Interim Results

RNS Number : 1770Q

Soco International PLC

28 August 2014

 



SOCO International plc

("SOCO" or the "Company")

INTERIM RESULTS FOR THE HALF-YEAR TO 30 JUNE 2014

Operations

·     Production averaged 13,960 BOEPD in the first half; 2014 full year production guidance remains 14-15,000 BOEPD

·     TGT 2014 in-fill drilling programme is ongoing with 6 development wells to be drilled in 2014

·     TGT FPSO total liquids test to 140,000 barrels of liquids completed; the oil production test to above 60,000 BOPD expected in H1 2015

·     The TGT H5 development is progressing as planned - the H5 wellhead jacket and drilling deck will be installed in Q3 2014 and first oil is on target for September/October 2015

·     Currently drilling an exploration well on the Marine XI Block, offshore the Republic of Congo (Brazzaville)

Financial

·     Financial results in the first half in line with the Company's expectations; revenue of $246.4 million (1H 2013: $324.0m) and net profit of $79.8 million (1H 2013: $105.4m) reflecting the TGT FPSO sharing from May 2013

·     Continued strong cash generation from Vietnam

·     Strong balance sheet with net cash and liquid investments of $284 million as at 30 June 2014; capex guidance for the full year 2014 at $160-170 million

·     Proposed cash return of $121 million, or 22 pence per share, representing c. 60% of free cash flow for 2013

Ed Story, Chief Executive Officer, commented:

"Our focus this year has been on delivering steady progress on the TGT field which continues to perform as expected.  The 2014 TGT in-fill development drilling programme is underway with three wells drilled to date. The H5 development project is progressing according to plan targeting first oil in just a little over a year. Our exciting two-well exploration programme offshore the Republic of Congo is underway with the first well in the programme, the Lidongo X Marine-101, currently being drilled.

Our revenue and cash flows in the first half continued to be strong. We are pleased to recommend a return of 22 pence per share to shareholders. With continued strong cash generation and a solid balance sheet, SOCO is well positioned to fund its development and exploration programme and to continue the strategy of targeting half of free cash flow to return to shareholders."

ENQUIRIES:

SOCO International plc

Anya Weaving, Chief Financial Officer

Tel: [phone]

Bell Pottinger

Rollo Crichton-Stuart

Elizabeth Snow

Tel: [phone]                                                                                                                   

NOTES TO EDITORS:

SOCO is an international oil and gas exploration and production company, headquartered in London, traded on the London Stock Exchange and a constituent of the FTSE 250 Index. The Company has interests in Vietnam, the Republic of Congo (Brazzaville), the Democratic Republic of Congo (Kinshasa) and Angola, with production operations in Vietnam.

STRATEGIC OVERVIEW AND OUTLOOK

Our strategy remains two-pronged: delivering to shareholders both value - through meaningful ongoing cash returns - and growth from relatively low risk upside through the exploration part of our business model. Furthermore, we will continue to explore all options to maximise value creation for shareholders including increasing the value of our existing asset base and investing in growth organically or inorganically. We see growth as an important part of the SOCO story but we will continue to manage our portfolio and make new investment decisions in a manner which is consistent with our capital discipline, without committing a disproportionate share of our capital expenditure budget to exploration drilling.

Following our first capital return to shareholders last year and commitment to target a 50% return of annual free cash flow, the Directors of the Company are pleased to recommend the return of 22 pence per share, approximately £73 million ($121 million), subject to the approval of shareholders. The total cash return represents approximately 60% of the 2013 free cash flow of c.$200 million. As last year, the cash return is being structured in a tax efficient manner as a B and/or C Share scheme. Going forward, as we use up good tax capital, we will explore other options including a move to dividend payments, with the level of return still targeting 50% of annual free cash flow.

The TGT field has continued to perform in line with the Company's expectations, with Group production target for the full year 2014 maintained at 14-15,000 BOEPD. After initial delays, the 2014 TGT in-fill development drilling programme is now underway, with three wells having been completed so far. The H5 development project is progressing well still targeting first oil in September/October 2015. While the partners are working toward the formal sanctioning of the H5 project, all development activities are progressing as planned, with the H5 well head platform due to be installed ahead of schedule by mid-September in preparation for the five initial development wells to be drilled after installation. The Company has commenced drilling the Lidongo X Marine-101 well on the Marine XI Block, the first of its exciting two-well exploration programme offshore the Republic of Congo. The second well, on the Mer Profonde Sud Block, is expected to be drilled mid 2015.

The operational focus for the rest of 2014 will be development drilling on the TGT field including the H5 fault block. Despite the delay due to rig issues earlier this year, we now expect a total of six in-fill development wells, in addition to the planned H5 wells, to be drilled this year, with the Hoang Long Joint Operating Company  close to finalising a contract for another rig which would allow us to continue drilling  wells through the winter. FPSO de-bottlenecking and increase in production remains another strategic priority. We have successfully tested the FPSO total liquids handling capacity to 140,000 barrels per day and will continue to work towards a second oil capacity handling test to above 60,000 BOPD, which will most likely now take place in the first half of 2015.

