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Soco International (SIA)

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Wednesday 06 March, 2019

Soco International

2018 PRELIMINARY RESULTS

RNS Number : 9543R
Soco International PLC
06 March 2019
 

 

 SOCO International plc

("SOCO" or the "Company" or, together with its subsidiaries, the "Group")

 

2018 PRELIMINARY RESULTS

SOCO International plc, an international oil and gas exploration and production company, announces its preliminary results for the year ended 31 December 2018.

 

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

In 2018 SOCO set out its vision to become a full cycle and growth orientated E&P company of scale. We made some significant steps towards achieving this in 2018, including the announcement and shareholder approval of the Merlon Petroleum El Fayum Company acquisition, putting in place SOCO's new debt facility and portfolio optimisation through the divestment of our West African position. A year of opportunities and achievements, but 2018 has also had its challenges, including operational issues and delays which impacted on production from Vietnam.  Upon completion, the Merlon acquisition will mark a significant turning point for SOCO, as we double our production, open up a whole new region of potential future opportunities and welcome key members of the Merlon team with a track record and proven ability to create value in Egypt. We look to deliver on increased production in Egypt and on our exploration plans in both Egypt and Vietnam.  We remain committed to creating value for our shareholders through a combination of capital growth and capital returns. I am pleased that the Board has decided to recommend a 2018 final dividend of 5.5p per share, a 5% increase on 2017.  In addition, we have repositioned SOCO to support further growth in the wider Middle East and North Africa region, both organically and through additional mergers and acquisitions.

2018 STRATEGIC HIGHLIGHTS

·      Shareholder approval of the Merlon transaction in Egypt with completion on track for 1H 2019 - the acquisition will;

Add proven and probable (2P) reserves of 24 million barrels and contingent (2C) resources of 37 million barrels

Complement and diversify SOCO's existing Vietnam-focused portfolio and create a new hub for our business in Egypt

Increase SOCO's through-cycle financial resilience through Merlon's low cost resource base

 

·      Reserve Base Lending Facility ("RBL") of $125m in place

·      Portfolio optimisation through divestment of non-core interests in Congo (Brazzaville) and Angola completed in line with the Company's strategy

2018 FINANCIAL HIGHLIGHTS

·      Strong and efficient balance sheet, RBL in place, solid cash flow and low cash operating costs:

Revenue of $175.1m (2017: $156.2m), an average realised crude oil price of $74/bbl (2017: $56/bbl), representing a premium to Brent of over $3/bbl

Low cash operating expenditure of $13.63/boe (2017: $13.73/boe) *

$55.9m of cash generated from continuing operations (2017: $45.0m)

 

·      Profit before tax ("PBT") of $80.1m (2017: $22.7m)

·      Recommended 2018 final dividend of 5.5 pence per Ordinary share (approx. $28.9m), an increase of 5%

Dividends paid to shareholders during 2018 of $23.3m (2017: $21.0m)

 

·      2018 cash capital expenditure of $22.4m from continuing activities (2017: $25.2m from continuing activities and $4.1m from discontinued activities), fully funded from existing cash resources

 

·      Year-end cash and liquid investment balance of $240.1m (2017: $137.7m), including the $100m draw down from the RBL, giving net cash of $140.1m   

 

*See Non-IFRS measures in page 27

2018 OPERATIONAL HIGHLIGHTS

·      Net production average of 7,274 boepd (2017: 8,276 boepd) in line with revised guidance - TGT production averaged 5,686 boepd (2017: 6,724 boepd) and CNV production averaged 1,588 boepd (2017: 1,552 boepd)

·      On Blocks 125 & 126 in Vietnam, bid packages for a 2D seismic acquisition programme have been agreed and issued targeting commencement in mid-2019

·      Successful extension of two key operational contracts, resulting in significant cost savings for the TGT Field: the FPSO Operations and Maintenance Agreement and the Bare Boat Charter for the FPSO Armada TGT 1

OUTLOOK FOR 2019

·      Production guidance, maintained at 6,500 to 7,500 boepd net

·      Completion of the acquisition of Merlon El Fayum is expected in H1 2019

·      2019 Vietnam capex guidance of approx. $34m fully funded from existing cash resources, to cover the development drilling and infrastructure upgrade on TGT and 2D seismic acquisition and processing for Blocks 125 & 126  

·      Optimise capital allocation providing shareholder return through dividends or acquisitions that can support value accretion and underpin a longer-term dividend stream.

ENQUIRIES:

SOCO International plc                                                                                                                                       Tel: 020 7747 2000

Ed Story, President and Chief Executive Officer             

Jann Brown, Managing Director and Chief Financial Officer

Mike Watts, Managing Director

Sharan Dhami, Group Investor Relations Manager

 

Camarco                                                                                                                                                                 Tel: 020 3757 4980

Billy Clegg/ Owen Roberts

NOTES TO EDITORS

SOCO is an international oil and gas exploration and production company, headquartered in London and traded on the London Stock Exchange.  The Company has a vision and strategy to become a full cycle and growth orientated E&P company of scale.

SOCO has production, development and exploration interests in Vietnam.

SOCO holds a 30.5% working interest in the Te Giac Trang Field of Block 16-1, which is operated by the Hoang Long Joint Operating Company. Block 16-1 is located in the shallow water Cuu Long Basin, offshore southern Vietnam.

SOCO holds a 25% working interest in the Ca Ngu Vang field of Block 9-2, which is operated by the Hoan Vu Joint Operating Company. Block 9-2 is located in the shallow water Cuu Long Basin, offshore southern Vietnam.

SOCO holds a 70% interest in and is designated operator of Blocks 125 & 126, located in the moderate to deep water Phu Khanh Basin, offshore central Vietnam.

Upon completion of the Merlon acquisition, the SOCO Group will acquire a 100% working interest in the onshore El Fayum concession in the Western Desert, Egypt, around 80km south west of Cairo. The concession includes ten development leases for oil fields operated by Petrosilah, an Egyptian joint stock company to be held 50 / 50 between the SOCO Group and the Egyptian General Petroleum Corporation. The acquisition will add proven and probable (2P) reserves of 24 million barrels and contingent (2C) resources of 37 million barrels.

 

 

Chair's Welcome

Repositioned for growth

Last year I reported that the Company had renewed its focus and commitment to the pursuit of growth opportunities, supported by the establishment of an experienced business development team. In September 2018, SOCO announced that it had signed a sale and purchase agreement for the acquisition of Merlon Petroleum El Fayum Company, which has onshore oil assets in Egypt. The transaction was approved by shareholders in December 2018 and is on track for completion in H1 2019. The proposed acquisition of Merlon complements and diversifies SOCO's existing Vietnam-focused portfolio, builds scale through doubling of our reserves and resources, increases SOCO's financial resilience through the low cost resource base and provides tangible production growth, re-setting SOCO's growth trajectory. This acquisition is a significant step forward for SOCO in our vision to become a full-cycle, growth orientated E&P company of scale. 

Safety remains the highest priority within the business and on the Board agenda. We are proud to report that SOCO's Joint Operations continue to achieve a high record of safety and have maintained commitment to local sourcing, employment, training and industry upskilling.  In Vietnam, we are pleased by HLHVJOCs' high level of safe operations, with zero LTIs in over 24 million man-hours worked since project inception, representing seven production years on TGT and ten production years on CNV. SOCO aims to have a positive presence in the countries where it operates. Our purpose is the responsible development of energy from natural resources for global economic prosperity and to deliver value for all our stakeholders.

SOCO is also committed to responsible and sustainable development, resulting in value for the host countries and local communities as well as for our staff and shareholders. In Vietnam, community projects are selected by HLHVJOC and during 2018, the HLHVJOC Charitable Donation programme focused on long term goals to assist in the development of poor rural areas especially in healthcare, education and assistance to flood victims.

Financial discipline

Capital discipline and financial stability have been SOCO hallmarks from inception and continue to underpin the business.  Capital investment and divestment decisions are taken to allocate capital where it will provide the best risk adjusted returns.  It is this approach that has allowed us to return significant amounts of capital to shareholders. SOCO continues to have a stable financial base. The balance sheet remained strong throughout 2018 and the Company had solid cash flows and low cash operating costs. To improve the efficiency of the balance sheet and provide financial flexibility, SOCO signed a $125m Reserved Base Lending facility ("RBL") secured against the Group's producing assets in Vietnam with a further $125m available on an uncommitted accordion basis. In December 2018 SOCO drew down $100m from the RBL facility.

The Group finished the year with $240.1m in cash, after returning $23.3m to shareholders through a 5.25 pence per share final dividend for the 2017 financial year and bringing the total return to shareholders since 2006 to $0.5 bn.

Prudent planning and risk management

Risk Management has always been a primary focus of the Board but, in these highly volatile commodity markets, we are giving the matter even more attention. Effective risk management is integral to SOCO achieving its corporate strategy to further strengthen the business through growth. In the 2018 Annual Report and Accounts, we set out our assessment of the principal risks facing the business and the mitigation measures we have adopted, whilst focusing on maintaining a business that remains robust and competitive.

