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Trinidad’s new energy minister seeks to tackle oil production

A new government took office in September. The energy ministry is focusing on securing new production of oil and cleaning up the power-generation sector

The Caribbean state of Trinidad & Tobago has a new energy minister, Nicole Ollivierre, after the People’s National Movement (PNM) won the general election on 7 September. The most urgent task facing her is arresting the ineluctable decline in crude oil production. The island is also looking at imports of other fuels.

Trinidad & Tobago is one of the world’s oldest oil producers – its first barrel was lifted in 1908. It hit a production peak of 229,589 b/d on average in 1978, six years after Amoco – now BP – discovered three new oilfields off the east coast.

Unfortunately, no new finds of any substance have been made since then, either on or offshore and production in July averaged 67,347 b/d. Most of it was lifted by the state-owned company, Petrotrin.

This is bad news on many fronts: it deprives Petrotrin itself of the crude it needs to fill out its 168,000 b/d full conversion refinery at Pointe-a-Pierre in south Trinidad. The energy ministry allows about 31,000 b/d to be exported and it lowers the tax revenue that the government can expect from the energy sector, a challenge for the new administration to confront as it moves immediately to prepare the 2015-2016 national budget.

The last minister of energy, Kevin Ramnarine declared that reversing the decline in crude oil output was his main goal when he assumed office but has left without seeing it happen.

Oil production has been held stable because of regular workovers and development drilling by the companies that lift oil, which include not only Petrotrin, but a number of small and medium-sized firms, collectively called the independents, most of whom are foreign owned, such as Range Resources – now Chinese managed – Touchstone Exploration and Leni Gas and Oil.

As happened in the late 1970’s, a large new oil find could give the required boost to oil output and former minister Ramnarine did set in motion an exploration programme designed to achieve that.

During his four-year watch, he signed off on three new exploration & production licences for onshore blocks – St. Mary’s, which went to Range Resources, Ortoire (Touchstone) and Rio Claro, which was given to a local company, Lease Operators.

This was a well-received initiative, since there had been no dedicated onshore bid rounds for 15 years and land exploration is widely expected to be the activity that delivers more oil in the future (in addition to the nearshore west coast marine area (WCMA), where Petrotrin again holds most of the acreage, under its Trinmar subsidiary.

The E&P licences commit the three companies involved to shooting 295 line km of 2D seismic, 60 km² of 3D seismic and the sinking of 12 exploratory wells, all at a cost of $55m. The ministry estimates another $945m could thereafter be spent on development-related investment if the exploration phase is successful.

Offshore Trinidad is now considered a gas-prone province, considering that that is the hydrocarbon identified by all explorers off the east and north coasts in the last 15 years, principally by the international oil companies (IOC’s) who prefer the offshore. The only IOC operating on land is the UK company BG and it mainly produces gas, with a sprinkling of condensate.

However, one of the four new blocks offshore, allotted during the stewardship of Carolyn Seepersad-Bachan, who preceded Ramnarine as minister for one year, is considered a potential oil producer – Block 4b, in the east coast marine area (ECMA).

The others given out at the same time – North Coast Marine Area (NCMA) 2, NCMA 3 and NCMA 4 – are all seen as likely for natural gas, which, it is hoped, will bring condensate with it.

Another offshore block awarded during Ramnarine’s era was 5d, off the south east coast, which BG took on under a production sharing contract (PSC), the preferred licensing method for marine acreage. But this, too, is regarded as gas prone.

Oil search

So where does all that leave the chance of an oil discovery offshore? The long shot in that regard is the deepwater region, which sweeps in an arc from north of Tobago on the boundary line with Grenada in the west, out into the Atlantic, terminating southeast of Trinidad, on the boundary line with Venezuela.

Deepwater is defined by the energy ministry as anything more than 1,000m below the surface.

Two deepwater block auctions were conducted by the ministry over the last five years, out of which came successful bids for nine blocks, two of these from BP for blocks 14 and 23a. The rest – Blocks 3, 5, 6, 7, 23b, 28 and 29 – were all won by BHP Billiton, in some cases in concert with others. It has BG as its partner in four – Blocks 3, 5, 6 and 7 – and Repsol in Block 23b. BP, for cost-cutting reasons rather than any lack of faith in the potential of the blocks, has invited BHP Billiton to take over operatorship and a 70% holding in blocks 14 and 23a.

