ENERGY Caribbean newsletter (April 2014 • Issue no. 72)
The final edition of the ENERGY Caribbean newsletter
The final edition of the ENERGY Caribbean newsletter
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<strong>April</strong> <strong>2014</strong> <strong>•</strong> <strong>Issue</strong> <strong>no</strong>. <strong>72</strong><br />
WHAT’S INSIDE<br />
3 PPGPL suffers setbacks in<br />
overseas investment<br />
4 Staatsolie expects upsurge<br />
in exploration<br />
9 BHP Billiton to decide on<br />
block 3a this year<br />
NEWSLETTER<br />
10-11 The best ways to get gas<br />
to <strong>Caribbean</strong> markets<br />
CARIBBEAN LNG<br />
New LNG venture<br />
promises electricity<br />
price relief<br />
Trinidad plant will target Martinique and Guadeloupe first<br />
Roland Fisher<br />
Courtesy Roland Fisher<br />
<strong>Caribbean</strong> electric utilities desperate<br />
for deliverance from high fuel oil<br />
and diesel prices may finally have<br />
their prayers answered.<br />
Roland Fisher, CEO of Gasfin<br />
Development SA, which has been<br />
given the green light by the Trinidad<br />
and Tobago government to establish a<br />
500,000 tonne-a-year LNG plant at La<br />
Brea, says he is confident that <strong>Caribbean</strong><br />
LNG, as the La Brea plant will be k<strong>no</strong>wn,<br />
should be able to deliver gas at around<br />
US$14-15 per mmbtu, or at least 20%<br />
below the current cost of fuel oil in<br />
mmbtu terms.<br />
That could mean a substantial<br />
reduction in the current cost of electricity<br />
to regional consumers, who currently<br />
pay prices ranging from US$0.39 per<br />
kilowatt hour in St Vincent to $0.22 per<br />
kwh in Aruba (compare $0.06 in Trinidad<br />
and Tobago).<br />
Gasfin Development is a Luxembourgregistered,<br />
UK-headquartered company,<br />
but the state-owned National Gas<br />
Company (NGC) will be an equal partner<br />
in <strong>Caribbean</strong> LNG and will be directly<br />
involved in part ownership of the first<br />
train (and probably a second in time),<br />
as well as a likely equity partner in the<br />
two floating, storage and regasification<br />
units (FSRUs) to be based in Martinique<br />
and Guadeloupe, the first customers the<br />
company is targeting.<br />
TGE Marine and TGE Gas<br />
Engineering, both Gasfin subsidiaries,<br />
will be designing and building these<br />
vessels as well as the carrier that will<br />
deliver the LNG from La Brea – and of<br />
course the LNG plant itself.<br />
Since LNG is being delivered FOB,<br />
Gasfin has <strong>no</strong> control over possible<br />
NGC partnership in the LNG carrier part<br />
of the supply chain unless, as Fisher<br />
explains, “we take the project on to<br />
being a deliverer of gas, rather than a<br />
seller of LNG. The buyer has to manage<br />
their own logistics.” The situation may<br />
change when <strong>Caribbean</strong> LNG begins to<br />
sell to the smaller Caricom states, which<br />
may <strong>no</strong>t be in a position to engage their<br />
own transport.<br />
Fisher has been wooing Électricité<br />
de France (EdF), the power producer<br />
in both Martinique and Guadeloupe,<br />
almost from the day he started selling<br />
his idea about the vast potential of the<br />
<strong>Caribbean</strong> gas trade to energy ministry<br />
officials, who were sceptical at first but<br />
eventually came around. The current<br />
minister, Kevin Ramnarine, became a<br />
convert and formally an<strong>no</strong>unced the<br />
go-ahead for the project at the Energy<br />
Chamber’s annual petroleum conference<br />
in early February. A project development<br />
agreement <strong>no</strong>w has to be worked out.<br />
New business<br />
Production of LNG under national<br />
and sympathetic foreign control opens<br />
the door to a host of new business<br />
possibilities.<br />
<strong>Caribbean</strong> LNG will be the conduit<br />
for the transfer of Trinidad gas to as<br />
many <strong>Caribbean</strong> markets as possible, to<br />
relieve them of crippling and potentially<br />
everlasting dependence on oil. As Fisher<br />
points out: “What we are really doing<br />
is supplying the infrastructure that will<br />
enable NGC gas to go to the region, and<br />
NGC has told us that’s what our job is,<br />
<strong>no</strong>t to sell their gas to the world.”<br />
<strong>Caribbean</strong> LNG could also do what<br />
the much bigger LNG company, Atlantic,<br />
has never contemplated: providing LNG<br />
to domestic Trinidad customers. “We are<br />
very serious that containers of LNG will<br />
be available for the Trinidad market,”<br />
Fisher says. “It will be a real opportunity<br />
for small industries, for [ to page 12 ]<br />
Energy <strong>Caribbean</strong> <strong>•</strong> <strong>April</strong> <strong>2014</strong> 1
PPGPL<br />
Unlucky in Africa, gas<br />
liquids company turns<br />
to Americas<br />
And seeks closer alignment with 90% owner NGC<br />
The Point Lisas-based gas liquids<br />
extractor and marketer Phoenix<br />
Park Gas Processors Ltd. (PPGPL)<br />
has <strong>no</strong>t been as successful as it hoped<br />
in its international outreach, part of the<br />
mandate given to it by the Trinidad and<br />
Tobago government.<br />
PPGPL is virtually a state company<br />
<strong>no</strong>w, being 90% owned by the National<br />
Gas Company (NGC), which is itself<br />
state-owned. “We have got to get aligned<br />
with NGC’s own strategies,” company<br />
president Eugene Tiah explained in<br />
an exclusive interview with <strong>ENERGY</strong><br />
<strong>Caribbean</strong>. “We need to get clear on what<br />
the overall strategy is for what is <strong>no</strong>w the<br />
NGC Group.”<br />
NGC has always owned 51% of<br />
PPGPL, and extended its holding by<br />
buying the 39% share previously held<br />
by the US’s Co<strong>no</strong>coPhillips. Even before<br />
that purchase, the two companies<br />
collaborated closely on international<br />
initiatives, jointly considering gasbased<br />
projects in Ghana, Tanzania and<br />
Equatorial Guinea, though <strong>no</strong>ne have so<br />
far come to fruition.<br />
The magazine of the<br />
<strong>Caribbean</strong> energy industry<br />
APRIL <strong>2014</strong> <strong>•</strong> <strong>Issue</strong> No. <strong>72</strong><br />
Subscriptions Department<br />
6 Prospect Avenue, Maraval, Port of Spain,<br />
Trinidad & Tobago<br />
Tel: (868) 622 3821, Fax: (868) 628 0639,<br />
e-mail: energy@meppublishers.com<br />
Writer David Renwick<br />
Editor Jeremy Taylor<br />
Layout Bridget van Dongen<br />
© <strong>2014</strong> Media & Editorial Projects Ltd.<br />
All rights reserved<br />
Africa<br />
A potential investment in gas gathering<br />
and processing facilities in Ghana, once<br />
viewed with great enthusiasm, was lost<br />
to China in 2010. The Ghana National<br />
Gas Company then issued a request for<br />
expressions of interest in operating and<br />
maintaining the plant, to which PPGPL<br />
responded. But Tiah says: “They then<br />
told us they had scrapped all of that.”<br />
PPGPL and NGC also examined a<br />
gas processing project in Nigeria, but<br />
“based on a rigorous review of risks and<br />
returns and other factors, both companies<br />
decided that the project should <strong>no</strong> longer<br />
be pursued.”<br />
In Tanzania, “we were looking at<br />
the feasibility of micro-LNG for power<br />
generation for mining facilities, and<br />
were getting aligned with an Australian<br />
company that wanted to do that.” But<br />
PPGPL soon realised that “it would have<br />
been an unbalanced sort of relationship:<br />
we wanted to bring to the table our<br />
expertise and k<strong>no</strong>wledge, but they<br />
seemingly preferred just money, with<br />
limited involvement.”<br />
Advertising<br />
Yuri Chin Choy,<br />
<strong>ENERGY</strong> <strong>Caribbean</strong> Sales Department<br />
6 Prospect Avenue, Maraval, Port of Spain,<br />
Trinidad & Tobago<br />
Tel: (868) 683 0832,<br />
e-mail: yuri@meppublishers.com<br />
<strong>ENERGY</strong> <strong>Caribbean</strong> is published six times a<br />
year, on February 1, <strong>April</strong> 1, June 1, August 1,<br />
October 1 and December 1.<br />
Subscriptions: Trinidad and Tobago TT$750<br />
per year (six issues), <strong>Caribbean</strong> US$125, Rest<br />
of the World US$150.<br />
For multiple copies please contact the<br />
Subscriptions Department.<br />
Nothing much has happened in<br />
Equatorial Guinea either. “An initial<br />
assessment visit was made to that country,<br />
which has a developing gas sector, to<br />
evaluate potential gas processing and<br />
related opportunities, and subsequently a<br />
country risk assessment was completed to<br />
guide pursuit of any future opportunities.”<br />
The Americas<br />
For a company operating against<br />
a background of “fewer growth<br />
opportunities locally and leaner gas<br />
supplies coming into the Point Lisas<br />
plant”, four unsuccessful attempts<br />
to spread itself abroad must be<br />
demoralising. Apparently undaunted,<br />
Tiah has switched PPGPL’s attention<br />
to the western hemisphere, targeting<br />
Colombia and Nova Scotia, Canada.<br />
In Colombia, the company is again<br />
looking at gas gathering and processing.<br />
“Colombia has both associated gas<br />
and some pure gas production – small<br />
pockets and small projects – but it is<br />
looking to gather and harness as much<br />
of the resource as they can for power<br />
generation. State company Ecopetrol and<br />
some associated companies have been<br />
asking for EOI for project development.”<br />
PPGPL complied but “the challenge with<br />
these things is that they issue a request<br />
