Home' Trinidad and Tobago Guardian : January 14th 2016 Contents BG8 ENERGY
BUSINESS GUARDIAN www.guardian.co.tt JANUARY 14 • 2016
The global oil glut will swell until late
2017, the US government forecast on
Tuesday in an outlook that offered little
hope of near-term relief for energy
producers reeling from the collapse of
crude prices to 12-year lows around US$30 a bar-
rel.Increased Iranian oil output should feed the global
glut this year with the expected lifting of Western
sanctions on that country s exports, the US Energy
Information Administration said. The agency forecast
that a limited decline in US supplies next year and
steady growth in global demand will help ease the
glut only in the third quarter of 2017, the first decline
after nearly four straight years of gains.
In its first forecast for 2017, the EIA said global
oil production would likely rise to nearly 96.7 million
barrels per day from more than 95.9 million bpd
this year. Demand would grow by only 1.4 million
bpd in 2017, the same rate as 2015 and 2016. US
production, now expected to decline by 700,000
bpd this year to 8.7 million bpd, will fall by a slower
rate in 2017 to about 8.5 million bpd.
"If nothing big blows up and emerging economies
don t warm up, the oil price doesn t look likely to
go up until late 2017," said Kevin Book, an energy
policy analyst at ClearView Energy Partners.
The EIA also predicted that Iran s oil exports would
expand into 2017, growing by 500,000 bpd that year
after a 300,000 bpd increase in 2016, if Western
sanctions are lifted.
The timing of sanctions relief is uncertain, but
EIA assumed that implementation of the nuclear
deal will occur in the first three months of 2016, as
Iran has made "faster than expected progress" in
meeting obligations under the deal.
Continued strong production from Saudi Arabia
has added to the supply glut and US oil producers
have been hit hard. Oil prices sank this week on
concerns about losses on China s stock market. On
Tuesday, Brent and U.S. crude both briefly fell below
US$30 a barrel.
Brent crude should average US$40 a barrel in 2016
and US$50 a barrel in 2017, with U.S. prices averaging
about US$2 per barrel lower than Brent in 2016 and
US$3 lower in 2017.
Forty years ago America, still reeling from the 1973 oil
crisis, banned most exports of crude oil. That prohibition
was lifted by Congress in December 2015, and the first
shipment under the new rules set sail on December
31 from the Texan port of Corpus Christi. The renewed
flow of crude already is changing how oil is priced.
Not all barrels of oil are alike. Crudes can be viscous like tar or
so "light" that they float on water. Their sulfur content ranges from
the negligible ("sweet") to the highly acidic ("sour"). Though hundreds
of grades are bought and sold, traders use a handful of benchmarks
to make sense of the market. Brent, from the North Sea, is the current
international standard. Americans prefer to use a similar grade known
as West Texas Intermediate.
WTI once was the main global benchmark. It has a number of
advantages over Brent. For one thing, it arrives at the delivery point---
Cushing, Oklahoma---by pipeline, and so can be sold in batches of
variable size. Brent, in contrast, can be sold only by the tankerload.
As Brent sees fewer, bigger transactions, generating continuous prices
is tricky. The ever-shifting price of WTI can be observed directly,
making it more transparent.
Finally, Brent is umbilically connected to a declining oil province.
It comes from only a handful of oil fields, whereas a WTI contract
can be satisfied by any suitable oil delivered to Cushing.
WTI had one vital flaw, though. The export ban meant that it
could detach from world oil prices if America produced more crude
than expected, since the surplus could not be exported. For most of
the late 20th century that risk was hypothetical, as America s output
In recent years, though, the shale-oil boom has revived American
production. A glut of crude emerged, first at Cushing and then by
the cluster of refineries on the Gulf of Mexico. That pushed American
crude prices below Brent. The spread peaked in 2011 at US$28 a
barrel. As the price of WTI began to say less and less about the state
of the world market, traders spurned it in favor of Brent. Trading
in contracts linked to Brent overtook those linked to WTI in early
The resumption of American exports has changed all that. The
two benchmarks now trade at more or less the same price. WTI has
duly regained its position as the most traded oil benchmark.
