ENERGY Caribbean Yearbook (2013-14)

The annual review of the Caribbean energy industry 

YEARBOOK 2013/14

YEARBOOK 2013/14 

Contents 

Caribbean energy map 2-3 

Section 1: the big issues 

World energy outlook 4 

Caricom energy policy 1 6 

Caricom energy policy 2 7 

Energy security 8 

The future of gas 9 

Caribbean gas market 10 

The green agenda 11 

Going international 12 

Alternative fuels 13 

Trinidad & Tobago’s oil revival 1 14 

Trinidad & Tobago’s oil revival 2 15 

Cross-border gas 16 

Deep water exploration 17 

Independents 18 

Climate change 19 

Local content 20 

Gas-based development 21 

Section 2: the energy producers 

Trinidad and Tobago 22 

Suriname 28 

Barbados 30 

Belize 32 

Jamaica 33 

Guyana 34 

Cuba 35 

Section 3: company profiles 

Atlantic 36 

CIBC FirstCaribbean International Bank 38 

Gasfin Development SA 40 

Methanex Trinidad 42 

The National Gas Company 44 

Repsol Trinidad & Tobago 46 

Solaris Energy 48 

Written by 

David Renwick 

Editor 

Jeremy Taylor 

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 

© Media & Editorial Projects Ltd. 2013 

All rights strictly reserved. 

ISSN 1811-1726 

energycaribbean YEARBOOK 2013/14 

1

Mississippi R. 

Houma 

New Orleans 

Tallahassee 

Orlando 

Daytona Beach 

USA 

Gulf 

Miami 

of 

Nassau 

Mexico 

Havana 

Bahamas 

Cuba 

Villahermosa 

Cayman Islands 

Jamaica 

Kingston 

Ha 

Port-au-Prin 

Flores 

Belize 

Tuxtla Gutierrez 

C a r i b 

Honduras 

b e a n 

S 

Caribbean 

energy map 

Nicaragua 

San José 

Maraca 

Oil or gas field 

Costa Rica 

Panama 

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 

C 

2

A t l a n t i c 

O c e a n 

Haiti 

ort-au-Prince 

Maracaibo 

Dominican 

Republic 

S e a 

Santo Domingo 

Aruba 

Oranjestad Curaçao 

Bonaire 

Willemstad 

Valencia 

San Juan 

Puerto Rico 

Caracas 

Virgin Islands 

Philipsburg St Maarten 

St Kitts & Nevis Antigua 

Basseterre St John 

Montserrat 

Pointe-á-Pitre 

Guadeloupe 

Roseau Dominica 

Fort-de-France Martinique 

Castries 

St Lucia 

St Vincent & 

the Grenadines 

Barbados 

Kingstown Bridgetown 

St George’s 

Grenada 

Scarborough Tobago 

Port of Spain 

Trinidad 

N 

Venezuela 

Georgetown 

Colombia 

Guyana 

Paramaribo 

Cayenne 

Suriname 

French 

Guiana 

energycaribbean YEARBOOK 2013/14 3

Energy 

issues 

world energy outlook 

Oil price will stay high 

Companie 

In the Caribbean, the international energy outlook is a good deal brighter for 

Countries 

supply challenge. LNG projects these days are notoriously difficult to deliver.” With 

4 

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 

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. 

The price of oil is likely to stay within the $95-100 

range, well above the cost of production of any 

reasonably efficient company 

Another 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 

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

appealing strategy. 

issues 

One 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 

Compani 

North America, electric utilities will ask themselves: 

why convert to renewables? 

Countries 


5

caricom energy policy 1 

Energy 

issues 

The Caribbean’s 

nightmare import bill 

Except 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 

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

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 Field- 

Ridley’s figures. After a down-payment 

of part of the commercial price would 

be made, buyers would pay the balance 

over several years. 

Companie 

Countries 

Caricom’s energy-importing countries 

Despite PetroCaribe, when the price 

of oil soared to $147 a barrel in 2008, 

“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. 

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. 

The 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 40- 

60% 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. 

6

Energy 

caricom energy policy 2 

issues 

Is the Caribbean serious 

about renewable energy? 

The 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 

Compani 

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. 

Countries 

Even geothermal-fired electricity 

Most 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. 

exchanged between two members 

could be regarded as a national source. 

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.” 

The 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.” 

The Caricom Energy Policy focuses on increasing 

renewable energy while simultaneously pursuing 

efficiency 

Wigton wind farm, Jamaica (courtesy pcj.com) 


7

Energy 

issues 

energy security 

A price you can’t afford 

Energy 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.” 

