In light of the fall in global oil prices, the government of Trinidad and Tobago has proposed a series of ambitious reforms. Keith Rowley, the recently elected prime minister, has raised the possibility of amending the tax code to better reflect the current state of the energy sector. The move has been lauded by oil executives, who believe these changes can make the sector more competitive. In another encouraging sign, oil and gas players are moving forward with several major projects.
The prime minister has acknowledged the impact that the fall in energy prices has had. Speaking at the T&T Energy Conference in early 2016 he commented on the international slowdown in oil and gas prices and the far-reaching implications for exporting countries like his own. Rowley told conference attendees that T&T was at a critical juncture in its existence, and he recognised the implications for oil exporters like T&T, such as reduced revenues, capital outflows, sharp currency depreciation and reassessment of sovereign risks by investors.
The Shape Of The Recession
A matter of critical importance for the country’s energy industry and for the wider Trinbagonian economy is whether the current international decline in commodity prices will be V-shaped (a sharp decrease in prices followed by an equally sharp recovery), U-shaped (a slower, longer drop and a slower recovery) or even, in the worst scenario, L-shaped (a sharp fall to a new, lower base level for prices, which will not be able to recover to where they were before).
In early 2015 many hoped for the former of these options. However, a year later in early 2016 many feared the third. A phrase often heard was that international prices would be “lower for longer”. These possible outcomes have a direct bearing on both corporate and government policies. Dwight Mahabir, executive chairman of mechanical fabrication and offshore operations supplier Damus, told OBG that market conditions were difficult but that the company was adapting to a relative fall in order-book levels and scarce foreign exchange. “There has been a fall in orders, but we have been helped by the fact that before the oil price slumped we already had a number of big projects in the pipeline and set to continue,” he told OBG. “On the other hand, we have seen a number of maintenance projects in the Port Lisas area be postponed from 2016 to 2017 and, in one case, shifted as far ahead as 2018.”
Temporary cost reductions might be enough to deal with a V-shaped dip in prices, but at the other extreme an L-shaped one will require much greater and more sustained adjustments and restructurings. “What is becoming very clear is that with the development of shale in the US and the re-emergence of Iran as a major supplier in the Middle East, we have a situation where the supply of oil and gas has become very elastic and production can be increased at short notice,” Dominic Rampersad, acting president of the state-owned gas-processing facility Phoenix Park Gas Processors Ltd (PPGPL), told OBG. “At the same time demand remains quite inelastic. If you put those two things together, it suggests that even if prices eventually recover, it will not be back to their old levels. I think that $60 a barrel is the new $100 a barrel.” One of the key evolving themes across the local industry in 2016 is how, if that view is correct, companies will adapt and restructure their operations.
T&T is the largest oil and natural gas producer in the Caribbean. In 2014 it was the world’s sixth-largest liquefied natural gas (LNG) exporter and the largest LNG supplier to the US, accounting for 71% of that country’s imports. Since the 1990s gas production has grown in economic importance and overshadowed crude oil in terms of annual revenues. Total proven gas reserves stood at 11.5trn standard cu feet (scf) at the beginning of 2016, with proven reserves falling moderately since 2005. Proven crude oil reserves at the beginning of 2016 stood at 728m barrels.
Gas production was 1.5trn scf in 2014, with two companies, BP Trinidad and Tobago (BPTT) and BG Group Trinidad and Tobago (BGTT) accounting for roughly three-quarters of total gas production. In early 2016 Royal Dutch Shell completed its global takeover of BG Group, and BGTT was rebranded as a Shell subsidiary. Important new gas fields have been identified and some are currently under development. Of particular significance due to its size is the Loran-Manatee cross-border offshore gas field, which straddles the maritime limit between Trinbagonian and Venezuelan waters. Reserves at this field are estimated at 10.3trn scf.
The twin-island nation’s share – 2.7trn scf – is equivalent to an estimated 26% of its total proven reserves; both governments have recently signed agreements on the joint exploitation of this field, agreeing for the operators on both sides of the table to engage in commercial discussion for a unitisation and unit operating agreement. T&T is home to some of the largest natural gas processing plants in the Western Hemisphere, including PPGPL, which has the capacity to handle as much as 2bn scf per day (scfd), producing some 70,000 barrels per day (bpd) of natural gas liquids (NGLS).
