ENERGY Caribbean Yearbook (2013-14) by MEP Caribbean Publishers

The annual review of the Caribbean energy industry

YEARBOOK 2013/14

Contents Caribbean energy map

Written by David Renwick

2-3

Section 1: the big issues World energy outlook Caricom energy policy 1 Caricom energy policy 2 Energy security The future of gas Caribbean gas market The green agenda Going international Alternative fuels Trinidad & Tobago’s oil revival 1 Trinidad & Tobago’s oil revival 2 Cross-border gas Deep water exploration Independents Climate change Local content Gas-based development

Jeremy Taylor

4 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

Section 2: the energy producers Trinidad and Tobago Suriname Barbados Belize Jamaica Guyana Cuba

22 28 30 32 33 34 35

Section 3: company profiles Atlantic CIBC FirstCaribbean International Bank Gasfin Development SA Methanex Trinidad The National Gas Company Repsol Trinidad & Tobago Solaris Energy

Editor

36 38 40 42 44 46 48

Sales Denise Chin

Design Bridget van Dongen

Administration Joanne Mendes, Jacqueline Smith

Cover photo Drilling (courtesy Petrotrin) The ENERGY Caribbean Yearbook is published annually by Media & Editorial Projects Ltd., 6 Prospect Avenue, Maraval, Port of Spain, Trinidad and Tobago Tel: (868) 622-3821 Fax: (868) 628-0639 energy@meppublishers.com Sales: dchin@meppublishers.com Distributed free to subscribers of the bimonthly ENERGY Caribbean newsletter Retail price US$25 + p/p For subscription and retail information please visit www.meppublishers.com or call (868) 622-3821

iss

ipp

New Orleans

Tallahassee

Houma

Daytona Beach

Orlando USA

G u l f

Miami

o f

Nassau

M e x i c o

Bahamas

Havana

Cuba

Cayman Islands

Kingston

Villahermosa Flores

C a r i b b e a n

Belize

Tuxtla Gutierrez Honduras

Caribbean energy map

Port-au-Prin

Nicaragua

Maraca

San JosĂŠ

Costa Rica

Oil or gas field

Jamaica

Panama

Refinery LNG train Eastern Caribbean gas pipeline English-speaking territory French-speaking territory Dutch-speaking territory Spanish-speaking territory

P a c i f i c O c e a n

A t l a n t i c Haiti

Port-au-Prince

Dominican Republic

San Juan

Santo Domingo

Puerto Rico

O c e a n

Virgin Islands Philipsburg

St Maarten

St Kitts & Nevis

Basseterre

Antigua

St John

Montserrat

Pointe-á-Pitre

S e a Aruba

Oranjestad

Guadeloupe

Roseau

Dominica

Fort-de-France Castries

Curaçao

St Vincent & the Grenadines

Martinique St Lucia

Barbados

Kingstown

Bonaire

Willemstad

St George’s

Grenada

Scarborough

Port of Spain

Maracaibo Valencia

Caracas

Bridgetown

Tobago

Trinidad

Venezuela Georgetown

Colombia

Guyana

Paramaribo Cayenne

Suriname

French Guiana

energycaribbean YEARBOOK 2013/14

Energy issues world energy outlook

Oil price will stayCompanie high

n the Caribbean, the international energy outlook is a good deal brighter for oil and gas producers than for consumers. With reviving economic growth in North America and continued economic expansion in the Far East, the price of oil is likely to stay within the $95-100 range, well above the cost of production of any reasonably efficient company. The gas price will probably remain lower in the United States than has been the case until recently, moving between $4 and $4.50 per mmbtu. But it will continue strong in major Eastern markets such as Japan, South Korea and Taiwan, and even in the European Union, where demand for LNG is rising. Until the US starts to export LNG late in the current decade, pressures on pricing will intensify. Several LNG projects in other countries are having difficulty getting off the ground, because of spiralling costs for LNG construction, most notably in Australia, Canada and Qatar, and because of infrastructural deficiencies in areas like East Africa, the new hotspot for LNG development. Spokesmen for the BG Group in the UK, a major LNG trader which operates in Trinidad and Tobago, insist that “it is not going to be easy to meet an enormous supply challenge. LNG projects these days are notoriously difficult to deliver.” With LNG expected to comprise 14% of all globally traded gas by 2025, there is clearly a challenge in bringing enough supply projects on stream to be able to meet this demand.

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The price of oil is likely to stay within the $95-100 range, well above the cost of production of any reasonably efficient company

nother piece of bad news is that coal could be making a comeback, thanks to the high cost of oil. The Paris-based International Energy Agency (IEA) suggests, startlingly, that “demand for coal could catch up with oil by 2022.” As early as 2017, global coal consumption could stand at 4.32 billion tonnes of oil equivalent, compared with 4.4 billion tonnes for oil itself, the IEA predicts. This, of course, will be terribly unhealthy for the environment, since coal is the most polluting fossil fuel, and already over 66% of climate change-causing emissions emanate from the energy sector. The expectation was, of course, that energy-importing countries would turn to the more climate-friendly natural gas. But, with export projects facing long delays, coal could bridge the gap in the market. The price competitiveness of coal also poses a threat to the development of renewable energy (RE) sources in 2013 and beyond. If coal is cheaper and the gas price remains high outside North America, electric utilities will ask themselves: why convert to RE? Governments could artificially depress the price of RE to make it attractive to

Atlantic LNG tank (courtesy bpTT)

Energy issues

the consumer, but at a time of constrained budgets everywhere, this is hardly an appealing strategy.

ne energy concern has now been taken off the table and will no longer be exercising the energy planners’ minds in 2013 and beyond – peak oil. The day when oil production reach its zenith and starts to decline has now been pushed well into the future – and may not occur at all, because new sources of fossil fuel energy are coming into the picture to add to existing oil output. These are the “unconventional” fuels – shale oil, shale gas, tar sands, coal bed methane, biofuels – that are being retrieved in greater quantities and will replace (and probably add to) conventional production from existing geological structures.

If coal is cheaper and the gas price remains high outside North America, electric utilities will ask themselves: why convert to renewables?

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Countries energycaribbean YEARBOOK 2013/14

Energy issues caricom energy policy 1

The Caribbean’s nightmare import bill Companie

xcept for Trinidad and Tobago, the countries of Caricom have long faced the acute problem of having to import the energy they need for their economies to function. This dependence has been worsening. “The total cost of the annual fuel import bill for the region today is around (US) $8-9 billion,” says Desiree Field-Ridley, officer in charge of trade and economic integration at the Caricom secretariat in Guyana, “with the tendency to be rising.” Compare that with $2.5 billion in 2006, when the Caricom task force, appointed three years earlier with a mandate to “develop mechanisms for a regional energy policy,” was finalising its draft report. The magnitude of the dependence is staggering. With so much foreign exchange going to pay for one product, however essential, there is a “deleterious effect”, as Field-Ridley puts it, “on the economic and social development of the net

energy-importing countries of Caricom.” The effort made by Venezuela in 2005 to ease that “deleterious effect” through the PetroCaribe oil supply programme only plunged the 13 Caricom states who signed up for it further into debt and did little to ease their foreign exchange liability, according to FieldRidley’s figures. After a down-payment of part of the commercial price would be made, buyers would pay the balance over several years.

Countries

espite PetroCaribe, when the price of oil soared to $147 a barrel in 2008, Caricom’s energy-importing countries “were almost at a panic stage”, to quote Joseph Williams, manager of the secretariat’s energy unit. The secretariat responded with a programme named C-SERMS (Caricom Sustainable Energy Road Map and Strategy), to help accelerate the move towards renewable energy and more efficient usage in member states.

Traffic in St. John’s, Antigua (courtesy Hugh Fiske/Flickr)

C-SERMS has now been subsumed into the Caricom Energy Policy, which updates and completes the 2007 task force report. It was adopted by regional energy ministers at a special Council for Trade and Economic Development meeting in Port of Spain on March 1, 2013, and was due to go forward to the Caricom heads of government in July for formal ratification.

he major petroleum products on which Caricom depends are residual fuel oil for power generation (57% of the total in 2008) and motor gasolene for transportation (16%). “Other petroleum products” accounted for 13%. The larger Caricom states like Jamaica and Guyana have to divert 4060% of their total export earnings to pay for this lifeline, leaving relatively little for other imports, including food and medicines. As the Caricom Energy Policy points out, “for the tourism/services-oriented countries, such as Belize, Grenada, St Vincent and the Grenadines and Barbados, petroleum imports range from 13% to 30% of export earnings.” When export income falls, as it did in Grenada in the year under review (2008), “a higher oil import/foreign exchange earnings ratio” has to be faced. In Caricom, Jamaica is most heavily dependent on imported energy. It requires crude oil to feed its 36,000 b/d Petrojam refinery and refined products to run the various parts of its economy. In 2008, it imported 16.3 million barrels of fuel oil for power generation, and 4.3 million barrels of gasolene and 3.6 million barrels of diesel for transportation.

Energy issues

caricom energy policy 2

Is the Caribbean serious about renewable energy?

he principal purpose of the Caricom Energy Policy is to reduce substantially the Community’s historic dependence on imported petroleum products. Once approved by the regional heads of government, it will provide a measure of energy security that has not been possible when the cost of oil can fluctuate widely overnight and import needs are decided by the state of the economy from year to year. A major source of Caricom’s petroleum imports is actually one of its own – Trinidad and Tobago. But that is small comfort, since Trinidad and Tobago sells its refined products at prices related to international crude benchmarks. Caricom states do get some relief from the part-payment they make on Venezuelan oil, but that too is little comfort when deliveries fall short, as they have often tended to do. Hence the problem: how to adjust the energy mix so that oil plays a less burdensome part? The Caricom Energy Policy settles unsurprisingly for a multi-pronged approach, focusing on enhanced renewable energy alongside efficiency measures to reduce the amount of energy needed to create each dollar of GDP. It lists renewable inputs as solar, wind, biomass, landfill gas, bio-ethanol, hydro, geothermal, waste-to-energy, marine energy (including tidal and wave), and even hydrogen.

The Caricom policy document points out that, though some progress has been made with renewable energy in the region, “the overall proportion of [its] contribution in primary energy still remains quite low”. The creation of a “sustainable energy path” will require “commitments to increasing the contribution of both RE and EE.” EE (energy efficiency) may prove more difficult to adopt than RE (renewable energy) because it requires a conscious change in human behaviour. Governments are urged to make EE a more attractive exercise through “fiscal and other incentives”, especially “solarthermal systems for hot water production in all sectors” and setting “minimum efficiency standards that require electric

utilities to decommission inefficient generation plant and conduct demand side management programmes.”

he electricity sector is seen as the main channel for increasing RE, since renewable sources can “provide direct replacement for fossil fuels as the principal source (base-load type) for generating electricity at the national level.” The 2009 C-SERMS initiative (the Caribbean Sustainable Energy Road Map and Strategy) will take responsibility for promoting both RE and EE. It is expected to set “quantitative targets for sustainable energy and “provide an implementation framework, engaging all member states and actors in the energy sector.”

Compani The Caricom Energy Policy focuses on increasing renewable energy while simultaneously pursuing efficiency

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ost of those resources are available domestically and do not involve the use of precious foreign exchange once plant and equipment are installed. Their very presence enhances energy security. Even geothermal-fired electricity exchanged between two members could be regarded as a national source.

Wigton wind farm, Jamaica (courtesy pcj.com)

energycaribbean YEARBOOK 2013/14

Energy issues energy security

A price you can’t afford

nergy security is said to be the ultimate goal of the Caricom Energy Policy (CEP). But what exactly does that mean? According to the policy document, it means: “The availability of, and timely access to, energy resources of an acceptable quality at competitive prices that are both affordable for consumers and reasonable for producers and reflect true final costs for producing and supplying energy.” There’s a mouthful for you. In fact, Caricom has always enjoyed energy security, thanks to Trinidad and Tobago, the only energy exporter in the region. A spokesman for Petrotrin, whose refinery has traditionally supplied gasolene, diesel and fuel oil to the Caribbean, once observed to this YEARBOOK: “Refined products from Trinidad and Tobago have always been essential to the lifeblood of the region. Refining started in Trinidad in 1911 and we have always had a tradition of supplying oil to the Caribbean. We have always met our commitments, through good and bad times. The other islands could always have relied on Trinidad for oil – even when they did not pay their bills.”

upplying a scattered archipelago made up of relatively small markets is no easy task. As the Petrotrin spokesman pointed out: “Petrotrin is a merchant refiner, meaning that we buy crude oil, we have some of our own and we make product and people order it, with required specifications – sulphur is a certain range, diesel of a cetane number, we will make that for you. This demands extraordinary flexibility from the refinery. We respond to specific customer needs.” That historic security role was ostensibly taken over by Venezuela when it launched its PetroCaribe programme in 2005. Trinidad and Tobago energy minister Kevin Ramnarine acknowledged recently that “some security is now being provided by the Venezuelans”, adding: “But Trinidad and Tobago still provides significant volumes of fuel to the Caricom member states.” The reason for that is refinery flexibility, which Venezuela’s PdVSA has been unable to match on a consistent basis. So “availability of and timely access to energy resources” is not a problem for Caricom. “Competitive prices”, however, have been a serious challenge in recent years. Soaring oil costs have hit Caricom companies and households hardest through the cost of gasolene at the pump (governments have had to bargain with fuels retailers to keep rises to a minimum) and in the cost of electricity.

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“The other islands could always have relied on Trinidad for oil – even when they did not pay their bills”

uel costs represent 40-50% of generation costs, says the regional utilities body, Carilec. The average regional fuel cost was $150 per megawatt hour in 2010. This has translated into crippling electricity bills throughout Caricom, except in Trinidad and Tobago (see box). Affordable pricing is thus the big challenge. Carilec itself has called for “the creation of an enabling environment, both regulatory and institutional, for the introduction of indigenous renewable energy into the national energy mix.” The CEP comes down heavily on the side of RE. But will that, at least in its early days, really help to make power costs “more affordable” for consumers? Carilec itself has cast doubt on the likelihood of that happening. The Jamaican public utility restructuring and regulation consultant, Winston C. Hay, has categorically told this YEARBOOK: “RE is not the immediate answer to costs. I believe it ought to be encouraged and governments are developing incentives for individuals and small companies to get involved in RE, but, if anything, it will increase the price of electricity in the short term.”