Supplying 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. 

Companie 

“The other islands could always have 

relied on Trinidad for oil – even when 

they did not pay their bills” 

Fuel 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.” 

Countries 

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.” 

Caricom electricity prices 

Selected countries 

(US$ per Kwh, 2012) 

Antigua 0.38 

St Vincent 0.36 

Barbados 0.36 

Grenada 0.35 

St Kitts/Nevis 0.34 

Guyana 0.34 

Jamaica 0.32 

Trinidad and Tobago 0.06 

Source: Energy Dynamics 

8

Energy 

the future of gas 

issues 

Regional policy 

undervalues gas 

Many, 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 

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 

have traditionally used. But the Caricom 

Compani 

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.” 

That 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. 

Countries 

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 

derived from natural gas, with 2% from RE, with oil accounting 

for the remaining 93%. 

Gas 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. CO 2 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. 

Potential gas demand 

Power generation capacity (peak demand) in line 

for conversion to gas 

Antigua 

Bahamas 

Grenada 

Guyana 

Jamaica 

St Lucia 

St Vincent 

Suriname 

Source: Caribbean Energy Policy, 2013 

51MW 

308MW 

30.5 MW 

94MW 

644 MW 

55.9 MW 

24.5 MW 

145 MW 


9

caribbean gas market 

Energy 

issues 

TT must get moving 

Is 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) 

Companie 

2020, so Trinidad and Tobago still has the 

Federal Energy Regulatory Commission. 

Gasfin does not expect to be ready to 

export LNG from the US much before 

opportunity to get in first and capture 

the market before Gasfin Development 

USA decides to target that customer 

base. 

One 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. 

Countries 

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. 

La 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. 

Roland Fisher (courtesy Gasfin) 

10

Energy 

issues 

the green agenda 

It will take a long time to 

replace fossil fuels 

The “green energy movement” 

is slowly gaining momentum 

in the Caribbean, reflected 

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 

in the growing enthusiasm 

Compani 

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. 

Gas, 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.” 

Countries 

The policy document urges Caricom 

members to “satisfy their demand 

for natural gas from the resources 

Roger Salloum (courtesy Green Building Council) 

“Fossil fuels will still account for 80-85% of 

overall world energy consumption 

in 2030” 

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. 

Other initiatives to move the “green 

agenda” forward are slowly 

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. 


11

Energy 

issues 

going international 

Can state energy companies 

make the grade? 

Almost 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. 

The 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 

Companie 

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. 

Countries 

West 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). 

12

Energy 

alternative fuels 

issues 

Fuel switching is not 

catching on 

Only Trinidad and Tobago, 

and to some extent 

Jamaica, which has 

experimented with an 

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 

E10 (ethanol) mixture at 

Compani 

(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. 

Countries 

In other words, the adoption of nonconventional 

transport fuels has a very 

long way to go in Caricom. 

While 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 200- 

250 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. 

Hybrid car donated to the Ministry of Energy 

It 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. 


13

TT oil revival 1 

Energy 

issues 

After three decades of 

decline ... 

Trinidad 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. 

One 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, 

Companie 

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 

Countries 

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 

Galeota platform (courtesy Petrotrin) 

b/d in 2012, compared with 21,543 b/d 

from onshore. 

In 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. 

14

Energy 

tt oil revival 2 

issues 

How to increase oil 

production 

What 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? 

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 

The obvious answer is new discoveries. 

Compani 

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. 

Exploratory 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 

Countries 

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 

The energy ministry says it will 

offer three land blocks for 

exploration this year 

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. 

New 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. 


15

cross-border gas 

Energy 

issues 

Venezuela lethargy keeps 

gas stranded 

The 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. 

Trinidad 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 

Companie 

“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, 

Countries 

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. 

As 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. 

16

Energy 

issues 

Deep water exploration 

The last real frontier? 

Deep 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 

The ministry has bent over backwards 

to make deep water activity 

economically attractive, which it has 

not been in the past 

frontier for substantial hydrocarbon discovery 

Compani 

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. 

While 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 

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”. 

Countries 

The 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 

“BP and BHP Billiton, two long-established 

players in the country, stand 

poised to take us into a period of 

exciting deep water exploration” 

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.” 


17

independents 

Small 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. 

