Preliminary Results
Soco International PLC
15 March 2007
SOCO International plc
('SOCO' or 'the Company')
Preliminary Results For The Year Ended 31 December 2006
SOCO is an international oil and gas exploration and production company,
headquartered in London, traded on the London Stock Exchange and a constituent
of the FTSE 250 Index. The Company has interests in Vietnam, Yemen, Thailand,
the Republic of Congo (Brazzaville) and the Democratic Republic of Congo
(Kinshasa) with production operations in Yemen.
The Company today announces its Preliminary Results for the year ended 31
December 2006.
Key Highlights
• 20% increase in proven and probable reserves (greater than 40%
increase in Vietnam and 30% in Yemen);
• 34% increase in revenue to $76.5 million (2005 $57.2 million);
• Increase of 43% in pre-tax profits to $48.2 million (2005
$33.7million);
• 70% exploration and appraisal drilling success rate during the year;
• 19% increase in production;
• Pilot development plan approved on Block 9-2 in Vietnam with first oil
expected in 2008;
• Extensive pre-drill activity across the West Africa portfolio;
• Convertible bonds issue netted the Group $243 million;
• Acquisition of additional 2% working interest in Block 16-1 Vietnam;
• Accelerated development in Thailand associated with farm-out.
Ed Story, Chief Executive Officer, commented:
'There is no question that 2006 was a banner year for the Company. However, the
2007 drilling programme in Vietnam alone will expose the Company to unrisked
recoverable resource potential of 2.5 billion barrels of crude equivalent.'
15 March 2007
Enquiries:
SOCO International plc Tel : 020 7747 2000
Roger Cagle
Executive VP, Deputy CEO and Chief Financial Officer
Pelham PR Tel : 020 7743 6676
James Henderson
Alisdair Haythornthwaite
CHAIRMAN'S AND CHIEF EXECUTIVE'S STATEMENT
The past 12 months have been a watershed year for SOCO. Our hugely successful
Vietnam project has evolved from pure exploration to development, appraisal and
exploration; the potential of our Yemen project has been increasingly realised
through Basement development drilling and increased facilities capacity and our
West Africa portfolio has been expanded to increase the potential to repeat
these successes. The Company has successfully de-risked its chances of long term
success whilst maintaining significant upside that offers plenty of opportunity
for exponential future growth.
We have again been very successful with the drill bit with our exploration and
appraisal drilling success in Vietnam exceeding 70%. This coupled with the
successful infill/injector drilling in Yemen has led to an increase in 2P
reserves net to our working interest of 32.4 million barrels and 9.4 million
barrels in Vietnam and Yemen, respectively. Before factoring in the reserve
reduction associated with farming out half of our Marine XI interest in the
Republic of Congo (Brazzaville), 2P reserves increased to 172.5 million barrels
in 2006. Following the farm-out, 2P reserves at the end of 2006 equalled 160.6
million barrels.
FINANCIAL AND OPERATING RESULTS
After tax profit from continuing operations hit a record high of $29.1 million
in 2006 exceeding that of the previous year that totalled $20.3 million. Largely
as a result of the ongoing facilities expansion and infill drilling programme at
the Kharir field in Yemen, production net to the Company's working interest
increased, rising to 6,766 barrels of oil per day (BOPD) in 2006 from 5,684 BOPD
the prior year.
The Group had its highest ever capital expenditures during the year with an
extensive exploration/appraisal drilling programme in Vietnam, significant
facilities expansion and development drilling in Yemen and its initial 3D
seismic acquisition in Congo (Brazzaville). In order to bridge the period prior
to translating its successes into operating cash flow, the Company guaranteed a
convertible bonds issue of $250 million in May. Capital expenditure on
operational activities rose to $114.3 million in 2006 from $76.2 million in
2005. With net proceeds from the issue of convertible bonds equalling $243.0
million and cash generated by operations of $53.0 million, the cash balance rose
by $136.8 million to $187.8 million at year end 2006.
2006 OPERATIONS REVIEW
VIETNAM
The year got off to an impressive start when the second well drilled in the same
fault block as the initial 2005 discovery well on the Te Giac Trang (TGT)
structure, the TGT-2X, tested at a total combined flow rate of approximately
17,500 barrels of oil equivalent per day (BOEPD) from the Miocene Lower Bach Ho
5.2 (LBH 5.2) and Oligocene 'C' intervals. The good news continued when the rig
moved to a location on the fourth fault block on the TGT structure and the
TGT-3X tested at a combined maximum rate of 9,908 BOEPD.
Buoyed by so much early success on the TGT structure, the rig moved
approximately 30 kilometres south of the TGT-3X discovery to spud the initial
well on the 'L' prospect, the Te Giac Vang (TGV) 1X well. The TGV structure was
a priority not only because of an apparent large shallow structure with good
Miocene potential, but also because success here would hold the rights for the
apparently even larger high potential Basement/Oligocene structure. Enthusiasm
was tempered by realism as the TGV-1X intersected poorly developed reservoir
sands in the primary targeted Clastic sequence at the LBH 5.2 horizon. The well
did have good oil shows in several Oligocene sands when the well was deepened.
However, after analysis of the logs, it appeared that these lacked sufficient
permeability.
Following the TGV well, the rig was moved to drill the sidetrack to the Ca Ngu
Vang (CNV) 4X well on Block 9-2 that was temporarily suspended late in 2005
after encountering unexpected high pressures in the Oligocene sequence above the
Basement. We were back on track when the sidetrack of the appraisal well,
CNV-4XST, tested at 7,050 BOEPD from Basement. This result provided final
confirmation that CNV was ready to move into development. All regulatory
approvals were received and the pilot development plan was approved in December
2006. From that point forward, Petrovietnam has funded its full share of costs
on Block 9-2.
With a new rig, activity once again focused on Block 16-1. The third 2006
appraisal well on the TGT structure, the TGT-4X, was drilled on the H3 fault
block between the initial discovery well, TGT-1X, and the TGT-3X. The primary
target, a lower Miocene trap, was breached due to late movement on a fault
located south of the TGT-4X well. The Oligocene 'D' interval, a new reservoir on
the TGT structure, flowed at a rate slightly over 600 BOPD on a short test.