 

Board engagement and changes

Olivier Barbaroux, a long standing non-executive director, retired from the Board of SOCO following conclusion of last year's AGM on 7 June 2018. SOCO would like to thank Olivier for his contribution to the Company and to wish him all the best for the future. On the same date, John Martin was appointed as an Independent non-executive director, Chair of the Audit and Risk Committee and a member of the Remuneration Committee and the Nominations Committee. John has more than 30 years' experience in international banking in the oil and gas industry.  Ambassador António Monteiro, non-executive director, will retire from the Board of SOCO at the conclusion of the Company's forthcoming AGM. SOCO would like to thank António for his service to the Company and wish him all the very best in his retirement. Marianne Daryabegui has been appointed as an Independent non-executive director with effect from 15 March 2019 and will also serve as a member of the Audit and Risk Committee, the Remuneration Committee and the Nominations Committee. Marianne has extensive experience in oil and gas corporate transactions and capital markets. Both John and Marianne bring a wealth of oil and gas experience and expertise which will complement and enhance the experience of the Board. Each of them will offer themselves for election by shareholders for the first time at the forthcoming AGM.

The Board looks to foster a genuine two-way dialogue between the Company and its stakeholders and welcomes the requirements of the 2018 Corporate Governance Code on engaging with the workforce and other stakeholders. In line with this John Martin has been appointed as the designated non-executive director for workforce engagement and we are hugely committed to this engagement and look forward to hearing the views of our employees.

Outlook and future opportunities

There is much for SOCO to look forward to in 2019 as the Company returns to growth. In Egypt, upon completion of the Merlon acquisition, we will seek to implement an increased drilling programme as we further develop the discovered resource base and test new exploration play concepts. In Vietnam we will look to pro-actively manage the production decline of TGT and CNV. On Blocks 125 & 126 2D seismic acquisition will commence mid-2019 in a new and exciting exploration basin. Upon completion of the Merlon acquisition and the implementation of the drilling programme in Egypt, our portfolio of Egyptian and Vietnam assets has the potential to offer one of the most competitive low operating cost production bases.

Since inception SOCO has been committed to shareholder value creation through the growth of the business and cash returns to shareholders. In line with this, the Board proposes a final dividend for 2018 of 5.5 pence per share.

We would like to thank our shareholders for their continued support. It is the firm belief of your Board, that with our competitive low-cost development projects, our strong financial stability, our culture of financial discipline and our talented and committed staff, SOCO is well placed to grow the business. The Board remains committed to delivering total shareholder returns through both dividends and capital growth. We continue to pursue new business opportunities where they are determined by the Board to be in the best interest of our shareholders.

 

Rui de Sousa

Chair

       
 

 

 

Chief Executive Officer's statement

A key step forward for SOCO this year was the proposed acquisition of Merlon Petroleum El Fayum Company, which has low-cost oil production assets in the prolific Western Desert region of Egypt, close to local energy infrastructure. The consideration will be satisfied through the payment of approximately US$136 million in cash and the issue of c.66 million new SOCO shares. The acquisition will add proven and probable (2P) reserves of 24 million barrels and contingent (2C) resources of 37 million barrels. In addition to providing a high quality oil concession with significant development upside and exploration optionality, Merlon creates a new hub for our business in Egypt. We plan to utilise this platform to support further growth not only in Egypt but also the wider Middle East and North Africa region, both organically and through additional mergers and acquisitions. We have a high regard for the business that Merlon has established in Egypt and look forward to working with our new colleagues.

SOCO's balance sheet remained strong throughout 2018 and the Company had solid cash flows and low cash operating costs. In September we announced that we had put in place a new RBL facility and we were pleased to have received such strong interest in the bank market and firm support from our new lenders. The facility provides balance sheet efficiency and financial flexibility.

The Group finished the year with cash balances of $240.1m, which includes the $100m drawn down from the RBL, after fully funding its operating and capital expenditure programmes and returning $23.3m to shareholders through a 5.25 pence per share dividend. Revenues were $175.1m. The average realised oil price per barrel achieved for the same period was approximately $74/bbl, representing a premium of over $3/bbl to Brent.

Operations in Vietnam were not without challenges in 2018 and production was affected by the late arrival of a drilling rig and equipment, operational issues and further weather related rig delays. In addition, gas compressor inefficiencies and the third-party production through the FPSO also had an impact on TGT's 2018 production performance. Actions are being taken to help mitigate the impact of these issues and delays, including acceleration of key workovers, upgrade of the gas compressors and optimised management of the third party FPSO throughput. Group production was 7,274 boepd (2017: 8,276 boepd) net to SOCO's working interest. Group 2018 year-end Vietnam commercial (2P) reserves are 23.0 mmboe (2017: 28.1 mmboe). TGT and CNV reserves were re-evaluated in February 2019 and revised following 2018 production from 25.4 mmboe to 23.0 mmboe. TGT reserves were revised downwards due to operational delays causing recovery of some production volumes to slip beyond the licence expiry date. CNV reserves were revised upwards following successful execution of the 2018 work programme, the impact of which had not been reflected in year end 2017 reported volumes. Production guidance for 2019 remains at 6,500-7,500 boepd.

Significant cost savings for the TGT field were secured in 2018, through the extension of two key operational contracts; the Bare Boat Charter for the FPSO Armada TGT 1, which applies to the period 27 August 2018 to 14 November 2024, and the revised FPSO Operations and Maintenance Agreement. Overall, these two contract extensions have resulted in significant operating cost savings of over US$40 million (gross and pre-tax) over the extension period relative to extension of the original contract with no changes.

In line with our strategy to optimise the SOCO portfolio, and our announced plans to exit from our West African positions, SOCO completed the sale of its former interests in Congo (Brazzaville) and in the Cabinda North Block, Angola in 2018. The combination of existing cash, the new credit facility and the cash flow from our producing assets in Vietnam ensures that we are funded to take advantage of acquisition opportunities in line with our strategy of creating a full-cycle exploration and production company with a diversified portfolio.   

During 2018, SOCO's focus has been to further strengthen the business through growth opportunities and to build scale, all the while underpinned by our relentless focus on financial discipline and shareholder return. These strong foundations have been built as a result of a great deal of hard work and I would like to thank all our staff for their effort and contribution to our achievements this year.

Upon completion, the Merlon acquisition will mark a significant turning point for SOCO, doubling its production and opening up a whole new region of potential future opportunities. We look to deliver on increased production in Egypt and on our exploration plans in both Egypt and Vietnam.  Activity in 2019 is expected to include implementing an increased drilling programme in Egypt as we further develop the discovered resource base and test new exploration play concepts. Our portfolio of Egyptian and Vietnam assets has the potential to offer one of the most competitive low operating cost production bases. In Vietnam we will look to pro-actively manage the production decline of TGT and CNV. On Blocks 125 & 126 2D seismic acquisition will commence mid 2019 in a new and exciting exploration basin.

We aim to build a business fostering and developing good relationships with host countries so that we are partner of choice. Safety will always be of the highest priority within the business and, just as SOCO's Joint Operations have achieved an outstanding record of safety in Vietnam, we will work to continue this success in Egypt. Our goal is to have a responsible and positive presence in the regions in which we operate, resulting in value for the host countries, local communities, employees, contractors and shareholders.

SOCO has always been committed to capital discipline and differentiates itself amongst its peers by having a consistently strong and efficient balance sheet, a portfolio of assets with a competitive low operating cost, steady cash flows, recurring cash dividends and a highly experienced management team with a demonstrable track record of creating and delivering value to shareholders. This year has sown the seeds of an important return to growth for the business and I am confident in the outlook for the Company.

Ed Story
President and Chief Executive Officer

 

REVIEW OF OPERATIONS

Vietnam

Blocks 16-1 and 9-2, which contain the TGT and CNV fields respectively, are located in shallow water in the hydrocarbon-rich Cuu Long Basin, near the Bach Ho field, the largest in the region with production already in excess of one billion barrels of oil equivalent. The Blocks are operated through non-profit Joint Operating companies in which each partner holds an interest equivalent to its share in the respective Petroleum Contract. The Group holds a 30.5% working interest in Block 16-1 and a 25% working interest in Block 9-2 and its partners in both blocks are PetroVietnam Exploration and Production, a subsidiary of the national oil company of Vietnam and PTTEP, the national oil company of Thailand.

 

Vietnam Production

Production in 2018 from the TGT and CNV fields net to the Group's working interest average was 7,274 boepd (2017: 8,276 boepd).  This is in line with the production guidance of 7,000 to 7,400 boepd given on 20 September 2018.  TGT 2018 production averaged 18,857 boepd gross and 5,686 boepd net to SOCO (2017: 22,300 boepd gross and 6,724 boepd net). CNV production averaged 6,352 boepd gross and 1,588 boepd net to SOCO (2017: 6,206 boepd gross and 1,552 boepd net).

 

The Group's Vietnam production guidance for 2019 remains 6,500-7,500 boepd. Actual production at the higher end of this range will depend on several operational factors, including the timing of the drilling, completion and hook-up of the two firm TGT wells in the approved 2019 work programme.  

 

The average realised crude oil price for 2018 was approximately $74 per bbl, a premium to Brent of over $3 per bbl.

 

Production by field

FY  2018

FY  2017

TGT Production

5,686

6,724

Oil 

5,346

6,299

Gas1

340

425

CNV Production

1,588

1,552

Oil

1,052

1,037

Gas1

536

515

Total Production

7,274

8,276

Oil

6,398

7,336

Gas1

876

940

Figures in boepd
Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.

Vietnam Development and Operations

 

Block 9-2 - CNV Field (25% interest; operated by HVJOC)

CNV production averaged 6,352 boepd gross and 1,588 boepd net to SOCO's working interest in 2018 (2017: 6,206 boepd gross and 1,552 boepd, respectively).