On the CNV field, we commenced drilling the CNV-7P well which unfortunately had to be suspended due to unexpected geological issues. It is anticipated that the well will be re-entered during the 2015 programme. The decision to suspend the well is not expected to have any material impact on the Company's financial performance.

First half 2014 revenue, net profit and cash flows, although reduced in comparison with 2013, are in line with the Company's expectations reflecting the contractual sharing of FPSO production capacity from May 2013. With the additional rig to progress the TGT drilling programme and complications on the CNV-7P well, capital expenditure for the full year 2014 is expected to be in the region of $160-170 million, the exact amount depending on the pace of the development drilling programme.

SOCO remains well financed with no debt on the balance sheet and $284 million of cash, cash equivalents and liquid investments as at 30 June 2014. With its strong cash generation, the Company is well positioned to fund its development and exploration programme and to continue the strategy of targeting a return of 50% of annual free cash flow to shareholders.

OPERATIONS REVIEW

VIETNAM

The TGT and CNV fields combined production, net to SOCO's working interest, averaged 13,960 barrels of oil equivalent per day ("BOEPD") in the first half of 2014 (17,135 BOEPD for the same period last year and 16,694 BOEPD for the full year 2013). This level of production is in line with the Company's previous expectations. Full-year guidance remains at 14-15,000 BOEPD.

Production of oil and gas by field

	1H 2014	1H 2013	FY 2013
TGT production	11,939	14,967	14,635
Oil (BOPD)	10,751	14,967	13,301
Gas (BOEPD)	1,188	-	1,334
CNV production	2,021	2,168	2,059
Oil (BOPD)	1,403	1,575	1,494
Gas (BOEPD)	618	593	565
Total Production	13,960	17,135	16,694
Oil (BOPD)	12,154	16,542	14,795
Gas (BOEPD)	1,806	593	1,899

Block 16-1 - Te Giac Trang (TGT) Field (30.5% interest; operated by Hoang Long Joint Operating Company ("HLJOC"))

Production

The TGT field is currently producing from 16 wells from two unmanned platforms. The field continues to perform in line with expectations.

TGT field production averaged 39,863 BOEPD through the first six months of the year, 11,939 BOEPD net to SOCO (14,967 BOEPD for the first six months of 2013 and 14,635 BOEPD for the full year of 2013). As expected, the year-on-year decrease in production is due to TGT's reduced share of the Floating, Production, Storage and Offloading vessel ("FPSO") capacity and, to a lesser extent, to the deferral of the 2013 TGT development drilling programme. TGT crude sales currently realise a premium of above $4 per barrel to the Brent benchmark crude price.

2014 Drilling Programme

Drilling of the 2014 in-fill development programme at the TGT field continues. Three wells have been drilled and completed so far by the Ensco 109 rig. The two producer wells, TGT-17PST1 and TGT-18PST1, are on-line and producing in line with expectations. The third well, TGT-11X, an exploration/appraisal well on the H2S fault block, is currently being completed as a producer/injector. This well was targeting primarily an Oligocene oil column with only a thin Lower Miocene column. However, the actual pay sections in both horizons of this well are thinner than expected from the pre-drilling prognosis. The well is being completed as a producer with the ability to convert to an injector when required.

The first well, the TGT-17PST1, was spudded in early March by the Hercules Resilience rig, but was suspended following various mechanical complications with the rig, which was subsequently released. Drilling of the well was completed by the Ensco 109 rig which arrived on location in late April. The Ensco 109 rig is expected to complete another TGT well before being released. The TGT partners are in the process of finalising a contract for an additional rig to drill on the H4 well head platform ("WHP").  The TGT partners are currently expecting to drill a total of six development wells (excluding the planned wells on H5) during 2014, remaining within the range of the six to eight wells previously planned to be drilled.  Any approved wells planned for this year but not completed will likely be added to the 2015 programme.

The 2015 drilling programme for TGT will be approved in October/November 2014 in line with the annual budgeting process for the HLJOC. To coincide with the expected completion of the activities under the original TGT Field Development Plan ("FDP"), the partners are also working on an updated TGT FDP which is expected to be submitted to the relevant authorities in Q1 2015.

FPSO Capacity Testing

As the TGT field's FPSO oil throughput currently remains contractually limited to up to 40,000 barrels of oil per day ("BOPD") of the 55,000 BOPD nameplate capacity, the FPSO de-bottlenecking and increase in TGT production remains a strategic priority. Delay to the 2014 drilling programme has required changes to other operational plans. The main change has been to accelerate the testing of the total liquids (oil and water) handling capacity of the FPSO ahead of carrying out the second phase test of the oil handling capacity.

