TIDMSIA
RNS Number : 5697Q
Soco International PLC
13 September 2017
SOCO International plc
("SOCO" or the "Company")
INTERIM RESULTS FOR THE HALF YEAR TO 30 JUNE 2017
SOCO, an international oil and gas exploration and production
company, today announces its Interim Results for the half year
ended 30 June 2017 ("1H 2017").
Ed Story, President and Chief Executive Officer, commented:
"Underpinned by financial strength that has endured low oil
prices and harsh macro-economics, whilst delivering sustained cash
returns to shareholders, our tenacity was rewarded on many fronts
in the first half of 2017. The $42.7m payable associated with the
2005 sale of our Mongolia assets was recovered in full, whilst in
Vietnam, the TGT Full Field Development Plan was formally approved,
additional water-handling construction commenced and development
infill drilling was completed on time and within budget. In Congo
(Brazzaville), favourable terms on the Lidongo Permit were
achieved, with potential for three further permits to be agreed. We
remain confident that, as we focus on strategically reshaping the
business and growing our portfolio, we will continue to deliver
substantive value to shareholders."
OPERATIONAL HIGHLIGHTS
Vietnam
-- Stable rates of production during 1H 2017, averaged 29,600
BOEPD gross and 8,606 BOEPD net to SOCO's working interest (1H2016:
37,180 BOEPD and 10,862 BOEPD, respectively).
o Te Giac Trang ("TGT") production averaged 7,056 BOEPD net
(1H2016: 9,252 BOEPD)
o Ca Ngu Vang ("CNV") production averaged 1,550 BOEPD net
(1H2016: 1,610 BOEPD)
-- Full Field Development Plan for TGT approved in February 2017
-- Two infill wells, TGT-30P on the H1-WHP and TGT-29P on the
H5-WHP, executed on time and within budget
o TGT-30P producing at 2,500 BOEPD and TGT-29P producing at
1,600 BOEPD
-- Installation of new processing equipment on the TGT H1
Wellhead Platform ("WHP") currently well advanced which will allow
for higher levels of water management and oil production
Republic of Congo (Brazzaville)
-- Discussion to improve the commercial terms of the 20-year
Lidongo Permit concluded in 1Q 2017
o Discussions with the authorities and the Marine XII partners
on commercialisation of the Lidongo area continue.
-- Applications for three further exploration permits were
submitted in March 2017 for retention of the Lideka East, Viodo and
Loubana prospect areas beyond the expiry of the Marine XI
Exploration Licence.
FINANCIAL HIGHLIGHTS
-- Increase in return to shareholders to $21.0m via a final
dividend of 5 pence per share for 2016 (1H 2016: $9.4m), paid on 16
June 2017
-- Ongoing balance sheet strength; half year-end cash and liquid
investments balance of $132.0m with no debt ($100.3m at 31 December
2016)
o $42.7m collected in March in association with the 2005 sale of
Mongolia assets
-- Low cash operating costs just under $13/bbl (1H 2016: $10/bbl)*
-- Cash capital expenditure down to $15.5m (1H 2016: $27.2m)
-- Revenues up at $74.0m (1H 2016: $72.7m)
-- Net operating cash flow of $27.1m (1H 2016: $16.2m)
-- Net loss down to $6.7m (1H 2016: loss $12.2m)
-- Average realised crude oil price up at $53.90/bbl, a $2.13
premium to Brent (1H 2016: $40.89/bbl)
OUTLOOK
-- 2017 production guidance range is maintained at 8,000 to
9,000 BOEPD, reflecting planned shut-ins later in the year
-- Formal signing of Production Sharing Contract over Blocks 125
& 126, offshore Vietnam, after Vietnamese Government and Prime
Minister approval in August 2017.
-- Ongoing focus on sustainable cash flow generation and commitment to strategy of cash returns
-- 2017 capital expenditure of $50.0m (Vietnam $35.0m, Africa
$15.0m) fully funded from existing cash resources
-- Transformational business development involving growth and rationalisation of the portfolio
ENQUIRIES:
SOCO International plc
Roger Cagle, Deputy Chief Executive and Chief Financial
Officer
Antony Maris, Chief Operating Officer
Tel: 020 7747 2000
Camarco
Billy Clegg
Georgia Edmonds
Tel: 020 3757 4980
NOTES TO EDITORS
SOCO is an international oil and gas exploration and production
company, headquartered in London and traded on the London Stock
Exchange. The Company has field development and production
interests in Vietnam and exploration and appraisal interests in the
Republic of Congo (Brazzaville) and Angola.
_______________________
* See Glossary
CHAIRMAN AND CHIEF EXECUTIVE'S STATEMENT
SOCO's hallmark disciplined approach to capital allocation,
solid cash flow and low cash operating costs have made the Company
a strong performer through a prolonged period of low and volatile
oil prices. Our strategy has delivered sustainable cash returns to
shareholders, has internally cash funded ongoing development
operations and, moreover, has positioned the Company to focus on
growth, new ventures and further shaping of the business.
SOCO's balance sheet remains robust with zero debt and over
$130.0m in cash, cash equivalents and liquid investments at half
year-end after returning $21.0m to shareholders through a cash
dividend and fully funding its 1H capital expenditure programme.
The Company is vigorously reviewing business development growth
opportunities and options to maximise value from its current
assets.