The CNV field is located in the western part of Block 9-2, offshore southern Vietnam and is operated by the HVJOC.  In contrast to the geology of TGT, the CNV field reservoir is fractured granitic Basement which produces a volatile oil with a high gas to oil ratio. Exploitation is dependent on the fracture interconnectivity to deplete the reservoir efficiently. Accordingly, traditional reservoir properties and STOIIP calculations are not straightforward but, managed properly, the fractured Basement reservoir declines at a much slower rate than commonly seen in clastic reservoirs. Hydrocarbons produced from CNV are transported via subsea pipeline to the BHCPP, where wet gas is separated from oil and transported via pipeline to an onshore gas facility for further distribution.  The crude oil is stored on a floating, storage and offloading vessel prior to sale, realising a premium to Brent.   

 

Production wells

The Japan Drilling Company Hakuryu-II jack-up rig drilled drilling the CNV-5PST3 side-track well, finishing in mid-October.  As a result of mechanical and operational difficulties completion of the well took longer than anticipated and consequently the excessive volume of sea-water losses in the fractured reservoir were beyond the original coiled tubing nitrogen lift specification. The water injection pipeline was subsequently converted to transport gas and lift operations commenced. Operations are now running normally with CNV-5PST3 and, although flowing naturally, the well continues to clean-up and oil flow may further improve as the well stabilises.  Following the well completion, the rig was moved to the TGT H5-WHP.

 

Block 16-1 - TGT Field (30.5% interest; operated by HLJOC)

TGT production averaged 18,857 boepd gross and 5,686 boepd net to SOCO's working interest in 2018 (2017: 22,300 boepd gross and 6,724 boepd net, respectively).

 

The TGT field is located in the north eastern part of Block 16-1, offshore southern Vietnam and is operated by the HLJOC.  The Block 16-1 petroleum contract was originally signed in December 1999, with the first commercial discovery made in 2005.  TGT is a simple structure, with a series of stacked producing intervals, extending over 16km and with hydrocarbons located in at least five major fault blocks.  The producing reservoirs comprise a complex series of over 80 clastic reservoir intervals of Miocene and Oligocene age.  Each interval requires individual reservoir management to optimise field recovery.  The TGT field continues to be a rewarding investment for SOCO, with its attractive fiscal terms, low operating costs and an oil quality which realises a premium to Brent.

 

The first platform, H1-WHP, came on stream in August 2011, followed by the H4-WHP in July 2012 and the H5-WHP in August 2015.  Crude oil from TGT is transported via subsea pipeline to the FPSO, where it is processed, stored and exported by tankers to regional oil refineries.  Gas produced from the field is exported by pipeline to the nearby Bach Ho facilities for processing and onward transportation to shore by pipeline to supply the Vietnamese domestic market.

 

Production wells

The PetroVietnam Drilling rig, PVD-1, successfully completed TGT-16AP and the rig was released in 3Q 2018.  

 

The Hakuryu-II jack-up rig arrived at the H5-WHP on 19 October 2018 and successfully drilled the TGT-14XST3 well. This well was a re-drill of the reservoir section of the H5 South prospect, to the south of the main H5 area.  The well operations were completed on 2 December 2018 and the rig was moved to the TGT-31P location.

 

The TGT-31P well was drilled through the main reservoir sections to total target depth on 16 January 2019 targeting the deeper high temperature, high pressure section below the main producing horizons at the H5-WHP.  The deep section encountered hydrocarbons in the D1 and E Oligocene targets. A single DST was conducted and oil flowed to surface under controlled conditions. Evaluation of this data to appraise the possible additional potential in the equivalent deeper sections of the wider TGT area is ongoing to establish if this new high pressure, high temperature play continues in the up-dip TGT fault blocks to the north.  

 

FPSO Contract

Significant cost savings for the TGT field were secured in 2018, through the extension of two key operational contracts; the Bare Boat Charter for the FPSO Armada TGT 1, which applies to the period 27 August 2018 to 14 November 2024, and the revised FPSO Operations and Maintenance Agreement. Overall, these two contract extensions have resulted in significant operating cost savings of over $40m (gross and pre-tax) over the contracts' extension period relative to extension of the original contract with no changes.

 

TGT Compressors and FPSO Tie-in Agreement (TIA)

As announced on 14 February 2019, tests to evaluate solutions for inefficiencies in the gas compressors have confirmed that the gas from a third party well was the main cause of the gas compressors suffering unplanned outages and delivering lower gas lift, which impacted on TGT oil production. Production from the third-party well is currently being managed to reduce the gas flare and the effect on TGT production. Upgrade work to the compressors is scheduled to begin Q4 2019. 

 

The existing TIA for the FPSO between the HLJOC and the third-party, the Thang Long Joint Operating Company (TLJOC), expired on 30 August 2018, and an interim agreement has been put in place while new terms for the third-party production are being negotiated. The interim agreement between the HLJOC and the TLJOC includes a cost sharing mechanism that has resulted in a reduction in operating costs to the HLJOC.

 

 

2019 Work Programme

On TGT, the 2019 work programme and budget was formally approved by the HLJOC on 22 January 2019.  The programme includes two firm and two contingent in-field wells, 18 well interventions and the upgrade of the gas compressors. Due to likely timing of the rig tendering process, the HLJOC anticipates that the wells in the approved 2019 TGT work programme will not be drilled before late 2019. 

VIETNAM EXPLORATION

Blocks 125 & 126 (70% interest, SOCO-operated)

Exploration Blocks 125 & 126 are in moderate to deep waters in the Phu Khanh Basin, north of the Cuu Long Basin, and multiple structural and stratigraphic plays are interpreted on the available 2D seismic data. There is good potential for source, expulsion and migration of oil in the basin with numerous reservoir and seal intervals likely.

 

Acquisition of new 2D seismic acquisition is targeted to commence mid-year 2019.

 

GROUP DIVESTMENTS

Marine XI Block, offshore Congo (Brazzaville) (40.39% working interest, SOCO-operated) and Cabinda North Block, onshore Angola (22% working interest, non-operated)

SOCO divested the Group's former interests in Congo (Brazzaville) on 25 June 2018 and the Company's former interests in the Cabinda North Block, Angola on 5 October 2018.

GROUP RESERVES AND CONTINGENT RESOURCES

In accordance with the requirements of its new Reserve Base Lending Facility announced on 17 September 2018, SOCO commissioned an independent audit of gross (100% field) reserves for TGT and CNV, as of 31 December 2018, by RISC Advisory Pty Ltd ("RISC"). The numbers in the table below are SOCO's revisions to Vietnam reserves, based on SOCO's unitised working interest of the gross reserves. The gross reserves have been independently agreed by RISC.

 

Table: TGT & CNV reserves net to SOCO

 

TGT

CNV

Total Vietnam

 

2P (mmboe) 1

2P (mmboe) 1

2P (mmboe)1

 

 

 

 

Opening Balance 1.1.18

23.1

5.0

28.1

2018 Production

(2.1)

(0.6)

(2.7)

 

 

 

 

Total after Production

21.0

4.4

25.4

 

 

 

 

Revision

(4.8)

2.4

(2.4) 

 

 

 

 

Closing Reserves 31.12.18

16.2 

 6.8

 23.0

 

Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.

 

On TGT, reserves were revised downwards due to operational delays causing recovery of some production volumes to slip beyond the licence expiry date.

 

On CNV, the reported reserves position at 31 December 2017 did not include the potential impact of the 2018 work programme, as this had not yet been approved by the Hoan Vu Joint Operating Company.  The execution of the 2018 work programme, although delayed, has resulted in successful production performance which has now been taken into account, resulting in an improvement in the field's reserves.

SOCO's acquisition of Merlon Petroleum El Fayum Company, anticipated to complete in H1 2019, is expected to add 24 mmbbl 2P reserves as at 30 June 2018, consistent with LR Senergy's CPR included in the Circular for the transaction.

 

 

 

 

SOCO Working Interest Reserves and Resources

TGT Field at 31 December 2018 (mmboe)

Reserves1

1P

2P

3P

Oil

11.6

15.3

19.5

Gas1

0.5

0.9

1.4

Total

12.1

16.2

20.9

Contingent Resources

1C

2C

3C

Oil

5.3

11.5

18.1

Gas1

0.2

0.7

1.2

Total

5.5

12.2

19.3

Sum of Reserves and Contingent Resources2

1P & 1C

2P & 2C

3P & 3C

Oil

16.9

26.8

37.6

Gas1

0.7

1.6

2.6

Total

17.6

28.4

40.2

 

 

 

 

1 Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.

2 The summation of Reserves and Contingent Resources has been prepared by the Company

 

SOCO Working Interest Reserves and Contingent Resources

CNV Field at 31 December 2018 (mmboe)

Reserves

1P

2P

3P

Oil

3.3

4.5

5.8

Gas1

1.6

2.3

2.9

Total

4.9

6.8

8.7

Contingent Resources

1C

2C

3C

Oil

1.1

2.8

4.5

Gas1

0.6

1.4

2.2

Total

1.7

4.2

6.7

Sum of Reserves and Contingent Resources2

1P & 1C

2P & 2C

3P & 3C

Oil

4.4

7.3

10.3

Gas1

2.2

3.7

5.1

Total

6.6

11.0

15.4

1 Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.