In July 2014, the HLJOC successfully tested with the existing facilities on the FPSO beyond the current total liquids nameplate capacity of 120,000 barrels of liquids per day to approximately 140,000 barrels of liquids per day. The test also allowed confirmation of minor additional production system modifications to increase the total liquids handling capacity to the level expected to be in excess of 160,000 barrels of liquids per day. Accelerating the total liquids test will enable the HLJOC to work with the vessel owner/operator (BAB-VSP Alliance) to allow the capacity of the vessel to be re-certified at higher levels.

The programme to test the oil production capacity beyond the 60,000 BOPD previously tested is expected to be completed in the first half of 2015, with the actual timing determined by the progress of the in-fill drilling programme.

H5 Development

The TGT partners continue to focus on achieving approval for the H5 FDP and meeting the first oil target in September/October 2015.  The Hydrocarbons Initially In Place/Reserve Assessment Report ("RAR") was approved on 18^th June 2014, and work is ongoing on the H5 FDP which is expected to be submitted for approval by the relevant Vietnamese authorities by the end of the third quarter.  

In the meantime, all the related development works required to meet the first oil schedule remain on target. The construction of the H5-WHP jacket and drilling deck is complete; the offshore installation of the platform commenced on 21 August ahead of schedule and is expected to be completed by early September in preparation for the five initial planned wells to be drilled from mid-September onwards. Production from the H5-WHP will be tied-in to the FPSO via a pipeline from the H5 WHP to the H1 WHP.

Field Evaluation

Earlier this year, SOCO retained ERC Equipoise Limited ("ERCE") as independent experts to construct a field wide model of the TGT field, incorporating all available data including seismic, appraisal and development well data and production history. The first step of the ERCE work is to build a new static geoscience model followed by a dynamic engineering model. The ERCE study is currently ongoing, with full field simulation model expected to be completed by the end of 2014.

The new field model will enable us to further advance our understanding of the field and to optimise future drilling and field management activity. The results of the new model will be incorporated into the reserves assessment at year-end. SOCO also expects to commission an independent reserves evaluation report following completion of the ERCE work. 

Block 9-2 - Ca Ngu Vang Field (CNV) (25% interest; operated by Hoan Vu Joint Operating Company ("HVJOC"))

Production

Production from CNV averaged 2,021 BOEPD net to the Company's working interest during the first six months of the year (2,168 BOEPD in the first half of 2013 and 2,059 BOEPD for the full year 2013).

Drilling

The drilling of the CNV-7P well by the Naga 2 rig commenced on 19 April 2014. The well is designed to target the thus far unpenetrated fractures located in the south-west area of the CNV field and to enable production to be increased. The well encountered unexpected geological problems, not encountered previously on the structure, in the upper hole section just above the reservoir, requiring the section to be re-drilled. The same geological problems persisted during two attempted side-tracks preventing the successful completion of this section to be safely achieved. The decision was made to suspend the well and to allow for a review of alternative plans and well paths that will enable the well to be successfully completed. The decision as to the timing of returning to the well is expected to be made in October/November as part of the HVJOC budgeting process for next year.

The Naga 2 rig will be moved to the TGT field to start drilling the H5 development wells following installation of the H5 WHP platform.  Until then the rig will be used for routine abandonment operations on previously suspended exploration wells.

AFRICA

REPUBLIC OF CONGO (BRAZZAVILLE)

Marine XI (40.39% interest held by 85% owned subsidiary; operated)

The Lidongo X Marine-101 ("LXM-101") exploration well spudded using the jack-up drilling rig Noble Percy Johns on 5 August 2014 in the Marine XI Block, located in the offshore Congo Basin. The LXM-1 well is designed to test the extension of an adjacent gas/condensate/oil field into the Marine XI licence Block. The LXM-101 well is located 23 kilometres north west of Pointe Noire in a water depth of approximately 45 metres. The planned total depth for the well is provisionally estimated to be 2,600 metres Total Vertical Depth subsea ("TVDss"), although provision has been made to continue drilling to a maximum depth of circa 3,100 metres TVDss, terminating in the lower most part of the Djeno sandstone formation. The well is currently preparing to drill ahead after setting 13 3/8 inch casing, and the drilling is expected to be completed in mid-late September.

Nanga II A (100% interest held by 85% owned subsidiary; operated)

SOCO has received approval from the Congolese Ministry of Hydrocarbons for an extension to the Prospection Authorisation through mid-October 2014. The Company is evaluating various options and will make a decision shortly on proceeding into negotiations for a Petroleum Sharing Agreement.

Mer Profonde Sud (MPS) permit (60% interest; operated)

The Company's farm-in to acquire a 60% working interest in the offshore MPS Block has been completed following government approval of the commencement of the relevant two-year licence period from 1 June 2014. The partners have now commenced a detailed well location study and would look to drill in mid 2015.