OPERATIONS REVIEW
Group operations throughout 1H 2017 centred on optimising
production efficiency on Te Giac Trang ("TGT") and Ca Ngu Vang
("CNV") Fields in our core business area, offshore Vietnam. Two
infill wells were completed on time and within budget under the
2017 TGT Development Drilling Programme and construction of new
processing equipment for installation on the TGT H1-Wellhead
Platform ("WHP") is well advanced. Negotiations have been
successfully concluded securing a Production Sharing Agreement over
Blocks 125 & 126, also offshore Vietnam.
VIETNAM
Production
Both TGT and CNV Fields achieved stable rates during 1H 2017.
Gross production averaged 29,600 BOEPD and 8,606 BOEPD net to
SOCO's working interest.
TGT field production in 1H 2017 averaged 23,401 BOEPD gross and
7,056 BOEPD net to SOCO's working interest. CNV field production in
1H 2017 averaged 6,199 BOEPD gross and 1,550 BOEPD net to SOCO's
working interest. The average realised crude oil price for 1H 2017
was $53.90/bbl, a premium of $2.13/bbl to Brent.
Production by field 1H 2017 1H 2016 1H 2017 1H 2016 FY 2016
(gross) (gross) (net) (net) (net)
===================== ========= ========= ======== ======== ========
TGT Production 23,401 30,739 7,056 9,252 8,330
===================== ========= ========= ======== ======== ========
Oil 21,898 28,530 6,604 8,588 7,825
===================== ========= ========= ======== ======== ========
Gas(1) 1,503 2,209 452 664 505
===================== ========= ========= ======== ======== ========
CNV Production 6,199 6,441 1,550 1,610 1,553
===================== ========= ========= ======== ======== ========
Oil 4,199 4,446 1,050 1,111 1,076
===================== ========= ========= ======== ======== ========
Gas(1) 2,000 1,995 500 499 477
--------------------- --------- --------- -------- -------- --------
Total Production 29,600 37,180 8,606 10,862 9,883
===================== ========= ========= ======== ======== ========
Oil 26,097 32,976 7,654 9,699 8,901
===================== ========= ========= ======== ======== ========
Gas(1) 3,503 4,204 952 1,163 982
--------------------- --------- --------- -------- -------- --------
Figures in BOEPD
1 Assumes oil equivalent conversion factor of 6,000 standard
cubic feet per barrel of oil equivalent.
SOCO's production guidance range for 2017 is maintained at 8,000
to 9,000 BOEPD for the full year 2017 reflecting planned shut-ins
later in the year.
Block 16-1 - TGT Field
(30.5% working interest; operated by Hoang Long Joint Operating
Company ("HLJOC"))
TGT is currently producing from three platforms, which have a
total of 28 producing wells and one injector well, and is located
in the north-eastern part of Block 16-1 offshore Vietnam.
TGT Field Development
Formal approval of the updated TGT Full Field Development Plan
("FFDP") was received from the Vietnamese Government in February
2017, following submission in Q4 2016. The FFDP is a dynamic plan,
incorporating development beyond 2017 and considerations resulting
from prediction scenarios based on the 2016 TGT Reserve Assessment
Report and the 2015 TGT Geological Model and the Dynamic
Simulation. The approval provides for up to 18 additional wells,
with locations and additional support to be defined at a later
date, and installation of new processing equipment on the H1-WHP,
with the focus being on arresting and reversing the production
decline of the field.
The TGT Development Drilling Programme commenced in Q4 2016 with
two infill wells on the H4-WHP. Two further infill wells were added
to the programme for execution during 2017. Accordingly, drilling
operations on the TGT Field resumed in March 2017 with the jack-up
drilling rig, PetroVietnam Drilling VI ("PVD VI") moving on
location at the H1-WHP. The TGT-30P well spudded on 8 March 2017,
targeting the Miocene and Oligocene reservoir horizons in the
crestal part of the H1.1 fault block. TGT-30P is now producing
approximately 2,500 BOEPD with an as-expected 40% water cut.
On completion of TGT-30P, the PVD VI moved to the H5-WHP in the
southern part of the field to drill the TGT-29P infill well.
Drilling utilised smart completion technology to optimise
hydrocarbons recovery. The TGT-29P well was tied into the
production system in June 2017, after being completed on time and
within budget, and is producing at approximately 1,600 BOEPD.
The third and final drilling operation in the 2017 TGT
Development Drilling Programme was the resumption of the TGT-14X
step-out appraisal well on the H5 south fault block, initially
spudded in 2015. The high angle and long reach of the well has
added complexity to drilling operations. The well was successfully
drilled to the target depth, however, poor hole conditions
prevented successful completion of the well. Smaller, non-standard
drilling equipment will be required to re-drill the reservoir
section of the well and, consequently, completion of drilling has
been deferred to the next campaign.
TGT Production Optimisation
Construction of new processing equipment for installation on
H1-WHP is complete and installation activities fully underway. The
processing equipment will handle an additional 90,000 barrels of
liquid per day ("BLPD") with specific water handling capacity of up
to 65,000 barrels of water per day. This will increase the handling
capacity of the total system to approximately 180,000 BLPD,
allowing for higher levels of oil production at the same or higher
water cut rate than previously possible.
Block 9-2 - CNV Field
(25% working interest; operated by Hoan Vu Joint Operating
Company ("HVJOC"))
The CNV Field is located in the western part of Block 9-2
offshore Vietnam. Discussions with the Bach Ho owners are ongoing
to establish the most effective means of enhancing performance
through modifications at the reception terminal. Fishing operations
on CNV-6PST1 to recover wireline stuck in the completion were
unsuccessful. Alternative operations to work over the well are
being considered for execution in 2018.