2 The summation of Reserves and Contingent Resources has been prepared by the Company.

 

New business

The period saw SOCO enter into the proposed acquisition of Merlon Energy. This marked a significant turning point for the Group, providing a high quality, oil concession with significant development upside and exploration optionality. The acquisition will create a new hub for SOCO in Egypt, which the Group will utilise to support further growth not only in Egypt but also the wider MENA region, both organically and through additional M&A.

 

The SOCO team has a track record of delivering shareholder value through asset acquisition and monetisation, delivering large scale developments, and returning capital to shareholders. We evaluate M&A opportunities by reference to our strategic, financial and operational criteria and only pursue transactions if they are determined by the Board to be in the best interest of shareholders. The Board continues to evaluate a number of opportunities in accordance with these criteria.

 

 

FINANCIAL REVIEW

FINANCE STRATEGY

Our finance strategy underpins the Group's business model and goes hand in hand with our commitment to building shareholder value through capital growth and dividends. 

 

The finance strategy is founded on three core areas- capital discipline, capital allocation and capital return.

 

During 2018, we generated operating cash flow from continuing operations of $55.9m (2017: $45.0m).  In addition, we entered into an RBL facility. The facility has been arranged and underwritten by BNP Paribas, Crédit Agricole Corporate and Investment Bank and Standard Chartered Bank. The RBL has $125m secured over the Vietnam assets, of which $100m was drawn in December 2018 to part fund the cash consideration element of the proposed Merlon El Fayum acquisition. The RBL facility also includes an uncommitted accordion feature of a further $125m, which can be activated by bringing new assets in to the borrowing base.

 

We have a low cost asset base and our operating cash flows plus the accordion feature of the RBL facility provide us with the financial flexibility and capacity to support the right projects and growth opportunities.

OPERATING PERFORMANCE

The Group continued to deliver robust revenue of $175.1m representing a 12% increase over the prior year (2017: $156.2m). The increase year on year is the result of the higher average realised crude oil price of $74.34/bbl (2017: $56.43/bbl), a $3/bbl premium to Brent, offset by the decline in production levels from 8,276 boepd to 7,274 boepd.

 

Cash operating costs decreased to $36.2m (2017: $41.5m), mainly as result of the improved terms of the extended FPSO and bareboat charter contracts. DD&A reduced to $51.8m (2017: $56.5m), largely as a function of the number of barrels produced.

 

Cash Operating Cost per Barrel*

2018

$m

2017

$m

Cost of sales

104.6

115.0

 

 

Depreciation, depletion and amortisation

(51.8)

(56.5)

Production based taxes

(15.1)

(13.6)

Inventories

(0.1)

(1.5)

Other cost of sales

(1.4)

(1.9)

Cash operating costs

36.2

41.5

 

 

 

Production (boepd)

7,274

8,276

 

 

 

Cash operating cost per boe ($)

13.63

13.73

 

 

 

DD&A per barrel*

2018

$m

2017

$m

Depreciation, depletion and amortisation

51.8

56.5

7,274

8,276

DD&A per boe ($)

19.51

18.72

 

*See Non-IFRS measures in page 27

 

Administrative expenses for the year totalled $28.4m (2017: $18.3m) and including $12.0m (2017: $4.7m) on new venture third party costs, reflecting the renewed effort on portfolio rationalisation and capturing new business.

 

During 2019, the underlying staff cost will reduce following an internal restructuring and streamlining of the Head Office function.

 

Operating profit from continuing operations, for the year, was $79.9m (2017: $22.9m), which included $37.8m reversal of the impairment charge in CNV.

Taxation

The tax expense for the year increased to $56.0m (2017: $27.7m) in line with profit and the impact of the reversal of the impairment charge ($13.9m). The Group's effective tax rate approximates to the statutory tax rate in Vietnam of 50%, after adjusting for non-deductible expenditure.

Profit post tax

Profit post tax for the period from continuing operations was $24.1m (2017: loss $5m). Following our sale of the interests in Congo (Brazzaville) and Angola, results from these assets have been classified as discontinued operations for all periods shown, with a resulting post-tax profit from discontinued operations of $3.6m (2017: loss $152.3m). This profit reflects the $5.0m of proceeds from the sale of Angola, which had a $nil carrying value following the impairment of the Exploration asset in prior years, offset by costs of exit from both these positions.

 

Cash Flow

Net cash flow from operations in Vietnam amounted to $55.9m (2017: $45.0m).

 

Net operating cash flow for the year (before working capital movements) was $96.7m (2017: $81.7m). Capital expenditure on continuing operations for the year was $22.4m (2017: $25.2m). This reduction year on year is in part due to deferral of acquisition of seismic data on Blocks 125 & 126 and delay of the TGT drilling programme into 2019.

 

Net cash flows from investing activities included a cash outflow from the disposal of a subsidiary Congo (Brazzaville) of $4.5m, to match the transfer of accrued liabilities, offset by a cash inflow for the sale of the Angolan assets of $5m.

 

A final dividend for the year of $23.3m (2017: $21.0m) was paid to shareholders in June 2018 following approval of a final dividend of 5.25p (2017: 5.00p) per share at the 2018 AGM.

Tax strategy and total tax contribution

Tax is managed proactively and responsibly with the goal of ensuring that the Group is compliant in all countries in which it holds interests. Any tax planning undertaken is commercially driven and within the spirit as well as the letter of the law. This approach forms an integral part of SOCO's sustainable business model.

 

The Group's Code of Business Conduct & Ethics seeks to build open, cooperative and constructive relationships with tax authorities and governmental bodies in all territories in which it operates. The Group supports greater transparency in tax reporting to build and maintain stakeholder trust. We have a number of overseas subsidiaries, set up some time ago and the Group is now proactively planning to bring these into the UK tax net to ensure greater transparency and comparability.  No additional taxes are expected to be due as a result of this exercise.

 

During 2018, the total payments to governments for the Group amounted to $202.4m, of which $196.5m or 97% was related to the Vietnam producing licence areas, of which $133.0m (2017: $117.8m) was for indirect taxes based on production entitlement. The breakdown of the other contributions, including payroll taxes and other taxes is contained within the additional information in the 2018 Annual Report & Accounts.

 

Balance Sheet

The $2.0m incurred on blocks 125 and 126 in Vietnam was booked to Intangible assets, which now stand at $5.8m (2017: $3.8m).

The movements in the Property, Plant and Equipment asset class are shown below:

 

 

2018

$m

As at 1 Jan 2018

505.9

Capital spend      

15.5

DD&A     

(52.0)

Reversal of impairment

37.8

As at 31 Dec 2018

 

In 2014 an impairment of the Group's CNV asset of $60.5m and associated $22.3m deferred tax was charged to the Income Statement. The 2018 upward revision in the 2P reserves of this asset has resulted in a reversal of the impairment of $37.8m in the period and $13.9m reversal of the tax asset.

 

Cash is set aside for abandonment on both TGT and CNV in the form of abandonment funds for each field. These abandonment funds are operated by PetroVietnam and, as the Group retains the legal rights to the funds pending commencement of abandonment operations, they are treated as other non-current assets in our financial statements.

 

Oil inventory was $4.1m at 31 December 2018 (2017: $4.2m). Trade and other receivables decreased to $19.6m (2017: $20.7m) largely due to the timing of crude oil cargos.

 

Cash and cash equivalents, including liquid investments, prior to the drawdown of $100 m from the RBL facility, were steady at $140.1m. (2017: $137.7m).  The drawdown is included in the balance sheet as cash.  There were no liquid investments at 31 December 2018 (2017: $25.3m) as these were moved to liquid investments of less than three months' maturity and so classified as Cash and cash equivalents.

 

Trade and other payables were almost flat at $22.9m (2017: $23.1m). Tax payable was $5.2m (2017: $6.8m)

 

Long term provisions comprise the Group's decommissioning obligations in Vietnam which has decreased from $52.7m at 2017 year-end to $51.7m at 2018 due to a decrease in the inflation rate used from 2.5% to 2%, offset by unwinding of the discount $1.4m.

Own Shares

The SOCO EBT holds ordinary shares of the Company for the purposes of satisfying long term incentive awards for senior management. During the year the EBT bought 1,139,861 shares at an average cost of £0.8712 per share.  Following this acquisition, the EBT held 2,897,094 (2017: 2,114,596) shares as at 31 December 2018, representing 0.85% (2017: 0.64%) of the issued share capital.

 

In addition, as at 31 December 2018, the Company held 9,122,268 (2017: 9,122,268) treasury shares, representing 2.67% (2017: 2.67%) of the issued share capital.

Going Concern

SOCO regularly monitors its business activities, financial position, cash flows and liquidity. Scenarios and sensitivities are included in the forecasts, including changes in commodity prices and in production levels from the existing assets in Vietnam and the proposed acquisition of Merlon El Fayum, plus other factors which could affect the Group's future performance and position.

 

These forecasts show that the Group will have sufficient financial headroom for the 12 months from the date of approval of the 2018 Accounts.  Based on this analysis, the directors have a reasonable expectation that that the Group has adequate resources to continue in operational existence for the foreseeable future.  Therefore, they continue to use the going concern basis of accounting in preparing the annual Financial Statements.

Annual dividend and company distributable reserves

SOCO remains committed to paying a dividend. During the year the Company paid a final dividend to shareholders in respect of the financial year ended 31 December 2017 of 5.25 pence per Ordinary Share (2017: 5 pence), at a cost to the company of $23.3m (2017: $21.0m).