18 

Energy 

issues 

A key contribution to 

oil revival 

Independents could be 

pioneers in the application 

of carbon dioxide 

(co2) injection for enhanced 

oil recovery 

There are about 17 independents 

active in the local petroleum sector 

today, occupying different niches. Some 

are lease operatorships (in 1989 Trintopec 

Companie 

independent of all, straddles the whole 

Countries 

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 

spectrum, being simultaneously a lease 

operator, farm-out operator and joint 

venturer. 

All 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 (CO 2 ) injection for enhanced oil 

recovery. 

Minister Ramnarine has mandated 

the National Gas Company to examine 

the feasibility of a CO 2 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. 

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 

climate change 

issues 

What should the Caribbean do? 

Caricom’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 

(CO 2 ) 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 CO 2 into the 

Compani 

atmosphere every year, China being the worst offender with 

10 billion. The United States, the second worst offender, has 

actually been lowering its CO 2 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. 

The 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. 

Countries 

and Tobago’s Institute of Marine Affairs is 

Trinidad developing a vulnerability and risk agreement for 

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.” 

Contribution to climate 

change 

Trinidad and Tobago (2009) 

• CO 2 emissions per capita 

• CO 2 emissions per unit of GDP 

• Total CO 2 emissions 

• Breakdown: 

40 tonnes per person* 

1.9 kg per dollar* 

52 million tonnes** 

Petrochemical plants 58% Power generation 23% 

Landfill 7% Transport 6% 

Process emissions (oil & gas) 3% Agriculture 2% 

Domestic cooking 1% 

* second highest in the world that year 

** 54th highest in the world that year 

Source: Dr Donnie Boodlal, University of Trinidad and Tobago 


19

local content 

Successive 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. 

Legislation 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 

20 

Energy 

issues 

Government may prescribe 

level of local input 

Companie 

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 

Countries 

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.” 

The 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

Energy 

GAS-BASED DEVELOPMENT 

issues 

Will there be enough gas 

for everyone? 

Trinidad 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. 

Compani 

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: 

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 

Countries 

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 

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. 

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. 

One 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. 


21

Countries 

trinidad and tobago 

A year of heavy drilling 

In 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. 

Drilling in Fyzabad (courtesy Petrotrin) 

• 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. 

Besides 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. 

22

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 


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 



2007 121,754 

2008 114,634 

2009 107,169 

2010 98,246 

2011 91,919 

2012 81,735 

ENERGY SECTOR 

Share of GDP 45.2% (2011) 

of which 

Exploration and production 19.2% 

Refining (inc. LNG) 7.6% 

Petrochemicals 12.7% 

Others (energy services, etc) 5.7% 

Share of government revenue 57.5% (2011) 

of which 

Oil/gas exploration and production 47.5% 

Other taxes (royalties, oil impost, &c) 10.0% 

Share of merchandise exports receipts 85.4% (2009) 

of which 

Extracted (crude oil) 12.9% 

Refined (inc. LNG, natural gas liquids) 62.9% 

Processed (inc. petrochemicals) 9.6% 

Share of total employment 3% (2011) 

Share of bank credit (2010) 

Loans and advances 

TT$1.4 billion 

Percentage of total 3.1% 

ENERGY RESERVES 

Oil (2007) 

Proven 

Probable 

Possible 

Natural gas (2011) 

Proven 

Probable 

Possible 

Unrisked exploratory resources 

317.9 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 

77% (capacity 165,000 b/d) 

Natural gas production 

4.3 billion cubic feet daily (bn cfd) 

Natural gas sales 

4.0 bn cfd 

of which petrochemicals 

1.1 bn cfd 

Electricity generation 

293 million cubic feet daily (mmcfd) 

LNG 

2.3 bn cfd 

Natural gas liquids production 17.2 million barrels (mm b) 

Exports 

16.9 mm b 

Ammonia production 6.2 million tonnes (mm t) 

Exports 

5.9 mm t 

Methanol production 

5.9 mm t 

Exports 

5.9 mm t 

Sources: Central Bank Annual Economic Survey (2011), MEEA Draft Green Paper on energy 

policy (unpublished), ENERGY Caribbean archives 


23

OPEN 

0 500,000 

1,000,000 

2,000,000 

ST VINCENT 

BEQUIA 

CANOUAN 

UNION 

MAYREAU 

1,500,000 

CARRIACOU 

GRENADA 

TTDAA 30 

89879 Ha 

OPEN 

TTDAA 31 

94092 Ha 

OPEN 

TTDAA 32 

113043 Ha 

OPEN 

-2000 

TTDAA 24 

112042 Ha 

OPEN 

TTDAA 25 

100086 Ha 

OPEN 

TTDAA 26 

100086 Ha 

OPEN 

TTDAA 27 

100086 Ha 

OPEN 

TTDAA 28 

101609 Ha 

BHP Billiton Petroleum Ltd 

1,000,000 

-1000 

BLOCK 21 

132015 Ha 

OPEN 

OPEN 

30783 Ha 

-400 

BLOCK 22 

CENTRICA / PETROTRIN 

BLOCK 23(a) 