The rig then moved to drill the first exploration well on the Te Giac Xang (TGX)
structure on Prospect 'K', approximately 15 kilometres west of the TGT
structure. Although the TGX-1X encountered reservoir sands, it was abandoned
after initial analysis indicated that it was not drilled within structural
closure.
To close out the 2006 drilling campaign, the rig moved back to drill the fifth
well on the TGT structure as a final prelude to seeking a declaration of
commerciality on the field. The TGT-5X had a total combined maximum flow rate of
approximately 16,430 BOEPD from the LBH 5.2 and Oligocene 'C' intervals.
Thus, sandwiched between clear success with the TGT appraisal programme, there
were inconclusive results when looking for repeatability on the Clastics fairway
elsewhere on Block 16-1. The 3D seismic acquired during the year is expected to
be a critical tool in leading to drilling success in 2007 outside the proven TGT
structure.
YEMEN
During 2006, the East Shabwa Block 10 consortium continued its programme to
further appraise the Kharir field and increase production capacity from the
Block. Drilling results and the addition of a self-contained production facility
enabled the fields to exceed all previous production records averaging more than
40,000 BOPD.
A number of successful development wells were drilled in the Kharir field (KHA)
during 2006. These include the KHA-1-12 well in the western part of the
structure, the KHA-1-14 well in the southern flank of the structure, the
KHA-1-07.G1 sidetrack, which was drilled as a water injection well but completed
as a producer based on drilling results and the KHA-1-16 drilled on the last 3D
line on the eastern extension of the field. These wells are all connected to the
production facilities and were tested at rates between 5,500 and 8,400 BOPD.
Significantly, the highest rate was from the eastern extension well. This
portends further extension of the field in that direction.
The consortium also had a very active exploration programme in the northern part
of the Block that yielded one discovery, but overall proved inconclusive as to
the additional potential in that area.
WEST AFRICA
The Group added to its West Africa portfolio when its 85% owned subsidiary
acquired an 85% working interest in the 800 square kilometre Nganzi Block,
onshore the Democratic Republic of Congo (Kinshasa). As operator, the Group
carried out a reconnaissance aeromagnetic and gravity survey over the onshore
extension of the coastal basin in order to delineate prospective areas for
hydrocarbon generation and migration delineating several leads, interpreted as
large horst blocks.
In September, the Group's 85% owned subsidiary signed an agreement to farm-out a
37.5% interest in the Marine XI Block, offshore the Republic of Congo
(Brazzaville), whilst retaining a 37.5% working interest. As operator, the Group
began evaluation of the Marine XI Block when it acquired an approximate 1,200
square kilometre 3D seismic programme in the fourth quarter of 2006.
THAILAND
In April, the Group's Thai subsidiary signed a Participation Agreement that
could accelerate the development of the project in the Bualuang field in the
Gulf of Thailand and provide meaningful production as early as the first half of
2008.
The assignment of interest, predicated on meeting certain work requirements and
subject to the appropriate regulatory approval by the Government of Thailand,
enables the Farmee to earn up to a 60% working interest, whilst allowing the
Group to focus resources on higher profile projects in Vietnam and Yemen.
CORPORATE
CONVERTIBLE BONDS
Primarily to fund the impending development of its Vietnam projects, in May of
2006, the Company was the guarantor of an offering of $250 million in guaranteed
bonds convertible into preference shares of the issuing subsidiary (Bonds),
which are exchangeable for fully paid ordinary shares of SOCO. The size of the
offering was increased from $200 million due to strong institutional demand, but
was still six times oversubscribed upon issue. The Bonds will pay a coupon of
4.50% per annum and will initially be convertible into an aggregate of
approximately 6.238 million ordinary shares. The initial conversion price is
£21.847 per ordinary share, a premium of 42%. The Bonds will be repaid at 100%
of their principal amount on 16 May 2013 unless previously converted or
redeemed.
INCREASE IN VIETNAM INTERESTS
In June, the Group seized the opportunity to increase its interest in the
promising Clastics play in the Cuu Long Basin of Vietnam by acquiring OPECO
Vietnam Ltd., which holds a direct 2% interest in Block 16-1. The purchase price
was $22 million.
BOARD CHANGES
In December, the Company's Non-Executive Chairman, Patrick Maugein, died after a
long illness. Patrick was a friend, a tireless worker on behalf of SOCO and a
champion of the Company. The Company benefited significantly through its
relationship with Patrick and he will be missed. At the December Directors'
meeting, the Board voted unanimously to accept the Nominations Committee
recommendation to appoint Rui de Sousa to succeed Patrick.
OUTLOOK
As active as we were in 2006, we will be even busier on the operations front in
2007. The development programme on Block 9-2 in Vietnam will be in full swing
leading up to expected first oil in 2008. With only the rest of this year before
licence expiry to explore Block 16-1 in Vietnam, barring an extension, we expect
to drill up to eight exploration wells. We have prioritised an exploration well
on a TGT 'look-a-like' structure, Prospect 'S', identified from the 2006 3D
seismic programme. This is expected to be followed by a high potential
Oligocene/Basement target in the deep 'E' prospect that essentially underlies
the shallower 'L' prospect. A declaration of commerciality on the TGT field is
imminent.
We should see the initial results from the water flooding that began last year
in the Kharir field in Yemen. The combination of the water flood, additional
infill drilling and expanded production capacity should allow considerable
growth in oil sales in Yemen, albeit after an early 2007 cutback due to
additional facilities installation.
While evaluation of our West Africa portfolio is in its infancy, indeed, even
the portfolio itself is evolving, 2007 will be a busy year in terms of
pre-drilling activity. We are processing and will soon be interpreting the 3D
seismic acquired last year on Marine XI offshore Republic of Congo
(Brazzaville). It is conceivable that we could be ready to drill in the latter
part of the year, but more likely in 2008. We expect to be acquiring 2D seismic
on the Democratic Republic of Congo (Kinshasa) Nganzi Block.
We know that not every well drilled in 2007 will be a success. We understand
that even on the highly prospective Vietnam Block 16-1 Clastics play, the
chances of drilling success are only in the 25% range. However, we have positive
indications for further good news from the Vietnam exploration programme. There
certainly will be an abundance of news. We trust that you share our enthusiasm
for what is in store.
