For the last four decades Trinidad and Tobago’s oil and gas industry has been the primary engine driving the economy. However, it has faced challenges during the last three years due to an extended period of low international hydrocarbons prices.
With prices expected to begin a moderate recovery in 2017, the industry may now experience some relief. The medium- and long-term focus will remain on halting and reversing recent declines in production. T&T gas fields set to come on-line in 2017 should help. Indeed, in June 2017 international oil company BP T&T (BPTT) announced two major finds that will provide a significant boost to production. BPTT (a partnership of BP and Spain’s Repsol) has unlocked around 2trn standard cu feet (scf) of gas through its drilling of the offshore Savannah and Macadamia wells.
However, stepping up production alone will not be quite enough. Important strategic decisions also need to be made across the entire energy value chain, ranging from incentivising upstream production to improving refinery profitability in the mid-stream, and boosting liquefied natural gas (LNG) and petrochemical capacity utilisation downstream.
The energy sector has traditionally played a key role in T&T’s economy. The US Department of Energy cites T&T as the largest oil and natural gas producer in the Caribbean, and the world’s sixth-largest LNG exporter. In early 2016 the country had some 11.5trn scf of proven natural gas reserves and around 728m barrels of proven crude oil reserves. In 2014 T&T produced 1.5trn scf of dry natural gas and 114,000 bpd of crude and other liquids, including crude oil, condensates and liquefied petroleum gas. The volume of proven reserves has been falling gradually since 2005, and production has been on a downward trend as existing fields have reached maturity.
In 2011 – a typical year prior to the steep drop in international hydrocarbons prices in 2014-16 – the energy sector accounted for 44.8% of GDP, 57.5% of government revenue and 83% of merchandise exports. Given its capital-intensive nature, however, it employed only 3% of the country’s labour force.
Hydrocarbons also dominated the energy balance. According to the Inter-American Development Bank, in 2012 T&T produced some 689,000 barrels of oil equivalent per day (boepd) of natural gas and 110,000 barrels per day (bpd) of crude oil. Almost half of the gas, or 333,000 boepd, was exported, as was 32,000 bpd of crude oil. There were also 60,000 bpd of crude oil imports that year, used primarily as feedstock for the country’s refinery, which runs on a mix of indigenous and imported crude oil.
The country’s electricity in 2012 was produced by 53,000 boepd of natural gas and 100 bpd of oil product to deliver 15,000 bpd worth of electricity, with some output lost to heat and waste. Total energy consumption in T&T stood at 269,000 boepd. Per capita electricity consumption was 6510 KWh in 2012, more than three times the Latin America and Caribbean average at the time. Overall, the Inter-American Development Bank reports that between 1994 and 2016, electricity consumption in the country rose by an annual average of 4.3%.
The hydrocarbons industry in the country can be divided into three main realms – upstream, midstream and downstream. Upstream activities cover exploration and production of crude oil and natural gas. In gas production this phase tends to be dominated by international oil majors like BPTT and Shell, with a smaller share held by EOG Resources. State-owned Petrotrin is the biggest player in upstream oil production, particularly from onshore wells and shallow-water wells in the Gulf of Paria. There are also a number of small independent oil companies operating mainly onshore.
MIDSTREAM: Midstream activities are the transmission, refining and transformation of oil and natural gas. Many of these steps are concentrated in a cluster of plants in the Point Lisas Industrial Estate. The dominant player in midstream oil is Petrotrin, which operates T&T’s only refinery. On the gas side, the dominant player is the major privately owned liquefaction plant Atlantic, which serves the global export market and is the country’s single largest gas consumer. In the five years to 2015 Atlantic accounted for 55% of total gas demand in T&T.
The main midstream firm processing gas for domestic use is Phoenix Park Gas Processors. Phoenix Park extracts propane and butane from natural gas, and supplies downstream players. The state-owned National Gas Company (NGC) purchases, distributes and sells gas to a range of clients, including petrochemicals plants, the steel industry (although this was interrupted when the main Arcelor Mittal plant closed in March 2016), and the Trinidad and Tobago Electricity Commission for electricity generation.
The downstream sector includes the production of petrochemicals such as methanol, ammonia and urea. T&T is the world’s largest methanol and ammonia exporter. Two privately owned companies produce methanol: Methanol Holdings of Trinidad (MHT) and Methanex Corporation of Canada. The former is a locally owned joint venture, while the latter, a Canadian company, is the world’s largest producer and is listed on the Toronto Stock Exchange. A cluster of companies produce ammonia, including PCS Nitrogen, Tringen, Point Lisas Nitrogen, Yara and Caribbean Nitrogen. PCS Nitrogen and Aum Complex – owned by MHT – produce urea.
