Pharos Energy Regulatory News (PHAR)

RNS Number : 5553B

Soco International PLC

05 March 2014

 

SOCO International plc

(SOCO or the Company)

 

PRELIMINARY RESULTS

 

SOCO, an international oil and gas exploration and production company, today announces its preliminary results for the year ended 31 December 2013.

 

Operational Highlights

· TGT gross production exceeded 60,000 barrels of oil equivalent per day (BOEPD) in April's first phase of Floating Production, Storage and Offloading vessel (FPSO) testing prior to production scale back associated with sharing the FPSO

· The TGT H5 exploration/appraisal well tested over 27,600 BOEPD making it one of the highest flow rate wells ever in Vietnam 

· Annual production net to the Group's working interest averaged 16,694 BOEPD (2012: 14,757 BOEPD)

· Lideka East Marine-1 well, in the Marine XI Block offshore Congo (Brazzaville), intersected 50 metres of net oil pay

 

Financial Highlights

· Revenue of $608.1 million (2012: $621.6 million)

· Earnings before Interest, Taxes, Depreciation, Amortisation and Exploration write offs (EBITDA) equalled $472.9 million (2012: $496 million)

· Operating cash flow of $314.4 million (2012: $334.8 million)

· Free cash flow of $200 million

· Net cash, cash equivalents and liquid investments at 31 December 2013 were $210 million (2012: $211.3 million)

 

Corporate Highlights

· Returned $213.3 million (40pence per share) to shareholders on 14 October 2013

· All outstanding convertible bonds were purchased and cancelled in May 2013

· Strengthened the Board with the addition of two new independent Non-Executive Directors, Marianne Daryabegui and Rob Gray

· 2013 saw zero lost time injuries

 

Outlook

· Continued strong cash generation from Vietnam assets

· Ongoing development and drilling on TGT and CNV with three rigs contracted

· Two potentially high impact exploration wells targeted to be drilled offshore Congo (Brazzaville)-Litchendjili Extension (Marine XI), rig contracted, and Mer Profonde Sud Block

· Fast track TGT H5 development with first oil expected in 2015

· 2014 return of capital to shareholders

 

 

Ed Story, President and Chief Executive Officer of SOCO, commented:

 

"The Company is pleased that we have been able to create value for shareholders from cash returns and a 100% success ratio in our Vietnam and operated drilling programmes. Whilst revenues are slightly down due to both lower product prices and our previously announced FPSO sharing agreement in Vietnam, the future looks extremely bright with the TGT field extension as a result of the hugely successful H5 exploration well. Given our strong cash generation and high potential portfolio, the Company looks forward to sustaining value creation in 2014 and beyond."

 

 

ENQUIRIES:

 

SOCO International plc

Roger Cagle, Deputy Chief Executive and Chief Financial Officer

Tel: 020 7747 2000

 

Bell Pottinger

Rollo Crichton-Stuart

Elizabeth Snow

Tel: 020 7861 3232

 

 

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.

 

SOCO holds its interests in Vietnam, all in the Cuu Long Basin offshore, through its wholly-owned subsidiaries, SOCO Vietnam Ltd and OPECO Vietnam Limited. SOCO Vietnam Ltd holds a 25% working interest in Block 9-2, which is operated by the Hoan Vu Joint Operating Company and holds a 28.5% working interest in Block 16-1, which is operated by the Hoang Long Joint Operating Company. OPECO Vietnam Limited holds a 2% interest in Block 16-1.

 

SOCO holds its interests in the Marine XI and the Nanga II A Blocks in the Republic of Congo (Brazzaville) through its 85% owned subsidiary, SOCO Exploration and Production Congo SA (SOCO EPC). SOCO EPC holds a 40.39% interest in the Marine XI Block located offshore in the shallow water Lower Congo Basin and is designated operator of the Block. SOCO EPC also holds a 100% interest in a one-year Prospection Authorisation over the Nanga II A Block, located onshore, adjacent to the coast.

 

SOCO hold its 60% working interest in the Mer Profonde Sud Block, offshore the Republic of Congo (Brazzaville) through its wholly owned subsidiary, SOCO Congo BEX Limited.

 

SOCO holds its interests in the Democratic Republic of Congo (Kinshasa) (DRC), all onshore, though its 85% owned subsidiary, SOCO Exploration and Production DRC Sprl (SOCO E&P DRC). SOCO E&P DRC holds an 85% working interest and is the designated operator in Block V, situated in the southern Albertine Graben in eastern DRC.

 

SOCO holds its interests in the Angolan enclave of Cabinda through its 80% owned subsidiary, SOCO Cabinda Limited, which holds a 17% participating interest in the Production Sharing Agreement for the Cabinda North Block.

 

 

Our business model is very simple; we are value focused. We do not approach this by setting reserve or production milestones, which may or may not add value. We aim to deliver shareholder value by offering an attractive and sustainable yield via annual returns whilst providing relatively low risk upside through focused exploration. 

 

The Company was pleased to have successfully initiated the yield leg of the business model last year by returning over $200 million to shareholders during the fourth quarter. We are also pleased to confirm our intention to recommend a further cash return this year. Using previous guidance of returning 50% of free cash flow, the magnitude of the cash return would be approximately $100 million. The intent is to again make this return in a manner which is tax efficient to many shareholders and the structure and quantum is expected to be confirmed with mid year results.

 

On the operations front, both our Vietnam and Congo wells drilled during 2013 were successful. Offshore Vietnam, on the Te Giac Trang (TGT) field, the TGT-10XST1 exploration/appraisal well, which tested beyond expectations at over 27,600 barrels of oil equivalent per day (BOEPD), will result in adding another unmanned production platform to increase productive capability from the TGT field in the range of 15,000 to 25,000 BOEPD when H5 comes on stream, projected to be in the third quarter of 2015.

 

The Lideka East Marine-1 well, in the Marine XI Block offshore Congo (Brazzaville), was also successful as it intersected 50 metres of net oil pay. The extent of this discovery is currently being evaluated. The potential extension of a significant field discovery on a contiguous block and several other potentially exploitable leads clearly add value to the Marine XI Block.