Vietnam New Ventures
Following the 2015 signing of a Memorandum of Understanding,
SOCO received approval from the Vietnam government in May 2016 to
enter into formal negotiations with PetroVietnam and SOVICO
Holdings over a Production Sharing Contract ("PSC") for Blocks 125
& 126, offshore central Vietnam. These discussions are complete
and the PSC was approved by the Vietnamese Government and Prime
Minister in August 2017. Formal signature of the final PSC is being
arranged and is anticipated in Q4 2017. The capital expenditure for
2017 includes the purchase of existing seismic data for Blocks 125
& 126.
Blocks 125 & 126 are in moderate to deep water in the Phu
Khanh Basin, to the north of the Cuu Long Basin, and have multiple
structural and stratigraphic plays observed on the available
seismic data. Interpretation of the available data indicates there
is good potential for source, expulsion and migration of oil with
numerous reservoir and seal intervals likely. Initial activities
will include reprocessing and interpretation of seismic data, with
a view to there being a first exploration well potentially in
2021-2022.
Vietnam 2017 capital expenditure
The firm capital expenditure budget for Vietnam remains at
approx. $35.0m and is fully funded from existing cash resources.
The budget includes the funding of the 2017 TGT Development
Drilling Programme, infrastructure upgrade on our existing assets
and the purchase of existing seismic data for new venture Blocks
125 & 126.
REPUBLIC OF CONGO (BRAZZAVILLE)
Marine XI Block
(Operated, 40.39% working interest)
Activity during 1H 2017 was focussed on securing production and
exploitation permits in the prospect areas beyond the expiry of the
exploration licence on 30 March 2017.
Lidongo
A 20-year production and exploitation permit ("PEX") over the
Lidongo prospect area, to the north east, commenced in Q4 2016,
followed by discussions to improve its commercial terms which
concluded in Q1 2017 and is pending the approval of the Congolese
Ministry of Hydrocarbons. Discussions with the authorities and the
Marine XII partners on commercialisation of the Lidongo area
continue.
Loubana, Lideka East and Viodo
Three further PEX applications were submitted in March 2017 over
the three remaining prospect areas on Marine XI: Loubana in the
north west, Lideka East to the south west and Viodo in the centre
and south east. The Company has been informed by the Congolese
Ministry of Hydrocarbons that, pending approval of the PEX
applications, the Marine XI research permit is considered
extended.
ANGOLA
Cabinda North Block
(Non-operated, 17% working interest)
Discussions amongst the partners and the authorities are ongoing
to agree the new partnership, operator and activities during the
licence extension period to April 2018. The legal documents to
complete the changes are pending formal approval.
FINANCIAL RESULTS
The Group retains its strong financial position despite the
continuing low oil price environment. The Group has a robust
balance sheet with no debt, low operating cash costs and attractive
Vietnam production economics, which underpin the SOCO business
model.
First half 2017 results were in line with the Company's
expectations. Cash balances and liquid resources as of 30 June 2017
were $132.0m, including $42.7m collected in March 2017 in
association with the Company's full and final collection of the
receivable due following the disposal of its Mongolia assets in
2005 and after returning $21.0m in cash to shareholders through a
5p per share dividend.
Revenues for the first six months of 2017 were $74.0m (1H 2016:
$72.7m). The average realised oil price per barrel achieved for the
same period was approx. $53.90 (1H 2016: $40.89), representing a
premium of approx. $2/bbl to Brent; a similar premium is expected
for the remainder of 2017.
A final dividend of 5 pence per share for 2016 was approved at
the AGM and paid to shareholders on 16 June 2017.
The capital expenditure forecast for 2017 remains at approx.
$50.0m. In Vietnam, $35.0m is included to cover the development
drilling and infrastructure upgrade on our existing assets and the
purchase of existing seismic data for the Blocks 125 & 126 new
venture. $15.0m is included for Africa to cover Marine XI PEX
bonuses.
KEY FINANCIAL METRICS
1H 2017 1H 2016
---------------------------------------------------- -------- --------
Oil and gas revenue ($m) 74.0 72.7
---------------------------------------------------- -------- --------
Oil price realised ($/bbl) 53.90 40.89
---------------------------------------------------- -------- --------
Gross profit ($m) 12.0 4.1
---------------------------------------------------- -------- --------
Operating profit/(loss) ($m) 5.8 (1.6)
---------------------------------------------------- -------- --------
Loss for the period ($m) (6.7) (12.2)
---------------------------------------------------- -------- --------
Net cash from operating activities ($m) 27.1 16.2
---------------------------------------------------- -------- --------
Cash capital expenditure ($m) 15.5 27.2
---------------------------------------------------- -------- --------
Cash, cash equivalents and liquid investments ($m) 132.0 80.6
---------------------------------------------------- -------- --------
INCOME STATEMENT
Revenue
Oil and gas revenues were up slightly in the first half of 2017
to $74.0m compared with $72.7m in the same period last year. SOCO
realised an average oil price of $53.90/bbl compared with $40.89
for 1H 2016. As expected, the Group's production was down during
the first half to 8,606 BOEPD compared 10,862 BOEPD in the 1H 2016
(see Operations Review section).
Cost of Sales
Cost of sales were $62.0m for the six-month period to 30 June
2017, compared with $68.6m in the same period last year, reflecting
the impact from the lower production volumes, which also resulted
in a lower DD&A charge in the period. Total Vietnam operating
cash costs on a per barrel basis (excluding DD&A, inventory
movements and sales related duties and royalties) were up at $12.99
(1H 2016: $10.06/bbl), a result of a largely fixed cost base being
allocated over a lower number of produced barrels. The underlying
operating costs remaining relatively flat at $21.0m (1H 2016:
$20.9m).
