ENERGY Caribbean newsletter (April 2014 • Issue no. 72)

April 2014 • Issue no. 72
WHAT’S INSIDE
3 PPGPL suffers setbacks in
overseas investment
4 Staatsolie expects upsurge
in exploration
9 BHP Billiton to decide on
block 3a this year
NEWSLETTER
10-11 The best ways to get gas
to Caribbean markets
CARIBBEAN LNG
New LNG venture
promises electricity
price relief
Trinidad plant will target Martinique and Guadeloupe first
Roland Fisher
Courtesy Roland Fisher
Caribbean electric utilities desperate
for deliverance from high fuel oil
and diesel prices may finally have
their prayers answered.
Roland Fisher, CEO of Gasfin
Development SA, which has been
given the green light by the Trinidad
and Tobago government to establish a
500,000 tonne-a-year LNG plant at La
Brea, says he is confident that Caribbean
LNG, as the La Brea plant will be known,
should be able to deliver gas at around
US$14-15 per mmbtu, or at least 20%
below the current cost of fuel oil in
mmbtu terms.
That could mean a substantial
reduction in the current cost of electricity
to regional consumers, who currently
pay prices ranging from US$0.39 per
kilowatt hour in St Vincent to $0.22 per
kwh in Aruba (compare $0.06 in Trinidad
and Tobago).
Gasfin Development is a Luxembourgregistered,
UK-headquartered company,
but the state-owned National Gas
Company (NGC) will be an equal partner
in Caribbean LNG and will be directly
involved in part ownership of the first
train (and probably a second in time),
as well as a likely equity partner in the
two floating, storage and regasification
units (FSRUs) to be based in Martinique
and Guadeloupe, the first customers the
company is targeting.
TGE Marine and TGE Gas
Engineering, both Gasfin subsidiaries,
will be designing and building these
vessels as well as the carrier that will
deliver the LNG from La Brea – and of
course the LNG plant itself.
Since LNG is being delivered FOB,
Gasfin has no control over possible
NGC partnership in the LNG carrier part
of the supply chain unless, as Fisher
explains, “we take the project on to
being a deliverer of gas, rather than a
seller of LNG. The buyer has to manage
their own logistics.” The situation may
change when Caribbean LNG begins to
sell to the smaller Caricom states, which
may not be in a position to engage their
own transport.
Fisher has been wooing Électricité
de France (EdF), the power producer
in both Martinique and Guadeloupe,
almost from the day he started selling
his idea about the vast potential of the
Caribbean gas trade to energy ministry
officials, who were sceptical at first but
eventually came around. The current
minister, Kevin Ramnarine, became a
convert and formally announced the
go-ahead for the project at the Energy
Chamber’s annual petroleum conference
in early February. A project development
agreement now has to be worked out.
New business
Production of LNG under national
and sympathetic foreign control opens
the door to a host of new business
possibilities.
Caribbean LNG will be the conduit
for the transfer of Trinidad gas to as
many Caribbean markets as possible, to
relieve them of crippling and potentially
everlasting dependence on oil. As Fisher
points out: “What we are really doing
is supplying the infrastructure that will
enable NGC gas to go to the region, and
NGC has told us that’s what our job is,
not to sell their gas to the world.”
Caribbean LNG could also do what
the much bigger LNG company, Atlantic,
has never contemplated: providing LNG
to domestic Trinidad customers. “We are
very serious that containers of LNG will
be available for the Trinidad market,”
Fisher says. “It will be a real opportunity
for small industries, for [ to page 12 ]
Energy Caribbean • April 2014 1

PPGPL
Unlucky in Africa, gas
liquids company turns
to Americas
And seeks closer alignment with 90% owner NGC
The Point Lisas-based gas liquids
extractor and marketer Phoenix
Park Gas Processors Ltd. (PPGPL)
has not been as successful as it hoped
in its international outreach, part of the
mandate given to it by the Trinidad and
Tobago government.
PPGPL is virtually a state company
now, being 90% owned by the National
Gas Company (NGC), which is itself
state-owned. “We have got to get aligned
with NGC’s own strategies,” company
president Eugene Tiah explained in
an exclusive interview with ENERGY
Caribbean. “We need to get clear on what
the overall strategy is for what is now the
NGC Group.”
NGC has always owned 51% of
PPGPL, and extended its holding by
buying the 39% share previously held
by the US’s ConocoPhillips. Even before
that purchase, the two companies
collaborated closely on international
initiatives, jointly considering gasbased
projects in Ghana, Tanzania and
Equatorial Guinea, though none have so
far come to fruition.
The magazine of the
Caribbean energy industry
APRIL 2014 • Issue No. 72
Subscriptions Department
6 Prospect Avenue, Maraval, Port of Spain,
Trinidad & Tobago
Tel: (868) 622 3821, Fax: (868) 628 0639,
e-mail: energy@meppublishers.com
Writer David Renwick
Editor Jeremy Taylor
Layout Bridget van Dongen
© 2014 Media & Editorial Projects Ltd.
All rights reserved
Africa
A potential investment in gas gathering
and processing facilities in Ghana, once
viewed with great enthusiasm, was lost
to China in 2010. The Ghana National
Gas Company then issued a request for
expressions of interest in operating and
maintaining the plant, to which PPGPL
responded. But Tiah says: “They then
told us they had scrapped all of that.”
PPGPL and NGC also examined a
gas processing project in Nigeria, but
“based on a rigorous review of risks and
returns and other factors, both companies
decided that the project should no longer
be pursued.”
In Tanzania, “we were looking at
the feasibility of micro-LNG for power
generation for mining facilities, and
were getting aligned with an Australian
company that wanted to do that.” But
PPGPL soon realised that “it would have
been an unbalanced sort of relationship:
we wanted to bring to the table our
expertise and knowledge, but they
seemingly preferred just money, with
limited involvement.”
Advertising
Yuri Chin Choy,
ENERGY Caribbean Sales Department
6 Prospect Avenue, Maraval, Port of Spain,
Trinidad & Tobago
Tel: (868) 683 0832,
e-mail: yuri@meppublishers.com
ENERGY Caribbean is published six times a
year, on February 1, April 1, June 1, August 1,
October 1 and December 1.
Subscriptions: Trinidad and Tobago TT$750
per year (six issues), Caribbean US$125, Rest
of the World US$150.
For multiple copies please contact the
Subscriptions Department.
Nothing much has happened in
Equatorial Guinea either. “An initial
assessment visit was made to that country,
which has a developing gas sector, to
evaluate potential gas processing and
related opportunities, and subsequently a
country risk assessment was completed to
guide pursuit of any future opportunities.”
The Americas
For a company operating against
a background of “fewer growth
opportunities locally and leaner gas
supplies coming into the Point Lisas
plant”, four unsuccessful attempts
to spread itself abroad must be
demoralising. Apparently undaunted,
Tiah has switched PPGPL’s attention
to the western hemisphere, targeting
Colombia and Nova Scotia, Canada.
In Colombia, the company is again
looking at gas gathering and processing.
“Colombia has both associated gas
and some pure gas production – small
pockets and small projects – but it is
looking to gather and harness as much
of the resource as they can for power
generation. State company Ecopetrol and
some associated companies have been
asking for EOI for project development.”
PPGPL complied but “the challenge with
these things is that they issue a request
today and they want a proposal next
week.”
The situation requires PPGPL to “have
a presence in such countries”, and teams
have been to Colombia, spending “a
couple of weeks developing a network
and relationships”, and to Nova Scotia,
engaging with “some entrepreneurial
types whose business idea is that there are
big arbitrage opportunities for gas liquids
from shale gas between North America
and Europe and Asia, using terminalling
assets presently under-utilised.” Tiah
thinks this is an “interesting model
because of the terminalling business and
the marketing of natural gas liquids, both
of which we are interested in, as well as
the future potential for fractionation.”
At home, one growth opportunity is
a processing plant at Union industrial
estate, La Brea, to capture the 300 million
cubic feet a day (mmcfd) of gas that will
be flowing through that estate before long.
PPGPL invited expressions of interest
for the provision of “standard design
solutions”, and has been reviewing the
responses.
Energy Caribbean • April 2014 3