 

Extended testing on the TGT-10XST1 well consumed all of the contracted rig time during the year. Consequently a number of planned development wells required to test additional reservoir intervals in the producing part of the TGT field were deferred until 2014. Thus the additional field data needed to validate fully the newly developed reservoir simulation model is not yet available. 

 

As a consequence, we believe the sensible approach is to keep the notional assessment of recoverable volumes for the field unchanged from last year, which now includes gas, until we have more production data and a fully functioning full field simulation model. The notional in-place volumetric estimates are supported by an independent assessment by RPS, the reservoir engineering group retained by SOCO.

 

Enhancing our corporate governance was also a key achievement in 2013. We are very pleased to have added two extremely capable independent Non-Executive Directors to our Board. Marianne Daryabegui joined the Board in October 2013 and Rob Gray joined in December 2013.

 

It is with great pride that we were able to maintain our exemplary record from the health and safety aspect as we completed another year free of any lost time injuries. 

 

 

Financial and Operating Results

Group revenue for 2013 was relatively stable dropping slightly from last year's record level of $621.6 million to $608.1 million. This was an extremely strong result giving consideration to the necessary production curtailment from our largest producing asset, the TGT field, when capacity at the Floating Production Storage and Offloading (FPSO) facility was reduced by up to 15,000 BOEPD when a contiguous field commenced production into the vessel in May.

 

Before accounting for the non-cash impact of the Nganzi relinquishment, post-tax profits were similarly down slightly from $207.0 million in 2012 to $196.1 million in 2013. 

 

Net entitlement volumes actually increased year on year on a BOEPD basis, increasing from 15,496 to 16,694, after the TGT gas sales contract was signed during 2013, thus allowing gas volumes to be included in production and reserve statistics. Following the fulfilment of the cost recoupment associated with the Group's cost carry of PetroVietnam on Block 16-1 in 2012, the Group's entitlement volume is now equivalent to its working interest share of production. Realised oil prices dropped approximately $5.00 per barrel year on year with realised prices in 2013 averaging approximately $113 per barrel of crude oil sold.

 

Cash generated from operations came in at $314.4 million in 2013, down from $334.8 million in 2012, reflecting lower realised oil prices that were partially offset by higher volumes sold. Capital expenditures were down from $109.9 million in 2012 to $99.1 million in 2013. On 16 May 2013, the outstanding convertible bonds were purchased at par value and cancelled. On 14 October 2013, SOCO completed a return of $213.3 million to shareholders (£133 million), after receiving shareholder approval at a general meeting on 25 September 2013. The Group ended the year with cash, cash equivalents and liquid investments of $210.0 million, dropping only $48.5 million despite the large return to shareholders and the retirement of the convertible bonds. At year end 2013, SOCO was completely debt free.

 

2013 Operations Review

Vietnam

The TGT and Ca Ngu Vang (CNV) fields combined production during 2013 equalled 16,694 BOEPD net to SOCO's working interest, exceeding full year guidance by slightly over four per cent. CNV continues to produce steadily averaging 2,059 BOEPD net to the Company's working interest during 2013, slightly down from the previous year. During 2014, we expect to increase CNV's gross production by up to 25% when we drill the CNV-7P well, which should spud in the second quarter.

 

Production from TGT averaged 14,635 BOEPD net to the Group's working interest during 2013, as compared with 12,618 BOPD the previous year, which was prior to the signing of the TGT gas sales agreement. TGT production was adversely impacted by two events, sharing of the FPSO which reduced TGT throughput by 15,000 BOEPD and deferral of the 2013 development drilling programme due to the extended testing programme on the highly successful TGT-10XST1 exploration/appraisal well which flowed at a combined average maximum rate at over 27,600 BOEPD.

 

The partners have approved a three rig drilling programme in Vietnam for 2014. All three rigs are already under contract and the first, the Hercules Resilience, arrived on site on TGT on 1 March 2014. Additional activity is underway to bring H5 on-stream with an anticipated start date in the third quarter of 2015.

 

The positive TGT-10XST1 well result provides an opportune reminder that TGT is a field in early stage development. Also, the number and complexity of the oil bearing reservoirs across the entirety of the field means that the forward development plan must be optimised fully to deliver maximum recoverable oil over the field life.

 

Whilst the TGT field has a structurally simple trap configuration, it comprises a complex series of more than 50 reservoirs and, to date, only approximately 4% of its estimated P50 Stock Tank Oil Initially In Place (STOIIP) has been produced. The full field development of TGT will require optimisation of the development programme over the next six years that will include an additional 35-45 infill producer and injection wells, subject to the annual approval process in Vietnam. Similarly, individual reservoir optimisation also requires that the producing intervals for each and every development well throughout the field are continuously and actively managed. 

 

Africa

We are negotiating final terms to contract a rig to drill what is assessed to be a relatively low risk prospect in our Marine XI Block offshore Congo Brazzaville. This well is designed to determine whether the Litchendjili field, previously discovered on the contiguous Marine XII Block due to come on-stream next year, extends into our acreage. 

 

While we maintain our focus on organic growth generating our own prospect inventory, we do not ignore other value creation opportunities. One such opportunity was the farm-in to the Mer Profonde Sud (MPS) Block offshore Congo (Brazzaville) where we will evaluate significant exploration potential.

 

Following a detailed review by joint venture partners of the Nganzi Block onshore the Democratic Republic of Congo (DRC), it was decided not to apply to extend the exploration period. Thus the partners relinquished the Block in the last quarter of 2013. Although SOCO did not find commercial reserves in the Block, it has helped the Company to develop relationships in-country that will stand it in good stead for any potential future licence applications.

 

On Block V, after obtaining regulatory approval from the DRC Government, obtaining pre-programme environmental and regulatory sign-off from the managers of the Virunga National Park and conducting extensive consultation with local communities, SOCO expects to commence acquiring seismic data on Lake Edward. This is expected to be completed in the second quarter of 2014. Social investment projects for the communities on Block V began in August 2013, including a mobile hospital, the launch of a disease mapping campaign and the installation of a communications mast at Nyakakoma, a community located on the shores of Lake Edward.

 

SOCO takes its social and environmental responsibilities very seriously. Whilst there are some who oppose the DRC Government's decision to allow data gathering activities in Block V in the Eastern DRC, we are operating under valid contracts with the DRC Government which is fully entitled to award these contracts under both national laws and international convention. We remain committed to ensuring that the Government is able to obtain the knowledge it needs about the natural resource potential of the region using the most sustainable methodology practicable and that industry best practice is maintained. 