DEMOCRATIC REPUBLIC OF CONGO (KINSHASA) ("DRC")

Block V (85% interest held by 85% owned subsidiary; operated)

After receiving all necessary regulatory approvals, the lake bed seismic survey on Lake Edward was completed in July. The acquired data will now be processed and interpreted. Work is ongoing to withdraw all the equipment and services used during the survey from the area under the supervision of the environmental authorities.

Part of Block V overlaps a portion of Virunga National Park, and on 11 June 2014 SOCO announced that WWF and the Company had agreed the way forward on SOCO's future activity.  SOCO committed, that, in the absence of an agreement between the DRC and UNESCO, SOCO will not progress its operations in Virunga National Park.

The Company has non-operational investment obligations regarding environmental baseline studies and social projects, which include the recent installation of facilities capable of providing potable water to several local communities.

ANGOLA

Cabinda North (17% interest held by 80% owned subsidiary; non-operated)

Data from the 2013 drilling programme has been incorporated into the seismic interpretation and the operator, Sonangol, is preparing detailed plans for operations in 2015. These are expected to be reviewed by the partnership in the fourth quarter.

FINANCIAL RESULTS

First half 2014 revenue, net profit and cash flows are in line with the Company's expectations.  SOCO remains well financed with no debt on the balance sheet and $284 million of cash, cash equivalents and liquid investments as at 30 June 2014.

Key Financial Metrics

	1H 2014	1H 2013	Change
Production (BOEPD, working interest)	13,960	17,135	-18.5%
Oil price realised ($/bbl)	113.11	112.45	0.5%
Sales revenue ($m)	246.4	324.0	-24.0%
Gross profit ($m)	180.4	235.3	-23.3%
EBITDA ($m)	199.0	257.6	-22.8%
Operating profit ($m)	174.4	229.6	-24.0%
Net profit ($m)	79.8	105.4	-24.3%
Operating Cash Flow ($m)	141.4	181.6	-22.1%
Capital expenditure ($m)	60.1	30.9	94.5%
Free cash flow ($m)	74.7	150.7	-50.4%
Net cash, cash equivalents and liquid investments ($m)	284.0	361.3	-21.4%

INCOME STATEMENT

Revenue

Oil and gas revenues in the first half of 2014 were $246.4 million, down from $324.0 million in the equivalent period last year, mainly due to part of the capacity of the TGT floating production storage and offloading vessel (FPSO) being made available, from May 2013, to the Thang Long Joint Operating Company (TLJOC) which operates a contiguous field to the north of TGT.  Offsetting this was the inclusion of TGT gas sales following the signing of the TGT gas sales agreement in the second half of 2013.  The Group's working interest (which is equivalent to its entitlement interest) share of production during the period was 13,960 BOEPD down from 17,135 BOEPD in the first half of 2013. For the reporting period the Group realised an average oil price of $113.11 per barrel of oil sold (period to 30 June 2013, $112.45 per barrel).

Cost of Sales

Cost of sales in the period was $66.0 million for the six month period to 30 June 2014, down from $88.7 million in the first half of 2013. This decrease is mainly associated with the TGT field where cost of sales was $59.2 million in the current period including an inventory credit, recorded at market value, of $5.9 million (1H 2013 $80.5 million including an inventory credit of $2.8 million). Operating costs for TGT were $19.1 million for this six month reporting period down from $22.6 million for the period to 30 June 2013 mainly due to allocation of costs to the TLJOC via a tariff arrangement for the use of the TGT FPSO, and lower production.

Cost of sales associated with the CNV field was $6.8 million, including an inventory credit of $0.5 million (first half of 2013 - $8.2 million, including an inventory charge of $0.7 million).  Operating costs associated with CNV were $2.3 million in the first half of 2014, up slightly from $2.1 million for the first half of 2013. 

Royalties on oil sales from TGT and CNV in the current period totalled $19.4 million consistent with lower revenue compared with $25.4 million in the first half of 2013. Export duty arising on TGT oil sales amounted to $5.1 million in the current period, down from $10.8 million in the first half of 2013, due to lower oil sales revenues and a proportion of cargoes being sold into the domestic market which are not subject to export duty.  All CNV oil was sold into the domestic market for both the current period and equivalent period last year. Depreciation, depletion and decommissioning costs (DD&A) were $23.7 million in the first half of 2014 compared with $27.3 million in the equivalent period last year mainly reflecting the production and cost basis of the TGT development.

Operating costs on a per barrel basis (excluding DD&A, inventory movements and sales related duties and royalties) were approximately $8.50 per barrel compared with approximately $7.90 per barrel in the first half of 2013. The primary cause of the increase is related to the lower production volumes on the TGT field which has dedicated production and processing facilities on the floating production storage and offloading vessel, the costs of which, net of TLJOC allocations, are predominately fixed.