today and they want a proposal next<br />
week.”<br />
The situation requires PPGPL to “have<br />
a presence in such countries”, and teams<br />
have been to Colombia, spending “a<br />
couple of weeks developing a network<br />
and relationships”, and to Nova Scotia,<br />
engaging with “some entrepreneurial<br />
types whose business idea is that there are<br />
big arbitrage opportunities for gas liquids<br />
from shale gas between North America<br />
and Europe and Asia, using terminalling<br />
assets presently under-utilised.” Tiah<br />
thinks this is an “interesting model<br />
because of the terminalling business and<br />
the marketing of natural gas liquids, both<br />
of which we are interested in, as well as<br />
the future potential for fractionation.”<br />
At home, one growth opportunity is<br />
a processing plant at Union industrial<br />
estate, La Brea, to capture the 300 million<br />
cubic feet a day (mmcfd) of gas that will<br />
be flowing through that estate before long.<br />
PPGPL invited expressions of interest<br />
for the provision of “standard design<br />
solutions”, and has been reviewing the<br />
responses.<br />
Energy <strong>Caribbean</strong> <strong>•</strong> <strong>April</strong> <strong>2014</strong> 3
SURINAME<br />
Major exploration<br />
programme is under way<br />
And the next round of bidding is in progress too<br />
Staatsolie, Suriname’s national<br />
petroleum company and only oil<br />
producer, confidently expects<br />
a<strong>no</strong>ther wave of offshore exploration<br />
after March 2015, when it will award<br />
yet more blocks based on the outcome<br />
of the “<strong>no</strong>mination” process <strong>no</strong>w under<br />
way.<br />
The company has adopted a new<br />
approach to acreage awards, which<br />
mimics what Trinidad and Tobago has<br />
done for some time in relation to the<br />
deep water: potential explorers indicate<br />
which open blocks specifically interest<br />
them, and that information is used to<br />
decide which ones will be offered for<br />
auction.<br />
Fifteen demarcated offshore blocks<br />
are available, their 1.2 million acres<br />
representing about 66% of the marine<br />
area under Suriname’s control, so<br />
the exploration potential is clearly<br />
substantial.<br />
So far, blocks <strong>no</strong>rthwest of Suriname’s<br />
coastline have proved of most interest<br />
to companies <strong>no</strong>w operating there,<br />
which leaves most of the 15 on the<br />
<strong>no</strong>rtheast of the marine area, abutting<br />
the delimitation line with French<br />
Guiana, open for bids. Staatsolie will be<br />
hoping that the offshore discoveries in<br />
that French department will be a spur to<br />
the <strong>no</strong>mination, and subsequent takeup,<br />
of acreage.<br />
More to come<br />
So far, the belief that the geology of<br />
AUCTION SCHEDULE<br />
February <strong>2014</strong><br />
March <strong>2014</strong><br />
June 1, <strong>2014</strong><br />
July <strong>2014</strong><br />
August <strong>2014</strong><br />
January 30, 2015<br />
March 2015<br />
4th quarter, 2015<br />
EXPLORATION<br />
Company Block Wells Timeframe<br />
Inpex 31 1 <strong>April</strong> 2015<br />
Kosmos/Chevron 42 1 tba<br />
Kosmos/Chevron 45 2 2015<br />
Tullow Oil 47 1 <strong>2014</strong> Q4–2015 Q1<br />
Murphy Oil 48 1 tba<br />
Petronas (Malaysia) 52 1 <strong>April</strong> 2015<br />
Apache/Kepsa 53 1 by <strong>April</strong> 2015<br />
Tullow Oil/Statoil (Norway) 54 tba tba<br />
the Guyana/Suriname/French Guiana<br />
basin mirrors that of west Africa, where<br />
Tullow Oil made its famous Jubilee<br />
discovery in Ghana, has been proved<br />
correct only in the case of French<br />
Guiana itself, with the Zaedyus find of<br />
about 840 million barrels in 2011.<br />
The four wells drilled in Suriname’s<br />
blocks 37 and 31 in 2011, by Murphy<br />
Oil and Japan’s Inpex respectively,<br />
were <strong>no</strong>t successful. Nor was recent<br />
exploration offshore Guyana.<br />
But the possibilities have <strong>no</strong>t been<br />
exhausted by any means, and there is an<br />
ongoing drilling programme by existing<br />
block holders in Suriname which will see<br />
extensive offshore exploration activity<br />
(see box). And there will be much more<br />
to come, towards 2017 and beyond.<br />
Nominations from companies for<br />
blocks of interest to them began in<br />
February. On the basis of US$50,000<br />
data packages, they will have until June<br />
1 to put forward their choices. Staatsolie<br />
Block <strong>no</strong>minations open<br />
Data packages<br />
Deadline for <strong>no</strong>minations<br />
Nominations evaluated<br />
Selected blocks an<strong>no</strong>unced; bids open<br />
Bids close<br />
Successful bidders an<strong>no</strong>unced<br />
Seismic acquisition begins<br />
requires companies to “briefly indicate<br />
the reasons” for their selections, but if<br />
a company declines to <strong>no</strong>minate, it can<br />
still bid in the subsequent auction.<br />
Process<br />
In July, Staatsolie will be evaluating<br />
the acreages <strong>no</strong>minated, including<br />
whatever leads/prospects may<br />
have been identified, and will assess<br />
companies according to their technical<br />
expertise, resource management record,<br />
and health, safety and environmental<br />
reputation.<br />
The selection of blocks for production<br />
sharing contracts will be governed by<br />
their commercial potential, strategic fit<br />
with Staatsolie’s vision, the information<br />
available, and the degree of interest that<br />
has been expressed.<br />
The blocks chosen for auction<br />
will be an<strong>no</strong>unced on August 1, and<br />
will be open for bids until January<br />
30, 2015. Successful bidders will be<br />
revealed in March 2015, and are likely<br />
to be companies that have offered a<br />
participating interest to Staatsolie,<br />
with maximum work obligations,<br />
which have a good operating record<br />
and demonstrate a sound grasp of the<br />
geology.<br />
Staatsolie expects the companies<br />
chosen to get moving on exploration<br />
activity quickly and begin seismic<br />
acquisition by as early as the fourth<br />
quarter of 2015.<br />
4
TRINIDAD & TOBAGO<br />
Major drilling to resume<br />
on land<br />
Twelve exploration wells planned for Rio Claro, Ortoire and St Mary’s<br />
Exploration activity on land in Trinidad should ramp up<br />
by late 2015, <strong>no</strong>w that the successful bidders for three<br />
blocks offered in 2013 have been an<strong>no</strong>unced.<br />
As formally confirmed by the ministry of energy and<br />
energy affairs in February, the 75,089-acre Rio Claro block<br />
in southeast Trinidad, which extends to the Atlantic Ocean,<br />
was awarded to Lease Operators (LOL); the 44,674-acre<br />
Ortoire block, which also abuts the Atlantic, to Canada’s<br />
Touchstone Exploration; and the 37,895-acre St Mary’s<br />
block, further west, to the Anglo-Australian firm Range<br />
Resources.<br />
These companies have committed to collectively<br />
acquiring 295 line km of 2D seismic and 60 sq km of 3D,<br />
and thereafter sinking 12 exploration wells, all at a cost<br />
of US$55 million. If they find commercial reservoirs and<br />
decide to develop them, a further US$945 million could be<br />
spent.<br />
The onshore therefore joins the current shallow water<br />
and deep water offshore exploration initiatives in one of the<br />
busiest periods of exploration activity in decades.<br />
Energy minister Kevin Ramnarine has been quick to<br />
point out that the land is <strong>no</strong>w bracketed with the offshore<br />
as a focus of exploration activity only because the ministry<br />
sanctioned the “first dedicated onshore bid round in 15<br />
years.”<br />
The energy ministry sanctioned the<br />
“first dedicated onshore bid round<br />
in 15 years”<br />
He also pointed out that all three blocks are next to and<br />
on trend with existing hydrocarbon sources, including<br />
the Barrackpore field (130 million barrels), Rock Dome/<br />
Catshill/Inniss (25-30 million barrels) and Carapal Ridge<br />
(20-500 million cubic feet of gas and condensate).<br />
Touchstone<br />
Touchstone Exploration, whose chair-man and CEO is<br />
Paul Baay, has wasted <strong>no</strong> time in moving to finalise the<br />
exploration and production licence for Ortoire, which was<br />
expected by early March.<br />
The company’s vice president for geosciences, James<br />
Shipka, sees Ortoire as “an incredible opportunity for<br />
Touchstone, as it is an extension of the well-k<strong>no</strong>wn<br />
southern basin and presents exploration and development<br />
opportunities in a number of different horizons. As with the<br />
company’s existing budget, the commitments associated<br />
with the bid are expected to be funded through future cash<br />
flow.”<br />
Jim Krissa, Touchstone’s Trinidad and Tobago country<br />
chairman, speaks of the “high impact potential” of Ortoire,<br />
which gives the company access to a significant amount of<br />
exploration acreage “that will be immediately integrated<br />
into our long-term operational plan in Trinidad and Tobago.”<br />
Krissa says that this additional acreage (Touchstone <strong>no</strong>w<br />
holds a total of 63,000 acres on land in Trinidad and 5,000<br />
acres nearshore in the Gulf of Paria) enables the company<br />
“to move forward as a leader in onshore exploration and<br />
development in Trinidad.”<br />
Range Resources<br />
Range Resources seems happy to have acquired St Mary’s,<br />
since it is “contiguous to its existing Morne Diable farmout<br />
block licence and the Guayaguayare Shallow and Deep<br />
Horizon blocks, held by Niko Resources, in which Range<br />