SURINAME
Major exploration
programme is under way
And the next round of bidding is in progress too
Staatsolie, Suriname’s national
petroleum company and only oil
producer, confidently expects
another wave of offshore exploration
after March 2015, when it will award
yet more blocks based on the outcome
of the “nomination” process now under
way.
The company has adopted a new
approach to acreage awards, which
mimics what Trinidad and Tobago has
done for some time in relation to the
deep water: potential explorers indicate
which open blocks specifically interest
them, and that information is used to
decide which ones will be offered for
auction.
Fifteen demarcated offshore blocks
are available, their 1.2 million acres
representing about 66% of the marine
area under Suriname’s control, so
the exploration potential is clearly
substantial.
So far, blocks northwest of Suriname’s
coastline have proved of most interest
to companies now operating there,
which leaves most of the 15 on the
northeast of the marine area, abutting
the delimitation line with French
Guiana, open for bids. Staatsolie will be
hoping that the offshore discoveries in
that French department will be a spur to
the nomination, and subsequent takeup,
of acreage.
More to come
So far, the belief that the geology of
AUCTION SCHEDULE
February 2014
March 2014
June 1, 2014
July 2014
August 2014
January 30, 2015
March 2015
4th quarter, 2015
EXPLORATION
Company Block Wells Timeframe
Inpex 31 1 April 2015
Kosmos/Chevron 42 1 tba
Kosmos/Chevron 45 2 2015
Tullow Oil 47 1 2014 Q4–2015 Q1
Murphy Oil 48 1 tba
Petronas (Malaysia) 52 1 April 2015
Apache/Kepsa 53 1 by April 2015
Tullow Oil/Statoil (Norway) 54 tba tba
the Guyana/Suriname/French Guiana
basin mirrors that of west Africa, where
Tullow Oil made its famous Jubilee
discovery in Ghana, has been proved
correct only in the case of French
Guiana itself, with the Zaedyus find of
about 840 million barrels in 2011.
The four wells drilled in Suriname’s
blocks 37 and 31 in 2011, by Murphy
Oil and Japan’s Inpex respectively,
were not successful. Nor was recent
exploration offshore Guyana.
But the possibilities have not been
exhausted by any means, and there is an
ongoing drilling programme by existing
block holders in Suriname which will see
extensive offshore exploration activity
(see box). And there will be much more
to come, towards 2017 and beyond.
Nominations from companies for
blocks of interest to them began in
February. On the basis of US$50,000
data packages, they will have until June
1 to put forward their choices. Staatsolie
Block nominations open
Data packages
Deadline for nominations
Nominations evaluated
Selected blocks announced; bids open
Bids close
Successful bidders announced
Seismic acquisition begins
requires companies to “briefly indicate
the reasons” for their selections, but if
a company declines to nominate, it can
still bid in the subsequent auction.
Process
In July, Staatsolie will be evaluating
the acreages nominated, including
whatever leads/prospects may
have been identified, and will assess
companies according to their technical
expertise, resource management record,
and health, safety and environmental
reputation.
The selection of blocks for production
sharing contracts will be governed by
their commercial potential, strategic fit
with Staatsolie’s vision, the information
available, and the degree of interest that
has been expressed.
The blocks chosen for auction
will be announced on August 1, and
will be open for bids until January
30, 2015. Successful bidders will be
revealed in March 2015, and are likely
to be companies that have offered a
participating interest to Staatsolie,
with maximum work obligations,
which have a good operating record
and demonstrate a sound grasp of the
geology.
Staatsolie expects the companies
chosen to get moving on exploration
activity quickly and begin seismic
acquisition by as early as the fourth
quarter of 2015.
4

TRINIDAD & TOBAGO
Major drilling to resume
on land
Twelve exploration wells planned for Rio Claro, Ortoire and St Mary’s
Exploration activity on land in Trinidad should ramp up
by late 2015, now that the successful bidders for three
blocks offered in 2013 have been announced.
As formally confirmed by the ministry of energy and
energy affairs in February, the 75,089-acre Rio Claro block
in southeast Trinidad, which extends to the Atlantic Ocean,
was awarded to Lease Operators (LOL); the 44,674-acre
Ortoire block, which also abuts the Atlantic, to Canada’s
Touchstone Exploration; and the 37,895-acre St Mary’s
block, further west, to the Anglo-Australian firm Range
Resources.
These companies have committed to collectively
acquiring 295 line km of 2D seismic and 60 sq km of 3D,
and thereafter sinking 12 exploration wells, all at a cost
of US$55 million. If they find commercial reservoirs and
decide to develop them, a further US$945 million could be
spent.
The onshore therefore joins the current shallow water
and deep water offshore exploration initiatives in one of the
busiest periods of exploration activity in decades.
Energy minister Kevin Ramnarine has been quick to
point out that the land is now bracketed with the offshore
as a focus of exploration activity only because the ministry
sanctioned the “first dedicated onshore bid round in 15
years.”
The energy ministry sanctioned the
“first dedicated onshore bid round
in 15 years”
He also pointed out that all three blocks are next to and
on trend with existing hydrocarbon sources, including
the Barrackpore field (130 million barrels), Rock Dome/
Catshill/Inniss (25-30 million barrels) and Carapal Ridge
(20-500 million cubic feet of gas and condensate).
Touchstone
Touchstone Exploration, whose chair-man and CEO is
Paul Baay, has wasted no time in moving to finalise the
exploration and production licence for Ortoire, which was
expected by early March.
The company’s vice president for geosciences, James
Shipka, sees Ortoire as “an incredible opportunity for
Touchstone, as it is an extension of the well-known
southern basin and presents exploration and development
opportunities in a number of different horizons. As with the
company’s existing budget, the commitments associated
with the bid are expected to be funded through future cash
flow.”
Jim Krissa, Touchstone’s Trinidad and Tobago country
chairman, speaks of the “high impact potential” of Ortoire,
which gives the company access to a significant amount of
exploration acreage “that will be immediately integrated
into our long-term operational plan in Trinidad and Tobago.”
Krissa says that this additional acreage (Touchstone now
holds a total of 63,000 acres on land in Trinidad and 5,000
acres nearshore in the Gulf of Paria) enables the company
“to move forward as a leader in onshore exploration and
development in Trinidad.”
Range Resources
Range Resources seems happy to have acquired St Mary’s,
since it is “contiguous to its existing Morne Diable farmout
block licence and the Guayaguayare Shallow and Deep
Horizon blocks, held by Niko Resources, in which Range
farmed in 2013.”
The company has identified several geological horizons in
which it hopes for exploration success once drilling begins,
including “Pliocene Deltaic sands, Miocene Herrera sands,
Cretaceous sands, and the source rock itself.”
Minister Ramnarine had previously suggested that around
590 million barrels could be present in the Miocene Herrera
sandstone “in several accumulations, each ranging in size
between 15 and 150 million barrels of oil.”
Lease Operators
Lease Operators has been silent on the significance of its
acquisition, but it is clear that, as a strictly local company
with no access to international corporate connections, it
has its work cut out for it, especially since it has taken
on the biggest block by far, and the one with the fewest
portions excised because of licences earlier granted to
others.
In its favour, however, is that the owners, the Brash family,
also control the largest local drilling company, Well Services
Petroleum (WSP), so equipment availability should not be a
problem when that stage is reached.
Anthony Brash, son of company patriarch Charlie Brash,
is quoted as saying that the company has five rigs available
for onshore work, but they all seem to be contracted to LOL
rivals, including, ironically, Touchstone, Trinity Exploration
and Production (in which the Brashes are shareholders),
Fram Exploration, Leni Gas and Oil, and Petrotrin.
He does point out, however, that LOL will have use of
WSP’s Rig 2, Rig 20 and Rig 70 at various times during 2014.
Energy Caribbean • April 2014 5