Analysis of Cost of Sales
$ millions 1H 2017 1H 2016
-------------------------------------- --------- --------
Operating costs 21.0 20.9
-------------------------------------- --------- --------
Inventory movements (0.8) (2.4)
-------------------------------------- --------- --------
Royalty 5.7 5.7
-------------------------------------- --------- --------
Export duty 0.9 0.8
-------------------------------------- --------- --------
DD&A 35.2 43.6
-------------------------------------- --------- --------
Total cost of sales 62.0 68.6
-------------------------------------- --------- --------
Per barrel costs, $ 1H 2017 1H 2016
-------------------------------------- --------- --------
Operating cash costs per barrel, $* 12.99 10.06
-------------------------------------- --------- --------
DD&A costs per barrel, $(*) 22.61 22.04
-------------------------------------- --------- --------
Administrative Expenses
Administrative expenses were up at $6.2m compared with $5.7m in
the equivalent period last year, reflecting the renewed effort on
portfolio rationalisation and capturing new business.
Operating Profit/(loss)
Operating profit for the period was $5.8m, which primarily
reflects the increased revenues and lower cost of sales (1H 2016:
$1.6m loss).
Tax
The tax expense increased from $9.7m in the six-month period
ending 30 June 2016 to $12.3m in the current reporting period
consistent with higher profit. The Group's effective tax rate
approximates to the statutory tax rate in Vietnam of 50% during 1H
2017 after excluding non-deductible expenditure.
BALANCE SHEET
Intangible assets increased during the period by $2.7m which
represents costs associated with the Vietnam Blocks 125 & 126
and expenditure on the Congo (Brazzaville) assets.
Property, plant and equipment decreased by $17.5m since 2016
year-end representing the capital programme offset by the six
months DD&A charge.
Other receivables of $35.4m increased by $1.6m from the 2016
year-end which reflects the additional cash funding provided for
TGT and CNV abandonment. The funds are operated by PetroVietnam and
partners retain the legal rights to the funds pending commencement
of abandonment operations.
Oil inventory was $6.5m at 30 June 2017, increasing from $5.7m
at 2016 year-end. Trade and other receivables at 30 June 2017 were
$13.0m, being down $11.7m from 2016 year-end. This decrease
reflects the timing of the oil and gas sales.
The $42.7m Subsequent Payment Amount outstanding at the 2016
year-end associated with SOCO's 2005 sale of its Mongolia interests
was settled in full in March 2017.
SOCO's cash, cash equivalents and liquid investments totalled
$132.0m as at 30 June 2017, up from $100.3m at 31 December 2016.
The increase since year-end of $31.7m is mainly a result of the
recovery of the $42.7m Subsequent Payment Amount, production
inflows from Vietnam, offset by cash outflows for the capital
programme and the payment of the dividend in June 2017.
Trade and other payables were $24.1m at the current period-end,
up from $22.4m at 31 December 2016 mainly due to the status of the
work programme in Vietnam. Tax payable of $5.1m was down $4.1m from
$9.2m as at the end of 2016.
Deferred tax liabilities have decreased to $157.8m at 30 June
2017 from $165.7m at 31 December 2016.
Long term provisions comprise the Group's decommissioning
obligations in Vietnam which have increased to $64.9m as at 30 June
2017 from $62.9m at 2016 year-end.
CASH FLOW
Net cash flows from operating activities for the first six
months of 2017 comprise the Group's continuing Vietnam operations
and amounted to $27.1m (1H 2016: $16.2m). This increase is mainly
the result of an increase in realised oil prices offset by a
reduction in production volumes and associated cost of sales from
the TGT and CNV Fields including the associated impact on working
capital movements.
Capital expenditure for the period ending 30 June 2017 was
$15.5m (1H 2016: $27.2m). This reduction period on period reflects
our strategy of discipline around capital spend.
The Group made a final dividend payment to shareholders of
$21.0m in the period (1H 2016: $9.4m).
RELATED PARTY TRANSACTIONS
There have been no new material related party transactions in
the period and there have been no material changes to the related
party transactions described in Note 35 to the Consolidated
Financial Statements contained in the 2016 Annual Report and
Accounts.
RISKS AND UNCERTAINTIES
There are a number of potential risks and uncertainties which
could have a material impact on the Group's performance over the
remaining six months of 2017 and could cause actual results to
differ materially from expected and historical results. The
principal risks and uncertainties, along with the mitigation
measures in place to reduce risks to acceptable levels, remain
unchanged from those published in the 2016 Annual Report and
Accounts and are summarised below:
-- Health, safety, environment and social risks - arising due to
the nature and location of the Group's activities
-- Operational risk - in conducting exploration, drilling,
construction and production operations in the upstream oil and gas
industry
-- Empowerment risk - the conduct of international operations
requires the delegation of a degree of decision making to partners,
contractors and locally based personnel
-- Reserves risk - inherent uncertainties in the application of
standard recognised evaluation techniques to estimate proven and
probable reserves
-- Stakeholder and Reputational risk - associated with the
conduct of oil and gas activity in locations where social and
environmental matters may be highly sensitive both on the ground
and as perceived globally
-- Commodity price risk - associated with the Group's sales of oil and gas
-- Liquidity and credit risk - associated with meeting the Group's cash requirements
-- Capital risk management - associated with ensuring that the
Group will be able to continue as a going concern while maximising
the return to shareholders
-- Strategic risk - associated with ensuring the Company is well
funded to deliver on its capital commitments and business
development opportunities
-- Human resource risk - associated with retention and recruitment of high quality personnel
Further information on the above principal risks and
uncertainties facing the Group is included in the Risk Management
section of the 2016 Annual Report and Accounts and in Note 4 to the
Consolidated Financial Statements in that report in relation to
reserves estimation risk and its impact on the Consolidated
Financial Statements.
