TIDMGPX
RNS Number : 7145N
Gulfsands Petroleum PLC
20 May 2015
Gulfsands Petroleum Plc
("Gulfsands" or the "Company")
Annual Results for the year ended 31 December 2014
20 May 2015
Gulfsands, the AIM listed oil and gas company (AIM:GPX) with
activities in Syria, Morocco, Tunisia and Colombia, is pleased to
announce its preliminary results for the year ended 31 December
2014.
Gulfsands Petroleum Plc
Alastair Beardsall, Chairman +44 (0)20 7024 2130
Cantor Fitzgerald Europe
Sarah Wharry
David Porter +44 (0)20 7894 7000
First Energy Capital
Jonathan Wright +44 (0)20 7448 0220
Our 2014 Highlights
-- 2D and 3D seismic acquired in Morocco.
-- Gas discovery at LTU-1.
-- Group working interest Proved plus Probable Reserves of 73.5 mmboe.
-- Awarded Moulay Bouchta exploration licence in Morocco.
-- Syrian assets remain shut-in and secure during continuation of sanctions.
-- Total cash resources at year end of $19.4 million.
-- Cash available for use by the Group of $7.9 million.
-- Restricted cash balances of $11.5 million.
-- Convertible loan facility established. $5 million drawn at
year end and a further $5 million drawn in 2015 with interest
accruing at 10% per annum.
Post Period Highlights
-- Drilling and testing of DRC-1 and DOB-1 prove up two further gas discoveries.
-- Continued significant reduction in office expenses.
Executive Chairman's Statement
Dear Shareholder,
During 2014 the Group made good progress in Morocco completing
the acquisition and processing of 2D and 3D seismic on Fes and
Rharb Centre respectively; we believe the new 3D seismic was
instrumental in producing the drilling success that has followed on
the Rharb Centre area; three gas discoveries have been made at
LTU-1, DRC-1 and DOB-1. Discussions are underway with Office
National des Hydrocarbures et des Mines (Morocco) ("ONHYM") and
other local operators to start connecting these wells to local gas
sales pipelines to enable the Group to enter into a gas sales
contract to monetise the gas.
The Group's interests in Morocco are held in three licences,
covering four permits. The Rharb Centre and Rharb Sud permits are
included in one licence under which the outstanding work commitment
of three exploration wells must be drilled before the period
expires in November 2015. The Group is actively working with
several parties who have expressed an interest in partnering
Gulfsands in the Rharb Centre area.
The Moulay Bouchta licence was awarded to Gulfsands during 2014;
it covers an area of some 2,800 km(2), including three abandoned
legacy oil fields which demonstrate that there is an active
hydrocarbon system present, likely to be oil prone. The initial two
year exploration period runs to June 2016 during which time the
Group must acquire 500km of new 2D seismic and reprocess some
existing seismic data.
The Fes licence in Morocco covers a large under-explored area
where seismic acquisition, processing and interpretation are
difficult. Gulfsands is working with a processing company with
particular expertise to better image the subsurface using the
existing seismic data set. We are optimistic that the end product
will help us identify potential leads to be matured to drill-ready
prospect status. The contract for Fes includes an, as yet,
unfulfilled work obligation of an additional 350km of 2D seismic,
100km(2) of 3D seismic and three exploration wells that should be
completed before 25 September 2015.
Gulfsands are in discussions with ONHYM regarding the
outstanding work commitments on our licences for Rharb Centre,
Rharb Sud and Fes, and we are hopeful we can agree a forward plan
that allows Gulfsands to continue to explore and develop our
interests in Morocco.
In December 2013 the Group entered into a transaction with ADX
Energy Limited ("ADX") whereby Gulfsands would acquire ADX's
interest in the Chorbane licence in Tunisia for $1.75 million
giving the Group 100% of the Chorbane licence. The transaction
closed in 2014 and final consideration amounts were paid in early
2015. The current exploration period under the licence runs to mid
July 2015 and Gulfsands has submitted an application for a two year
extension during which the work obligation of acquiring 200km 2D
seismic and drilling one exploration well must be completed. If the
application is successful the Group will look to farm-down its 100%
interest in exchange for a carried work programme; if the
application is unsuccessful, the licence will terminate.
The Group now holds 100% interest in its two Colombian blocks.
Joint venture arrangements with our former partners, Luna Energy
Inc, were terminated in early 2015 under the terms of the original
farm-out agreements. Under the contracts for Llanos Block 50 and
Putumayo Block 14, the Group has a minimum work obligation of
acquiring approximately 100km of 2D seismic and drilling one
exploration well on each block before the end of the current phase
which has one and a half years to run to November 2016 for Llanos
Block 50 and two and a half years to run to November 2017 for
Putumayo Block 14. The Group is actively seeking farm-in candidates
to share the cost of the exploration programme on these blocks.
In December 2014 the Group sold its interest in Gulfsands
Petroleum USA, Inc., for $50,000, thus divesting itself of its
operations in the US; under the transaction all staff associated
with the US operations were transferred to the purchaser along with
all abandonment obligations. This transaction brought to a close an
association with North American assets that were the cornerstone of
Gulfsands when it was first founded.
Financial Overview
The Group posted a loss for the year of $16.1million, a
significant reduction from the prior year, and completed
exploration and evaluation asset investments of $21.0 million,
predominantly in Morocco. At year end the Group had total cash
resources of $19.4 million of which $11.5 million was restricted;
held as security for anticipated work programmes. At the date of
this report the Group had unaudited cash and cash equivalents of
$3.0 million.
The Group entered into a Strategic Cooperation Agreement with
Arawak Energy International Limited in November 2014, providing a
framework so both parties could jointly identify, evaluate and
acquire new ventures within a joint venture structure with a focus
on the Middle East and North Africa ("MENA") region. Concurrently
the Group entered into a $20 million Facility Agreement with Arawak
Energy Bermuda Ltd ("Arawak") as a means of securing working
capital. As of 9 January 2015 a total of $10 million had been
drawn-down under the Facility Agreement. On 23 January 2015 however
Arawak advised the Group that it was terminating the Strategic
Cooperation Agreement and would not fund any further draw-downs
under the Facility Agreement. Following this, in early March 2015,
Arawak requested repayment of the $10 million drawn-down, and the
interest that accrues at 10% per annum. The Group is in discussions
with Arawak over the repayment of the monies owing.
The Group has material work obligations that must be completed
under its various exploration licences and if these obligations are
not met the Group may be forced to forfeit both its interest in
these contracts and any sums of restricted cash lodged with host
governments as guarantees for our performance of the minimum work
obligations. The 2014 Financial Statements have been prepared on a
going concern basis, and further details on this can be found in
the Financial Review.
The Company is proposing to seek short term, unsecured,
financing from some of its shareholders to use as working capital
while it implements a new strategy for the Group's assets that is
both financeable and sustainable in the current equity capital
markets. Longer term funding will probably be an equity raising or
some combination of debt and equity. Further details will be
announced before the Company's Annual General Meeting that is
scheduled for 30 June 2015.
Board and Management Changes
James Ede-Golightly and John Bell were appointed as
Non-Executive Directors on 13 August 2014. James has extensive
board experience with a focus on financial matters, whilst John has
more than 20 years international experience in the management of
oil and gas projects from exploration through to production. We
welcome James and John and look forward to benefiting from their
experience.
David Cowan and Michel Faure stepped down from the board on 30
June 2014 and 13 August 2014 respectively. David had served as a
Non-Executive Director for more than eight years; his legal
expertise has been a great asset during the growth and development
of the Gulfsands business since joining the board in 2006. Michel
was appointed a Non-Executive Director shortly after completing a
long and successful career with Shell. Whilst his tenure was just
over a year, his contribution was assisting in country relations in
Morocco and Tunisia. On behalf of the Board we thank both David and
Michel for their respective contributions to the business.
In February 2015 Ken Judge left the Board and was served notice
to terminate his executive services as Gulfsands legal counsel.
On 13 April 2015 Mahdi Sajjad was removed from his role as the
Company's Chief Executive. The Company has been advised by Mayer
Brown International LLP, acting on behalf of Mr Sajjad, the action
taken on 13 April 2015 constituted a material adverse change to Mr
Sajjad's employment which he had not consented to; furthermore, Mr
Sajjad has elected to treat his employment contract terminated on 8
May 2015 and claims certain payments are now due under his
employment contract. Mr Sajjad remains a Director of Gulfsands.
In April 2015 Andrew West stood down as Non-Executive Chairman
and remains on the Board as a Non-Executive Director.
Simultaneously I was appointed to the Board as a Director and
Executive Chairman; I look forward to working with the Board,
Management and staff in ensuring that the Group can operate within
its means and fulfil the vision shared by many of our
shareholders.
Also in April 2015 Andrew Morris was appointed to the board as a
Non-Executive Director. Andrew is Chairman of Madagascar Oil
Limited and his career includes a period with the global accounting
firm Ernst & Young. We look forward to Andrew contributing on
both technical and financial matters.
In April 2015 Alan Cutler resigned from his executive role as
Director - Finance and Administration; it is expected that Alan
will step down from the Board and leave the Company during the
third quarter of 2015.
Outlook for 2015 and Beyond
The Group remains committed to maintaining its presence in
Syria, and it considers its partnership with General Petroleum
Corporation ("GPC") as a key element for the safe stewardship of
Block 26 while the various sanctions prevent Gulfsands from a more
active role.
In Morocco the portfolio of interests vary greatly in nature;
early stage exploration in Fes where interpreting the seismic may
unlock our understanding of the sub-surface, highly prospective
exploration acreage in Rharb Sud and Moulay Bouchta located in an
area known to be oil prone, and appraisal and development
opportunities in Rharb Centre; however to capitalise on these
opportunities the Group will need to secure new funds from both
existing and new investors.
We shall seek to farm-out the assets we hold in Colombia and
Tunisia ensuring we can benefit from any success but without being
exposed to the full cost of exploration.
The Group faces many challenges over the coming months,
including seeking extensions to licences and completing our work
programmes, but above all, securing new funds sufficient to repay
the Arawak loan facility and to provide the necessary working
capital to allow progress to be made on some of our assets.
I would like to thank all our staff for the fortitude shown over
the last twelve months and look forward to working with them in the
future to develop Gulfsands into an oil & gas company we can
all be proud to be part of.
Yours sincerely,
Alastair Beardsall
Executive Chairman
19 May 2015
Disclaimer
This results announcement contains certain forward-looking
statements that are subject to the risk factors and uncertainties
associated with the oil and gas exploration and production
business. Whilst the Group believes the expectations reflected
herein to be reasonable in light of the information available to
them at this time, the actual outcome may be materially different
owing to a variety of factors including specific factors identified
in this statement and other factors outlined in the Group's 2014
Annual Report.