So the Anglo/Australian IOC now has responsibility for the entire, nine-block deep water exploration programme.

This imposes on it the tremendous responsibility of being successful in what is regarded as the country’s “last frontier” for new oil and gas discoveries, barring deep horizon drilling both on and offshore, which has not been undertaken to any great degree during the life of the energy industry.

No estimate has been given or how much oil could be added to current production by means of deep horizon drilling but energy ministry in-house estimates suggest deep water crude oil potential ranges from a low of 1.2bn barrels to a high of 6.6bn barrels of oil initially in place (OIIP). Natural gas potential is put at between 11.4 and 37.8 trillion cf. For its nine blocks, BHP Billiton arranged the largest seismic survey ever conducted by an IOC – 20,199 km² of 3D – almost four times bigger than the area of the state.

BHP Billiton and its partners will splash out $1bn on the exploration phase, with a lot more on the development period which will follow, if it does.

The company’s country manager, Vincent Anthony Pereira, who quit BP’s local office to take on the BHP Billiton job, is reluctant to be specific about potential resources and reserves but does say he holds “a somewhat more conservative view than that of the ministry.”

He says: “The way I think about it, for the deep water to work, you need to find hydrocarbons in very significant quantities. The economics of development are so challenging in the deep water, you need scale. So whatever numbers you want to play around with, at the end of the day, what is required is significant volumes of hydrocarbons. So we are not talking about 50m barrels of oil, we are talking about hundreds of millions of barrels of oil. Likewise with gas – we’re not talking about 100s of billions of cubic feet, we’re talking trillions.”

Former minister Ramnarine says BHP Billiton stood a good chance of a successful hydrocarbon discovery in the deep water because of the “depositional environment” in which it was operating.

“Oil has been found in the deep water Gulf of Mexico because of the depositional environment of the Mississippi river system. Oil discoveries in the deep water off the west coast of Africa are related to the depositional environment of the Niger River system. Oil discoveries in the deep water in India are a product of the depositional environment created by the Krishna and Godavari rivers. Oil discoveries in Brazil’s Santos Basin deepwater is a product of the depositional environment of the Amazon river system,” he says.

Likewise, “the depositional environment in deep water Trinidad and Tobago is a product of the Orinoco river system.”

But that is not the only favourable factor. “There is also the presence of source rock, in the form of the Cretaceous. The 2D seismic originally acquired in 2002 and reprocessed in 2011 shows the existence of big reservoir systems and large traps. What’s more, there is also the “Atlantic mirror” theory in Trinidad & Tobago’s favour “which says that there are similarities between the Tano Basin in Ghana and the deep water off French Guiana/Suriname/Guyana. In 2011, Tullow and Shell created a lot of excitement when they discovered oil in French Guiana with the deep water Zaedyus well, which many believe proved the theory correct. Exxon has since discovered oil in Guyana’s deepwater. The Nigeria/Equatorial Guinea deepwater is perhaps a similar analogue for our own deepwater.”

Pereira says he hopes to be able to sanction the first well in 2016, though at the time he was speaking he had not yet decided, on the basis of the seismic interpretation, in which of the nine blocks that was likely to take place.

Fortunately for the decision-makers, “the seismic data quality is very good and not all seismic surveys start in that position. Many of them can have some really noisy data that you have to try and filter out.”

The BHP Billiton country manager cannot resist congratulating his own company on the speed with which the pre-drilling phase has been undertaken. “We have optimised our schedule enormously,” he notes, “moving from the signing the PSC to preparing to drill over a three year period, is an enormous accomplishment. Enormous. I can’t stress that enough.”

It was not only geological factors that encouraged the Anglo/Australian IOC to bid aggressively for exploration blocks in deep water.

Another incentive was a tax regime that the ministry had made as attractive as possible. For tax purposes only, deep water was re-defined to start at 400m, so companies other than BHP Billiton could be encouraged to consider additional drilling. Cost recovery (“cost oil or gas” as defined in the PSC), was increased from 60% to 80%, including a write-off of 140% on each well sunk. BHP Billiton will also be able to claim on any future production a higher than normal “profit oil or gas” share under the PSC because the ministry’s share is based on existing supplemental petroleum tax (SPT) and petroleum profits tax (PPT) and both of these have been reduced for deep water activity.