Rui de Sousa Chairman
Ed Story President and Chief Executive
REVIEW OF OPERATIONS
The high impact drilling programme in Vietnam continued apace throughout 2006
whilst production in Yemen experienced a major uplift and significant progress
was made in the development of the Kharir field. The drilling success ratio in
Vietnam exceeded 70% as five of seven exploration/appraisal wells were
discoveries.
Results from the Yemen appraisal programme and production capacity expansion
translated into an immediate economic impact as production net to the Group's
working interest was up approximately 20% averaging 6,766 barrels of oil per day
(BOPD) versus 5,684 BOPD in 2005.
VIETNAM
SOCO holds its interests in Vietnam, all in the Cuu Long Basin offshore, through
its 80% owned subsidiary SOCO Vietnam Ltd. (SOCO Vietnam) and through its 100%
ownership of OPECO, Inc. SOCO Vietnam holds a 25% working interest in Block 9-2,
which is operated by the Hoan Vu Joint Operating Company (HVJOC) and holds a
28.5% working interest in Block 16-1, which is operated by the Hoang Long Joint
Operating Company (HLJOC). OPECO, Inc. holds a 2% interest in Block 16-1.
Both Blocks are on trend with several major Basement and Tertiary discoveries in
the Cuu Long Basin. Both are also contiguous to the Bach Ho field, where 2006
production reportedly averaged approximately 191,000 BOPD and 150 million cubic
feet of gas per day (MMCFD), and the Rang Dong field, where production
reportedly averaged approximately 42,000 BOPD, primarily from the Basement.
Review of 2006 activities
Block 16-1
In March 2006, the TGT-2X appraisal well on the Te Giac Trang (TGT) structure,
an up-dip follow-up well to the previous year's TGT-1X discovery well, tested
with a total combined flow rate of approximately 17,500 BOEPD from the Miocene
Lower Bach Ho 5.2 (LBH 5.2) and Oligocene 'C' intervals.
Two main pay zones were tested within the LBH 5.2 interval, one between 2,763
and 2,817 metres and the other between 2,666 and 2,726 metres. A total of 89
metres of pay was confirmed by log analysis in this reservoir horizon.
The combined stabilised flow rate from the two Miocene zones was 14,053 BOEPD
comprising 12,615 BOPD of 38 degree API gravity crude and approximately 8.63
MMCFD through a one inch choke size. Flow rates were limited due to mechanical
restrictions in the surface separation equipment.
The drill stem test over the Oligocene 'C' interval tested water-free at a
stabilised rate of 3,300 BOPD of 37.5 degree API gravity crude and approximately
0.88 MMCFD through a 52/64 inch choke size.
As was expected from the log analysis, water was produced from the lower set of
perforations in the Miocene. The approximate 8% water cut provided evidence of
the presence of an aquifer, which will be factored into plans for the field's
depletion management.
A third reservoir horizon, the LBH 5.1 which is considered to be oil-bearing and
productive, was also identified, but not tested as this would limit the ability
to retain the well as a future producer, as originally designed. This horizon
had 18 metres of net pay and, from the analysis of logs and oil samples from
wireline formation tests, is considered to be oil-bearing and productive.
Following the temporary suspension of the TGT-2X well, the rig moved immediately
to drill a follow-up appraisal well, the TGT-3X, approximately 10 kilometres to
the south on a separate fault block on the structure. A drill stem test was
conducted in the LBH 5.2. The tested interval, perforated between 2,827 and
2,887 metres, flowed at a combined maximum rate of 9,908 BOEPD comprising 9,008
BOPD of 40.5 degree API gravity crude and approximately 5.4 MMCFD through an 88/
64 inch choke size.
Log analysis of the well indicated approximately 68 metres of net pay were
present in the LBH 5.2. Additionally, approximately six metres of net pay in the
Lower Oligocene 'C' interval were also identified but not tested.
The LBH 5.2 reservoir sands encountered in the TGT-3X well are the same as those
tested in the TGT-1X and TGT-2X wells. This proved the presence of a laterally
extensive reservoir sand in the Block, further reducing the risk of the other
prospects and leads along the play fairway.
The third well drilled on Block 16-1 during 2006 was the first exploration well
on the 'L' prospect approximately 30 kilometres south of the TGT-3X discovery.
The Te Giac Vang 1X (TGV-1X) spudded on 2 May and reached a total measured depth
(MD) of 3,926 metres in the Upper Oligocene. The well was deepened from its
original prognosis due to the presence of encouraging hydrocarbon shows
continuing below the original target depth. It was primarily positioned to test
a closure at the LBH 5.2 level, the main productive horizon at the TGT
discoveries.
The well intersected a clastic sequence at the LBH 5.2 horizon, however the
reservoir sands were poorly developed at the location and no pay was
encountered. The sediments encountered suggested that the well was located
outside the LBH 5.2 play fairway and that this fairway is to the north and west
of the TGV-1X location.
The well was also drilled into the Oligocene, however the location was down-dip
on the flank of the structure. Despite being in a flank position, good oil shows
were encountered in several sands. After analysis of the logs, although the
sands were confirmed to be hydrocarbon bearing, it appeared that these lacked
sufficient permeability to produce at commercial rates and were therefore not
tested.
These overall encouraging well results are being evaluated and the seismic
re-interpreted prior to drilling a follow-up well to fully test the Oligocene in
a more prospective up-dip position. The well also penetrated the source rock
section at the top of the Oligocene validating the geological interpretation and
confirming the potential of the deep Oligocene and Basement prospect underlying
the shallower closures.
The 2006 drilling campaign continued on the Block 16-1 play fairway when the
Transocean Trident 9 jack-up rig spudded the TGT-4X well on the 'H3' fault block
in the TGT structure on 31 August. This third appraisal well on the TGT
structure, was drilled on a separate fault block between the initial discovery
well, TGT-1X and the TGT-3X. The well intersected the hydrocarbon bearing Lower
Miocene reservoir interval as predicted. However, the trap had been breached and
only residual oil was encountered. The well also encountered hydrocarbons in the
Oligocene 'D' interval, a new reservoir on the Block, and flowed at a rate
slightly over 600 BOPD on a short test.