 

Corporate

Return of Cash to Shareholders

On 14 October 2013, SOCO completed a return of $213.3 million (£133 million) to shareholders, after receiving shareholder approval at a general meeting on 25 September 2013. The return of cash was structured using an issue of B Shares and/or C Shares, which enabled Shareholders to elect to receive their return of cash proceeds as either income or capital or any combination thereof on the equivalent basis of 40 pence per ordinary share.

 

The Board of Directors

Further strengthening of the Board was a high priority for the year, motivated by the unexpected departure of Michael Johns, our Senior Independent Director, for personal health reasons and the need to add complementary expertise, different perspectives and strengthen board independence. We are very appreciative of Michael's contributions during his tenure on the Board and are grateful for his insight and dedication to the Company.

 

We are delighted to add two highly qualified independent members to the Board. Marianne Daryabegui was appointed in October 2013 and will serve as a member of the Audit and Risk, Remuneration and Nominations Committees. Rob Gray was appointed in December 2013 and will serve as the Senior Independent Director and a member of the Audit and Risk and Remuneration Committees. This means that we have introduced at least one new member to the Board in four of the past five years. We point to this as a strong indication of our commitment to maintain high standards of governance.

 

Marianne is currently the Managing Director of the Corporate Finance Oil and Gas Team at BNP Paribas in Paris, France. She has extensive experience in oil and gas corporate transactions, including structured financing and reserve based lending facilities, and has advised a wide number of oil companies across the sector. Prior to this, she worked for eight years in BNP Paribas' Energy Commodities Export Project Department where she headed the Commodity Structure Finance team for the Middle East, North and West Africa. Before joining BNP Paribas, Marianne spent eight years at TOTAL, working amongst other activities on upstream acquisitions and divestments in Europe and Africa.

 

Rob Gray was a co-founder of RegEnersys, a natural resources investment entity, and is currently the principal of ReVysion LLP, a financial advisory business in the natural resources sector. Rob has been an advisor to the natural resources sector for more than 30 years, including 13 years at Deutsche Bank where he was latterly a Senior Advisor having been Chairman of UK Investment Banking for five years and formerly Global Head of Natural Resources. Prior to joining Deutsche Bank, he was instrumental in establishing a number of leading institutional oil and gas groups. Rob continues as an industry advisor to various natural resource entities.

 

The Board takes its responsibilities with regard to succession planning very seriously. Accordingly, attention is focused on attracting and retaining strong leadership to ensure that the Company continues to be well positioned to deliver value for shareholders.

 

Outlook

We remain committed to offering investors the opportunity for both an attractive and sustainable yield and substantial growth. During 2014, we intend to make a recommendation of a cash return to shareholders. Using previous guidance of returning 50% of 2013 free cash flow, the sum would approximate $100 million. As was the case in the 2013 cash distribution, this return will most likely be structured as a B and/or C Share scheme, which will provide our UK shareholders optionality for the most efficient way to accept funds. However, going forward as we use up good tax capital, we will likely revert to a typical semi-annual dividend payment targeting a yield comparable to this year's but with the intent of growing it annually, subject to various macro parameters. 

 

The operational focus for 2014 will be on the development of the H5 fault block of the TGT field. Whilst a decision is yet to be taken with regard to optimal production tie-in options, we expect that the additional productive capability will be on-line before the end of next year. Fabrication of an unmanned production platform for the H5 fault block will commence as soon as the official sanctioning of the project is received, which is anticipated to be before the end of the first quarter of this year.

 

Three rigs have been contracted for drilling in Vietnam. While one will be designated for drilling further development wells on the H1, H2, H3 and H4 fault blocks in the TGT field, another will drill the final production well on CNV, which will allow us to access the thus far unpenetrated southwest corner of the field fractures in basement. The third, on a short term two well contract, has arrived on location and will commence drilling from the H1-WHP in March 2014.

 

As stated, growth remains an important part of the SOCO story and exploration remains a cornerstone of our business model. However, we are committed to evaluating every alternative to optimise our exposure to upside without jeopardising a meaningful yield. What that means is that we will manage our portfolio and maintain capital discipline in such a manner to ensure that we do not commit a disproportionate share of our capital expenditure budget to exploration drilling. We will continue to explore innovative ways to gain upside through the drill bit.

 

Our near term exploration drilling programme is sharply focused, with half targeting a high chance of success with a relatively low capital commitment, whilst the other half offers significant upside. In 2014, we are concentrating on the former and final negotiations should be completed shortly for a rig for the drilling of an exploration well offshore Congo (Brazzaville) to probe what is expected to be an extension of the Litchendjili field discovery made by ENI several years ago on the Marine XII Block. This field is slated to begin production in 2015. Should drilling successfully demonstrate that the field extends into the Marine XI Block, unitisation could result in revenue being generated from the Block very early following the discovery. 

 

We remain very optimistic about the exploration potential of the MPS Block to deliver significant upside and will seek to drill it as soon as practical.

 

Again, we are value driven and will continue to explore all options to maximise this goal, which could include acquisitions or divestitures subject to either delivering on the value principle.

 

 

Rui de Sousa

Chairman

 

 

Ed Story

President and Chief Executive Officer

 

 

 

 

Development of the Te Giac Trang (TGT) field offshore Vietnam was slowed during 2013 in favour of drilling an exploration/appraisal well on the southern-most H5 fault block. This well, the TGT-10XST1, was a spectacular success, one of the highest flow rate wells ever drilled in Vietnam, achieving over 27,600 barrels of oil equivalent per day (BOEPD). In Africa, we drilled a discovery with the sole exploration well drilled there, offshore the Republic of Congo (Brazzaville). The scope of the discovery is being evaluated prior to drilling a follow-up appraisal well. Elsewhere in Africa, we are in the early stages of evaluating two other projects and have farmed into a near-ready-to-drill prospect, also offshore Congo (Brazzaville). 

 

Total production for the year averaged 16,694 BOEPD net to the Company's working interest (2012 - 14,757 BOEPD). All production is from the Company's interests in Vietnam.