ST VINCENT
The future: multiple
energy sources
Already hydro supplies 18% of St Vincent’s power
With no oil nor gas of its
own, St Vincent and the
Grenadines is turning to
renewable energy. It already produces
18% of its power from hydro, according
to Thornley Myers, CEO of St Vincent
Electricity Services (total installed
capacity 42MW). Solar also makes a
modest contribution.
Five other member utilities of the
Caribbean Electricity Utility Services
Corporation, the “trade union” for power
providers in the region, have installed RE
generation systems to complement their
diesel and fuel oil facilities: the Jamaica
Public Service Company, Lucelec in St
Lucia, Barbados Light and Power, St Kitts
Electricity (a government department),
and Aqualectra in Curaçao. Myers sees
others moving slowly but surely in this
direction.
RE installation costs are high, and the
intermittency of all but two RE sources
– hydro and geothermal – will always
require a more reliable baseload system.
But RE allows greater price stability,
Myers observes. “Fuel prices change
every month now, based on the price
of oil.” There is also a foreign exchange
saving from reduced oil imports, and
as an indigenous resource RE offers a
measure of “energy independence”.
Then there’s the CO 2
reduction factor.
Carbon emissions are comparatively
low in the Caribbean (the IDB puts St
Vincent’s CO 2
discharges at 48,805 tons
a year), but Myers supports reduction.
“If we demonstrate a commitment to
lowering our greenhouse gas emissions,
other countries will say, if these small
states are committed to this exercise,
why shouldn’t we be trying too?”
While RE will grow, Myers predicts,
multiple energy sources will be the
pattern in the Caribbean, with the
fossil fuel contribution coming from
gas. Roland Fisher, CEO of Gasfin
Development SA, has been trying
to enlist St Vincent as a client of
the proposed small LNG train to be
established at La Brea in Trinidad.
“We were receptive,” Myers says,
“but the key question will always be
cost. Price stability is first and foremost
in our considerations.” Consumers
in St Vincent presently pay US$0.39
per kilowatt hour (kwh). “If we can
import gas at a price that lowers that to
US$0.25, we would be very happy. Of
course, if it were US$0.15, we would be
even happier!”
SUSTAINABILITY
BG T&T comes
clean on CO 2
And prepares plans on emission reduction and local content
Corporate contributions to global
warming are a delicate subject, but
BG Trinidad and Tobago frankly
states in its most recent Sustainability
Review (2012/2013) that its greenhouse
gas emissions during the former year
amounted to 45,526 tonnes. Flaring
accounted for 42.08%. Fuel gas usage
contributed 22.82%, diesel usage 18.24%,
venting 10.97%, “fugitive” emissions
5.08%, and aircraft fuel 0.81%.
The 2012 figure was a 2% reduction
on 2011. Upgrading BG T&T’s Beachfield
blowdown system reduced emissions
from flaring by as much as 76%. Greater
use of gas generators and less of diesel as
a primary fuel source reduced emissions
by 12%. Imposing a fixed flight schedule
for aircraft cut that source by 25% and
lopped US$1.9 million off the fuel bill.
However, gas compression facilities
installed at BG T&T’s Central block on
land in 2013, and those to be completed
on the Hibiscus platform in its North
Coast Marine Area 1 block in 2014, will
“significantly increase” emissions from
those sources.
BG T&T is the country’s second largest
provider of natural gas (25% of the total),
and is not happy that its greenhouse
gas (GHG) emissions will be rising
again. It pledges to develop an energy
management plan for emissions (methane
and nitrous oxide as well as CO 2
).
A UK company, Process Improvement,
has already undertaken “an energy
efficiency survey of all existing facilities
to determine how efficiently energy
is being consumed and managed.”
Sixteen ways to enhance efficiency were
identified, which BG T&T says “could
result in potential savings of over 100,000
tonnes of emissions.”
A technical review of the existing
“GHG accounting and reporting process”
has been undertaken, which the company
believes could “help improve the overall
accuracy and quality of data reported.”
Assessment of “fugitive” discharges
(attributable to leaks and other irregular
gas emissions from equipment) has been
reviewed in the light of “changes in
operational design.”
In another area of national concern,
local content, BG T&T claims in its report
that it is falling in line and “developing a
local content strategy.” Energy minister
Kevin Ramnarine recently revealed that
“serious consideration is being given to
legislating local content ... as has been
done in Norway.”
6

EMISSIONS
Petrotrin plans “clean
development mechanism”
A quarter of its wells will be involved initially
Petrotrin plans to recover about five
million cubic feet a day (mmcfd) of
associated gas currently vented in
its oilfields. By mid-year, it should have
selected a contractor to “finance, build,
own, operate, maintain and transfer”
Trinidad and Tobago’s first clean
development mechanism (CDM).
This will keep about 78,000 tonnes of
CO 2
out of the atmosphere. Total national
emissions are estimated at 53 million
tonnes a year by Dr Donnie Boodlal,
assistant professor of process engineering
at the University of Trinidad and Tobago.
Though the project represents only a
modest cut in overall country emissions,
it is significant in the context of process
ad_energy_caribbean_hp.pdf 1 03/03/2014 10:02
emissions from oil and gas, since they
account for only 2% of total emissions,
according to Boodlal’s research. The
petrochemical plants at Point Lisas
are responsible for 57%, and power
generation for 28%.
The finance will come from the fee
that Phoenix Park Gas Processors
(PPGPL) is paying to integrate that 5
mmcfd of associated gas into its own
gas stream, and to develop the ability to
trade certified emission reduction credits
on the European Union carbon market.
PPGPL will achieve some minor benefit
from extracting the liquids from the gas,
which is its primary business.
Financing for such activities is seen as
a challenge for local companies. Ramona
Ramdial, minister of state in the ministry
of the environment and water resources,
stressed the “urgent need” for climate
finance when she met the European
Union commissioner for climate action,
Connie Hedegaard, in New York late last
year.
Petrotrin has 2,216 active wells, but
only 562 will be targeted in the first
phase of the CDM project. “The big cost
in this is getting a pipeline system to all
the wells,” explains Hemraj Ramdath, the
company’s vice president for strategy and
business development. There is already a
gas line from Pointe-à-Pierre to PPGPL,
“so we will be tapping into that.”
Finally, LNG for 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 868 224 3495
At every step...in every size...on land or sea...across the globe
Energy Caribbean • April 2014 7

4 th -­‐ 6 th JUNE 2014
Cara Suites, Pointe-­‐à-­‐Pierre, Trinidad & Tobago
Course Overview:
This three day course provides an opportunity to
understand the global oil and gas industry (with a
focus upon the Caribbean) while gaining an overview
of its physical and technical characteristics.
Geology, Seismic, Drilling, Development
Investment Criteria, Economics
Fiscal Regimes (e.g. Production Sharing Contracts),
Joint Venture Agreements
Funding, Accounting, Financial Reporting
Benchmarking, Mergers & Acquisitions
Corporate Governance
Who should attend?
Oil and Gas Technical Specialists, Accountants,
Lawyers, Treasurers, Engineers, Auditors, Service
Suppliers, Banking and Insurance Professionals, etc.
hc
Organised by Hydrocarbon College
Course Director: Terry Follen FCMA CGMA
Terry is the founder and Principal of Hydrocarbon College. In a 35-­‐year oil
and gas career in the UK, Trinidad, India, Russia and Yemen, he has acquired
a wealth of experience including: Vice President Finance Atlantic LNG,
Finance Director BG India and Country Manager BHP Yemen.
exceptional learning experience -­‐ could not have been
-­‐ General Manager, Republic Bank
Industry enabled him to
relate -­‐ Repsol
you at ease and encourages -­‐ Staatsoile
David Renwick, acclaimed energy journalist,
will give a talk on the Caribbean oil and gas scene.
Full Fee: US$1,895
Team Fee: US$1,795 (two or more)
Early Bird Fee: US$1,695 (payment by 23 rd April)
Register by EMAIL:
hydrocarboncollege@gmail.com
or on-­‐line at www.hydrocarboncollege.com
8