Subsequent detailed review of the seismic identified that the breaching of the
Lower Miocene trap was due to late movement on a fault located south of the
TGT-4X well. This appears to be the only such fault on the TGT field and the
effect is considered to be local to this well.
The following well, in October, was a test of Prospect 'K', a subtle closure to
the west of the higher amplitude TGT structure. After encountering reservoir
sands, the first exploration well on the Te Giac Xang (TGX) structure on
Prospect 'K' was plugged and abandoned when initial analysis indicated that it
was not drilled within structural closure. Located in a previously untested
portion of the Clastics fairway on Block 16-1, the TGX-1X well was drilled to a
depth of 3,506 metres. Finding reservoir is the main risk in drilling in this
fairway, so the presence of reservoir in TGX-1X is a positive indicator for
future success as drilling locations step out from the initial TGT discovery.
The seismic over the area is being reprocessed and remapped to better define the
structure for a possible second well.
The final well drilled in 2006 and the fifth appraisal well on the TGT structure
was drilled on the 'H2' fault block. The TGT-5X had a total combined maximum
flow rate of approximately 16,430 BOEPD from the LBH 5.2 and Oligocene 'C'
intervals.
The first drill stem test, over the 32 metre Oligocene 'C' interval, tested
water-free at a maximum rate of 7,098 BOPD of 36.5 degree API gravity crude and
approximately 2.07 MMCFD through an 80/64 inch choke size. The most prolific
interval in the other successful wells drilled on TGT, the LBH 5.2 pay zone, was
perforated and tested separately between 2,841 and 2,866 metres with a maximum
flow rate of 8,987 BOEPD comprising 8,104 BOPD of 41 degree API gravity crude
and approximately 5.3 MMCFD through an 80/64 inch choke size.
On the TGT structure, only the southern most fault block in the five fault block
structure remains to be drilled. The LBH 5.2 and Oligocene 'C' reservoirs
encountered in the TGT-5X well appear to be the same as those tested in the
previous TGT wells. With an 80% drilling success rate on the TGT structure and
tests ranging from approximately 9,000 BOEPD to approximately 17,500 BOEPD,
activities are now focussed on early approval for development of the field.
The rig was moved to Block 9-2 to drill the initial Clastics well on the Ca Ong
Doi (COD) structure after a long delay due to inclement weather.
Block 9-2
Drilling operations recommenced on 5 June 2006 into the 'D' fault block of the
Ca Na Vang (CNV) structure to drill the sidetrack to the CNV-4X well on Block
9-2 that was temporarily suspended in 2005 after encountering unexpected high
pressures in the Oligocene sequence above the Basement. The re-entry and
sidetrack of the appraisal well, CNV-4XST, tested at a maximum combined rate of
approximately 7,050 BOEPD comprised of approximately 5,333 BOPD and
approximately 10.3 MMCFD. The open hole test was conducted over a 13 hour period
from a Basement interval of approximately 1,350 metres.
Log analysis of the Oligocene 'E', penetrated by this well, indicated that the
interval lacked permeability. The CNV-4X ST was drilled to a MD of 6,330 metres
making it the longest MD well to be drilled in Vietnam, exceeding the previous
record set by the HVJOC when it drilled the CNV-3X appraisal well in 2005. The
well was suspended as a producer.
Preparations for development of the CNV field picked up momentum in April of
2006 following the unanimous approval of the Declaration of Commerciality on the
field by the shareholders of the HVJOC. Petrovietnam officially approved the
Pilot Development Plan in December. Subsequent to this approval, Petrovietnam
has become a full paying participant in its 50% interest in Block 9-2.
Vietnam has become a participant in the World Trade Organisation (WTO).
Following its admission into the WTO, portions of the state operated
enterprises, including Petrovietnam, are expected to be privatised. This
portends a change in negotiating certain aspects of the development programme,
particularly a gas sales agreement as the gas group is expected to be an early
candidate for privatisation. However, discussions on the sales agreement for the
associated gas produced from the CNV field have continued. Equipment and
materials are being ordered and fabrication of various structures will begin
soon in anticipation of having first oil in the first half of 2008.
The rig, which had been conducting the Group's Vietnam drilling programme since
the beginning of 2005, moved out of Vietnamese waters after completion of the
CNV-4XST. However, the drilling campaign continued uninterrupted with the
Trident 9 drilling rig, which the JOCs had contracted in 2005, commencing
operations back on Block 16-1. A further two rigs were put under contract during
the year to conduct an even more extensive 2007 drilling programme.
Subsequent events and 2007 outlook
The drilling rig that began operations on Block 16-1 in the third quarter of
2006 was delayed from moving to a Block 9-2 drilling location on the COD
structure after completing the TGT-5X well due to inclement weather that
prevented the rig from being safely towed. Accordingly, the COD-2X Clastics
target well did not spud until 16 February 2007. Although the well encountered
sands in the Oligocene and Lower Miocene, there was no significant oil pay
encountered and the well was subsequently plugged and abandoned and the rig
moved back to Block 16-1.
Although the rig currently working is only available into the second quarter of
this year, the JOCs have already contracted two other rigs - one of which is
expected to be available late in the first quarter or early in the second
quarter and the other later in the second quarter. The prognosed drilling
programme calls for eight wells on Block 16-1 and three to five development
injector/producer wells on the Block 9-2 CNV field as it prepares for first oil
in the first half of 2008.
Efforts are underway to obtain a declaration of commerciality for the TGT
structure. The front-end work required to transition operations from the
exploratory phase to the development phase is in progress with the hopes to
allow first oil from Block 16-1 sometime in 2009.
The exploration phase on both blocks is set to expire at the end of 2007 unless
further extended by agreement with the Vietnamese Government. Thus the 2007
drilling campaign is extremely important in terms of fully evaluating the blocks
and securing areas for longer term development.
YEMEN
Throughout the year, the East Shabwa Block 10 consortium continued its programme
to further appraise the Kharir field and to increase production capacity from
Block 10. The East Shabwa Block 10 consortium comprises Comeco Petroleum, Inc.
(28.57% interest), in which SOCO holds a 58.75% interest, TOTAL E&P Yemen
(28.57% interest and operator), Occidental Yemen Ltd. (28.57% interest) and
Kuwait Foreign Petroleum Exploration Co. (14.29% interest).