Atlantic operates four liquefaction trains, with a total capacity of around 15m tonnes per annum, and is an LNG exporter. Furthermore, T&T has 11 ammonia plants and seven methanol plants, making it the world’s largest exporter of ammonia and the second-largest exporter of methanol. The country’s main electricity generators are gas-fired; gross power generation is around 9.2 TWh per annum. Crude oil output in 2014 stood at 81,000 bpd, or 114,000 bpd including other liquids, mainly NGLS. The country’s only refinery is operated by state-owned Petrotrin at Pointe-à-Pierre, and has a capacity to handle some 168,000 bpd of locally produced (indigenous) and imported crude.
Energy Still Dominates The Economy
The energy sector has been at the heart of T&T’s economy for the past four decades. Its contribution to GDP, exports, government revenue and employment has been substantial, although fluctuating in step with the rise and fall of international oil and gas prices. On average, the industry’s contribution to GDP has been around 40%, although this has ranged from a high of 50.8% in 2008 to a low of 32.1% in 2015. Of that total the minister said exploration and production activities represented 23% of GDP, refining accounted for 9% and petrochemicals for 5%. Due to its capital-intense nature, the energy sector accounts for a relatively modest share of total employment, at 3.8%.
Falling Hydrocarbons Output
Production of crude oil has been on a fairly consistent downward trend over the last decade. According to the BP Statistical Review of World Energy, T&Ts total crude oil output, including NGLs and other liquids, reached a peak of 193,000 bpd in 2006 and declined consistently since then to reach 112,000 bpd in 2014. The average rate of decline over the ten years to 2014 amounted to 3.5% per annum.
Data compiled by the Central Bank of T&T (CBTT) covers a more up-to-date period running to the end of 2015. This shows a five-year average annual rate of decline of 4.3%. Production in 2015, according to the Ministry of Energy and Energy Industries was down by 3.2% to 78,656 bpd (crude oil and condensates). In contrast to the crude oil story, natural gas production rose consistently in the first decade of the 21st century. However, according to BP’s data, it reached a plateau in 2010 of 44.8bn cu metres, from where it has since edged down to 42.1bn cu metres in 2014. On average in the ten years to 2014 gas production grew by 3.6% per annum. CBTT data shows natural gas production also falling since its 2010 peak. In the five years to 2015 gas production was down by an annual average of 2.4%. This includes a sharp drop 2015, when output fell by 5.8% to 3.8bn scfd. Production of LNG has broadly followed the same pattern as output of natural gas although with some extra volatility. In 2015 LNG output was down by around 10.2% to 28.9m cu metres.
A Difficult Market In 2015
On taking office in September 2015 the new Peoples National Movement (PNM) government appointed Nicole Olivierre as minister for energy. In a speech to the Energy Chamber of Trinidad and Tobago, she outlined her first assessment of the state of the industry. The minister said the country faced an “unabated decline” in oil and gas reserves and production and needed to take action to halt the downward trend. In the year to date, natural gas production had averaged 3.86bn scfd, down from a peak production level of 4.3bn scfd in 2010. The government has, therefore, emphasised the need to reinvigorate the industry, to accelerate production, to build back reserves and to provide the certainty of gas supply to the domestic industry, in order to enable it to move from the current short-term planning to a longer horizon.
Olivierre also focused on gas supply shortfalls – shortages of gas relative to promised delivery volumes by The National Gas Company of Trinidad and Tobago (NGC) to downstream processing companies. “At present the industry is characterised by inadequate supply, which has led to short-term contractual arrangements and a state of uncertainty, given that contracts between the upstream operators and NGC are due to expire over the period 2015 to 2018,” Olivierre said. One of her first decisions as minister had been to instruct NGC to expedite new contract negotiations. Under the current structure of the industry, while upstream producers deliver gas directly to LNG plants, all other sales must go through NGC, which has a dominant position on supplies to non-LNG downstream users.
The contracts between NGC and downstream users have typically carried no penalties for delivery shortfalls, meaning that the curtailments have a negative and unpredictable impact on processing plant throughput levels and, ultimately, on cash flow.