TRINIDAD & TOBAGO
BHP Billiton TT
closer to a decision
on block 3a
Uncertain of the real size of its discoveries, the company is taking
its time to decide on further development
Block 3a, 25 miles off the northeast
coast of Trinidad with water
depth of 100-300 feet, could be a
new productive oil and gas location – if
the operator, BHP Billiton Trinidad and
Tobago, finally decides that it is worth
developing.
ENERGY Caribbean has been prodding
the Anglo-Australian multinational to
declare its hand on 3a for some time, since
the potential 135 million barrels of oil in
the Kingbird-Ruby discoveries and the
550 billion cubic feet of gas in Delaware
could both make a valuable contribution
to hydrocarbon output.
BHP Billiton T&T’s president, Vincent
Pereira, now says “we are getting close to
the point where we will have enough data
to make an assessment. If we can make
3a work, we will.”
Seven exploratory wells and two
sidetracks have been sunk in 3a, adjoining
the company’s productive 2c block, since
it was first taken on under a production
sharing contract (PSC) in October 2001.
Two oil discoveries were made,
with Kingbird and Ruby, and one gas
discovery, with Delaware. So why haven’t
BHP Billiton T&T and its co-holders
Chayong, Anadarko, Petrotrin and the
National Gas Company (NGC) proceeded
to commercialise them?
Another look
The challenge, Pereira says, is the true size
of both the oil and gas resources. “The
extent of the discoveries is what matters,”
he told us in an exclusive interview. “These
things only work when they are a certain
size. So what we decided to do was to take
a re-look at the seismic, to reinterpret the
seismic to see if it would give us any hints
as to what’s going on in 3a.”
Further appraisal drilling may be
needed before any development can
be undertaken – but that can only be
contemplated “where we have enough
information as a partnership to really
understand what it is about 3a that we
don’t now understand.” The company
should be in that position “hopefully,
early in 2014.”
Ever cautious, Pereira warns: “I can’t
sit here right now and tell you that 3a
is commercial.” But the fact that the
consortium has been willing to pay
the cost of rolling over the market
development phase (which 3a is now in
because a discovery was made) suggests
it is more optimistic than pessimistic.
It would be justified in
considering itself the
most active petroleum
company in Trinidad
and Tobago at the
moment
The energy ministry supports the
consortium because, as Pereira notes, “it
is as interested in trying to understand
what’s in 3a as all of us are.”
Other projects
The 3a reassessment is just one of
the projects on which BHP Billiton
T&T is working – it would be justified
in considering itself the most active
petroleum company in Trinidad and
Tobago at the moment.
It is acquiring 17,717 sq km of 3D
broadband seismic over its five deep
water blocks – TTDAA 28-29, TTDAA
Vincent Pereira
5-6, and 23b – in collaboration with the
BP Exploration Operating Company,
which needs imaging of its own deep
water acreage, blocks 23a and TTDAA
14. At the same time, it is moving
ahead with its “Angostura phase 3
development” in block 2c, where it is
also the operator, with a view to tapping
into the gas discovered by the Angostura
well, the first ever sunk in that block.
The company has already had gas
flowing from 2c via the Aripo discovery,
which was made after Angostura but
which BHP Billiton T&T and its joint
venture partners in 2c – Chayong and
NGC (Total at the time) – chose to
commercialise first.
That entails supplying the NGC with
220 mmcfd from 2011 to 2021. This
arrangement is likely to be renewed in
the wake of the extension in November
2013 of the PSC for the block itself,
up to April 2026. If that happens, the
consortium will certainly need backup
gas to compensate for any decline in
deliveries from Aripo.
Pereira explains: “The new supply
will help us maintain our gas plateau.
Reservoirs decline so you have to keep
filling in, and this is what Angostura will
do. It extends our plateau, which is the
reason we needed the PSC extension
because our productive life is beyond
2021.”
Reserves in Angostura amount to
400-500 bn cf, and production will be
about 100 mmcfd from the second half
of 2016. Development will take place
through subsea wells tied back to the gas
export platform in 2c, into which Aripo
gas already feeds
Courtesy BHP Billiton
Energy Caribbean • April 2014 9

CARIBBEAN NATURAL GAS MARKET • CARIBBEAN NATURAL GAS MARKET • CARIBBEAN NATUR
The IDB’s natural gas study
Inter-American Development Bank experts Jed Bailey
and Nils Janson have produced the most comprehensive
analysis so far of the Caribbean natural gas trade – “A
Pre-Feasibility Study of the Potential Market for Natural
Gas as a Fuel for Power Generation in the Caribbean”.
This formed the reference document for a meeting of
Caribbean energy ministers held under the Bank’s auspices
in Washington in early December 2013. The study focuses
on 13 possible recipients of natural gas, including the
Dominican Republic but excluding the French Caribbean
territories of Martinique and Guadeloupe, which are
expected to buy natural gas for the power turbines they
are installing, probably from the small LNG plant the
UK’s Gasfin Development intends to build at La Brea
in Trinidad. The strengths and weaknesses of the three
methods of gas delivery are outlined in the study.
CNG can’t compete
with LNG
Shipping costs make all the difference
The IDB study has bad news for the UK’s Centrica
Energy, which has been trying to put together a deal to
export its gas from blocks 22 and NCMA 4 in Trinidad and
Tobago to Puerto Rico in compressed natural gas (CNG)
form, and for other promoters thinking along similar lines
for other Caribbean markets. It rules out marine CNG as a
commercial proposition for the region.
“Seaborne CNG does not appear to provide a large
enough cost reduction [compared with fuel oil] to justify the
added risk of using an unproven technology,” it says firmly.
Since the whole point of Caribbean utilities switching to
natural gas is to dramatically lower their fuel costs, this
conclusion seems to make sense.
For example, the final delivered price of CNG from
Trinidad and Tobago to Barbados, as calculated by the
study’s authors, is expected to be US$8.71 per mmbtu,
while that for LNG is US$8.65. The disparity is even
greater in the case of gas supplied to Antigua (US$11.48
per mmbtu for CNG, US$9.06 for LNG).
The difference in price, for the same fuel costing the
same at the point of export but delivered by different
methods, seems to lie in the cost of shipping. The IDB study
concludes that “shipping CNG is likely to be much more
expensive. CNG ships are essentially floating platforms
for high pressure pipelines which require thick, high-grade
steel that is heavy and expensive ... each CNG ship will
likely cost more than a typical LNG ship, particularly the
first generation of ships, and will be able to carry much
less natural gas.”
Because of the transportation cost, “shipping distance
has a large impact on the final delivered cost.” CNG
shipping costs will “likely come down as the technology
matures, but much additional investment and development
is required before seaborne CNG will be as readily available
as LNG.”
Examples of round-trip shipping costs for CNG and LNG
vessels out of Point Fortin in Trinidad (in US$ per mmbtu)
are:
CNG
LNG
Grenada 6.90 0.19
Dominica 11.70 0.39
St Vincent 7.21 0.21
Part of the higher CNG cost is attributed to unloading
times in port. “Indeed, loading and unloading each
shipment accounts for more days than the actual shipping
transit in almost all cases considered.”
The bottom line, according to the IDB, is that long-run
marginal cost savings by Caribbean power utilities from
adopting gas delivered as CNG from Point Fortin would be
a minuscule 5% in Grenada and 4% in St Vincent.
All CNG deliveries from Trinidad and Tobago would
realise some savings, though very small for some recipients,
while “smaller markets and those further away would see
a substantial cost increase if they were to switch to CNG
– some by more than 50%” in the case of deliveries from
other sources.
Pipeline gas even costlier
Though extra clients could bring prices down
Probably to the surprise of many,
the IDB study says a pipeline
would be the most expensive way of
getting gas to Barbados from Tobago,
as the Eastern Caribbean Gas Pipeline
Company (ECGPC) is attempting to
do. It puts the cost at US$11.42 per
mmbtu for the 30 million mmcfd that
is initially expected to be piped there,
compared with US$8.65 for LNG
US$8.71 for CNG.
Most of the pipeline cost is incu
in transportation, which would
US$7.12 per mmbtu in Barbad
case. This largely has to do with
cost of building the undersea pipe
which the IDB study calculate
US$3 million a mile for a line w
10