Operations Review
Syria
Gulfsands is the operator of the Block 26 Production Sharing
Contract ("PSC") and holds a 50% working interest in the PSC along
with Sinochem. The Group is not presently involved in any
production or exploration activities on Block 26 as force majeure
has been declared in respect of the contract following the
introduction of EU sanctions against Syria.
The Group has ensured that it remains compliant with all
applicable sanctions in relation to Syria and intends to return to
production and exploration activities as soon as permitted.
Block 26 covers an area of 5,414 km(2) in north east Syria and
the PSC grants rights to explore, develop and produce hydrocarbons
from all depths outside the pre-existing fields within the area and
from the deeper stratigraphic levels below the pre-existing
discovered fields. The final exploration period of the PSC was set
to expire in August 2012 when force majeure was declared in
December 2011. It is anticipated that an extension in the
exploration period can be negotiated with the Syrian authorities to
at least replace that period of time which was remaining when force
majeure was declared. Rights to the benefits of production from
discovered fields last for a minimum of 25 years from the date of
development approval with extension thereto at the partners'
option.
Under the Group's operatorship, two oil fields containing
reservoirs of Cretaceous age have been discovered and developed
within the PSC area, Khurbet East (2008) and Yousefieh (2010).
During 2011 combined production from these fields reached a level
of just under 25,000 barrels of oil per day ("bopd") before the
impact of EU sanctions resulted in the curtailing of production
levels. In addition, two further oil and gas discoveries with
reservoirs of Triassic age have been identified beneath the
Cretaceous aged oil producing reservoir in the Khurbet East field
and within the Butmah and Kurrachine Dolomite formations.
Development approvals for these discoveries were granted in 2011
and 2008 respectively. A further oil discovery was made late in
2011 by Gulfsands in the Cretaceous aged reservoirs at the Al
Khairat exploration well, this discovery awaits further evaluation
and development work.
The operation of these fields during the production phase is
undertaken by Dijla Petroleum Corporation ("DPC"), a joint
operating company formed between Gulfsands, Sinochem and the
General Petroleum Corporation ("GPC") for this purpose, to which
staff of both Gulfsands and GPC had previously been seconded. Since
the introduction of EU sanctions on 1 December 2011 that identified
GPC as a designated entity and the subsequent declaration of force
majeure under the PSC, Gulfsands has had no involvement with the
operations of DPC, and Gulfsands staff seconded to DPC have been
withdrawn, leaving DPC under the management of GPC secondees.
Sanction Compliance
Gulfsands has taken extensive legal advice with respect to its
obligations under the sanctions in place at the time and has
liaised regularly with relevant regulators and generally acted
cautiously to ensure it remains compliant with all relevant
sanctions. The Board is determined to ensure that the Group's
activities remain compliant and Management will continue to liaise
closely with the relevant regulatory authorities to ensure this
objective is achieved while continuing to keep GPC fully informed
of the breadth and scope of restrictions on our activities as a
result of continuing to comply with applicable sanctions.
Morocco
Gulfsands is the operator of a contiguous portfolio of onshore
oil and gas exploration permits covering an area of approximately
7,210 km(2) in northern Morocco which incorporate proven petroleum
systems. The Group has material equity interests in the three
Contracts which govern the Moulay Bouchta, Fes, Rharb Centre and
Rharb Sud permits.
Moulay Bouchta Contract
Contract expiry First exploration phase, June 2016.
date:
Minimum work Acquisition of 500 km of 2D seismic
obligation: data to be captured in a new survey;
reprocessing and interpretation
of selected legacy 2D seismic lines
and the existing 3D seismic data;
and a legacy oil field reactivation
study.
Further details are provided in
note 5 to the Preliminary Financial
Statements.
---------------- --------------------------------------
In June 2014, the Group finalised agreements with Morocco's
Office National des Hydrocarbures et des Mines ("ONHYM") and the
government of Morocco for the award of the newly created Moulay
Bouchta permit. Gulfsands acquired operatorship of the permit with
a 75% participating interest while ONHYM retained a 25%
participating interest, the attributable cost of which will be
carried by Gulfsands upon the usual terms for such participation,
through the exploration phase of the permit. The Moulay Bouchta
permit encompasses an area of approximately 2,850 km(2) and is
located to the north of the Group's Rharb Sud permit and extends
eastwards to surround the western, northern and eastern boundaries
of the Fes Block onshore in northern Morocco.
The Moulay Bouchta permit includes an area where the existence
of a working petroleum system has been confirmed with the discovery
and development of three oil fields, the most recent of which was
the Haricha Field which had produced a total of 2.8 mmboe of oil
and 4.2 bcf of gas when production ceased in 1990. A portion of the
Moulay Bouchta permit area that surrounds and incorporates the
Haricha Field has been the subject of a 175 km(2) 3D seismic survey
by a previous operator. It is the intention of the Group to
evaluate the potential for deeper and potentially larger structures
containing Jurassic and Cretaceous aged reservoirs within the
permit area. The permit is also believed to contain Tertiary aged
reservoirs that may contain biogenic gas accumulations similar to
those that occur in the adjacent Rharb Centre permit area, where
commercially viable natural gas accumulations are found at depths
of approximately 800-2,000 metres.
Plans with respect to the minimum work obligation activities are
at a well developed stage. The Group is pursuing options with
respect to funding this work programme including bringing in
industry partners.
Fes Contract
Contract expiry September 2015.
date:
Minimum work Acquisition of an additional 350
obligation: km of 2D seismic data to be captured
in a new survey; 100km(2) of new
3D seismic data; and drilling three
exploration wells.
Further details are provided in
note 5 to the Preliminary Financial
Statements.
---------------- --------------------------------------
2D seismic data has been acquired across the Fes permit area in
a 650 km survey that commenced in 2013 and was completed in early
2014. Following this a conventional seismic processing of the data
was undertaken that was completed in July 2014, however the results
of this processing work did not yield the step change uplift in
data quality and imaging that was anticipated.
Work is now underway to further reprocess and upgrade these 2D
data using a bespoke approach that is more specifically tailored to
the geological fold and thrust belt setting in the Fes permit where
the data was acquired. This additional seismic data reprocessing is
being carried out in Calgary, Canada, by specialists using
processing techniques not previously applied in Morocco. Initial
results from the newly reprocessed data set indicates that it is
yielding greater clarity in data imaging, which in turn offers
opportunities to improve upon the geological interpretation of the
data and on the reliability of mapping of key prospective potential
oil bearing horizons. The results from the reprocessing work
conducted to date have supported a more extensive and fulsome
reprocessing of the 2D data acquired by Gulfsands during the course
of 2015 which is currently underway. Once reprocessed, a further
phase of re-interpretation and mapping work will be conducted
in-house during 2015.
Gulfsands are working closely with ONHYM to optimise the work
programme in the complex geological area of the Fes permit, and an
extension period to the current permit exploration period beyond
September 2015 is currently being discussed with ONHYM. In
parallel, the Group will pursue options for funding this work
programme including bringing in industry partners.
Evaluation of Oil Prospectivity
The Moulay Bouchta, Rharb Sud and Fes permits are all considered
prospective for oil, encompassing a working petroleum system
incorporating three previously developed and produced shallow oil
fields, and with many oil seeps encountered at surface.
Working closely with the technical staff of ONHYM, the Group's
technical teams have been consolidating, updating and interpreting
a significant amount of technical data that covers the three
permits, and includes 2D and 3D seismic and well data from more
than 850 legacy wells within the permits and surrounding area.
The Group's technical teams have identified leads on each of the
Moulay Bouchta, Rharb Sud and Fes permits via 2D and 3D seismic
data and/or legacy well data, and these will be subject to further
evaluation in 2015, with the possibility that some may be the
location of further acquisition of 2D seismic data by the
Group.
Rharb Contract
Contract expiry November 2015.
date:
Minimum work Drilling three exploration wells.
obligation:
Further details are provided in
note 5 to the Preliminary Financial
Statements.
---------------- -------------------------------------
A formal ten month extension to the Rharb exploration contract
was granted by ONHYM in January 2015 extending the licence period
to 9 November 2015. The contract governs the Rharb Centre and Rharb
Sud permits.
During 2014, Gulfsands drilled its fourth and fifth gas
exploration wells in the Rharb centre permit area, both of which
were located and drilled utilising Gulfsands 3D seismic survey data
acquired in 2013 and processed in 2014. Both of these exploration
wells resulted in gas discoveries.
Well LTU-1, targeting the Lalla Yetou Updip prospect was spudded
on 20 June 2014 and was drilled to a total depth of 1,182 metres.
Elevated gas readings obtained while drilling, as well as
interpretation of wireline logs, indicated the presence of a gas
bearing reservoir section of twelve metres thickness at the
pre-drill target interval depth. The main reservoir encountered
appeared consistent with the pre-drill expectation of a turbidite
distributary channel/fan complex, with laminated sand and silt
layers and normal bed grading. A gas-to-water contact was
interpreted in the well, based on gas shows and petrophysical data,
at a depth approximately 13 metres below the reservoir section,
also consistent with the pre-drill expectation.
After the conclusion of drilling and formation evaluation
operations, the twelve metre reservoir section was perforated and a
short production clean up flow period was undertaken. Within one
hour of commencing the cleanup flow period, the well had unloaded
the completion fluids and was producing 100% gas to surface with 0%
bulk solids and water. The estimated flow rate for the well, based
on empirical calculation methods, was approximately 6.6 million
standard cubic feet per day ("mmscfpd") on a 28/64 inch choke.
After the clean up flow period the well was shut in and is now
temporarily suspended as a future gas producer.
The LTU-1 gas discovery can be tied back to the area gas export
pipeline system, and related civil works involving the installation
of production facilities and connecting flow trunk lines are
currently being evaluated.
Well DRC-1, targeting the Dardara South East gas exploration
prospect and located in the north-west corner of the 3D seismic
survey area, was spudded on the 19 December 2014, and drilled to a
total depth of 1,153 metres. The well encountered the primary
reservoir target interval on prognosis at a depth of 875 metres.
Significantly elevated gas readings obtained while drilling, as
well as interpretation of geological samples and wireline logs,
indicate the presence of a gas bearing sandstone reservoir section
of excellent quality.
Detailed petrophysical evaluation of DRC-1 wireline logs yielded
an interpretation indicating a 53 metres gross thickness of
excellent quality reservoir sand between 875-928 metres, with a net
gas bearing sand thickness of 16 metres, evaluated average gas
saturation of 65% and average porosity of 32%. A gas-to-water
contact was observed in the well at approximately 895 metres as
evidenced by wireline log and formation pressure data.