The energy minister said a related priority was to review LNG export contracts to maximise revenue to the state because “in this current scenario of low to moderate energy prices the state can ill afford such leakages”. In later comments Olivierre explained that government revenue from LNG had been adversely affected by changes in the destination of LNG exports. The minister said that 72% of the country’s LNG exports went to North America in 2006, but that this figure had fallen to 16% in 2015. T&T’s dominant market for LNG had become South America, with an estimated 62% of exports in 2015. South American LNG importers usually pay a premium on the US Henry Hub marker price for LNG. However, she suggested the government was not realising a fair share of that premium.
Under the current pricing formula, payments are made on a netback price basis, calculated as sale price less transport cost. However, Olivierre expressed the notion that this could change. “With many of our commercial pricing arrangements tied to a US destination, this country is realising netbacks well below the actual market price applicable to the true destination of our cargoes.” In 2015 the netback price was $1.93 per million British thermal units (Btu), 30% below the $2.75 per million Btu Henry Hub price the government had used for its budget calculations. Many of the government’s private sector LNG partners opted not to comment on the details of their pricing arrangements on the grounds of commercial confidentiality. However, BP issued a statement saying, “We believe that BP’s marketing of LNG cargoes is fully aligned with the spirit of the agreements with the government of Trinidad and Tobago”.
In her speech, the minister additionally highlighted the need for reform at state-owned oil company Petrotrin. She said it had failed to engender any significant production increases. A new board would be appointed to assess the company’s capabilities and outline a way forward. Olivierre expressed her belief that the company had to get its act together quickly. Thackwray “Dax” Driver, president of the Energy Chamber of Trinidad and Tobago, acknowledged the serious effect the global slump in oil and gas prices has had on T&T’s local industry. “With international prices set to stay lower for longer, it is clearly having a very severe impact. We are in fact suffering from a double whammy as we have both lower prices and lower production. Government revenues have also been affected. So it has put the energy sector in a very difficult position,” Driver told OBG.
Tax Changes Sought
One priority for the industry now is to attempt to ameliorate conditions during the current low-price environment. A number of oil and gas companies have complained that, at the current low level of international prices, the Supplementary Petroleum Tax (SPT) has become a marked disincentive to their operations.
The SPT was originally introduced as a windfall tax kicking in when oil prices reached $50 a barrel or higher. As a result of inflation over the years, together with oil market changes, $50 a barrel is no longer seen as exceptionally high price level. Since the SPT is levied on revenue, not profit, it is seen as particularly onerous. Companies say at prices of under $40 a barrel (as experienced during early 2016) they have difficulty operating profitably. Things begin to improve as prices rise above $40, but in the $50-60 range the extra tax burden of the SPT kicks in and pushes them into a “poverty trap” from which they cannot escape until prices move up beyond the $60 a barrel mark. This creates significant uncertainty over the financial consequences of the eventual oil market recovery. A recovery which sees prices hovering consistently around the $50-60 range would intensify the negative poverty trap effect. For this reason the Energy Chamber of Trinidad and Tobago, which represents companies active in the sector, has been suggesting potential amendments to SPT. One solution might be to taper the tax rate, so that the poverty trap effect is reduced.
Richard Jeremie, chief technical officer at the ministry of energy, told OBG, “the government is setting up a committee to review the taxes and incentives that currently exist. The new government has recognised that in the current low-price environment a review is needed; we also need to examine what happens to the SPT as prices begin to go up.” While the government would be reluctant to see any further reductions in its revenues from the energy sector, Jeremie noted that it also had a strong interest in finding ways to incentivise private sector companies to boost production and investment.
Colm Imbert, minister of finance, set out that position earlier in his first presentation of the fiscal year 2016 budget in October 2015, when he committed the government to “a new and appropriate fiscal regime designed to encourage further exploration in fields on land, on shallow and on deepwater acreage”. In his April 2016 mid-term budget speech the minister said the review would be extended further to include the tax regimes for marginal fields and areas of so-called “stranded gas”. The statement marks a shift in previous thinking on taxes.
A sign of the government’s willingness to review the fiscal regime came in March 2016, when officials agreed to modify the royalty structure for the small onshore Goudron oil field, operated by LGO Energy and the Morne Diablo, Beach Marcelle and South Quarry fields, operated by Range Resources. Changes were possible because of the type of farm-out and work-over contracts held by the two firms, which permit variation of fiscal terms. This differs from the majority of contractual arrangements, where the terms are applied uniformly to all operators and modifications require parliamentary approval. In the case of Goudron, the royalty rate was cut by 40% to under 10% when international oil prices are below $50 per barrel.