AL GAS MARKET • CARIBBEAN NATURAL GAS MARKET • CARIBBEAN NATURAL GAS MARKET
Delivery: LNG “the best option”
But which supplier would be most competitive?
The IDB come downs unequivocally on the side of
liquefied natural gas (LNG) as the preferred form
of delivery. “We conclude that the best option for most
Caribbean countries would be LNG”, says the study, partly
because “it appears to be the safest technology for individual
markets.”
LNG’s appeal, according to the IDB, rests in part on the
assumption that “LNG exports to the Caribbean will likely
originate from Cheniere Energy’s Sabine Pass, Louisiana,
supply point”, because of its ability to piggyback on the low
US gas prices now prevailing as a result of the inrush of
shale gas into the domestic US market.
Other potential supply sources are seen as Trinidad and
Tobago (Point Fortin), Colombia (Covenas), Venezuela
(Guiria), Mexico (Altamira), Florida (West Palm Beach) and
Peru.
The authors netted back the Henry Hub gas cost to the
six other locations in order to come up with a cost that
could compete with deliveries from Sabine Pass. Venezuela,
Mexico, West Palm Beach and Peru were ruled out as
realistic candidates for any regional gas trade, reducing
the competition to Sabine Pass, Trinidad and Tobago, and
Colombia.
Some prices suggested by the study for gas delivered
to an LNG plant which would make Trinidad and Tobago
and Colombia competitive with Sabine Pass (where the gas
price was based on an average of US$4 per mmbtu):
Trinidad and Tobago Colombia
(Point Fortin) (Covenas)
For delivery to Grenada US$4.66 US$4.40
For delivery to St Lucia US$4.62 US$4.38
For delivery to Antigua US$4.40 US$4.27
Gas supply being a matter for the producers, it will
require some hard bargaining on the part of the liquefaction
companies to achieve these or even lower prices.
From the recipient countries’ point of view, of course,
it is not the cost of gas to the liquefactor that is important
but the cost of gas to them, after liquefaction, storage,
regasification and transport are all taken into account.
The IDB study takes a stab at ascertaining what “the final
delivered price of gas” will be in selected markets:
Trinidad and Tobago Colombia
(Point Fortin) (Covenas)
For delivery to Grenada US$9.99 US$9.99
For delivery to St Lucia US$9.29 US$9.29
For delivery to Antigua US$9.06 US$9.06
Trinidad and Tobago and Colombia are running neckand-neck
in competitiveness, but neither matches Cheniere,
whose gas would cost US$9.23 in Grenada, US$8.53 in St
Lucia, and US$8.30 in Antigua.
The silver lining, says the study, is that “countries that
are able to reduce their upstream gas price can effectively
compete with US Gulf Coast exporters.” And, by using
Sabine Pass as the source point for Caribbean LNG, the IDB
may have calculated the delivered LNG price too favourably.
Cheniere itself said that it will use its second LNG facility, at
Corpus Christi, Texas, for supplying any Caribbean market.
The economics of liquefaction at Corpus Christi may be
quite different from those at Sabine Pass.
The IDB points out that “no single supplier enjoys an
insurmountable advantage over the other. As a result, the
supplier who is able to first reach the market and secure
contracts would face limited pressure from competitors.”
than LNG/CNG
and
rred
be
os’s
the
line,
s at
ith a
capacity of 100 to 300 mmcfd. The
ECGPC line is likely to have a capacity
of 150 mmcfd and a length of 188
miles.
Annual operating and maintenance
costs, says IDB, can be calculated on
the basis of “1.8% of the line’s total
capital cost and annual fuel costs for
pipeline operations (compression)
equal to 2% of the total capital cost as a
proxy for volume and distance.”
The study calculates the pipeline tariff
using “an assumed 80% load factor, 80/20
debt to equity ratio, 8% interest rate, 12%
allowed rate of return on equity, 15-year
depreciation and 35% tax rate, allowing the
pipeline’s capital cost to be spread across
an average tariff for the project’s 15-year
economic life.”
Multiple markets along the pipeline route
would benefit from lower costs, the IDB says,
“because the price may be less competitive
at the end of the pipeline and it is desirable
to attract as great a demand in the terminal
market as possible, so regional pipelines may
benefit from cost-sharing mechanisms that
spread the cost more evenly across markets.”
This suggests that Barbados could have
lower gas costs if the pipeline continued to
Martinique and Guadeloupe, with spurs to
St Lucia and Dominica, as earlier envisaged.
But with the two French territories in the
sights of the Caribbean LNG project in
Trinidad and Tobago, this does not now
seem likely.
The IDB also expresses concerns about
supply vulnerability, demand fluctuation,
and the capital cost disadvantage of longdistance
pipelines.
Energy Caribbean • April 2014 11