farmed in 2013.”<br />
The company has identified several geological horizons in<br />
which it hopes for exploration success once drilling begins,<br />
including “Pliocene Deltaic sands, Miocene Herrera sands,<br />
Cretaceous sands, and the source rock itself.”<br />
Minister Ramnarine had previously suggested that around<br />
590 million barrels could be present in the Miocene Herrera<br />
sandstone “in several accumulations, each ranging in size<br />
between 15 and 150 million barrels of oil.”<br />
Lease Operators<br />
Lease Operators has been silent on the significance of its<br />
acquisition, but it is clear that, as a strictly local company<br />
with <strong>no</strong> access to international corporate connections, it<br />
has its work cut out for it, especially since it has taken<br />
on the biggest block by far, and the one with the fewest<br />
portions excised because of licences earlier granted to<br />
others.<br />
In its favour, however, is that the owners, the Brash family,<br />
also control the largest local drilling company, Well Services<br />
Petroleum (WSP), so equipment availability should <strong>no</strong>t be a<br />
problem when that stage is reached.<br />
Anthony Brash, son of company patriarch Charlie Brash,<br />
is quoted as saying that the company has five rigs available<br />
for onshore work, but they all seem to be contracted to LOL<br />
rivals, including, ironically, Touchstone, Trinity Exploration<br />
and Production (in which the Brashes are shareholders),<br />
Fram Exploration, Leni Gas and Oil, and Petrotrin.<br />
He does point out, however, that LOL will have use of<br />
WSP’s Rig 2, Rig 20 and Rig 70 at various times during <strong>2014</strong>.<br />
Energy <strong>Caribbean</strong> <strong>•</strong> <strong>April</strong> <strong>2014</strong> 5
ST VINCENT<br />
The future: multiple<br />
energy sources<br />
Already hydro supplies 18% of St Vincent’s power<br />
With <strong>no</strong> oil <strong>no</strong>r gas of its<br />
own, St Vincent and the<br />
Grenadines is turning to<br />
renewable energy. It already produces<br />
18% of its power from hydro, according<br />
to Thornley Myers, CEO of St Vincent<br />
Electricity Services (total installed<br />
capacity 42MW). Solar also makes a<br />
modest contribution.<br />
Five other member utilities of the<br />
<strong>Caribbean</strong> Electricity Utility Services<br />
Corporation, the “trade union” for power<br />
providers in the region, have installed RE<br />
generation systems to complement their<br />
diesel and fuel oil facilities: the Jamaica<br />
Public Service Company, Lucelec in St<br />
Lucia, Barbados Light and Power, St Kitts<br />
Electricity (a government department),<br />
and Aqualectra in Curaçao. Myers sees<br />
others moving slowly but surely in this<br />
direction.<br />
RE installation costs are high, and the<br />
intermittency of all but two RE sources<br />
– hydro and geothermal – will always<br />
require a more reliable baseload system.<br />
But RE allows greater price stability,<br />
Myers observes. “Fuel prices change<br />
every month <strong>no</strong>w, based on the price<br />
of oil.” There is also a foreign exchange<br />
saving from reduced oil imports, and<br />
as an indige<strong>no</strong>us resource RE offers a<br />
measure of “energy independence”.<br />
Then there’s the CO 2<br />
reduction factor.<br />
Carbon emissions are comparatively<br />
low in the <strong>Caribbean</strong> (the IDB puts St<br />
Vincent’s CO 2<br />
discharges at 48,805 tons<br />
a year), but Myers supports reduction.<br />
“If we demonstrate a commitment to<br />
lowering our greenhouse gas emissions,<br />
other countries will say, if these small<br />
states are committed to this exercise,<br />
why shouldn’t we be trying too?”<br />
While RE will grow, Myers predicts,<br />
multiple energy sources will be the<br />
pattern in the <strong>Caribbean</strong>, with the<br />
fossil fuel contribution coming from<br />
gas. Roland Fisher, CEO of Gasfin<br />
Development SA, has been trying<br />
to enlist St Vincent as a client of<br />
the proposed small LNG train to be<br />
established at La Brea in Trinidad.<br />
“We were receptive,” Myers says,<br />
“but the key question will always be<br />
cost. Price stability is first and foremost<br />
in our considerations.” Consumers<br />
in St Vincent presently pay US$0.39<br />
per kilowatt hour (kwh). “If we can<br />
import gas at a price that lowers that to<br />
US$0.25, we would be very happy. Of<br />
course, if it were US$0.15, we would be<br />
even happier!”<br />
SUSTAINABILITY<br />
BG T&T comes<br />
clean on CO 2<br />
And prepares plans on emission reduction and local content<br />
Corporate contributions to global<br />
warming are a delicate subject, but<br />
BG Trinidad and Tobago frankly<br />
states in its most recent Sustainability<br />
Review (2012/2013) that its greenhouse<br />
gas emissions during the former year<br />
amounted to 45,526 tonnes. Flaring<br />
accounted for 42.08%. Fuel gas usage<br />
contributed 22.82%, diesel usage 18.24%,<br />
venting 10.97%, “fugitive” emissions<br />
5.08%, and aircraft fuel 0.81%.<br />
The 2012 figure was a 2% reduction<br />
on 2011. Upgrading BG T&T’s Beachfield<br />
blowdown system reduced emissions<br />
from flaring by as much as 76%. Greater<br />
use of gas generators and less of diesel as<br />
a primary fuel source reduced emissions<br />
by 12%. Imposing a fixed flight schedule<br />
for aircraft cut that source by 25% and<br />
lopped US$1.9 million off the fuel bill.<br />
However, gas compression facilities<br />
installed at BG T&T’s Central block on<br />
land in 2013, and those to be completed<br />
on the Hibiscus platform in its North<br />
Coast Marine Area 1 block in <strong>2014</strong>, will<br />
“significantly increase” emissions from<br />
those sources.<br />
BG T&T is the country’s second largest<br />
provider of natural gas (25% of the total),<br />
and is <strong>no</strong>t happy that its greenhouse<br />
gas (GHG) emissions will be rising<br />
again. It pledges to develop an energy<br />
management plan for emissions (methane<br />
and nitrous oxide as well as CO 2<br />
).<br />
A UK company, Process Improvement,<br />
has already undertaken “an energy<br />
efficiency survey of all existing facilities<br />
to determine how efficiently energy<br />
is being consumed and managed.”<br />
Sixteen ways to enhance efficiency were<br />
identified, which BG T&T says “could<br />
result in potential savings of over 100,000<br />
tonnes of emissions.”<br />
A technical review of the existing<br />
“GHG accounting and reporting process”<br />
has been undertaken, which the company<br />
believes could “help improve the overall<br />
accuracy and quality of data reported.”<br />
Assessment of “fugitive” discharges<br />
(attributable to leaks and other irregular<br />
gas emissions from equipment) has been<br />
reviewed in the light of “changes in<br />
operational design.”<br />
In a<strong>no</strong>ther area of national concern,<br />
local content, BG T&T claims in its report<br />
that it is falling in line and “developing a<br />
local content strategy.” Energy minister<br />
Kevin Ramnarine recently revealed that<br />
“serious consideration is being given to<br />
legislating local content ... as has been<br />
done in Norway.”<br />
6
EMISSIONS<br />
Petrotrin plans “clean<br />
development mechanism”<br />
A quarter of its wells will be involved initially<br />
Petrotrin plans to recover about five<br />
million cubic feet a day (mmcfd) of<br />
associated gas currently vented in<br />
its oilfields. By mid-year, it should have<br />
selected a contractor to “finance, build,<br />
own, operate, maintain and transfer”<br />
Trinidad and Tobago’s first clean<br />
development mechanism (CDM).<br />
This will keep about 78,000 tonnes of<br />
CO 2<br />
out of the atmosphere. Total national<br />
emissions are estimated at 53 million<br />
tonnes a year by Dr Donnie Boodlal,<br />
assistant professor of process engineering<br />
at the University of Trinidad and Tobago.<br />
Though the project represents only a<br />
modest cut in overall country emissions,<br />
it is significant in the context of process<br />
ad_energy_caribbean_hp.pdf 1 03/03/<strong>2014</strong> 10:02<br />
emissions from oil and gas, since they<br />
account for only 2% of total emissions,<br />
according to Boodlal’s research. The<br />
petrochemical plants at Point Lisas<br />
are responsible for 57%, and power<br />
generation for 28%.<br />
The finance will come from the fee<br />
that Phoenix Park Gas Processors<br />
(PPGPL) is paying to integrate that 5<br />
mmcfd of associated gas into its own<br />
gas stream, and to develop the ability to<br />
trade certified emission reduction credits<br />
on the European Union carbon market.<br />
PPGPL will achieve some mi<strong>no</strong>r benefit<br />
from extracting the liquids from the gas,<br />
which is its primary business.<br />
Financing for such activities is seen as<br />
a challenge for local companies. Ramona<br />
Ramdial, minister of state in the ministry<br />
of the environment and water resources,<br />
stressed the “urgent need” for climate<br />
finance when she met the European<br />
Union commissioner for climate action,<br />
Connie Hedegaard, in New York late last<br />
year.<br />
Petrotrin has 2,216 active wells, but<br />
only 562 will be targeted in the first<br />
phase of the CDM project. “The big cost<br />
in this is getting a pipeline system to all<br />
the wells,” explains Hemraj Ramdath, the<br />
company’s vice president for strategy and<br />
business development. There is already a<br />
gas line from Pointe-à-Pierre to PPGPL,<br />
“so we will be tapping into that.”<br />