LGO Energy’s chief executive Neil Ritson said that the change was equivalent to a 10% reduction in costs at less than $50 per barrel and that “LGO has responded by increasing the level of ongoing investment… and this will be good for the company, its investors and for Trinidad generally”.
“The reduced overriding royalty rates are particularly encouraging for operators like Range who are committed to growing their production in Trinidad over the coming years and are a welcome incentive introduced by Petrotrin during this period of sustained lower commodity prices,” said a statement from Range Resources released in May 2016, adding that the net revenue benefit on a production rate of 2500 bpd would be around 7%.
Industry executives suggest additional tax and contractual changes might improve industry performance for the benefit of all stakeholders. They note that there can be important differences in the geology of different oil and gas fields, and that applying the same fiscal regime uniformly to most of them may not be the best way to maximise investment and production.
Oil and gas companies active in particular basins usually focus on developing the largest fields first. The fiscal regime that encourages them to do that may need to be modified to incentivise them or others who may come in after them, to develop the smaller fields in a subsequent phase. It is suggested that one way of doing this might be to transfer some operations from production sharing contracts to more flexible exploration and production licences.
Although the low price environment has adversely affected T&T, there is also a very positive account to be made of the industry’s resilience in both 2015 and 2016. “The positive part of the T&T story is that some really big investment projects have continued in active development throughout the price slump. Investment is holding up well, and that shows us that the companies have confidence in the country,” Driver told OBG.
Attention has focused on four major gas projects. These are first: the BPTT Juniper offshore gas project; second, the Sercan offshore gas development led by EOG Resources; third, BHP Angostura Phase 3; and fourth, an onshore compression project. In addition, the drilling of BHP deepwater wells is another major project, this time for oil.
The Juniper project consists of five subsea gas wells in the Corallita and Lantana fields, 80 km off Trinidad’s south-east coast. Drilling began in 2015 and the complex, including subsea trees, platform and pipeline links, is expected to come on-stream sometime in 2017. Initial production capacity will be 590m scfd. This represents an additional 15.4% on top of the existing total of T&T’s gas output. The total investment cost is $2.1bn.
Juniper is regarded as critically important as it should alleviate persistent shortfalls in gas supplies to downstream processing plants (see analysis).
The Sercan natural gas field lies to the northeast of T&T, and is being developed as a joint venture between EOG Resources and BPTT; EOG is the operator. The field lies in the East Manzanilla block some 65 km offshore. The development will use an unmanned 6-slot wellhead protector platform in a depth of 104 metres, with pipeline connections to EOG’s Toucan platform. Production should begin in 2017 with a flow of 275m scfd, equivalent to another 7.2% on top of the country’s total 2015 gas output.
Meanwhile, BHP Billiton and partners began drilling the first well in their Angostura Phase III project in November 2015. The Greater Angostura field is located in 36-46 metres of water around 37 km east of Trinidad. Production from Phase III is not expected to increase BHP’s total gas output of nearly 400m scfd, but will help prevent a drop by replacing output from other declining wells.
The BPTT onshore compression project, known as Trinidad Regional Onshore Compression (TROC), is expected to add 200-300m scfd worth of capacity, by increasing deliveries into the onshore pipeline network. “A project that will help in the short to medium term is TROC, being built here at Atlantic’s facility,” Nigel Darlow, chief executive of T&T-based Atlantic, told OBG. “The TROC project is designed to reduce pipeline pressure, which in turn will reduce pressure at the offshore wells, resulting in increased gas flow being available to Trinidad.” In January 2016 BHP Billiton said that despite low international prices, the company still planned to go ahead with a deepwater oil- and gas-drilling programme in five offshore blocks in the Atlantic during the course of the year.
The announcement was particularly significant since deepwater production costs tend to be higher, meaning that a large number of oil and gas companies globally have shelved such projects as they await a recovery in prices. The blocks are known as TTDAA 5, 6, 14, 23(a) and 29. BHP completed a marine seismic survey off the country’s east coast in February 2015. The total drilling commitment associated with the company’s licences are eight wells, with the first phase of the drilling expected to take around six months starting in May 2016. Additional wells may be drilled in a second phase.
The future of Petrotrin is emerging as an important issue for the local energy sector. The state-owned company is present in the upstream segment as an oil and gas producer, and in the midstream as the operator of the country’s only refinery, located at Pointe-à-Pierre.