Drilling results and the addition of a self-contained production facility have
enabled the fields to exceed all previous production records. For the second
consecutive year, production increases were significant-circa 40% and 22% for
2005 and 2006, respectively. During the year, production exceeded 40,300 BOPD,
up almost 7,400 BOPD from the 32,937 BOPD year average the previous year,
despite having to curtail production due to safety and production management
reasons below the 45,000 BOPD plateau reached earlier in the year.
Production from the East Shabwa Development Area (ESDA), approximately 80% of
which originates from the Kharir field, is transported by pipeline and
commingled with production from the neighbouring Masila Block before
transportation by pipeline to the coastal Ash Shihr export terminal. SOCO's
crude entitlement is sold under a 12-month spot market contract.
Review of 2006 activities
A number of successful development wells were drilled in the Kharir field (KHA)
during the first half of 2006. These include the KHA-1-12 well in the western
part of the structure, the KHA-1-14 well in the southern flank of the structure
and the KHA-1-07.G1 sidetrack, which was drilled as a water injection well but
completed as a producer based on drilling results. These wells are all connected
to the production facilities and were tested at rates between 5,500 and 8,000
BOPD.
The KHA-1-16 well, drilled on the eastern most 3D seismic line as part of the
continuing appraisal and development of the Basement reservoir in the Kharir
field, tested at over 8,400 BOPD. The implications of the results of this edge
of field are that the field could have a substantial eastward expansion.
Most of the drilling activity in the Kharir field in the second half of 2006 was
spent on the drilling of water injection wells to provide pressure support for
the Basement production. These include the KHA-1-15, KHA-1-17, KHA-1-19 and the
KHA-2-18 wells. In addition, the gas injection well, KHA-1-11 was completed with
two open hole sections to maximise the injection capacity of the well.
The appraisal of the Kharir North area has continued with the KHA-3-08 drilled
to the very northwest of the mapped area of the structure. Testing operations on
this well are ongoing.
Activity to enhance the recovery of the Biyad reservoir horizons at both Atuf
and Kharir are also ongoing. At Atuf the ANW-012 and ANW-013 infill production
wells encountered the reservoir horizons higher than expected. These have
provided encouragement for more efficient reservoir recovery.
The thrust of the exploration programme in 2006 was in the northern part of
Block 10 in the Jathma/Wadi Taribah area. The first Jathma exploration well, the
JAT-01 that tested early in the year over 1,900 BOPD, was placed on long term
production in the third quarter of the year. The oil produced is trucked to the
existing Kharir facilities for processing and export.
Two other exploration wells in the Jathma area, the JAT-02-ST and the
exploration well on the eastern side of the Jathma area, JAT-04, encountered
significant oil columns, but did not flow commercial volumes of hydrocarbons
when tested. An evaluation of the results of all the Jathma area wells drilled
to date is underway.
Subsequent events and 2007 outlook
Drilling of development and injector wells in the Kharir field to increase
Basement productivity will continue throughout the year. In particular,
delineation of the eastern end of the field will be a priority in 2007.
Additionally, the KHA-1-20 and KHA-1-22 Biyad oil production wells are being
drilled currently to accelerate and improve the recovery from the Clastics
horizon.
The additional surface facilities required to provide injection capacity are
being installed and the predrilled water injection wells will be connected
during the middle of 2007. Currently, the final elements of the commissioning of
the gas injection equipment are being completed prior to commencing gas
injection to provide pressure maintenance in the crestal area of the Basement.
Production capacity is expected to continue to increase during the year as
various initiatives progress. Together with adding water injection capability to
improve pressure maintenance in the Basement reservoir, considerable productive
capability should be added throughout the year, albeit after an early 2007
cutback pending the installation of these facilities.
Three drilling rigs are expected to continue operating throughout the year. As
at the date of this publication three rigs are under contract on Block 10 and
are drilling in the Kharir field. One rig is expected to be used for exploratory
drilling in the southeast corner of the Block later in the year.
REPUBLIC OF CONGO (BRAZZAVILLE)
SOCO Exploration and Production Congo (SOCO EPC), the Company's 85% owned
subsidiary was initially awarded a 75% interest in the Marine XI Block, offshore
the Republic of Congo (Brazzaville) in 2005. The terms of the Production Sharing
Agreement signed by the Societe Nationale des Petroles du Congo (SNPC) and SOCO
EPC was approved during the Congolese Parliament and the Senate extraordinary
session in the first quarter of 2006. The law became effective 30 March when
signed by the President of the Republic.
The Block, located in the Lower Congo Basin, is in shallow water adjacent to the
coast with water depths ranging up to 110 metres and covers approximately 1,400
square kilometres. There has been previous exploration activity on the Block
resulting in four oil discoveries, the largest of which has initial recoverable
reserves estimated to be in the 30 to 60 million barrel range.
Review of 2006 activities
In September, SOCO EPC entered into an agreement to farm-out an 18.75% interest
in the Marine XI Block, offshore the Republic of Congo (Brazzaville), to each of
a subsidiary of Lundin Petroleum AB and to Raffia Oil SARL. SOCO EPC retained
operatorship with a 37.5% working interest in the Block. The regulatory
authorities of the Government of the Republic of Congo (Brazzaville) ratified
the farm-out on 4 January 2007.
Acquisition of an approximate 1,200 square kilometre 3D seismic programme was
completed in the fourth quarter. By employing the modern seismic techniques that
the Company successfully applied in Vietnam to map the Basement reservoir, SOCO
EPC expects to exploit the potential of the pre-salt section.
Subsequent events and 2007 outlook
Processing and interpreting the 3D seismic acquired in 2006 will be the
priority. Although it is possible that SOCO EPC could be ready to drill in the
latter half of this year, it is more likely that drilling will commence in the
first half of 2008.
DEMOCRATIC REPUBLIC OF CONGO (KINSHASA)
In July, the Company's 85% owned subsidiary, SOCO DRC Limited (SOCO DRC), signed
subject to presidential decree, a Production Sharing Contract with the
Government of the Democratic Republic of Congo (Kinshasa) and La Congolaise des
Hydrocarbures (Cohydro), the state owned oil company, wherein it acquired an
interest in the Nganzi Block. The Block, onshore the Democratic Republic of
Congo (Kinshasa), comprises an area of approximately 800 square kilometres. SOCO
is the designated operator with an 85% working interest in the Block.
