INTERIM RESULTS FOR THE HALF YEAR TO 30 JUNE 2017

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: [phone]

Camarco

Billy Clegg

Georgia Edmonds

Tel: [phone]

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 (gross)	1H 2016 (gross)	1H 2017 (net)	1H 2016 (net)	FY 2016 (net)
TGT Production	23,401	30,739	7,056	9,252	8,330
Oil	21,898	28,530	6,604	8,588	7,825
Gas1	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
Gas1	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
Gas1	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

 

INDEPENDENT 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) six months ended				(unaudited) 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) six months ended			(unaudited) six months ended				year ended
										30 Jun 17			30 Jun 16				31 Dec 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) six months ended	(unaudited) six months ended				year ended
										30 Jun 17	30 Jun 16				31 Dec 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

 

END

 

 

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