In March 2016 US ratings agency Moody’s downgraded Petrotrin debt to “Ba3” from “Ba1”, reflecting what it said was the company’s “weak liquidity and high refinancing risk, triggered by persistent negative operating performance in the last couple of years”. The agency had previously downgraded Petrotrin once before, in May 2015, as part of a general review of T&T’s sovereign debt. Standard & Poor’s (S&P), the other main US ratings agency, had earlier also downgraded Petrotrin in November 2015, to “BB” weak from “BB+” stable.
In its March 2016 announcement Moody’s noted that Petrotrin had reported a loss in 2015, a year in which other regional refineries enjoyed improving margins because of the lower cost of crude. In the absence of major new investment to improve efficiency, Moody’s said Petrotrin’s refinery margins would be further compressed as crude prices recovered, meaning cash generation would remain weak for the foreseeable future, increasing its reliance on external sources of funding. The ratings agency also expressed concern over the small size and maturity of Petrotrin’s hydrocarbons reserves. This was offset on the upside by its effective monopoly in the wholesale distribution and export of refined products, and by a modest degree of integration between its exploration and production activities.
The company’s refinery has throughput capacity of 168,000 bpd. On average, in 2015 actual throughput was 125,308 bpd, or 75% of capacity. The refinery operates on a combination of imports and locally produced or “indigenous” crude. In 2015 Petrotrin imported around 78,356 bpd of crude oil, mainly from Colombia, Gabon, Norway and Russia. Petrotrin employs around 5000 staff; a large proportion of the employees are members of the Oilfield Workers’ Trade Union (OWTU). There has been a history of adversarial relations between the management and the leadership of the OWTU.
The company carries significant debt, estimated at $2.1bn, with a particularly substantial $850m bond repayment due in 2019. Concern has been by expressed by analysts over the quality of prior management decisions and execution, including building an ultra low-sulphur diesel (ULSD) plant and the World Gas-to-Liquids (GTL) Project. The ULSD project, which started in 2009 and was expected to take up to three years, has suffered cost overruns and delays and is still not finished.
According to a parliamentary committee of enquiry, the final cost of the project may be TT$4bn ($616m) and a large number of design faults, including structural steel weaknesses and insufficient earthquake protection have been identified, with the current Petrotrin management considering legal action against the main contractor. Meanwhile, the cost of the GTL project has been put at TT$3.3bn ($508m). The project, which was never completed, was designed to produce low emission fuels. Petrotrin was expected to sell the unfinished plant assets to NiQuan Energy Trinidad for $35m.
In October 2015 the government appointed a new Petrotrin chairman, Andrew Jupiter, who in a stark warning to staff said that the company was spending more than it earned and “unless this is quickly reversed we may soon go out of business”. At the same time Petrotrin outlined some key elements of a recovery programme for FY2016. This included a focus on the safety of operations though an asset integrity management system (AIMS) including pipeline integrity, inspection and refurbishment. The company recognised that most of its pipelines “are severely aged”. Another key objective grouped together a series of “oil winning activities” including a combination of new drilling and workover programmes at existing wells. Work was to be focused on developing the South West Soldado field and on a range of enhanced oil recovery procedures. In response to the Moody’s downgrade the new management said it was beginning to make progress by reducing operating costs, maintaining crude output levels and improving refinery throughput. “The cost of production is far too high at Petrotrin. Hard decisions are necessary and the company needs serious structural change,” Driver told OBG. He said problem areas included the need for massive investments in asset integrity; a high-cost structure created through the terms and conditions of employment for staff that also have to be followed by contractors; and reliance on imported crude oil for the refinery, given falling production of indigenous crude. Driver felt the government could consider the type of reforms introduced over a decade earlier at Ecopetrol, the Colombian state oil company, which was listed on the stock exchange and encouraged to operate more commercially.
The prospect of continuing low hydrocarbons prices makes 2016 likely to be a very tough year for the Trinbagonian energy sector. However, some insiders point to reasons for optimism. “I am comfortable with the way the industry is being managed. The majority of the companies in the sector have high levels of expertise and management sophistication, indeed, many of them are global companies operating in the local environment,” Rampersad Motilal, director of the Energy Institute at the UTT told OBG. He suggested, therefore, that while conditions are difficult, the main players will find a way to come through this difficult time, through new projects and the use of enhanced techniques.
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