Review of 2006 activities
Most of the activity during the year was focused on detailed analysis of a
reconnaissance aeromagnetic and gravity survey over the onshore extension of the
coastal basin in order to delineate prospective areas for hydrocarbon generation
and migration. The survey indicated the presence of a deep pre-salt source
graben in the northern part of the basin in the Nganzi Block. Regional mapping
shows the graben to be on trend with the source basin for the M'Boundi field in
the southern part of the Republic of Congo (Brazzaville). Several leads,
interpreted as large horst blocks, have been identified on the Block.
Subsequent events and 2007 outlook
Prior to acquiring a 2D seismic survey, the Company expects to conduct a
geochemical survey to further define the prospectivity of various identified
structures. Initially, the plan is to acquire some 300 to 500 kilometres of 2D
seismic. Dependent upon the timing of the seismic acquisition, processing and
interpretation could be substantially completed this year. Any meaningful work
programme is conditional upon obtaining the presidential decree.
THAILAND
SOCO's 99.93% owned Thailand subsidiary, SOCO Exploration (Thailand) Co. Ltd.
(SOCO Thai), holds a 100% interest in Block B8/38 located offshore in the Gulf
of Thailand. An application and development plan was approved in 2006 by the
Thailand Department of Mineral Fuels to convert the concession into a production
licence on the Bualuang discovery on the Block.
Review of 2006 activities
Upon securing approval from the Thailand Department of Mineral Fuels to convert
the field from an exploration to a production licence in the first quarter of
2006, SOCO Thai signed an agreement to allow a two group consortium to earn up
to a 60% working interest in the licence. If the earn-in terms of the agreement
are fulfilled, SOCO Thai would retain a 40% working interest in the field. The
assignment of interests in the agreement is subject to approval of the
appropriate regulatory authorities of the Government of Thailand.
During the year, the farmee's efforts were directed toward the planning and
contracting of several frontend activities precluding the start-up of
development operations in 2007.
Subsequent events and 2007 outlook
In January, the farmee group was consolidated with GFI Oil and Gas Corporation
(GFI) becoming the sole farmee. GFI expects to conclude a high resolution 100
kilometre 2D seismic programme during the second quarter of 2007 in preparation
for drilling the initial commitment well and completing the milestone to earn a
20% interest in the Bualuang field.
Further, GFI has already entered into a contract with a floating production,
storage, and offloading vessel with the expectation of concluding the work
programme to earn an additional 40% interest by funding 92% of the costs to take
the project to first oil. GFI estimates first production would be achieved in
the first half of 2008.
OTHER AREAS OF INTEREST
CABINDA
In October, the Company was informed by Sonangol, the national oil company of
Angola, that it would have a participating interest in the contractor group of
the Cabinda Onshore North Petroleum Concession. The Group anticipates formal
completion of the assignment in the first half of 2007. Preparation has begun
for the acquisition of a high resolution aeromagnetic and gravity survey over
the Block.
LIBYA
The Group maintains its shareholding in the ODEX Exploration Limited (ODEX)
joint venture. The ODEX shareholding comprises SOCO North Africa Ltd. (34%), and
subsidiaries of Oilinvest (Netherlands) B.V. (46%) and Joint Stock Bank of the
Gas Industry Gazprombank (20%). From SOCO's standpoint, the niche for ODEX was
to participate with one or more indigenous Libyan companies in exploiting
existing but problematic development opportunities. While the focus in the past
two years of the Libyan National Oil Company has been on open exploration bid
rounds, it announced in late 2006 an initiative to negotiate for participation
in production and development projects.
Accordingly, the Group will continue to assess its participation in the
consortium in light of reasonable expectations of success. It is anticipated
that ODEX will continue to be the vehicle through which the Group will explore
various opportunities that may arise in Libya and certain parts of Africa as the
consortium is well placed to take advantage of its strong regional
relationships.
Consolidated income statement
for the year to 31 December 2006
2006 2005
Notes $000's $000's
Continuing operations
Revenue 3 76,476 57,160
Cost of sales (21,162) (19,588)
Gross profit 55,314 37,572
Administrative expenses (8,772) (5,295)
Other operating expenses (231) (1,013)
Operating profit from continuing operations 3 46,311 31,264
Investment revenue 9,292 2,042
Other gains and losses 690 853
Finance costs (8,136) (497)
Profit before tax from continuing operations 48,157 33,662
Tax 4 (19,094) (13,366)
Profit for the year from continuing operations 29,063 20,296
Profit for the year from discontinued operations 3 - 181
Profit for the year 29,063 20,477
Earnings per share (cents) 5
Basic
From continuing operations 41.3 29.0
From discontinued operations - 0.3
From continuing and discontinued operations 41.3 29.3
Diluted
From continuing operations 36.9 25.6
From discontinued operations - 0.2
From continuing and discontinued operations 36.9 25.8
Balance sheets
as at 31 December 2006
Group Company
2006 2005 2006 2005
Notes $000's $000's $000's $000's
Non-current assets
Intangible assets 146,954 151,213 - -
Property, plant and equipment 159,472 29,988 680 737
Investments - - 204,286 179,690
Financial asset 32,571 31,882 - -
Other receivable - 10,134 - -
Deferred tax assets 1,530 2,591 - -
340,527 225,808 204,966 180,427
Current assets
Inventories 88 310 - -
Trade and other receivables 26,670 6,285 566 244
Tax receivables 2,299 1,138 177 104
Cash and cash equivalents 187,791 50,967 63 360
216,848 58,700 806 708
Total assets 3 557,375 284,508 205,772 181,135
Current liabilities
Trade and other payables (35,029) (15,233) (22,161) (974)
Tax payables (134) (446) (68) (446)
(35,163) (15,679) (22,229) (1,420)
Net current assets 181,685 43,021 (21,423) (712)
Non-current liabilities
Convertible bonds 6 (220,233) - - -
Long term provisions (6,187) (2,590) - -
(226,420) (2,590) - -
Total liabilities 3 (261,583) (18,269) (22,229) (1,420)
