Various factors influence the upstream natural gas investment cycle. One of the most important of these factors is that once an investment project is given a green light it can take anywhere from between three and five years for gas production to begin. Therefore, companies need to calculate the future commercial viability of a project on the basis of a variety of assumptions about future levels of demand, gas prices, taxation and capital allowances, among other factors. Although the geology of different fields varies, one rule of thumb is that an offshore gas field may have a lifetime of over 20 years, but that its output will be at peak levels in the first five years, before subsequently beginning to decline. Companies therefore usually look to the first five years as being critical for determining a project’s overall profitability.
Executives in the Trinidad and Tobago energy sector often argue that the current shortfall in gas production – experienced over the last four years – reflects an earlier misjudgement by the government, which set tax and royalty rates at a level which discouraged the oil majors from investing. Better terms were subsequently offered, but because of the development time lag, it is still taking a number of years for big new projects to come on-stream. Despite uncertainty over future gas prices, a number of analysts are confident that current projects in the pipeline will deliver the desired recovery in gas output. Kevin Ranmarine, former minister of energy, believes that improved capital allowances, such as allowing 100% of capital expenditure to be set against taxable income over a shorter time span than in the past, have made a positive contribution. In April 2016 Ranmarine argued that after difficult conditions, marked by low natural gas, methanol and ammonia prices, a recovery would begin in 2017. However, the gas shortfalls remain a significant issue. Addressing the annual Energy Conference in January 2016 Ramnarine’s successor Nicole Olivierre, said that gas production in 2015 had run at an average of 3.8bn standard cu feet per day (scfd), compared to the minimum consumption requirement of 4.2bn scfd. Data for 2015 from the Ministry of Energy and Energy Industries indicated that BPTT’s natural gas production had fallen by 9.9% to 1.9bn scfd, while BG Group Trinidad and Tobago (BG T&T – which has been taken over by Shell) had experienced a drop of 7.1% to 867m scfd. The other two main gas producers, EOG Resources and BHP Billiton had, however, seen increases in output that partially offset these falls. Indeed, total gas production was down by 5.8% to 3.8bn scfd in 2015 due to field declines. The shortfalls meant that a number of key consumers – including liquefied natural gas (LNG), natural gas liquids (NGLs) and other downstream processing plants received less gas feedstock than they needed.
Gas Master Plan
The previous government commissioned two reports designed to outline longer-term strategies for gas development. Consultancy Ryder Scott was commissioned to update an audit of total gas reserves, while UK-based Poten & Partners was commissioned to draw up a gas master plan for 2014-24. Both reports were submitted just before the September 2015 elections, but have not been made public. The new government has said that the master plan is being reviewed in the light of its new priorities, as well as new developments relating to cross-border reserves shared with Venezuela. The plan is believed to address the question of gas production shortfalls and to consider whether changes in the structure of the industry are necessary.
Development of the Loran-Manatee gas deposits located in the waters between T&T and Venezuela could make a major difference to the country’s gas outlook. While BPTT’s Juniper development is seen as being the main contributor to closing the current gas supply shortfall, bringing Loran-Manatee on-stream would decisively modify the demand-supply balance, making possible a significant increase in downstream gas processing capacity in T&T. As mentioned (see overview) reserves at this field are estimated at 10.3trn cu feet. T&T’s share, 2.7trn cu feet is equivalent to around 26% of its total proven reserves. According to some estimates the combined field when fully developed could produce 750m scfd. If T&T’s share of output is equivalent to its share of total reserves, that would imply additional supply to the country of just under 200m scfd. Although both governments have been aware of these reserves since their discovery in 1983 it was only recently that a formal agreements have been reached to enable joint development.
A 2013 agreement between the two countries committed them to jointly develop the Loran-Manatee field, but it was not until after a February 2015 meeting between Venezuelan president, Nicolás Maduro, and the then-prime minister of T&T, Kamla Persad-Bissessar, that, in acknowledgement of geography and Trinidad’s more developed pipeline network in the area, the Venezuelans agreed to the gas being extracted and sold through T&T, with the two governments splitting the revenues.
There was also an agreement relating to another cross-border field, known as the Unitisation Agreement for the Exploitation and Development of the Hydrocarbon Reservoirs of the Manakin-Cocuina field, which covers block 5(b) in T&T and the contiguous block 4 in Venezuela. The key commercial decision on whether to proceed with Loran-Manatee now lies with the oil and gas companies holding the licences for the relevant blocks. These include Shell (formerly BG Group T&T) and Chevron on the T&T side and Chevron and PDVSA, the state-owned Venezuelan oil company. These companies will have to asses not only the commercial prospects based on future oil prices, but also the question of political risk, assessed by many to be a significant factor on the Venezuelan side, given recent domestic political and economic tensions and the current government’s history of expropriating foreign investment assets. A further potential political risk issue is that Venezuela has an outstanding dispute with Guyana, where it claims sovereignty over the Essequibo region.
In May 2016 President Maduro returned Rowley’s earlier visit, accompanied by the Venezuelan ministers of petroleum and mining, Eulogio Del Pino, and the minister of industry and commerce, Miguel Perez Abad. The two countries signed a memorandum of understanding (MoU) whereby Venezuela would help T&T with its current shortfall in natural gas. This move points toward closer relations for the two countries. What is not clear at this stage is the likely timetable for developing Loran-Manatee. Various industry sources have spoken of between three and five years. In February 2015 the Energy Chamber of Trinidad and Tobago said it “eagerly awaits further news of the Loran-Manatee field, which has the potential to be developed relatively quickly and to bolster the delivery of gas in T&T”. The recently signed MoU between the two countries could mean that work on monetising the Loran-Manatee field could begin sooner rather than later. However, other sources suggested it would be unlikely for gas from Loran-Manatee to begin flowing before 2020.
NGC In The Midstream
A key player in the gas sector is The National Gas Company of Trinidad and Tobago (NGC), which occupies a midstream position in the gas production and supply chain. NGC has a monopoly role buying gas from the upstream and distributing to the non-LNG sector. The non-LNG portion is sold to the local petrochemicals sector, power generation and other consumers.
Most gas production (55%) is exported in the form of LNG, with the rest used in the local petrochemicals industry (34%), electricity generation (8.2%) and other sectors (2.8%). Locally-based credit rating agency CariCRIS in September 2015 reaffirmed its CariAAA “highest creditworthiness” score for NGC debt, stressing the company’s economic importance. In 2014 NGC had contributed TT$6.9bn ($1.1bn) to government revenue through corporate taxes and dividends. In that year NGC revenue of TT$23.5bn ($3.6bn) accounted for 83.8% of total energy sector revenue and 40% of total government revenue.
Outlook For Atlantic
The key gas exporter in T&T is Atlantic. In May 2016 the company said that it remained confident over the long-term outlook for its business, with most of the output of Trains 1-3 being shipped to South America (21% to Argentina, 20% to Chile and 9% to Brazil). Despite the fall in global gas prices, chief executive Nigel Darlow told OBG “Gas is increasingly the fossil fuel of choice – being much cleaner than coal and oil – which is important given the need for improved worldwide environmental stewardship. This growth in the relative importance of gas in the energy mix will continue to support global demand for LNG, which is projected to increase by around 5% per annum over the next decade.”
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