country currently consumes 1.5trn scf of natural gas per year, both as a result of its downstream industries and the country’s reliance on gas for electricity generation. While recent gas discoveries may offset demand over the longer term, the country still faces a shortfall in infrastructure investment, particularly in terms of utilising deepwater finds.

In an attempt to overcome this challenge, the government signed a memorandum of understanding with the Venezuelan government in August 2018 to purchase 150m scfd, before later increasing this amount to 300m scfd. However, with the imposition of sanctions by the US and the Organisation of American States on Venezuela, the deal was suspended. “We were hoping to import gas from Venezuela and those plans were well advanced, but there is almost no expectation that there will be progress on this in the short term,” Thackwray Driver, CEO of the T&T Energy Chamber, told OBG. “Over the longer term, however, there is significant potential, as Venezuela’s obvious export market would be T&T.” Sanctions on Venezuela also led to the February 2020 decision to halt joint development of the Dragon cross-border shallow-water natural gas field, which was agreed upon in 2013. The two countries will instead pursue independent development of the field, which holds 10.2trn cu feet of gas.

Another option to increase gas supply to T&T would be to import from Guyana, a country which has rapidly emerged as an oil exporter following a spate of discoveries since 2015, including a number of new findings in 2019. In August 2019 hydrocarbons multinational Tullow Oil announced the discovery of a major oil well in the Orinduik block in Guyana, with reserves at the site estimated to exceed 100m barrels. This was followed in December 2019 by an announcement by ExxonMobil that it had discovered further oil resources, bringing its current resources in the country to over 5bn barrels. “The discoveries in Guyana are phenomenal, and I am very optimistic about what T&T can gain from it,” Boyce told OBG. “If Guyana can build a gas industry, they can help alleviate T&T’s gas supply problem.”

Nevertheless, while the emergence of Guyana as a hydrocarbons exporting player in the region may help alleviate T&T’s natural gas shortage, it also adds pressure to the country’s industry, introducing another player to an already increasingly competitive field. “T&T must ensure it fully leverages the energy advantage that is possesses in the region,” Leon Brunings, CEO of Ventrin Petroleum, told OBG. “The booming Guyana economy as well as geopolitical difficulties in the region pose challenges that could lead to T&T losing the upper hand on energy production if it does not focus more on efficiency and streamlining its energy operations.”


Companies engaged in the LNG segment largely operate under long-term contracts with the government of T&T. However, falling international gas prices and increased global competition have resulted in a drop in gas revenues. In 2017 the Gas Master Plan 2014-24 was submitted for review, with consultancy Poten & Partners commissioned by the government to recommend amends to the plan. One recommendation was that, upon expiry of the existing contracts, future gas supply should be routed through NGC to enable the government to reap maximum benefits from the LNG value chain. According to Poten & Partners, such an expanded role would allow NGC to provide an LNG-linked pricing scheme to upstream suppliers to support new developments, which could then be applied to a basket price of LNG, methanol and ammonia.

Following the consultation recommendations, the government kick-started a number of contract renegotiations beginning in 2018, most notably with Atlantic LNG (ALNG). The T&T-based company is one of the world’s largest LNG producers and operates the liquefaction facility at Point Fortin, on the south-west coast of T&T. ALNG operates four supply trains to its liquefaction facility, the ownership of which is shared between NGC and the international players Shell, BP and the China Investment Corporation. However, ALNG’s exports have been under pressure in recent years, particularly as a result of the expansion of US shale gas, which has negatively impacted US demand for imported gas. In June 2019 the government reached an agreement with Shell and BP to restructure ALNG. The government stated at the announcement of the contract renegotiation that the aim of this restructuring was to create a more flexible system of gas delivery in order to cover shortfalls from different sources.


T&T is the world’s largest exporter of ammonia – with 10 ammonia plants in operation in the county as of January 2020 – and the world’s second-largest exporter of methanol. However, the closure of one of the country’s ammonia production facilities at Point Lisas in November 2019 by operator Yara International has brought uncertainty to the segment. Indeed, the closure of the plant is expected to reduce the country’s total ammonia production by 5%. The decision to close the facility was attributed to uncertainty regarding gas prices from NGC, coupled with a fall in international ammonia prices and the plant’s deteriorating energy efficiency. Furthermore, the decision has put the future of other ammonia plants into question, notably the two facilities operated by Tringen – a joint venture between Yara International and the T&T government – as they had yet to reach an agreement with NGC over gas prices as of January 2020.