 

Vietnam

SOCO's Block 16-1 and Block 9-2 projects in Vietnam are located offshore in the oil rich Cuu Long Basin, which is a shallow water, near shore area defined by several high profile producing oil fields, the largest of which, Bach Ho, is located between the two Blocks and has produced more than one billion barrels of oil to date. The projects are operated through non-profit Joint Operating Companies (JOCs) wherein each participating party owns shares equivalent to its respective interests in the Petroleum Contracts governing the projects.

 

SOCO's interests are held through its wholly-owned subsidiaries, SOCO Vietnam Ltd and OPECO Vietnam Limited. SOCO Vietnam Ltd holds a 25% working interest in Block 9-2, which is operated by the Hoan Vu JOC (HVJOC) and holds a 28.5% working interest in Block 16-1, which is operated by the Hoang Long JOC (HLJOC). OPECO Vietnam Limited holds a 2% interest in Block 16-1. SOCO's partners on both Blocks are PetroVietnam, the national oil company of Vietnam, and PTTEP, the national oil company of Thailand.

 

Block 16-1

Te Giac Trang (TGT) Field

The TGT field is situated in the north-eastern part of Block 16-1 offshore Vietnam and is operated by the HLJOC. The Block was awarded in December 1999 and the first commercial discovery, TGT, was made in 2005. TGT is considered to be a simple structure, with complicated production intervals, extending over 16 kilometres and at least five fault blocks. The producing reservoir comprises a complex series of over 50 clastic reservoir intervals of Miocene and Oligocene age. Each reservoir interval requires individual reservoir management to ensure optimised field recovery. Production from the TGT field started in August 2011 and thus is early in field life and without a directly comparable field analogue.

 

The TGT field is currently producing from sixteen wells from two unmanned platforms. Production net to SOCO's working interest averaged 14,635 BOEPD, an increase of almost 16% over the previous year. Considering the production limitations associated with sharing the Floating, Production, Storage and Offloading Vessel (FPSO), the field continues to perform in line with expectations, with field production averaging approximately 40,000 BOEPD (approximately 12,220 BOEPD net to the Group's working interest) through the first two months of 2014. TGT crude sales are at a premium to the Brent benchmark crude price, ranging from approximately $2 to $7.40 in 2013. The premium averaged approximately $4 per barrel to the Brent benchmark crude price to date in 2014.

 

TGT-10XST1 Exploration/Appraisal Well

The TGT-10XST1 exploration/appraisal well is located on the H5 fault in the southern part of the TGT field, approximately six kilometres south of the H4 Well Head Platform. Testing, completed in October 2013, exceeded all pre-test expectations, flowing at a combined average maximum production from the three zones tested at over 27,600 BOEPD. 

 

The first test, over a net 93 metre section in the Oligocene "C", produced at a maximum rate of 9,488 BOPD of 41.1 degree API oil and 1.16 million standard cubic feet of gas per day (MMSCFD). The second test, over the Miocene Lower 5.2L sequence, tested 7,100 BOPD and 1.76 MMSCFD. The final test, in the Lower Miocene Intra Lower Bach Ho 5.2 Upper and Lower sequence, over a perforated interval of 88.6 metres, flowed at an average maximum rate of 5,156 BOPD and 32.5 MMSCFD.

 

The well encountered approximately 250 metres of gross pay section (approximately 119 metres of net pay) in the Miocene and Oligocene reservoir horizons. Approximately 100 metres of net pay were evaluated by the three tests.

 

Floating, Production, Storage and Offloading Vessel Capacity Testing and Maintenance

By prior contractual agreement that limited its throughput to 15,000 BOPD and/or 27,000 barrels of water per day, the Thang Long JOC (TLJOC) began producing from its field on Block 15-2/01 into the TGT FPSO in May of 2013. As a consequence, TGT throughput had to be limited with the FPSO operating at its nameplate capacity of 55,000 BOPD. 

 

In anticipation of TGT throughput limitations associated with accepting TLJOC production, the HLJOC agreed with the owner/operator of the vessel to conduct testing of actual throughput capacity of the FPSO. In April 2013, the HLJOC completed the first phase of a multi-stage test of the TGT FPSO oil production handling capacity beyond the 55,000 BOPD contractual minimum quantity. During the test, the FPSO successfully processed sustained production of over 60,000 BOPD, which confirmed our expectations based on the detailed pre-test simulations that only minor modifications to the low pressure separator system would be required.

 

Production problems in August limited TLJOC's ability to contribute to the second phase FPSO testing, as did delays to the TGT infield drilling programme resulting from the extended time on the TGT-10X well. Consequently, the second phase testing did not occur as planned. The HLJOC took advantage of the delay and the entire FPSO system was shut in for seven days in order to carry out annual maintenance and to do some necessary repairs.

 

Current plans call for the second phase of FPSO testing to be conducted as soon as practicable in 2014. Expectations are that this will occur in the second half of this year, following additional development drilling on TGT.

 

2014 Drilling Campaign

Further appraisal and development drilling will commence with an initial six wells, and a further two contingent wells. These wells are across the field, drilled from both the H1 and H4 WHPs, and part of the ongoing exploitation of the TGT field. Results from these wells will be incorporated into the continued evaluation of the field for the determination of future development well locations over the next six years.

 

Associated Gas Gathering and Sales Agreement

In November 2013, the Group signed an Associated Gas Gathering and Sales Agreement in Hanoi for gas produced from the TGT field. The produced gas from the field is used for fuel and power generation offshore, and for gas lift on wells to enhance well performance, thus reducing the environmental impact of the operations. Gas in excess of these requirements is sold into the Bach Ho gathering system for transmission to shore for further use.

 

Gas produced during 2013 was 26.8 million cubic feet per day.

 

Reserves Determination

During 2013, SOCO improved its understanding of the TGT Field. Besides the production history, well management programme and the southern appraisal wells (TGT-10X and TG-10XST1 sidetrack), the Company retained ERC Equipoise Limited as independent experts to construct a field wide reservoir simulation model. 