Finally, LNG for the <strong>Caribbean</strong><br />
Right-sized LNG<br />
solutions<br />
Gasfin, building on its extensive global references in Mid-scale<br />
LNG, stands ready to assist Trinidad & Tobago to win the race to<br />
serve the <strong>Caribbean</strong> gas market.<br />
For more information visit www.gasfin.net or call 868 224 3495<br />
At every step...in every size...on land or sea...across the globe<br />
Energy <strong>Caribbean</strong> <strong>•</strong> <strong>April</strong> <strong>2014</strong> 7
4 th -‐ 6 th JUNE <strong>2014</strong><br />
Cara Suites, Pointe-‐à-‐Pierre, Trinidad & Tobago<br />
Course Overview:<br />
This three day course provides an opportunity to<br />
understand the global oil and gas industry (with a<br />
focus upon the <strong>Caribbean</strong>) while gaining an overview<br />
of its physical and technical characteristics.<br />
Geology, Seismic, Drilling, Development<br />
Investment Criteria, Eco<strong>no</strong>mics<br />
Fiscal Regimes (e.g. Production Sharing Contracts),<br />
Joint Venture Agreements<br />
Funding, Accounting, Financial Reporting<br />
Benchmarking, Mergers & Acquisitions<br />
Corporate Governance<br />
Who should attend?<br />
Oil and Gas Technical Specialists, Accountants,<br />
Lawyers, Treasurers, Engineers, Auditors, Service<br />
Suppliers, Banking and Insurance Professionals, etc.<br />
hc<br />
Organised by Hydrocarbon College<br />
Course Director: Terry Follen FCMA CGMA<br />
Terry is the founder and Principal of Hydrocarbon College. In a 35-‐year oil<br />
and gas career in the UK, Trinidad, India, Russia and Yemen, he has acquired<br />
a wealth of experience including: Vice President Finance Atlantic LNG,<br />
Finance Director BG India and Country Manager BHP Yemen.<br />
exceptional learning experience -‐ could <strong>no</strong>t have been<br />
-‐ General Manager, Republic Bank<br />
Industry enabled him to<br />
relate -‐ Repsol<br />
you at ease and encourages -‐ Staatsoile<br />
David Renwick, acclaimed energy journalist,<br />
will give a talk on the <strong>Caribbean</strong> oil and gas scene.<br />
Full Fee: US$1,895<br />
Team Fee: US$1,795 (two or more)<br />
Early Bird Fee: US$1,695 (payment by 23 rd <strong>April</strong>)<br />
Register by EMAIL:<br />
hydrocarboncollege@gmail.com<br />
or on-‐line at www.hydrocarboncollege.com<br />
8
TRINIDAD & TOBAGO<br />
BHP Billiton TT<br />
closer to a decision<br />
on block 3a<br />
Uncertain of the real size of its discoveries, the company is taking<br />
its time to decide on further development<br />
Block 3a, 25 miles off the <strong>no</strong>rtheast<br />
coast of Trinidad with water<br />
depth of 100-300 feet, could be a<br />
new productive oil and gas location – if<br />
the operator, BHP Billiton Trinidad and<br />
Tobago, finally decides that it is worth<br />
developing.<br />
<strong>ENERGY</strong> <strong>Caribbean</strong> has been prodding<br />
the Anglo-Australian multinational to<br />
declare its hand on 3a for some time, since<br />
the potential 135 million barrels of oil in<br />
the Kingbird-Ruby discoveries and the<br />
550 billion cubic feet of gas in Delaware<br />
could both make a valuable contribution<br />
to hydrocarbon output.<br />
BHP Billiton T&T’s president, Vincent<br />
Pereira, <strong>no</strong>w says “we are getting close to<br />
the point where we will have e<strong>no</strong>ugh data<br />
to make an assessment. If we can make<br />
3a work, we will.”<br />
Seven exploratory wells and two<br />
sidetracks have been sunk in 3a, adjoining<br />
the company’s productive 2c block, since<br />
it was first taken on under a production<br />
sharing contract (PSC) in October 2001.<br />
Two oil discoveries were made,<br />
with Kingbird and Ruby, and one gas<br />
discovery, with Delaware. So why haven’t<br />
BHP Billiton T&T and its co-holders<br />
Chayong, Anadarko, Petrotrin and the<br />
National Gas Company (NGC) proceeded<br />
to commercialise them?<br />
A<strong>no</strong>ther look<br />
The challenge, Pereira says, is the true size<br />
of both the oil and gas resources. “The<br />
extent of the discoveries is what matters,”<br />
he told us in an exclusive interview. “These<br />
things only work when they are a certain<br />
size. So what we decided to do was to take<br />
a re-look at the seismic, to reinterpret the<br />
seismic to see if it would give us any hints<br />
as to what’s going on in 3a.”<br />
Further appraisal drilling may be<br />
needed before any development can<br />
be undertaken – but that can only be<br />
contemplated “where we have e<strong>no</strong>ugh<br />
information as a partnership to really<br />
understand what it is about 3a that we<br />
don’t <strong>no</strong>w understand.” The company<br />
should be in that position “hopefully,<br />
early in <strong>2014</strong>.”<br />
Ever cautious, Pereira warns: “I can’t<br />
sit here right <strong>no</strong>w and tell you that 3a<br />
is commercial.” But the fact that the<br />
consortium has been willing to pay<br />
the cost of rolling over the market<br />
development phase (which 3a is <strong>no</strong>w in<br />
because a discovery was made) suggests<br />
it is more optimistic than pessimistic.<br />
It would be justified in<br />
considering itself the<br />
most active petroleum<br />
company in Trinidad<br />
and Tobago at the<br />
moment<br />
The energy ministry supports the<br />
consortium because, as Pereira <strong>no</strong>tes, “it<br />
is as interested in trying to understand<br />
what’s in 3a as all of us are.”<br />
Other projects<br />
The 3a reassessment is just one of<br />
the projects on which BHP Billiton<br />
T&T is working – it would be justified<br />
in considering itself the most active<br />
petroleum company in Trinidad and<br />
Tobago at the moment.<br />
It is acquiring 17,717 sq km of 3D<br />
broadband seismic over its five deep<br />
water blocks – TTDAA 28-29, TTDAA<br />
Vincent Pereira<br />
5-6, and 23b – in collaboration with the<br />
BP Exploration Operating Company,<br />
which needs imaging of its own deep<br />
water acreage, blocks 23a and TTDAA<br />
14. At the same time, it is moving<br />
ahead with its “Angostura phase 3<br />
development” in block 2c, where it is<br />
also the operator, with a view to tapping<br />
into the gas discovered by the Angostura<br />
well, the first ever sunk in that block.<br />
The company has already had gas<br />
flowing from 2c via the Aripo discovery,<br />
which was made after Angostura but<br />
which BHP Billiton T&T and its joint<br />
venture partners in 2c – Chayong and<br />
NGC (Total at the time) – chose to<br />
commercialise first.<br />
That entails supplying the NGC with<br />
220 mmcfd from 2011 to 2021. This<br />
arrangement is likely to be renewed in<br />
the wake of the extension in November<br />
2013 of the PSC for the block itself,<br />
up to <strong>April</strong> 2026. If that happens, the<br />
consortium will certainly need backup<br />
gas to compensate for any decline in<br />
deliveries from Aripo.<br />
Pereira explains: “The new supply<br />
will help us maintain our gas plateau.<br />
Reservoirs decline so you have to keep<br />
filling in, and this is what Angostura will<br />
do. It extends our plateau, which is the<br />
reason we needed the PSC extension<br />
because our productive life is beyond<br />
2021.”<br />
Reserves in Angostura amount to<br />
400-500 bn cf, and production will be<br />
about 100 mmcfd from the second half<br />
of 2016. Development will take place<br />
through subsea wells tied back to the gas<br />
export platform in 2c, into which Aripo<br />
gas already feeds<br />
Courtesy BHP Billiton<br />
Energy <strong>Caribbean</strong> <strong>•</strong> <strong>April</strong> <strong>2014</strong> 9
CARIBBEAN NATURAL GAS MARKET <strong>•</strong> CARIBBEAN NATURAL GAS MARKET <strong>•</strong> CARIBBEAN NATUR<br />
The IDB’s natural gas study<br />
Inter-American Development Bank experts Jed Bailey<br />
and Nils Janson have produced the most comprehensive<br />
analysis so far of the <strong>Caribbean</strong> natural gas trade – “A<br />
Pre-Feasibility Study of the Potential Market for Natural<br />
Gas as a Fuel for Power Generation in the <strong>Caribbean</strong>”.<br />
This formed the reference document for a meeting of<br />
<strong>Caribbean</strong> energy ministers held under the Bank’s auspices<br />
in Washington in early December 2013. The study focuses<br />
on 13 possible recipients of natural gas, including the<br />
Dominican Republic but excluding the French <strong>Caribbean</strong><br />
territories of Martinique and Guadeloupe, which are<br />
expected to buy natural gas for the power turbines they<br />
are installing, probably from the small LNG plant the<br />
UK’s Gasfin Development intends to build at La Brea<br />
in Trinidad. The strengths and weaknesses of the three<br />
methods of gas delivery are outlined in the study.<br />
CNG can’t compete<br />
with LNG<br />
Shipping costs make all the difference<br />
The IDB study has bad news for the UK’s Centrica<br />
Energy, which has been trying to put together a deal to<br />
export its gas from blocks 22 and NCMA 4 in Trinidad and<br />
Tobago to Puerto Rico in compressed natural gas (CNG)<br />
form, and for other promoters thinking along similar lines<br />
for other <strong>Caribbean</strong> markets. It rules out marine CNG as a<br />
commercial proposition for the region.<br />
“Seaborne CNG does <strong>no</strong>t appear to provide a large<br />
e<strong>no</strong>ugh cost reduction [compared with fuel oil] to justify the<br />
added risk of using an unproven tech<strong>no</strong>logy,” it says firmly.<br />
Since the whole point of <strong>Caribbean</strong> utilities switching to<br />
natural gas is to dramatically lower their fuel costs, this<br />