Additional information therein includes the manner in which the
Group seeks to mitigate each of its principal risks, including
those that may be impacted by a global transition to a lower carbon
intensity economy in response to climate change.
GOING CONCERN
It should be recognised that any consideration of the
foreseeable future involves making a judgement, at a particular
point in time, about future events which are inherently uncertain.
Nevertheless, at the time of preparation of these accounts and
after making enquiries, the Directors have a reasonable expectation
that the Group has adequate resources to continue operating for the
foreseeable future. For this reason, and taking into consideration
any additional factors, they continue to adopt the going concern
basis in preparing the accounts.
CORPORATE
Director Changes
Roger Cagle and Cynthia Cagle, each an Executive Director, have
decided to retire in the second half of 2018 after over 20 years
with the Company. Each will step down from the Board with effect
from 12 November 2017, but will continue in employment with the
Group until 11 September 2018.
Mike Watts, who stood down as a non-executive Director to
co-head Business Development for the Group in January 2017, will
re-join the Board as Managing Director on 12 November 2017. Jann
Brown, now co-head of Business Development for the Group, will also
join the Board on that date as Managing Director and Chief
Financial Officer.
Rob Gray, the Board's Senior Independent Director, replaced Mike
Watts as Chairman of the Audit & Risk Committee.
Corporate governance remains a priority as reflected in SOCO's
programme of Board refreshment. Whilst we believe that the
continuing Directors comprise an appropriately balanced Board, with
the experience and attributes critical to the success of the
Company, we will continue to review the balance and effectiveness
of the Board with a view to adding independent non-executives
commensurate with our size and need.
Dividend
Following approval at the Company's AGM in June, SOCO paid a
final dividend to shareholders of 5 pence per share ($21.0m). The
Board will decide on the level of future cash returns in light of
the oil price, cash flow generation from Vietnam and expected
capital expenditure at the time.
STRATEGIC Outlook
For the remainder of 2017, our focus will continue to be
three-fold:
1) Maintaining our disciplined approach to capital allocation;
2) Optimising production from the TGT Field, our major producing asset; and
3) Rationalisation and growing the portfolio of assets.
Our operational priorities continue to be optimisation of
production in Vietnam, with the installation of new processing
equipment on H1-WHP during 2H 2017. Production guidance for 2017 is
maintained at 8,000 to 9,000 BOEPD for the full year 2017.
In Q4 2017, we expect to announce a new PSC over the two blocks
125 & 126, offshore Vietnam, adding to our existing strong
presence in the region. Maximisation of value from our Africa
exploration portfolio remains a priority.
The Company is well positioned for growth. It is the intention
to use this platform to grow the business and deliver value by
maintaining focus on capital discipline, capital allocation and
capital return.
Rui de Sousa
Chairman
Ed Story
President and Chief Executive Officer
RESPONSIBILITY STATEMENT
We confirm to the best of our knowledge:
-- The condensed set of financial statements has been prepared
in accordance with IAS 34 Interim Financial Reporting;
-- The interim management report includes a fair review of the
information required by DTR 4.2.7R (indication of important events
during the first six months and description of principal risks and
uncertainties for the remaining six months of the year); and
-- The interim management report includes a fair review of the
information required by DTR 4.2.8R (disclosure of related parties'
transaction and changes therein).
By order of the Board
Roger Cagle
Deputy Chief Executive Officer and Chief Financial Officer
12 September 2017
DISCLAIMER
This Interim Report has been prepared solely to provide
additional information to shareholders to assess the Group's
strategies and the potential for those strategies to succeed. The
Half Year Report should not be relied on by any other party or for
any other purpose.
The Interim Report contains certain forward-looking statements.
These statements are made by the Directors in good faith based on
the information available to them up to the time of their approval
of this report and such statements should be treated with caution
due to the inherent uncertainties, including both economic and
business risk factors, underlying any such forward-looking
information.
_____________________________
* See Glossary
INDEPENT REVIEW REPORT TO SOCO INTERNATIONAL PLC
We have been engaged by the company to review the condensed
consolidated set of financial statements in the half-yearly
financial report for the six months ended 30 June 2017 which
comprises the condensed consolidated income statement, condensed
consolidated statement of comprehensive income, the condensed
consolidated balance sheet, the statement of changes in equity, the
condensed consolidated cash flow statement and related notes 1 to
9. We have read the other information contained in the half-yearly
financial report and considered whether it contains any apparent
misstatements or material inconsistencies with the information in
the condensed set of financial statements.
This report is made solely to the company in accordance with
International Standard on Review Engagements (UK and Ireland) 2410
"Review of Interim Financial Information Performed by the
Independent Auditor of the Entity" issued by the Auditing Practices
Board. Our work has been undertaken so that we might state to the
company those matters we are required to state to it in an
independent review report and for no other purpose. To the fullest
extent permitted by law, we do not accept or assume responsibility
to anyone other than the company, for our review work, for this
report, or for the conclusions we have formed.
Directors' responsibilities
The half-yearly financial report is the responsibility of, and
has been approved by, the directors. The directors are responsible
for preparing the half-yearly financial report in accordance with
the Disclosure and Transparency Rules of the United Kingdom's
Financial Conduct Authority.