Due to the presence of over-pressured shales in the lower
section of the well-bore, and in order to ensure that the well-bore
integrity was maintained for wireline logging operations, the well
was not deepened further into a secondary target objective and
beyond that to the original planned Total Depth ("TD") of 1,280
metres. Instead the well was cased, cemented, and perforated over
the interval 876-884 metres, and a completion run in order to
perform a flow test.
Following an initial two hour well clean-up flow period, the
well was fully unloaded of completion fluids to a 100% gas stream.
During two subsequent flow periods of six hours and eight hours
respectively the well flowed first at an average gas rate of 7.1
mmscfpd on a 32/64(th) inch choke and then later at an average rate
of 9.4 mmscfpd on a 40/64(th) inch choke. The well flowed with no
associated formation water production or sand production in both
flow periods. Following the second flow period the well was shut-in
for a pressure survey in order to evaluate reservoir information
and connected gas volumes, after which the well was suspended as a
future gas production well.
In the Dardara area in addition to encountering a potentially
highly productive net gas bearing interval of 16 metres, the DRC-1
well result indicates additional gas exploration potential to exist
in adjacent areas and fault blocks.
The DOB-1 well was spudded in January 2015 and drilled to a TD
of 1,140 metres Measured Depth ("MD") where it encountered the
primary reservoir target interval on prognosis at a depth of
approximately 808 metres MD. Significantly elevated gas readings
obtained while drilling, as well as interpretation of geological
samples and wire line logs, indicated the presence of a gas bearing
sandstone reservoir section of excellent quality. Detailed
petrophysical evaluation of wireline logs over the primary target
yielded an interpretation indicating a 4.2 metres gross sand
thickness, with a net sand thickness of 3.7 metres and evaluated
average gas saturation of 70% and average porosity of 34%.
The well was subjected to a flow testing and pressure survey
period for evaluation of well flow performance and connected gas
volumes. During initial clean up flow operations over this
reservoir, the well produced natural gas at an estimated rate in
excess of 10 million mmscfpd on a 48/64th inch choke setting.
During subsequent multi-rate flow testing, a stable flow of 6.2
mmscfpd was established for a period of 4 hours on a 32/64th inch
choke setting, with a final wellhead flowing pressure of 1,084 psi.
No formation water was detected in the gas production stream during
testing operations.
The secondary reservoir target interval for the well was
encountered at a depth of approximately 1,075 metres MD.
Significantly elevated gas readings were encountered over the
interval 1,075 -1,127 metres MD. However, problems with well bore
integrity above this interval prevented further evaluation of the
potential of this deeper potential reservoir at this time. The
Group is reviewing options for evaluating this reservoir in future
operations.
Subsequent to these drilling operations the Group have been
conducting a detailed technical assessment over the DOB-1 and DRC-1
gas discoveries that will include the identification of potential
locations for further drilling in the near vicinity of these
discoveries.
The Group have additionally been working with its partner,
ONHYM, on strategies to commercialise the discoveries made. These
discussions are ongoing at the date of this report.
Following the drilling of DOB-1, Gulfsands has three remaining
well commitments across the Rharb concession including the Rharb
Sud permit, to be drilled by the end of the licence period on 9
November, 2015. The Group are working closely with ONHYM with
respect to these work obligations and the commercialisation of
discoveries made on this permit. In parallel, the Group are
considering options for funding this work programme and the
development of discoveries which may include bringing in industry
partners.
Tunisia
Gulfsands has a 100% interest in the operated Chorbane
exploration permit onshore Tunisia covering approximately
1,942km(2).
Contract expiry July 2015.
date:
Minimum work Drilling one exploration well.
obligation:
Further details are provided in
note 5 to the Preliminary Financial
Statements.
---------------- -------------------------------------
The Tunisian Authorities (Comité Consultatif des Hydrocarbures
or "CCH") have approved the transfer of all of ADX Energy Limited's
remaining legal interest (30%) in the Chorbane permit, onshore
Tunisia, to Gulfsands Petroleum Tunisia Limited, a wholly owned
subsidiary of the Company. The Company's subsidiary is Operator of
the Chorbane permit and is now legal owner of a 100% interest in
the permit.
The current exploration period under the licence runs to mid
July 2015 and Gulfsands has submitted an application for a two year
extension during which the work obligation of acquiring 200km 2D
seismic and drilling one exploration well must be completed. If the
application is successful the Group will look to farm-down its 100%
interest in exchange for a carried work programme; if the
application is unsuccessful, the licence will terminate.
Colombia
Gulfsands has Exploration and Production Contracts ("E&P
Contracts") over two onshore contract areas, Putumayo Block 14
("PUT 14") and Llanos Block 50 ("LLA 50").
Llanos Block
50
Contract expiry First exploration phase, November
date: 2016.
Minimum work Acquisition of an additional 93
obligation: km of 2D seismic data to be captured
in a new survey; and drilling one
exploration well.
Further details are provided in
note 5 to the Preliminary Financial
Statements.
Putumayo Block
14
Contract expiry First exploration phase, November
date: 2017.
Minimum work Acquisition of an additional 103
obligation: km of 2D seismic data to be captured
in a new survey; and drilling one
exploration well.
Further details are provided in
note 5 to the Preliminary Financial
Statements.
---------------- --------------------------------------
The Group continues to undertake the preliminary studies
required to be completed prior to the commencement of either 2D or
possibly exploration-oriented 3D seismic acquisition programmes on
the contract areas. Discussions with other operators in the
Putumayo and Llanos areas and seismic contractors active in these
areas have commenced with a view to co-ordinating and sharing
logistics as well as optimising parameters for the seismic
programmes being planned on both contract areas.
The next phase of the work programme on PUT 14 includes a
"Consulta Previa", being a consultation with local indigenous and
tribal peoples regarding the implementation of any project that may
have an impact on their culture, heritage, social - economical
conditions and environment. This Consulta Previa has an expected
duration of six months. In parallel, a PMA "Plan de Manejo
Ambiental", or Environmental Management Plan, is required to be
prepared across the whole contract area, completion of which will
allow the commencement of a seismic survey. Operators in nearby
contract areas in the Putumayo basin have successfully utilised 2D
and 3D seismic data and interpretation methods generating multiple
discoveries in the area.
On LLA 50, a MMA "Medidas Manejo Ambiental", or Environmental
Management Measures, is being prepared across the whole contract
area, completion of which will allow the commencement of a seismic
survey. The annual weather window (dry season) for seismic
operations in this region is quite narrow, typically restricting
seismic acquisition to the period from mid-December to mid-April.
The LLA 50 contract area is located within the proven and
productive Llanos basin in eastern Colombia.
The Group is currently considering divestment or farm-down
options for its interests in the contract areas prior to any
significant financial commitment with respect to further
exploration work.
Reserves Report
Reserves
Reserves are categorised into Proved, Probable and Possible
reserves in accordance with the 2007 Petroleum Resources Management
classification system ("PRMS") of the Society of Petroleum
Engineers ("SPE"). Definitions for Proved, Probable and Possible
reserves are contained in the Glossary.
The Group's Reserves are based on estimates made by Gulfsands'
Technical teams which are approved by Management and then reviewed
by independent petroleum engineers from external parties. External
reviews have been performed for the Group by Senergy (GB) Limited
("Senergy") since 2009.
Summary of Reserves
Working interest reserves in Syria represent the proportion,
attributable to the Group's 50% participating interest, of forecast
future hydrocarbon production during the economic life of the Block
26 PSC, including the share of that production attributable to
General Petroleum Corporation ("GPC"). In assessing the Group's
Reserves attributable to Syria Block 26 it has been assumed that
the force majeure condition is lifted with effect from 1 January
2016 and Gulfsands resumes its role as operator. It should be noted
that there remain significant uncertainties with respect to the
timing of the Group's re-entry into Syria and the conditions
encountered upon its return.
Reserves attributable to the Group's US business, which was
divested during 2014, are no longer recorded.
Working interest basis
Syria US Group total
------ ------------------- -------------------------
Oil Gas Oil Gas Oil Gas Oil & Gas
mmbbl bcf mmbbl bcf mmbbl Bcf mmboe
As at 31 December 2014
Proved 38.5 11.0 0.0 0.0 38.5 11.0 40.3
Probable 29.7 20.5 0.0 0.0 29.7 20.5 33.2
------ ----- ------ ---- ------ ----- ----------
Proved and Probable 68.2 31.5 0.0 0.0 68.2 31.5 73.5
------ ----- ------ ---- ------ ----- ----------
Possible 41.8 35.5 0.0 0.0 41.8 35.5 47.7
------------------------------- ------ ----- ------ ---- ------ ----- ----------
Proved, Probable and Possible 110.0 67.0 0.0 0.0 110.0 67.0 121.2
------------------------------- ------ ----- ------ ---- ------ ----- ----------
Movements in Proved and Probable reserves during year
As at 31 December 2013 68.9 33.0 1.0 2.0 69.9 35.0 75.8
Discoveries and additions 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Disposals 0.0 0.0 (0.9) (1.9) (0.9) (1.9) (1.2)
Revisions (0.5) (1.5) 0.0 0.0 (0.5) (1.5) (0.8)
Less estimated production (0.2) (0.0) (0.1) (0.1) (0.3) (0.1) (0.3)
--------------------------------------------------------- ------- ------- ------ ------ ------- ------- -------
At 31 December 2014 68.2 31.5 0.0 0.0 68.2 31.5 73.5
--------------------------------------------------------- ------- ------- ------ ------ ------- ------- -------
Represented on an entitlement basis At 31 December 2014 29.5 16.5 0.0 0.0 29.5 16.5 32.3
--------------------------------------------------------- ------- ------- ------ ------ ------- ------- -------
NB Certain figures may not add up due to roundings.
"Oil" includes condensate and NGLs.
Gas is converted to mmboe at the conversion factor 1 bcf =
0.1667 mmboe.
Resources
The Group's Resources are based on estimates made by Gulfsands'
Technical teams which are approved by Management and then reviewed
by independent petroleum engineers from external parties. External
reviews have been performed for the Group by Senergy since
2009.
Summary of Contingent Resources
Contingent Resources are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
known accumulations by the application of development projects, but
are not currently considered to be commercially recoverable due to
one or more contingencies. Contingent Resources are further
categorised by the SPE into 1C, 2C and 3C according to the level of
uncertainty associated with the estimates.
In accordance with the 2007 SPE PRMS, a guideline risk factor
should be stated associated with the Contingent Resources quoted
for each category; the risk factor indicates the likelihood that
the Group will ultimately commercially develop the resource. The
risk factor considers all technical and non-technical factors that
are impacting or are likely to impact on the likelihood of
development, and is termed the "Chance of Development".