PROFILE
Anthony
Ramlackhansingh
Former Petrotrin geologist: deep drilling will reverse TT’s
falling crude production
The fall in crude oil production in
Trinidad and Tobago – output
averaged only 67,804 b/d up
to November 2013, compared with
68,744 b/d in 2012 – really should not
be happening, according to Anthony
Ramlackhansingh, 60, the former
Petrotrin divisional geologist, now an
independent petroleum geo-consultant.
Why? Because there’s more than
enough available to bump that figure up
considerably.
For starters, there’s 800 million to 2
billion barrels of oil awaiting retrieval
from existing reservoirs which are
no longer producing because neither
natural pressure nor pumping can bring
them to the surface. Then there are
around a billion barrels of heavy oil (API
gravity of 18 degrees and below) which
New LNG venture
promises electricity
price relief
[ from page 1 ] the development
of a new sort of gas business where
there isn’t a pipeline. If you look
at the Dominican Republic, they
don’t produce gas but already have
13 trucking companies servicing
their market with LNG as a fuel
source for small industrial plants,
air conditioning systems, service
stations.” The inter-island ferries
can also be converted to run on gas.
LNG bunkering in La Brea is
another possibility. “The potential
is there,” Fisher says. “There is
now a lot of activity around the
concept of gas-fired ships. We
may eventually be able to attract
cruise ships to bunker with gas in
Trinidad.”
has never been tackled with any great
enthusiasm by companies, principally
because it costs more to extract.
On top of all this is entirely new oil,
awaiting access principally by deep
drilling to about 20,000 feet or more.
The three new land blocks awarded
at the start of 2014 (see page 5) –
Ortoire (Touchstone Energy), Rio Claro
(Lease Operators) and St Mary’s (Range
Resources) – are prime candidates
for this, though it remains to be seen
whether any of the 13 exploratory wells
the three companies are contractually
mandated to sink will meet the criteria.
Petrotrin’s Gulf of Paria Trinmar acreage
also has deep horizon prospectivity.
“There is huge upside potential,
greater than one billion barrels of
oil equivalent on land, that requires
deep drilling,” Ramlackhansingh
says. “Integrated seismic and well
interpretation point me to this.” He
is particularly keen on the three new
blocks, “which came out of work I did
for Petrotrin.”
Drilling deep
Deep drilling, of course, is much
more expensive than shallow drilling,
principally because rigs are paid for by
the day and it obviously takes much
longer to sink a well to 20,000 feet
than it does to 10,000 feet. This kind of
expenditure is generally the province
of the bigger companies, though none
of the three block winners fall into that
category.
“Deeper drilling is high-risk but has
great potential,” Ramlackhansingh
points out. “That’s why it requires
attracting the big players – but none
of those presently in Trinidad and
Tobago seem willing to come on shore.”
These include bpTT, Chevron and BHP
Billiton.
Among the bigger players in Trinidad
and Tobago, only BG has ventured
onshore, and it was chasing gas, not oil
– though its Central block does deliver
close to 2,000 b/d of the light oil called
condensate which comes with gas
production.
Ramlackhansingh, who also lectures
in geosciences at the University of the
West Indies (UWI), has been studying
the “big picture” of Trinidad’s southern
basin geology for decades, “looking at
the geology along the Caribbean plate
margin, with a focus on the Trinidad
and Tobago area.”
After obtaining a BSc honours
degree in geology at the University of
Manitoba in Canada, he returned home
and joined the then Trinidad-Tesoro
Petroleum Company, “starting out in
development drilling, which was really
coming up with the single-well type of
in-fill location.”
Big picture
When Trinidad-Tesoro merged with
Trintoc to become today’s Petrotrin,
Ramlackhansingh moved into
exploration and regional geology. “This
gave me the opportunity to study the
whole regional geology of eastern
Venezuela and Trinidad and link up
with old geology.”
He helped inspire Petrotrin’s block
offerings in the late 1990s, the most
successful of which was the Central
block which BG now operates, with
Petrotrin as its joint venture partner.
As a “big picture” man, he found
himself in the position of being “the
first person multinationals wanted to
speak to when they came to Trinidad
and visited Petrotrin.” He will have a lot
more opportunity to do that now he is
an independent consultant.
He also expects to have more time for
his favourite sport, lawn tennis, and for
writing. “I have completed the first draft
of a book on the techno-stratigraphic
evolution of the greater Trinidad and
Tobago area, which will give the whole
history of the basin.”
Ramlackhansingh and his wife have
a 25-year-old son, André, a UWItrained
doctor, now a house officer in
the accident and emergency unit at the
San Fernando General Hospital. “So, if
I take ill suddenly, I know where I am
going!” he grins.
12

ENERGY EFFICIENCY
How Caricom is tackling
inefficient energy use
Energy-saving programmes in Jamaica, the OECS and Trinidad and Tobago
The “zero-energy/energy-plus
building”, otherwise known as a
ZEB/EB, was virtually unheard
of in the Caribbean until the University
of the West Indies (UWI) in Jamaica
announced it was teaming up with the
Global Environment Facility (GEF)
and the United Nations Environment
Programme (UNEP) to create a model
for the first such structure in Caricom,
to be sited on the university’s campus
at Mona.
ZEB/EB buildings are at the cutting
edge of energy efficiency, in that they
create as much energy as they use. The
initiative is part of UWI’s programme
“Promoting Energy Efficiency and
Renewable Energy in Buildings”.
The Jamaican prototype is expected
to be ready “within the next two to
three years.” This will obviously have
relevance for the rest of Caricom, if it
works and achieves the envisaged 40%
saving on energy costs for conventional
buildings.
The Organisation of Eastern
Caribbean States (OECS), a
Caricom sub-group, has launched
a campaign called “Power Savers –
the Power is in Your Hands”, with
the less ambitious goal of reducing
electricity bills by 15%. Funded by the
Caribbean Development Bank, this
initiative aims to educate businesses
and households to “learn how to
make energy-efficient improvements
and manage energy costs, which
can be as much as 25% of a family’s
income.”
In Trinidad and Tobago, home
of the most flagrant energy users in
Caricom, the ministry of energy and
energy affairs is pursuing efficiency
initiatives alongside its renewable
energy programme (ENERGY
Caribbean, December 2013). Minister
Kevin Ramnarine offered his staff “an
early Christmas present” at the end of
2013 – the opportunity to trade in two
incandescent bulbs for two ministrysupplied
fluorescent bulbs.
1 st Suriname international
www.SurimeP.Com
1 st Suriname international mining, energy & Petroleum ConferenCe and exhibition
17 – 19 June 2014 • Paramaribo • republiC of Suriname
organiSed by
miniSterie van natuurlijke hulpbronnen
gold SponSor
Silver SponSorS
booking ContaCtS
suriname@ametrade.org ~ www.surimep.com
Suriname: +597 811 9338 / +597 883 8632 ~ international: +44 207 700 4949
Energy Caribbean • April 2014 13

LNG DIGEST
The shale gas
threat retreats
Pricing reform may well erode US competitiveness
The popular thesis that shale
gas from the United States will
become invincible, dominating
the global liquefied natural gas (LNG)
trade, continues to be called into
question, even as potential LNG
exporters line up for approval by the US
Department of Energy.
It has been assumed that LNG from
American shale gas will threaten
Trinidad and Tobago’s ambitions for the
small and medium LNG export business
in the Caribbean archipelago. But this
view is being increasingly debunked by
experts, including Albert Nahas, vice
president for international government
affairs at Cheniere Energy, which is
seen as the main rival for Trinidad and
Tobago LNG in the region.
The recent Inter-American
Development Bank’s “Pre-Feasibility
Study of the Potential Market for Natural
Gas as a Fuel for Power Generation in
the Caribbean” unequivocally plumps
for the US as the probable main LNG
supplier for Caribbean countries,
specifically Sabine Pass, Louisiana,
where Cheniere is building its first LNG
export complex.
But even Nahas does not go along
with that. As he told ENERGY Caribbean
last year: “Why shouldn’t Trinidad and
Tobago be able to compete with us?
After all, your LNG will still be cheaper
than that in most of the rest of the world,
except the US.”
Dr Anthony Bryan, energy analyst
specialising in Caribbean and Latin
American energy matters, thinks
that “the shale gas threat has been
overblown.” He contends: “Trinidad and
Tobago need not fear any immediate
significant competition from US
exporters for the LNG market in the
Caribbean. Trinidad and Tobago is very
capable of holding its own.”
Pricing
The same might well be true further
afield, specifically in the Far East, where
the world’s biggest LNG importers are
located, headed by Japan. There, as
in the European Union and elsewhere
outside North America, gas pricing has
tended to be linked to current oil pricing,
on a barrel-of-oil equivalency basis. With
oil prices relatively high in recent years,
this linkage has kept the price of gas
high, at least by comparison with North
America.
The system naturally suits gas
exporters, and was reaffirmed at the Gas
“Why shouldn’t Trinidad and Tobago be able to
compete with us?”
Exporting Countries’ Forum (GECF) in
Moscow last year. Russia’s president
Vladimir Putin, the conference host,
observed: “The oil link is the fairest and
most market-oriented way of pricing
gas. Rejecting this would mean not only
a blow for gas producers but also serious
costs, and would undermine energy
security even for consuming nations.”
But Putin and the GECF may be
waging a losing battle. More LNG will
be coming onto the international market
in the years ahead, led by Australian
exports, which are set to rise 156%
between 2013 and 2018. Angola has
ironed out its export problems, and
Tanzania and Mozambique will also be
joining the queue.
Russia itself, mainly known for
pipeline gas (state-owned Gazprom is
the largest gas company in the world),
is elbowing its way further into LNG. Its
Yamal LNG plant is expected to come on
stream in 2016-7, with three trains and
a capacity of 16.5 million tonnes (more
than Trinidad and Tobago’s Atlantic
complex). The project is being funded
by the country’s largest independent gas
producer, Novatek, reflecting President
Putin’s desire to bring private investors
into LNG to take full advantage of the
growing international LNG trade.
Broken link
The flood of new gas will put pressure
on prices, and the whole principle of
relating gas prices to oil is likely to be
modified, if not to collapse altogether.
Japan, which pays some of the
highest prices for LNG, is among those
clamouring for a more market-based
LNG system, which would have the
effect of slashing prices.
After the accident at its Fukushima
nuclear reactor in 2012, Japan shut
down virtually all its 48 nuclear plants
and was forced to import much more
LNG to plug the gap, costing the country
US$40 billion according to one estimate.
With new LNG contracts coming up
for renewal, Japan seems determined to
bargain hard for lower gas prices. “Oillinked
pricing is no longer rational,” an
executive of Tokyo Gas has insisted.
Thus, by the time they arrive in the
Far East or elsewhere, US LNG exports
“Oil-linked pricing is no longer rational”
based on shale gas may no longer
be as competitive as expected. Price
convergence will, in effect, lop off the
US advantage, to the point where US
companies may no longer find exporting
gas attractive at all.
14