As disclosed in note 2, the annual financial statements of the
group are prepared in accordance with IFRSs as adopted by the
European Union. The condensed set of financial statements included
in this half-yearly financial report has been prepared in
accordance with International Accounting Standard 34 "Interim
Financial Reporting" as adopted by the European Union.
Our responsibility
Our responsibility is to express to the Company a conclusion on
the condensed set of financial statements in the half-yearly
financial report based on our review.
Scope of review
We conducted our review in accordance with International
Standard on Review Engagements (UK and Ireland) 2410 "Review of
Interim Financial Information Performed by the Independent Auditor
of the Entity" issued by the Auditing Practices Board for use in
the United Kingdom. A review of interim financial information
consists of making inquiries, primarily of persons responsible for
financial and accounting matters, and applying analytical and other
review procedures. A review is substantially less in scope than an
audit conducted in accordance with International Standards on
Auditing (UK) and consequently does not enable us to obtain
assurance that we would become aware of all significant matters
that might be identified in an audit. Accordingly, we do not
express an audit opinion.
Conclusion
Based on our review, nothing has come to our attention that
causes us to believe that the condensed set of financial statements
in the half-yearly financial report for the six months ended 30
June 2017 is not prepared, in all material respects, in accordance
with International Accounting Standard 34 as adopted by the
European Union and the Disclosure and Transparency Rules of the
United Kingdom's Financial Conduct Authority.
Deloitte LLP
Statutory Auditor
London, United Kingdom
12 September 2017
Condensed consolidated income statement
(unaudited) (unaudited)
six months ended six months ended year ended
30 Jun 17 30 Jun 16 31 Dec 16
Notes $ million $ million $ million
----------------- ------------------------- --------------------------
Revenue 3 74.0 72.7 154.6
Cost of sales 4 (62.0) (68.6) (135.0)
----------------- ------------------------- --------------------------
Gross profit 12.0 4.1 19.6
Administrative expenses (6.2) (5.7) (13.5)
Exploration write back - - 1.1
----------------- ------------------------- --------------------------
Operating profit/(loss) 5.8 (1.6) 7.2
Investment revenue 0.6 0.2 0.5
Finance costs (0.8) (1.1) (2.0)
----------------- ------------------------- --------------------------
Profit/(loss) before
tax 3 5.6 (2.5) 5.7
Tax 5 (12.3) (9.7) (24.0)
----------------- ------------------------- --------------------------
Loss for the period (6.7) (12.2) (18.3)
----------------- ------------------------- --------------------------
Loss per share (cents) 6
Basic (2.0) (3.7) (5.6)
----------------- ------------------------- --------------------------
Diluted (2.0) (3.7) (5.6)
----------------- ------------------------- --------------------------
The results are from continuing
activities only.
Condensed consolidated statement of comprehensive income
(unaudited) (unaudited)
six months ended six months ended year ended
30 Jun 17 30 Jun 16 31 Dec 16
$ million $ million $ million
----------------- ------------------------- --------------------------
Loss for the
period (6.7) (12.2) (18.3)
Items that may be subsequently
reclassified to profit or loss:
Unrealised currency
translation differences (0.1) 0.4 (0.2)
----------------- ------------------------- --------------------------
Total comprehensive loss for
the period (6.8) (11.8) (18.5)
----------------- ------------------------- --------------------------
Condensed consolidated balance sheet
(unaudited) (unaudited)
30 Jun 17 30 Jun 16 31 Dec 16
Note $ million $ million $ million
------------ ------------------------ ------------------------
Non-current assets
Intangible assets 220.9 214.8 218.2
Property, plant and equipment 673.1 718.1 690.6
Other receivables 35.4 31.8 33.8
------------ ------------------------ ------------------------
929.4 964.7 942.6
------------ ------------------------ ------------------------
Current assets
Inventories 6.5 5.5 5.7
Trade and other receivables 13.0 30.4 24.7
Tax receivables 0.6 0.6 0.7
Financial asset 7 - 52.7 2.7
Liquid investments 25.3 10.3 15.3
Cash and cash equivalents 106.7 70.3 85.0
------------ ------------------------ ------------------------
152.1 169.8 174.1
Total assets 1,081.5 1,134.5 1,116.7
Current liabilities
Trade and other payables (24.1) (21.6) (22.4)
Tax payables (5.1) (6.8) (9.2)
------------ ------------------------ ------------------------
(29.2) (28.4) (31.6)
Non-current liabilities
Deferred tax liabilities (157.8) (173.7) (165.7)
Long term provisions (64.9) (61.0) (62.9)
------------ ------------------------ ------------------------
(222.7) (234.7) (228.6)
Total liabilities (251.9) (263.1) (260.2)
------------ ------------------------ ------------------------
Net assets 829.6 871.4 856.5
------------ ------------------------ ------------------------
Equity
Share capital 27.6 27.6 27.6
Other reserves 244.7 242.4 243.8
Retained earnings 557.3 601.4 585.1
------------ ------------------------ ------------------------
Total equity 829.6 871.4 856.5
------------ ------------------------ ------------------------
STATEMENT OF CHANGES IN EQUITY
Called up share
capital Other reserves Retained earnings Total
$ million $ million $ million $ million
----------------------- --------------- ------------------ ------------------
As at 1 January 2016 27.6 242.3 622.6 892.5
Loss for the period - - (12.2) (12.2)
Unrealised currency
translation differences - (0.4) 0.5 0.1
Distributions - - (9.4) (9.4)
Share-based payments - 0.4 - 0.4
Transfer relating to
share-based payments - 0.1 (0.1) -
As at 30 June 2016
(unaudited) 27.6 242.4 601.4 871.4
Loss for the period - - (6.1) (6.1)
Unrealised currency
translation differences - 0.2 (0.7) (0.5)
Distributions - - (8.1) (8.1)
Share-based payments - (0.2) - (0.2)
Transfer relating to
share-based payments - 1.4 (1.4) -
As at 1 January 2017 27.6 243.8 585.1 856.5
Loss for the period - - (6.7) (6.7)
Unrealised currency
translation differences - 0.3 (0.1) 0.2
Distributions - - (21.0) (21.0)
Share-based payments - 0.6 - 0.6
As at 30 June 2017