In addition to the country’s significant oil and gas production, T&T has one of the largest gas processing facilities in the Americas, the Phoenix Park Gas Processors (PPGPL) LNG complex. PPGPL, a stateowned subsidiary of NGC, is located in Savonetta, on T&T’s west coast. The plant has a processing capacity of around 2bn scfd and a daily LNG output capacity of 70,000 barrels, according to the MEEI. The country’s electricity generation is currently entirely based on natural gas, with LNG supplied to the country’s power stations and its petrochemical plants for use as a feedstock in the production of ammonia and fertiliser. “The petrochemical industry finds itself in a very competitive market, with very cheap gas in the US,” Driver told OBG. “Everybody is operating on reduced margins, so it is all about keeping costs under control and being efficient.”

Global Investment

As part of its broader efforts to increase international investment in the sector, T&T launched a shallow water auction in November 2018, its first since 2010. The auction – which offered six offshore blocks – attracted one joint bid from BP and Shell, with Claire Fitzpatrick, regional president of BPTT telling local press that, “The decision to bid highlights our intent to continue to seek out opportunities to develop resources in the Colombus Basin. It also demonstrates our confidence in the potential of the Basin”. Nevertheless, there was a lack of multiple competitive bids, with Franklin Khan, the minister of energy, describing the results of the auction as “disappointing”.

A deepwater round is expected to be announced for 2020 and is anticipated to generate more interest among operators. Furthermore, investment in the upstream sector is expected to increase in 2020 as a result of the oil and gas discoveries made in 2019. In addition to the $283m of investment in the Ruby petroleum project announced by BHP in August 2019, Shell also announced a major investment drive in the country. In June 2019 Shell embarked on the development of two major gas projects located in Barracuda and Colibri, with gas production expected to begin in 2020 and 2021, respectively, according to the MEEI. In an additional sign of increasing investment activity in the sector, the UK-based hydrocarbons services firm Noble Corporation stated in December 2019 that it had signed a contract with BHP to lease the Noble Regina Allen oil rig to the company for operations in T&T from September 2020 to February 2021. The rig – which is currently being contracted to ExxonMobil at a site in Canada – can operate in 122 metres of water and drill to a depth of 10,668 metres.

Similarly, in December 2019 the Denmark-headquartered multinational Maersk Drilling was awarded a three-well contract for the use of its semi-submersible Maersk Discoverer in the development of BP’s Matapal project. This project will commercialise the gas resources found in 2017 at the Savannah exploration well, which has an estimated production capacity of 400m scfd of natural gas and is expected to come on-line in 2022. Also in December 2019 the US offshore drilling contractor Tansocean was awarded a one-year contract for the use of its Development Driller III rig, with an undisclosed operator off the T&T coastline. The semi-submersible oil rig can operate in water depth of 2286 metres and achieve a drilling depth of 11,430 metres.


While the country’s electricity system remains almost entirely reliant on gas-fired power stations, there has been a recent increase in renewable energy activity in T&T. In November 2015 the country announced its objective of generating 10% of its energy needs from renewable sources by 2021, though progress towards this target was initially slow. However, in 2017 the MEEI announced an expression of interest for investors in the development of large-scale renewable energy projects. As of July 2019 the government announced that it had received 11 proposals. Notable among these was a joint bid from BP and Shell for the construction of a major solar power facility in T&T. Furthermore, in June 2019 the country received $3m in financial support from the International Renewable Energy Agency to support its green energy transition.

Nevertheless, while progress is being made in the development of the renewables segment, a number of barriers remain. Notably, the low price of electricity compared with other countries in the region, which serves as a barrier for increased investment in small-scale projects. The other major obstacle to increasing the renewable share of the country’s energy mix is the current surplus of power generated, meaning the country is already generating more power than it needs. Therefore, policies such as potentially introducing a law mandating the use of renewables, will be needed for T&T to meet its goals.


The new oil and gas discoveries made in 2019 along with the new investment pledges by major international operators in the country’s upstream sector appear set to support a short-term recovery in T&T’s energy sector. Furthermore, the country’s scheduled 2020 deepwater auction is expected to attract investment. Nevertheless, faced with an increasingly competitive international market for its energy commodities, more will need to be done to ensure the continued recovery of the sector.

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The Report: Trinidad & Tobago 2020

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