Net assets 295,792 266,239 183,543 179,715
Equity
Share capital 23,532 23,479 23,532 23,479
Share premium account 68,325 68,221 68,325 68,221
Other reserves 54,406 54,259 (25,839) (658)
Retained earnings 149,529 120,280 117,525 88,673
Total equity 7 295,792 266,239 183,543 179,715
Cash flow statements
for the year to 31 December 2006
Group Company
2006 2005 2006 2005
Notes $000's $000's $000's $000's
Net cash from (used in) operating 8 33,230 30,536 11,899 (5,409)
activities
Investing activities
Purchase of intangible assets, net 3 (82,148) (65,268) - -
Purchase of property, plant and (32,191) (10,907) (30) (150)
equipment
Purchase of own shares into treasury (13,634) - (13,634) -
Investment in subsidiary undertakings - - - (12,883)
Dividends received from subsidiary - - 12,935 20,617
undertakings
Proceeds on disposal of subsidiary - 27,510 - -
undertaking
Net cash (used in) from investing (127,973) (48,665) (729) 7,584
activities
Financing activities
Share-based payments (11,372) (1,837) (11,372) (1,837)
Proceeds on issue of convertible bonds 242,966 - - -
Proceeds on issue of ordinary share - 14 - 14
capital
Net cash from (used in) financing 231,594 (1,823) (11,372) (1,823)
activities
Net increase (decrease) in cash and 136,851 (19,952) (202) 352
cash equivalents
Cash and cash equivalents at beginning 50,967 71,122 360 113
of year
Effect of foreign exchange rate changes (27) (203) (95) (105)
Cash and cash equivalents at end of 187,791 50,967 63 360
year
Statements of recognised income and expense
for the year to 31 December 2006
Group Company
2006 2005 2006 2005
$000's $000's $000's $000's
Profit for the year 29,063 20,477 4,350 15,372
Unrealised currency translation 186 (363) 24,502 (20,351)
differences
Total recognised income (loss) for the 29,249 20,114 28,852 (4,979)
year
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. General information
The financial information for the years ended 31 December 2006 and 2005 does not
constitute statutory accounts as defined in Section 240 of the Companies Act
1985 (Act), but is derived from those accounts. A copy of the statutory
accounts for 2005 has been delivered to the Registrar of Companies and those for
2006 will be delivered following the Company's annual general meeting. The
auditors' report on those accounts was unqualified and did not contain
statements under Section 237(2) or (3) of the Act. Whilst the financial
information included in this preliminary announcement has been computed in
accordance with International Financial Reporting Standards (IFRS), this
announcement does not itself contain sufficient information to comply with IFRS.
The Company expects to publish full financial statements that comply with IFRS
in its Annual Report and Accounts 2006.
The financial statements are presented in US dollars which is the functional
currency of each of the Company's subsidiary undertakings. The Directors do not
recommend the payment of a dividend.
This preliminary announcement was approved by the Board on 14 March 2007.
2. Basis of preparation
The financial information has been prepared in accordance with the recognition
and measurement criteria of International Financial Reporting Standards (IFRS)
and with IFRSs adopted for use in the European Union. The financial information
has been prepared under the historical cost basis.
3. SEGMENT INFORMATION
Geographical segments
Geographical segments form the basis on which the Group reports its primary
segment information.
2006
Continuing operations Discontinued
operations 1
Middle East SE Asia West Unallocated Total Central Asia Group
Africa
$000's $000's $000's $000's $000's $000's $000's
Oil sales 76,476 - - - 76,476 - 76,476
Operating profit 55,113 - - (8,802) 46,311 - 46,311
Assets 64,872 226,184 30,768 235,551 557,375 - 557,375
Liabilities 8,384 10,605 12,398 230,196 261,583 - 261,583
Capital 35,888 100,790 (2,050) 28 134,656 - 134,656
additions, net 2
Depletion and 9,318 - - 208 9,526 - 9,526
depreciation
2005
Continuing operations Discontinued
operations 1
Middle East SE Asia West Unallocated Total Central Asia Group
Africa
$000's $000's $000's $000's $000's $000's $000's
Oil sales 57,160 - - - 57,160 1,498 58,658
Operating profit 37,263 - - (5,999) 31,264 - 31,264
Assets 39,950 125,346 28,225 90,987 284,508 - 284,508
Liabilities 8,696 5,498 27 4,048 18,269 - 18,269
Capital additions 11,845 41,825 28,067 183 81,920 (630) 81,290
Depletion and 7,149 - - 176 7,325 - 7,325
depreciation
1 In August 2005 the Group disposed of its Central Asia segment which comprised
its Mongolia interest. The results of this segment are therefore included in
discontinued operations. In 2005, the profit for the year from discontinued
operations of $181,000 was the profit on disposal, net of other expenses, of the
Mongolia interest.
2 Capital additions, together with the related figures for purchases in the cash
flow statements, are net of certain farm-out proceeds.
Business segment
The Group has one principal business activity being oil and gas exploration and
production. Revenue by destination does not materially differ from revenue by
origin. There are no inter-segment sales.
4 Tax
2006 2005
$000's $000's
Current tax 18,033 13,839
Deferred tax 1,061 (473)
19,094 13,366
UK corporation tax is calculated at 30% (2005 - 30%) of the estimated assessable
profit for the year. Taxation in other jurisdictions is calculated at the rates
prevailing in the respective jurisdictions. During 2005 and 2006 both current
and deferred taxation have arisen in overseas jurisdictions only.
The charge for the year can be reconciled to the profit per the income statement
as follows:
2006 2005
$000's $000's
Profit before tax on continuing operations 48,157 33,662
Profit before tax on discontinued operations - 181
48,157 33,843
Profit before tax multiplied by standard rate of corporation tax 14,447 10,153
in the UK of 30% (2005 - 30%)
Effects of:
Expenses not expected to be utilised as a tax loss 2,151 1,423
Non taxable profit on disposal - (58)
Higher tax rates on overseas earnings 2,456 1,906
Adjustments to tax charge in respect of previous years 40 (58)
Tax charge for the year 19,094 13,366
The tax charge in future periods may also be affected by these factors. The
Group's overseas tax rates are higher than those in the UK, primarily because
the profits earned in Yemen are taxed at a rate of 35%.