This back-and-forth, however, may prove a distraction compared
with another shift in the oil market: Its center of gravity is moving
inexorably eastward. OPEC, a cartel of oil exporters, expects demand
in Asia to grow by 16 million barrels a day by 2040. If that happens,
Asia will end up consuming more than 46 million barrels a day, four
times as much as Europe. As Asia grows, it will become the dominant
force in the world market.
A good benchmark has to reflect supply and demand for oil wherever
it is used. WTI may continue to be influenced by bottlenecks in the
American market. Brent reflects the market for oil in northwestern
Europe. That was once a positive, but, as Europe s share of global
demand for oil declines, proximity to the continent is no longer the
advantage it was.
That suggests that an Asian benchmark will rise to the fore. The
Shanghai International Energy Exchange plans to launch its own
yuan-denominated contract this year.
The new benchmark will have trouble getting off the ground. For
one thing, China s capital controls make it difficult for foreigners to
buy the yuan needed to trade the contracts. The wild swings in
China s equity markets set an unnerving example for investors.
Time is on its side, however. @2016 The Economist
US sees no relief
from swelling oil
glut until late 2017
A crude measure may be
nearing the end of its run
With the T&T Energy Conference just days
away, there is a sobering reality that the
country s natural gas production is short
by an average of 400 million cubic feet
a day and the shortage is almost entirely
the result of curtailed production from the country s largest
natural gas producer, bpTT.
Highly placed sources at state-owned National Gas Company
(NGC) told the Business Guardian it is also worrying that
bpTT is not meeting its contracted gas supplies to the company
and this is one of the main reasons why the downstream com-
panies are experiencing as high as a 15 per cent curtailment
in their feedstock.
The shortage in supply from bpTT has also heavily affected
Atlantic LNG s reliability of supply to its global customers
while, at the same time, hammering the country s finances
at a time of low crude production and low energy prices.
Production statistics over the last six years show that the
decline of the country s natural gas sector mirror the fall in
bpTT s production. The production figures seen by the Business
Guardian go as far back 2009 when all the LNG trains were
producing and the country s methanol, ammonia and urea
production were already in place. There was no major growth
in demand for natural gas, mainly due to the fact that no new
projects were started in the energy sector in the last six years.
In 2009, T&T s natural gas production was---on average---
4.220 billion cubic feet per day (bcf/d).
At that time, bpTT was producing 2.526 bcf/d. In 2010
natural gas production continued to rise, averaging 4,330 bcf/d
and bpTT further ramped up production and was then producing
2.562 bcf/d. However, in that year there was the Macondo
disaster in the Gulf of Mexico and the company said it was
doing a global risk assessment and improving its global safety
which required, among other things, maintenance work on
many of its facilities. The company also said it would no longer
be in a position to keep gas behind pipe which it was not con-
tracted to provide.
Fast forward to 2014 at the end of the maintenance work
and the picture is significantly different.
The country s natural gas production falls from 4.330 bcf/d
to 4.071 bcf/d--- decline of 259 million cubic feet per day.
bpTT s average production drops from 2.562bcf/d to a mere
2.169 bcf/d, or a fall of 393 mmcf/d.
The figures show that during that time BHP Billiton s natural
gas production was significantly increased which helped reduce
the burden of bpTT s curtailment and also assist with the
falling production from BGTT.
The most recent data from the Ministry of Energy is up to
October 2015. During that period bpTT s performance worsened
to the point where they were no longer meeting their obligations.
According to the data, T&T s average production dropped to
3.830 or about 400 mmscf/d short of what is required to satisfy
demand. The company s production has also now fallen to
1.938 bcf/d , or about 550 mmscf/d lower than its 2011 peak.
Up to press time, bpTT officials had not responded to ques-
tions about meeting its contracted obligation to the NGC and
whether the reduced production was being used as a negotiating
tool against the NGC and Government. BGTT s production
during the same period fell by 120 mmscf/d but that would
have been easily taken up by BHP s higher production and the
slightly improved performance by EOG Resources which has
remained steady at about 500mmscf/d.
Only last week it was revealed that BGTT s attempt to develop
its Starfish field turned out to be a disaster with the company
losing two of its three wells.
bpTT blamed for gas pains
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