Countries Caricom electricity prices Selected countries (US$ per Kwh, 2012)

Antigua St Vincent Barbados Grenada St Kitts/Nevis Guyana Jamaica Trinidad and Tobago Source: Energy Dynamics

0.38 0.36 0.36 0.35 0.34 0.34 0.32 0.06

Energy issues

the future of gas

Regional policy undervalues gas

any, perhaps most, of the electric utilities in Caricom want to switch to natural gas for power generation instead of the high-priced diesel and the light and heavy fuel oil they have traditionally used. But the Caricom Energy Policy (CEP) does not appear to grasp the significance of that. In a document meant to outline the energy path that regional states are expected to travel in the coming decades, only perfunctory mention is made of gas. True, the policy does encourage member states to “implement programmes and projects which aim to incorporate and optimise the use of natural gas in the energy mix” and to “establish natural gas as a key energy transitional source for the region”. But it fails to note the fact that specific gas-supply investments are already going ahead. These are, of course, the Eastern Caribbean gas pipeline, which will take gas from Trinidad and Tobago to Barbados, and the small LNG plant proposed for La Brea in southwest Trinidad. Compressed natural gas is touted as another gas source for Caricom, but the CEP appears much more enthusiastic about renewable energy, and urges the adoption of “geothermal, hydro, bio-fuels, solar power, wind power and waste-toenergy, which can provide direct replacement for fossil fuels as the principal source (base load type) for generating electricity at the national level and can support regional, or cross-border, supply of electricity.”

derived from natural gas, with 2% from RE, with oil accounting for the remaining 93%.

as evangelists urge governments to increase that 5% rather than to undertake the complex and expensive exercise of creating geothermal and hydro-electric facilities, at least in the short term. Indeed, the 2010 Nexant study for the World Bank on “Regional Energy Solutions for Power Generation in the Caribbean” recommended gas more often than RE as part of the strategy to reduce energy costs up to 2028. Gas was identified as the main substitute energy source for oil for Barbados, Jamaica, St Lucia, the Dominican Republic and Haiti. With specific reference to the Caribbean gas pipeline, Nexant said it would be a “highly economic” investment for Barbados “if it displaces heavy fuel oil and diesel”, as it will. Barbados’s own National Energy Policy (2007) envisaged that 70% of its power would be generated by natural gas by 2030, with only 10% from oil and 20% from RE. The country will need about 46 mmcfd of gas to achieve this goal, which suggests it may be in line for LNG as well as pipeline gas. While natural gas is guilty of higher greenhouse gas emissions than RE, they are still far lower than oil’s. CO2 releases from natural gas are 117,000 pounds per billion British thermal units of energy input, while those of oil are 164,000. The figure for coal, by comparison, is 208,000 pounds. Natural gas releases 92 pounds of nitrogen oxide per billion btu of energy input, compared with 448 for oil, and one pound of sulphur dioxide compared with 1,122 pounds from oil.

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hat last reference is to Nevis and Dominica, which have plans for developing geothermal power and exporting it by undersea cable to neighbouring territories. It is also a reminder of Guyana’s long-held desire to use its large rivers for hydro-electricity and to export surplus power to the island archipelago. As the CEP points out: “Cross-border transmission of electricity can facilitate a paradigm shift where more member states can become exporters of energy” – rather than just Trinidad and Tobago with its existing trade in refined petroleum products, and regional gas delivery to come. Trinidad and Tobago might justly feel aggrieved that the gas it is prepared to offer its fellow Caricom members as an alternative to oil has been so casually treated in the CEP. According to the St Lucia-based Caribbean Electric Utility Services Corporation (Carilec), the regional “trade union” for the power sector, only 5% of primary energy consumption is

Potential gas demand Power generation capacity (peak demand) in line for conversion to gas

Countries Antigua Bahamas Grenada Guyana Jamaica St Lucia St Vincent Suriname

51MW 308MW 30.5 MW 94MW 644 MW 55.9 MW 24.5 MW 145 MW

Source: Caribbean Energy Policy, 2013

energycaribbean YEARBOOK 2013/14

caribbean gas market

Energy issues

TT must get moving

s Trinidad and Tobago moving fast enough to secure the emerging market for natural gas in the Caribbean? Many energy analysts think not. At the time of writing, Gasfin Development SA, the Luxembourgbased company leading the way in trying to push the country into making sales contracts with Caribbean electricity utilities, had still not been able to line up an assured gas supply with which to approach potential customers. Only about 70 million cubic feet a day (mmcfd) is required for the first train of about 500,000 tonnes a year that Gasfin would like to see sited at the Labidco industrial estate at La Brea to liquefy gas for regional export. Perhaps frustrated by Trinidad and Tobago’s apparent slothfulness, Gasfin’s CEO Roland Fisher has hedged his bets by also seeking permission from the US Department of Energy to export low-priced shale gas from a plant he wants to build in Louisiana. He was quickly given the green light, though he now has to clear his 1.5 million tonne per year complex, which he wants to build in phases, with the

Albert G. Nahas (courtesy Cheniere)

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Federal Energy Regulatory Commission. Gasfin does not expect to be ready to export LNG from the US much before 2020, so Trinidad and Tobago still has the opportunity to get in first and capture the market before Gasfin Development USA decides to target that customer base.

ne piece of luck for the La Brea project, which Fisher is calling Project Constantine, is that his US company, at least for now, will be permitted to export only to countries with which the US has a free trade agreement. Puerto Rico and the US Virgin Islands (which are part of the US anyway) and the Dominican Republic are the only parts of the insular Caribbean that qualify, so Fisher will be limited to seeking markets there. This leaves 21 other potential markets in the Caribbean archipelago to which La Brea LNG could theoretically sell gas. Even Guyana, Suriname and French Guiana, the first two of which are members of Caricom, could be potential targets. Gasfin Development USA is not the only company gunning for the Caribbean market: Pacific Rubiales in Colombia is also planning a small LNG export project. As a competitor, Colombia is an unknown quantity. But even if Fisher chose not to try and sell in the Caribbean, and others such as Cheniere did, Trinidad and Tobago might very well hold its own. Albert G. Nahas, Cheniere’s vice president for international government affairs, believes that “Trinidad and Tobago is perfectly capable of competing in the Caribbean gas market. After all, gas will still be cheaper in TT than in most of the rest of the world, except the US.” Fisher himself has told this YEARBOOK that he would prefer to supply Caribbean markets that materialise from Trinidad and Tobago rather than the US.

a Brea LNG will open markets near to home for Trinidad and Tobago LNG. But it could also present the country with a unique value-chain opportunity through the National Gas Company or its subsidiary, the National Energy Corporation, not only in the LNG train itself but in the ships needed to transport the gas and the re-gasification facilities at the receiving end. At the moment, NGC holds a 10% share in Atlantic’s train one and 11.1% in train four, which gives it a quota of 88 mmcfd. Until recently, this was sold internationally on its behalf. It has recently taken back 30 mmcfd to market on its own account, thus giving it some experience in these matters prior to any involvement in La Brea LNG. Gasfin has been working closely with EdF, the electricity company in Martinique and Guadeloupe, with a view to supplying 200,000 tonnes of LNG to each French department to run the gas turbines both are installing. This would provide a market for 80% of the capacity of La Brea train one, but no deal can be struck until a gas supply from NGC is pinned down.

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Roland Fisher (courtesy Gasfin)

Energy issues

the green agenda

It will take a long time to replace fossil fuels

he “green energy movement” is slowly gaining momentum in the Caribbean, reflected in the growing enthusiasm for renewable energy and efficient use of fossil fuel energy. These initiatives are dealt with elsewhere in this YEARBOOK, in the context of the Caricom Energy Policy. But it’s going to be a hard slog. Oil will not willingly surrender its position as the region’s leading energy source. The International Energy Agency (IEA), which looks after the interests of western industrialised countries, predicts that fossil fuels “will still account for 80-85% of overall world energy consumption by 2030.” And coal, the least green fossil fuel, is making something of a comeback, and could even reach energy use parity with oil before the end of the present decade.

taking shape. Trinidad and Tobago, a late convert to energy sustainability, even has a Green Building Council, established in September 2010, to preach the virtues of green buildings. The Council’s president, Roger Salloum, says its mission is to “transform the way Trinidad and Tobago’s buildings are built and communities are designed, built and operated.” Salloum claims that “green buildings can increase worker productivity” by being “more comfortable and healthier for the occupants, as compared with conventionally constructed and maintained buildings.” Greening, he suggests, includes a range of very simple practical steps such as installing energy-saving bulbs, recycling plastics and other materials, and collecting rain water for wetting plants and flushing toilets. The energy ministry in Port of Spain wants citizens to set airconditioning units a few degrees warmer, turn off electronic devices when not in use, and unplug bedside lamps, TV sets, video games, computers etc. until they are needed. Thirteen years ago, Trinidad and Tobago established a Green Fund, financed through an annual tax of 0.1% on gross company sales. It now has well over TT$2.5 billion available. NGOs and other groups (but not corporations) that promote “reforestation, remediation, environmental education and public awareness of environmental issues” can apply to it for assistance.

Compani Roger Salloum (courtesy Green Building Council)

“Fossil fuels will still account for 80-85% of overall world energy consumption in 2030”

as, the least emissions-intensive of the three, makes the strongest claim. Even the Caricom Energy Policy acknowledges that “compared with crude oil, natural gas is a less expensive and cleaner fossil fuel which can be used not only to generate electricity efficiently, by deploying advanced technologies, but also as a feedstock for the manufacture of petrochemical products, fuel for the manufacturing sector and for vehicular transportation.” The policy document urges Caricom members to “satisfy their demand for natural gas from the resources

of those member states with such resources.” The only Caricom state with exportable gas resources, Trinidad and Tobago, can take that as an endorsement of its role in the emerging Caricom market for LNG and possibly CNG, and rejection of the deals US exporters will want to do with Caricom customers. With significant take-up of RE some decades away, most energy analysts see natural gas as a “bridging fuel” between oil era and RE.

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ther initiatives to move the “green agenda” forward are slowly

energycaribbean YEARBOOK 2013/14

going international

Energy issues

Can state energy companies make the grade?

lmost every famous name in the energy business has been involved in Trinidad and Tobago’s energy sector at one time or another. Yet, despite 105 years of commercial production, no local company has ever gone abroad to invest in oil or gas exploration and production. There was a very short-lived alliance between Petrotrin and Venezuela’s Inelectra in the early 2000s for exploration in the Gulf of Paria East block. Petrotrin even set up a special subsidiary, Petrotrin de Venezolana, for the purpose. But after one well had been drilled, the arrangement was aborted. Petrotrin toyed with the idea of investing in the Cuban oil sector at one point, but that never went very far either. It’s not hard to guess why the many companies formed locally to dabble in domestic upstream activity never considered going overseas. Most of them didn’t last very long, and none had the financial muscle, even in the Caribbean. But times and attitudes have changed. The local company Trinity Exploration and Production, armed with US$90 million of shareholders’ funds from a listing in London early in 2013, is mulling the possibility of investing in oil and gas activity outside Trinidad and Tobago. But the real thrust in this direction is coming from the energy ministry itself, which is anxious for state-owned firms in the energy sector, having demonstrated that they can perform competently at home, to spread their wings abroad. The companies involved are: • NGC (National Gas Company: gas trader, pipeline operator, LNG exporter) • Petrotrin (the Petroleum Company of Trinidad and Tobago: oil and gas producer, refiner) • NP (the National Petroleum Marketing Company: bunkerer, refined fuels wholesaler/retailer) • PPGPL (Phoenix Park Gas Processors: gas liquids extractor/ marketer). The first three are fully owned by the government: the last is 51% owned by NGC.

he major role in this international outreach has been assigned to the NGC, probably the most profitable domestically-owned firm in Caricom, public or private. Its turnover was TT$19 billion in fiscal year 2011, TT$5 billion more than the year before. Its after-tax profit was TT$4.6 12

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billion, compared with TT$2 billion in 2010. Energy minister Kevin Ramnarine has pinned his faith on NGC to an extraordinary degree. He sees it “becoming to Trinidad and Tobago what Petrobras is to Brazil or Petronas to Malaysia. Petrobras is almost as powerful in Brazil as the Brazilian government. There is also the wonderful story of state company Ecopetrol in Colombia. It was worth a couple of billion dollars a few years ago and now is being quoted at over US$100 billion, creating tremendous value for the people of Colombia, who are its shareholders.” NGC’s successful foray abroad is therefore essential to the minister’s grand vision. It has been mandated to “look at investment opportunities around the world” in order to expand.

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est and East Africa, where there have been several major oil and gas discoveries in recent years, is particularly in the frame. “We are keen on establishing an investment portfolio in Africa through the vehicle of the NGC,” says the minister, noting that “natural gas has the potential for eradicating poverty in East Africa through the provision of cheap electricity to the populations in Tanzania, Kenya and Mozambique. These are just some of the possibilities as we seek to internationalise the Trinidad and Tobago energy model.” In its African initiatives, NGC has worked closely with PPGPL, the specialist in gas liquids extraction and marketing, a likely activity for state investment in Africa. PPGPL has already initialled a memorandum of understanding with the Tanzania Petroleum Development Corporation for “technical and expert services” in conjunction with a 500 km pipeline being built by the Chinese Petroleum Development Services to take gas from discoveries offshore southern Tanzania to the capital, Dar es Salaam. PPGPL’s president Eugene Tiah confirms that “there are lots of opportunities in Africa, but you have aggressive countries like China that are not waiting around. If we don’t take advantage of the opportunities, they will be gone soon.” Nearer to home, Central America is seen as a fruitful area for state energy company outreach, particularly Panama, with whom an MOU was signed in March 2012. Potential avenues for Trinidad and Tobago state company investment there include bunkering facilities (Petrotrin), a blending plant and refined products retailing (NP), and gas-based industries (NGC/PPGPL).

Energy issues

alternative fuels

Fuel switching is not catching on

nly Trinidad and Tobago, and to some extent Jamaica, which has experimented with an E10 (ethanol) mixture at the pump, are showing any interest in alternatives to gasolene and diesel as transportation fuels. But the Caribbean Energy Policy (CEP) devotes a whole chapter to the subject. This means that the adoption of non-traditional fuels for transport is now an imperative to which Caricom’s 15 member nations will have to adhere (though the CEP is not a mandatory guideline, only voluntary). “Fuel switching”, as the CEP describes it, is designed to encourage the use of “cleaner energy sources and a more efficient transportation sector.” Transport is seen as “contributing a high level of emissions, including greenhouse gases,” thus making it “a serious environmental matter” in the eyes of the CEP. Transport in Caricom is also “highly vulnerable to dependence on imported fuel supplies and unpredictable spikes in oil prices.” So, not surprisingly, the CEP recommends greater use of compressed natural gas and biofuels like ethanol and bio-diesel, as well as “electric and hybrid vehicles.” Trinidad and Tobago has about 4,500 vehicles equipped with CNG (out of some 650,000 registered). A few hybrids have been imported by motor vehicle dealers, including one for the ministry of energy, to boost “energy efficiency awareness among the driving population”. It is not clear how many motorists in Jamaica have opted for E10, but it can’t be very many. In other words, the adoption of nonconventional transport fuels has a very long way to go in Caricom.

hile Trinidad and Tobago is not dependent on imported fuel supplies, the driver for fuel switching is the need to reduce the use of gasolene and diesel and cut the government subsidy on the price of these fuels at the pump, which is costing several billion TT dollars a year. The energy ministry is still seeking a way of enticing motorists to add CNG capability to their vehicles. One approach under consideration is to fund the cost in whole or in part. CNG has some advantages, but it also has some disincentives, as even the ministry concedes. The vehicle becomes heavier, it loses trunk space to the CNG cylinders, the system has to be inspected annually (instead of every three years for gasolene and diesel vehicles over a certain age), stricter safety measures are applied, engine power is reduced 5-10% by conversion, and range falls to 200250 km compared with 400-550 km for gasolene/diesel vehicles. With such an array of negatives, it is perhaps unsurprising that CNG had not enjoyed the take-up the ministry would like to see. If and when natural gas deliveries finally arrive in the rest of Caricom, the same hesitation will presumably be seen.

t is hard to predict whether electricity would fare any better. Purely electric vehicles are not on the immediate horizon for Caricom, since charging points are unlikely to be available for a long time. The halfway house is the hybrid vehicle, powered by gasolene or diesel but equipped with a battery which does not need a recharging station. “The motion of the wheels as the car moves charges a battery,” minister Ramnarine explains, “and at the opportune time, when the battery is charged, the vehicle switches to the battery.” Another unconventional fuel source is methanol, made from natural gas blended with gasolene or diesel, or even used on its own. An experiment in 2011, involving Petrotrin and Trinidad and Tobago’s two methanol giants, Methanol Holdings and Methanex, was said to have produced “encouraging” results. But the initiative was not taken any further by Petrotrin, whose participation in any long-term addition of methanol to gasolene is essential for any real progress to be made.