On a per barrel basis, DD&A increased from approximately $8.80 per barrel in the first half of 2013 to $9.40 per barrel in the six months ended June 2014 reflecting a higher estimated cost basis of developing the TGT reserves.

Operating Profit

Operating profit for the period was $174.4 million arising from the Group's production operations in Vietnam compared with $229.6 million for the first half of 2013.

Tax

The tax expense decreased from $123.3 million in the six month period ending 30 June 2013 to $94.9 million in the current reporting period consistent with the lower profit in the current period.

BALANCE SHEET

Intangible assets increased by $27.8 million since year end 2013 and decreased by $10.3 million since 30 June 2013. The increase in the six months to 30 June 2014 arises predominantly from continued exploration activity in the Group's Africa region, including seismic acquisition in Block V in the Albertine Graben, DRC and preparation for drilling offshore Congo Brazzaville.  The decrease of $10.3 million since June 2013 is attributable to the $92.0 million write off of Nganzi costs taken in 2H 2013, offset by $81.7 million of exploration costs in Africa over the 12 month period. Property, plant and equipment increased by $7.4 million since 2013 year end and by $9.7 million over the last 12 months due to TGT field development and appraisal activities and CNV development drilling offset by DD&A charges.

Other receivables of $21.6 million (31 December 2013 - $15.0 million and 30 June 2013 - nil) comprise abandonment security funds for TGT and CNV which have been established to ensure that sufficient funds exist to meet future abandonment obligations.  The funds are operated by PetroVietnam and partners retain the legal rights to the funds pending commencement of abandonment operations.

Oil inventory was $13.7 million at 30 June 2014, comparable to the $13.2 million reported at 30 June 2013, and up from $7.3 million at year end 2013. Trade and other receivables at 30 June 2014 were $57.2 million, up from $53.6 million at 30 June 2013, and down from $68.9 million at year end 2013. The movements in oil inventory and trade receivables arise mainly due to the timing of oil sale liftings and the oil price realised.

SOCO's cash, cash equivalents and liquid investments totalled $284.0 million at 30 June 2014 (31 December 2013 and 30 June 2013, $210.0 million and $361.3 million, respectively). This increase since year end is a result of net cashflows from production operations in Vietnam, partly offset by the Group's TGT H5 development programme, TGT and CNV drilling activity and exploration activity in Africa.

Trade and other payables were $37.4 million at the current period end, up from $29.5 million at 30 June 2013 and close to $36.1 million at 31 December 2013 mainly due to the status of the ongoing work programmes, in particular in Vietnam associated with the TGT development. Tax payable of $18.1 million at the end of the reporting period compared, with $17.2 million at 30 June 2013 and $18.5 million at the end of 2013, is consistent with the timing of liftings in Vietnam where tax is paid on each cargo lifted.

Deferred tax liabilities have increased to $213.7 million at 30 June 2014 from $152.0 million at 30 June 2013 and $184.2 million at 31 December 2013 mainly due to accelerated tax depreciation and other tax timing differences associated with Block 16-1, Vietnam. Long term provisions comprise the Group's decommissioning obligations in South East Asia which have increased to $44.4 million from $42.8 million at 30 June 2013 and from $42.9 million at year end 2013. This reflects the development drilling activity at the TGT field.

CASH FLOW

Net cash flows from operating activities for the first six months of 2014 comprise the Group's continuing Vietnam operations and amounted to $141.4 million compared with $181.6 million in the first half of 2013. This decrease is mainly due to the lower contribution of production from the TGT field including the associated impact on working capital movements, as described above.

Capital expenditure for the period ending 30 June 2014 was $60.1 million compared with

$30.9 million in the equivalent period last year. The higher capital spend in the current period reflects a more active development programme, including the TGT H5 development and TGT and CNV drilling activity, compared to the same period last year.

Free cash flow for the period was $74.7 million (year ended 31 December 2013 - $200.3 million and six months ended 30 June 2013 - $150.7 million).

RELATED PARTY TRANSACTIONS

There have been no material related party transactions in the period and there have been no material changes to the related party transactions described in Note 34 to the Consolidated Financial Statements contained in the 2013 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 2014 and could cause actual results to differ materially from expected and historical results. Risks and uncertainties, along with the mitigation measures in place to reduce risks to acceptable levels, that remain unchanged from those published in the 2013 Annual Report and Accounts are summarised below:

·    Operational risk - associated with 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.

·    Credit risk - in respect of the Group's short term financial assets and financial asset at fair value through profit or loss arising on the Group's disposal of its Mongolia interest.

·    Foreign currency risk - associated with cash balances held in non-US dollar denominations.

·    Liquidity risk - associated with meeting the Group's cash requirements.

·    Interest rate risk - applicable to the Group's cash balances and financial asset.