 

The directors are recommending a final dividend of 5.5 pence per Ordinary Share, subject to approval at the AGM on 23 May 2019.

 

The distributable reserves of the parent company of the group amount to $269.9m (2017: $157.3m)

Financial OUTLOOK

SOCO's financial strength is founded on our long term approach to managing capital. 

Capital discipline focuses on controlling and managing costs. Capital investment and divestment decisions are taken to allocate capital where it will provide risk adjusted full cycle returns.  It is this approach that has allowed us to return significant amounts of capital to shareholders. We have looked to add another strand to the story - capital growth - to underpin the sustainability of the dividends over the longer term. This year we have made a first significant step towards this with the Merlon El Fayum acquisition and we will continue to look for growth opportunities in 2019 and beyond.

 

 

 

 

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF SOCO INTERNATIONAL PLC ON THE PRELIMINARY ANNOUNCEMENT OF SOCO INTERNATIONAL PLC

 

As the independent auditor of SOCO International plc we are required by UK Listing Rule LR 9.7A.1(2)R to agree to the publication of SOCO International plc's preliminary announcement statement of annual results for the year ended 31 December 2018.

The preliminary statement of annual results for the year ended 31 December 2018 includes the preliminary results, chair's and chief executive officer's statement, review of operations, financial review, the consolidated income statement, the consolidated statement of comprehensive income, the group and parent company balance sheets, the group and parent company statements of changes in equity, the group and parent company cash flow statements, the related notes 1 to 12, non-IFRS measures and the glossary of terms. We are not required to agree to the publication of the preliminary results presentation.

The directors of SOCO International plc are responsible for the preparation, presentation and publication of the preliminary statement of annual results in accordance with the UK Listing Rules.

We are responsible for agreeing to the publication of the preliminary statement of annual results, having regard to the Financial Reporting Council's Bulletin "The Auditor's Association with Preliminary Announcements made in accordance with UK Listing Rules".

Status of our audit of the financial statements

Our audit of the annual financial statements of SOCO International plc is complete and we signed our auditor's report on 5 March 2019. Our auditor's report is not modified and contains no emphasis of matter paragraph.

Our audit report on the full financial statements sets out the following key audit matters which had the greatest effect on our overall audit strategy; the allocation of resources in our audit; and directing the efforts of the engagement team, together with how our audit responded to those key audit matters and the key observations arising from our work:

Impairment and impairment reversal of Producing Oil & Gas Assets

Key audit matter description

The value of property, plant and equipment relating to the group's producing oil and gas assets as at 31 December 2018 was $506.9 million (2017: $505.4 million). This is considered a key audit matter due to the significant judgements and estimates involved in assessing whether any impairment, or impairment reversal, has arisen at year-end, and in quantifying any such impairments or reversals. Given the importance of producing assets to the group and the judgemental nature of the inputs used in determining the recoverable amounts, we also considered there to be a potential for fraud in this area.

 

Management reviewed both of its producing fields in Vietnam for indicators of impairment and impairment reversal. As a result of the movements in reserves estimates, Management identified an indicator of impairment for Te Giac Trang ('TGT') and an indicator of impairment reversal for Ca Ngu Vang ('CNV'). Management has estimated the fair values less costs of disposal of each field and compared these to the balance sheet carrying amount of each field on the balance sheet.

 

For TGT the recoverable value was above of the carrying amount and as such Management considered that no impairment was required. For CNV the recoverable amount was greater than the carrying amount and taking into account the key driving factor being the uplift in reserves, Management concluded it was appropriate for an impairment reversal of $37.8 million to be recognised. This impairment reversal represents the reversal in full of the prior impairment recorded on the CNV field.

 

Management's fair value estimates were based on key assumptions which for both fields included:

·      oil and gas prices;

·      reserves estimates and production profiles; and

·      the discount rate adopted, which remains consistent with the prior year at 10% for both fields.

 

In relation to reserves estimates Management has engaged a third party reservoir engineering expert to provide an independent report on the group's reserves estimates using standard industry reserve estimation methods and definitions for both the CNV and TGT fields. In addition, management has explained the scope of work of the third party expert and their findings in the review of operations, as well as highlighting oil and gas reserves as a key source of estimation uncertainty in note 4 to the financial statements.

 

The carrying value of property, plant and equipment is considered by management as a critical accounting judgement and key source of estimation uncertainty.

 

Further details of the key assumptions used by management in their impairment evaluation are provided in note 7 of the financial information.

 

 

How the scope of our audit responded to the key audit matter

 

For both the TGT and CNV assessments, we performed the following procedures;

·      we understood the basis for management's conclusion as to the existence or otherwise of impairment and impairment reversal triggers for TGT and CNV;

·      we compared oil and gas price assumptions with third party forecasts and publicly available forward curves;

·      we understood the process used by management to derive their reserves estimates and how they provide information to, and interact with, the third party expert;

·      we reviewed the third party expert's report on SOCO's reserves estimates as summarised in the review of operations and checked that these estimates were used consistently throughout the accounting calculations reflected in the financial statements

·      we communicated directly with the third party reserves experts to discuss and assess their scope of work, expertise and objectivity.

·      we used our internal valuation specialists to perform an independent recalculation of the discount rates used for both TGT and CNV;

·      we assessed management's other assumptions by reference to third party information, our knowledge of the group and industry and also budgeted and forecast performance;

·      we tested management's impairment calculations for mechanical accuracy;

·      we completed a scenario analysis for TGT and CNV, through which we conducted sensitivities for a range of input assumptions, including oil price and discount rates, and computed what we believed to be a reasonable range of recoverable amounts for CNV, and then compared the carrying value of CNV against this range; and

·      we considered whether management's disclosures relating to impairment and associated estimation uncertainty were adequate.

Key observations

 

We are satisfied that following the identification of impairment indicators on TGT an impairment test was appropriately performed and no impairment was required. .We note that the level of available headroom on TGT is low ($1 million) and have concluded that this is appropriately disclosed in the sensitivity disclosures provided within note 7.

 

 

In relation to CNV, following the identification of impairment reversal indicators we were satisfied that an impairment reversal test was appropriately performed resulting in an impairment reversal of $37.8 million.

 

Our work noted that assumptions regarding discount rates were below our assessment of benchmarks but that the oil prices used were also below the middle of the range of pricing that we view as appropriate.  Accordingly, as these matters offset, Management's combined assumptions in determining their recoverable value were within the reasonable range of assumptions.

 

These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we did not provide a separate opinion on these matters.

Procedures performed to agree to the preliminary announcement of annual results

In order to agree to the publication of the preliminary announcement of annual results of SOCO International plc we carried out the following procedures:

checked that the figures in the preliminary announcement covering the full year have been accurately extracted from the audited or draft financial statements and reflect the presentation to be adopted in the audited financial statements;

(a)  considered whether the information (including the management commentary) is consistent with other expected contents of the annual report;

(b)  considered whether the financial information in the preliminary announcement is misstated;

(c)  considered whether the preliminary announcement includes a statement by directors as required by section 435 of CA 2006 and whether the preliminary announcement includes the minimum information required by UKLA Listing Rule 9.7A.1;

(d)  where the preliminary announcement includes alternative performance measures ("APMs"), considered whether appropriate prominence is given to statutory financial information and whether:

·      the use, relevance and reliability of APMs has been explained;

·      the APMs used have been clearly defined, and have been given meaningful labels reflecting their content and basis of calculation;

·      the APMs have been reconciled to the most directly reconcilable line item, subtotal or total presented in the financial statements of the corresponding period; and

·      comparatives have been included, and where the basis of calculation has changed over time this is explained.

 

(e)  read the management commentary, any other narrative disclosures and considered whether they are fair, balanced and understandable.

Use of our report

Our liability for this report, and for our full audit report on the financial statements is to the company's members as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the company's members those matters we are required to state to them in an auditor's 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 and the company's members as a body, for our audit work, for our audit report or this report, or for the opinions we have formed.

 

 

Anthony Matthews FCA (Senior statutory auditor)

For and on behalf of Deloitte LLP

Statutory Auditor

London, United Kingdom

5 March 2019

 

 

 

 

 

cONSOLIDATED income statement

 

 

for the year to 31 December 2018

 

 

 

 

 

 

 

 

 

 

 

2018

2017

 

 

 

 

 

 

 

Notes

$ million

$ million

 

Continuing operations

 

 

 

 

 

 

 

Revenue

 

 

 

 

 

3

175.1

156.2

 

Cost of sales

 

 

 

 

4

(104.6)

(115.0)

 

Gross profit

 

 

 

 

 

70.5

             41.2

 

 

 

 

 

 

 

 

 

 

 

Administrative expenses

 

 

 

 

(28.4)

(18.3)

 

Reversal of impairment charge

 

 

 

7

37.8

-

 

Operating profit

 

 

 

 

79.9

      22.9

 

 

 

 

 

 

 

 

 

 

 

Investment revenue

 

 

 

 

 

2.7

             1.4

 

Finance costs

 

 

 

 

 

(2.5)

(1.6)

 

Profit before tax

 

 

 

 

3

80.1

        22.7

 

Tax

 

 

 

 

 

5

(56.0)

   (27.7)

 

Profit/(loss) for the period from continuing operations

 

24.1

         (5.0)

 

 

 

 

 

 

 

 

 

 

 

Discontinued operations

 

 

 