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Countries Hybrid car donated to the Ministry of Energy

energycaribbean YEARBOOK 2013/14

TT oil revival 1

Energy issues

After three decades of decline ...

rinidad and Tobago’s petroleum liquids production peaked at 229,589 barrels a day (b/d) in 1978, almost all of it crude oil. By 2012 it had fallen to 81,735 b/d, of which crude represented 69,062 b/d (the rest was condensate). The loss of 160,527 b/d over 34 years translates into billions of dollars of lost foreign exchange earnings and government revenue. A former minister of energy, Senator Conrad Enill, once suggested that 80,000 b/d of crude output should set alarm bells ringing. He could hardly have envisaged how quickly that scenario would come to pass and how much worse it might get. What has saved the day, to some extent, is the fact that oil prices have held up remarkably well in the last few years, at $90-100 a barrel: even with a staggering drop in production, oil sales still provide the Trinidad and Tobago treasury with 55% of its revenue from hydrocarbons. Gas yields 45%, despite the fact that it out-produces oil by a factor of seven in terms of barrels of oil equivalent. Finance minister Larry Howai pegged his oil tax inflows for the 2012-3 fiscal year at $75 a barrel and gas at $2.75 per mmbtu netted back to Trinidad and Tobago. ne reason for the headlong decline in crude retrieval is the fact that older reservoirs (which means most of them) are delivering 8-10% less every year (Petrotrin’s land fields and the Repsol-Petrotrin-NGC Teak/Samaan/ Poui block off the east coast are prime examples). Other reasons are the fall of 12,726 b/d in production from Trinmar,

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Petrotrin’s Gulf of Paria unit, between 2004 and 2010, and the failure of the Kairi and Canteen oil discoveries, operated by BHP Billiton T&T in block 2c off Trinidad’s north east coast, to live up to expectations. The latter was producing 50,542 b/d on average a few months after start-up in 2005, but had dwindled to 12,479 b/d by 2012. A further factor in this unsettling decline situation has been the inability of companies signing production sharing contracts with the energy ministry in the last 20 years to find new oil resources. Out of 36 such agreements, only two – yes, two – resulted in discoveries of crude, both of them by BHP Billiton T&T and its partners, in block 2c (see above) and in block 3a, where no development has yet begun. The development of block 2c and the fact that Trinmar has held relatively steady in the last three years means that crude production still comes primarily from offshore – about 47,519

n his first public address after becoming energy minister in 2011, Senator Kevin Ramnarine declared that the “number one priority” of his stewardship (which ends in May 2015) was to “increase national oil production.” At the time of writing, he had not achieved much success in that regard. But he remains optimistic, predicting “a major increase in oil production around the period May/June 2013.” By February 2013, according to the latest data available, there had been only a very marginal improvement: the average 69,163 b/d of crude being lifted that month was 101 b/d above the 2012 average. It remains to be seen what will happen during the rest of 2013. The following story in this YEARBOOK recounts what is being done, and what can still be done, to achieve a muchdesired turnaround.

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b/d in 2012, compared with 21,543 b/d from onshore.

Galeota platform (courtesy Petrotrin)

Energy issues

tt oil revival 2

How to increase oil production

hat is the key to reviving crude oil production in Trinidad and Tobago, which, as already noted, has crashed from 229,589 b/d 34 years ago to 69,062 b/d today? The obvious answer is new discoveries. But there have been precious few of those by companies working under the current system of production-sharing contracts (PSCs). Companies operating under the older exploration and production (E&P) licences have been a little more successful. Bayfield Energy (now absorbed by Trinity Exploration and Production) has identified what it said were about 32 million barrels of recoverable oil with its FG8 exploratory well in the Galeota block off southeast Trinidad, while Petrotrin found about 48 million barrels of “new hydrocarbon potential” in the course of a five-well exploration programme in the East Soldado area, subsequently named Jubilee in honour of the 50th anniversary of the country’s independence. Both finds were made in 2012. Some new oil was also discovered in the Cory Moruga block on land in 2010. Further discoveries may be made in the course of the extensive exploratory drilling due to take place in the course of 2013: among others, by Trinity in the Point Ligoure, Guapo Bay, Brighton Marine (PGB) block in the Gulf of Paria, and in the Galeota block; by Niko in the Mayaro/Guayaguayare block, which runs from the onshore to the offshore in south Trinidad; and by Parex Resources in the Central Range Shallow and Deep blocks on land. Under renewed E&P licences, Petrotrin has to drill four exploratory wells for Trinmar and two in the North Marine block. Following the interpretation of its 2012 3D seismic survey, it will also be doing exploratory drilling on land in late 2013 and beyond.

The energy ministry says it will offer three land blocks for exploration this year

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xploratory drilling is risky and results can not be guaranteed, but development drilling in an already producing location is of course much less so and can at least replace reserves. Trinity plans to sink 12 development wells onshore in 2013, and 12 in the Galeota block. Lease operators, farmout operators and incremental production service contractors will all be doing similar work. Energy minister Kevin Ramnarine has put great faith in Petrotrin as being “at the centre of the strategy for oil production”, and Trinmar as “at the centre of that centre.” Concurrent with its exploratory activities in Trinmar, Petrotrin is reactivating its South West Soldado field, now producing

about 6,000 b/d, in the belief that it can be boosted to 8,000 b/d by the end of 2013. Sixty wells which were capped ten years ago are being gradually returned to production: a few are already producing again, and the rest will come on line as they are worked over by a rig hired for that purpose. New block allocations are an important part of minister Ramnarine’s oil revival plan. In conjunction with Petrotrin, the ministry says it will offer three land blocks for exploration this year. More deep water and some shallow water blocks are also carded for allocation before the end of 2013.

ew blocks, and exploratory and development drilling in existing blocks, are all essential, but many analysts point out that for decades companies have ignored oil that is known to exist and which could have contributed long ago to arresting the production decline – both heavy oil and “leftbehind” medium-gravity crude in reservoirs that have ceased to produce, or are producing very little. Geologist Dr Krishna Persad has estimated that there is probably well over two billion barrels of crude left behind in reservoirs where natural pressure or even pumping no longer works. As for heavy oil, minister Ramnarine suggests there are “seven billion barrels in places like Trinmar and the southern basin on land.” Even if the correct figure is only half that or less, it represents a vast unexploited resource that could help achieve the country’s oil restoration goals. The government has offered incentives over the years to encourage companies to invest in mature marine and land fields, via a 20% tax credit, and to use enhanced oil recovery measures for lifting heavy oil. In the current national budget, it introduced a special supplemental petroleum tax rate of 25% for the development of small discovered oil pools lying inactive. Deep horizon drilling both on and offshore was encouraged with the offer of a 40% uplift on exploration costs. The deep horizon, like the deep water, could be an entirely new source of crude which the ministry has been urging companies to target.

Countries energycaribbean YEARBOOK 2013/14

cross-border gas

Energy issues

Venezuela lethargy keeps gas stranded Companie

he cross-border gas straddling the maritime boundary between Trinidad and Tobago and Venezuela southeast of Trinidad and northeast of the Orinoco Delta looks likely to remain out of reach indefinitely, because the two countries seem unable to move the commercialisation process forward. That means that 1.8 trillion cubic feet (tcf) of confirmed gas reserves in the Manatee discovery in Trinidad and Tobago’s block 6d (which partners the Loran find in Venezuela’s Plataforma Deltana block 2), and around 1 tcf of gas in the Manakin discovery in block 5b (linked with Coquina in Plataforma Deltana block 4), will not be available for use in Trinidad and Tobago’s reviving downstream gas-based industrial development programme. Such a waste of badly-needed gas at a time when current exploitable reserves are almost all committed is clearly unacceptable. The problem, as energy analysts see it, is that Venezuela feels no urgency in developing cross-border gas because it has dumped plans – for how long, no one knows – to get into the LNG business. Its Plataforma Deltana reserves were always destined for the export trade. Chevron, the operator of block 2, has made no secret of the fact that under its licence it must provide 90% of the 6.2 tcf in Loran for use as LNG and the remaining 10% for domestic use in Venezuela. It has a 39% holding in block 2, Venezuela’s PdVSA holding the other 61%. With LNG off the table, the government in Caracas sees little sense in rushing to commercialise the gas. The 10% that was destined for domestic use can be sourced from other gas discoveries closer to the mainland, such as the very large one that Repsol made in the Gulf of Venezuela recently, or even the proven reserves in the Paria Norte region.

rinidad and Tobago’s energy minister Kevin Ramnarine could scarcely conceal his impatience when he last spoke publicly about the cross-border gas matter. In an address at the Austin Jackson School of Geosciences at the University of

Commercialisation has long been under way with the development of Kapok 16

“It is very hard to get the Venezuelans to meet with us on this issue”

Texas in Austin in March 2013, he said: “It is very hard to get the Venezuelans to meet with us on this issue.” He noted that he had “been in contact with minister Rafael Ramírez” (who has been retained as minister of energy and petroleum in the new Maduro government) and had also “spoken with Chevron” (the operator of both Manatee and Loran), but did not seem to hold out much hope for crossborder monetisation any time soon. The project appears to be stuck at the stage of selecting a unit operator. A unit directing committee representing all the stakeholders in the matter – the two energy ministries, Chevron, the BG Group and PdVSA – was supposed to select the operator early last year, but the Venezuelans failed to turn up in Port of Spain for the scheduled technical meeting. Then President Chávez’s lengthy illness and death, and the election of Nicolás Maduro Moros as his successor, put a stop to decision-making in Caracas on matters like cross-border gas for most of 2012; and the post-electoral situation does not seem to have changed anything.

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s far as the Manakin (BP/Repsol) and Coquina (Statoil/ PdVSA) discoveries are concerned, no unitisation agreement has been signed. The reservoir joint working group, comprising officials from both sides, has identified the total volume of gas reserves they believe to be there. But the specific amount on each side has not yet been determined. A “best guess” estimate is about 1 tcf in each discovery. The situation in the third pair of cross-border gas blocks – bpTT’s Kapok discovery on the Trinidad side and the Dorado find by PdVSA in block 1 in Venezuela – is different, in that commercialisation has long been under way with the development of Kapok. The estimated combined reserves in the two blocks is about 1 tcf, and PdVSA has allowed bpTT to produce what it can from the two reservoirs. When the exact amount on each side is determined, if production from the Kapok field has exceeded the allocated reserves allocated, bpTT would agree on some form of compensation for PdVSA.

Energy issues

Deep water exploration

The last real frontier?

eep geological horizons on land and offshore are a possible new oil and gas play in Trinidad and Tobago (and received incentives in the 2012-2013 national budget), but the real last frontier for substantial hydrocarbon discovery is exploration in deep water, at whatever geological depth. Deep water is defined by the energy ministry in Port of Spain as a water depth of 1,000 metres and more. No exploration beyond about 1,500 metres has actually taken place before. Eight wells were sunk in the continental slope in the late 1990s and early 2000s in water depths of 750-1,500 metres, but only one find of non-commercial gas was made. In 2012, the BP Group signed two production-sharing contracts for exploring in the Atlantic deep water off the east coast. Water depth in the two blocks, 23a and TTDAA 14, is around 2,000 metres. BP is leading the first assault on real deep water acreage in Trinidad and Tobago. It will be followed by BHP Billiton, which was awarded four other blocks – TTDAA 5-6 and TTDAA 28-9 – in the subsequent bid round (see map on p26-27). Deep horizon exploration, on land or offshore, could itself result in the identification of a new play, if the incentive offered – a 140% write-off on exploration costs – is enough to entice explorationists. “Deep horizon” has been defined by the ministry as 8,000 feet or more on land and 12,000 feet or more offshore.

The ministry has bent over backwards to make deep water activity economically attractive, which it has not been in the past

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hile he would clearly be pleased with a deep horizon discovery, Trinidad and Tobago’s energy minister Kevin Ramnarine is betting on the deep water. He believes that “both BP and BHP Billiton, two long-established players in the country, stand poised to take us into a period

“BP and BHP Billiton, two long-established players in the country, stand poised to take us into a period of exciting deep water exploration”

of exciting deep water exploration” and that “the deep water in Trinidad is one of the holy grails of geologists, who have long suspected its vast hydrocarbon potential.” This potential has been estimated by the energy ministry at 4.7-8.2 trillion cubic feet (tcf ) of gas in the two BP blocks (no estimate has been given publicly for possible oil resources), and 2.4-23.6 tcf of gas and 428-4,200 million barrels of oil in BHP Billiton’s four blocks. The latter would have had its own reasons for bidding so aggressively on four of the five blocks that attracted companies’ attention in the 2012 deep water auction, but the ministry has bent over backwards to make deep water activity economically attractive, which it has not been in the past. These attractions are intended to “reduce risk and offer companies a more competitive environment,” and include: • Cost recovery (“cost oil or gas”) increased from 60 to 80% • A 35% petroleum profits tax and an 18% supplemental petroleum tax payable on oil only. This allows the company to claim a higher share of “profit oil or gas” since the government’s take under the productionsharing system is based on these two taxes • A 140% write-off for deep water exploratory wells, further enhancing the companies’ share of “profit oil or gas”.

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he ministry is following up on its 2010 and 2012 deep water bid rounds with another in 2013, which it hopes will attract new companies into the hydrocarbon sector. Minister Ramnarine told this YEARBOOK: “companies which did not bid in 2012 have told us they will bid in 2013 ... In one case, they told us that they had a restructuring exercise going on in 2012, and another said it had quite a lot on its plate at the time. So, I think that we have stimulated widespread interest in our deep water bid rounds.” energycaribbean YEARBOOK 2013/14

Energy issues

independents

A key contribution to oil revival

mall and medium-sized petroleum enterprises in Trinidad and Tobago, the “independents”, are expected to play a key role in the revival of oil production. There is no formal definition of an “independent” in terms of assets or reserves, though when companies producing up to 3,500 b/d were exempted from petroleum production levy payment nine years ago, this was generally taken as an indication of independent status. It’s only a rough guide, however, because some “independent” upstreamers are already close to that level or beyond it. A more reliable definition of an independent in the Trinidad and Tobago context might be an operator which is not state-owned, and does not belong to a major international group like BHP Billiton or Repsol (oil), bpTT, BG T&T or EOG Resources (condensate). On that basis, independents were responsible for about 10,241 b/d of crude output on average in 2012, out of 69,062 b/d from all companies (another 12,673 b/d was condensate, taking the liquids total up to 81,735 b/d). Petrotrin’s contribution was 34,818 b/d (oil) from its onshore and offshore fields. Nobody is likely to challenge Petrotrin in the future, unless some major discovery of crude is made in deeper geological horizons or in the deep water. Petrotrin’s dominance is secure, given the extent of its acreage compared with that of the independents. But 10,241 b/d out of 69,062 b/d (almost 15%) is a good performance, when you consider that most of those companies are lifting crude from wells Petrotrin itself abandoned or from very small tracts of farmed-out land.