 

The lengthy drilling operations for TGT-10X and the TGT-10XST1 sidetrack were followed by an extensive testing programme which meant that the planned six well development programme scheduled for 2013 had to be deferred another year until 2014. A consequence of this deferral is that vital new information required to add to the sparse historical production data (18 months for the H1 platform producers and little more than four months from the H4 platform producers) was unavailable to feed into the initial field simulation model. Thus, the evaluation of the field remains one step behind where we would like to be at this time. As a result, the Company has decided to leave its TGT reserve estimates unchanged from the previous year with the expectation of commissioning an independent reserves evaluation report as soon as practicable. 

 

These volumetric estimates are supported by an independent assessment by RPS, the reservoir engineering group retained by SOCO. For clarity, RPS was not retained to produce a report on Reserves or Resources but to provide an interim update of STOIIP and gas initially in place (GIIP) and recovery factors, incorporating information from the first phase of the field-wide static and reservoir simulation models prepared by SOCO. RPS arrived at a range of approximately 510 to 1,120 million barrels of oil equivalent in place which now includes GIIP. RPS modelled recoveries from various producing intervals which showed a wide range from 8% to 46%, depending on the quality, thickness and height above water contact of the individual reservoir sands. As we reported last year, RPS' initial assessment of STOIIP ranged from 466 to 958 MMBBLS, with average field-wide recovery factors ranging from 28% to 35%. SOCO anticipates recovery factors of up to 50% for reservoir zones across the field and currently it targets an aggregate recovery factor of 40% for the total field.

 

Block 9-2

Ca Ngu Vang (CNV)

The CNV field is located in the western part of Block 9-2, offshore Vietnam and is operated by the HVJOC. The field has been on-stream since 2008 and has been producing at stable rates with CNV production net to the Company's working interest averaging 2,059 BOEPD in 2013 (2012: 2,139 BOEPD). In contrast to TGT, the CNV field is a fractured granitic Basement field which produces highly volatile oil from a fractured Basement reservoir with a high gas to oil ratio and exploitation is dependent on the fracture interconnectivity to efficiently deplete the reservoir. Accordingly, traditional reservoir properties and STOIIP calculations are not straightforward and a further well will be required to allow assessment of the revised full reserve potential of this field.

 

Hydrocarbons produced from CNV are transported via subsea pipeline to the Bach Ho central processing platform (BHCPP) where the wet gas is separated from crude oil and transported via pipeline to an onshore gas facility for further distribution. The crude oil is stored on a FPSO vessel prior to sale. At BHCPP, dedicated test separation and metering facilities have been installed and commissioned.

 

Preparations have commenced for drilling of the CNV-7P well in the first half of 2014, following formal approval by the relevant Vietnamese authorities of the updated CNV Full Field Development Plan. The well will be drilled into the south-west area of the field and will enable production to be increased.

 

Republic of Congo (Brazzaville)

SOCO holds its interests in the Marine XI and the Nanga II A Blocks in Congo (Brazzaville) through its 85% owned subsidiary, SOCO Exploration and Production Congo SA (SOCO EPC). SOCO EPC holds a 40.39% interest in the Marine XI Block located offshore in the shallow water Lower Congo Basin and is designated operator of the Block. SOCO EPC also holds a 100% interest in a one-year Prospection Authorisation over the Nanga II A Block, located onshore, adjacent to the coast. SOCO holds a 60% working interest in the Mer Profonde Sud Block, offshore Congo (Brazzaville) through its wholly owned subsidiary, SOCO Congo BEX Limited.

 

Marine XI

Lideka East Marine-1 Well (LDKEM-1)

The LDKEM-1 well targeted a post-salt structure, up-dip from the Lideka Marine-1 well which found oil shows in the Sendji Formation (iS3). The well encountered approximately 50 metres of net pay section in the Upper and Lower Sendji, of which approximately 30 metres of net pay are within the targeted iS3 and S4 horizons.

 

The LDKEM-1 well was tested over a 20 metre interval in the iS3 and S4 horizons. The well flowed 35 degree API oil at a sustained rate of 268-335 BOPD, with base, sediment and water around 1%, in line with predictions from the petrophysical analysis. Produced gas volumes were very low.

 

The well was drilled on the crest of the structure to identify the length of the oil column. The Sendji is known to be a heterogeneous reservoir, and detailed rock physics and inversion models will need to be used to determine where the best porosity zones are situated. The oil water contact was not clearly defined in the exploration well, and an "oil down to" shale barrier could present upside. Further work will be conducted to establish viable opportunities on this field.

 

Litchendjili Extension

The large Litchendjili oil and gas discovery on the Marine XII Block, operated by ENI, lies adjacent to, and potentially extends onto SOCO's Marine XI Block. A geological-geophysical evaluation has been completed and a suitable well location determined. Negotiations are currently underway to secure a rig to drill in the second quarter of 2014.

 

SOCO has completed a well recommendation, subject to fine tuning based on additional information gained from sharing data with the operator on the contiguous block, to be submitted to partners at an upcoming meeting in March. A well site survey was completed in February 2014.

 

Nanga II A

Reprocessing is still ongoing of the remaining previously acquired seismic data, and is expected to be completed in the second quarter of 2014. We have received approval from the Congolese Ministry of Hydrocarbons for an extension to the Prospection Authorisation through mid-October of 2014.

 

Mer Profonde Sud (MPS)

The Company has acquired a 60% working interest in the MPS Block, offshore Congo (Brazzaville). The interest was acquired through a farm-in agreement entered into with PA Resources Congo SA (PAR), a wholly owned subsidiary of PA Resources AB. The MPS Block comprises the exploration area of the licence but excludes the Azurite Field.

 

In return for carrying certain of PAR's costs, SOCO will assume a 60% working interest in the MPS exploration area as operator and will drill an exploration well in the remaining licence period. The well will test a different structural setting and play, identified from recent seismic reprocessing and subsurface re-evaluation, from the other wells already drilled on the Block. It will target similar reservoirs that produce from offsetting fields in Congo (Brazzaville) and in Angola/Cabinda.

 

The transaction received government approval, but remains subject to regulatory approval to enter into the third and final period of the licence. Subsequent to obtaining the necessary approvals, the partners would look to drill by early 2015.

 

Upon completion of the transaction, PAR will retain a 25% working interest in the licence, whilst the Congolese state oil company, SNPC, will retain its current 15% interest.