Unrisked working interest basis
As at 31 March 2015
Risk factor
(Chance
of
Constituent 1C 2C 3C development)
----------------------- ---------------------- ---- ----- ----- --------------
Syria Block 26
(Working interest
50%)
Al Khairat discovery Oil, mmbbl 2.9 12.0 45.7 30%
----------------------- ---------------------- ---- ----- ----- --------------
Morocco Rharb Centre permit
(Working interest
75%)
Sales Gas,
Beni Fdal discovery bcf 0.3 0.7 1.9 50%
Douar Nouaoura Sales Gas,
discovery bcf 0.4 1.3 4.3 20%
Lalla Yetou Updip Sales Gas,
discovery bcf 0.8 2.0 4.3 90%
Dardara Southeast Sales Gas,
discovery bcf 1.6 4.7 13.9 90%
Douar Ouled Balkhair Sales Gas,
discovery bcf 0.2 0.6 1.9 90%
---------------------- ----------------------- ---- ----- ----- --------------
Total, bcf 3.3 9.3 26.3
----------------------- ---- ----- ----- --------------
NB Certain figures may not add up due to roundings.
"Oil" includes condensate and NGLs.
Gas is converted to mmboe at the conversion factor 1 bcf =
0.1667 mmboe.
Summary of Prospective Resources
Prospective Resources are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations. They are further categorised by the
2007 SPE PRMS into Low, Best and High estimates. The quoted Low,
Best and High estimates are the 90% probability ("P90"), 50%
probability ("P50") and 10% probability ("P10") values respectively
derived from probabilistic estimates generated using a Monte Carlo
statistical approach.
In accordance with the 2007 SPE PRMS, a guideline risk
assessment should be provided associated with the Prospective
Resources quoted for Low, Best and High estimate categories. The
risk assessment here is the Chance of Discovery; the additional
risk assessment relating to the Chance of Development is not
normally quantified at this level of resource classification.
Unrisked working interest basis
As at 31 March 2015
Risk factor
(Chance
of
Constituent Low Best High discovery)
----------------------- ---------------- ----- ------ ------ --------------
Morocco Rharb Centre permit
(Working interest
75%)
Upper Miocene Sales Gas,
prospects bcf 3.0 7.4 16.3 35-48%
Upper Miocene Sales Gas,
leads bcf 6 17 37 Medium-High
Morocco Rharb Sud permit
(Working interest
75%)
Oil and Sales
Jurassic leads Gas, mmboe 1 11 66 Low-Medium
Morocco Moulay Bouchta permit
(Working interest
75%)
Oil and Sales
Jurassic leads Gas, mmboe 1 11 75 Low-Medium
Morocco Fes permit
(Working interest
50%)
Oil and Sales
Jurassic leads Gas, mmboe 21 478 2,250 Low-Medium
----------------------- ---------------- ----- ------ ------ --------------
Morocco total mmboe 24 504 2,400
----------------------- ---------------- ----- ------ ------ --------------
Risk factor
(Chance
of
Constituent Low Best High discovery)
------------------------ --------------- ----- ------ ------ --------------
Tunisia Chorbane permit
(Working interest
100%)
Sidi Agareb prospect
Eocene / Upper
Cretaceous Oil, mmbbl 8 27 63 9%-25%
Lafaya Deep &
Sidi Daher prospects Sales Gas,
Jurassic leads bcf 21 103 398 Low
------------------------ --------------- ----- ------ ------ --------------
Tunisia total mmboe 12 44 129
------------------------ --------------- ----- ------ ------ --------------
NB Certain figures may not add up due to roundings.
"Oil" includes condensate and NGLs.
Gas is converted to mmboe at the conversion factor 1 bcf =
0.1667 mmboe.
Financial Review
Selected operational and financial data
Year ended Year ended
31 December 31 December
2014 2013
$' 000 $' 000
---------------------------------------- ------------- -------------
General administrative expenses (5,469) (9,408)
Exploration costs written-off (6,040) (12,301)
Loss from continuing operations (12,113) (25,382)
Loss for the year (16,091) (26,757)
Net cash used in operating activities
by continuing operations (3,799) (8,611)
E&E cash expenditure (26,987) (17,302)
Cash and cash equivalents 7,907 33,824
Restricted cash balances 11,514 19,138
---------------------------------------- ------------- -------------
The loss for the year was $16.1 million (2013: $26.8 million),
consisting of a loss from continuing operations for the year of
$12.1 million (2013: $25.4 million) and a loss from discontinued
operations for the year of $4.0 million (2013: $1.4 million). The
loss from discontinued operations related to the US operations
which were disposed of in December 2014. Under the requirements of
IFRS 5, the 2013 comparatives for discontinued operations have been
reclassified in the Income Statement.
General administrative expenses fell by $4.0 million during the
year. Office expenses after partner recoveries reduced by $1.7
million whilst a reduction in depreciation and an increase in
office expenses capitalised, further reduced general administrative
expenses by $2.3 million.
Exploration and evaluation asset write-offs decreased in the
year to $6.0 million (2013: $12.3 million). 2014 write-offs
consisted of $5.2 million in respect of Moroccan E&E assets and
$0.8 million in respect of Tunisian E&E assets. 2013 write-offs
largely reflected three unsuccessful exploration wells drilled on
the Rharb Centre permit.
The carrying value of exploration and evaluation assets on the
Balance Sheet increased to $53.0 million at 31 December 2014 (31
December 2013: $37.1 million), predominantly due to the substantial
investment in Morocco during the year including the drilling of the
successful LTU-1 and DRC-1 gas wells.
The Group continues to value its investment in its Syrian
interest at $102.0 million.
Total unrestricted cash and cash equivalents reduced by $25.9
million in the year to $7.9 million at 31 December 2014 (31
December 2013: $33.8 million). Restricted cash balances reduced by
$7.6 million to $11.5 million (31 December 2013: $19.1
million).
Operating performance
Year ended Year ended
31 December 31 December
2014 2013
General administrative expenses $' 000 $' 000
---------------------------------- ------------- -------------
Office expenses after partner
recoveries (12,163) (13,815)
Depreciation and amortisation (602) (1,124)
Office expenses capitalised 7,296 5,531
---------------------------------- ------------- -------------
General administrative expenses (5,469) (9,408)
---------------------------------- ------------- -------------
Gulfsands made significant progress in 2014 to further reduce
its operating cost base with general administrative expenses
reducing to $5.5 million in the year (2013: $9.4 million). $1.7
million of the reduction represents a reduction in office expenses
after partner recoveries. In addition to this: a reduction in
depreciation; and the progression in the Group's business model
toward operatorship of its assets as well as increased operational
activity, particularly in Morocco, resulting in increased amounts
capitalised, further reduced general administrative expenses by
$2.3 million in the year.
Exploration write-offs for the year totalled $6.0 million (2013:
$12.3 million), of which $5.2 million relates to Moroccan
operations and $0.8 million relates to Tunisian operations.
Expenditure written-off in relation to Moroccan operations included
$1.5 million of expenditure related to 2014 expenditures on the
wells drilled in the first phase of drilling on the Rharb Centre
permit, which commenced in October 2013 and completed in January
2014. These wells were deemed non-commercial and plugged and
abandoned. A further $3.7 million of expenditure, on activities
that were unsuccessful, was written-off in the year.
The Group reported a reduced loss before tax from continuing
operations of $12.1 million (2013: $25.4 million) for the year. In
addition to the reduction in general administrative expenses and
reduced exploration write-offs in the year, this improved
performance also reflects the incurrence of exceptional one-off
Syrian inventory write-offs and impairments in 2013 of $2.9
million.
The Group sold its investment in its wholly-owned US subsidiary,
Gulfsands Petroleum USA, Inc. ("GPUSA"), to Hillcrest Resources Ltd
("Hillcrest") for a consideration of $50k. As part of the sale and
purchase agreement the intercorporate debt owed by GPUSA to the
Gulfsands Group was also assigned to Hillcrest. The sale of the
investment in GPUSA means all of the Group's interests in oil and
gas licences in the Gulf of Mexico as well as their related
decommissioning liabilities and amounts held in escrow to guarantee
those decommissioning liabilities have been disposed of. The
transaction was completed on the 18 December 2014. Losses from
discontinued operations in the year were $4.0 million (2013: $1.4
million) consisting of a loss on disposal of $2.5 million in
addition to the loss for the eleven months to disposal generated by
the US operations of $1.5 million (2013 twelve months loss: $1.4
million). The results of the discontinued US operations have been
consolidated to 30 November 2014 which is treated as the effective
completion date; the results for the eighteen days to 18 December
2014 are considered not material to the Group. Under the
requirements of IFRS 5, the 2013 comparatives for the discontinued
operations have been reclassified in the Consolidated Income
Statement and Consolidated Cash Flow Statement.
The Group reported a reduced loss for the year of $16.1 million
(2013: $26.8 million).
Balance sheet
Property, plant and equipment reduced as the Group's producing
Gulf of Mexico oil and gas assets were disposed of in December 2014
as part of the sale of the Group's investment in GPUSA.
The Group continued to build on its exploration portfolio and
was awarded the Moulay Bouchta contract, onshore Morocco, in April
2014. At 31 December 2014, intangible exploration and evaluation
assets are held at a net book value of $53.0 million (31 December
2013: $37.1 million) of which $46.6 million relates to cumulative
expenditure capitalised against Moroccan permits (31 December 2013:
$31.6 million). Capital expenditures during the year totalled $21.0
million (2013: $46.5 million), on an accrued basis, including $7.9
million of drilling related costs incurred in respect of successful
drilling on the Rharb Centre permit. The drilling of LTU-1
commenced on 20 June 2014 and a gas discovery made. Drilling of the
DRC-1 well commenced on 19 December 2014. This well, was being
tested at year end and declared a discovery post year end. Drilling
continued into the first quarter of 2015 with a further well,
DOB-1, also declared a discovery post year end.
Other significant exploration expenditures incurred in the year
for Moroccan operations included: $1.1 million of Rharb Centre 3D
seismic costs with processing completed in the first quarter of
2014; $2.7 million of 2D seismic costs over the Fes area with the
acquisition and processing completing in the first quarter of 2014;
and $1.2 million for the first phase of drilling in Rharb Centre,
with the final well of three, BFD-2, completing in January 2014. As
a result of the increased operational activity during the year,
$7.3 million of operations office expenses were capitalised against
the Moroccan, Tunisian and Colombian contracts. Exploration
write-offs for the year totalled $6.0 million (2013: $12.3
million); the previous year included the cost of the three
unsuccessful wells drilled.