Local distribution of fuel from Petrotrin’s refinery is largely controlled by two companies. The companies own and operate the country’s network of petrol stations. They are the National Petroleum Marketing Company and United Independent Petroleum Marketing Company (UNIPET). The former business is owned by the T&T government, while the latter is a privately operated domestic company.
Electricity in T&T is indirectly subsidised, as NGC sells gas to the T&T Electricity Commission at a reduced price, giving the country the lowest electricity tariffs in the Caribbean. Transport fuels, meanwhile, are also subsidised. The government has achieved this by fixing both wholesale and retail prices for the three main fuels sold, namely, premium gasoline, super gasoline and diesel.
The difference between the market price and the subsidised price has been covered in two ways. First, all exploration and production companies are required to pay up to 4% of their gross income as a levy into a special fund, known as the Petroleum Products Subsidy Fund. Second, the government tops up the fund out of its general budget to make up the total amount needed (which varies according to international market price levels and the level at which the government chooses to fix domestic fuel prices). National Petroleum and Unipet buy gasoline and diesel from Petrotrin at the market rate before selling it on at the subsidised rate and receiving a reimbursement to cover the difference from the government. However, these refunds have not always been paid promptly. The total value of the subsidy reached a peak in FY 2012, when it was estimated at TT$4.46bn ($666m).
Following the fall in international oil prices after 2014, the government took the opportunity to begin a phased reduction in fuel subsidy payments. In the March 2016 budget review the government announced that it was setting the price of premium gasoline at TT$5.75 ($0.86) per litre and the price of super gasoline at TT$3.58 ($0.53) per litre, meaning the fuels were no longer subsidised at that level. The authorities also set the pump price for diesel at TT$2 ($0.30) per litre, retaining a subsidy of approximately TT$1 ($0.15) per litre. In his September 2016 budget speech, minister of finance Colm Imbert announced a further 15% increase in the price of diesel, taking it to TT$2.30 ($0.34) per litre, which represented 75% of the true market rate. The remaining diesel subsidy may be eliminated entirely in the future.
While the reduction in subsidy levels has been considered a sensible approach to the government’s need for fiscal austerity, and a way of reducing what has been seen as a regressive price distortion (the subsidy primarily benefits middle class and wealthier car owners), the new policy is not without its critics. Some have noted that the government retains central control of fuel prices, meaning that this or future administrations could choose to reintroduce fuel subsidies at short notice.
Afraz Ali, chairman of UNIPET, told OBG that the retail fuel segment in T&T remains too tightly regulated. When first set, centrally administered prices contemplated an operating margin for the service stations, but that margin had not been reviewed since the year 2006. The margin no longer properly accounts for rising costs and increased government requirements, such as tighter health and safety regulations or the requirements of the Metrology Act, which sets minimum standards for weights and measures.
“There are numerous market pressures causing costs to fluctuate, and a set price no longer sufficiently accounts for these pressures, putting significant strain on operating margins,” said Ali.
There is little use of non-conventional and renewable energy at present, apart from small-scale wind and solar installations in some households and businesses, or through pilot programmes in government facilities. While the administration of Prime Minister Keith Rowley committed T&T to a renewables target of 10% by 2021 in October 2015, it is unclear how that target will be achieved. In the 2016/17 budget address, Imbert reiterated the government’s commitment to shifting towards renewable energy, announcing the removal of all taxes on electric and hybrid vehicles. The budget also allocated $200,000 for a proposed integrated Photovoltaic Park for the manufacture and assembly of parts and components.
Smart Energy is perhaps the most active in the private sector, and one of its projects involved partnering with telecoms provider TSTT on a 10-KW solar installation on the island of Chacachacare, off Trinidad’s western coast. The company also imported the first Tesla into the Caribbean, with a view to promoting sustainable transportation. “Electric vehicles such as Tesla are the future, and economies of scale will soon leave behind bridging technology such as compressed natural gas,” Ian Smart, CEO of Smart Energy, told OBG. However, without a strong legislative and regulatory framework encouraging development of renewable energies, the private sector has largely been reluctant to invest in the industry.
T&T is a member of the Extractive Industries Transparency Initiative (EITI), an international agreement that seeks to produce clear and accurate information on the financial flows and payments generated by oil, gas and mining operations in different countries around the world. In September 2016 the T&T EITI Report for FY 2014 and FY 2015 was presented, covering all payments made, directly or indirectly, to the government by a total of 49 oil and gas companies in the country.