 

Democratic Republic of Congo (Kinshasa) (DRC)

SOCO holds its onshore interest in the DRC though its 85% owned subsidiary, SOCO Exploration and Production DRC Sprl (SOCO E&P DRC). SOCO E&P DRC holds an 85% working interest and is the designated operator in Block V, situated in the southern Albertine Graben in eastern DRC.

 

Nganzi

The Board has decided not to proceed into the next phase of the licence. Accordingly, the Company submitted its application to relinquish the Block in October 2013. It received partner and regulatory approval in December and formal ministry confirmation of the joint venture partners' relinquishment of the Nganzi licence was received in early 2014. The non-cash write off of exploration costs amounted to $92 million.

 

Block V

Block V is in eastern DRC, adjacent to the border with Uganda. The region is geologically within the Albertine Graben and Albertine Rift and is commonly referred to as North Kivu and The Great Lakes Region. Block V includes Lake Edward (on the DRC side) and the adjacent lowland savannah, both of which are within the Virunga National Park. SOCO's interest in the Block V licence was ratified in June 2010 when the Block V Production Sharing Contract with the DRC Government received its DRC Presidential Decree, the final step in the licensing process.

 

The DRC Government has granted permission to SOCO to proceed with a seismic survey on Lake Edward as one of a number of scientific studies to be conducted in the Virunga National Park under the Government's Strategic Environmental Evaluation. Preparation for the seismic survey commenced in November 2013 with a bathymetry study of the lake to chart the shape of the lake floor.

 

The environmental impact assessment (EIA) relating to the seismic survey was conducted in 2011. The EIA highlighted a number of potential impacts on the flora and fauna. Accordingly, SOCO has taken mitigation steps, including change to the scale and scope of the seismic study, in order to reduce and where possible to eliminate these impacts. The Group has sought permission from the DRC Government to publish the EIA and it is understood that the report will soon be published on the Government's own website. An EIA for any potential subsequent activities has not yet been conducted as these activities are not currently being considered.

 

Although exploration is yet to begin on Block V, the Company has been very active fulfilling its non-exploratory operational commitments, including social projects and environmental baseline studies. 

 

Angola

Cabinda North

A two well exploration programme was initiated in the Cabinda North Block in the second half of 2013. The wells were both drilled in the area of the previous Dinge discovery. The Vovo sands of the Dinge Field are in an equivalent stratigraphic position to the Mengo-Kundji-Bindi reservoirs of the Republic of Congo, 17 kilometres northwest and on trend.

 

Although not material to SOCO's interests, the detailed results of the drilling programme will be released by the operator, Sonangol, in due course. The data from the two wells is currently being incorporated into the seismic data previously acquired ahead of any decision on the continuation of the drilling programme.

 

Consolidated Income Statement
for the year to 31 December 2013
														2013		2012
										Notes				$ million		$ million
Revenue										3				608.1		621.6
Cost of sales														(169.1)		(161.1)
Gross profit														439.0		460.5
Administrative expenses														(13.2)		(12.3)
Exploration costs written off										7				(92.0)		-
Operating profit														333.8		448.2
Investment revenue														1.0		1.0
Other gains and losses														1.3		1.5
Finance costs														(2.8)		(5.1)
Profit before tax										3				333.3		445.6
Tax										3, 4				(229.2)		(238.6)
Profit for the year														104.1		207.0
Earnings per share (cents)											6
Basic														31.7		62.7
Diluted														31.6		62.6
Consolidated Statement of Comprehensive Income
for the year to 31 December 2013
														2013		2012
														$ million		$ million
Profit for the year														104.1		207.0
Items that may be subsequently reclassified to profit or loss:
Unrealised currency translation differences														9.3		(0.2)
Total comprehensive income for the year														113.4		206.8

 

 

Balance Sheets
as at 31 December 2013
							Group			Company
							2013	2012		2013	2012
						Notes	$ million	$ million		$ million	$ million
Non-current assets
Intangible assets						7	215.7	199.7		-	-
Property, plant and equipment							801.3	816.6		0.9	1.0
Investments							-	-		884.6	811.4
Financial asset						8	43.4	42.1		-	-
Other receivables							15.0	-		-	-
							1,075.4	1,058.4		885.5	812.4
Current assets
Inventories							7.3	11.1		-	-
Trade and other receivables							68.9	72.2		0.8	0.6
Tax receivables							0.9	0.6		0.4	0.2
Assets classified as held for sale							-	36.3		-	-
Liquid investments							80.1	50.0		-	-
Cash and cash equivalents							129.9	208.5		0.3	0.2
							287.1	378.7		1.5	1.0
Total assets							1,362.5	1,437.1		887.0	813.4
Current liabilities
Trade and other payables							(36.1)	(34.3)		(1.7)	(5.2)
Tax payable							(18.5)	(21.4)		(0.1)	(0.1)
Convertible bonds						9	-	(47.2)		-	-
Liabilities associated with assets classified as held for sale							-	(1.6)		-	-
							(54.6)	(104.5)		(1.8)	(5.3)
Net current assets (liabilities)							232.5	274.2		(0.3)	(4.3)
Non-current liabilities
Deferred tax liabilities							(184.2)	(113.3)		-	-
Long term provisions							(42.9)	(42.7)		-	-
							(227.1)	(156.0)		-	-
Total liabilities							(281.7)	(260.5)		(1.8)	(5.3)
Net assets							1,080.8	1,176.6		885.2	808.1
Equity
Share capital							27.6	27.6		27.6	27.6
Share premium account							11.1	73.0		11.1	73.0
Other reserves							226.5	105.5		183.1	60.8
Retained earnings							815.6	970.5		663.4	646.7
Total equity							1,080.8	1,176.6		885.2	808.1

 

 