(unaudited) 27.6 244.7 557.3 829.6
----------------------- --------------- ------------------ ------------------
Condensed consolidated cash flow statement
(unaudited) (unaudited)
six months ended six months ended year ended
30 Jun 17 30 Jun 16 31 Dec 16
Note $ million $ million $ million
----------------- ----------------- ----------------
Net cash from operating activities 8 27.1 16.2 46.0
Investing activities
Purchase of intangible assets (2.8) (24.3) (27.4)
Purchase of property, plant and equipment (12.7) (2.9) (8.4)
Increase in liquid investments (1) (10.0) (10.3) (15.3)
Payment to abandonment fund (1.6) (2.3) (4.3)
Deferred proceeds on disposal of
Mongolia assets 42.7 - 10.0
----------------- ----------------- ----------------
Net cash from/(used in) investing activities 15.6 (39.8) (45.4)
Financing activities
Share-based payments (0.3) (0.2) (0.9)
Distributions (21.0) (9.4) (17.5)
----------------- ----------------- ----------------
Net cash used in financing activities (21.3) (9.6) (18.4)
Net increase/(decrease) in cash and cash
equivalents 21.4 (33.2) (17.8)
Cash and cash equivalents at beginning of
period 85.0 103.6 103.6
Effect of foreign exchange rate changes 0.3 (0.1) (0.8)
Cash and cash equivalents at end of period
(1) 106.7 70.3 85.0
----------------- ----------------- ----------------
(1) Liquid investments comprise short term liquid investments of between three to six months
maturity while cash and cash equivalents (which are presented as a single class of asset on
the balance sheet) comprise cash at bank and other short term highly liquid investments of
less than three months maturity that are readily convertible to a known amount of cash and
which are subject to an insignificant risk of change in value. The combined cash and cash
equivalents and liquid investments balance at 30 June 2017 was $132.0m (1H 2016: $80.6m).
Notes to the condensed consolidated financial statements
1. General information
The information for the year ended 31 December 2016 does not
constitute statutory accounts as defined in section 435 of the
Companies Act 2006. A copy of the statutory accounts for that year
has been delivered to the Registrar of Companies. The auditor's
report on those accounts was not qualified, did not include a
reference to any matters to which the auditors drew attention by
way of emphasis without qualifying the report and did not contain
statements under section 498(2) or (3) of the Companies Act
2006.
The half year financial report is presented in US dollars
because that is the currency of the primary economic environment in
which the Group operates.
A final dividend of 5 pence per share was approved at the Annual
General Meeting and subsequently paid to Shareholders on 16 June
2017. See Note 9 below.
The half year financial report for the six months ended 30 June
2017 was approved by the Directors on 12 September 2017.
2. Significant accounting policies
The half year financial report, which is unaudited, has been
prepared in accordance with the recognition and measurement
criteria of International Financial Reporting Standards (IFRS) as
adopted by the European Union and the disclosure requirements of
the Listing Rules and using the same accounting policies and
methods of computation as applied by the Company in its 2016 Annual
Report and Accounts for the year ended 31 December 2016.
The condensed set of financial statements included in this half
year financial report has been prepared on the going concern basis
of accounting for the reasons set out in the Financial Results
section of this report and in accordance with International
Accounting Standard 34 Interim Financial Reporting, as adopted by
the European Union, and the requirements of the UK Disclosure and
Transparency Rules of the Financial Services Authority in the
United Kingdom as applicable to interim financial reporting.
There have not been any new or amended standards and
interpretations that would have a material impact on the financial
information for the six months ended 30 June 2017.
3. Segment information
The Group has one principal business activity being oil and gas
exploration and production. The Group's operations are located in
South East Asia and Africa and form the basis on which the Group
reports its segment
information. There are no inter-segment sales. Segment results are presented below:
Six months ended 30 June 2017 (unaudited)
SE Asia Africa Unallocated Group
$ million $ million $ million $ million
-------------------- --------------------- ----------------------- --------------------
Oil and gas
sales 74.0 - - 74.0
-------------------- --------------------- ----------------------- --------------------
Profit/(loss)
before tax 11.3 - (5.7) 5.6
-------------------- --------------------- ----------------------- --------------------
Six months ended 30 June 2016 (unaudited)
Oil and gas
sales 72.7 - - 72.7
-------------------- --------------------- --------------------
Profit/(loss)
before tax 3.1 - (5.6) (2.5)
-------------------- --------------------- ----------------------- --------------------
Year ended 31 December 2016
Oil and gas
sales 154.6 - - 154.6
-------------------- ---------------------
Profit/(loss)
before tax 17.8 0.6 (12.7) 5.7
-------------------- --------------------- ----------------------- --------------------
4. Cost of sales
(unaudited) (unaudited)
six months ended six months ended year ended
30 Jun 17 30 Jun 16 31 Dec 16
$ million $ million $ million
----------------- ---------------------- ------------------------
Production operating
costs 21.0 20.9 44.4
Inventory movements (0.8) (2.4) (2.6)
Royalty 5.7 5.7 12.0
Export duty 0.9 0.8 1.4
Depreciation, depletion and
amortisation 35.2 43.6 79.8
Total cost of sales 62.0 68.6 135.0
----------------- ---------------------- ------------------------
5. Tax
(unaudited) (unaudited)
six months ended six months ended year ended
30 Jun 17 30 Jun 16 31 Dec 16
$ million $ million $ million
----------------- ---------------------- -----------------------
Current tax 20.2 19.6 42.0
Deferred tax (7.9) (9.9) (18.0)
---------------------- -----------------------
12.3 9.7 24.0
----------------- ---------------------- -----------------------
The Group's corporation tax is calculated at 50% (1H 2016: 50%)
of the estimated assessable profit for each period in Vietnam.