The report showed that total government revenues from the oil and gas sector rose by 35.2% to TT$28.65bn ($4.3bn) in FY 2014, just before the slump in international oil prices. In FY 2015, with both output and prices falling, revenues dropped by 27.1% to TT$20.89bn ($3.12bn). There were differences in the reconciliation process between the payments reported by companies on the one hand and funds received by the government on the other, but the EITI Report said the gaps could be explained by foreign exchange differences, the phasing of payments between financial years and the way in which some insurance payments were classified.
Victor Hart, chair of the EITI Steering Committee in T&T, said that he thought the launch of the organisation was one of the most important initiatives in the history of the industry. “We start from the premise that the natural resources of T&T belong to the people,” he told OBG. The quest to disseminate the most transparent and comprehensive information possible has faced a number of obstacles. While the companies had agreed to share information on tax and royalty payments made, the government was initially unable to do the same for tax and royalties received, citing the Income Tax Act under which that information was confidential. It took 18 months to find a solution, with lawyers eventually agreeing on a formula where information could be shared after, but not during, any confidential negotiations on the determination of tax liabilities. Hart acknowledged that there were limits to the degree of openness that could be achieved in this field, particularly in areas that are commercially sensitive, such as tax negotiation, reserves, geological and seismic information, and the government’s selling price for gas, which might be significant in regards to competition for oil and gas licences.
In both FY 2014 and FY 2015 state-owned gas company NGC was the largest single contributor to the government, with payments totalling TT$8.3bn ($1.24bn) in FY 2014 and TT$8.4bn ($1.25bn) in FY 2015. The contribution from NGC was largely attributable to increased dividend payments to its sole shareholder, the government. Of the amount paid in FY 2015, 80% consisted of dividends. In 2012 NGC had made a much smaller payment of TT$2.2bn ($327.9m), of which a smaller proportion – 40% – was in the form of dividends. The rise in dividend payments relates to the government’s need for one-off revenue items to help reduce the fiscal deficit. The EITI Report noted that, “In the 2015 fiscal year, a year in which the company’s profits were the lowest in over 15 years, NGC made its highest-ever dividend payment to the government totalling TT$6.84bn ($1.02bn).” The amount included retroactive dividend payments for 2013-15.
Due to dwindling overall revenues, the energy sector’s contribution to GDP – which hit 44.8% in 2011 – fell to 37.2% in FY 2014 and 32.1% in FY 2015. This was the smallest contribution since the global economic crisis of 2008-09. The sector’s contribution to total government revenues was 57.6% in 2011, but fell to 30.5% in FY 2015, the lowest in 15 years. Data from the EITI Report was used to guide the policy prescriptions of the country’s Gas Master Plan and T&T’s participation in the EITI has helped the government meet its Open Government Partnership commitments.
A Challenging Year
The energy sector faced a significant recession in 2016, mainly caused by the combination of falling hydrocarbons production and weak international prices. Based on preliminary data, the Central Bank of Trinidad and Tobago said in November 2016 that overall GDP had fallen by 6.7% in the first half of the year, a drop caused by a much sharper 10.8% contraction of the energy sector and a less intense 4.3% contraction of non-energy sectors.
The decline in energy sector activity was caused by declining rates of oil and gas field extraction, and by temporary shutdowns of operations at both BPTT and BHP T&T. Both of these upstream producers had to close facilities in order to prepare new fields for production. During the first six months of 2016 crude oil production decreased by 9.9%, and natural gas output was down by 10.7%.
The fall in upstream production impacted the midstream and downstream realms of the industry, where there were also some shutdowns for maintenance. LNG production dropped by 15.2%; natural gas liquids output by 14.3%; refining by 10.1%; petrochemical output by 2.9%; methanol output by 7.9%; and fertiliser output by 2.3%. Similar falls continued in the third quarter of 2016.
In August 2016 BPTT shut down its Mahogany Bravo hub in order to install tie-ins that will bring in gas from the new Juniper field in late 2017. The maintenance shutdown of Atlantic LNG’s Train 1 during the third quarter also depressed output levels. In the first nine months of 2016 crude oil production dropped by around 10.7% to 71,300 bpd, while natural gas production was down by some 13.8% to 3.34bn standard cu feet per day (scfd). This was the lowest level of oil production in around 60 years.