The fair value of the Group's net investment in its Syrian
interests remains unchanged at $102.0 million. The Board
reconsidered the valuation as at 31 December 2014, and it is their
view that there has been little significant change to the
circumstances and status of the Group's Syrian interests. The Board
are still unable to provide a firm view as to the eventual outcome
and the timing of resolution of the situation in Syria that would
lead to the EU lifting sanctions against Syria, allowing Gulfsands
to return, however, they continue to consider that its position in
respect of its interests remains strong and all indications are
that Syrian authorities expect Gulfsands and its partner to return
to operational control of their interests in accordance with the
terms of the PSC as soon as circumstances permit. The carrying
value of the Syrian interest continues to be supported by the
Group's valuation model based on the estimated future cash flows
that could be generated from the Group's remaining entitlement
reserves in Block 26 in Syria. Due to the recent significant fall
in oil price the Board has decided that it would be more
appropriate to use the forward Brent oil price curve to value
forecast production from the assets, with an assumption of 2% price
inflation beyond the end of the quoted curve. This would have a
significant impact on the value of near-term production but,
because the valuation model includes an assumption that the
recommencement of production is deferred for five years, the actual
impact on forecast revenues is limited. The Board continues to hold
the view that its current valuation of $102.0 million, representing
25% of the base "value in use" calculation for its Syrian
interests, remains fair and appropriate.
Trade and other receivables have decreased during the year to
$1.0 million (31 December 2013: $3.5 million). This is
predominantly due to the recovery of historic balances due from oil
and gas partners totalling $1.3 million.
Current trade and other payables at 31 December 2014 have
decreased significantly from 2013 year end to $5.9 million (31
December 2013: $15.2 million) predominantly as a result of the
timing of drilling operations in Morocco with substantially lower
activity at the 2014 year end than the previous year end.
Decommissioning provisions relate to abandonment and restoration
provisions on the Rharb Centre Moroccan wells and total $1.0
million at 31 December 2014. Decommissioning provisions at 31
December 2013 totalled $13.2 million and related to the US Gulf of
Mexico assets which have been disposed of in December 2014.
On 19 November 2014, the Group announced the closing of a $20.0
million convertible loan facility with Arawak Energy Bermuda Ltd
("Arawak") and subsequently drew down the first $5.0 million
tranche on 25 November 2014. The loan bears interest at 10% per
annum in addition to a commitment fee of 3% per annum on the
available facility, both of which are rolled up quarterly into the
loan balance. The loan matures on the 30 November 2017 and is
repayable in full on the maturity date. The convertible loan is a
hybrid financial instrument and the option to convert is an
embedded derivative. The conversion option has been valued at the
date of the first draw-down and at the year end using a
Black-Scholes model and the valuation considered immaterial for
separate recognition in the Balance Sheet. Subsequent to the year
end a further $5.0 million was drawn-down. In early March Arawak
requested early repayment of the outstanding loan amount.
Cash flow
Operating cash outflow from continuing operations was
substantially reduced in the year to $3.8 million (2013: $8.6
million) largely as a consequence of the reduction in general
administrative expenses.
Investing cash outflow from continuing operations during the
year totalled $24.0 million (2013 $45.6 million). This
predominantly consists of: $27.0 million of exploration expenditure
inclusive of $24.8 million spent on Moroccan operations and $1.75
million being placed as security with respect to the newly awarded
Moulay Bouchta licence obligations; partially offset by restricted
cash balances released during the year totalling $6.5 million.
The total cash outflow for the US discontinued operation in the
year was $2.8 million (2013: $3.0 million). This consisted of: cash
outflows for investing activities of $5.0 million (2013: $3.7
million); cash disposed of as part of the disposal of $0.2 million;
partially offset by cash generated by production operations of $2.4
million (2013: $0.7 million). The improvement in cash generated by
operating activities was due to the increased revenues from Eugene
Island Block 32 resulting from the work-over of well #33 and the
sidetrack of well #30. These work-overs and sidetracks were also
the reason for the increase in investing cash outflows in 2014.
The total decrease in cash and cash equivalents during the year
was $25.9 million (2013: $57.2 million).
Financial position
The Group had total unrestricted cash and cash equivalents of
$7.9 million (31 December 2013: $33.8 million).
Restricted cash balances at the end of the period (which are
presented as long-term financial assets in the Balance Sheet)
totalled $11.5 million, and represent funds securitised as
collateral in respect of future work obligations - principally in
respect of the Group's Moroccan interests. Restricted cash balances
have decreased by $7.6 million during the year as a result of: a
release of $6.5 million due to partial completion of the Moroccan
work programmes, disposal of the $2.9 million US guarantees as part
of the disposal of the investment in GPUSA, all partially offset by
a new $1.75 million deposit being placed for future work
obligations relating to the award of the Moulay Bouchta licence.
The restricted cash balances will continue to be released to the
Group as work programmes are completed with $2.5 million to be
repaid to a third party upon release.
Going concern
The Consolidated and Company Financial Statements have been
prepared on the going concern basis which has been approved by the
Board. The basis on which the Board has reached this decision is as
follows:
As at the date of this report, the Group has cash balances
immediately available to it totalling approximately $3.0 million
with net current liabilities of approximately $2.6 million and
ongoing costs currently approximating to $1.0 million per month.
Restricted cash balances and the work commitments to which they
relate are described in note 5 to the Preliminary Financial
Statements. Additionally, the Group has an outstanding loan of $10
million from Arawak, which they have requested be repaid. This loan
is described in note 7 to the Preliminary Financial Statements.
Early repayment will cause a minimum of $1 million of interest and
fees to also become payable.
The Board is in the process of actioning its strategy for each
asset and these strategies are laid out in the Operations Review of
this Report. This includes substantially reducing its costs whilst,
farming-down, divesting or otherwise rationalising certain
interests and the associated work commitments. In parallel the
Group is actioning a financing strategy which includes accessing a
short-term working capital loan from existing shareholders to
provide the Group with time to progress a more significant
financing exercise. The Board has received indications from certain
of its shareholders of a willingness to contribute to such a
working capital loan. Shortly, the Board will develop and
communicate its longer-term financing strategy which should allow
the Group to achieve the following:
-- repayment of the Arawak facility;
-- rationalisation of existing minimum work commitments;
-- further appraisal and exploitation of selected assets;
-- working capital to provide stability for the medium term.
As stated elsewhere, the Group may not finance all its work
commitments itself but will look to bring in partners to reduce the
Group's net exposure to such commitments to a level that the Board
considers sustainable and financeable or, alternatively, it will
divest itself of assets as necessary.
Based upon its experience and ongoing discussions with existing
shareholders and potential partners, the Board is confident that
the Group will be able to access appropriate resources to finance
the strategy that it is developing.
Notwithstanding the confidence that the Board has in its ability
to stabilise and finance the Group's re-shaped business, the
Directors, in accordance with FRC guidance in this area, conclude
that at this time there is material uncertainty that such finance
can be procured and failure to do so might cast significant doubt
upon the Company's and the Group's ability to continue as a going
concern and that the Company and the Group may therefore be unable
to realise their assets and discharge their liabilities in the
normal course of business. Such scenario could impact upon the
carrying value of intangible exploration and evaluation assets and
on the recoverability of certain restricted cash amounts, held in
escrow to support guarantees of performance of minimum work
obligations. See further details in note 5 to the Preliminary
Financial Statements.
However, following completion of a review of the going concern
position of the Company and Group at the meeting of the Board of
Directors on 18 May 2015, including the uncertainties described
above, the Board has concluded that, with current consolidated cash
and cash equivalents totalling $3.0 million and taking into account
both the revised strategy of farming-down or divesting assets and
new financial resources that the Board might reasonably expect to
become available, the Company and the Group will have sufficient
resources to continue in operational existence for the foreseeable
future, a period not less than twelve months from the date of
approval of this Annual Report. Accordingly, the Directors consider
it appropriate to continue to adopt the "going concern basis" in
preparing these Financial Statements.
Consolidated Income Statement
for the year ended 31 December 2014
2014 2013
Notes $'000 $'000
-------------------------------------- ----- -------- --------
Continuing Operations
General administrative expenses (5,469) (9,408)
Share-based payments (56) (514)
-------------------------------------- ----- -------- --------
Total administrative expenses (5,525) (9,922)
-------------------------------------- ----- -------- --------
Exploration costs written-off 5 (6,040) (12,301)
Syrian inventory provision/ write-off - (2,905)
Other Syrian adjustments (202) (383)
-------------------------------------- ----- -------- --------
Operating loss (11,767) (25,511)
Foreign exchange (losses)/ gains (218) 89
Bank fees and charges (76) (49)
Loan facility finance cost 7 (70) -
Net interest income 18 89
-------------------------------------- ----- -------- --------
Loss before taxation from continuing
activities (12,113) (25,382)
Taxation from continuing activities - -
Loss for the year from continuing
operations (12,113) (25,382)
Discontinued Operations
Loss for the year from discontinued
operations 2 (3,978) (1,375)
-------------------------------------- ----- -------- --------
Loss for the year attributable
to owners of the parent company (16,091) (26,757)
-------------------------------------- ----- -------- --------
Loss per share from continuing
operations (cents):
Basic and diluted 3 (10.28) (21.54)
-------------------------------------- ----- -------- --------
Loss per share attributable to
the owners of the parent company
(cents):
Basic and diluted 3 (13.65) (22.70)
-------------------------------------- ----- -------- --------
There are no items of comprehensive income outside of the Income
Statement.