259908 Ha 

BPEOC 

OPEN 

44254 Ha 

TRINIDAD & TOBAGO & VENEZUELA 

NCMA 2 

101,931.8 Ha 

NIKO RESOURCES (CARIBBEAN) LIMITED / RWE Dea AG/ 

PETROTRIN 

NCMA 4 

NCMA 1 

BGTT /CENTRICA / 

1 

EMI 

182,946.2 Ha 

CENTRICA ENERGY 

Scarborough 

NCMA 3 NCMA 5 

210,622.5 Ha 

231,098.8 Ha 

OPEN 

NIKO RESOURCES/ 

PETROTRIN 

TOBAGO 

-400 

-1000 

BLOCK 23(b) 

257920 Ha 

OPEN 

BLOCK 24 

340114 Ha 

OPEN 

500,000 

VENEZUELA 

BLOCK 

1(a) 

INTERNATIONAL BOUNDARY 

CENTRICA / 

PETROTRIN 

TRINMAR 

LINE BETWEEN 

PETROTRIN 

20 579 Ha 

4 

OPEN 

3 

BLOCK 1(b) 

CENTRICA / 

PETROTRIN 

BLOCK 1(b) 

5 

4 

2 

Port of Spain 

OPEN 

TRINIDAD 

PAREX / VOYAGER / PETROTRIN 

San 

Fernando 

CENTRAL 

BLOCK 

CENTRAL RANGE 

BLOCK 

BGTT 

8 

8 

8 

8 

TNA 

BLOCK 2(ab) 

133,504 Ha 

OPEN 

9 

(B) 

10 

10 

(A) 

11 

OPEN 

40048 Ha 

12 

bpTT/ REPSOL 

BLOCK 3(a) 

13 

bpTT/ REPSOL 

14 

OPEN 

74345 Ha 

OPEN 

5736 

Ha 

OPEN 


OPEN 

74345 Ha 

BLOCK 3(b) 

64513 Ha 

BLOCK 4(a) 

EOG RESOURCES 

PRIMERA 

CHEVRON 

6(b) 

OPEN 

16 17 

BGTT / CHEVRON 

BLOCK 4 (b) 

75328 Ha 

NIKO RESOURCES 

(CARIBBEAN) LIMITED 

BLOCK 

5(c) 

BGTT 

SONDE 

RESOURCES 

CORP 

BLOCK 5 (d) 

68420 Ha 

BLOCK 25(a) 

138860 Ha 

BG 

INTERNATIONAL 

Plc 

OPEN 

BLOCK 25(b) 

139129 Ha 

OPEN 

BLOCK 26 

119569 Ha 

OPEN 

BLOCK 27 

117915 Ha 

OPEN 

6 

7 

SOUTH MARINE 

52384 Ha 

OPEN 

NIKO 

VOYAGER ENERGY 

(TRINIDAD) LIMITED 

PETROTRIN 

bpTT/ REPSOL 

NGC/PETROTRIN 15 

EOG RESOURCES 

bpTT/ REPSOL 

BLOCK 6(d) 

BGTT / 

CHEVRON 

18 

LOWER REVERSE 'L' 

36378 Ha 

0 

VENEZUELA 

OPEN 

0 500,000 

1,000,000 

BLOCKS 2010/2011 DEEP WATER BID ROUND 

BLOCKS 2012 DEEP WATER BID ROUND 

BLOCKS 2013 DEEP WATER BID ROUND 

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. 