In early 2017 major stakeholders in T&T’s oil and gas sector expressed confidence that a strategic turning point was imminent. The question was whether key decisions would be made to reverse the decline in oil and gas output. Given the nature of the business, stable or growing production requires a fairly steady pipeline of new investment projects. The exploration, discovery and development of new fields in turn requires substantial capital expenditure, risk-taking and years of intense development work on each field before oil or gas can begin to flow. Typically, each new field has around four to five years of peak production and then begins to mature, with output levels starting to taper off. At the beginning of 2017 there was some concern that not enough new projects were in the pipeline to eliminate the existing, and potentially widening, supply deficit.
Factors at Play
A number of external and internal factors are combining to restrict the flow of new projects needed for a sufficiently stocked pipeline. Hope is being placed on one very large development, BPTT’s Juniper gas field, which is due to become operational in late 2017. There is also interest in deep-sea exploration by BHP, and the potential for increased exploitation of Petrotrin’s on- and offshore assets, including secondary recovery from mature fields. According to Imbert, there could be as much as 3bn barrels worth of oil still in mature fields that could be exploited if appropriate fiscal incentives were offered to private sector oil companies; Petrotrin had announced in May 2017 that it intends to increase production by some 30% over the next three years.
However, industry analysts bore in mind the possibility of a more pessimistic scenario, in which Juniper gas would provide only temporary relief from declining output from other fields, and in which gas shortages could return as early as 2018-19. Those who took this view also highlighted insufficient supply on the oil side, and noted that heavy losses at Petrotrin’s refinery were likely to continue until the facility managed to increase its use of locally produced crude. A lasting reversal of the downward trend in oil production and revenues could therefore, in the relatively pessimistic scenario, still be some years away. Externally, uncertainty over the low-price environment was an important factor, although there were hopes of a modest recovery in international prices in 2017. Independent of the pricing issue, it was feared that the new administration had not been able to make the domestic operating environment attractive enough to persuade more companies to invest in new development. Analysts recognised, however, that the government faced a difficult dilemma: it could offer better fiscal terms and conditions to encourage major oil companies to come back to T&T in a big way, but doing that would have a negative impact on tax revenues at a time when the administration faces severe strains on its fiscal accounts. Furthermore, the government introduced accelerated capital depreciation allowances in 2014 that are due to expire in 2017, and it is not yet clear whether officials will seek to extend them.
A consultancy report for the Energy Chamber of Trinidad and Tobago conducted by Rystadt Energy, and presented during the annual Energy Conference in January 2017, underlined the nature of the gas supply problem. The report stated that gas production had both increased sharply and decreased steeply within the last five years. Up until the early 2000s annual gas delivery projects averaging around 1.5trn scf had been approved, but this had subsequently dropped to 700bn scf. As a result, and bearing in mind the time required for new projects to come onstream, gas production dropped from 4.2bn scfd in 2013 to 3.34bn scfd in 2016.
The exploration success rate had also fallen off since 2009. According to Rystadt’s calculations, in the period between 2016and 2019, fields currently under development that come on-stream will almost – but not quite – offset natural declines in production from older fields. As a result, the consultancy estimates that gas production will fall by 3% per annum. That will result in a drop of around 14% between 2016 and 2030. In the absence of any new projects, output will decline steeply after 2019. The consultancy further examined the fiscal regime oil and gas producers in T&T must adhere to. It concluded that it was not very competitive, and that the royalty regime had a negative impact on profitability, particularly at certain price levels. Production-sharing contracts include some measures that were deemed too harsh and could discourage companies from investing. According to the report, adjusting fiscal terms “could unleash new resources from blocks where the tax system makes otherwise profitable resources unprofitable”.
Issues to Tackle
Some in the private sector felt that after having a good start in 2015, the new government had lost some of its original momentum. Upstream operators were disappointed that their concerns over the supplementary petroleum tax (SPT) had not been quickly resolved.
The SPT is levied on revenue, rather than profit, and was originally intended as a windfall tax, kicking in when international oil prices rose higher than $50 a barrel. That price level is no longer seen as particularly high, and companies are being penalised with a particularly heavy tax when prices are at $50-60 per barrel. Given that 2017 prices are widely predicted to move up into that range, the SPT is now considered by private sector operators to be a significant disincentive to new investment. In his September 2016 budget speech, Imbert said that the government was reviewing the country’s oil and gas taxation regime, on advice from IMF experts. He said that there was a proposal to replace the SPT with a new cash flow-based tax, to simplify and reduce tax levels, and to introduce “a moderate fixed-rate royalty in the order of 10-12%.”