·    Commodity price risk - associated with the Group's sales of oil and gas.

·    Regulatory risk - arising in countries where the Group has an interest, including compliance with and interpretation of taxation and other regulations.

·    Contractual risk - in relation to contractual terms that may be subject to further negotiation at a later date.

·    Capital risk management - in relation to Group financing.

·    Reserves risk - associated with inherent uncertainties in the application of standard recognised evaluation techniques to estimate proven and probable reserves.

·    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.

·    Business conduct and bribery risk - the industry sector and certain countries where SOCO operates may be perceived as falling short of the standards expected by the UK Bribery Act.

·    Political and regional risk - due to the location of the Group's projects, often in developing countries or countries with emerging free market systems.

·    Health, safety, environment and social risks - arising due to the nature and location of the Group's activities.

Further information on the above principal risks and uncertainties facing the Group is included in the Risk Management section of the 2013 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.

GOING CONCERN

The Group has a strong financial position and based on future cash flow projections should be able to continue in operational existence for the foreseeable future. Consequently the Directors believe that the Group is well placed to manage its financial and operating risks successfully and have prepared the Half Year Report on a going concern basis.

CORPORATE

 

Capital distribution to Shareholders

SOCO's Board has recommended a cash return to shareholders via the implementation of a B/C Share scheme and has recommended that shareholders vote to approve the scheme at a General Meeting of the Company that is scheduled for 22 September 2014. 

Chief Financial Officer

On 1 May 2014 Anya Weaving joined the Company as Chief Financial Officer from Bank of America Merrill Lynch where she was a Managing Director in Mergers and Acquisitions with responsibility for the oil and gas sector.

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

27 August 2014

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 Half Year 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.

 

INDEPENDENT REVIEW REPORT TO SOCO INTERNATIONAL PLC

We have been engaged by the Company to review the condensed set of financial statements in the half year financial report for the six months ended 30 June 2014 which comprises the condensed consolidated income statement, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash flow statement and related notes 1 to 8. We have read the other information contained in the half year 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 year financial report is the responsibility of, and has been approved by, the Directors.  The Directors are responsible for preparing the half year 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 year 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 year 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 Ireland) 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 year financial report for the six months ended 30 June 2014 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

Chartered Accountants and Statutory Auditor

London, United Kingdom

27 August 2014

CONDENSED CONSOLIDATED INCOME STATEMENT

			(unaudited)	(unaudited)
			six months ended	six months ended	year ended
			30 Jun 14	30 Jun 13	31 Dec 13
		Notes	$ million	$ million	$ million
Revenue		3	246.4	324.0	608.1
Cost of sales			(66.0)	(88.7)	(169.1)
Gross profit			180.4	235.3	439.0
Administrative expenses			(6.0)	(5.7)	(13.2)
Exploration costs written off			-	-	(92.0)
Operating profit			174.4	229.6	333.8
Investment revenue			0.4	0.6	1.0
Other gains and losses			0.8	0.6	1.3
Finance costs			(0.9)	(2.1)	(2.8)
Profit before tax		3	174.7	228.7	333.3
Tax		4	(94.9)	(123.3)	(229.2)
Profit for the period			79.8	105.4	104.1
Earnings per share (cents)		5
Basic			24.3	32.1	31.7
Diluted			24.2	32.0	31.6
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 14	30 Jun 13	31 Dec 13
			$ million	$ million	$ million
Profit for the period			79.8	105.4	104.1
Items that may be subsequently reclassified to profit or loss:
Unrealised currency translation differences			0.1	0.1	9.3
Total comprehensive income for the period			79.9	105.5	113.4

CONDENSED CONSOLIDATED BALANCE SHEET

			(unaudited)	(unaudited)
			30 Jun 14	30 Jun 13	31 Dec 13
		Note	$ million	$ million	$ million
Non-current assets
Intangible assets			243.5	253.8	215.7
Property, plant and equipment			808.7	799.0	801.3
Financial asset		6	44.2	42.7	43.4
Other receivables			21.6	-	15.0
			1,118.0	1,095.5	1,075.4
Current assets
Inventories			13.7	13.2	7.3
Trade and other receivables			57.2	53.6	68.9
Tax receivables			1.1	0.7	0.9
Liquid investments			47.5	30.1	80.1
Cash and cash equivalents			236.5	331.2	129.9
			356.0	428.8	287.1
Total assets			1,474.0	1,524.3	1,362.5
Current liabilities
Trade and other payables			(37.4)	(29.5)	(36.1)
Tax payables			(18.1)	(17.2)	(18.5)
			(55.5)	(46.7)	(54.6)
Non-current liabilities
Deferred tax liabilities			(213.7)	(152.0)	(184.2)
Long term provisions			(44.4)	(42.8)	(42.9)
			(258.1)	(194.8)	(227.1)
Total liabilities			(313.6)	(241.5)	(281.7)
Net assets			1,160.4	1,282.8	1,080.8
Equity
Share capital			27.6	27.6	27.6
Share premium account			11.2	73.0	11.1
Other reserves			227.8	106.0	226.5
Retained earnings			893.8	1,076.2	815.6
Total equity			1,160.4	1,282.8	1,080.8