RENEWABLE ENERGY
IDB: RE can’t match gas
for power generation
Wind and water power won’t cut it without subsidy, though
waste, solar and geothermal could be viable
Perhaps the most influential
voice so far has entered the
debate on whether unsubsidised
renewable energy (RE) can ever
be competitive with natural gas in
Caribbean power generation. And the
bad news from the Washington-based
Inter-American Development Bank
(IDB) is that several RE sources will
never be able to match gas in price.
The IDB is not totally negative
about RE competitiveness. It
concedes that geothermal energy,
waste-based technologies and solar
photovoltaics, for example, “could
all be viable.” But it rules out major
technologies such as wind and hydro
power for electricity generation.
Other recent observers of the
Caribbean energy scene have cast
doubt on the competitiveness of RE
in the electricity sector (see ENERGY
Caribbean 71, February 2014),
including efficiency specialist Andre
Escalante. Ramona Ramdial, minister
of state in Trinidad and Tobago’s
ministry of the environment and
water resources, believes all fossil
fuels, not just gas, are likely to remain
preferable to utilities on the basis of
cost.
Yet the 15 countries of Caricom are
pledged to promote the adoption of
RE as quickly as practicable. It is an
essential ingredient of the Caricom
Energy Policy (CEP), which envisages
that 20% of the electricity generated
in Caricom should be from RE by
2017, 28% by 2022, and 47% – almost
half – by 2027.
Reaching these goals may now force
regional governments to subsidise RE
to make it attractive to generators
– and Ms Ramdial notes that “even
subsidies do not always ensure that
RE is competitive.”
No sense
Joseph Williams, former programme
manager for energy at the Caricom
Secretariat in Guyana (who has
moved temporarily to the Caribbean
Development Bank in Barbados as
an energy adviser) has rejected Ms
Ramdial’s assessment. But it may be
“Even subsidies do not always ensure that RE is
competitive”
more difficult to debunk the IDB’s
conclusions in its exhaustive “Pre-
Feasibility Study of the Potential
Market for Natural Gas as a Fuel for
Power Generation in the Caribbean”,
the reference document for the IDBsponsored
conference of Caribbean
energy ministers in Washington last
December.
The Bank’s view is that “introducing
natural gas [into the Caribbean
energy matrix] would affect which RE
technologies are economically and
commercially viable.” Assuming a
natural gas fuel price of 5.64 to 9.64
US cents per kwh (kilowatt hour), and
the long-run marginal cost (LRMC)
of a natural gas-fired power plant
as 10.08 to 13.98 US cents per kwh,
IDB concludes that a number of RE
technologies “no longer make sense.”
Wind and water
One of these is wind. The IDB points
out that “the LRMC for wind is 10 US
cents per kwh, but because wind is an
intermittent technology, the LMRC
of wind should be compared with the
fuel price of a firm technology, such
as low-speed diesel plants or natural
gas plants.” In such a scenario, “all
fuel prices, which range from 5.64
to 9.54 US cents per kwh, are below
the LMRC of wind at 10 US cents per
kwh, meaning that wind is no longer
viable in a situation with natural gas.”’
That assessment will have to be
taken into account in Jamaica, which
is thinking of adding gas to replace oil
in power generation, but already has a
functioning wind farm; and in Trinidad
and Tobago, which is conducting a
wind resource assessment.
The IDB’s verdict on hydro power
is also negative. The Bank says hydro
power “makes no sense” in the face
of competition from gas. That will be
a disappointment for entrepreneur
Donald Baldeosingh, who is
vigorously promoting a hydro-electric
project in Guyana which he thinks
can elbow out gas in Trinidad and
Tobago eventually. (And of course
the same IDB is busily offering loans
to Caricom states to add RE to their
domestic energy mix.)
Why does the Bank rule out hydro
power? “The LRMC for a hydro plant
“Wind is no longer
viable in a situation
with natural gas”
is 12 US cents per kwh,” it says, “and
the only Caribbean state where the
LRMC of a natural gas power plant is
higher than a hydro plant is Dominica,
where the estimated LRMC of a
natural gas plant is 13.98 US cents
per kwh. So hydro still makes sense in
Dominica.” But not elsewhere.
Energy Caribbean • April 2014 15

20/20 ENERGY VISION
How the US is shaking
up world oil trade
China’s hunger for crude is also setting new trading patterns
While the US is boosting
its domestic crude oil
production and reducing its
need for imported oil, China is being
forced to increase its imports, which are
expected to hit 9.2 million b/d by 2020.
The US cut its need for imported crude
to about 10.8 b/d in 2013 by raising its
own production to around 8 million
b/d, the highest since 1989. Consultants
Wood Mackenzie predict that its need for
oil imports will drop below China’s by
2017 as domestic output rises. The US
could become the world’s biggest crude
oil producer as early as 2016, according
to the International Energy Agency,
overtaking Saudi Arabia and Russia,
which both produce around 10 million
b/d.
Weakening demand for oil is also a
factor. Analysts predict that demand
will stay at its present level, around
18.8 million b/d, for some time, and
may even fall as vehicle fuel efficiency
improves. The Energy Information
Administration (EIA) predicts a 25%
reduction in demand for fuel by cars
and light trucks over the next 28 years,
and President Obama plans to raise
fuel efficiency standards to 55 miles per
gallon for new vehicles by 2025. Mixing
corn-based ethanol with the gasoline
pool is also reducing demand.
In China, on the other hand, car
ownership is currently 70 cars per 1,000
people, and is likely to increase to 400
per 1,000 by 2034. China produces only
3.3 million b/d of crude compared with
total oil demand of 12.5 million b/d,
and its need for imports is forecast to
rise from 2.5 million b/d (2005) to 9.2
million b/d by 2020.
The trend is clear. OPEC countries are
already switching exports to China and
other Far East countries. According to
the EIA, crude oil shipments from OPEC
to the US fell to as little as 3.9 million b/d
in 2013, from the peak of 6.7 million b/d
in 1977. Its need for crude is the main
reason why China has been assiduously
wooing resource-rich African countries.
If the US decides to export some of
its crude – currently not allowed except
to Canada – the picture could change
again. Much new US production is of
light, “sweet” crude, while the domestic
refinery sector is geared for heavier
crudes. The US could thus become
not only a smaller importer but also
an exporter of crude as well as refined
petroleum products such as diesel and
gasoline.
LATIN AMERICA ENERGY
Venezuela may restart
Aruba refinery
Decision not to buy delayed coker clears the way for PdVSA
Since Trinidad and Tobago decided
not to buy the delayed coker
unit from the mothballed Valero
refinery in Aruba, Venezuela’s PdVSA
has been eyeing the unit for itself.
Petrotrin is engaged in a bottom-ofthe
barrel upgrade of its 160,000 b/d
refinery at Pointe-à-Pierre in Trinidad,
and considered buying the coker
outright when the Aruba refinery closed
in 2012. But relocation costs alone were
about 85% of a new coker, so an inhouse
upgrade became the preferred
route.
Venezuela needs as much refinery
capacity as it can find, despite today’s
challenging refinery economics. It
already leases and operates the 335,000
b/d Isla refinery in Curaçao. In addition
to wanting the Aruba delayed coker
restarted, PdVSA is negotiating with
Valero to bring other refinery facilities
back on line, such as two crude
distillation units, a hydrotreater and a
hydrocracker.
PdVSA suffered a disastrous explosion
at its Amuay refinery in 2012, a storage
tank fire at the Puerto La Cruz refinery
in August 2013, and a shutdown at the
El Palito refinery due to a power cut.
The Aruban government desperately
needs activity of some sort resumed at
the refinery. Prime minister Mike Eman
wants to see a deal reached between
Valero and PdVSA, which would put the
Venezuelan company in charge of the
restarted units.
One of the benefits for PdVSA of
restarting the Aruba refinery would be
to access naphtha, which it can use as
a blend with the increasing amount of
extra heavy oil likely to be extracted
over the coming years as joint ventures
with international oil companies take
shape in the Orinoco oil belt (“the Faja”).
Because of cash flow problems,
PdVSA uses crude oil to reduce debt.
Almost a third of the 640,000 b/d of
crude exported to China goes towards
servicing Chinese loans, and PdVSA
pays for storage space at the Valero
complex with crude shipped directly to
the US.
16