During each period both current and deferred taxation have arisen
in overseas jurisdictions only.
6. Loss per share
The calculation of the basic and diluted loss per share is based
on the following data:
(unaudited) (unaudited)
six months ended six months ended year ended
30 Jun 17 30 Jun 16 31 Dec 16
$ million $ million $ million
----------------- ----------------- -----------------------
Earnings for the purpose of basic
and diluted loss per share (6.7) (12.2) (18.3)
----------------- ----------------- -----------------------
Number of shares (million)
-------------------------------------------------------------
(unaudited) (unaudited)
six months ended six months ended year ended
30 Jun 17 30 Jun 16 31 Dec 16
Weighted average number of
ordinary shares for the purpose
of basic earnings per share 329.8 329.2 329.4
Effect of dilutive potential
ordinary shares - Share awards
and options 3.8 5.0 2.8
Weighted average number of
ordinary shares for the purpose
of diluted earnings per share 333.6 334.2 332.2
----------------- ----------------- -----------------------
7. Financial asset
In 2005, the Group disposed of its Mongolia interest to Daqing
Oilfield Limited Company. Under the terms of the transaction the
Group was entitled to receive a subsequent payment amount of up to
$52.7 million, once cumulative production reached 27.8 million
barrels of oil, at the rate of 20% of the average monthly marker
price for Daqing crude multiplied by the aggregate production for
that month. Daqing notified SOCO that the production threshold of
crude oil in excess of 27.8 million barrels was achieved in
December 2015.
As at 30 June 2017 the full amount of $52.7m had been
settled.
8. Reconciliation of operating profit/(loss) to operating cash
flows
(unaudited) (unaudited)
six months ended six months ended year ended
30 Jun 17 30 Jun 16 31 Dec 16
$ million $ million $ million
----------------- ------------------------ ------------------------
Operating profit/(loss) 5.8 (1.6) 7.2
Share-based payments 0.9 0.6 1.1
Depreciation, depletion
and amortisation 35.3 43.7 80.0
Exploration write-back - - (1.1)
----------------- ------------------------ ------------------------
Operating cash flows before
movements in working
capital 42.0 42.7 87.2
Increase in inventories (0.8) (2.4) (2.6)
Decrease/(increase) in
receivables 12.2 (8.4) (6.8)
(Decrease)/increase in
payables (4.1) 3.4 7.8
----------------- ------------------------ ------------------------
Cash generated by
operations 49.3 35.3 85.6
Interest received 0.5 0.2 0.4
Interest paid - - (0.1)
Income taxes paid (22.7) (19.3) (39.9)
----------------- ------------------------ ------------------------
Net cash from operating
activities 27.1 16.2 46.0
----------------- ------------------------ ------------------------
9. Dividend
On 16 June 2017, following approval at the Annual General
Meeting, the Company paid a dividend of 5 pence per share in total
of $21.0m (2016: $9.4m) to Shareholders.
Glossary
Non-IFRS measures
The Group uses certain measures of performance that are not
specially defined under IFRS or other generally accepted accounting
principles. These non-IFRS measures include cash operating costs
per barrel and DD&A per barrel.
Cash-operating costs per barrel
Cash-operating costs for the period calculated over barrels of
oil equivalent produced. This is a useful indicator of cash
operating costs incurred to produce oil and gas from the Group's
producing assets.
(unaudited) (unaudited)
six months six months
ended ended year ended
30 Jun 31 Dec
17 30 Jun 16 16
$ million $ million $ million
------------ ----------------------- -----------------------
Cost of sales 62.0 68.6 135.0
Less:
Depreciation, depletion
and amortisation (35.2) (43.6) (79.8)
Production based taxes (6.6) (6.5) (13.4)
Inventories 0.8 2.4 2.6
Other cost of sales (0.8) (1.0) (2.1)
Total cost of
sales 20.2 19.9 42.3
------------ ----------------------- -----------------------
Production (BOEPD) 8,606 10,862 9,883
------ ----------------------- --------------------
Cash operating
cost per BOE $12.99 $10.06 $11.70
------- ----------------------- ---------------------
DD&A per barrel
The Group believes this non-IFRS measure is a useful indicator
of DD&A charge and should follow any changes in reserves
estimates.
(unaudited)
(unaudited) six months
six months ended ended year ended
31 Dec
30 Jun 17 30 Jun 16 16
$ million $ million $ million
------------------------- ------------------ ------------ ---------------------
Depreciation, depletion
and amortisation 35.2 43.6 79.8
------------------ ------------ ---------------------
Production (BOEPD) 8,606 10,862 9,883
------------------ ------------ ---------------------
DD&A per BOE $22.61 $22.04 $22.04
------------------ ------------ ---------------------
This information is provided by RNS
The company news service from the London Stock Exchange
END
IR KMGMLMZFGNZZ
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