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

	Called up share capital	Share premium account	Other reserves	Retained earnings	Total
	$ million	$ million	$ million	$ million	$ million
As at 1 January 2013	27.6	73.0	105.5	970.5	1,176.6
Share-based payments	-	-	0.7	-	0.7
Transfer relating to convertible bonds	-	-	(0.2)	0.2	-
Unrealised currency translation differences	-	-	-	0.1	0.1
Retained profit for the period	-	-	-	105.4	105.4
As at 30 June 2013 (unaudited)	27.6	73.0	106.0	1,076.2	1,282.8
Distributions	-	-	-	(210.9)	(210.9)
Issue and redemption of B shares	-	(61.9)	61.9	-	-
Share-based payments	-	-	0.7	-	0.7
Transfer relating to share-based payments	-	-	(0.7)	0.7	-
Transfer relating to share-based payments in prior years	-	-	58.3	(58.3)	-
Unrealised currency translation differences	-	-	0.3	9.2	9.5
Loss for the period	-	-	-	(1.3)	(1.3)
As at 1 January 2014	27.6	11.1	226.5	815.6	1,080.8
New shares issued	-	0.1	-	-	0.1
Share-based payments	-	-	(0.4)	-	(0.4)
Transfer relating to share-based payments	-	-	1.7	(1.7)	-
Unrealised currency translation differences	-	-	-	0.1	0.1
Retained profit for the period	-	-	-	79.8	79.8
As at 30 June 2014 (unaudited)	27.6	11.2	227.8	893.8	1,160.4

CONDENSED CONSOLIDATED CASH FLOW STATEMENT

			(unaudited)	(unaudited)
			six months ended	six months ended	year ended
			30 Jun 14	30 Jun 13	31 Dec 13
		Note	$ million	$ million	$ million
Net cash from operating activities		7	141.4	181.6	314.4
Investing activities
Purchase of intangible assets			(31.6)	(17.7)	(63.1)
Purchase of property, plant and equipment			(28.5)	(13.2)	(36.0)
Decrease (increase) in liquid investments 1			32.6	19.9	(30.1)
Payment to abandonment fund			(6.6)	-	(15.0)
Net cash (used in) investing activities			(34.1)	(11.0)	(144.2)
Financing activities
Share-based payments			(0.7)	-	-
Repayment / Repurchase of convertible bonds			-	(47.8)	(47.8)
Proceeds on issue of ordinary share capital			0.1	-	-
Distributions			-	-	(210.9)
Net cash (used in) financing activities			(0.6)	(47.8)	(258.7)
Net increase (decrease) in cash and cash equivalents			106.7	122.8	(88.5)
Cash and cash equivalents at beginning of period			129.9	208.5	208.5
Effect of foreign exchange rate changes			(0.1)	(0.1)	9.9
Cash and cash equivalents at end of period 1			236.5	331.2	129.9
1 Liquid investments comprise short term liquid investments of between three to six months maturity while cash and cash equivalents comprise cash at bank and other short term highly liquid investments of less than three months maturity. The combined cash and cash equivalents and liquid investments balance at 30 June 2014 was $284.0 million (31 December 2013 - $210.0 million and 30 June 2013 - $361.3 million).

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1        General information

The information for the year ended 31 December 2013 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.

The Directors do not recommend the payment of a dividend, however the Company has announced its intent to provide a cash return to shareholders. See Note 8 below.

The half year financial report for the six months ended 30 June 2014 was approved by the Directors on 27 August 2014.

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 2013 Annual Report and Accounts for the year ended 31 December 2013, except for the new accounting standards and interpretations effective as of 1 January 2014, as outlined below.  The condensed set of financial statements included in this half year financial report has been prepared on a 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.

The Group has adopted the following new and amended IFRS and IFRIC interpretations as of 1 January 2014 for the historical information presented for the six months ended 30 June 2014:

●          IFRS 1, 2, 3, 8, 13 as a result of the Annual Improvements 2011-2013 Cycles

●          IFRS 10 Consolidated Financial Statements

●          IFRS 11 Joint Arrangements (Amendments)

●          IFRS 12 Disclosures of Involvement with other entities Regulatory Deferral Accounts

●          IAS 19 Employee Benefits (Amendments)

●          IAS 27 Separate Financial Statements

●          IAS 28 Investment in Associates and Joint Ventures

The new and amended standards and interpretations had no material impact on the financial information for the six months ended 30 June 2014.