Trinidad and Tobago energy statistics
Oil and condensate production (barrels per day)
2009 2010 2011 2012 November 2013
average average average average average
BPTT 20,720 19,487 13,957 7,745 8,900
Repsol 15,335 13,829 11,771 11,961 11,112
Trinmar 23,410 22,389 22,765 21,127 22,392
Petrotrin 15,198 13,942 13,669 13,691 13,457
BHP Billiton TT 15,407 9,451 12,929 12,479 9,406
Primera Oil and Gas 496 460 417 408 382
EOG Resources 5,280 7,486 5,233 2,276 1,499
TED/SWP* 14 13 10 6 7
Moraven 229 273 214 229 348
Trinity Exploration** 680 655 599 546 578
Neal and Massy Energy 196 165 155 134 128
BGTT (Central Block) 1,312 1,260 1,230 1,014 1,031
BGTT (ECMA) 2,208 1,758 1,623 1,201 951
Lease operators 4,892 4,758 4,854 5,685 5,893
Farmout operators 1,172 1,099 888 1,059 903
IPSC*** na 223 330 365 857
New Horizon Exploration na 76 80 87 86
Bayfield Energy 541 921 1,195 1,722 1,383
Total 107,169 98,246 91,919 81,735 79,220
*Trinidad Exploration and Development/South West Peninsula Joint Venture
**Brighton Marine and Point Ligoure
*** Incremental Production Service Contractors (Petrotrin)
Depth drilled (feet)
2011 2012 2013
December December November
BPTT 5,900 9,734 1,152
Niko 1,929 ... ...
Petrotrin ... ... 140
Trinmar 5,079 1,173 4,013
EOG Resources 200 8,656 ...
BHP Billiton 4,462 ... ...
Farmout operators 42 2,341 ...
Lease operators 6,086 14,897 ...
Bayfield 1,602 … ...
Parex 2,920 … ...
Primera ... … ...
Centrica ... ... ...
Trinity (Galeota) ... ... 4,368
BGTT (ECMA) ... ... 9,539
Total 28,220 37,401 19,212
Petrotrin refinery output (bbl)
2009 2011 2012 2013
total total total November
LPG 1,259,913 467,728 134,981 107,048
Motor gasolene 11,491,748 8,589,559 4,833,960 822,265
Aviation gasolene (3,099) (265) (1,868) 8
Kerosene/jet fuel 6,264,257 5,430,534 3,378,689 421,802
Gas oil/diesel 12,815,467 10,297,034 6,870,568 823,847
Fuel oil 17,064,805 16,375,621 15,302,402 1,690,486
Sulphur 60,700 37,229 5,611 2,170
Bitumen 183,325 244,428 190,696 9,889
Other 4,868,269 6,765,601 6,576,739 115,435
Refinery (gain)/loss 1,410,635 1,870,118 1,768,657 286,448
Total 55,416,020 50,097, 587 39,060,435 4,279,308
Crude oil exports (bbl)
2011 2012 2013 2013
total June June November
Galeota Mix 10,199,415 759,161 760,005 771,393
Calypso Crude 4,262,064 378,467 461,052 360,560
Total 14,461,479 1,137,628 1,221,057 1,131,953
Energy Caribbean • April 2014 17

Condensate production (b/d)
2011 2012 2013
average average November
BPTT 13,957 7,745 8,900
BGTT (ECMA) 1,623 1,201 951
BGTT (Central block) 1,230 1,014 1,031
EOG Resources 5,233 2,276 1,499
National Gas 1,085 437 133
Total 23,137 12,673 12,513
Natural gas production (mmcfd)
2010 2011 2012 2013
average average average November
BPTT 2,565 2,265 2,119 2,079
BG T&T 1,006 994 937 802
EOG Resources 534 513 537 552
BHP Billiton 153 314 431 398
Trinmar 25 24 16 14
Repsol 34 31 30 27
Petrotrin 2 3 4 5
Total 4,319 4,143 4,073 3,877
Natural gas utilisation (mmcfd)
2010 average 2011 average 2012 average 2013 November
Power generation 293 304 304 307
Ammonia 620 583 569 549
Methanol 561 557 521 587
Iron and steel 104 101 108 118
Petrotrin refinery 41 56 74 79
Gas processing 39 35 29 26
Cement 12 12 10 13
Ammonia derivatives ... 23 24 19
Small consumers 10 11 11 11
LNG 2,316 2,160 2,159 1,933
Total 4,005 4,011 3,808 3,642
Non-oil petrochemical production (tonnes)
2010 total 2011 total 2012 total 2013 November
Ammonia (11 plants)
Yara Trinidad 287,940 170,976 262,382 20,734
Tringen One 448,612 375,027 406,400 35,585
Tringen Two 540,368 484,367 459,780 41,271
PCS Nitrogen (4 plants) 2,193,775 2,094,517 1,968,907 170,810
Point Lisas Nitrogen 613,923 682,949 527,111 42,103
Caribbean Nitrogen 606,493 549,715 584,682 5,496
Nitro 2000 661,327 611,110 614,915 45,950
AUM – NH 3 200,803 130,269 63,779 2,269
Total ammonia 5,553,242 5,098,927 4,887,956 364,218
Methanol (7 plants)
T&T Methanol One 461,288 402,963 330,582 9,004
T&T Methanol Two 587,951 539,728 592,161 42,521
Caribbean Methanol 560,742 515,505 499,308 43,754
Methanol 4 585,583 485,765 520,902 49,019
Methanex Trinidad Unltd 871,726 712,196 785,533 71,818
Atlas Methanol 1,401,050 1,420,685 1,309,058 140,803
Methanol 5000 1,444,350 1,827,416 1,503,134 158,687
Total methanol 5,932,231 5,904,258 5,490,678 515,806
Urea (one plant)
PCS Nitrogen 708,760 616,247 564,892 33,377
Source: Ministry of Energy and Energy Affairs
18

Fifteen record-setting years, and we’re not done yet.
At Smith Bits, we’re committed to producing bits that exceed the capabilities of our previous designs.
Using the most advanced technology to develop the widest range of rock destruction products in the
industry, we continually push the boundaries of reliable bit performance for every application. So, while
we continue to surpass our drillbit performance records for fastest ROP and longest drilled intervals—
more than all other bit companies combined in the past 15 years—our work is far from over.
Find out more at
slb.com/bits
Copyright © 2013 Schlumberger. 13-BT-0111