Consolidated Balance Sheet
as at 31 December 2014
2014 2013
Notes $'000 $'000
---------------------------------- ----- -------- --------
Assets
Non-current assets
Property, plant and equipment 4 285 12,893
Intangible assets 5 53,352 37,558
Long-term financial assets 11,514 19,138
Investments 6 102,000 102,000
---------------------------------- ----- -------- --------
167,151 171,589
---------------------------------- ----- -------- --------
Current assets
Inventory 2,361 2,247
Trade and other receivables 1,028 3,542
Cash and cash equivalents 7,907 33,824
11,296 39,613
---------------------------------- ----- -------- --------
Total assets 178,447 211,202
---------------------------------- ----- -------- --------
Liabilities
Current liabilities
Trade and other payables 5,882 15,245
Provision for decommissioning 580 2,573
6,462 17,818
---------------------------------- ----- -------- --------
Non-current liabilities
Trade and other payables 6,178 6,155
Provision for decommissioning 397 10,578
Loan facility 7 4,855 -
---------------------------------- ----- -------- --------
11,430 16,733
---------------------------------- ----- -------- --------
Total liabilities 17,892 34,551
---------------------------------- ----- -------- --------
Net assets 160,555 176,651
---------------------------------- ----- -------- --------
Equity
Capital and reserves attributable
to equity holders
Share capital 13,131 13,131
Share premium 105,926 105,926
Merger reserve 11,709 11,709
Treasury shares (11,502) (11,502)
Retained profit 41,291 57,387
---------------------------------- ----- -------- --------
Total equity 160,555 176,651
---------------------------------- ----- -------- --------
Consolidated Statement of Changes in Equity
for the year ended 31 December 2014
Share Share Merger Treasury Retained Total
capital premium reserve shares profit equity
$'000 $'000 $'000 $'000 $'000 $'000
-------------------- -------- -------- -------- -------- -------- --------
At 1 January 2013 13,131 105,926 11,709 (11,619) 83,776 202,923
Options exercised - - -- 117 (148) (31)
Share-based payment
charge - - - - 516 516
Loss for 2013 - - - - (26,757) (26,757)
-------------------- -------- -------- -------- -------- -------- --------
At 31 December 2013 13,131 105,926 11,709 (11,502) 57,387 176,651
-------------------- -------- -------- -------- -------- -------- --------
Options exercised - - -- - (61) (61)
Share-based payment
charge - - - - 56 56
Loss for 2014 - - - - (16,091) (16,091)
-------------------- -------- -------- -------- -------- -------- --------
At 31 December 2014 13,131 105,926 11,709 (11,502) 41,291 160,555
-------------------- -------- -------- -------- -------- -------- --------
The merger reserve arose on the acquisition of Gulfsands
Petroleum Ltd and its subsidiaries by the Company by way of
share-for-share exchange in April 2005, in conjunction with the
flotation of the Company on the Alternative Investment Market of
the London Stock Exchange.
Consolidated Cash Flow Statement
for the year ended 31 December 2014
2014 2013
Notes $'000 $'000
--------------------------------------- ----- -------- --------
Cash flows from operating activities
Operating loss from continuing
operations (11,767) (25,511)
Depreciation and amortisation 4&5 602 877
Exploration costs written-off 5 6,040 12,301
Other Syrian adjustments 202 383
Share-based payment charge 56 514
Syrian inventory provision / write-off - 2,905
Decrease/ (increase) in receivables 1,598 (527)
(Decrease) / increase in payables (254) 318
Foreign exchange (losses) / gains (218) 89
Bank fees (76) (49)
Interest received 18 89
Net cash used in operating activities
by continuing operations (3,799) (8,611)
--------------------------------------- ----- -------- --------
Net cash generated by operating
activities of discontinued operations 2 2,347 724
--------------------------------------- ----- -------- --------
Total net cash used in operating
activities (1,452) (7,887)
--------------------------------------- ----- -------- --------
Investing activities
Acquisition of subsidiary undertaking - (17,103)
Exploration and evaluation expenditure (26,987) (17,302)
Inventory purchased (1,420) (2,247)
Other capital expenditures (340) (630)
Change in restricted cash balances 4,750 (8,270)
Net cash used in investing activities
by continuing operations (23,997) (45,552)
--------------------------------------- ----- -------- --------
Net cash used in investing activities
by discontinued operations 2 (5,011) (3,688)
--------------------------------------- ----- -------- --------
Total net cash used in investing
activities (29,008) (49,240)
--------------------------------------- ----- -------- --------
Financing activities
Loan draw-down 7 5,000 -
Transaction costs paid on loan
facility 7 (215) -
Other payments in connection with
options exercised (61) (31)
--------------------------------------- ----- -------- --------
Net cash provided by / (used in)
financing activities of continuing
operations 4,724 (31)
--------------------------------------- ----- -------- --------
Net cash used in financing activities
of discontinued operations 2 - -
Total net cash provided by / (used
in) financing activities 4,724 (31)
Cash disposed as part of disposal
of discontinued operations 2 (181) -
Decrease in cash and cash equivalents (25,917) (57,158)
Cash and cash equivalents at beginning
of year 33,824 90,982
--------------------------------------- ----- -------- --------
Cash and cash equivalents at end
of year 7,907 33,824
--------------------------------------- ----- -------- --------
Condensed Notes to the Preliminary Financial Statements
for the year ended 31 December 2014
General information
Gulfsands Petroleum plc is a public limited company listed on
the Alternative Investment Market ("AIM") of the London Stock
Exchange and incorporated in the United Kingdom. The principal
activities of the Company and its subsidiaries ("the Group") are
that of oil and gas production, exploration and development. The
address of the registered office is 1 America Square, Crosswall,
London, United Kingdom, EC3N 2SG. This preliminary announcement was
authorised for issue in accordance with a resolution of the Board
of Directors on 19 May 2015.
The financial information for the year ended 31 December 2014
set out in this announcement does not constitute statutory accounts
within the meaning of section 434 of the Companies Act 2006.
Statutory accounts for the year ended 31 December 2013 were
approved by the Board of Directors on 3 April 2014 and delivered to
the Registrar of Companies and those for 2014 will be delivered
following the Company's Annual General Meeting ("AGM").
While the financial information included in this preliminary
announcement has been prepared in accordance with International
Financial Reporting Standards ("IFRS"), this announcement does not
itself contain sufficient information to comply with IFRS. The
Company expects to distribute the full financial statements that
comply with IFRS in early June 2015.
Audit Report
The financial information set out above does not constitute the
Company's statutory accounts for the year ended 31 December 2014 or
2013, but is derived from those accounts. The Auditor has reported
on those accounts; its reports were unqualified, but did contain
two emphasis of matter paragraphs in 2014 in respect of: going
concern, on which further details are available below and in the
Financial Review; and in respect of the valuation of the Syrian
investment, on which further details are included in note 6 to the
Preliminary Financial Statements. The Auditor's Report did not
contain statements under sections 498(2) or (3) of the Companies
Act 2006.
Basis of preparation
The Preliminary Financial Statements has been prepared in
accordance with the recognition and measurement criteria of
International Financial Reporting Standards adopted for use in the
European Union. However, this announcement does not itself contain
sufficient information to comply with IFRS. The Company will
publish full financial statements that comply with IFRS in early
June 2015.
The Preliminary Financial Statements have been prepared under
the historical cost convention except for the share-based payments
and the valuation of available-for-sale investments.
The Preliminary Financial Statements are presented in US
Dollars. The majority of all costs associated with foreign
operations are denominated in US Dollars and not the local currency
of the operations. Therefore the presentational and functional
currency of the Group, and the functional currency of all
subsidiaries, is the US Dollar.
Going concern
The Preliminary Financial Statements has been prepared on the
going concern basis which has been approved by the Board,
notwithstanding the material uncertainty, as discussed in the going
concern section of the Financial Review.
Accounting policies
The accounting policies applied in this announcement are
consistent with those of the annual financial statements for the
year ended 31 December 2013, as described in those annual financial
statements. A number of amendments to existing standards and
interpretations were applicable from 1 January 2014. The adoption
of these amendments did not have a material impact on the Group's
financial statements for the year ended 31 December 2014.
1. Segmental analysis of continuing operations
For management purposes, at 31 December 2014 the Group operated
in three geographical areas: Morocco, Tunisia and Colombia with
suspended operations in Syria as discussed in note 6. All segments
are involved with the production of, and exploration for, oil and
gas. The "Other" segment represents corporate and head office
costs.
The Group's result and certain asset and liability information
for the year are analysed by reportable segment as follows. The
comparatives for the year ended 31 December 2013 have been
re-presented to remove the discontinued US operations.
Year ended 31 December 2014
Syria Morocco Tunisia Colombia Other Total
$'000 $'000 $'000 $'000 $'000 $'000
------------------------- -------- -------- --------- --------- -------- ---------
Total administrative
expenditure (482) (149) 10 (168) (4,736) (5,525)
Exploration costs
written-off - (5,246) (794) - - (6,040)
Other Syrian
adjustments (202) - - - - (202)
------------------------- -------- -------- --------- --------- -------- ---------
Operating loss (684) (5,395) (784) (168) (4,736) (11,767)
Financing cost (346)
---------
Net loss from
continuing activities (12,113)
------------------------- -------- -------- --------- --------- -------- ---------
Total assets 102,325 51,845 5,256 1,324 17,697 178,447
Total liabilities (3,827) (6,486) (1,587) (69) (5,923) (17,892)
------------------------- -------- -------- --------- --------- -------- ---------
E&E capital expenditure - 19,188 794 982 - 20,964
------------------------- -------- -------- --------- --------- -------- ---------
Year ended 31 December 2013
Syria Morocco Tunisia Colombia Other Total
$'000 $'000 $'000 $'000 $'000 $'000
-------------------------- -------- --------- -------- --------- -------- ----------
Total administrative
expenditure (1,573) (18) (280) (11) (8,040) (9,922)
Exploration costs
written-off - (10,147) (2,154) - - (12,301)
Other Syrian adjustments (383) - - - - (383)
Inventory provision
/ written-off (2,905) - - - - (2,905)
-------------------------- -------- --------- -------- --------- -------- ----------
Operating loss (4,861) (10,165) (2,434) (11) (8,040) (25,511)
Net financing
cost credit 129
----------
Net loss from
continuing activities (25,382)
-------------------------- -------- --------- -------- --------- -------- ----------
Total assets 104,128 39,924 5,673 489 44,640 194,854
Total liabilities (3,766) (12,562) (1,835) (347) (1,205) (19,715)
-------------------------- -------- --------- -------- --------- -------- ----------
E&E capital expenditure 474 41,783 3,553 243 - 46,053
-------------------------- -------- --------- -------- --------- -------- ----------
2. Discontinued operations
In November 2014 the Group entered into a sale agreement with
Hillcrest Resources Ltd to dispose of its
wholly-owned US subsidiary GPUSA. The disposal was completed on the 18 December 2014.
The results of the discontinued operations, which have been
included in the Consolidated Income Statement, were as follows:
2014 2013
$'000 $'000
--------------------------------------- ---------- --------
Revenue 5,366 4,367
Expenses (6,870) (5,742)
---------------------------------------- ---------- --------
Loss before tax (1,504) (1,375)
Attributable tax expense - -
--------------------------------------- ---------- --------
(1,504) (1,375)
Loss on disposal of discontinued (2,474)
operations -
--------------------------------------- ---------- --------
(3,978) (1,375)
Attributable tax expense - -
--------------------------------------- ---------- --------
Net loss attributable to discontinued
operations (attributable to
owners of the parent company) (3,978) (1,375)
---------------------------------------- ---------- --------
2. Discontinued operations (continued)
During the year, GPUSA contributed $2.4 million (2013: $0.7
million) to the Group's net operating cash flows and paid $5.0
million (2013: $3.7 million) in respect of investing activities.
Cash and cash equivalents of $0.2 million were disposed of as part
of the disposal of discontinued operations.
