Home' Trinidad and Tobago Guardian : November 26th 2015 Contents ---Courtesy the Geological Society of T&T
BSc (Hons) Petroleum Geoscience --
University of the West Indies,
Trinidad and Tobago
Deepwater E&P has expanded phenom-
enally in recent years. Global oil supply is
currently 92 million bopd (Seng 2015).
Onshore and shallow water account for
60% and 33% of global production respec-
tively, while deepwater takes the remain-
ing 7% at 6 million barrels per day.
Despite the current downturn in oil
prices, deepwater growth is expected to
continue. Only 40% of deepwater discover-
ies are producing, while the rest await ap-
praisal or development. 75% of deepwater
expenditure is spent in the 'Golden Trian-
gle', the historically producing deepwater
region between West Africa, Brazil and the
Gulf of Mexico (see Figure 1).
T&T's 1st deepwater campaign took
place between 1999 and 2003, when eight
wells were drilled by BP, Arco, Shell and
Exxon in water depths ranging 1000 --
1400m. Unfortunately, none found com-
mercial hydrocarbons. Oil and gas shows
proved however, that a working petroleum
system exists. T&T re-opened its deep and
ultra-deep waters for competitive bidding
in 2006. This and several subsequent bid
rounds had little interest, and no blocks
were awarded until the taxation regime
was revised and made more attractive in
2011. Between 2012 and 2014, nine deep-
water blocks were awarded.
T&T is currently exploring these nine
frontier blocks in water depths of 1800 --
2200m. 3D seismic was completed in 2015
and the first well is to be spudded before
the end of 2016. As per the contracts, a
minimum of eight exploration wells are to
be drilled. All blocks are operated by BHP
Billiton, and partners include BP, Repsol
and BG. The main objective of this project
was to determine how small an oil or gas
field could be and still generate economic
rent, within the confines of the contracts
and tax regime. This is especially impor-
tant with today's low oil and gas prices.
Oil fields of reserves 100, 200 and 300
million barrels (mmbbl) and gas fields of
reserves 600, 1200, 2400 and 4800 billion
cubic feet (Bcf) were modelled at a range
of oil and gas prices.
THE MAIN CONCLUSIONS ARE:
1. The minimum obligatory expenditure
across the nine blocks is just over $US 1.1
billion, which has an NPV @10% of $0.77 bil-
lion in 2012 dollars. This includes eight ex-
ploration wells and 20,000km2 of 3D
seismic, gravity and magnetics. If all phases
are completed in all blocks, this becomes $3
billion with an NPV @10% of $1.75 billion.
This includes 26 exploration wells.
2. One oil and one gas field were mod-
elled respectively. For the reserves sizes
used (100 -- 300 mmbbl), the capital costs
for the oil field were between $3.2 and $5.6
billion. These were between $3.1 and $8.9
billion for the gas field (600 -- 4800 Bcf re-
serves). Production for all fields was via
FPSO with pipeline to Galeota. For oil, an
additional option of using shuttle tankers
instead of pipelines was also considered.
3. Economic means that the field must
attain a positive after tax Net Present
Value (NPV) @10%.
As of July 2015, WTI oil prices are below
the base case of $60/bbl used. At this
price only the field with 300 mmbbl re-
serves generates a marginally positive
post-tax NPV (of $90M). Assuming a RF
of 30%, the minimum economic field size
at current prices will therefore be approxi-
mately 1 billion bbl OIIP.
As of July 2015, Current Henry Hub natural
gas is under $3/mcf, our base case price. Based
on the assumptions made, even a huge gas
field with 8 Tcf in place (4800 Bcf reserves)
could not generate a positive post-tax NPV.
The minimum economic gas field size was not
calculated. However, a prediction can be made;
20 Tcf GIIP (12 Tcf recoverable) may be com-
mercially viable at current prices. This is on the
scale of the recent discoveries in East Africa.
The economics for oil is therefore much more
favourable than gas on a boe basis.
4. First tax revenues are forecasted as
2026 for oil and 2029 for gas. The first
PSCs were executed in 2012, so first pro-
duction is optimistically forecasted for 14 to
17 years later. The PSC profit sharing mech-
anism guarantees government an annual
portion of gross revenue. Government take
ranges 55 -- 62% for the fields modelled.
5. Strengths of tax regime:
proven deepwater provinces like Ghana,
Brazil, Australia and Nigeria. This has
been a major factor in successful PSC ex-
ecution between 2012 and 2014.
• Cost Recovery Limit of 80% allows in-
vestment to be recovered quickly.
• There are no signature bonuses unless
bidders have tied.
• Production and signature bonuses are
• There is no state participation, which is ef-
fectively a form of tax. The operator is there-
fore free to choose all its own partners.
• The mechanism by which taxes are paid
out of government share reflects strong
fiscal stability over the long term.
Weaknesses of tax regime:
• Uplifts for exploration wells may lead to
• Non-consolidation of these PSCs can
lead to an overall negative NPV, even if
some fields are commercially viable.
• The government share is often too small to
extract the required taxes. It is unclear how
these taxes are then carried forward. It is
predicted that government never receives
the full taxes owed over the field life.
• Paying taxes out of government share is
an administratively arduous task that re-
quires transferring money from the
MEEA to Ministry of Finance.
• The individual tax rates may be irrelevant
as all taxes are taken out of the govern-
Guardian www.guardian.co.tt Thursday, November 26, 2015
Figure 1 - T&T within the
Golden Triangle of deep-
water production (after
BBC article on deepwa-
ter drilling 2010).
Figure 2 -- T&T concession
map with 9 active deepwa-
ter blocks highlighted in
red (after MEEA conces-
sion map 2012).
Links Archive November 25th 2015 November 27th 2015 Navigation Previous Page Next Page