24

1,500,000 

2,000,000 

2,000,000 

TTDAA 29 

100195 Ha 


Block BLOCK OPERATOR LICENSEE 

BARBADOS 1 Block_9 BGTT PETROTRIN 

2 EAST_BRIGHTON_A SOOGL SOOGL 65%_PRIMERA 35% 

EAST BRIGHTON B SOOGL SOOGL 45.5%/ PETROTRIN 30%/ PRIMERA 24.5% 

3 BRIGHTON MARINE TRINITY EXPL. AND PROD. TRINITY EXPLORATION AND PRODUCTION / PETROTRIN 

4 POINT LIGOURE TRINITY EXPL. AND PROD. TRINITY EXPLORATION AND PRODUCTION / PETROTRIN 

5 SOUTH WEST PENINSULA TED TED / PETROTRIN 

6 ISLOTE BAY TED TED 

7 ERIN BAY TED TED 

8 Area_b PETROTRIN PETROTRIN 

9 MAYARO_GUAYAGUAYARE BAY NIKO RESOURCES NIKO RESOURCES / PETROTRIN 

10 GALEOTA TRINITY EXPL. AND PROD. TRINITY EXPLORATION AND PRODUCTION / PETROTRIN 

11 GALEOTA RIDGE MORAVEN MORAVEN 

12 2c BHP BHP 45%/ TOTAL 30%/CHAOYANG (CNOOC 12.5%, SINOPEC 12.5%) 

13 3a BHP BHP 25.5%/KERR MCGEE 25.5%/CHAOYANG(CNOOC 12.75%, 

SINOPEC 12.75%)/PETROTRIN 15%/TOTAL 8.5% 

14 MODIFIED U (a) EOG EOG 

15 MODIFIED U (b) EOG EOG 

16 BLOCK E BGTT BGTT/CHEVRON 

17 BLOCK 5(a) BGTT BGTT/CHEVRON 

18 BLOCK 5(b) bpTT bpTT/REPSOL 

19 NORTH MARINE PETROTRIN PETROTRIN 

-2000 

-3000 

-4000 

1,500,000 

1,000,000 

TTDAA 14 

99808 Ha 

BPEOC 

TTDAA 15 

98632 Ha 

OPEN 

TTDAA 16 

99336 Ha 

OPEN 

TTDAA 11 

100150 Ha 

OPEN 

TTDAA 12 

100057 Ha 

OPEN 

TTDAA 13 

100052 Ha 

OPEN 

TTDAA 17 

101198 Ha 

OPEN 

TTDAA 20 

101537 Ha 

TTDAA 8 

99809 Ha 

OPEN 

TTDAA 9 

99349 Ha 

OPEN 

TTDAA 10 

99337 Ha 

OPEN 

TTDAA 18 

101153 Ha 

OPEN 

OPEN 

TTDAA 22 

105227 Ha 

TTDAA 23 

91142 Ha 

OPEN 

TTDAA 4 

100185 Ha 

OPEN 

TTDAA 6 

99747 Ha 


TTDAA 7 

99783 Ha 

OPEN 

TTDAA 19 

102917 Ha 

OPEN 

TTDAA 21 

101194 Ha 

OPEN 

500,000 

TTDAA 2 

104755 Ha 

OPEN 

TTDAA 5 

109559 Ha 


TTDAA 3 

109722 Ha 

OPEN 

TTDAA 1 


OPEN 

Scale 

10 

0 

10 

20 

25 Ml. 

10 

0 10 

20 

30 

40 Km. 

0 

1,500,000 Lk. 

2,000,000 Lk. 

2,500,000 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 25

trinidad and tobago 

Energy timeline 

Countries 

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 

1908 Commercial oil production begins at La Brea 

1910 First export shipment of crude oil 

1911 Small refinery build at Brighton 

1917 Refinery built at Pointe-à-Pierre 

1930 First crude oil imports for local refining 

1933 First enhanced oil recovery at Forest Reserve 

1937 Labour protests 

Development 

1953 First commercial use of gas, for power generation 

1953 Marine exploration off southeast coast by Dominion Oil 

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 

1956 Texaco buys Pointe-à-Pierre refinery from Trinidad Leaseholds 

1959 

WR Grace subsidiary Federation Chemicals uses BP gas for 

petrochemical production 

1961 First exploration off Trinidad’s east coast 

1967 Peak oil production on land – 111,883 b/d 

The gas age 

1968 e east coast by Amoco 

1968 Peak oil production off the west coast – 76,948 b/d 

1968 First seismic survey off the north coast 

1969 Amoco finds commercial quantities of oil off the east coast 

1969 Government takes over BP’s land fields with Tesoro 

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 

1974 

First large-scale commercial gas production, from Amoco’s 

Teak field off the east coast; reserves estimated at 1.1 trillion 

cubic feet 

Expansion 

Trintoc created as the government’s first upstream and refining 

1974 company after purchase of Shell’s oilfields and Point Fortin 

refinery 

1974 16-inch, 24-mile pipeline brings gas ashore from east coast fields 

1975 National Gas Company (NGC) established 

1977 

Gas-based industrial development begins at Point Lisas with 

Tringen ammonia plant 

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 

1978 Peak national oil production – 240,000 b/d 

1978 First marine platforms built locally and installed off southeast coast 

Heavy industry 

1980 Government-owned ISCOTT steel plant established at Point Lisas 

1981 FERTRIN ammonia plant at Point Lisas (government holds 51%) 

1983 Government establishes urea plant at Point Lisas 

1983 Amoco’s giant Cassia gas field comes on stream 

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) 