Companies operating in shallow and average water depths offshore pay 33% SPT at oil prices between $50 and $90/barrel (there is no SPT on gas production) and 50% PPT, from which SPT is deducted. SPT for land-based operators is 18%. SPT is paid on a quarterly basis and PPT at the end of the year. Royalty rates, also deducted from PPT, range from 10%-15% on a barrel of oil and $0.015/m ft³ on natural gas.

It should be stressed that while new crude oil finds from exploratory drilling would be a welcome addition to crude output, Trinidad has no shortage of crude oil resources and reserves.

These consist of two categories: “stranded oil” which is found in existing reservoirs; and heavy oil, which the ministry defines as that with an API gravity of 18 degrees and below. Both types have historically been considered by the oil companies as too expensive to exploit, more so now that the oil price is down.

Resources in these two categories have been estimated by the country’s leading geologist, Krishna Persad, at 3.5bn and 4bn barrels, respectively (as against official country reserves of 199.54m barrels (proven), 85.46m (probable) and 124.77m (possible) or 409.77m barrels all told, according to a December 2011 audit by Netherland Sewell & Associates.

A Ryder Scott audit has put condensate reserves at 43.45m (proven), 24.39m barrels (probable) and 30.83m barrels (possible). Adding both the oil and condensate 3P reserves produces a total of 508.42m barrels as of December 2011.

Strict criteria were used by the auditors to define the 3P reserves which means that neither stranded or “left behind” oil or heavy oil were included. To have them included requires a definite move to recover the crude in both categories.

Before he left office, the ex-minister had engaged researchers at the University of Trinidad & Tobago (UTT) to undertake a “techno-economic analysis of heavy oil in Trinidad” (Tobago has no hydrocarbons) as well as a “tech-economic analysis of carbon management in Trinidad & Tobago through coupled enhanced oil recovery and geological storage.”

These two subjects are linked because the capture of CO2 emissions from ammonia plants at the Point Lisas industrial estate in central Trinidad and its use in the oilfields of south Trinidad to recover both stranded oil and heavy oil was a central part of Ramnarine’s plan to add to crude production, which the incoming minister will undoubtedly wish to continue to pursue.

Persad has been a fervent backer of CO2/EOR and the ministry has taken up the cause. The state-owned gas aggregator, the National Gas Co (NGC), has been handed the task of having the pipeline to carry the CO2 built.

Both the recovery of stranded crude and heavy oil, as well as any hydrocarbon discovery in the deep water, or anywhere else for that matter, will take years to be brought to fruition, so the new energy minister may find that any increase in the production of crude oil is likely not to happen until well into her five-year term.

Domestic gas plans

There’s probably better news on the gas front where Trinidad & Tobago is already a major LNG producer and exporter thanks to Atlantic LNG at Point Fortin in the southwest. The four trains there yield about 15mn mt/y, of which only a very small proportion is sold in the Caribbean itself, specifically to Puerto Rico and the Dominican Republic.

A new company called Caribbean LNG wants to change that focus and is moving along with an initiative that will target the Caribbean only.

The company is a joint venture between Gasfin Development, registered in Luxembourg but whose principals, headed by CEO Roland Fisher, mainly live in the UK, and Parallax, which describes itself as “an integrated energy investment company with an LNG focus,” which has funds and is run by Martin Houston, who set it up in January 2014.

Houston is well known to the worldwide LNG fraternity because of his role as chief operating officer of BG. He developed a mercantile approach to what had been previously a very rigidly traded commodity, turning the company into a major LNG trader thanks to flexible delivery contracts. He left during the change of leadership in 2011.

Gasfin Development prides itself on being “dedicated to the provision of small to mid-scale LNG production, shipping, regasification and distribution solutions.” It has already built such plants in China.

Fisher was the first to recognise the potential of LNG deliveries to the small power stations in the eastern Caribbean, which were buckling under the weight of high costs for heavy fuel oil and diesel, particularly prior to the current reduction in prices.

This was forcing them to charge as much as $0.32/kWh, which destroyed the competitiveness of their business customers in particular, while drawing the ire of their residential customers. It is little surprise that, against this background, almost 200,000 Jamaican households have been found to be illegally tapping into the lines of the Jamaican Public Service Co, the country’s sole power distributor.