However, progress has been slow, and a promised round of government-industry consultations on the subject has not yet taken place. At the time of the January 2017 Energy Conference, Imbert again referred to the review of the fiscal regime carried out by the IMF, and described reform of the SPT as an issue that had to be confronted. In addition, Imbert referred to government concern over transfer pricing of LNG exports, which some officials believe may reduce tax revenues. He described the issue by saying, “There is significant disparity in value accruing to [the] government as compared to that received by energy companies and their associates from the monetisation of this country’s hydrocarbon resources.” This, he said, made it necessary to “realign the interests of the companies and the government” so as to “ensure equitable outcomes for all parties”.
Two other key decisions are seen as becoming urgent. One relates to the future of Petrotrin, the state-owned oil company that is active both upstream (as an oil producer) and midstream (where it operates the refinery). Petrotrin has been recording heavy financial losses. It lacks the funds to invest in developing primary and secondary recovery in its existing fields, but increasing local oil production is seen as critical to stemming losses at the Pointe-a-Pierre refinery by increasing the proportion of indigenous crude used as feedstock there. Imbert noted that Petrotrin accounts for more than 50% of the country’s crude oil production, and said the government was looking to implement a range of strategies in 2017 to boost its onshore and offshore output (see analysis).
The other strategic issue on the agenda is to clarify the government’s plan for the downstream gas industry. Gas shortages have caused a series of business and technical problems for the downstream plants. Plants operate most profitably when close to full capacity, so interruptions and shut-downs have a negative effect on equipment and profit margins. Any new private sector investor in the downstream segment for gas will require reassurance that the government has a clear vision for the sector’s development, and will ensure reliability of gas supply commensurate with that vision.
Administrations have been keen to encourage minimum levels of local content in the oil and gas sector. There is a general requirement but no detailed legislation on the subject, and until recently each company largely followed its own local content policies. After considerable discussion within the industry, in early 2017 a total of 21 companies signed a Local Content Charter, committing them to promote local participation in the industry.
The signatories adopted a sole definition of local content, outlined in the Public Procurement and Disposal of Public Property Act of 2015. The act describes the concept as “the local value added to goods, works and services measured as the amount of money or percentage of each dollar remaining in T&T”. The charter binds all of these firms to a set of general principles, which include developing a strong local supply chain, optimising the retention of value within the country, and following policies that will allow local firms to improve productivity, quality and efficiency.
The charter also commits its signatories to providing information on any upcoming business opportunities, encouraging the development of relevant education and skills, and seeking to ensure the “transparent measurement and standardised reporting of progress in respect of local content delivery”.
Gas Master Plan
How T&T should seek to achieve the greatest economic benefits from its natural gas resources has been open to recent debate, as the country is involved in various stages of the gas value chain. It produces natural gas, propane, butane, LNG, methanol and urea, as well as related products.
Gas has been used in domestic iron and steel manufacturing, and to generate low-priced electricity to supply local industry. At each stage in the value chain, there is a potential debate over how much should be exported and how much should be retained for downstream use and processing – part of which may also be exported in the form of products with greater added value. The debate applies equally in periods of expanding gas supply or, as at present, when the production curve is trending downward. Supply shortfalls have caused significant disruption to downstream processing, raising the question of how best to manage the necessary supply cutbacks and whether some activities should be prioritised.
To tackle such questions, the previous government commissioned UK-based consultancy Poten & Partners to draft a Gas Master Plan for 2014-24. The final report was submitted just before the September 2015 elections and the current administration began a review of the plan. In September 2016, in a speech to commemorate the government’s first year in office, Rowley said a sub-committee of the government’s standing committee on energy had finalised its review of the Master Plan, and that it would be considered by the full committee in the coming weeks and then be made available to the parliamentary Energy Committee.
Analysts have pointed out that the government needs to make informed choices and have the data to guide it. Philip Farfan, a geologist at consultancy PetroCom, told OBG that the government needed to build an economic model for the gas industry that would allow it to test the impact of various policies at different international price levels. “For example, the government needs to be able to know whether it is better – in terms of price and profitability – to put any increased natural gas production through processing to produce LNG rather than methanol or the other way around, or to look at a wider portfolio of downstream products,” Farfan told OBG.
Low global oil and gas prices have left the energy sector with challenges. Underinvestment in upstream exploration has resulted in declining production and gas availability, leading to downstream industries operating below capacity. Still, T&T continues to attract investment from oil majors and independent producers. With the government and sector players committed to crafting an equitable new fiscal regime, a strong energy services industry and a new frontier in deepwater exploration, there is reason to expect the sector to bounce back over the medium term.
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