 

11

 

 

 

Profit/(loss) post-tax for the year from discontinued operations

 

3.6

(152.3)

 

 

 

 

 

 

 

 

 

 

 

Profit/(loss) for the year

 

27.7

(157.3)

 

 

 

 

 

 

Earnings/(loss) per share from continuing operations (cents)

6

 

 

 

Basic

 

 

 

 

 

7.3

 (1.5)

 

Diluted

 

 

 

 

 

7.0

(1.5)

 

 

 

 

 

 

 

 

 

 

 

Earnings/(loss) per share from continuing and discontinued operations (cents)

 

 

 

 

Basic

 

 

 

 

8.4

 (47.7)

 

Diluted

 

 

 

 

 

8.1

(47.7)

 

 

Consolidated statement of comprehensive income

 

 

 

 

 

 

 

 

 

 

for the year to 31 December 2018

 

 

 

 

 

 

 

 

 

 

 

 

2018

2017

 

 

 

 

 

 

 

 

$ million

$ million

 

 

 

 

 

 

 

 

 

 

 

Profit/(loss) for the year

 

 

 

 

27.7

(157.3)

 

Items that may be subsequently reclassified to profit or loss:

 

 

 

Unrealised currency translation differences

 

 

0.2

(0.4)

 

 

 

 

 

 

 

 

 

 

 

Total comprehensive profit/(loss) for the year

 

27.9

(157.7)

 

                       

 

The above condensed consolidated income statement and condensed consolidated statement of comprehensive income should be read in conjunction with the accompanying notes.
 

 

balance sheetS

 

 

 

 

 

As at 31 December 2018

 

 

 

 

 

 

 

 

 

 

 

 

Group

 

 

Company

 

 

 

 

 

 

 

2018

2017

 

2018

2017

 

 

 

 

 

 

 

$ million

$ million

 

$ million

$ million

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-current assets

 

 

 

 

 

 

 

 

 

 

Intangible assets

 

 

 

 

5.8

                 3.8

 

-

-

 

Property, plant and equipment

 

 

 

507.2

505.9

 

0.3

0.5

 

Investments

 

 

 

 

-

-

 

396.7

388.2

 

Other assets

 

 

 

 

40.6

 36.9

 

-

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

553.6

           546.6

 

397.0

388.7

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

 

 

 

Inventories

 

 

 

 

 

4.1

                 4.2

 

-

-

 

Trade and other receivables

 

 

 

19.6

     20.7

 

0.9

0.7

 

Tax receivables

 

 

 

 

0.6

        0.6

 

0.6

0.1

 

Liquid investments

 

 

 

 

-

  25.3

 

-

-

 

Cash and cash equivalents

 

 

 

240.1

   112.4

 

105.9

1.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

264.4

163.2

 

107.4

1.8

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

 

 

 

818.0

          709.8

 

504.4

390.5

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

 

 

 

Trade and other payables

 

 

 

(22.9)

(23.1)

 

(9.5)

(9.6)

 

Tax payables

 

(5.2)

(6.8)

 

(0.7)

(0.2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(28.1)

(29.9)

 

(10.2)

(9.8)

 

 

 

 

 

 

 

 

 

 

 

Net current assets (liabilities)

 

 

 

236.3

133.3

 

97.2

(8.0)

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-current liabilities

 

 

 

 

 

 

 

 

 

 

Deferred tax liabilities

 

 

 

 

(141.8)

(132.6)

 

-

-

 

Borrowings

 

 

 

 

(95.6)

-

 

-

-

 

Long term provisions

 

 

 

 

(51.7)

(52.7)

 

-

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(289.1)

(185.3)

 

-

-

 

 

 

 

 

 

 

 

 

 

 

 

 

Total liabilities

 

 

 

 

(317.2)

(215.2)

 

(10.2)

(9.8)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net assets

 

 

 

 

500.8

            494.6

 

494.2

380.7

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity

 

 

 

 

 

 

 

 

 

 

 

Share capital

 

 

 

 

27.6

               27.6

 

27.6

27.6

 

Other reserves

 

 

 

 

246.6

             245.9

 

196.7

195.8

 

Retained earnings

 

 

 

 

226.6

             221.1

 

269.9

157.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Total equity

 

 

 

 

500.8

             494.6

 

494.2

380.7

 

                               

 

The above condensed consolidated balance sheet should be read in conjunction with the accompanying notes.

 

STATEMENTs OF CHANGES IN EQUITY

for the year to 31 December 2018

 

 

 

 

 

Group

 

 

 

 

 

Called up share capital

Other reserves

Retained earnings

Total

 

 

 

 

 

$ million

$ million

$ million

$ million

As at 1 January 2017

 

 

 

        27.6

       243.8

        399.8

     671.2

 

 

 

 

 

 

 

 

Loss for the period

 

 

 

-

-

(157.3)

(157.3)

Unrealised currency translation differences

 

 

 

-

0.4

(0.4)

-

Distributions

 

 

 

-

-

(21.0)

(21.0)

Share-based payments

 

 

 

               -  

1.7

                -  

1.7

 

 

 

 

 

 

 

 

As at 1 January 2018

 

 

 

      27.6

245.9

221.1

494.6

 

 

 

 

 

 

 

 

 

Profit for the period

 

-

-

27.7

27.7

Unrealised currency translation differences

 

-

(1.4)

0.2

(1.2)

Distributions

 

-

-

(23.3)

(23.3)

Share-based payments

 

-

3.0

-

3.0

Transfer relating to share-based payments

 

-

(0.9)

0.9

-

 

 

 

 

 

 

 

 

As at 31 December 2018

 

 

27.6

246.6

226.6

500.8

 

 

 

 

 

 

 

 

 

Company

 

 

 

 

 

Called up share capital

Other reserves

Retained earnings

Total

 

 

 

 

 

$ million

$ million

$ million

$ million

As at 1 January 2017

 

 

 

        27.6

       194.5

303.9

526.0

 

 

 

 

 

 

 

 

Loss for the period

 

 

 

-

-

(176.6)

(176.6)

Unrealised currency translation differences

 

 

 

-

0.4

51.0

51.4

Distributions

 

 

 

-

-

(21.0)

(21.0)

Share-based payments

 

 

 

               -  

1.7

                -  

1.7

Transfer relating to share-based payments

 

 

 

-

(0.8)

-

(0.8)

 

 

 

 

 

 

 

 

As at 1 January 2018

 

 

 

      27.6

195.8

157.3

380.7

 

 

 

 

 

 

 

 

 

Profit for the period

 

-

-

159.9

159.9

Unrealised currency translation differences

 

-

(1.4)

(24.8)

(26.2)

Distributions

 

-

-

(23.3)

(23.3)

Share-based payments

 

-

3.0

-

3.0

Transfer relating to share-based payments

 

-

(0.7)

0.8

0.1

 

 

 

 

 

 

 

 

As at 31 December 2018

 

 

27.6

196.7

269.9

494.2

The above statements of changes in equity should be read in conjunction with the accompanying notes.

 

 

 

 

cash flows statements

for the year to 31 December 2018

 

 

 

 

 

 

 

 

 

 

 

Group

 

 

Company

 

 

 

 

 

 

2018

2017

 

2018

2017

 

 

 

 

 

Notes

$ million

$ million

 

$ million

$ million

 

 

 

 

 

 

 

 

 

 

 

 

Net cash from (used in) continuing operating activities

 

55.9

45.0

 

(23.2)

(12.9)

 

Net cash used in discontinuing operating activities

 

(1.7)

-

 

-

-

 

Net cash from (used in) operating activities

10

54.2

        45.0

 

(23.2)

(12.9)

 

 

 

 

 

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

 

 

 

 

Purchase of intangible assets

 

 

(2.4)

(1.3)

 

-

-

 

Purchase of property, plant and equipment

 

(16.6)

(20.8)

 

(0.1)

(0.1)

 

Decrease (increase) in liquid investments 1

 

 

25.3

       (10.0)

 

-

-

 

Payment to abandonment fund

 

 

(3.4)

(3.1)

 

-

-

 

Deferred proceeds on disposal of Mongolia assets

 

 

-

42.7

 

-

-

 

Investment in subsidiary undertaking

 

 

-

-

 

(33.4)

(3.1)

 

Dividends received from subsidiary undertaking

 

 

-

-

 

187.0

37.6

 

 

 

 

 

 

 

 

 

 

 

 

Net cash from continuing investing activities

 

2.9

7.5

 

153.5

34.4

 

Net cash from (used in) discontinuing investing activities

 

0.5

(4.1)

 

-

-

 

Net cash from investing activities

 

3.4

3.4

 

153.5

34.4

 

 

 

 

 

 

 

 

 

 

 

 

Financing activities

 

 

 

 

 

 

 

 

 

Net proceeds from borrowings

 

 

 

95.6

-

 

-

-

 

Proceeds from exercise of share options

 

-

(0.3)

 

(1.2)

(0.3)

 

Purchase of own shares into treasury

 

(1.3)

-

 

-

-

 

Dividends paid to Company shareholders

 

 

(23.3)

(21.0)

 

(23.3)

(21.0)

 

 

 

 

 

 

 

 

 

 

 

 

Net cash from (used in) continuing financing activities

 

71.0

(21.3)

 

(24.5)

(21.3)

 

Net cash from (used in) financing activities

 

71.0

(21.3)

 

(24.5)

(21.3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

128.6

27.1

 

105.8

0.2

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at beginning of year

 

112.4

      85.0

 

1.0

0.5

 

 

 

 

 

 

 

 

 

 

 

 

Effect of foreign exchange rate changes

 

(0.9)

0.3

 

(0.9)

0.3

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents at end of year 1

 

240.1

       112.4

 

105.9

1.0

 

 

 

 

 

 

 

 

 

 

 

 

                                   

1 Liquid investments comprise short term liquid investments of between three to six month's maturity while cash and cash equivalents comprise cash at bank and other short term highly liquid investments of less than three month's maturity that are readily convertible to a known amount of cash and which are subject to an insignificant risk of change in value.  The combined cash and cash equivalents and liquid investments balance at 31 December 2017 was $137.7m. No Liquid investments were held as of 31 December 2018.  