A loss of $2.5 million arose on the disposal of GPUSA being the
proceeds of disposal and the carrying amount of the subsidiary's
net assets, as follows:
$'000
-------------------------------------- ---------
Property, plant and equipment 13,458
Long term financial assets 2,865
Trade and other receivables 609
Cash and cash equivalents 181
Trade and other payables (3,601)
Provision for decommissioning (11,031)
--------------------------------------- ---------
Net assets of discontinued operation
at disposal 2,481
Consideration 50
Costs to sell (57)
--------------------------------------- ---------
Loss on disposal of discontinued
operations (2,474)
--------------------------------------- ---------
3. Loss per share
The basic and diluted loss per share have been calculated using
the loss for the year ended 31 December 2014 of $12.1 million
(2013: $25.4 million) for continuing operations and $16.1 million
(2013 : $26.8 million) for the loss attributable to the owners of
the parent company. The basic loss per share was calculated using a
weighted average number of shares in issue less treasury shares
held, of 117,886,145 (2013: 117,855,702). The weighted average
number of ordinary shares, allowing for the exercise of share
options, for the purposes of calculating the diluted loss per share
was 118,210,676 (2013: 118,192,648).
Where there is a loss, the impact of share options is
anti-dilutive and hence, basic and diluted loss per share are the
same.
4. Property, plant and equipment
Other
Oil and fixed
gas properties assets Total
$'000 $'000 $'000
----------------------------------- --------------- ------- --------
Cost:
At 1 January 2013 34,799 2,397 37,196
Additions 2,467 217 2,684
Changes to decommissioning
estimates (1,859) - (1,859)
----------------------------------- --------------- ------- --------
At 31 December 2013 35,407 2,614 38,021
----------------------------------- --------------- ------- --------
Additions 2,787 401 3,188
Changes to decommissioning
estimates (92) - (92)
Disposals (38,102) (180) (38,282)
----------------------------------- --------------- ------- --------
At 31 December 2014 - 2,835 2,835
----------------------------------- --------------- ------- --------
Accumulated depreciation
and depletion:
At 1 January 2013 (17,351) (1,691) (19,042)
Charge for 2013 (1,267) (479) (1,746)
At 31 December 2013 (18,618) (2,170) (20,788)
----------------------------------- --------------- ------- --------
Charge for 2014 (1,686) (556) (2,242)
Disposals 20,304 176 20,480
----------------------------------- --------------- ------- --------
At 31 December 2014 - (2,550) (2,550)
----------------------------------- --------------- ------- --------
Accumulated impairment:
At 1 January 2013 (4,282) - (4,282)
Impairment charge for 2013 (58) - (58)
At 31 December 2013 (4,340) - (4,340)
----------------------------------- --------------- ------- --------
Disposals 4,340 - 4,340
----------------------------------- --------------- ------- --------
At 31 December 2014 - - -
----------------------------------- --------------- ------- --------
Net book value at 31 December
2014 - 285 285
----------------------------------- --------------- ------- --------
Net book value at 31 December
2013 12,449 444 12,893
----------------------------------- --------------- ------- --------
In December 2014 the Group completed the disposal of all of its
US Gulf of Mexico interests, including its producing oil and gas
assets, through the disposal of its wholly-owned subsidiary, GPUSA.
See note 2 for further details of this disposal.
5. Intangible assets
Exploration and Evaluation assets
Computer
Syria Morocco Tunisia Colombia software Total
$'000 $'000 $'000 $'000 $'000 $'000
Cost:
At 1 January 2013 10,031 -- 4,796 - 2,537 17,364
Additions 474 41,783 3,553 243 421 46,474
Other write-offs - - (1,000) - (475) (1,475)
Exploration expenditure
written-off - (10,147) (2,154) - - (12,301)
At 31 December 2013 10,505 31,636 5,195 243 2,483 50,062
-------------------------- -------- --------- ------- ---------- --------- --------
Additions - 19,188 794 982 10 20,974
Change in decommissioning
estimates - 977 - - - 977
Disposals - - - - (123) (123)
Exploration expenditure
written-off - (5,246) (794) - - (6,040)
-------------------------- -------- --------- ------- ---------- --------- --------
At 31 December 2014 10,505 46,555 5,195 1,225 2,370 65,850
-------------------------- -------- --------- ------- ---------- --------- --------
Accumulated amortisation:
At 1 January 2013 - - - - (1,126) (1,126)
Charge for 2013 - - - - (398) (398)
At 31 December 2013 - - - - (1,524) (1,524)
-------------------------- -------- --------- ------- ---------- --------- --------
Charge for 2014 - - - - (46) (46)
Disposals - - - - 52 52
-------------------------- -------- --------- ------- ---------- --------- --------
At 31 December 2014 - - - - (1,518) (1,518)
-------------------------- -------- --------- ------- ---------- --------- --------
Accumulated impairment:
At 1 January 2013 (10,031) - - - - (10,031)
Impairment provision
for 2013 (474) - - - (475) (949)
-------------------------- -------- --------- ------- ---------- --------- --------
At 31 December 2013 (10,505) - - - (475) (10,980)
-------------------------- -------- --------- ------- ---------- --------- --------
Impairment provision - - - - - -
for 2014
-------------------------- -------- --------- ------- ---------- --------- --------
At 31 December 2014 (10,505) - - - (475) (10,980)
-------------------------- -------- --------- ------- ---------- --------- --------
Net book value at
31 December 2014 - 46,555 5,195 1,225 377 53,352
-------------------------- -------- --------- ------- ---------- --------- --------
Net book value at
31 December 2013 - 31,636 5,195 243 484 37,558
-------------------------- -------- --------- ------- ---------- --------- --------
Syria
The accumulated costs of E&E assets in Syria represent the
Group's share of the drilling costs of the Al Khairat, Twaiba and
Wardieh wells and certain 3D seismic surveys. The Al Khairat well
was successfully tested but commercial development approval is yet
to be granted by the government of the Syrian Arab Republic. The
Twaiba and Wardieh wells are still under evaluation.
Following the imposition of EU sanctions against the oil
industry in Syria, an impairment test was conducted and the
carrying value of all E&E assets in Syria was impaired to nil
as it is was unclear whether the Group would be able to apply for
commercial development approval in the manner contemplated by the
Production Sharing Contract. That position remains at the date of
this Report.
Morocco
Moroccan E&E assets at 31 December 2014 represent
exploration expenditure on the Rharb Centre, Rharb Sud, Fes and
Moulay Bouchta permits, in addition to $17.8 million of fair value
attributed to the Fes, Rharb Centre and Rharb Sud permits at
acquisition in 2013, less write-offs.
In respect of the Rharb petroleum contract, the BFD-2 well was
completed in early January 2014, considered non-commercial and
plugged and abandoned. In 2014, $1.3 million of costs related to
the three non-commercial wells in the first phase of drilling were
written-off. In addition, during 2014, $3.9 million of further
abortive exploration expenditure was written-off.
In June 2014, a second phase of drilling commenced with the
fourth Rharb well, LTU-1. This well discovered hydrocarbons and was
temporarily suspended as a future gas producer. Drilling of the
fifth well on the Rharb Centre permit, DRC-1, commenced in December
2014 and completed shortly after the year end as a discovery and
also temporarily suspended as a future gas producer. At the year
end, as the commerciality of these two wells had not been
determined, the cost of these wells was retained in intangible
assets.
Management have reviewed the carrying value of all its interests
in Morocco as at the date of this Report and notes that the Rharb
contract expires in November 2015 and the Fes contract in September
2015. There remain significant work obligations to be performed on
both contracts as set out below and which, if not completed before
expiry, could lead to ONHYM terminating those contracts. The Moulay
Bouchta contract by contrast expires in June 2016. Management have
considered the risks associated with licence expiry and are
optimistic that through dialogue with ONHYM and with its partner it
can retain these contracts in good order. Management would seek to
restructure some of the work obligations to allow the contracts to
be appropriately re-financed or divested in part or whole. Should
Management be unsuccessful in this strategy, the carrying value of
those assets and the restricted cash, set out below, securing those
work obligations would become impaired. However, Management has
considered the risks and determined that no impairment in the
carrying value of its Moroccan interests is appropriate at this
time.
Tunisia
At 31 December 2014, the Tunisian E&E assets represent
expenditures on the Chorbane permit including amounts paid during
2013 to increase participation in the licence. During 2014, $0.8
million of abortive exploration expenditure was written-off. The
Chorbane licence expires in July 2015 but Management are actively
pursuing an extension to that contract following which a part or
full disposal of its interests would be anticipated. Management
have reviewed its intentions for these assets and the carrying
value thereof as at the date of this report and concluded that no
impairment of their carrying value is required. Management notes
however, that if the licence is not extended or if satisfactory
terms in any disposal cannot be obtained then the carrying value of
this asset might become impaired. There is no security deposit or
other guarantee in place with respect to these work
obligations.
Colombia
The Group has interests in E&P contracts over two blocks in
Colombia; LLA 50 and PUT 14, which expire in November 2016 and
November 2017 respectively. At 31 December 2014 the E&E assets
of $1.2 million (2013: $0.2 million) represent costs incurred in
respect of these blocks which are in the early stages of
exploration. Management have reviewed its intentions for these
assets, which could include divestment thereof, and the carrying
value of these assets as at the date of this report and concluded
that no impairment of their carrying value is required. The work
obligations and the restricted cash securing these obligations are
set out below. Both the asset carrying values and the restricted
cash amounts could become impaired should the Group fail to satisfy
the work obligations or to realise sufficient value from any
divestment or farm-out.
Work obligation commitments
At 31 December 2014 the Group had the following capital
commitments in respect of its exploration activities:
Morocco
Rharb permit - licence expiry date and deadline for fulfilment
of capital commitments extended to November 2015
-- Drilling of a further four exploration wells. Note DOB-1 was
drilled in the first quarter of 2015.
-- Total cost of commitments outstanding estimated at $9.3 million including DOB-1.
$1 million (2013: $6 million) of deposits have been lodged to
support guarantees given to ONHYM in respect of completion of these
minimum work commitments. Of these amounts $1 million (2013: $1
million) is payable to a third party following release of deposits
by ONHYM. Note, by agreement subsequent to the year end, the amount
repayable to the third party has reduced to a maximum of $0.5
million.
Fes permit - licence expiry date and deadline for fulfilment of
capital commitments; September 2015
-- Drilling of three exploration wells.
-- Acquisition of a further 350 km of 2D seismic.
-- Acquisition of 100 km(2) of 3D seismic.
-- Total cost of commitments outstanding estimated at $32.8
million inclusive of a $5.7 million carry in favour of a third
party.