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Independents could be pioneers in the application of carbon dioxide (CO2) injection for enhanced oil recovery

independent of all, straddles the whole spectrum, being simultaneously a lease operator, farm-out operator and joint venturer.

ll knowledgeable observers of the Trinidad and Tobago energy scene expect the independents to enlarge their contribution to crude production in the years ahead. Energy minister Kevin Ramnarine has begun regular meetings with the sector to hear and try to resolve its problems. David Borde, managing director of PetroCom Technologies, the company promoting a “smart pumping” system that could help independents improve well productivity, sees their role in oil revival as “absolutely critical”. Geologist Dr Krishna Persad, a farmout operator through his company KPA and Associates, has just acquired Trinidad Exploration and Development in southwest Trinidad, and strongly believes the independents could be pioneers in the application of carbon dioxide (CO2) injection for enhanced oil recovery. Minister Ramnarine has mandated the National Gas Company to examine the feasibility of a CO2 pipeline from the Point Lisas industrial estate to the oilfields of the southern basin. Trinity Exploration and Production is aiming for production of 5,000 b/d by the end of 2013. Range Resources is targeting 4,000 b/d, and Touchstone Exploration 3,300 b/d.

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here are about 17 independents active in the local petroleum sector today, occupying different niches. Some are lease operatorships (in 1989 Trintopec handed over idle and low-producing wells to smaller independent operators who might do a better job with them). Others are farm-out operators, who have obtained larger areas on which to sink new wells if they want. Joint venture arrangements involve whole blocks, where the independent company is obliged to undertake seismic surveying and exploration. Incremental production service contractors are a new breed invented by Petrotrin in 2009 to help generate more production from its southeastern onshore fields, which had found themselves neglected over the years. There is also one standalone independent, Mora Oil Ventures (Moraven), which only operates offshore, not on land at all, unlike the rest of the independent sector. Trinity, shaping up to be the biggest

Independents were responsible for about 10,241 b/d of crude output on average in 2012, out of 69,062 b/d from all companies

Energy issues

climate change

What should the Caribbean do?

aricom’s 15 member nations have pledged to measure and reduce the level of greenhouse gas emissions in the region, in keeping with the Caricom Energy Policy (CEP). Targets will be influenced by Caricom’s “international obligations and voluntary commitments under the United Nations Framework Convention on Climate Change and the Alliance of Small Island States’ climate change negotiating strategy and objectives.” This initiative is part of the agenda of Caricom’s Caribbean Sustainable Energy Road Map and Strategy (C-SERMS). Determining the baselines for greenhouse gas emissions has become more urgent with global emission levels reaching their highest point in over two million years. Carbon dioxide (CO2) emissions, by far the major contributor to global warming, hit 400 parts per million in May, a jump of 85 ppm in 55 years. The world is now pumping 38.2 billion tons of CO2 into the atmosphere every year, China being the worst offender with 10 billion. The United States, the second worst offender, has actually been lowering its CO2 discharges, which are now down to 5.9 billion tons a year. The reasons are said to be the rapid switch to gas-fired power generation and the growth of fuel-efficient vehicles.

southwest Tobago based on climate change scenarios. The idea of moving hotels further inland could be one element of adaptation. The CEP focuses on adaptation initiatives in energy, particularly electricity, the key factor in regional states without indigenous oil or natural resources. Hurricanes can cause “catastrophic damage to the overhead transmission and distribution facilities in the region,”CEP points out, urging member states to “support the development and implementation of a regional rapid response strategy for the restoration of electricity facilities.” On the wider energy front, Caricom is supposed to create a plan for “maintaining regional reserves of crude oil and energy products to be accessecy or crisis.” Grenada is among those already seeking assistance from multilateral bodies for climate change adaptation. The German Agency for International Cooperation and the United Nations Development Programme are funding a four-year, US$6.5 million programme to “increase the resilience of vulnerable communities and ecosystems to climate change risks through integrated adaptation approaches.”

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he 400 ppm reading augurs badly for governments’ goal of holding the rise in average temperature below two degrees Celsius. Beyond that, it is feared that catastrophic warming becomes unstoppable, with all the predicted weather threats such as more intense hurricanes, rising sea levels, floods and drought. The Caribbean, being mainly composed of small island developing states, is more vulnerable to the results of global warming than most. Indeed, according to an Inter-American Development Bank survey, “extreme events” already cost US$135 billion in losses in 14 Caribbean countries between 1970 and 2008. Some hoteliers in the region are seriously thinking of moving to higher ground because their beach locations leave them completely exposed to rising sea levels, flooding and storms. As noted elsewhere in this YEARBOOK, Caricom’s contribution to resisting global warming is to develop renewable energy sources and to use fossil fuels more efficiently. These are the twin pillars on which C-SERMS is mounted. But with the outlook for mitigation so bleak and Caricom’s likely effect on it so minuscule, the region will have to embrace climate change adaptation more vigorously.

Contribution to climate change Trinidad and Tobago (2009)

• CO2 emissions per capita 40 tonnes per person* • CO2 emissions per unit of GDP 1.9 kg per dollar* • Total CO2 emissions 52 million tonnes** • Breakdown: Petrochemical plants 58% Landfill 7% Process emissions (oil & gas) 3% Domestic cooking 1%

Power generation 23% Transport 6% Agriculture 2%

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rinidad and Tobago’s Institute of Marine Affairs is developing a vulnerability and risk agreement for

* second highest in the world that year ** 54th highest in the world that year

Source: Dr Donnie Boodlal, University of Trinidad and Tobago

energycaribbean YEARBOOK 2013/14

local content

Energy issues

Government may prescribe level of local input Companie

uccessive Trinidad and Tobago governments have tried to maximise local content in the energy sector, with varying degrees of success. The greatest progress has been made with support services for oil or gas exploration and development. But many of the 450 local service companies have complained that foreign service providers are being favoured in the current round of drilling activity by international companies. Local platform fabricating was a success story, and nine such structures were built at the La Brea fabrication yard between 2004 and 2010. But that activity seems to have come to a standstill, as companies opt for tying back new producing wells to existing platforms. Energy minister Kevin Ramnarine has spoken of his vision for Trinidad and Tobago as “a major international energy services hub.” This will require the “structured development of local companies along the entire value chain of the energy sector, from the upstream to the midstream to the downstream and possibly even beyond that.” With the lack of work at home, some local services firms have already expanded internationally, especially in their own region and more recently to African states such as Ghana and Nigeria. The ministry is anxious to establish relations with countries entering the oil and gas business. Explorationists and producers are urged by the ministry to use as much local content as feasible; so are major downstream gas-based industrial plants. Construction of Atlantic’s LNG trains was a landmark in this regard; a budget was agreed for the amount of work to be awarded to local contractors.

egislation may be forthcoming to enforce a percentage of local content in all energy projects. The energy ministry says it is currently reviewing the local content and local participation policy and framework, prepared as long ago as 2004, “which will guide the way for the drafting of local content legislation.” This “will seek to strengthen the existing local content policy, while allowing for consistent application” reflects the importance placed on local content

The government should “enact into law the local content policy for the oil and gas industry as soon as possible”

in the ministry’s 2012-2016 strategic plan. The ministry has a broad definition of local content in the energy sector, encompassing not only firms offering traditional services like drilling, cementing, casing, open hole logging, wireline, coil tubing and so on, but also companies involved in upstream oil and gas exploration, production and finance. Locally-owned upstream “independents” have been disappearing in recent times, on the back of take-overs by foreign firms, an area that may need special attention. Lennox Sirjuesingh, president of the Trinidad and Tobago Local Content Chamber, formed in early 2011 primarily to promote more local involvement in energy, regards legislation as long overdue. He has called on the government to “enact into law the local content policy for the oil and gas industry as soon as possible.”

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he allocation of gas for downstream use is also being used as a tool to encourage the wider embrace of local content. Early in the life of the present government, the ministry laid out a gas allocation policy in which local content accounted for 15 points out of 100 when an applicant’s eligibility for a gas supply was scored. Local content in gas-based activity was defined in relation to ownership, local debt/equity financing, engineering design, feasibility studies, project management, technical skills, the number of permanent jobs per unit of capex, number of permanent jobs for operations, peak employment during construction, and average employment during construction.

Legislation may be forthcoming to enforce a percentage of local content in all energy projects 20

Energy issues

GAS-BASED DEVELOPMENT

Will there be enough gas for everyone?

rinidad and Tobago’s gas-based heavy industrial development programme has been in abeyance since the opening of Methanol Holdings’ ammoniaurea-melamine 1 plant at Point Lisas in 2010. But it is springing back to life in 2013, with a number of new projects identified and moving forward. The only question hanging over this resurgence is whether there will be enough gas to service all the new entrants. The most recent Ryder Scott audit (2011) identified 13.2 trillion cubic feet (tcf) of proven gas reserves, which are almost all spoken for by the existing petrochemical and steel industries at Point Lisas and the four LNG trains at Point Fortin. Another 6 tcf of probable gas reserves could be transferred to the proven category with minimal drilling and reservoir reappraisal. The “unrisked exploratory resources” of 30.4 tcf are probably the best insurance for the future. As Ryder Scott’s managing senior vice president, Herman Acuna, points out: “This shows upside potential for gas and sustainability of supply, which is really what you should be looking at.” Energy minister Kevin Ramnarine takes a bullish view of the matter, pointing to bpTT’s discovery of around 1 tcf of new gas with its Savonette 4 well in late 2012, which doubled the recoverable reserves in the field to 2 tcf. He expects the 2012 gas reserves audit to be “positively impacted” by this development. The largest of the forthcoming projects is the Mitsubishi/ Neal and Massy Holdings methanol to dimethyl ether plant. Ramnarine has confirmed that “the Ministry of Energy and Energy Affairs and the National Gas Company are in dialogue with an established natural gas supplier in Trinidad and Tobago who has advised that it could have gas available by 2016.” The projects spearheading the revival of gas-linked industrial development are:

of DME at cost price, to supply to investors who want to use it in connection with other investments. Mitsubishi, Neal and Massy and the other shareholders will make their money in the methanol market.

Formaldehyde/Melanine This Chemtech cluster will obtain formaldehyde from methanol and melamine from ammonia, justifying its gas-based status on those grounds. It is envisaged as a US$200 million investment. The downstream products will be melamine-based resin, oriented strand board and veneer.

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Methanol-to-DME The US$800 million Mitsubishi/Neal and Massy Holdings plant will convert 100 mmcfd of gas into one million tonnes a year (t/y) of methanol, of which 140,000 t/y will be diverted to the production of dimethyl ether (DME), a versatile chemical that can be used in power generation, transport, cooking and heating, among other things. It is considered a major move in the ministry’s policy of going as far as possible downstream in the gas-based chemical chain. (This was also the case with AUM 1, which delivered melamine for a range of light manufacturing applications.) The government has been offered a 20% share in the methanol/DME project and has agreed to buy the 140,000 t/y

Steel

Neal and Massy Holdings and Metal Dom (of the Dominican Republic) propose a steel plant and rolling mill that will require 45-55 mmcfd of gas for heating purposes. The estimated cost is US$116 million. The plant will produce billets, reinforced bars, flats and angles, a very diversified range for a Caribbean steel plant.

LNG The Gasfin (Luxembourg)/National Energy Corporation “midscale” LNG plant at La Brea, southwest Trinidad, will cost US$400 million, with a 500,000 tonne-a-year capacity; it will need about 70 mmcfd of gas. It has been named Project Constantine after Trinidad and Tobago’s late legendary cricketer. ne major downstream initiative has been temporarily delayed: MHTL’s AUM 2, the successor to AUM 1. This is a larger project than its predecessor – 595,350 t/y of ammonia, 903,900 t/y of urea, 33,000 t/y of ammonium sulphate and 39,600 t/y of melamine. It has been costed at US$1.9 billion. A final investment decision has been held up by a dispute between the government (now the majority holder since it assumed ownership of the 56.53% formerly held by C L Financial) and the minority 43.47% shareholder Consolidated Energy, a consortium of three German firms, MAN Ferrostaal, Helm and Proman. The matter has gone to arbitration. A resolution is expected before the end of 2013. Another potential downstream project has been abandoned. Saudi Arabia’s SABIC and China’s Sinopec formed a joint venture but failed to reach an agreement with the government on gas pricing and supply. The partners were to have invested in two major complexes. Methanol to olefins would have opened the way to the production of propylene, polypropylene and plastics, while methanol to petrochemicals would have led to acetic acid, acetic anhydride and pharmaceuticals like asprin.

Countries energycaribbean YEARBOOK 2013/14

Countries trinidad and tobago

A year of heavy drilling

n 2013 Trinidad and Tobago’s energy sector should experience its busiest year for a very long time. Hundreds of millions of dollars will be spent drilling over 100 wells of all types – exploratory, developmental and recompletions, plus workovers to keep declining wells flowing. Virtually every company has plunged into a drilling programme, including bpTT, BG, Repsol, EOG Resources and Centrica Energy. Niko Resources and Parex will be sinking wells, as will Petrotrin, which intends to be busy both onshore and in its Gulf of Paria Trinmar unit.

Large companies

• BPTT says it may drill another appraisal well in the Savonette producing field, where it found a trillion cubic feet (tcf) of proven reserves in November 2012, to see if it can bump that up even further. • BG Trinidad and Tobago is launching its four-well development drilling programme for the Starfish discovery. • EOG Resources will be drilling one exploration and three development wells in its Osprey field in block 4a. • Centrica Energy, which so far has no production of its own in Trinidad and Tobago, is sinking an appraisal well to its Cassra discovery in block 22 north of Tobago, as well as drilling an exploratory well, Jasmine, in its NCMA 4 block and an appraisal well to the Iris discovery.

• Repsol says it will drill two appraisal wells and six in-fill wells in its Teak/Samaan/Poui block offshore Trinidad’s east coast. • Petrotrin, already the country’s largest single crude producer, is expected to drill 25 development and enhanced oil recovery wells onshore, while undertaking rig workovers to bring back on line as many as possible of the 57 wells still shut-in in its most productive Trinmar field, South West Soldado. • BHP Billiton has the dubious distinction of being the only large company not sinking any wells in 2013, though it will be signing off on the four deep water blocks it was awarded in the 2012 deep water bid round, TTDAA 5-6 and TTDAA 28-29. It will then have to start a work programme, which will include seismic acquisition and exploratory drilling in subsequent years.

Medium/small foreign and local companies

• Trinity Exploration and Production, mainly locally-owned but a member of the Alternative Investment Market in London, plans four exploratory wells split between its Point Ligoure/Guapo Bay/Brighton Marine acreage in the Gulf and its newly-acquired Galeota block off the southeast coast, taken over from the former Bayfield Energy, plus 12 development wells onshore and eight in Galeota. • Touchstone Exploration, working through its subsidiary, Territorial, plans 16 development wells in its various land blocks plus 2 recompletions. • Range Resources will be drilling in all three of its licences: Morne Diablo (40 wells), South Quarry (up to 10 wells) and Beach Marcelle (6 existing wells to be deepened). • Leni Gas and Oil will drill one exploratory well in Moruga North and two development wells in Goudron. • Niko Resources will embark on its NCMA 2 block work programme with one exploratory well • Parex is supposed to begin its own exploration with one exploratory hole in the Central Range Shallow and Deep blocks and an appraisal well to its Snowcap discovery in the Moruga E block.

B Drilling in Fyzabad (courtesy Petrotrin)

esides this extensive drilling activity, two block auctions are expected in 2013, for three blocks on land and for more acreage in the deep water. Two bid rounds in the same year are rare, but the country needs to identify new crude reserves to stop the haemorrhage in oil production, and also needs new gas reserves to underpin the heavy industrial development programme – and continuous exploration activity is the only way of doing it.