conclusion seems to make sense.<br />
For example, the final delivered price of CNG from<br />
Trinidad and Tobago to Barbados, as calculated by the<br />
study’s authors, is expected to be US$8.71 per mmbtu,<br />
while that for LNG is US$8.65. The disparity is even<br />
greater in the case of gas supplied to Antigua (US$11.48<br />
per mmbtu for CNG, US$9.06 for LNG).<br />
The difference in price, for the same fuel costing the<br />
same at the point of export but delivered by different<br />
methods, seems to lie in the cost of shipping. The IDB study<br />
concludes that “shipping CNG is likely to be much more<br />
expensive. CNG ships are essentially floating platforms<br />
for high pressure pipelines which require thick, high-grade<br />
steel that is heavy and expensive ... each CNG ship will<br />
likely cost more than a typical LNG ship, particularly the<br />
first generation of ships, and will be able to carry much<br />
less natural gas.”<br />
Because of the transportation cost, “shipping distance<br />
has a large impact on the final delivered cost.” CNG<br />
shipping costs will “likely come down as the tech<strong>no</strong>logy<br />
matures, but much additional investment and development<br />
is required before seaborne CNG will be as readily available<br />
as LNG.”<br />
Examples of round-trip shipping costs for CNG and LNG<br />
vessels out of Point Fortin in Trinidad (in US$ per mmbtu)<br />
are:<br />
CNG<br />
LNG<br />
Grenada 6.90 0.19<br />
Dominica 11.70 0.39<br />
St Vincent 7.21 0.21<br />
Part of the higher CNG cost is attributed to unloading<br />
times in port. “Indeed, loading and unloading each<br />
shipment accounts for more days than the actual shipping<br />
transit in almost all cases considered.”<br />
The bottom line, according to the IDB, is that long-run<br />
marginal cost savings by <strong>Caribbean</strong> power utilities from<br />
adopting gas delivered as CNG from Point Fortin would be<br />
a minuscule 5% in Grenada and 4% in St Vincent.<br />
All CNG deliveries from Trinidad and Tobago would<br />
realise some savings, though very small for some recipients,<br />
while “smaller markets and those further away would see<br />
a substantial cost increase if they were to switch to CNG<br />
– some by more than 50%” in the case of deliveries from<br />
other sources.<br />
Pipeline gas even costlier<br />
Though extra clients could bring prices down<br />
Probably to the surprise of many,<br />
the IDB study says a pipeline<br />
would be the most expensive way of<br />
getting gas to Barbados from Tobago,<br />
as the Eastern <strong>Caribbean</strong> Gas Pipeline<br />
Company (ECGPC) is attempting to<br />
do. It puts the cost at US$11.42 per<br />
mmbtu for the 30 million mmcfd that<br />
is initially expected to be piped there,<br />
compared with US$8.65 for LNG<br />
US$8.71 for CNG.<br />
Most of the pipeline cost is incu<br />
in transportation, which would<br />
US$7.12 per mmbtu in Barbad<br />
case. This largely has to do with<br />
cost of building the undersea pipe<br />
which the IDB study calculate<br />
US$3 million a mile for a line w<br />
10
AL GAS MARKET <strong>•</strong> CARIBBEAN NATURAL GAS MARKET <strong>•</strong> CARIBBEAN NATURAL GAS MARKET<br />
Delivery: LNG “the best option”<br />
But which supplier would be most competitive?<br />
The IDB come downs unequivocally on the side of<br />
liquefied natural gas (LNG) as the preferred form<br />
of delivery. “We conclude that the best option for most<br />
<strong>Caribbean</strong> countries would be LNG”, says the study, partly<br />
because “it appears to be the safest tech<strong>no</strong>logy for individual<br />
markets.”<br />
LNG’s appeal, according to the IDB, rests in part on the<br />
assumption that “LNG exports to the <strong>Caribbean</strong> will likely<br />
originate from Cheniere Energy’s Sabine Pass, Louisiana,<br />
supply point”, because of its ability to piggyback on the low<br />
US gas prices <strong>no</strong>w prevailing as a result of the inrush of<br />
shale gas into the domestic US market.<br />
Other potential supply sources are seen as Trinidad and<br />
Tobago (Point Fortin), Colombia (Covenas), Venezuela<br />
(Guiria), Mexico (Altamira), Florida (West Palm Beach) and<br />
Peru.<br />
The authors netted back the Henry Hub gas cost to the<br />
six other locations in order to come up with a cost that<br />
could compete with deliveries from Sabine Pass. Venezuela,<br />
Mexico, West Palm Beach and Peru were ruled out as<br />
realistic candidates for any regional gas trade, reducing<br />
the competition to Sabine Pass, Trinidad and Tobago, and<br />
Colombia.<br />
Some prices suggested by the study for gas delivered<br />
to an LNG plant which would make Trinidad and Tobago<br />
and Colombia competitive with Sabine Pass (where the gas<br />
price was based on an average of US$4 per mmbtu):<br />
Trinidad and Tobago Colombia<br />
(Point Fortin) (Covenas)<br />
For delivery to Grenada US$4.66 US$4.40<br />
For delivery to St Lucia US$4.62 US$4.38<br />
For delivery to Antigua US$4.40 US$4.27<br />
Gas supply being a matter for the producers, it will<br />
require some hard bargaining on the part of the liquefaction<br />
companies to achieve these or even lower prices.<br />
From the recipient countries’ point of view, of course,<br />
it is <strong>no</strong>t the cost of gas to the liquefactor that is important<br />
but the cost of gas to them, after liquefaction, storage,<br />
regasification and transport are all taken into account.<br />
The IDB study takes a stab at ascertaining what “the final<br />
delivered price of gas” will be in selected markets:<br />
Trinidad and Tobago Colombia<br />
(Point Fortin) (Covenas)<br />
For delivery to Grenada US$9.99 US$9.99<br />
For delivery to St Lucia US$9.29 US$9.29<br />
For delivery to Antigua US$9.06 US$9.06<br />
Trinidad and Tobago and Colombia are running neckand-neck<br />
in competitiveness, but neither matches Cheniere,<br />
whose gas would cost US$9.23 in Grenada, US$8.53 in St<br />
Lucia, and US$8.30 in Antigua.<br />
The silver lining, says the study, is that “countries that<br />
are able to reduce their upstream gas price can effectively<br />
compete with US Gulf Coast exporters.” And, by using<br />
Sabine Pass as the source point for <strong>Caribbean</strong> LNG, the IDB<br />
may have calculated the delivered LNG price too favourably.<br />
Cheniere itself said that it will use its second LNG facility, at<br />
Corpus Christi, Texas, for supplying any <strong>Caribbean</strong> market.<br />
The eco<strong>no</strong>mics of liquefaction at Corpus Christi may be<br />
quite different from those at Sabine Pass.<br />
The IDB points out that “<strong>no</strong> single supplier enjoys an<br />
insurmountable advantage over the other. As a result, the<br />
supplier who is able to first reach the market and secure<br />
contracts would face limited pressure from competitors.”<br />
than LNG/CNG<br />
and<br />
rred<br />
be<br />
os’s<br />
the<br />
line,<br />
s at<br />
ith a<br />
capacity of 100 to 300 mmcfd. The<br />
ECGPC line is likely to have a capacity<br />
of 150 mmcfd and a length of 188<br />
miles.<br />
Annual operating and maintenance<br />
costs, says IDB, can be calculated on<br />
the basis of “1.8% of the line’s total<br />
capital cost and annual fuel costs for<br />
pipeline operations (compression)<br />
equal to 2% of the total capital cost as a<br />
proxy for volume and distance.”<br />
The study calculates the pipeline tariff<br />
using “an assumed 80% load factor, 80/20<br />
debt to equity ratio, 8% interest rate, 12%<br />
allowed rate of return on equity, 15-year<br />
depreciation and 35% tax rate, allowing the<br />
pipeline’s capital cost to be spread across<br />
an average tariff for the project’s 15-year<br />
eco<strong>no</strong>mic life.”<br />
Multiple markets along the pipeline route<br />
would benefit from lower costs, the IDB says,<br />
“because the price may be less competitive<br />
at the end of the pipeline and it is desirable<br />
to attract as great a demand in the terminal<br />
market as possible, so regional pipelines may<br />
benefit from cost-sharing mechanisms that<br />
spread the cost more evenly across markets.”<br />
This suggests that Barbados could have<br />
lower gas costs if the pipeline continued to<br />
Martinique and Guadeloupe, with spurs to<br />
St Lucia and Dominica, as earlier envisaged.<br />
But with the two French territories in the<br />
sights of the <strong>Caribbean</strong> LNG project in<br />
Trinidad and Tobago, this does <strong>no</strong>t <strong>no</strong>w<br />
seem likely.<br />
The IDB also expresses concerns about<br />
supply vulnerability, demand fluctuation,<br />
and the capital cost disadvantage of longdistance<br />
pipelines.<br />
Energy <strong>Caribbean</strong> <strong>•</strong> <strong>April</strong> <strong>2014</strong> 11
PROFILE<br />
Anthony<br />
Ramlackhansingh<br />
Former Petrotrin geologist: deep drilling will reverse TT’s<br />
falling crude production<br />
The fall in crude oil production in<br />
Trinidad and Tobago – output<br />
averaged only 67,804 b/d up<br />
to November 2013, compared with<br />
68,744 b/d in 2012 – really should <strong>no</strong>t<br />
be happening, according to Anthony<br />
Ramlackhansingh, 60, the former<br />
Petrotrin divisional geologist, <strong>no</strong>w an<br />
independent petroleum geo-consultant.<br />
Why? Because there’s more than<br />
e<strong>no</strong>ugh available to bump that figure up<br />
considerably.<br />
For starters, there’s 800 million to 2<br />
billion barrels of oil awaiting retrieval<br />
from existing reservoirs which are<br />
<strong>no</strong> longer producing because neither<br />
natural pressure <strong>no</strong>r pumping can bring<br />