1985 Government buys Tesoro, which becomes Trintopec 

1985 

Government acquires Texaco’s land fields and Pointe-à-Pierre 

refinery, amalgamating operations with Trintoc 

1986 First compressed natural gas available as motor fuel 

1987 Last well drilled in the Northern Basin to 7,700 feet in Claxton Bay 

1989 

1989 

1990 

Rationalisation 

Lease operatorship/farmout programme introduced by 

Trintopec 

British Gas takes over Tenneco’s international assets and enters 

Trinidad and Tobago 

Government-owned Trintomar starts gas production from 

Pelican field in SECC 

26

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 

1993 

Petrotrin created to bring all government upstream assets 

under one company 

1994 

First oil company listed on Trinidad and Tobago stock 

exchange (Moraven Holdings) 

1994 

Amoco drills first horizontal well off southeast coast – 2,477 

feet through 40-foot thick sands at 8,000 feet depth 

1996 

BG/Texaco begin supplying gas to NGC from east coast 

Dolphin field 

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 

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 

2002 

BPTT installs world’s largest offshore gas processing unit off 

southeast coas 

2003 NGC’s profit crosses TT$1 billion 

2003 Natural gas production off north coast by BG and partners 

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 

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 

BPTT’s Ibis Deep, the deepest vertical well ever sunk in 

2006 Trinidad and Tobago, reaches 19,068 feet in SECC block but 

fails to find hydrocarbons 

2006 

Government stiffens PSC terms to add a direct tax element, 

which does not go down well with oil companies 

2006 Unsuccessful eight-block ultra-deepwater auction 

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 

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 

Petrotrin refinery upgrade; revised fiscal arrangements; new 

2010 exploration block auction; Tobago supplied with gas directly from 

Angostura field; concern over continued decline in oil production 

Eleven blocks offered in deep water auction, only two bids 

2011 successful – for 23a and TTDAA 14, both to BP Exploration 

Operating Co. 

Proven non-associated natural gas reserves downgraded to 

2011 13.46 tcf by Ryder Scott consultants, the seventh straight year 

of decline 

2011 

Sales missions to Ghana, Suriname and Brazil by energy 

service companies breaking into international markets 

2012 

First PSCs for ultra-deep blocks signed with BP Exploration 

Operating Co. for 23a and TTDAA 14 from 2010 bid round 

2012 PSC for block 5d signed with BG Group, 5 tcf of gas resources predicted 

2012 

Six blocks offered in 2012 deep water round; BHP Billiton 

awarded four of them – TTDAA 5-6, 28-29 

Centrica Energy continues negotiation with Puerto Rico 

2012 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. 


27

Countries 

suriname 

Keen interest in the 

deepwater blocks 

Suriname 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.” 

28

135 P0COAST 

oly line 

135 P0COAST 

oly line 

135 P0COAST 

oly line 

135 P0COAST oly line 


135 P0COAST 

oly line 

135 P0COAST 

oly line 


135 10 P0COAST 

ol 

y lin 

e 

135 P0COAST 

oly line 


135 P0COAST 

P0COAST 135 oly linle 

ine 

135 P0COAST 

oly l i ne 

135 P0COAST 

oly line 


P0COAST 

135 oly l ine 

135 P0COAST oly n135 P0COAST 

0eol 

y li 

n 

e 


135 P0COAST 

oly line 

135 P0COAST 

oly line 

135 P0COAST 

oly line 

P0COAST 

135 oly line 

135 0P0COAST 

oly line 

135 P0COAST 

oly line 

135 P0COAST 

oly line 

P0COAST 

135 oly line 

P0COAST 

135 oly line 

P0COAST 

135 oly line 

135 P0COAST 

oly line 

P0COAST 135 oly line 

135 P0COAST 

oly line 

P0COAST 135 oly line 

32 

35 

Tullow Oil 

46 

55 

Block 47 

Kosmos Energy 

Block 42 

Murphy Oil 

Block 48 

56 

50 

Apache 

Block 53 

Block 45 

Kosmos Energy 

54 

57 

1 

Nickerie 

Block 

43 

Suriname-Guyana Maritime Border 

51 

2 3 

Coronie Block 

44 

Calcutta Block 

Block 52 

Petronas 

Block 31 

Inpex 

13 14 15 

4 5 

6 7 

Tambaredjo Block 

Uitkijk Block 

Weg naar Zee 

Block 

Commewijne Block 

37 

36 

Suriname-French Guiana Maritime Border 

0 50 100 150 km 

Legend: 