 

The above condensed consolidated cash flow statement should be read in conjunction with the accompanying notes.
 

Notes to the condensed consolidated financial statements

1.     General information

The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2018 or 2017, but is derived from those accounts. A copy of the statutory accounts for 2017 has been delivered to the Registrar of Companies and those for 2018 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.     Significant accounting policies

(a)   Basis of preparation

The financial information has been prepared in accordance with the recognition and measurement criteria of 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 comfortably 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.

(b)   New and amended standards adopted by SOCO

SOCO Adopted IFRS 9: Financial Instruments and IFRS 15: Revenue from Contracts with Customers on 1 January 2018. These pronouncements have been endorsed by the European Union ('EU').

SOCO has not early adopted any amendments, standards or interpretations that have been issued but are not yet effective.

IFRS 9 Financial Instruments

On 1 January 2018, SOCO adopted IFRS 9 'Financial Instruments' which replaced IAS 39 'Financial Instruments: Recognition and Measurement' and includes requirements for classification and measurement of financial assets and financial liabilities, impairment of financial assets and hedge accounting.

The adoption of IFRS 9 has had immaterial quantitative effect on the consolidated financial statements of the Group and the separate financial statements of SOCO International Plc.

IFRS 15 Revenue from Contracts with Customers

On 1 January 2018, SOCO adopted IFRS 15 'Revenue from Contracts with Customers', which replaced IAS 18 'Revenue'.

The adoption of IFRS 15 has had no material quantitative effect on the consolidated financial statements of the Group and the separate financial statements of SOCO International Plc.

(c)    New standards and interpretations not yet adopted

At the date of authorisation of these financial statements, the following IFRS's and IAS's, which have not been applied in these financial statements, were in issue but not yet effective (and in some cases had not yet been adopted by the EU):

 

IFRS 16 Leases

In January 2016, the IASB issued IFRS 16 'Leases' which the Group will adopt for periods beginning on or after 1 January 2019. The adoption of IFRS 16 will impact both the measurement and disclosures of leases over a value threshold and with terms longer than one year. The lease expense recognition pattern for lessees will generally be accelerated. Additional lease liabilities and right of use assets are expected to be recorded. The cash flow statement will be affected as payments for the principal portion of the lease liability will be presented within financing, not operating, activities.

The Group has set up a project team which has reviewed all of the Group's leasing arrangements over the last year in light of the new lease accounting rules in IFRS 16. The standard will affect primarily the accounting for the Group's operating leases.

The Group will apply the standard from its mandatory adoption date of 1 January 2019. The Group intends to apply the simplified transaction approach and will not restate comparative amounts for the year prior to first adoption. Right-of-use assets will be measured at the amount of the lease liability on adoption (adjusted for any prepaid or accrued lease expenses).

The Group does not currently intend to bring short term leases (12 months or fewer to run as at 1 January 2019, including reasonably certain options to extend) or low value leases on balance sheet. Costs for these items will continue to be expensed directly to the income statement.

The critical judgemental matter for the Group with regard to the application of IFRS 16 is the treatment of its share in the bare boat charter of the FPSO leased by HLJOC. The FPSO facilities are also shared with a third party. We note that there are ongoing IFRIC discussions on IFRS 11 'Joint Arrangements' that may have a bearing on the Group's future recognition of lease costs under IFRS 16. With those discussions ongoing, we are currently taking the conservative view that the Group should disclose its share of the FPSO as a lease and will revisit the issue at the time of our 2019 interim reporting.

Accordingly, as at 1 January 2019, the Group reports that it has non-cancellable operating lease commitments of $55.9m. $54.0m of which relates to the FPSO facilities, and the remainder to office properties.

Based on the initial analysis presented above for lease commitments the Group expects to recognise right-of use assets of approximately $47.3m on 1 January 2019 and a matching lease liability. Overall net current assets will be $7.3m lower due to the presentation of a portion of the liability as a current liability.

The Group expects that the net profit after tax will decrease by approximately $0.8m for 2019 as a result of adopting the new rules.

There are no other standards that are not yet effective and that would be expected to have a material impact on the Group in the current or future reporting periods nor on foreseeable future transactions.

3.     Segment information

The Group has one principal business activity being oil and gas exploration and production. The Group's continuing operations are located in South East Asia. Africa has been classified as a discontinued operation for all years shown, as the Group disposed of all of its interests in that geographical area. There are no inter-segment sales. South East Asia and Africa form the basis on which the Group reports its segment information. Segment results are presented below:

 

 

 

2018

 

 

 

 

 

 

 

SE Asia

 

 Africa

 

Unallocated

 

Group

 

 

 

 

 

 

 

$ million

 

$ million

 

$ million

 

$ million

Oil and gas sales

 

 

 

 

175.1

 

-

 

-

 

175.1

Depreciation, depletion and amortisation

51.8

 

-

 

0.3

 

52.1

Reversal of impairment charge (see Note 7)

37.8

 

-

 

-

 

37.8

Profit (loss) before tax from continuing operations1

107.7

 

-

 

(27.6)

 

80.1

Profit post-tax from discontinued operations

-

 

3.6

 

-

 

3.6

Tax charge (see Note 5)

56.0

 

-

 

-

 

56.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017

 

 

 

 

 

 

 

SE Asia

 

 Africa

 

Unallocated

 

Group

 

 

 

 

 

 

 

$ million

 

$ million

 

$ million

 

$ million

Oil and gas sales

 

 

 

 

               156.2

 

-  

 

                    -  

 

156.2

Depreciation, depletion and amortisation

 

56.5

 

-

 

0.3

 

56.8

Reversal of impairment charge

 

-

 

-

 

-

 

-

Profit (loss) before tax from continuing operations1

39.9

 

-

 

(17.2)

 

22.7

Profit post-tax from discontinued operations

 

-

 

(152.3)

 

-

 

(152.3)

Tax charge (see Note 5)

27.7

 

-

 

-

 

27.7

 

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 As of December 2018, Africa operations had been disposed.

3 In December 2017, an impairment indicator of IFRS 6 was triggered following the Group's announcement that no substantive expenditure for the Africa assets was either budgeted or planned in the near future. The remaining costs capitalised associated with exploration areas in Africa of $152.3m was therefore fully impaired in the income statement.

Included in revenues arising from South East Asia are revenues of $129.1m and $35.0m which arose from the Group's two largest customers who contributed more than 10% to the Group's oil and gas revenue (2017: $102.9m and $21.1m from the Group's two largest customers).

Geographical information

The Group's oil and gas revenue and non-current assets (excluding 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 oil and gas revenue is derived from foreign countries. The Group's oil and gas revenue by geographical location is determined by reference to the final destination of oil or gas sold.

 

 

 

 

 

 

 

 

2018

 

 

2017

 

Revenue

 

 

 

$ million

 

 

$ million

Vietnam

 

 

 

 

 

131.8

 

 

105.7

 

Thailand

 

 

 

 

26.1

 

 

                   36.3

 

Other

 

 

 

 

17.2

 

 

14.2

 

 

 

 

 

 

175.1

 

 

               156.2

 

 

 

 

 

 

 

 

 

 

 

 

2018

 

 

2017

Non-current assets

 

 

 

$ million

 

 

$ million

United Kingdom

 

 

 

 

 

0.2

 

 

0.4

Vietnam

 

 

 

 

512.8

 

 

                   509.3

 

 

 

 

 

513.0

 

 

               509.7

                                                 

Excludes other receivables.

4.     Cost of sales

 

 

 

 

 

 

 

 

2018

 

 

2017

 

 

 

 

$ million

 

 

$ million

Depreciation, depletion and amortisation

51.8

 

 

56.5

Production based taxes

 

 

 

 

 

15.1

 

 

13.6

Production operating costs

 

 

 

 

 

37.6

 

 

43.4

Inventories

 

 

 

 

 

0.1

 

 

1.5

 

 

 

 

 

104.6

 

 

115.0

                           

5.     Tax

 

 

 

 

 

 

 

 

2018

 

 

2017

 

 

 

 

$ million

 

 

$ million

Current tax

 

 

 

 

 

46.8

 

 

42.1

Deferred tax

 

 

 

 

9.2

 

 

(14.4)

 

 

 

 

 

56.0

 

 

               27.7

                           

The Group's corporation tax is calculated at 50% (2017: 50%) of the estimated assessable profit for each period in Vietnam. During 2018 and 2017, both current and deferred taxation have arisen in overseas jurisdictions only. 