them to the surface. Then there are<br />
around a billion barrels of heavy oil (API<br />
gravity of 18 degrees and below) which<br />
New LNG venture<br />
promises electricity<br />
price relief<br />
[ from page 1 ] the development<br />
of a new sort of gas business where<br />
there isn’t a pipeline. If you look<br />
at the Dominican Republic, they<br />
don’t produce gas but already have<br />
13 trucking companies servicing<br />
their market with LNG as a fuel<br />
source for small industrial plants,<br />
air conditioning systems, service<br />
stations.” The inter-island ferries<br />
can also be converted to run on gas.<br />
LNG bunkering in La Brea is<br />
a<strong>no</strong>ther possibility. “The potential<br />
is there,” Fisher says. “There is<br />
<strong>no</strong>w a lot of activity around the<br />
concept of gas-fired ships. We<br />
may eventually be able to attract<br />
cruise ships to bunker with gas in<br />
Trinidad.”<br />
has never been tackled with any great<br />
enthusiasm by companies, principally<br />
because it costs more to extract.<br />
On top of all this is entirely new oil,<br />
awaiting access principally by deep<br />
drilling to about 20,000 feet or more.<br />
The three new land blocks awarded<br />
at the start of <strong>2014</strong> (see page 5) –<br />
Ortoire (Touchstone Energy), Rio Claro<br />
(Lease Operators) and St Mary’s (Range<br />
Resources) – are prime candidates<br />
for this, though it remains to be seen<br />
whether any of the 13 exploratory wells<br />
the three companies are contractually<br />
mandated to sink will meet the criteria.<br />
Petrotrin’s Gulf of Paria Trinmar acreage<br />
also has deep horizon prospectivity.<br />
“There is huge upside potential,<br />
greater than one billion barrels of<br />
oil equivalent on land, that requires<br />
deep drilling,” Ramlackhansingh<br />
says. “Integrated seismic and well<br />
interpretation point me to this.” He<br />
is particularly keen on the three new<br />
blocks, “which came out of work I did<br />
for Petrotrin.”<br />
Drilling deep<br />
Deep drilling, of course, is much<br />
more expensive than shallow drilling,<br />
principally because rigs are paid for by<br />
the day and it obviously takes much<br />
longer to sink a well to 20,000 feet<br />
than it does to 10,000 feet. This kind of<br />
expenditure is generally the province<br />
of the bigger companies, though <strong>no</strong>ne<br />
of the three block winners fall into that<br />
category.<br />
“Deeper drilling is high-risk but has<br />
great potential,” Ramlackhansingh<br />
points out. “That’s why it requires<br />
attracting the big players – but <strong>no</strong>ne<br />
of those presently in Trinidad and<br />
Tobago seem willing to come on shore.”<br />
These include bpTT, Chevron and BHP<br />
Billiton.<br />
Among the bigger players in Trinidad<br />
and Tobago, only BG has ventured<br />
onshore, and it was chasing gas, <strong>no</strong>t oil<br />
– though its Central block does deliver<br />
close to 2,000 b/d of the light oil called<br />
condensate which comes with gas<br />
production.<br />
Ramlackhansingh, who also lectures<br />
in geosciences at the University of the<br />
West Indies (UWI), has been studying<br />
the “big picture” of Trinidad’s southern<br />
basin geology for decades, “looking at<br />
the geology along the <strong>Caribbean</strong> plate<br />
margin, with a focus on the Trinidad<br />
and Tobago area.”<br />
After obtaining a BSc ho<strong>no</strong>urs<br />
degree in geology at the University of<br />
Manitoba in Canada, he returned home<br />
and joined the then Trinidad-Tesoro<br />
Petroleum Company, “starting out in<br />
development drilling, which was really<br />
coming up with the single-well type of<br />
in-fill location.”<br />
Big picture<br />
When Trinidad-Tesoro merged with<br />
Trintoc to become today’s Petrotrin,<br />
Ramlackhansingh moved into<br />
exploration and regional geology. “This<br />
gave me the opportunity to study the<br />
whole regional geology of eastern<br />
Venezuela and Trinidad and link up<br />
with old geology.”<br />
He helped inspire Petrotrin’s block<br />
offerings in the late 1990s, the most<br />
successful of which was the Central<br />
block which BG <strong>no</strong>w operates, with<br />
Petrotrin as its joint venture partner.<br />
As a “big picture” man, he found<br />
himself in the position of being “the<br />
first person multinationals wanted to<br />
speak to when they came to Trinidad<br />
and visited Petrotrin.” He will have a lot<br />
more opportunity to do that <strong>no</strong>w he is<br />
an independent consultant.<br />
He also expects to have more time for<br />
his favourite sport, lawn tennis, and for<br />
writing. “I have completed the first draft<br />
of a book on the tech<strong>no</strong>-stratigraphic<br />
evolution of the greater Trinidad and<br />
Tobago area, which will give the whole<br />
history of the basin.”<br />
Ramlackhansingh and his wife have<br />
a 25-year-old son, André, a UWItrained<br />
doctor, <strong>no</strong>w a house officer in<br />
the accident and emergency unit at the<br />
San Fernando General Hospital. “So, if<br />
I take ill suddenly, I k<strong>no</strong>w where I am<br />
going!” he grins.<br />
12
<strong>ENERGY</strong> EFFICIENCY<br />
How Caricom is tackling<br />
inefficient energy use<br />
Energy-saving programmes in Jamaica, the OECS and Trinidad and Tobago<br />
The “zero-energy/energy-plus<br />
building”, otherwise k<strong>no</strong>wn as a<br />
ZEB/EB, was virtually unheard<br />
of in the <strong>Caribbean</strong> until the University<br />
of the West Indies (UWI) in Jamaica<br />
an<strong>no</strong>unced it was teaming up with the<br />
Global Environment Facility (GEF)<br />
and the United Nations Environment<br />
Programme (UNEP) to create a model<br />
for the first such structure in Caricom,<br />
to be sited on the university’s campus<br />
at Mona.<br />
ZEB/EB buildings are at the cutting<br />
edge of energy efficiency, in that they<br />
create as much energy as they use. The<br />
initiative is part of UWI’s programme<br />
“Promoting Energy Efficiency and<br />
Renewable Energy in Buildings”.<br />
The Jamaican prototype is expected<br />
to be ready “within the next two to<br />
three years.” This will obviously have<br />
relevance for the rest of Caricom, if it<br />
works and achieves the envisaged 40%<br />
saving on energy costs for conventional<br />
buildings.<br />
The Organisation of Eastern<br />
<strong>Caribbean</strong> States (OECS), a<br />
Caricom sub-group, has launched<br />
a campaign called “Power Savers –<br />
the Power is in Your Hands”, with<br />
the less ambitious goal of reducing<br />
electricity bills by 15%. Funded by the<br />
<strong>Caribbean</strong> Development Bank, this<br />
initiative aims to educate businesses<br />
and households to “learn how to<br />
make energy-efficient improvements<br />
and manage energy costs, which<br />
can be as much as 25% of a family’s<br />
income.”<br />
In Trinidad and Tobago, home<br />
of the most flagrant energy users in<br />
Caricom, the ministry of energy and<br />
energy affairs is pursuing efficiency<br />
initiatives alongside its renewable<br />
energy programme (<strong>ENERGY</strong><br />
<strong>Caribbean</strong>, December 2013). Minister<br />
Kevin Ramnarine offered his staff “an<br />
early Christmas present” at the end of<br />
2013 – the opportunity to trade in two<br />
incandescent bulbs for two ministrysupplied<br />
fluorescent bulbs.<br />
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Energy <strong>Caribbean</strong> <strong>•</strong> <strong>April</strong> <strong>2014</strong> 13
LNG DIGEST<br />
The shale gas<br />
threat retreats<br />
Pricing reform may well erode US competitiveness<br />
The popular thesis that shale<br />
gas from the United States will<br />
become invincible, dominating<br />
the global liquefied natural gas (LNG)<br />
trade, continues to be called into<br />
question, even as potential LNG<br />
exporters line up for approval by the US<br />
Department of Energy.<br />
It has been assumed that LNG from<br />
American shale gas will threaten<br />
Trinidad and Tobago’s ambitions for the<br />
small and medium LNG export business<br />
in the <strong>Caribbean</strong> archipelago. But this<br />
view is being increasingly debunked by<br />
experts, including Albert Nahas, vice<br />
president for international government<br />
affairs at Cheniere Energy, which is<br />
seen as the main rival for Trinidad and<br />
Tobago LNG in the region.<br />
The recent Inter-American<br />
Development Bank’s “Pre-Feasibility<br />
Study of the Potential Market for Natural<br />
Gas as a Fuel for Power Generation in<br />
the <strong>Caribbean</strong>” unequivocally plumps<br />
for the US as the probable main LNG<br />
supplier for <strong>Caribbean</strong> countries,<br />
specifically Sabine Pass, Louisiana,<br />
where Cheniere is building its first LNG<br />
export complex.<br />
But even Nahas does <strong>no</strong>t go along<br />
with that. As he told <strong>ENERGY</strong> <strong>Caribbean</strong><br />
last year: “Why shouldn’t Trinidad and<br />
Tobago be able to compete with us?<br />
After all, your LNG will still be cheaper<br />
than that in most of the rest of the world,<br />
except the US.”<br />
Dr Anthony Bryan, energy analyst<br />
specialising in <strong>Caribbean</strong> and Latin<br />
American energy matters, thinks<br />
that “the shale gas threat has been<br />
overblown.” He contends: “Trinidad and<br />
Tobago need <strong>no</strong>t fear any immediate<br />
significant competition from US<br />
exporters for the LNG market in the<br />
<strong>Caribbean</strong>. Trinidad and Tobago is very<br />
capable of holding its own.”<br />