Countries TT energy profile Crude oil production (average b/d) 1970 39,855 1971 129,041 1972 140,273 1973 166,301 1974 186,575 1975 215,342 1976 212,876 1977 229,041 1978 229,589 1979 214,246 1980 212,057 1981 189,335 1982 177,038 1983 159,845 1984 169,513 1985 176,052 1987 155,180 1988 150,829 1989 134,051 1990 151,194 1991 145,395 1992 137,057 1993 124,604 1994 131,532 1995 130,574 1996 129,011 1997 123,881 1998 122,794 1999 125,332 2000 119,432 2001 113,959 2002 130,906 2003 134,865 2004 123,902 2005 144,339 2006 144,266 2007 121,754 2008 114,634 2009 107,169 2010 98,246 2011 91,919 2012 81,735

ENERGY SECTOR Share of GDP

of which Exploration and production Refining (inc. LNG) Petrochemicals Others (energy services, etc)

Share of government revenue

of which Oil/gas exploration and production Other taxes (royalties, oil impost, &c)

Share of merchandise exports receipts

of which Extracted (crude oil) Refined (inc. LNG, natural gas liquids) Processed (inc. petrochemicals)

Share of total employment Share of bank credit (2010) Loans and advances Percentage of total

45.2% (2011) 19.2% 7.6% 12.7% 5.7%

57.5% (2011) 47.5% 10.0%

85.4% (2009) 12.9% 62.9% 9.6%

3% (2011) TT$1.4 billion 3.1%

ENERGY RESERVES Oil (2007)

Proven Probable Possible

Natural gas (2011)

Proven Probable Possible Unrisked exploratory resources

317.9 million barrels 119.3 million barrels 1,046 million barrels (inc. tar sands) 13.2 trillion cubic feet (tcf) 6.0 tcf 6.1 tcf 30.4 tcf

Production (2010) Crude oil/condensate Crude oil imports Refinery throughput Refinery output Capacity utilisation Natural gas production Natural gas sales of which petrochemicals Electricity generation LNG Natural gas liquids production Exports Ammonia production Exports Methanol production Exports

35.8 million barrels 24.9 million barrels 46.1 million barrels 44.0 million barrels 77% (capacity 165,000 b/d) 4.3 billion cubic feet daily (bn cfd) 4.0 bn cfd 1.1 bn cfd 293 million cubic feet daily (mmcfd) 2.3 bn cfd 17.2 million barrels (mm b) 16.9 mm b 6.2 million tonnes (mm t) 5.9 mm t 5.9 mm t 5.9 mm t

Sources: Central Bank Annual Economic Survey (2011), MEEA Draft Green Paper on energy policy (unpublished), ENERGY Caribbean archives energycaribbean YEARBOOK 2013/14

1,000,000

500,000

0 2,000,000

ST VINCENT

BEQUIA

CANOUAN MAYREAU UNION

1,500,000

CARRIACOU

TTDAA 31 94092 Ha

GRENADA

OPEN

TTDAA 30 89879 Ha

TTDAA 32 113043 Ha

OPEN

-2000

TTDAA 24 112042 Ha

TTDAA 25 100086 Ha

OPEN

TTDAA 26 100086 Ha

OPEN

1,000,000

TTDAA 28 101609 Ha

TTDAA 27 100086 Ha

BHP Billiton Petroleum Ltd

OPEN

-1000 OPEN 30783 Ha

BLOCK 23(a)

BLOCK 22

BLOCK 21

259908 Ha

CENTRICA / PETROTRIN

132015 Ha

BPEOC

-400

OPEN

OPEN 44254 Ha

NCMA 2 BLOCK 23(b) 257920 Ha

101,931.8 Ha

NIKO RESOURCES (CARIBBEAN) LIMITED / RWE Dea AG/ PETROTRIN

NCMA 4

CENTRICA ENERGY

Scarborough

OPEN

NIKO RESOURCES/ PETROTRIN

-4

OPEN 5736 Ha

OPEN 40048 Ha

BLOCK 25(a)

BLOCK 3(a)

LIN

500,000

BLOCK 24 340114 Ha

NCMA 5 231,098.8 Ha

NCMA 3 210,622.5 Ha

-1000

TRINIDAD & TOBAGO & VENEZUELA

BGTT /CENTRICA / EMI

OPEN

182,946.2 Ha

NCMA 1

VENEZUELA

Port of Spain

133,504 Ha

BLOCK 25(b) 139129 Ha

OPEN 9614 Ha

OPEN

DA R

OPEN

BLOCK 2(ab)

TRINIDAD

OPEN

138860 Ha

BLOCK 3(b) 64513 Ha

OU N

OPEN

LB NA TIO NA INT ER

bpTT/ REPSOL

BLOCK 1(b) CENTRICA / PETROTRIN

CENTRAL RANGE BLOCK

BLOCK 1(a)

BLOCK 4(a)

BLOCK 4 (b)

EOG RESOURCES PRIMERA

75328 Ha NIKO RESOURCES (CARIBBEAN) LIMITED

PAREX / VOYAGER / PETROTRIN

PETROTRIN 20 579 Ha

3 4

TRINMAR

5 6

BLOCK 26 119569 Ha

A TN

OPEN

BLOCK 1(b)

CENTRICA / PETROTRIN

San Fernando

(B)

OPEN

BGTT

CENTRAL BLOCK

(A)

bpTT/ REPSOL

CHEVRON

BGTT SONDE RESOURCES CORP

BGTT / CHEVRON

OPEN 74345 Ha

6(b)

NIKO VOYAGER ENERGY (TRINIDAD) LIMITED PETROTRIN

NGC/PETROTRIN

BLOCK 6(d)

BGTT / CHEVRON LOWER REVERSE 'L' 36378 Ha OPEN

500,000

BLOCKS 2010/2011 DEEP WATER BID ROUND BLOCKS 2012 DEEP WATER BID ROUND BLOCKS 2013 DEEP WATER BID ROUND

68420 Ha BG INTERNATIONAL Plc

bpTT/ REPSOL

EOG RESOURCES

bpTT/ REPSOL

VENEZUELA 0

BLOCK 5 (d)

7 SOUTH MARINE 52384 Ha OPEN

OPEN

BLOCK 5(c)

OPEN 74345 Ha

1,000,000

Geographical positions are based on the Clarke 1858 Spheroid. Cassini Grid Coordinates are in links. Geographical Coordinates of Origin: Latitude 10° 26' 30" N Longitude 61° 20' 00" W.

BLOCK 27 117915 Ha OPEN

1,500,000

2,000,000 2,000,000

Block

BLOCK OPERATOR

LICENSEE

Block_9

BGTT

PETROTRIN

EAST_BRIGHTON_A

SOOGL

SOOGL 65%_PRIMERA 35%

EAST BRIGHTON B

SOOGL

SOOGL 45.5%/ PETROTRIN 30%/ PRIMERA 24.5%

BRIGHTON MARINE

TRINITY EXPL. AND PROD.

TRINITY EXPLORATION AND PRODUCTION / PETROTRIN

POINT LIGOURE

TRINITY EXPL. AND PROD.

TRINITY EXPLORATION AND PRODUCTION / PETROTRIN

BARBADOS 1

SOUTH WEST PENINSULA

TED

TED / PETROTRIN

ISLOTE BAY

TED

ERIN BAY

TED

TED PETROTRIN

Area_b

PETROTRIN

MAYARO_GUAYAGUAYARE BAY

NIKO RESOURCES

NIKO RESOURCES / PETROTRIN

GALEOTA

TRINITY EXPL. AND PROD.

TRINITY EXPLORATION AND PRODUCTION / PETROTRIN

GALEOTA RIDGE

MORAVEN

BHP

BHP 45%/ TOTAL 30%/CHAOYANG (CNOOC 12.5%, SINOPEC 12.5%)

BHP

BHP 25.5%/KERR MCGEE 25.5%/CHAOYANG(CNOOC 12.75%, SINOPEC 12.75%)/PETROTRIN 15%/TOTAL 8.5%

1,500,000

EOG

-3000

-4000

BHP Billiton Petroleum Ltd

MODIFIED U (a) MODIFIED U (b)

BLOCK E

BGTT

BLOCK 5(a)

BGTT

BGTT/CHEVRON

BLOCK 5(b)

bpTT

bpTT/REPSOL

NORTH MARINE

PETROTRIN

-2000

TTDAA 29 100195 Ha

14 15

BGTT/CHEVRON

1,000,000

TTDAA 14 99808 Ha BPEOC

TTDAA 15 98632 Ha

TTDAA 16 99336 Ha

OPEN

TTDAA 11 100150 Ha

TTDAA 12 100057 Ha

TTDAA 13 100052 Ha

OPEN

TTDAA 9 99349 Ha

TTDAA 10 99337 Ha

OPEN

TTDAA 17 101198 Ha OPEN

TTDAA 20 101537 Ha TTDAA 8 99809 Ha OPEN

TTDAA 18 101153 Ha

OPEN

TTDAA 22 105227 Ha

TTDAA 23 91142 Ha OPEN

OPEN

TTDAA 21 101194 Ha

TTDAA 6 99747 Ha

TTDAA 4 100185 Ha

TTDAA 7 99783 Ha

BHP Billiton Petroleum Ltd

OPEN

500,000

OPEN

TTDAA 19 102917 Ha OPEN

TTDAA 2 104755 Ha OPEN

TTDAA 3 109722 Ha

TTDAA 5 109559 Ha

OPEN

BHP Billiton Petroleum Ltd

TTDAA 1 119214 Ha OPEN

Scale 10

0 10

10 10

1,500,000 Lk.

20 20

25 Ml. 40 Km.

2,500,000 Lk.

2,000,000 Lk.

Rectangular Coordinates of Origin: Easting = 430,000 Links. Northing = 325,000 Links. Water depth contour in metres

GOVERNMENT OF THE REPUBLIC OF TRINIDAD AND TOBAGO MINISTRY OF ENERGY AND ENERGY AFFAIRS

UPSTREAM ACTIVITY MAP

energycaribbean YEARBOOK 2013/14

Countries trinidad and tobago

Energy timeline Early years 1857

First oil well drilled by Merrimac near La Brea

1866

First successful well drilled by Walter Darwent

1902-7

Successful wells drilled in Guayaguayare by Randolph Rust and John Lee Lum

First large-scale commercial gas production, from Amoco’s Teak field off the east coast; reserves estimated at 1.1 trillion cubic feet

Expansion 1974

Trintoc created as the government’s first upstream and refining company after purchase of Shell’s oilfields and Point Fortin refinery

Small refinery build at Brighton

1974

16-inch, 24-mile pipeline brings gas ashore from east coast fields

1917

Refinery built at Pointe-à-Pierre

1975

National Gas Company (NGC) established

1930

First crude oil imports for local refining

1933

First enhanced oil recovery at Forest Reserve

1977

Gas-based industrial development begins at Point Lisas with Tringen ammonia plant

1937

Labour protests

1977

South East Coast Consortium (SECC) makes first east coast gas discovery since Amoco in 1968

1977

24-inch, 40-mile pipeline increases transmission capacity

1978

Peak east coast oil production – 139,163 b/d

1908

Commercial oil production begins at La Brea

1910

First export shipment of crude oil

1911

Development 1953

First commercial use of gas, for power generation

1978

Peak national oil production – 240,000 b/d

1953

Marine exploration off southeast coast by Dominion Oil

1978

First marine platforms built locally and installed off southeast coast

1954

Apex Oil Company drills to 16,155 feet in Fyzabad

1955

Non-associated natural gas discovered on land

1955

First offshore production, in Soldado field in Gulf of Paria

1980

Government-owned ISCOTT steel plant established at Point Lisas

1956

Texaco buys Pointe-à-Pierre refinery from Trinidad Leaseholds

1981

FERTRIN ammonia plant at Point Lisas (government holds 51%)

1959

WR Grace subsidiary Federation Chemicals uses BP gas for petrochemical production

1983

Government establishes urea plant at Point Lisas

1961

First exploration off Trinidad’s east coast

1983

Amoco’s giant Cassia gas field comes on stream

1967

Peak oil production on land – 111,883 b/d

1983

Government builds new 30-inch, 40-mile offshore gas line

1983

South West Soldado oilfield off west coast is estimated at 100 million barrels

1984

First methanol plant established at Point Lisas (government-owned)

The gas age

1974

Heavy industry

1968

e east coast by Amoco

1985

Government buys Tesoro, which becomes Trintopec

1968

Peak oil production off the west coast – 76,948 b/d

1985

1968

First seismic survey off the north coast

Government acquires Texaco’s land fields and Pointe-à-Pierre refinery, amalgamating operations with Trintoc

1969

Amoco finds commercial quantities of oil off the east coast

1986

First compressed natural gas available as motor fuel

1969

Government takes over BP’s land fields with Tesoro

1987

Last well drilled in the Northern Basin to 7,700 feet in Claxton Bay

1970

Tesoro finds oil off the southeast coast

1970

First competitive bidding for offshore blocks

1971

Natural gas discovered off the north coast

1972

Commercial oil production from Amoco’s Teak field

1972

National Petroleum launched to take over BP’s gas stations

1972

Delta Exploration acquires speculative 2D seismic survey over northern Gulf of Paria and east coast of Trinidad

Rationalisation 1989

Lease operatorship/farmout programme introduced by Trintopec

1989

British Gas takes over Tenneco’s international assets and enters Trinidad and Tobago

1990

Government-owned Trintomar starts gas production from Pelican field in SECC

1991

Phoenix Park Gas Processors pioneers large-scale gas liquids extraction

1992

Unsuccessful exploration off south coast

1992

NGC takes over National Energy Corporation

1993

CL Financial establishes Caribbean Methanol at Point Lisas – first fully-owned private sector gas-based petrochemical plant

1993

Unsuccessful exploration in deeper zones on land by Exxonled Southern Basin Consortium

1993

First production-sharing contract, with BG/Texaco

1993

Enron invited to salvage SECC block as a natural gas producing unit

1993

Product-related pricing system for natural gas sales introduced: major factor in gas monetisation success

2006

BPTT’s Ibis Deep, the deepest vertical well ever sunk in Trinidad and Tobago, reaches 19,068 feet in SECC block but fails to find hydrocarbons

1993

Petrotrin created to bring all government upstream assets under one company

2006

Government stiffens PSC terms to add a direct tax element, which does not go down well with oil companies

1994

First oil company listed on Trinidad and Tobago stock exchange (Moraven Holdings)

2006

Unsuccessful eight-block ultra-deepwater auction

1994

Amoco drills first horizontal well off southeast coast – 2,477 feet through 40-foot thick sands at 8,000 feet depth

2006

BHP Billiton in block 3a makes first oil discovery since Kairi and Canteen in 2001

2006

NGC inaugurates largest gas pipeline in the western hemisphere

1996

BG/Texaco begin supplying gas to NGC from east coast Dolphin field

2007

Eastern Caribbean gas pipeline given formal go-ahead by first customer, Barbados

2007

New gas discoveries in offshore blocks 5c (southeast coast) and 22 (north of Tobago)

2007

Venezuela’s PetroCaribe deferred-payment and soft loan initiative threatens Trinidad and Tobago’s markets

2007

Cross-border natural gas estimated at 10 tcf, of which 27% is on the Trinidad side

2007

8.39MW demonstration methanol-fired power plant established at Point Lisas

2008

Global economic recession

2010

Petrotrin refinery upgrade; revised fiscal arrangements; new exploration block auction; Tobago supplied with gas directly from Angostura field; concern over continued decline in oil production

2011

Eleven blocks offered in deep water auction, only two bids successful – for 23a and TTDAA 14, both to BP Exploration Operating Co.