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 2014 (unaudited)
		SE Asia	Africa	Unallocated		Group
		$ million	$ million	$ million		$ million
	Oil sales	246.4	-	-		246.4
	Profit (loss) before tax	179.6	-	(4.9)		174.7
	Six months ended 30 June 2013 (unaudited)
	Oil sales	324.0	-	-		324.0
	Profit (loss) before tax	234.7	-	(6.0)		228.7
	Year ended 31 December 2013
	Oil sales	608.1	-	-		608.1
	Profit (loss) before tax	437.7	(92.0)	(12.4)		333.3

4        Tax

		(unaudited)	(unaudited)
		six months ended	six months ended	year ended
		30 Jun 14	30 Jun 13	31 Dec 13
		$ million	$ million	$ million
	Current tax	65.4	84.6	158.3
	Deferred tax	29.5	38.7	70.9
		94.9	123.3	229.2

The Group's corporation tax is calculated at 50% of the estimated assessable profit for each period. During each period both current and deferred taxation have arisen in overseas jurisdictions only.

5        Earnings per share

The calculation of the basic and diluted earnings per share is based on the following data:

		(unaudited)	(unaudited)
		six months ended	six months ended	year ended
		30 Jun 14	30 Jun 13	31 Dec 13
		$ million	$ million	$ million
	Earnings	79.8	105.4	104.1
		Number of shares (million)
		(unaudited)	(unaudited)
		six months ended	six months ended	year ended
		30 Jun 14	30 Jun 13	31 Dec 13
	Weighted average number of ordinary shares for the purpose of basic earnings per share	328.4	328.2	328.2
	Effect of dilutive potential ordinary shares - Share awards and options	0.7	0.8	0.8
	Weighted average number of ordinary shares for the purpose of diluted earnings per share	329.1	329.0	329.0

6        Financial asset

In 2005, the Group disposed of its Mongolia interest to Daqing Oilfield Limited Company. Under the terms of the transaction the Group will receive a subsequent payment amount of up to $52.7 million, once cumulative production reaches 27.8 million barrels of oil, at the rate of 20% of the average monthly posted marker price for Daqing crude multiplied by the aggregate production for that month. The subsequent payment amount is included in non-current assets as a financial asset at fair value through profit or loss. The timescale for the production of crude oil in excess of 27.8 million barrels and the price of Daqing marker crude oil are factors that cannot accurately be predicted. However, based upon the Directors' current estimates of proven and probable reserves from the Mongolia interests and the development scenarios as discussed with the buyer, the Directors believe that the full subsequent payment amount will be payable.  The fair value of the subsequent payment amount was determined using a valuation technique as there is no active market against which direct comparisons can be made (Level 3 as defined in IFRS 7). Assumptions made in calculating the fair value include the factors mentioned above, risked as appropriate, with the resultant cash flows discounted at a commercial risk free interest rate.  The fair value of the financial asset at the date of completion of the sale was $31.5 million. As at 30 June 2014 the fair value was $44.2 million (31 December 2013 - $43.4 million and 30 June 2013 - $42.7million) after accounting for the change in fair value of $0.8 million (31 December 2013 - $1.3 million and 30 June 2013 - $0.6 million) through other gains and losses for the period.

7        Reconciliation of operating profit to operating cash flows

		(unaudited)	(unaudited)
		six months ended	six months ended	year ended
		30 Jun 14	30 Jun 13	31 Dec 13
		$ million	$ million	$ million
	Operating profit	174.4	229.6	333.8
	Share-based payments	0.8	0.7	1.4
	Depreciation, depletion and amortisation	23.8	27.4	44.8
	Exploration write off	-	-	92.0
	Operating cash flows before movements in working capital	199.0	257.7	472.0
	(Increase) decrease in inventories	(6.4)	(2.1)	3.8
	Decrease in receivables	9.8	20.1	8.6
	Increase (decrease) in payables	6.3	(5.8)	(9.1)
	Cash generated by operations	208.7	269.9	475.3
	Interest received	0.3	0.5	1.1
	Interest paid	(0.1)	(1.1)	(1.2)
	Income taxes paid	(67.5)	(87.7)	(160.8)
	Net cash from operating activities	141.4	181.6	314.4

Cash and cash equivalents (which are presented as a single class of asset on the balance sheet) comprise cash at bank and other short term highly liquid investments that are readily convertible to a known amount of cash and which are subject to an insignificant risk of change in value.

8        Return of cash to Shareholders

The Board is recommending, subject to Shareholder approval, that a return of cash of 22 pence per share (2013 - 40 pence per share) is paid to shareholders, which amounts to approximately £73 million (2013 - approximately £133 million). Eligible Shareholders will be offered the option of a capital rather than an income treatment of their distribution. The circular to Shareholders will be posted on 28 August 2014 and, if approved by Shareholders in the general meeting, cash will be distributed in October 2014.

 

END

 

 

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