Pricing<br />
The same might well be true further<br />
afield, specifically in the Far East, where<br />
the world’s biggest LNG importers are<br />
located, headed by Japan. There, as<br />
in the European Union and elsewhere<br />
outside North America, gas pricing has<br />
tended to be linked to current oil pricing,<br />
on a barrel-of-oil equivalency basis. With<br />
oil prices relatively high in recent years,<br />
this linkage has kept the price of gas<br />
high, at least by comparison with North<br />
America.<br />
The system naturally suits gas<br />
exporters, and was reaffirmed at the Gas<br />
“Why shouldn’t Trinidad and Tobago be able to<br />
compete with us?”<br />
Exporting Countries’ Forum (GECF) in<br />
Moscow last year. Russia’s president<br />
Vladimir Putin, the conference host,<br />
observed: “The oil link is the fairest and<br />
most market-oriented way of pricing<br />
gas. Rejecting this would mean <strong>no</strong>t only<br />
a blow for gas producers but also serious<br />
costs, and would undermine energy<br />
security even for consuming nations.”<br />
But Putin and the GECF may be<br />
waging a losing battle. More LNG will<br />
be coming onto the international market<br />
in the years ahead, led by Australian<br />
exports, which are set to rise 156%<br />
between 2013 and 2018. Angola has<br />
ironed out its export problems, and<br />
Tanzania and Mozambique will also be<br />
joining the queue.<br />
Russia itself, mainly k<strong>no</strong>wn for<br />
pipeline gas (state-owned Gazprom is<br />
the largest gas company in the world),<br />
is elbowing its way further into LNG. Its<br />
Yamal LNG plant is expected to come on<br />
stream in 2016-7, with three trains and<br />
a capacity of 16.5 million tonnes (more<br />
than Trinidad and Tobago’s Atlantic<br />
complex). The project is being funded<br />
by the country’s largest independent gas<br />
producer, Novatek, reflecting President<br />
Putin’s desire to bring private investors<br />
into LNG to take full advantage of the<br />
growing international LNG trade.<br />
Broken link<br />
The flood of new gas will put pressure<br />
on prices, and the whole principle of<br />
relating gas prices to oil is likely to be<br />
modified, if <strong>no</strong>t to collapse altogether.<br />
Japan, which pays some of the<br />
highest prices for LNG, is among those<br />
clamouring for a more market-based<br />
LNG system, which would have the<br />
effect of slashing prices.<br />
After the accident at its Fukushima<br />
nuclear reactor in 2012, Japan shut<br />
down virtually all its 48 nuclear plants<br />
and was forced to import much more<br />
LNG to plug the gap, costing the country<br />
US$40 billion according to one estimate.<br />
With new LNG contracts coming up<br />
for renewal, Japan seems determined to<br />
bargain hard for lower gas prices. “Oillinked<br />
pricing is <strong>no</strong> longer rational,” an<br />
executive of Tokyo Gas has insisted.<br />
Thus, by the time they arrive in the<br />
Far East or elsewhere, US LNG exports<br />
“Oil-linked pricing is <strong>no</strong> longer rational”<br />
based on shale gas may <strong>no</strong> longer<br />
be as competitive as expected. Price<br />
convergence will, in effect, lop off the<br />
US advantage, to the point where US<br />
companies may <strong>no</strong> longer find exporting<br />
gas attractive at all.<br />
14
RENEWABLE <strong>ENERGY</strong><br />
IDB: RE can’t match gas<br />
for power generation<br />
Wind and water power won’t cut it without subsidy, though<br />
waste, solar and geothermal could be viable<br />
Perhaps the most influential<br />
voice so far has entered the<br />
debate on whether unsubsidised<br />
renewable energy (RE) can ever<br />
be competitive with natural gas in<br />
<strong>Caribbean</strong> power generation. And the<br />
bad news from the Washington-based<br />
Inter-American Development Bank<br />
(IDB) is that several RE sources will<br />
never be able to match gas in price.<br />
The IDB is <strong>no</strong>t totally negative<br />
about RE competitiveness. It<br />
concedes that geothermal energy,<br />
waste-based tech<strong>no</strong>logies and solar<br />
photovoltaics, for example, “could<br />
all be viable.” But it rules out major<br />
tech<strong>no</strong>logies such as wind and hydro<br />
power for electricity generation.<br />
Other recent observers of the<br />
<strong>Caribbean</strong> energy scene have cast<br />
doubt on the competitiveness of RE<br />
in the electricity sector (see <strong>ENERGY</strong><br />
<strong>Caribbean</strong> 71, February <strong>2014</strong>),<br />
including efficiency specialist Andre<br />
Escalante. Ramona Ramdial, minister<br />
of state in Trinidad and Tobago’s<br />
ministry of the environment and<br />
water resources, believes all fossil<br />
fuels, <strong>no</strong>t just gas, are likely to remain<br />
preferable to utilities on the basis of<br />
cost.<br />
Yet the 15 countries of Caricom are<br />
pledged to promote the adoption of<br />
RE as quickly as practicable. It is an<br />
essential ingredient of the Caricom<br />
Energy Policy (CEP), which envisages<br />
that 20% of the electricity generated<br />
in Caricom should be from RE by<br />
2017, 28% by 2022, and 47% – almost<br />
half – by 2027.<br />
Reaching these goals may <strong>no</strong>w force<br />
regional governments to subsidise RE<br />
to make it attractive to generators<br />
– and Ms Ramdial <strong>no</strong>tes that “even<br />
subsidies do <strong>no</strong>t always ensure that<br />
RE is competitive.”<br />
No sense<br />
Joseph Williams, former programme<br />
manager for energy at the Caricom<br />
Secretariat in Guyana (who has<br />
moved temporarily to the <strong>Caribbean</strong><br />
Development Bank in Barbados as<br />
an energy adviser) has rejected Ms<br />
Ramdial’s assessment. But it may be<br />
“Even subsidies do <strong>no</strong>t always ensure that RE is<br />
competitive”<br />
more difficult to debunk the IDB’s<br />
conclusions in its exhaustive “Pre-<br />
Feasibility Study of the Potential<br />
Market for Natural Gas as a Fuel for<br />
Power Generation in the <strong>Caribbean</strong>”,<br />
the reference document for the IDBsponsored<br />
conference of <strong>Caribbean</strong><br />
energy ministers in Washington last<br />
December.<br />
The Bank’s view is that “introducing<br />
natural gas [into the <strong>Caribbean</strong><br />
energy matrix] would affect which RE<br />
tech<strong>no</strong>logies are eco<strong>no</strong>mically and<br />
commercially viable.” Assuming a<br />
natural gas fuel price of 5.64 to 9.64<br />
US cents per kwh (kilowatt hour), and<br />
the long-run marginal cost (LRMC)<br />
of a natural gas-fired power plant<br />
as 10.08 to 13.98 US cents per kwh,<br />
IDB concludes that a number of RE<br />
tech<strong>no</strong>logies “<strong>no</strong> longer make sense.”<br />
Wind and water<br />
One of these is wind. The IDB points<br />
out that “the LRMC for wind is 10 US<br />
cents per kwh, but because wind is an<br />
intermittent tech<strong>no</strong>logy, the LMRC<br />
of wind should be compared with the<br />
fuel price of a firm tech<strong>no</strong>logy, such<br />
as low-speed diesel plants or natural<br />
gas plants.” In such a scenario, “all<br />
fuel prices, which range from 5.64<br />
to 9.54 US cents per kwh, are below<br />
the LMRC of wind at 10 US cents per<br />
kwh, meaning that wind is <strong>no</strong> longer<br />
viable in a situation with natural gas.”’<br />
That assessment will have to be<br />
taken into account in Jamaica, which<br />
is thinking of adding gas to replace oil<br />
in power generation, but already has a<br />
functioning wind farm; and in Trinidad<br />
and Tobago, which is conducting a<br />
wind resource assessment.<br />
The IDB’s verdict on hydro power<br />
is also negative. The Bank says hydro<br />
power “makes <strong>no</strong> sense” in the face<br />
of competition from gas. That will be<br />
a disappointment for entrepreneur<br />
Donald Baldeosingh, who is<br />
vigorously promoting a hydro-electric<br />
project in Guyana which he thinks<br />
can elbow out gas in Trinidad and<br />
Tobago eventually. (And of course<br />
the same IDB is busily offering loans<br />
to Caricom states to add RE to their<br />
domestic energy mix.)<br />
Why does the Bank rule out hydro<br />
power? “The LRMC for a hydro plant<br />
“Wind is <strong>no</strong> longer<br />
viable in a situation<br />
with natural gas”<br />
is 12 US cents per kwh,” it says, “and<br />
the only <strong>Caribbean</strong> state where the<br />
LRMC of a natural gas power plant is<br />
higher than a hydro plant is Dominica,<br />
where the estimated LRMC of a<br />
natural gas plant is 13.98 US cents<br />
per kwh. So hydro still makes sense in<br />
Dominica.” But <strong>no</strong>t elsewhere.<br />
Energy <strong>Caribbean</strong> <strong>•</strong> <strong>April</strong> <strong>2014</strong> 15
20/20 <strong>ENERGY</strong> VISION<br />
How the US is shaking<br />
up world oil trade<br />
China’s hunger for crude is also setting new trading patterns<br />
While the US is boosting<br />
its domestic crude oil<br />
production and reducing its<br />
need for imported oil, China is being<br />
forced to increase its imports, which are<br />
expected to hit 9.2 million b/d by 2020.<br />
The US cut its need for imported crude<br />
to about 10.8 b/d in 2013 by raising its<br />
own production to around 8 million<br />
b/d, the highest since 1989. Consultants<br />
Wood Mackenzie predict that its need for<br />
oil imports will drop below China’s by<br />
2017 as domestic output rises. The US<br />
could become the world’s biggest crude<br />
oil producer as early as 2016, according<br />