Statements of Changes in Equity
for the year to 31 December 2013
														Group
										Called up share capital	Share premium account	Other reserves	Retained earnings	Total
										$ million	$ million	$ million	$ million	$ million
As at 1 January 2012										27.5	72.7	140.8	857.1	1,098.1
New shares issued										0.1	0.3	-	-	0.4
Purchase of own shares into treasury										-	-	(32.9)	-	(32.9)
Share-based payments										-	-	(0.8)	-	(0.8)
Acquisition of non-controlling interest in subsidiary undertaking										-	-	-	(95.0)	(95.0)
Transfer relating to share-based payments										-	-	(1.1)	1.1	-
Transfer relating to convertible bonds										-	-	(0.5)	0.5	-
Unrealised currency translation differences										-	-	-	(0.2)	(0.2)
Retained profit for the year										-	-	-	207.0	207.0
As at 1 January 2013										27.6	73.0	105.5	970.5	1,176.6
Distributions										-	-	-	(210.9)	(210.9)
Issue and redemption of B shares										-	(61.9)	61.9	-	-
Share-based payments										-	-	1.4	-	1.4
Transfer relating to share-based payments										-	-	(0.7)	0.7	-
Transfer relating to share-based payments in prior years										-	-	58.3	(58.3)	-
Transfer relating to convertible bonds										-	-	(0.2)	0.2	-
Unrealised currency translation differences										-	-	0.3	9.3	9.6
Retained profit for the year										-	-	-	104.1	104.1
As at 31 December 2013										27.6	11.1	226.5	815.6	1,080.8
														Company
										Called up share capital	Share premium account	Other reserves	Retained earnings	Total
										$ million	$ million	$ million	$ million	$ million
As at 1 January 2012										27.5	72.7	93.8	432.9	626.9
New shares issued										0.1	0.3	-	-	0.4
Purchase of own shares into treasury										-	-	(32.9)	-	(32.9)
Share-based payments										-	-	(0.1)	-	(0.1)
Unrealised currency translation differences										-	-	-	31.2	31.2
Retained profit for the year										-	-	-	182.6	182.6
As at 1 January 2013										27.6	73.0	60.8	646.7	808.1
Distributions											-	-	(213.3)	(213.3)
Issue and redemption of B shares										-	(61.9)	61.9	-	-
Share-based payments										-	-	1.4	-	1.4
Transfer relating to share-based payments										-	-	(0.7)	0.7	-
Transfers relating to share-based payments in prior years										-	-	59.7	(54.3)	5.4
Unrealised currency translation differences										-	-	-	27.8	27.8
Retained profit for the year										-	-	-	255.8	255.8
As at 31 December 2013										27.6	11.1	183.1	663.4	885.2

 

 

Cash Flow Statements
for the year to 31 December 2013
								Group			Company
								2013	2012		2013	2012
						Notes		$ million	$ million		$ million	$ million
Net cash from (used in) operating activities						11		314.4	334.8		(13.7)	(7.0)
Investing activities
Purchase of intangible assets								(63.1)	(47.6)		-	-
Purchase of property, plant and equipment								(36.0)	(62.3)		(0.1)	(1.0)
Increase in liquid investments 1								(30.1)	(50.0)		-	-
Payment to abandonment fund								(15.0)	-		-	-
Investment in subsidiary undertakings								-	(95.0)		(90.7)	(152.8)
Dividends received from subsidiary undertakings								-	-		309.7	193.0
Proceeds on option to dispose of subsidiary						5		-	4.0		-	-
Net cash (used in) from investing activities								(144.2)	(250.9)		218.9	39.2
Financing activities
Purchase of own shares into treasury								-	(32.9)		-	(32.9)
Share-based payments								-	(1.9)		-	(1.9)
Repayment/repurchase of convertible bonds								(47.8)	(0.9)		-	-
Distributions								(210.9)	-		(213.3)	-
Proceeds on issue of ordinary share capital								-	0.4		-	0.4
Net cash (used in) financing activities								(258.7)	(35.3)		(213.3)	(34.4)
Net (decrease) increase in cash and cash equivalents								(88.5)	48.6		(8.1)	(2.2)
Cash and cash equivalents at beginning of year								208.5	160.1		0.2	2.6
Effect of foreign exchange rate changes								9.9	(0.2)		8.2	(0.2)
Cash and cash equivalents at end of year 1								129.9	208.5		0.3	0.2
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 31 December 2013 was $210.0 million (2012 - $258.5 million).

 

 

Notes to the consolidated financial information

 

1 General information

The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2013 or 2012, but is derived from those accounts. A copy of the statutory accounts for 2012 has been delivered to the Registrar of Companies and those for 2013 will be delivered following the Company's annual general meeting. The auditors have reported on those accounts; their reports were unqualified, did not draw attention to any matters by way of emphasis without qualifying their report and did not contain statements under section 498(2) or (3) of the Companies Act 2006. Whilst the financial information included in this preliminary announcement has been computed in accordance with International Financial Reporting Standards (IFRS), this announcement does not itself contain sufficient information to comply with IFRS. The financial statements are presented in US dollars which is the functional currency of each of the Company's subsidiary undertakings.

 

2 Basis of preparation

The financial information has been prepared in accordance with the recognition and measurement criteria IFRS and with IFRSs adopted for use in the European Union. The financial statements have been prepared under the historical cost basis, except for the valuation of hydrocarbon inventory and the revaluation of certain financial instruments.

 

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 financial information on a going concern basis.

 

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 (the Group's operating segments) and form the basis on which the Group reports its segment information. There are no inter-segment sales.
													2013
								SE Asia	Africa 2		Unallocated		Group
								$ million	$ million		$ million		$ million
	Oil and gas sales							608.1	-		-		608.1
	Profit (loss) before tax 1							437.7	(92.0)		(12.4)		333.3
	Tax charge							229.0	-		0.2		229.2
	Depletion and depreciation							44.6	-		0.2		44.8
													2012
								SE Asia	Africa 2		Unallocated		Group
								$ million	$ million		$ million		$ million
	Oil and gas sales							621.6	-		-		621.6
	Profit (loss) before tax 1							459.4	-		(13.8)		445.6
	Tax charge							238.6	-		-		238.6
	Depletion and depreciation							45.1	-		0.2		45.3
1	Unallocated amounts included in profit before tax comprise corporate costs not attributable to an operating segment, investment revenue, other gains and losses and finance costs.
2	Costs associated with the Africa segment are capitalised in accordance with the Group's accounting policy.
The accounting policies of the reportable segments are the same as the Group's accounting policies.
Included in revenues arising from South East Asia are revenues of $240.3 million, $102.2 million and $64.9 million (2012 - South East Asia $347.9 million, $86.1 million, $75.2 million and $64.2 million) which arose from the Group's largest individual customers who have contributed 10% or more to the Group's revenue.