2011

Proven non-associated natural gas reserves downgraded to 13.46 tcf by Ryder Scott consultants, the seventh straight year of decline

Gas eclipses oil 1996

Natural gas production overtakes oil, marking shift from an oil to a gas economy

1998

Amoco’s Trinidad and Tobago assets acquired by BP Group

1999

Petrotrin forms alliances to boost activity in undeveloped acreage

1999

Trinidad and Tobago becomes the only LNG producer in Latin America/Caribbean

1999

Shell drills first of eight wells in deep water; Exxon and BP follow suit. No oil discovered

2000

NGC’s natural gas sales top one billion standard cubic feet a day for the first time

2001

BHP Billiton makes first east coast offshore oil discovery since Amoco in 1968 with Kairi and Canteen wells

2001

Second non-associated gas find on land, by Vintage in the Central Block

2005

World’s largest LNG train – Atlantic train 4, with a capacity of 5.2 million tones a year – begins production at Point Fortin

2005

World’s largest methanol plant – locally-controlled Methanol 5000 – comes on stream

2005

Government increases royalty on gas exported by bpTT to 10%

2005

Cross-border gas reserves confirmed by Chevron in block 2 and Venezuela’s Plataforma Deltana

Declining oil

2002

BG drills deepest deviated wells, to 22,000 feet in Hibiscus field off the north coast

2002

BPTT commits to maximum local content upstream

2011

Sales missions to Ghana, Suriname and Brazil by energy service companies breaking into international markets

2002

BPTT installs world’s largest offshore gas processing unit off southeast coas

2012

First PSCs for ultra-deep blocks signed with BP Exploration Operating Co. for 23a and TTDAA 14 from 2010 bid round

2003

NGC’s profit crosses TT$1 billion

2012

PSC for block 5d signed with BG Group, 5 tcf of gas resources predicted

2003

Natural gas production off north coast by BG and partners

2012

Six blocks offered in 2012 deep water round; BHP Billiton awarded four of them – TTDAA 5-6, 28-29

2012

Centrica Energy continues negotiation with Puerto Rico Electric Power Authority (Prepa) for supply of gas from Trinidad in pioneering marine CNG form

2012

Beowulf Energy/First Reserve, joint majority owners of Eastern Caribbean Gas Pipeline Co., confirm pipeline gas supply to Barbados

2012

Trinidad and Tobago and Grenada sign framework agreement on energy cooperation

2012

Fiscal incentives for development of small oilfields offshore and deep horizon drilling.

Record breaking 2004

World’s first mega-methanol plant commissioned at Point Lisas for Atlas Methanol

2004

National Energy Corporation responsible for gas-based investment projects, industrial sites and harbours

2004

Petrotrin given automatic position in all exploration/ production arrangements with foreign companies

2005

NGC invests in upstream gas development

energycaribbean YEARBOOK 2013/14

Countries suriname

Keen interest in the deepwater blocks

uriname is billing itself as the “next giant”, meaning that in due course it expects to make a discovery as large as Zaedyus in next-door French

Guiana. In late 2011, 840 million barrels of oil on a P10 basis were found by the Zaedyus well, which has transformed prospects for the Guyana/ Suriname basin to the west. Zaedyus encountered oil in a fan system similar to that found in Tullow Oil’s Jubilee field offshore Ghana in West Africa:

Zaedyus discover off French Guiana (courtesy Tullow)

Suriname is naturally hoping these geological conditions extend westwards into its own waters Tullow’s geologists thought this could be replicated on the western side of the Atlantic – and so it proved. Shell and Northpet Investments are Tullow’s partners in the Guyana Maritime licence where Zaedyus was drilled. Suriname is naturally hoping these geological conditions extend

westwards into its own waters (Guyana is keeping its fingers crossed that its own offshore may be similarly favoured). Suriname’s national energy company Staatsolie, which deals with oil and gas matters on behalf of the government, has offered four blocks for bidding, which it believes to be in the path of any westward hydrocarbon trend – 54, 55, 56 and 57. Bids close on July 26 and the company hopes to be able to sign production sharing contracts with the winners by year’s end. These blocks are sited in the Demerara Plateau, described by Staatsolie as “a prominent submarine plateau located 5 degrees north of the coasts of Suriname and French Guiana and, based on available data, interpreted as a margin segment, comprising thinned continental crust, bound to the north and south by transform-type zones in which transtensional extension is accommodated.” That will be music to the ears of geologists. Wim Dwarkasing, deputy director of exploration and production contracts for Staatsolie, enthuses that “these blocks are all based on structures and the success rate is usually higher with such blocks.” He adds: “The Demerara Plateau is all part of what you have seen on the west coast of Africa where they have had these very good finds, so that’s also an attractive feature of the bid round.”

32 35 46

Tullow Oil Block 47 Murphy Oil Block 48

Kosmos Energy Block 42

Block 52 Petronas

ritim

or d

en ch

me -Fr

rin a

oAST ly line 1 CO P 0 35

1 CO P 0 35 oAST ly line

oAST C 0 P 1O 35 ly line

oAST ly line 1 0 CO P 35

1 CO P 0 35 oAST ly line

C P 1yO 35 o 1 CO P 0 35 l0 il y oAST n lei n e lAST

CO P 0 AST ly line 1 35 o

1 CO P 0 o 35 AST ly line

0 1 CO P o 35 AST ly line

1O 35 ly line oAST C 0 P 1 C P 0 35 o llyylliinnee CO P 0 O AST 1 35 oAST 1 0 CO P 35 oAST ly lin e

1 0 CO P 35 oAST ly line

oAST 1O C P 0 35 ly line

ly line 1 CO P 0 o 35 AST

Coronie Block

1 35 CO 0 P oAST ly line

CO P ly line 0 oAST 1 35

Commewijne Block

0 CO P oAST 3 1 35 ly line 5

Uitkijk Block

oAST ly line 1 0 CO P 35

Calcutta Block

1 CO P 0 o 35 AST ly line

Weg naar Zee Block

0 CO P oAST 1 35 ly line

Tambaredjo Block

ly line oAST CO P 0 1 35

1 CO P 0 35 oAST ly line 1 CO P 0 35 oAST ly line 1 CO P 0 35 AST ly line o

1 CO 0 P 35 oAST ly line

o 1 0 CO P 35 AST ly line

Gu ian

Nickerie Block

aM ar i

ti m eB

ord e

Block 31 Inpex

-G u ya am e

Block 53

r in

Block 45 Kosmos Energy

Apache

oAST C P 0 1O 35 ly line C 0 P 1O o 35 AST ly line

ly line oAST CO P 0 1 35

C 0 P 1O 35 oAST ly line

1 CO P 0 35 oAST ly line

oAST C 0 P 1O 35 ly line

100

150 km

Legend: Blocks under contract Blocks not on offer Staatsolie operated blocks

Suriname block map (courtesy Staatsolie)

aedyus appears to have triggered a rush into the Suriname deep water. Tullow itself had been first, with block 47 in 2010. The US’s Kosmos, which was associated with Tullow in the Jubilee find offshore Ghana, came in shortly after, taking blocks 42 and 45, and was quickly joined by a major, the US’s Chevron, which farmed in for 50%. Murphy Oil, which had earlier held block 37 further south, relinquished that after sinking two unsuccessful wells, and moved further north to block 48. Apache was awarded block 53 in a “short-listed bid round” in mid-2012, and Malaysia’s Petronas block 52. The arrival of a company from the other side of the world has been particularly satisfying for Staatsolie. Dwarkasing notes, “This is the first time an oil company from Malaysia has come into our part of the Caribbean to explore.” He might be even more pleased had he known that Petronas

Blocks Bid Round 2013 (28/01/2013 - 26/07/2013) Staatsolie Oil Fields

April 2013

had declined, three years ago, to participate with Petrotrin to explore in deep water block 27 in Trinidad and Tobago because it saw little prospectivity there. Staatsolie itself is planning a leap of faith into the offshore, but closer to the coast, in about 20 metres of water. It is using its subsidiary, Paradise Drilling, to undertake what will probably be a ten-well exploration programme in block 4, one of seven nearshore blocks Staatsolie is keeping for itself. “We have a good feeling about block 4,” Dwarkasing says. “The 3D ocean bottom cable seismic did produce good data. Since it’s shallow water, we can drill at reasonable cost.” The first quarter of 2014 “is a realistic date to start the drilling programme,” he notes, “but all efforts are being made to commence in the fourth quarter of 2013, if we can.” About 40 exploratory wells will also be sunk by Staatsolie in various blocks on land in the course of the year. energycaribbean YEARBOOK 2013/14

Countries barbados

Getting to grips with the offshore again

Andre Braithwaite (courtesy Andre Braithwaite)

he high point of energy activity in Barbados in 2013 will almost certainly be the signing of exploration and production (E&P) contracts with the Anglo-Australian explorer/ producer BHP Billiton, for two blocks in deep water acreage southeast of the island. The blocks adjoin each other, Carlisle Bay (2,498 sq km) directly to the north of Bimshire (2,506 sq km). These two pieces of exploratory acreage were first offered for auction in Barbados’s ill-fated 2007 bid round. But it is probably better late than never for Barbados, which is anxious for offshore exploration to be resumed in earnest. There has been no activity offshore since November 2001, when what is now ConocoPhillips drilled the unsuccessful US$35 million Sandy Lane 1 well in 6,500 feet of water.

arbados’s minuscule 900 b/d of oil is derived from onshore fields, worked by the Barbados National Oil Company 30

(BNOC). Around 2 million cubic feet (mmcfd) of associated gas is used in the fields or sold to the sole electricity provider, Barbados Light and Power. Barbados is the only Caricom oil producer to have stuck with the E&P agreement model for offshore. All others have preferred productionsharing contracts, first introduced in 1993 by Trinidad and Tobago (which still uses E&P agreements for onshore activity). Barbados’s position has always been that E&P contracts are better suited for a country at its stage of hydrocarbon development wanting to attract explorationists. The work programme agreed with BHP Billiton has not been formally announced, but is almost certain to include 3D seismic and one or two exploratory wells, once prospectivity is revealed. A carried share for BNOC – at least in the exploration phase – was a biddable item in the block auction and could be as much as 25%. BNOC is excited at going offshore for the first time on the back of a major international oil company. General manager Winton O’D. Gibbs told this YEARBOOK that “we will take up any stake with enthusiasm. We know offshore is expensive, but the rewards are much better.”

HP Billiton presumably sees opportunities in the Barbados offshore, despite ConocoPhillips’ disappointing experience, or it would not have persevered as long as it has. It has had to overcome various negotiating obstacles along the way, including a change of government in early 2008. Perhaps fortunately for the

company, the Democratic Labour Party retained power in the general election in February 2013, though with a severely reduced majority. ConocoPhillips’ failure to find commercial quantities of oil has not dampened the experts’ positive view of the Barbados deep water either. Mervyn Gordon, BNOC’s technical manager, believes that “both oil and gas will be found off Barbados, not just gas, as some people have said. Drilling will be taking place in about 6,000-7,000 feet of water and you can go another 10,00015,000 feet. I expect we will find some oil. I am very confident of that.” Andre Brathwaite, director, natural resources, in the division of energy and telecommunications in the office of prime minister Freundel Stuart, believes that “a discovery of oil or gas will be made offshore Barbados in the years ahead. I base that confidence on the geology.” He points out that “the more than 14,000 lines of offshore seismic we now have shows that we have prospectivity in the east, west and south,” and cites extensive seismic coverage as one of the reasons why “international companies are now showing interest in Barbados again.” Onshore, BNOC will be continuing its development drilling programmes in 2013, following the exploration and appraisal wells it sunk in 2011-2012, which added at least 64,000 barrels to proven reserves. Development drilling is important not only because it maintains or increases production, but also because it often leads to an upgrade of reserves. The 2011-2012 programme added 822,000 barrels, according to Gibbs.

Barbados Block Map (courtesy Barbados Division of Energy)

energycaribbean YEARBOOK 2013/14

Countries belize

Plenty of setbacks – but not fatal

elize became a Caricom oil expertise to drill safely.” producer in 2005 after 50 years The suit was brought by two of trying, and was doing quite environmental organisations, Citizens well until it suffered a number of Organised for Liberty through Action and body blows that will make 2013 the Belize Coalition to save our Natural a difficult year for the industry. Heritage. The latter has been agitating for The first blow is that production from some time to stop offshore exploration its two fields, Spanish Lookout and Never following BP’s Macondo well blowout in Delay in western Belize, has plummeted. the Gulf of Mexico in 2010. Belize Natural Energy (BNEL) identified The government responded by offering retrievable oil reserves with its first a referendum on the matter, but that has exploratory well eight years ago, and been on hold for some time. An appeal output rose rapidly to over 5,000 b/d. But against the judgment will probably be it has since declined to about 2,550 b/d, made but, in the meantime, Belize’s not only depriving the government of offshore acreage is out of bounds for exploration, a fact which will hardly much-needed revenue but reducing the associated gas and liquefied petroleum gas Hon. Senator Joy Grant (courtesy encourage international oil companies to www.belize.gov.bz) available for the local market. look seriously at offshore prospects. The bidding rounds which the The second blow is that other explorationists have not been able to replicate BNEL’s initial government says it wants to introduce will have to be confined success. New World Oil and Gas was forced to plug and to the onshore for the foreseeable future. abandon its Rio Bravo 1 exploratory well in northwestern Belize after failing to find oil, on the heels of a similar failure ut the future for hydrocarbons in Belize is not entirely bleak, with its Blue Creek 1 and 2 wells. The company is putting since companies which already hold onshore licences will a brave face on it, and pledges to return to the Blue Creek want to get started on exploration. These include Marenco, US area in due course, because “with multiple prospects already Capital Energy, Treaty Energy and the French firm Parenco. identified, we believe it is only a matter of time before we Belize’s minister of energy, A. Joy Grant, is prepared to locate a trap of significant size.” predict “a spate of exploratory drilling over the next few years, based on what the companies see as promising potential in he third blow has the biggest disruptive potential for the their blocks.” short to medium term: the Belize Supreme Court ruled Belize is committed to renewable energy, as a participant in that all drilling contracts for offshore exploration issued by the Caricom Energy Plan. the government between 2004 and 2007 are “null and void.” Minister Grant contends that already generates more It decided that proper environmental impact assessments electricity from renewable resources – 68% – than any other had not been carried out before the signing of contracts, as Caricom member, thanks to the wide use of sugar cane required by law. It also declared that the companies involved, residue, bagasse, to heat boilers for the industry’s own power which include Island Oil Belize, Tropical Energy, Petro Belize, needs, the surplus being passed on to the national grid. Princess Petroleum, Providence Energy and Sol Oil, “had failed to prove an ability to contribute the necessary funds, assets, machinery, equipment, tools and technical

Belize generates more electricity from renewable resources – 68% – than any other Caricom member

Countries jamaica

Restarting the exploration drive

“I am not going to allow any company to hold on to any licence without living up to its obligations”

amaica will be trying in 2013 to get its derailed programme for offshore exploration back on track, and to find more reliable companies on which to pin its faith for a hydrocarbon future. Last year, its minister of science, technology, energy and mining, Phillip Paulwell, had to terminate production sharing agreements with three companies – Finder/Flow, Sagres/Rainville and Proteam. They had failed to live up to the seismic or drilling obligations in the licences they had acquired over the last eight years for a total of 12 blocks off Jamaica’s south and southeast coasts. Both Finder/Flow and Sagres/Rainville had come close to meeting their obligation to sink an exploratory well following the completion and interpretation of seismic, but neither was apparently able to find financial partners to help fund what was certain to be an expensive drilling project.

inister Paulwell, back in his old job following the return of the People’s National Party to office, has taken a nononsense approach to the lagging exploration programme. “I am not going to allow any company to hold on to any licence without living up to its obligations,” he warned. “We have to send a strong signal to the marketplace that we mean business.” If Jamaica wants to make any progress at all towards realising its long-held desire for at least some energy independence, it now has to start exploration again after a long hiatus. Eleven wells were drilled for oil between 1955 and 1982, two in the offshore, but none found hydrocarbon reservoirs. Some of those were sunk by big names in the business at the time – Union Texas, Occidental, and Italy’s Agip (which is still around). Minister Paulwell thinks he will be best served by going that route again but attracting stronger companies into the drilling campaign than the three most recent licencees. “We recognise the need to get larger players and we are pursuing a number of them,” he told this YEARBOOK.