to the International Energy Agency,<br />
overtaking Saudi Arabia and Russia,<br />
which both produce around 10 million<br />
b/d.<br />
Weakening demand for oil is also a<br />
factor. Analysts predict that demand<br />
will stay at its present level, around<br />
18.8 million b/d, for some time, and<br />
may even fall as vehicle fuel efficiency<br />
improves. The Energy Information<br />
Administration (EIA) predicts a 25%<br />
reduction in demand for fuel by cars<br />
and light trucks over the next 28 years,<br />
and President Obama plans to raise<br />
fuel efficiency standards to 55 miles per<br />
gallon for new vehicles by 2025. Mixing<br />
corn-based etha<strong>no</strong>l with the gasoline<br />
pool is also reducing demand.<br />
In China, on the other hand, car<br />
ownership is currently 70 cars per 1,000<br />
people, and is likely to increase to 400<br />
per 1,000 by 2034. China produces only<br />
3.3 million b/d of crude compared with<br />
total oil demand of 12.5 million b/d,<br />
and its need for imports is forecast to<br />
rise from 2.5 million b/d (2005) to 9.2<br />
million b/d by 2020.<br />
The trend is clear. OPEC countries are<br />
already switching exports to China and<br />
other Far East countries. According to<br />
the EIA, crude oil shipments from OPEC<br />
to the US fell to as little as 3.9 million b/d<br />
in 2013, from the peak of 6.7 million b/d<br />
in 1977. Its need for crude is the main<br />
reason why China has been assiduously<br />
wooing resource-rich African countries.<br />
If the US decides to export some of<br />
its crude – currently <strong>no</strong>t allowed except<br />
to Canada – the picture could change<br />
again. Much new US production is of<br />
light, “sweet” crude, while the domestic<br />
refinery sector is geared for heavier<br />
crudes. The US could thus become<br />
<strong>no</strong>t only a smaller importer but also<br />
an exporter of crude as well as refined<br />
petroleum products such as diesel and<br />
gasoline.<br />
LATIN AMERICA <strong>ENERGY</strong><br />
Venezuela may restart<br />
Aruba refinery<br />
Decision <strong>no</strong>t to buy delayed coker clears the way for PdVSA<br />
Since Trinidad and Tobago decided<br />
<strong>no</strong>t to buy the delayed coker<br />
unit from the mothballed Valero<br />
refinery in Aruba, Venezuela’s PdVSA<br />
has been eyeing the unit for itself.<br />
Petrotrin is engaged in a bottom-ofthe<br />
barrel upgrade of its 160,000 b/d<br />
refinery at Pointe-à-Pierre in Trinidad,<br />
and considered buying the coker<br />
outright when the Aruba refinery closed<br />
in 2012. But relocation costs alone were<br />
about 85% of a new coker, so an inhouse<br />
upgrade became the preferred<br />
route.<br />
Venezuela needs as much refinery<br />
capacity as it can find, despite today’s<br />
challenging refinery eco<strong>no</strong>mics. It<br />
already leases and operates the 335,000<br />
b/d Isla refinery in Curaçao. In addition<br />
to wanting the Aruba delayed coker<br />
restarted, PdVSA is negotiating with<br />
Valero to bring other refinery facilities<br />
back on line, such as two crude<br />
distillation units, a hydrotreater and a<br />
hydrocracker.<br />
PdVSA suffered a disastrous explosion<br />
at its Amuay refinery in 2012, a storage<br />
tank fire at the Puerto La Cruz refinery<br />
in August 2013, and a shutdown at the<br />
El Palito refinery due to a power cut.<br />
The Aruban government desperately<br />
needs activity of some sort resumed at<br />
the refinery. Prime minister Mike Eman<br />
wants to see a deal reached between<br />
Valero and PdVSA, which would put the<br />
Venezuelan company in charge of the<br />
restarted units.<br />
One of the benefits for PdVSA of<br />
restarting the Aruba refinery would be<br />
to access naphtha, which it can use as<br />
a blend with the increasing amount of<br />
extra heavy oil likely to be extracted<br />
over the coming years as joint ventures<br />
with international oil companies take<br />
shape in the Ori<strong>no</strong>co oil belt (“the Faja”).<br />
Because of cash flow problems,<br />
PdVSA uses crude oil to reduce debt.<br />
Almost a third of the 640,000 b/d of<br />
crude exported to China goes towards<br />
servicing Chinese loans, and PdVSA<br />
pays for storage space at the Valero<br />
complex with crude shipped directly to<br />
the US.<br />
16
Trinidad and Tobago energy statistics<br />
Oil and condensate production (barrels per day)<br />
2009 2010 2011 2012 November 2013<br />
average average average average average<br />
BPTT 20,<strong>72</strong>0 19,487 13,957 7,745 8,900<br />
Repsol 15,335 13,829 11,771 11,961 11,112<br />
Trinmar 23,410 22,389 22,765 21,127 22,392<br />
Petrotrin 15,198 13,942 13,669 13,691 13,457<br />
BHP Billiton TT 15,407 9,451 12,929 12,479 9,406<br />
Primera Oil and Gas 496 460 417 408 382<br />
EOG Resources 5,280 7,486 5,233 2,276 1,499<br />
TED/SWP* 14 13 10 6 7<br />
Moraven 229 273 214 229 348<br />
Trinity Exploration** 680 655 599 546 578<br />
Neal and Massy Energy 196 165 155 134 128<br />
BGTT (Central Block) 1,312 1,260 1,230 1,014 1,031<br />
BGTT (ECMA) 2,208 1,758 1,623 1,201 951<br />
Lease operators 4,892 4,758 4,854 5,685 5,893<br />
Farmout operators 1,1<strong>72</strong> 1,099 888 1,059 903<br />
IPSC*** na 223 330 365 857<br />
New Horizon Exploration na 76 80 87 86<br />
Bayfield Energy 541 921 1,195 1,<strong>72</strong>2 1,383<br />
Total 107,169 98,246 91,919 81,735 79,220<br />
*Trinidad Exploration and Development/South West Peninsula Joint Venture<br />
**Brighton Marine and Point Ligoure<br />
*** Incremental Production Service Contractors (Petrotrin)<br />
Depth drilled (feet)<br />
2011 2012 2013<br />
December December November<br />
BPTT 5,900 9,734 1,152<br />
Niko 1,929 ... ...<br />
Petrotrin ... ... 140<br />
Trinmar 5,079 1,173 4,013<br />
EOG Resources 200 8,656 ...<br />
BHP Billiton 4,462 ... ...<br />
Farmout operators 42 2,341 ...<br />
Lease operators 6,086 14,897 ...<br />
Bayfield 1,602 … ...<br />
Parex 2,920 … ...<br />
Primera ... … ...<br />
Centrica ... ... ...<br />
Trinity (Galeota) ... ... 4,368<br />
BGTT (ECMA) ... ... 9,539<br />
Total 28,220 37,401 19,212<br />
Petrotrin refinery output (bbl)<br />
2009 2011 2012 2013<br />
total total total November<br />
LPG 1,259,913 467,<strong>72</strong>8 134,981 107,048<br />
Motor gasolene 11,491,748 8,589,559 4,833,960 822,265<br />
Aviation gasolene (3,099) (265) (1,868) 8<br />
Kerosene/jet fuel 6,264,257 5,430,534 3,378,689 421,802<br />
Gas oil/diesel 12,815,467 10,297,034 6,870,568 823,847<br />
Fuel oil 17,064,805 16,375,621 15,302,402 1,690,486<br />
Sulphur 60,700 37,229 5,611 2,170<br />
Bitumen 183,325 244,428 190,696 9,889<br />
Other 4,868,269 6,765,601 6,576,739 115,435<br />
Refinery (gain)/loss 1,410,635 1,870,118 1,768,657 286,448<br />
Total 55,416,020 50,097, 587 39,060,435 4,279,308<br />
Crude oil exports (bbl)<br />
2011 2012 2013 2013<br />
total June June November<br />
Galeota Mix 10,199,415 759,161 760,005 771,393<br />
Calypso Crude 4,262,064 378,467 461,052 360,560<br />
Total 14,461,479 1,137,628 1,221,057 1,131,953<br />
Energy <strong>Caribbean</strong> <strong>•</strong> <strong>April</strong> <strong>2014</strong> 17
Condensate production (b/d)<br />
2011 2012 2013<br />
average average November<br />
BPTT 13,957 7,745 8,900<br />
BGTT (ECMA) 1,623 1,201 951<br />
BGTT (Central block) 1,230 1,014 1,031<br />
EOG Resources 5,233 2,276 1,499<br />
National Gas 1,085 437 133<br />
Total 23,137 12,673 12,513<br />
Natural gas production (mmcfd)<br />
2010 2011 2012 2013<br />
average average average November<br />
BPTT 2,565 2,265 2,119 2,079<br />
BG T&T 1,006 994 937 802<br />
EOG Resources 534 513 537 552<br />
BHP Billiton 153 314 431 398<br />
Trinmar 25 24 16 14<br />
Repsol 34 31 30 27<br />
Petrotrin 2 3 4 5<br />
Total 4,319 4,143 4,073 3,877<br />
Natural gas utilisation (mmcfd)<br />
2010 average 2011 average 2012 average 2013 November<br />
Power generation 293 304 304 307<br />
Ammonia 620 583 569 549<br />
Metha<strong>no</strong>l 561 557 521 587<br />
Iron and steel 104 101 108 118<br />
Petrotrin refinery 41 56 74 79<br />
Gas processing 39 35 29 26<br />
Cement 12 12 10 13<br />
Ammonia derivatives ... 23 24 19<br />
Small consumers 10 11 11 11<br />
LNG 2,316 2,160 2,159 1,933<br />
Total 4,005 4,011 3,808 3,642<br />
Non-oil petrochemical production (tonnes)<br />
2010 total 2011 total 2012 total 2013 November<br />
Ammonia (11 plants)<br />
Yara Trinidad 287,940 170,976 262,382 20,734<br />
Tringen One 448,612 375,027 406,400 35,585<br />
Tringen Two 540,368 484,367 459,780 41,271<br />
PCS Nitrogen (4 plants) 2,193,775 2,094,517 1,968,907 170,810<br />
Point Lisas Nitrogen 613,923 682,949 527,111 42,103<br />
<strong>Caribbean</strong> Nitrogen 606,493 549,715 584,682 5,496<br />
Nitro 2000 661,327 611,110 614,915 45,950<br />
AUM – NH 3 200,803 130,269 63,779 2,269<br />
Total ammonia 5,553,242 5,098,927 4,887,956 364,218<br />
Metha<strong>no</strong>l (7 plants)<br />
T&T Metha<strong>no</strong>l One 461,288 402,963 330,582 9,004<br />
T&T Metha<strong>no</strong>l Two 587,951 539,<strong>72</strong>8 592,161 42,521<br />
<strong>Caribbean</strong> Metha<strong>no</strong>l 560,742 515,505 499,308 43,754<br />
Metha<strong>no</strong>l 4 585,583 485,765 520,902 49,019<br />
Methanex Trinidad Unltd 871,<strong>72</strong>6 712,196 785,533 71,818<br />
Atlas Metha<strong>no</strong>l 1,401,050 1,420,685 1,309,058 140,803<br />
Metha<strong>no</strong>l 5000 1,444,350 1,827,416 1,503,134 158,687<br />
Total metha<strong>no</strong>l 5,932,231 5,904,258 5,490,678 515,806<br />
Urea (one plant)<br />
PCS Nitrogen 708,760 616,247 564,892 33,377<br />
Source: Ministry of Energy and Energy Affairs<br />
18
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