Blocks under contract Blocks Bid Round 2013 

(28/01/2013 - 26/07/2013) 

Blocks not on offer 

Staatsolie operated blocks 

Staatsolie Oil Fields 

Suriname block map (courtesy Staatsolie) 

April 2013 

Zaedyus 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 

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. 


29

Countries 

barbados 

Getting to grips with the 

offshore again 

Andre Braithwaite (courtesy Andre Braithwaite) 

The 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. 

Barbados’s minuscule 900 b/d of oil is 

derived from onshore fields, worked 

by the Barbados National Oil Company 

(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.” 

BHP 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 10,000- 

15,000 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. 

30

Barbados Block Map (courtesy Barbados Division of Energy) 


31

Countries 

belize 

Plenty of setbacks – 

but not fatal 

Belize became a Caricom oil 

producer in 2005 after 50 years 

of trying, and was doing quite 

well until it suffered a number of 

body blows that will make 2013 

a difficult year for the industry. 

The first blow is that production from 

its two fields, Spanish Lookout and Never 

Delay in western Belize, has plummeted. 

Belize Natural Energy (BNEL) identified 

retrievable oil reserves with its first 

exploratory well eight years ago, and 

output rose rapidly to over 5,000 b/d. But 

it has since declined to about 2,550 b/d, 

not only depriving the government of 

much-needed revenue but reducing the 

associated gas and liquefied petroleum gas 

available for the local market. 

The second blow is that other 

explorationists have not been able to replicate BNEL’s initial 

success. New World Oil and Gas was forced to plug and 

abandon its Rio Bravo 1 exploratory well in northwestern 

Belize after failing to find oil, on the heels of a similar failure 

with its Blue Creek 1 and 2 wells. The company is putting 

a brave face on it, and pledges to return to the Blue Creek 

area in due course, because “with multiple prospects already 

identified, we believe it is only a matter of time before we 

locate a trap of significant size.” 

The third blow has the biggest disruptive potential for the 

short to medium term: the Belize Supreme Court ruled 

that all drilling contracts for offshore exploration issued by 

the government between 2004 and 2007 are “null and void.” 

It decided that proper environmental impact assessments 

had not been carried out before the signing of contracts, as 

required by law. It also declared that the companies involved, 

which include Island Oil Belize, Tropical Energy, Petro Belize, 

Princess Petroleum, Providence 

Energy and Sol Oil, “had failed to 

prove an ability to contribute the 

necessary funds, assets, machinery, 

equipment, tools and technical 

Hon. Senator Joy Grant (courtesy 

www.belize.gov.bz) 

expertise to drill safely.” 

The suit was brought by two 

environmental organisations, Citizens 

Organised for Liberty through Action and 

the Belize Coalition to save our Natural 

Heritage. The latter has been agitating for 

some time to stop offshore exploration 

following BP’s Macondo well blowout in 

the Gulf of Mexico in 2010. 

The government responded by offering 

a referendum on the matter, but that has 

been on hold for some time. An appeal 

against the judgment will probably be 

made but, in the meantime, Belize’s 

offshore acreage is out of bounds for 

exploration, a fact which will hardly 

encourage international oil companies to 

look seriously at offshore prospects. 

The bidding rounds which the 

government says it wants to introduce will have to be confined 

to the onshore for the foreseeable future. 

But the future for hydrocarbons in Belize is not entirely bleak, 

since companies which already hold onshore licences will 

want to get started on exploration. These include Marenco, US 

Capital Energy, Treaty Energy and the French firm Parenco. 

Belize’s minister of energy, A. Joy Grant, is prepared to 

predict “a spate of exploratory drilling over the next few years, 

based on what the companies see as promising potential in 

their blocks.” 

Belize is committed to renewable energy, as a participant in 

the Caricom Energy Plan. 

Minister Grant contends that already generates more 

electricity from renewable resources – 68% – than any other 

Caricom member, thanks to the wide use of sugar cane 

residue, bagasse, to heat boilers for the industry’s own power 

needs, the surplus being passed on to the national grid. 