The production-sharing agreements with Finder/Flow, Sagres/Rainville and Proteam emerged from the 2005 block round. The most recent block auction, in 2010-2011, produce no acceptable bids.

aulwell is now taking a different approach and will engage in bilateral negotiations with selected companies. He thinks this will afford more flexibility in agreeing terms. “My view is that the open-tender system does not seem to have worked. We will now engage companies in direct negotiations and come away with arrangements that we negotiate, rather than having a public bid.” This view has been strengthened by the lack of success in the 2010-2011 block auction, which Paulwell insists “was not marketed properly” (it opened during the time of the previous Jamaica Labour Party government). He says that more recent data has become available which “will make Jamaica far more attractive now,” and intends to “impress on some of the major corporations the raw data that we have which will show the substantial reserves we think Jamaica has.” On this basis, even the four land blocks that have been so far ignored by bidders – Negril, Portland, Santa Cruz and Windsor – might conceivably seem more attractive. While struggling to get the exploration process back on track, Paulwell is also preoccupied with the long-running problem of the Jamaican refinery, Petrojam, 51% of which is owned by the Petroleum Corporation of Jamaica (PCJ). Petrojam urgently needs to be upgraded from its present limited capacity of 35,000 b/d to around 50,000 b/d. Venezuela’s PdVSA, which has acquired the other 49%, is pledged to fund the upgrading. But if it does not happen, “we will have to shut it down. It’s as simple as that,” says Paulwell. The government has already decided to sell off one PCJ subsidiary – its fuels retailer, the Petroleum Company of Jamaica, better known as Petcom.

energycaribbean YEARBOOK 2013/14

Countries guyana

Could luck change with the Stabroek block?

f the geological structures that trapped oil off Ghana and other West African countries are really replicated off South America, it has yet to be demonstrated in Guyana, despite the evidence of oil off nearby French Guiana. Neither the US$71 million Eagle 1 well in CGX Energy’s Corentyne block nor the Jaguar 1 well in the Georgetown block found oil or gas in 2012. Repsol is the operator, partnering Tullow Oil, YPF Guyana and CGX itself. Jaguar was stopped at 4,878 metres instead of being drilled to the Late Cretaceous horizon, as planned, because “pressure design limits for safe operations prevented further drilling,” according to a Tullow spokesman. There was a glimmer of hope in that “samples of light oil were recovered from two Late Cretaceous turbidite sands above the primary objective.” How soon operators will return to drilling is uncertain. CGX’s intentions towards Corentyne are unknown, while Repsol says it considers the Georgetown block “still interesting” and may drill again, but “not before late 2013/early 2014.” CGX holds several other Guyana offshore blocks – Corentyne Annexe (100%), Pomeroon (100%) and, onshore, the majority share in Berbice through its fully-owned subsidiary,

Most hopes now lie with ExxonMobil/Shell, whose Stabroek block is by far the largest piece of offshore acreage Guyana has licensed ON Energy. But it has not said when it will try its luck again – and Berbice has probably been ruled out after three unsuccessful wells. There has been no word from ExxonMobil and Shell, who hold the Stabroek block in a 75/25% equity relationship.

have been surrendered. Next-door Suriname has also failed so far to identify offshore oil or gas. Two wells drilled in 2010-2011 by Murphy Oil in block 37 (Aracara and Caracari) and by Inpex in block 31 (Aitkanti) all failed to find retrievable volumes.

he most recent international oil company to take an interest in Guyana, Anadarko Petroleum Corporation, has said it will “study available data” for its block, named Roraima, “with a view to identifying leads that could result in prospects favourable for drilling.” So the possibility of some Guyanese offshore blocks being on trend with the Zaedyus find in French Guiana should not altogether be ruled out. Apart from Berbice, there is another licensed block onshore Guyana – Takutu in the interior, regarded as cross-border with Brazil. It is held 65% by Canacol, 25% by Sagres Energy and 10% by Takutu Oil and Gas, formerly Groundstar Resources. The Apoteri K2 well was drilled there, though without success, and the acreage may even

The possibility of some Guyanese offshore blocks being on trend with the Zaedyus find in French Guiana should not altogether be ruled out 34

ost hopes now lie with ExxonMobil/Shell, whose Stabroek block is by far the largest piece of offshore acreage Guyana has licensed. It extends from the Venezuelan maritime border in the west to the Suriname maritime border in the east, and could contain a wide sweep of prospects. The two companies were only obliged to undertake 2D seismic, which was completed, but they opted for another 2D exercise to fill in some blank spots. Newell Dennison, manager of the petroleum division in the Guyana Geology and Mines Commission, suggests that ExxonMobil/Shell might consider 3D acquisition. But they will have to make up their minds soon about sinking an actual well, since they keep losing parts of Stabroek through mandatory relinquishments which, in Dennison’s words, “are aggressive.” He says: “ExxonMobil has told us they are not interested in dragging the situation out, so may drill eventually.” It remains to be seen whether that happens in 2013.

Countries cuba

Deep water seems to be dry

uba had high hopes of success from its deep water drilling campaign in the Gulf of Mexico. But they were well and truly dashed in 2012 and into 2013, and no further offshore exploration is planned for the rest of the year. The list of well failures has been dispiriting. After drawing a blank with Jaguey 1, Repsol declined to drill a second well, and said it would quit the Cuban deep water. Malaysia’s Petronas and Russia’s Gazpromneft had no more success with the Catoche 1 well – a statement issued by the Cuban state oil company Cubapetroleo said that “the rocks are very compact and do not have the capacity to deliver significant quantities of petroleum or gas, so the well can not be classified as a commercial success.” Venezuela’s national energy company PdVSA had no luck with its Cabo de San Antonio well, not did Russia’s Zerubezhneft with its exploratory well. The Angolan state energy company Sonangol, Vietnam’s Petro Vietnam and India’s ONGC promised to try their hand in the deep water, where Cuba has delineated 59 blocks in its exclusive economic zone: but they are understood to be unlikely to proceed. Petro Vietnam said it would wait for the results of PdVSA’s work, which was unsuccessful, while ONGC reportedly told Cuban officials it needed partners to help finance wells in one of its two

offshore blocks. On current trends, such partners are unlikely to come on board.

owever, while the deep water may be sidelined for the foreseeable future, Zerubezhneft is staying on to drill some wells nearshore northern Cuba, and even plans to move onshore into blocks 9 and 12, where wells abandoned many years ago are considered ripe for revival. For now, it seems that Cuba’s crude oil production from onshore and nearshore wells will remain stuck at around 52,000 b/d, forcing it to continue importing about 110,000 b/d of refined products like gasolene, diesel and fuel oil, plus crude for its four refineries at Cienfuegos, Mantanzas, Habana and Santiago de Cuba, which is largely sourced from Venezuela. Upgrades are planned for three of these refineries, with Habana slated to be shut down. Combined nominal capacity is 300,000 b/d, but the four can deliver no more than about 104,000 b/d at present. Cienfuegos has actually exported a small amount of refined products (about 16,000 b/d) since PdVSA came on board as a partner with Cubapetroleo. Venezuela is pledged to fund an expansion programme at Cienfuegos under the two countries’ Cuvenpetrol joint venture, which will raise production from 65,000 b/d to 150,000 b/d. Financing for the expansion was to have been provided by Venezuela,

Repsol declined to drill a second well, and said it would quit the Cuban deep water

using funds from China under a cashfor-oil credit scheme. But under its new president Nicolás Maduro, Caracas may be having second thoughts about all these arrangements, which enable Venezuela to undertake development projects at home and abroad while pledging oil supplies as repayment in the future.

o it is not entirely surprising to hear from Cuvenpetrol that, at the time of writing, no contract for the Cienfuegos upgrading had been signed with the chosen contractor, China National Petroleum’s Huanqui Contracting and Engineering Unit. Alongside the Cienfuegos upgrade, other infrastructure is planned for the area: an LNG regasification plant, to handle LNG imports of around 2 million tonnes a year; a petrochemical complex; and power generation facilities. Cuba has long been in the frame for imported LNG, with Trinidad and Tobago a possible long-term supplier, since no US LNG exporter would be allowed to trade with the country. As in many other Caribbean states these days, Cuba is probably having more success with renewable energy than with hydrocarbons. Early in 2013 it announced a major programme of wind-farm construction, with six facilities across the country, generating 280MW. Officials reckon that this could save 184,000 tonnes of CO2 emissions, compared with oil-fired generators. 280MW is only scratching the surface of wind power, since Cuba is said to be capable of as much as 1,200MW of wind-generated energy.

energycaribbean YEARBOOK 2013/14

Companies atlantic

A global benchmark for LNG

Countries

n 2013 Atlantic, Trinidad and Tobago’s much-admired LNG complex at Point Fortin, should achieve the status of a global benchmark for LNG trains, according to its former CEO, Oscar Prieto. Prieto’s successor, Nigel Darlow, has not publicly confirmed that status yet, but clearly believes it is possible, since Atlantic is already close to it in areas like “safety performance, production reliability and corporate sustainability”. One aspect he concedes still needs attention is “cost efficiency.” “Sustainability” is a buzz word taken to mean different things by different interests. In Caricom’s new energy policy it refers to “renewable energy and energy efficiency”, at least in an upstream sense. Atlantic is a “midstream” company but efficiency in the use of its main input, natural gas, of which it is the prime consumer in Trinidad and Tobago (2.1 bn cfd in 2012), is equally important. The less gas used to make a tonne of LNG, the lower the costs of production and the higher the LNG output.

country’s precious natural gas reserves must be economically used. “We will continue to be a significant revenue generator for our shareholders and the government and people of Trinidad and Tobago for a very long time to come,” he says. “Our offtakers have been very successful at accessing high-class markets.” He has at least a 20-year timeframe for Atlantic, pointing out that “we’ve got to work to ensure that we compete in the global market, [and] get the gas supplies we need to enable the facility to last for another 20-plus years – that’s the goal.”

arlow is confident that Atlantic – whose shareholders are BP, BG, Summer Soca LNG liquefaction SA (train one only), and the National Gas Company (trains one and four only), soon to be joined by Royal Dutch Shell, which has bought out Repsol’s share

– “will always have a market for LNG because, despite all the plants that are planned, the consensus in the industry is that demand for LNG will continue to outstrip supply. Worldwide, gas is increasingly becoming the fuel of choice to replace oil and coal.” Atlantic is one of the few companies in the energy sector that publishes an annual sustainability review (and does so very attractively too, with a wealth of information about its activities). It is even completely honest about a subject few big-name companies want to talk about – its contribution to global warming. In its 2011 sustainability report, Atlantic revealed that its greenhouse gas (GHG) emissions were 5.31 million tonnes for the year. It “monitors and manages GHG emissions from the production process through multiple approaches, including efficiencies in operation and reductions in flaring.”

ost management is one of five focus areas that Darlow has identified as Atlantic becomes a benchmarking model for the LNG world. The others: personal safety, people development and talent management, project delivery of the plant optimisation programme, and production and reliability. Efficiency, the CEO stresses, “very much includes procurement, how we spend our supply-chain budget. We need to be cost-conscious and have a prudent approach to cost management.” Darlow is keenly conscious that the

Atlantic’s LNG complex at Point Fortin (courtesy Atlantic)

Companies CIBC firstcaribbean international bank

FCIB aspires to be the region’s energy bank

Countries

IBC FirstCaribbean International Bank, successor to the Barclays and CIBC operations in the region (making it the largest banking institution in the Englishspeaking Caribbean), will continue to seek out funding opportunities in the energy sector in 2013. It has been most successful so far in the area of electricity, where it has helped fund the Jamaica Public Service Company (with whom the Bank says it has a “strong relationship”), the Jamaican IPP West Kingston Power Partners, the Bahamas Electricity Corporation and St Lucia Electricity Services. It has also been lead arranger/underwriter for an equity issue by the Canadian power company Emera Inc., in relation to its Caribbean acquisitions. But it is likely to pay more attention in the future to upstream oil and gas activity, downstream projects, renewable energy and energy efficiency, all of which are likely to need injections of loan capital as new initiatives ramp up in various parts of the region, including, of course, Trinidad and Tobago. The Bank has already taken part in a US$235 million syndicated loan facility for the Suriname national oil company, Staatsolie, to which it contributed US$10 million, for production and refinery expansion.

s the recently-approved Caricom Energy Policy moves into its implementation phase, with the emphasis on greater take-up of renewable energy (RE) and the adoption of energy efficiency measures in the region, CIBC FirstCaribbean International will have even greater scope for extending financial support to energyrelated activity. It already has an RE project to its credit, having been part of a syndicate that underwrote a US$54 million secured term loan facility to NuCuraçao Windparken BV for 30MW of wind power generation. This represents, according to the Bank, “almost 20% of Curaçao’s annual energy demand.” Sharaz Ahamad, CIBC FirstCaribbean’s director for origination and capital market products in the Southern Caribbean, points out that the Bank has even ventured into biomass-to-energy, by “funding the first stage of a waste recycling plant for a company called Sustainable Recycling in Barbados, which will collect household waste and bundle it so it can be used in an incinerator to provide energy to the grid.” Though Trinidad and Tobago has signed on to the “sustainable energy” that underpins the Caricom Energy Policy, Ahamad has his doubts about whether RE will catch on easily in a

“The economics of RE will be challenging in Trinidad and Tobago: I don’t see a huge project in solar or wind here” 38

country already self-sufficient in both oil and gas sold at attractive prices for electricity generation, transport and cooking/water heating. “The economics of RE will be challenging in Trinidad and Tobago,” he says, “I don’t see a huge project in solar or wind here – the economics don’t really lend themselves to it.” He may be in for a pleasant surprise, however, since the energy ministry in Port of Spain seems determined to woo consumers into looking more kindly on RE and is itself active in promoting it.

hamad does concede that Trinidad and Tobago may be a strong candidate for the application of energy efficiency measures, since the very cheapness of energy tends to encourage laxity in its conservation. “There’s a huge opportunity here in all Caricom members,” he insists. “Energy costs are very high in most regional states. The hotel plant in particular is a very good candidate. In fact, we have a programme of loans to hotels to improve energy efficiency.” Downstream industries from the core petrochemical plants in Trinidad and Tobago is another area where CIBC FirstCaribbean is keen to be active. Two such investments in which it has had mild initial involvement – the Carisal caustic soda/calcium chloride plant and the EthylChem ethanol dehydration facility – do not now appear to be going forward, but no doubt other loan opportunities will arise in the downstream part of the energy sector in due course.