 

Geographical information
Group revenue and non-current assets (excluding the financial asset and other receivables) by geographical location are separately detailed below where they exceed 10% of total revenue or non-current assets, respectively:
Revenue
All of the Group's revenue is derived from foreign countries. The Group's revenue by geographical location is determined by reference to the final destination of oil or gas sold.
											2013		2012
											$ million		$ million
	Malaysia										146.9		231.8
	Australia										137.5		144.1
	China										86.0		20.5
	Vietnam										74.7		87.8
	Japan										58.3		-
	South Korea										49.6		96.1
	Other										55.1		41.3
											608.1		621.6
Non-current assets
											2013		2012
											$ million		$ million
	United Kingdom										0.9		1.0
	Vietnam										800.6		815.8
	Congo										116.7		80.5
	Other - Africa										98.8		119.0
											1,017.0		1,016.3

 

4 Tax

											2013		2012
											$ million		$ million
Current tax											158.3		162.8
Deferred tax											70.9		75.8
											229.2		238.6
The Group's corporation tax is calculated at 50% (2012 - 50%) of the estimated assessable profit for the year in Vietnam. During 2013 and 2012 both current and deferred taxation have arisen in overseas jurisdictions only.
The charge for the year can be reconciled to the profit per the income statement as follows:
											2013		2012
											$ million		$ million
Profit before tax											333.3		445.6
Profit before tax at 50% (2012 - 50%)											166.7		222.8
Effects of:
Non-taxable income and non-deductible expenses											11.0		(0.2)
Tax losses not recognised											5.6		13.4
Non-deductible exploration write off											46.0		-
Adjustments to tax charge in respect of previous years											(0.1)		2.6
Tax charge for the year											229.2		238.6
The prevailing tax rate in the jurisdictions in which the Group produces oil and gas is 50%. The tax charge in future periods may also be affected by the factors in the reconciliation.

 

5 Option to sell majority interest in SOCO Cabinda Limited to non-controlling interest holder

In September 2012, SOCO announced that it had entered into a conditional agreement (the Disposal) with Quill Trading Corporation (Quill) wherein SOCO will sell its 80% majority interest in SOCO Cabinda Limited (SOCO Cabinda) to Quill, which holds the remaining 20% interest. SOCO Cabinda has a 17% participating interest in the Cabinda North Block, onshore the Angolan enclave of Cabinda. Quill paid a non-refundable deposit to the Company for the option to acquire SOCO's entire shareholding in SOCO Cabinda. Consequently, as at 31 December 2012, SOCO Cabinda was classified as held for sale. Although discussions continued with Quill regarding the possible sale of SOCO`s majority interest, it was determined that there was no certainty that a transaction would occur. Accordingly, SOCO Cabinda has been reclassified as an intangible asset.

 

6 Earnings per share

The calculation of the basic and diluted earnings per share is based on the following data:
										2013		2012
										$ million		$ million
Earnings for the purposes of basic and diluted earnings per share										104.1		207.0
										Number of shares (million)
										2013		2012
Weighted average number of ordinary shares for the purpose of basic earnings per share										328.2		330.2
Effect of dilutive potential ordinary shares - Share awards and options										0.8		0.7
Weighted average number of ordinary shares for the purpose of diluted earnings per share										329.0		330.9

 

7 Intangible assets

The Nganzi licence, onshore Democratic Republic of Congo, expired in 2013 and partners decided, following exhaustive studies, not to apply to extend the exploration period and relinquished the Block in the last quarter of 2013. As a result costs incurred on the Block in the amount of $92.0 million were written-off in the income statement in accordance with the Group's accounting policy on oil and gas exploration and evaluation expenditure.

 

8 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 31 December 2013 the fair value was $43.4 million (2012 - $42.1 million) after accounting for the change in fair value.

 

9 Convertible bonds

On 16 May 2013, the remaining convertible bonds, with a par value of $47.8 million, were purchased at par value and cancelled. Interest of 4.5% was paid semi-annually up to that date. The liability component of the bonds at December 2012 was $47.2 million following the repurchase of bonds with a par value of $0.9 million in 2012.

 

10 Distribution to Shareholders

During the year, the Company announced a return of value to shareholders of 40 pence per Ordinary Share amounting to £133 million ($213.3 million) in cash by way of a B and/or C share scheme, which gave shareholders (other than certain overseas shareholders) a choice between receiving cash in the form of income or in the form of capital. The return of value, which was approved by shareholders on 25 September 2013, became effective on 3 October 2013. The Board expects to again recommend a return of capital to shareholders in the third quarter of this year, thereby confirming the sustainability of our capital return policy. The pay out is targeted to equal 50% of 2013 free cash flow.

 

 

11 Reconciliation of operating profit to operating cash flows

							Group			Company
							2013	2012		2013		2012
							$ million	$ million		$ million		$ million
Operating profit (loss)							333.8	448.2		(11.4)		(10.4)
Share-based payments							1.4	1.1		1.4		1.1
Depletion and depreciation							44.8	45.3		0.2		0.1
Exploration write off							92.0	-		-		-
Operating cash flows before movements in working capital							472.0	494.6		(9.8)		(9.2)
Decrease (increase) in inventories							3.8	(0.9)		-		-
Decrease (increase) in receivables							8.6	(3.9)		(0.2)		-
(Decrease) increase in payables							(9.1)	2.5		(3.8)		2.2
Cash generated by (used in) operations							475.3	492.3		(13.8)		(7.0)
Interest received							1.1	1.0		0.1		-
Interest paid							(1.2)	(2.4)		-		-
Income taxes paid							(160.8)	(156.1)		-		-
Net cash from (used in) operating activities							314.4	334.8		(13.7)		(7.0)
Cash is generated from continuing operating activities only.
Cash and cash equivalents (which are presented as a single class of asset on the balance sheet) comprise cash at bank and other short term highly liquid investments that are readily convertible to a known amount of cash and which are subject to an insignificant risk of change in value.

 

12 Preliminary results announced

Copies of the announcement will be available from the Company's head office, situated at 48 Dover Street, London, W1S 4FF and is also available to download from www.socointernational.com. The Annual Report and Accounts will be posted to shareholders in due course.