Belize generates more electricity from renewable 

resources – 68% – than any other Caricom member 

32

Countries 

jamaica 

Restarting the 

exploration drive 

Jamaica 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. 

Minister 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. 

“I am not going to allow any company to hold on to 

any licence without living up to its obligations” 

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. 

Paulwell 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. 


33

Countries 

guyana 

Could luck change with the 

Stabroek block? 

If 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, 

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. 

The 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 

Most hopes now lie with ExxonMobil/Shell, 

whose Stabroek block is by far the largest piece of 

offshore acreage Guyana has licensed 

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. 

Most 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. 

34

Countries 

cuba 

Deep water seems to be dry 

Cuba 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. 

However, 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. 

So 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 CO 2 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. 


35

Companies 

atlantic 

A global benchmark 

for LNG 

Countries 

In 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. 

Cost 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 

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.” 

Darlow 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 

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

– “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.” 

36

Companies 

CIBC firstcaribbean international bank 

FCIB aspires to be the 

region’s energy bank 

Countries 

CIBC 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. 

As 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” 

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. 

Ahamad 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. 

38

Innovative Financing and Hedging Solutions 

for the Energy and Utilities Sector 

At CIBC FirstCaribbean our dedicated team of investment banking professionals is committed to delivering the best 

financing and hedging solutions to meet the needs of the Energy and Utilities sector. 

We provide you with one-on-one service that addresses your business needs with innovative financing and hedging 

solutions to complement your business strategy. 

Benefits of Working with 

Our Investment Banking Team: 

• Market expertise with regional and international 

links with access to a full range of financial and 

advisory services. 

• A leading Investment Banking presence in the 

Caribbean region providing project financing to 

the energy and utilities sector. 

• A world-class transaction execution process with 

significant experience and distribution capability 

throughout the English and Dutch speaking 

Caribbean. 

• A solid group balance sheet and part of the CIBC 

group which has an A+/Stable credit rating from 

the Standard & Poor’s credit rating agency. 

For more information on how we can assist you please contact: 

INVESTMENT BANKING 

ENERGY & UTILITIES TEAM 

Sharaz Ahamad 

Director, Origination and 

Capital Markets Products 

Southern Caribbean 

Tel: 1 868 822-5071 

Mobile: 1 868 779-2994 

E-mail: sharaz.ahamad@cibcfcib.com 

Gillian Charles-Gollop 

Associate Director, Sector Specialist 

Energy & Utilities 

Tel: 1 246 467-8723 

Mobile: 1 246 232-8700 

E-mail: gillian.gollop@cibcfcib.com 

CORPORATE & INVESTMENT BANKING, 

TRINIDAD & TOBAGO 

Duane Hinkson 

Managing Director, 

Trinidad & Tobago Operations 

Tel: 1 868 822-5080 

E-mail: duane.hinkson@cibcfcib.com 

Anthony Seeraj 

Deputy Managing Director, Corporate 

& Investment Banking 

Tel: 1 868 628-4685 

E-mail: anthony.seeraj@cibcfcib.com 

HEDGING 

Winville Larcher 

Director, Client Solutions Group 

Tel: 1 246 367-2133 

E-mail: winville.larcher@cibcfcib.com 

The CIBC logo and For What Matters are trademarks of Canadian Imperial 

Bank of Commerce, used by FirstCaribbean International Bank under license.

Companies 

gasfin development sa 

Small LNG plant can 

transform TT gas exports 

Countries 

Gasfin 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 

The 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.” 

Trinidad 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. 

40

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 

At every step...in every size...on land or sea...across the globe

Companies 

methanex trinidad 

Happy with TT operation – 

but no expansion 

Countries 

Methanex 

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. 

Methanex’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” 

John Floren (courtesy Methanex) 

plant. All these factors may have 

affected thoughts of expansion. 

But 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.” 

42

Companies 

National gas company (NGC) 

NGC is set to expand 

Trinidad and Tobago’s National Gas Company (NGC) 

Countries 

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.” 

In 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.” 

Anand Ragbir (courtesy NGC) 

44

Companies 

repsol trinidad and tobago 

Repsol slims itself down 

Repsol finds itself a much smaller player in the 

Countries 

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. 

However, 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.” 

Repsol 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). 

46

Countries 

Solaris Energy is the result of an adroit move by a 

48 

Companies 

solaris energy 

Oil producer jumps 

into renewables 

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. 

Barbados 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 

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. 

Solaris 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.

ENERGY Caribbean Yearbook (2013-14)

Create successful ePaper yourself

Delete template?

Save as template?