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Companies gasfin development sa

Small LNG plant can transform TT gas exports Countries

asfin Development SA, a Luxembourgregistered “right-sized LNG solutions” company, as it describes itself, is anxious to establish a small LNG plant in Trinidad and Tobago, and has been trying to persuade the energy ministry and its gas promotion agency, the National Gas Company (NGC), towards that end for almost four years, without success up to the time of writing. Why is Gasfin Development so keen on Project Constantine, as it has named its LNG project? Because it thinks Trinidad and Tobago, the only country capable of exporting gas in the Caribbean and Central America, should be taking advantage of the expected demand from regional power utilities for small and mediumsized (i.e. “right-sized”) cargos of LNG for fuel. The high cost of conventional fuel oil and diesel is translating into crippling electricity bills for businesses and households. There is no government intervention in fuel costs in the Caribbean except in Trinidad and Tobago itself, so local utilities have to bear the full brunt of market prices. Gasfin’s CEO Roland Fisher, who has been pressing for a 500,000-tonne-per-year single train (at first), reckons that gas would be eminently competitive at the mmbtu equivalent price of fuel oil or diesel. He has identified several markets in the Caribbean and Central America that would be willing to convert to gas if they could be assured of a regular supply that significantly reduced their energy costs.

Gasfin designed and delivered the first mid-scale LNG plant and built the first mid-scale mixed-use LNG carrier 40

he small size of these regional power utilities means that their LNG requirements would be modest, in the range of 50,000 to 100,000 tonnes a year (7 million to 14 million cubic feet of gas a day). The total gas requirement for the LNG train which Fisher wants to site at La Brea in southwest Trinidad would therefore be only 70 mmcfd, which could probably be squeezed out of NGC’s current gas contracts, which amount to about 1.7 bn cfd. Another 2.3 bn cfd is already diverted to LNG production by direct deals between gas-producing companies and Atlantic at Point Fortin. Gasfin comes with impeccable credentials as a “right-sized LNG solutions” company. It designed and delivered the first mid-scale LNG plant – 400,000 tonnes a year – to China in 2004. It built the first mid-scale mixed-use LNG carrier, the 7,500 cubic metre Coral Methane, in 2009. If floating storage and regasification units are required – which is likely to be the case with the market Gasfin wants to service in the French Caribbean departments of Martinique and Guadeloupe – then it can construct those too. The company claims its type C LNG cargo tank “is the only tank design able to withstand pressure build-up from LNG storage.”

rinidad and Tobago, through Atlantic, already services about 21 LNG markets in the world, but the unique value of the Caribbean and Central American market is its scaleddown size. A local company, in the form of NGC, can handle this in such a way that Trinidad and Tobago, as a country, is directly involved in the LNG value chain, rather than indirectly through companies such as BP, BG and Repsol. Fisher believes that La Brea LNG will bring tangible benefits to Trinidad and Tobago by positioning it as “the world pioneer of mid-scale LNG exporting” through the “capture of long-term premium markets in the Caribbean.” What’s more, with a small LNG plant up and running, LNG for the first time could be used domestically for industry and transport, even rivalling CNG as an alternative motor fuel.

Delivering gas to the Caribbean

Right-sized LNG solutions Gasfin, building on its extensive global references in Mid-scale LNG, stands ready to assist Trinidad & Tobago to win the race to serve the Caribbean gas market. For more information visit www.gasfin.net or call +44 20 3369 9690

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Companies methanex trinidad

Happy with TT operation – but no expansion

Countries M ethanex Corporation, the world’s largest methanol supplier (7.5 million tonnes in 2012), is in expansionist mode – but not, curiously, in Trinidad and Tobago, where one of its major production facilities is sited at the Point Lisas industrial estate. One reason for that could be its caution about what newly-appointed president and CEO John Floren describes as “concentration – having too many plants in one location.” Methanex’s capacity in the Caribbean’s oil and gas capital is already up to 2.5 million tonnes annually – 850,000 tonnes from Titan, of which it is the sole owner, and 1.7 million tonnes from Atlas, which it operates with a 63.1% equity holding, partnered by bpTT (36.9%). “Concentration” has obliged Methanex to relocate two of its four methanol plants in Chile to the US Gulf Coast state of Louisiana. Those units have not actually been producing for some time, because of problems with gas supply, so it made sense to site them in a place with gas coming out of its ears thanks to the shale revolution, and at a very attractive price. “We wanted gas from Argentina, but that became a low-profitability in the short term”, Floren explains, “so running four plants in Chile was not feasible on a long-term basis.” Since the plants were idle, the two

million tonnes of methanol they will be producing by 2016 are regarded as new output.

ethanex’s 7.5 million tonnes a year represents 15% of global methanol sales, and the Vancouverbased corporation is determined to maintain that share of the market. To do that, says Floren, it must “grow by one million tonnes every two years.” The two Louisiana facilities will help meet that target. In New Zealand, Methanex is increasing capacity at its Motunui plant by 700,000 tonnes through a de-bottlenecking process, and is restarting the Waitara Valley unit, which will add another 500,000 tonnes to production. Two years ago, it brought back on stream its 470,000-tonne methanol facility in Medicine Hat, Alberta, which had been idle for several years, and will boost capacity up to 580,000 tonnes this year. Its 60% owned and operated plant in Egypt, with a capacity of 1.3 million tonnes, is said to be “one of the most energy-efficient methanol production facilities in the world,” and delivered its first cargo in 2011. Besides the risk in “concentration”, Methanex has experienced difficulties in Trinidad and Tobago in recent years – supplies of oxygen from Air Products and Air Liquide, gas delivery from the National Gas Company, “technical problems” in running the huge Atlas

To maintain that share of the market, Methanex must “grow by one million tonnes every two years” 42

John Floren (courtesy Methanex)

plant. All these factors may have affected thoughts of expansion.

ut overall, Floren says he is “happy” with his Trinidad and Tobago assets and is “making progress with getting the plants to be more reliable.” With the methanol price hovering around US$400 a tonne, “all of our operations are very profitable.” Methanex Trinidad is already prepared for any future local expansion: as Floren points out, it has “available land around our plant at Point Lisas, for which we pay a million dollars a year to keep.” But he is careful to stress that any future growth in Trinidad and Tobago will involve producing more methanol, not going downstream. “We have no interest in going there. When we look downstream, we don’t see the same type of market conditions as we do in methanol. We can not see any industry downstream that is as attractive as methanol.”

Companies National gas company (NGC)

NGC is set to expand

rinidad and Tobago’s National Gas Company (NGC) should be finalising agreements to participate in the local operation of three multinational energy companies in 2013. Its intention, as energy minister Kevin Ramnarine has indicated, is to “acquire all or part of their assets in Trinidad and Tobago.” One of those acquisitions is Total’s interest in the productive block 2c (30%) and in the Greater Ruby/Delaware Market Development Area in block 3a (8.5%), both off the northeast coast of Trinidad. Total has decided to sell because what it has in Trinidad and Tobago is small potatoes and it needs to focus investment and management time on areas of the world where it has grander prospects. Those include nearby French Guiana, where it holds 25% in the Guyane Maritime licence in which the Zaedyus oil discovery was made in late 2011. By contrast, its holdings in 2c provide it with a 30% share in only 12,479 b/d of oil and 431 mmcfd of gas (2012 average). In NGC’s quest to go upstream, where it is currently limited to 15% in the Repsol-operated Teak/Samaan/Poui block, even modest access to oil and gas production is welcome. It already buys 220 mmcfd from the BHP Billiton-operated block 2c; now it will be regaining some of that in revenue from its ownership position. Block 3a is an undeveloped play at the moment, but there could be significant amounts of oil and gas available from that source in the future. NGC’s new president, Indar Maharaj, has not confirmed the company’s takeover of Total’s holdings, nor the names of the other two intended acquisitions, only conceding in an interview with this YEARBOOK that “the discussions are at different stages at the moment.” The company’s strategic goal, he explains, is “to get into all aspects of the value chain – once the risk is acceptable, since I have to be very, very careful with risk. But if I want to go upstream and I see an entity that is already in operation and doing well, then I’m minimising my risk while getting an opportunity.” n 2012, NGC struck out boldly in another value-adding area – marketing the three cargos of LNG produced from the 30 mmcfd of gas it buys for export from EOG Resources Trinidad. Previously, these were sold internationally on its behalf by BP, but even before the new president came on board, NGC had been moving to insert itself into the LNG trading business. Its first cargo, of about 118,000 cubic metres, was sold to the

international trading company Gunvor at US$9.25 per mmbtu, minister Ramnarine has revealed. This was considerably more than the US$1.60 per mmbtu that NGC earned when BP Gas Marketing was doing the job. Subsequently, two other cargos were bought by Brazil’s Petrobras and Trafigura, at steadily increasing prices. According to Anand Ragbir, NGC’s vice president, commercial: “We earned about six times more for our second cargo than we used to get from BP, and about eight times more for the third.” Clearly, the company has been a quick learner and appears to have mastered the intricacies of global LNG marketing. On the home from, NGC will be helping to make compressed natural gas (CNG) a more attractive fuel for motorists in 2013. “The establishment of a new company to promote the concept is one of the options being considered,” Maharaj confirms. It will probably be partnered by its fellow state firms, Petrotrin and National Petroleum (NP). Such a company would have to deal with all aspects of the CNG initiative – service stations, vehicle conversions, and pipelines to take gas to the pumps. But Maharaj asserts: “We’ve got to break this cycle of indecision over CNG.”

Countries

Anand Ragbir (courtesy NGC)

Companies repsol trinidad and tobago

Repsol slims itself down

epsol finds itself a much smaller player in the Trinidad and Tobago energy sector in 2013 than it was only a year earlier. Its major asset – its shareholding in Atlantic’s four LNG trains – has, from all accounts, been purchased by Royal Dutch Shell, leaving Repsol with no ownership interest in the 15.2 million tonnes a year of gas liquefaction capacity in the world’s sixth largest LNG trader, though it may well continue to buy LNG from Trinidad and Tobago to service its own supply commitments. That Atlantic holding amounted to 20% in train one, 25% in trains 2 and 3, and 22.2% in train 4.

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owever, Repsol’s presence is still significant. It owns 30% of bpTT, the biggest upstream company in the energy sector, which produces around 408,000 barrels of oil equivalent a day (boed), mainly natural gas. It has 70% and operatorship in the Teak/Samaan/Poui (TSP) block off the east coast, which produces close to 12,000 b/d of oil and 30 mmcfd of gas.

Repsol is concentrating on the one asset of which it is in charge – the TSP block – and maximising its performance

Repsol Headquarters, Trinidad (courtesy Repsol)

Repsol’s major asset – its shareholding in Atlantic’s four LNG trains – has, from all accounts, been purchased by Royal Dutch Shell

Repsol is also a 30%, non-operating shareholder in block 5b, on the maritime boundary line with Venezuela southwest of Trinidad, where around 2 trillion cubic feet of gas was identified by the Manakin 1 exploration well 13 years ago. The Coquina 1 well sunk by Venezuela’s PdVSA in 1982 also encountered gas, in shallower horizons. This is a significant asset from Repsol’s point of view, but it can’t be monetised until agreement is reached with Venezuela on unitising the reservoirs on each side. The latest word on the matter from Norman Christie, regional president, Trinidad, for bpTT (the operator of 5b), is that “the reserves have been decided but divisions have not yet been agreed.” Not surprisingly, Christie sees Manakin as “a medium-term development matter.”

epsol also partnered BHP Billiton in the 2010 deep water acreage auction to bid for block 23b. The bid was not acceptable to the energy ministry in the terms in which it was couched, and the parties were supposed to hold discussions “with a view to attaining a mutually acceptable proposal.” Those discussions have not yet concluded, as far as this YEARBOOK is aware, and it is possible that BHP Billiton may no longer be interested in them, having been awarded no fewer than four other deep water blocks – TTDAA 5-6 and 28-29 – in the 2012 deep water bid round. Which leaves Repsol to concentrate on the one asset of which it is in charge – the TSP block – and maximise its performance in 2013. It is attempting to do that by drilling two appraisal wells and six in-fill wells, the latter in the Teak field, the old workhorse of the block. Some non-rig work will also be undertaken to improve the wells’ flow. TSP, being old fields, are declining fast, and Repsol’s challenge is how to arrest, and even reverse, that slide. It has done a commendable job so far, even managing to push production up a little between 2011 (average 11,771 b/d) and 2012 (average 11,961 b/d).

Companies solaris energy

Oil producer jumps into renewables

Countries

olaris Energy is the result of an adroit move by a small Trinidad and Tobago oil producer, Moraven Holdings, into renewable energy (RE), well before any of its fellow independents have thought of the idea. It’s an obvious case of hedging your bets, on the assumption that RE is going to claim a growing share of the energy market in Caricom in the years ahead, once its 15 members act on the basis of their own regional energy policy (see elsewhere in this YEARBOOK). Moraven Holdings, a public company quoted on the second tier of the Trinidad and Tobago stock exchange, is at the bottom end of the oil production scale, lifting an average of only 229 b/d in 2012, according to the ministry of energy and energy affairs. This comes from its subsidiary Mora Oil Ventures’ Mora A production platform off Trinidad’s southeast coast. Presumably seeing the writing on the wall, Moraven Holdings set up Solaris Energy in 2010. It acts as distributor for the flat plate and vacuum tube solar water heaters and photovoltaic solar panels made by Solaris Global Energy in Barbados, of which it is the majority owner. The Barbados entity was formerly Aqua Sol Components, a company with 30 years’ experience in manufacturing solar energy products.

arbados has long led the way in Caricom in using solar energy for water heating in place of electricity or liquefied petroleum gas. It has “the third highest penetration of solar water heaters in the world,” according to Vincent McClean, Solaris Global Energy’s chief innovation officer. The company is one of three manufacturing solar products in Barbados; there is another in St Lucia – and that’s about it as far as Caricom is concerned. Solaris regards itself as being head and shoulders above the competition: its new 8,000 sq foot factory at the Six Roads industrial estate in St Phillip, opened in October 2012 and, powered by a 50kW photovoltaic system, generates enough electricity to be able to feed back into the Barbados Light and Power’s national transmission grid. In short, it is not only preaching the benefits of renewable energy (RE) to its clients but using RE itself: Solaris Global Energy is the only RE products producer in the region running fully on RE. Barbados’s ministry of transport and works has received 48

that message loud and clear, and recently installed a 10kW wind turbine at its Chance Hall depot in St Lucy, mounted on a 48-foot structure. Excess energy is stored in batteries, which makes the facility completely self-sufficient. Unlike Solaris’s own 50kW photovoltaic system, the wind turbine is not tied into the national grid, and does not need to be, since it relies entirely on its own resources.

olaris Global Energy has broken into the export market and says its products are now “distributed regionally in more than a dozen countries” (not surprisingly, it expects to have a turnover of Bds$12 million “in the near future”). This is a clear indication that RE is gradually catching on in the Caribbean archipelago. McClean sees this as an inevitable development. “The high cost of fossil fuels, except in the case of Trinidad and Tobago, impacts the economies of those countries so harshly that it is a natural tendency to move in the direction of renewable energy,” he told this YEARBOOK. “The use of RE has a very beneficial influence on the economic viability of the hotel industry in the Caribbean.” He forecasts that solar water heaters “will be the most popular RE system in the region for some time”, but that, within 20 years, “solar electricity (photovoltaics) will take over, simply because of its far greater usefulness.”

Vincent McClean, Solaris Global Energy Ltd. Director and Chief Innovation Officer; Sen. Hon. Darcy Boyce, Minister of State in the Barbados Office of the Prime Minister; and Keith Scotland, Solaris Energy Ltd. Chairman discuss a solar water heating unit at Solaris Energy’s new factory gala opening on October 20, 2012.