Trinidad & Tobago has long switched to using gas to fuel its power stations and the government has ensured that average electricity pricing is around $0.6/kWh. Fisher and Houston want to convert around 70m cf/day of gas into 0.5m mt/year and undercut oil-based fuels in as many eastern Caribbean countries as possible.

Their first targets are, surprisingly, none of the anglophone Caribbean Community and Common Market (Caricom) states but the French overseas departments of Martinique and Guadeloupe, which are furthest ahead in switching from oil to gas.

In 2011, Gasfin and Electricite de France (EDF), which runs the power stations in both department, signed an agreement in Paris “for the development of a project to supply natural gas to EDF’s power generating facilities in Martinique and Guadeloupe.”

Each will require 200,000 mt/year, which leaves 100,000 mt available for sale elsewhere in the region.

Gasfin and Parallax expect to sign the project agreement for Caribbean LNG by the end of 2015 and building the $400m plant (2012 prices) will then proceed at the Labidco industrial estate in south west Trinidad. One of the two state-owned gas companies, NGC or its subsidiary, National Energy (NE), is likely to have a share in Caribbean LNG and NGC will supply the gas needed.

Ramnarine had estimated “late 2017 or early 2018” as the most likely date for first exports from Caribbean LNG, by which time he expected the company to have “sewn up its customers.”

As a first for the eastern Caribbean region, the question arises as to how to price the gas shipped from Trinidad. Gas prices are down, along with oil prices but Caribbean LNG will need a reasonable margin on its sales, especially when it will have competitors for fuel-displacement in the region, namely gas liquids, such as propane and butane. These are being pushed as substitutes by traders and producers based in the US, such as BP and Vitol.

The power producer in the US Virgin Islands has already switched to propane supplied by a consortium headed by Vitol and expects to cut 20% off current prices as a result. The US’s Tropigas is trying to get the Puerto Rico Electric Power Authority (Prepa) to do the same with some of its stations in the US Commonwealth territory.

Though gas prices in the US are probably the world’s most competitive at the moment, some analysts have argued against Caribbean LNG using that as a benchmark. The Institute of the Americas, an inter-American public policy think tank based in La Jolla, California, says Henry Hub pricing would not “properly reflect the realistic options for landing gas in the Caribbean.”

More useful, it thinks, would be a “Caribbean Basin Index” for the LNG trade in the region, which it says could be based on “Henry Hub-plus” to reflect the cost of transport from Louisiana.

Renewable energy

Caribbean LNG will have to work that one out for itself when it comes to negotiating with its customers but it does have the advantage of the Caribbean Energy Fund, jointly created by the Trinidad & Tobago government and the Inter-American Development Bank (IDB), for assisting Caribbean LNG’s customers in preparing themselves to meet the costs involved in receiving a regular supply of LNG and of establishing renewable energy projects, if they are so minded.

IDB has already pledged $600m to the Energy Fund for Caribbean Sustainability, to give it its formal name, and Trinidad & Tobago and other funding institutions, such as the Caribbean Development Bank, are also expected to help make up the target of $1bn.

One gas-related challenge the new minister faces, however, will be in bringing the gas reserves known to lie in three pairs of blocks cross-border with Venezuela into production. With gas demand likely to rise because of the domestic gas-based industrialisation programme and new export projects like Caribbean LNG, as much gas as can be made available to the country is required.

Of the three pairs of gas blocks, the one most advanced towards eventual exploitation is block 6D in Trinidad & Tobago waters, where a discovery called Manatee was made and block 2 in Venezuela, where the successful Loran well was drilled. Between them, about 10.25 trillion ft³ are available, of which 2.69 trillion ft³ are on the Trinidad & Tobago side.

Ramnarine and his Venezuelan counterparts were able to get the project to the stage where a unit operator would have been chosen and a unit operating agreement drawn up. This has to be approved by the energy ministers on both sides.

Since the incoming minister in Trinidad & Tobago would have to be briefed on all this, it is unlikely that work will be started for some time. 

The new minister will also be required to decide on other major issues, which include whether Trinidad & Tobago will pursue renewable energy, given low traditional energy costs. There are still an estimated 300m mt of tar sands estimated which could be worth exploiting. 

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