Home' Trinidad and Tobago Guardian : October 9th 2014 Contents OCTOBER 2014 • WEEK TWO www.guardian.co.tt BUSINESS GUARDIAN
ENERGY | BG9
BHP Billiton and its
partners will next begin
drilling in a fault block
south of the Greater
ment as it seeks to
increase its natural gas production.
This has been confirmed by well-
placed sources in the company who
say the three-well programme will seek
to develop close to 500 billion cubic
feet of natural gas and therefore allow
the company to add to its present pro-
duction out of Angostura.
"This development is just south of
the Greater Angostura field and we will
drill the wells in 2015, with first gas
expected to flow from the field in 2015.
As you would recall, Angostura is not
one contiguous block, but one with
several faults and therefore where we
are going into is another of that fault
where we know the gas exists," the
According to statistics from the Min-
istry of Energy, BHP Billiton production
has averaged 409 million standard cubic
feet per day or just under ten per cent
of the country s total daily production.
In August, the last month that the figures are available,
the company s natural gas production averaged 427
The news could not come at a better time as the
industry has been reeling from gas curtailment.
Methanol, urea, ammonia, melamine and LNG
production are all down as the midstream and down-
stream companies are not getting the quantum they
are demanding and as a result are operating at below
their name plate capacities.
In addition, the gas shortage has led to Canadian
firm Methanex advising its shareholders that they
expect the business in T&T to be negatively impacted
by gas shortages for the rest of the year.
The curtailments have also led to a fallout between
Energy Minister Kevin Ramnarine and the Point Lisas
executives with the minister accusing some of them
of politicising the issue.
The Greater Angostura field is located in 36-46
metres of water on the continental shelf, 37 kilometres
east of Trinidad and north east of Toco in what many
refer to as the eastern (Trinidadian) sector of the
eastern Venezuela basin.
The shallow water integrated oil and gas field devel-
opment is part of Trinidad offshore block 2c. It is
operated by BHP Billiton (45 per cent) on behalf of
joint venture (JV) partners. BHP first signed a pro-
duction sharing contract on April 22, 1996, and
acquired a 3D seismic survey in 1997. BHP and its
partners licence to operate the field continues until
2021 under a production sharing contract with the
Ministry of Energy and Energy Affairs.
The Greater Angostura field has a production life
expectancy of 19-24 years.
The discovery well, Angostura-1, was drilled in
1999. This intersected 950 feet (gross) of gas pay.
The hydrocarbon potential of the structure was con-
firmed by the drilling of Aripo-1, Kairi-1, Canteen-
1, Kairi-2, Angostura-2 and Canteen-2 wells. Each
of these exploration/appraisal wells also intersected
sands. The Kairi and Canteen fault blocks contain
most of the oil while Aripo has a thin oil rim overlain
by a significant gas cap.
During the six-year exploration phase of the pro-
duction sharing contract, a total of four exploration
and three appraisal wells were drilled, discovering
significant oil and gas resources within a large faulted
structure known as the Greater Angostura structure.
It first produced gas in May 2011 with a new gas
export platform with a design capacity of 280 million
cubic feet of gas per day and is located alongside the
company s existing facilities within the Greater Angos-
However, since then its gas production has been
above 400mmscf/d because of greater demand from
the National Gas Company.
BHP to drill south of Greater
Angostura for more gas
"That's how Chavez earned a place in heaven," Presi-
dent Nicolas Maduro of Venezuela said on a visit to New
York last month.
Maduro was lauding a programme begun by his prede-
cessor, the late President Hugo Chavez, to supply heating
oil to 150,000 low-income families in the United States.
Even such generosity pales, however, next to PetroCaribe,
a Venezuelan energy-assistance program for the
Caribbean and Central America that Chavez launched in
Under the PetroCaribe programme, 10 members of the
Caribbean Community, along with the Dominican Repub-
lic, Nicaragua and El Salvador, buy oil from Venezuela, and
St Lucia is preparing to receive its first shipment. How
much they pay upfront depends on market prices. The
more expensive oil is, the more of the cost is loaned on le-
nient terms: In the past loans have been extended for 25
years at interest rates as low as 1.0 per cent. The cash
saved is earmarked for many purposes, including energy
subsidies, education and beach cleanups.
Between 2011 and 2013 these deferred payments cost
Venezuela an average of US$2.3 billion each year in lost
income. Similar bilateral deals, most notably with Cuba,
add to the bill. That is much less than the US$28 billion
used for local energy subsidies, but no trifle in a country
that is badly short of dollars and basic goods.
So far the desire for influence in the Caribbean has out-
weighed economic pressures in Venezuela, but there al-
ready are signs that Petrocaribe's terms are becoming
more stringent: Guatemala withdrew from the group last
year after the terms became less favorable. The possibil-
ity that the program eventually may be wound down
prompted a recent report from Scotiabank, a Canadian
lender, to call PetroCaribe "more noose than lifeline."
If the trap door were to open, some Petrocaribe coun-
tries are far more exposed than others. For Jamaica,
Guyana, Haiti and Nicaragua, the value of preferential
Venezuelan financing for oil imports is more than 10 per
cent of government revenue and equivalent to around 4.0
per cent of GDP Cuba also is heavily dependent.
If Venezuela were to start being less generous, some
countries would have priority over others. Maduro would
doubtless think twice about cutting off his fellow-trav-
ellers in Cuba and Nicaragua, for example.
Once made, though, a decision could take effect quickly.
Each Petrocaribe member has a separate energy-cooper-
ation agreement, but the terms are broadly similar. The
agreements can be canceled or modified with only 30
days' notice, cutting off the flow of new financing and
forcing countries to pay market rates.
Even with the programme, Caribbean electricity costs
are painfully high. In Jamaica the average monthly elec-
tricity bill is equivalent to one week's earnings for those
on the minimum wage. If the program were to disappear,
prices would soar and the consequences would be severe.
If PetroCaribe is at risk, diversification of energy
sources is the obvious answer. Cheap financing so far has
blurred the price signals needed to spur new investment.
Imported oil remains the dominant energy source in
much of the Caribbean: Jamaica spends more on fuel im-
ports than it earns from tourism, for example. On most
islands antiquated generating equipment adds to the
problem. So do legally protected power-supply monopo-
lies.There may now be some movement. Jamaica has
dithered for years over its energy-investment strategy,
but now proposals are circulating for new power plants
fueled by liquefied natural gas, by low-sulfur Colombian
coal or by ethane or propane made available from Amer-
ica's shale-gas boom.
Within the English-speaking Caribbean, T&T has gas
resources and an LNG plant, which sends some supplies
to Puerto Rico and the Dominican Republic. There are
long-standing plans to build a gas pipeline from Trinidad
to the eastern Caribbean, but pipelines are an expensive
fixed asset and don't sit well with the idea of gas as a
"bridge fuel" to the renewables era. Small-scale LNG
plants may be the answer.
The longer-term prize in the Caribbean is renewable
energy. Too many projects get stuck on the drawing
board, however. Negotiating terms with commercial de-
velopers is a nightmare when costs and returns are un-
certain, while environmental issues cause endless
disputes. Once built, weather-dependent renewables still
can be unreliable. The Economist
The down side
of cheap energy
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