$5 million (2013: $6.5 million) of deposits have been lodged to
support guarantees given to ONHYM in respect of completion of these
minimum work commitments. Of these amounts, $1.5 million (2013:
$1.5 million) is payable to a third party following release of
deposits by ONHYM.
Moulay Bouchta permit - licence expiry date and deadline for
fulfilment of capital commitments; June 2016
-- Acquisition of a 500km of 2D seismic.
-- Reprocessing and interpretation of existing seismic data.
-- Legacy oil field reactivation survey.
-- Total cost of commitments estimated at $6.5 million.
$1.75 million (2013: $nil) of deposits have been lodged to
support guarantees given to the ONHYM in respect of completion of
these minimum work commitments.
Tunisia
Chorbane permit - licence expiry date and deadline for
fulfilment of capital commitments; July 2015
-- Drilling of one exploration well.
-- Total commitments outstanding estimated at $7.0 million.
Colombia
Putumayo 14 - licence expiry date and deadline for fulfilment of
capital commitments; November 2017
-- Drilling of one exploration well.
-- 2D seismic minimum 103 km.
-- Total commitments outstanding estimated at $22.9 million.
Llanos 50 - licence expiry date and deadline for fulfilment of
capital commitments; November 2016
-- Drilling of one exploration well.
-- 2D seismic minimum 93 km.
-- Total commitments outstanding estimated at $14.6 million.
$3.2 million (2013: $3.2 million) of deposits have been lodged
to support guarantees given to the Agencia Nacional de
Hidrocarburos in respect of completion of these minimum work
commitments on Putumayo 14 and Llanos 50.
The deposits referenced in this note are shown as long-term
financial assets in the Consolidated Balance Sheet.
6. Investments
The Group is party to a PSC for the exploitation of hydrocarbon
production in Block 26 in Syria. Pursuant to the PSC the Group
operates its Syrian oil and gas production assets through a joint
venture administered by DPC in which the Group has a 25% equity
interest. The Group lost joint control of DPC on 1 December 2011
following the publication of European Union Council Decision 2011 /
782 / CFSP. For the purposes of EU sanctions, DPC is considered to
be controlled by General Petroleum Corporation. Since the Group has
neither joint control nor significant influence over the financial
and operating policy decisions of the entity, it carries its
investment in DPC and the associated rights under the Block 26 PSC
as an available-for-sale financial asset. The fair value attributed
to DPC at 31 December 2014 is $102 million (31 December 2013: $102
million).
The valuation that the Group carries for its investment in DPC
is supported by the Company's economic model of the estimated
future cash flows that could be generated in respect of the Group's
entitlement reserves in Block 26. The model uses oil prices quoted
on the current forward Brent oil price curve, with an assumption of
2% price inflation beyond the end of the quoted curve discounted
using a 15% discount rate. The basic model also assumes a
short-term resumption of production. The net present value ("NPV")
derived from this model ("the base case NPV") is then subjected to
scenario analysis taking into account the Board's view of specific
risks associated with investments in the Syrian oil and gas sector
at the current time including the potential for significant delay
in resumption of oil production and in receipt of revenues,
potential additional costs associated with re-establishment of
operations and, ultimately, a potential inability to resume
operations. This methodology supports a valuation for the Group's
investment in DPC of $102 million which represents a 74% discount
to the base case NPV. The valuation represents a level 3
measurement basis as defined by IFRS 7.
Note, in previous financial periods the Group used a long-term
Brent oil price assumption of $90 / bbl in the valuation but, due
to the recent significant fall in the oil price, the Board decided
it was more appropriate to use the forward Brent oil price curve to
value forecast production from the assets. Whilst this change would
have a significant impact on the value of near-term production,
because the valuation model scenarios include an assumption that
the re-commencement of production is subject to a significant
delay, the actual impact on forecast revenue values is limited.
There is a high degree of subjectivity inherent in the valuation
due to the unknown duration of the sanctions and the eventual
outcome of events in Syria. Accordingly it may change materially in
future periods depending on a wide range of factors.
The following table sets out the impact that changes in the key
variables would have on the carrying value of the asset:
Change in
carrying
value of
Change investment
% $'000
----------------------------------------- ------ -----------
Increase in forecast capital expenditure 5% (1,888)
Decrease in long-term commodity
prices 5% (6,214)
Increase in forecast operating
expenditure 5% (1,015)
Change in discount rate to 10% 5% 40,022
Change in discount rate to 20% 5% (25,267)
----------------------------------------- ------ -----------
The Directors have reviewed the carrying value of this
available-for-sale financial asset at 31 December 2014 and are of
the opinion that the valuation, although subject to significant
uncertainty, remains appropriate in the circumstances, although not
necessarily reflective of the value of the Group's investments in
its Syrian operations over the long-term.
7. Convertible loan - Arawak Energy Bermuda Ltd
On 19 November 2014, the Group announced the closing of a
convertible loan facility of $20 million with Arawak Energy Bermuda
Ltd ("Arawak"). The loan has an initial available facility of $10
million with the balance of the facility available contingent upon
additional exploration drilling success in Morocco. The facility
has a twelve month availability period.
The loan bears interest at the rate of 10% per annum on the
drawn-down facility, which is rolled up into the loan balance
quarterly from the date of the draw-down. A commitment fee of 3% is
charged on the available facility undrawn during the twelve month
availability period and is rolled up into the loan balance
quarterly from the date of the loan draw-down. The loan matures on
30 November 2017 and is repayable in full on that date. Gulfsands
may prepay the facility on 60 days notice.
The loan amount (including amounts drawn and accrued but unpaid
interest and fees) is convertible at any time prior to maturity
into ordinary shares of the Company, initially at a price of
GBP0.80. In the event that the Company issues new shares prior to
conversion, repayment or maturity of the loan facility, Arawak
shall have the right but not the obligation to subscribe for new
shares, up to the amount of the loan amount at that time, at the
same subscription price per share as paid by the other subscribers.
If Arawak elects not to participate in such issue of new shares,
the mechanics of conversion of the loan amount provide that an
adjustment be made in order that Arawak's conversion rights will
continue to represent an entitlement to the same proportion of the
Company's issued share capital after the new issue of shares as
they represented prior to such new issue of shares.
Gulfsands may require conversion of the outstanding balance of
the loan facility into ordinary shares of the Company in the event
Gulfsands' share price, on an unadjusted basis, exceeds GBP1.04 per
share for a period of more than twenty consecutive trading days at
any time prior to the expiry of the term of the facility.
The loan facility is secured by a share mortgage over the shares
in Gulfsands Petroleum Morocco Ltd (the holding company for the
Group's interests in Morocco) and a floating charge over all of the
assets of Gulfsands Petroleum Holdings Limited (a subsidiary
company) with further credit support provided by a guarantee from
the Company.
On 25 November 2014 the Group drew-down the first $5.0 million
tranche of the loan facility.
The embedded derivative element of the loan amount has been
valued using a Black-Scholes model. The model assumes an expected
life of three years, a risk free rate of 0.8% and a volatility of
60%. The valuation of the embedded derivative at the date of the
first draw-down, 25 November 2014, and at the year end, 31 December
2014 is not considered material and has therefore not been
separately recognised from the host loan debt instrument.
Management will continue to revalue the conversion option at
subsequent accounting period ends and reassess its materiality. The
valuation represents a level 3 measurement basis as defined by IFRS
7.
The movement in the loan balance in the year is represented as
follows:
$'000
---------------------------------- -----
Loan draw-down 5,000
Transaction costs (215)
Interest expense 49
Commitment fee 15
Amortisation of transaction costs 6
---------------------------------- -----
At 31 December 2014 4,855
---------------------------------- -----
Glossary of Terms
1C Low estimate (P90) Contingent Resources
2C Best estimate (P50) Contingent Resources
3C High estimate (P10) Contingent Resources
ADX ADX Energy Limited
AIM Alternative Investment Market of the London Stock Exchange
Arawak Arawak Energy Bermuda Ltd
bbl Barrel of oil
bcf Billion cubic feet of gas
boe Barrels of oil equivalent where the gas component is
converted into an equivalent amount of oil using a
conversion rate of 1bcf to 0.1667 mmboe
bopd Barrels of oil per day
DPC Dijla Petroleum Company
E&E Exploration and evaluation
E&P Exploration and production
FRC Financial Reporting Council
G&A General and administrative expenses
GPC General Petroleum Corporation
GPUSA Gulfsands Petroleum USA, Inc.
Hillcrest Hillcrest Resources Ltd
IFRS International Financial Reporting Standards
km Kilometres
km(2) Square kilometres
KPI Key Performance Indicators
mboe Thousand barrels of oil equivalent
mcf Thousand cubic feet of gas
MD Measured depth
MENA Middle East and North Africa
mmbbl Millions of barrels of oil
mmboe Millions of barrels of oil equivalent
mmscfpd Million standard cubic feet per day
NGLs Natural Gas Liquids
NPV Net present value
ONHYM Office National des Hydrocarbures et des Mines (Morocco)
Possible reserves Possible reserves are those additional
reserves which analysis of geological and engineering
data suggests are less likely to be recoverable than Probable
reserves. The total quantities ultimately
recovered from the project have a low probability to exceed the
sum of Proved plus Probable plus Possible
("3P") reserves, which is equivalent to the high estimate
scenario. In this context, when probabilistic
methods are used, there should be more than a 10% probability
that the quantities actually recovered
will equal or exceed the 3P estimate.
Probable reserves Probable reserves are those unproved reserves
which analysis of geological and engineering data
suggests are more likely than not to be recoverable. In this
context, when probabilistic methods are used,
there should be more than a 50% probability that the quantities
actually recovered will equal or exceed
the sum of estimated Proved plus Probable reserves.
Proved reserves Proved reserves are those quantities of
petroleum which, by analysis of geological and engineering
data,
can be estimated with reasonable certainty (normally over 90% if
measured on a probabilistic basis) to be
commercially recoverable, from a given date forward, from known
reservoirs and under defined economic
conditions, operating methods, and government regulations.
P10 There exists a 10% probability that the true quantity or
value is greater than or equal to the stated P10
quantity or value
P50 There exists a 50% probability that the true quantity or
value is greater than or equal to the stated P50
quantity or value
P90 There exists a 90% probability that the true quantity or
value is greater than or equal to the stated P90
quantity or value
PRMS The 2007 Petroleum Resources Management classification
system of the SPE
PSC Production Sharing Contract
psi Pounds per square inch
Senergy Senergy (GB) Limited
SPE Society of Petroleum Engineers
TD Total depth
WPC World Petroleum Congress
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Gulfsands Petroleum (LSE:GPX)
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From Jun 2024 to Jul 2024
Gulfsands Petroleum (LSE:GPX)
Historical Stock Chart
From Jul 2023 to Jul 2024