5. EARNINGS PER SHARE
The calculation of the basic and diluted earnings per share is based on the
following data:
2006 2005
$000's $000's
Earnings from continuing operations 29,063 20,296
Earnings from discontinued operations - 181
29,063 20,477
Number of shares
2006 2005
Weighted average number of ordinary shares for the purpose of basic 70,338,272 70,003,067
earnings per share
Effect of dilutive potential ordinary shares:
Share options and warrants 6,021,356 7,010,483
Ordinary shares of the Company held by the Group 2,300,800 2,423,300
Weighted average number of ordinary shares for the purpose of 78,660,428 79,436,850
diluted earnings per share
The denominators used for the purposes of calculating earnings per share on both
continuing and discontinued operations are the same. At 31 December 2006 up to
6,238,000 (2005 - nil) potential ordinary shares in the Company that are
underlying the Company's convertible bonds and that may dilute earnings per
share in the future have not been included in the calculation of diluted
earnings per share because they are antidilutive for the year to 31 December
2006.
6. CONVERTIBLE BONDS
In May 2006, the Group issued bonds at a par value of $250 million which will be
convertible into ordinary shares of the Company at any time from June 2006 until
six days before their maturity date of 16 May 2013. At the initial conversion
price of £21.847 per share there are 6,238,000 ordinary shares of the Company
underlying the bonds. If the bonds have not been previously purchased and
cancelled, redeemed or converted, they will be redeemed at par value on 16 May
2013. Interest of 4.5% per annum will be paid semi-annually up to that date.
$000's
Nominal value of convertible bonds issued net of issue costs 242,966
Equity component (25,037)
Liability component at date of issue 217,929
Interest charged 9,359
Interest paid (5,625)
Total liability component as at 31 December 2006 221,663
Reported in:
Interest payable in current liabilities 1,430
Non-current liabilities 220,233
Total liability component as at 31 December 2006 221,663
7. Reconciliation of movements in Group total equity
2006 2005
$000's $000's
As at 1 January 266,239 247,187
New shares issued 157 475
Treasury shares purchased (13,634) -
Share-based payments (10,969) (1,773)
Equity component of bonds issue 25,037 -
Unrealised currency translation differences (101) (127)
Retained profit for the year 29,063 20,477
As at 31 December 295,792 266,239
8. Reconciliation of operating profit to operating cash flows
Group Company
2006 2005 2006 2005
$000's $000's $000's $000's
Operating profit 46,311 31,264 (8,598) (5,150)
Share-based payments 560 521 560 521
Depletion and depreciation 9,526 7,325 182 148
Operating cash flows before movements in 56,397 39,110 (7,856) (4,481)
working capital
Decrease (increase) in inventories 221 (172) - -
Increase in receivables (1,395) (710) (321) (140)
(Decrease) increase in payables (2,269) 4,754 20,055 (681)
Cash generated by operations 52,954 42,982 11,878 (5,302)
Interest received 4,944 1,943 38 12
Interest paid (5,925) (460) (17) (119)
Income taxes paid (18,743) (13,929) - -
Net cash from operating activities 33,230 30,536 11,899 (5,409)
Cash is generated from continuing operating activities only.
Cash and cash equivalents (which are presented as a single class of asset on the
balance sheet) comprise cash at bank and other short term highly liquid
investments that are readily convertible to a known amount of cash and which are
subject to an insignificant risk of change in value.
9. Preliminary results announced
Copies of the announcement will be available from the Company's head office, St
James's House, 23 King Street, London, SW1Y 6QY. The Annual Report and Accounts
2006 will be posted to shareholders in due course.
Reserve statistics
unaudited, net working interest (mmboe)
Net proven oil and
gas reserves
Total Thailand Vietnam 1 Congo 1, 2 Yemen 3
Reserves as at 31 59.7 5.0 30.0 9.5 15.2
December 2005
Changes in the year
Additions - - - - -
Revision to 23.5 - 17.5 - 6.0
previous estimates
Purchase of 1.1 - 1.1 - -
reserves
Change of interest (4.7) - - (4.7) -
Sale of reserves - - - -
Production (2.5) - - - (2.5)
Reserves as at 31 77.1 5.0 48.6 4.8 18.7
December 2006
Net proven and
probable oil and gas
reserves
Total Thailand Vietnam 1 Congo 1, 2 Yemen 3
Reserves as at 31 133.2 18.4 68.3 23.8 22.7
December 2005
Changes in the year
Additions - - - - -
Revision to 38.8 - 29.4 - 9.4
previous estimates
Purchase of 3.0 - 3.0 - -
reserves
Change of interest (11.9) - - (11.9) -
Sale of reserves - - - -
Production (2.5) - - - (2.5)
Reserves as at 31 160.6 18.4 100.7 11.9 29.6
December 2006
Net proven and probable oil
and gas reserves yearly
comparison
2006 2005 2004 2003 2002
Reserves as at 1 133.2 90.7 92.5 75.4 77.0
January
Changes in the year
Additions - 68.3 - - -
Revision to 38.8 8.5 6.0 9.9 0.6
previous estimates
Purchase of 3.0 23.8 - - -
reserves
Change of interest (11.9) - - 9.2 -
Sale of reserves - (56.0) (5.8) - -
Production (2.5) (2.1) (2.0) (2.0) (2.2)
Reserves as at 31 160.6 133.2 90.7 92.5 75.4
December
Note: mmboe denotes millions of barrels of oil equivalent
1 Reserves are shown before deductions for minority interests which are funded
by the Group. The Group is entitled to receive 100% of the cash flows until it
has recovered its funding of the minority interest plus accrued interest from
the minority interests pro rata portion of those cash flows.
2 During 2006 the Group farmed out 50% of its working interest in Congo
(Brazzaville).
3 The Group provides for depletion and depreciation on its Yemen reserves on an
entitlement basis. On an entitlement basis as at 31 December 2006 proven
reserves were 7.3 mmboe (2005 - 6.1 mmboe) and proven and probable reserves were
10.1 mmboe (2005 - 8.4 mmboe).
This information is provided by RNS
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