 

 

 

 

 

 

 

 

2018

 

 

2017

 

 

 

 

$ million

 

 

$ million

Profit / (loss) before tax

 

 

 

 

 

83.7

 

 

(129.6)

 

 

 

 

 

 

 

 

 

 

Profit / (loss) before tax at 50% (2017: 50%)

 

 

41.9

 

 

(64.8)

 

 

 

 

 

 

 

 

 

 

Effects of:

 

 

 

 

 

 

 

 

 

Non-deductible expenses

 

 

 

 

 

4.5

 

 

10.1

Tax losses not recognised

 

 

 

 

 

8.5

 

 

6.2

Non-deductible exploration costs written off/(back)

1.1

 

 

76.2

 

 

 

 

 

56.0

 

 

               27.7

                           

 

The prevailing tax rate in Vietnam, where the Group produces oil and gas is 50%. The tax charge in future periods may also be affected by the factors in the reconciliation above.

Non-deductible expenses, net of the effect of the CNV reversal of impairment charge of $5.0m, primarily relate to Vietnam DD&A charges for costs previously capitalised, which are non-deductible for Vietnamese tax purposes of $6.7m (2017: $6.9m). A further $2.8m (2017: $3.2m) relates to non-deductible corporate costs including share scheme incentives.

The effect from tax losses not recognised relates to costs, primarily of the Company, deductible for tax in the UK but not expected to be utilised in the foreseeable future.

The effect of non-deductible exploration costs written off of $76.2m in 2017 relates to the impairment of exploration assets in Africa.

 

6.     Earnings/(loss) per share

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

 

 

 

 

 

 

 

 

 

 

 

Group

 

 

 

 

 

 

 

 

 2018

 

2017

Profit/(loss) for the purposes of basic earnings/(loss) per share

27.7

 

            (157.3)

Effect of dilutive potential ordinary shares - Cash settled awards and options

(0.7)

 

                   (0.7)

Profit/(loss) for the purpose of diluted earnings/(loss) per share

27.0

 

(158.0)

 

 

 

 

 

 

 

 

 

 

 

Group

 

 

 

 

 

 

 

 

 2018

 

2017

Profit/(loss) from continuing operations for the purposes of basic earnings/(loss) per share

24.1

 

            (5.0)

Effect of dilutive potential ordinary shares - Cash settled awards and options

(0.7)

 

                   (0.7)

Profit/(loss) from continuing operations for the purpose of diluted earnings/(loss) per share

23.4

 

(5.7)

 

 

 

 

 

 

 

 

 

 

Number of shares (million)

 

 

 

 

 

 

 

 

2018

 

2017

Weighted average number of ordinary shares

329.8

 

329.8

Effect of dilutive potential ordinary shares - Share awards and options

4.6

 

                   3.6

Weighted average number of ordinary shares for the purpose of diluted earnings/(loss) per share

334.4

 

           333.4

In accordance with IAS 33 "Earnings per Share", the effects of antidilutive potential shares have not been included when calculating dilutive loss per share for the year ended 31 December 2018 or the prior year.

7.     Property, plant and equipment

The SOCO working interest in proved and probable oil and gas reserves, audited by RISC Advisory Pty Ltd, show a decrease of 4.8 MMBOE to 2P reserves numbers for TGT and an increase of 2.4MMBOE to 2P reserves numbers for CNV.

This downward revision triggered an impairment test on the Group's TGT asset in Vietnam. The recoverable amount of the TGT producing asset has been determined using the fair value less costs of disposal method which constitutes a level 3 valuation within the fair value hierarchy. The net book value is supported by the fair value derived from a discounted cash flow valuation of the 2P production profile. The key assumptions to which the fair value measurement is most sensitive are oil price, discount rate and 2P reserves (2017: oil price, discount rate and 2P reserves). In 2018, the post-tax nominal discount rate has been maintained at 10% as there has been no change in the technical confidence in the reservoir. As at 31 December 2018, the fair value of the asset is estimated based on a post-tax nominal discount rate of 10.0% (2017 10%) and an oil price of $63.8/bbl in 2019, $66.3/bbl in 2020, plus inflation of 2.0% thereafter (2017: an oil price reflecting a gradual increase over five years from $61/bbl in 2018 to $72 in 2022 plus inflation of 2% thereafter).

 

In 2014 an impairment of the Group's CNV asset of $60.5m and associated $22.3m deferred tax was charged to the Income Statement. The 2018 upward revision in the 2P reserves of this asset has resulted in a reversal of the impairment of $37.8m in the period and $13.9m reversal of the tax asset. The recoverable amount of the CNV producing asset has been determined using the fair value less costs of disposal method which constitutes a level 3 valuation within the fair value hierarchy.

Testing of sensitivity cases indicated that a $5/bbl reduction in the long term oil price used when determining the fair value less costs of disposal method would result in a post-tax impairment of the TGT asset of $27m and a reduction in the post-tax reversal of impairment of $5m of the CNV asset and a 1% increase in the discount rate would result in a post-tax impairment of $7m for the TGT asset and a reduction in the post-tax reversal of impairment of $0.6m of the CNV asset.

Other fixed assets comprise office fixtures and fittings and computer equipment.

8.     Borrowings

On September 2018, the Group signed a new $125m Reserve Base Lending Facility ('RBL') secured against the Group's producing assets in Vietnam. In addition to the committed $125m, a further $125m is available on an uncommitted accordion basis. The RBL has a five-year term and matures in September 2023. On 17 December 2018 $100m was drawn down against this facility and the proceeds of which are recorded as cash and cash equivalents as at 31 December 2018 in readiness of funding the Merlon acquisition.

9.     Distribution to Shareholders

In June 2018, the Company paid dividends to shareholders of $23.3m (2017: $21.0m) or 5.25 pence per Ordinary Share (2017: 5 pence per Ordinary Share).

The SOCO EBT, which is consolidated within the Group, waived its rights to receive a dividend in 2018 and 2017.

The Board is recommending a final dividend of 5.5 pence per Ordinary Share, which amounts to approximately $28.9m, assuming that the SOCO EBT waives its entitlement to dividends in respect of its holding of Ordinary Shares. The proposed final dividend is subject to approval by shareholders at the Annual General Meeting and has not been included as a liability in these Financial Statements. The proposed dividend, if approved by shareholders, will be paid on 31 May 2019 to shareholders on the register of members at the close of business on 10 May 2019 (the "Dividend Record Date". If the acquisition of Merlon El Fayum Petroleum Company (the "MPEFC Acquisition") has completed by the Dividend Record Date, the proposed dividend will be paid on the 65,561,041 consideration shares in the normal manner. If the MPEFC Acquisition has not completed by the Dividend Record Date, the payment of the proposed dividend will be treated as an adjustment event under the sale and purchase agreement relating to the MPEFC Acquisition, resulting in an increase in the cash consideration payable by the Company by such amount as is required to put the seller in the same economic position as it would have been had the dividend not been paid.

10.  Reconciliation of operating profit to operating cash flows

 

 

 

 

 

 

 

 

 

Group

 

Company

 

 

 

 

 

 

 

 

 

2018

2017

 

2018

2017

 

 

 

 

 

 

 

 

 

$ million

$ million

 

$ million

$ million

Operating profit/(loss)

 

 

 

 

 

79.9

22.9

 

(26.7)

(18.0)

Share-based payments

 

 

 

 

2.5

2.0

 

2.5

2.0

Depreciation, depletion and amortisation

 

 

 

52.1

56.8

 

0.3

0.3

Reversal of impairment charge

 

 

 

(37.8)

-

 

-

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating cash flows before movements in working capital

 

96.7

81.7

 

(23.9)

(15.7)

Decrease in inventories

 

 

 

0.1

1.5

 

-

-

Decrease/(increase) in receivables

 

 

 

 

1.2

4.4

 

(0.7)

0.4

Increase in payables

 

 

 

3.4

0.2

 

1.4

2.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash generated by (used in) operations

 

 

 

101.4

87.8

 

(23.2)

(12.9)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest received

 

 

 

 

 

2.6

1.4

 

-

-

Interest paid

 

 

 

 

(0.1)

-

 

-

-

Income taxes paid

 

 

 

 

(48.0)

(44.2)

 

-

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash from (used in) continuing operating activities

 

55.9

45.0

 

(23.2)

(12.9)

Net cash used in discontinuing operating activities

 

 

(1.7)

-

 

-

-

Net cash from (used in) operating activities

 

 

 

54.2

45.0

 

(23.2)

(12.9)

 

11.  Disposal of Africa interest

Disposal of Congo interest

On 24th June 2018, SOCO signed and completed a Sale and Purchase Agreement (the SPA) with Coastal Energy Congo Limited (Coastal Energy), to sell its entire shareholding in SOCO Congo Limited (SOCO Congo), which holds the Group's appraisal interests in Congo (Brazzaville). Under the terms of the Agreement the Group is entitled to receive a cash consideration of up to $10m plus subsequent payments based on future oil and condensate production sold from those interests in Congo (royalty). The cash consideration of up to $10m payable under the SPA is structured as follows:

·      Tranche 1: $1m within 10 business days on the later to occur of: i. agreement or expert determination of a statement of net assets or liabilities of SOCO Congo and its subsidiary as at 30 June 2018 (the 30 June Statement); and ii. execution of the first agreement relating to the bonus payable in respect of any of the four exploitation permits (the "PEX bonus agreement");

·      Tranche 2: $5m within 10 business days of formal approval of the first development plan on any of the exploitation permits; and

·      Tranche 3: $4m within 20 business days on the earlier to occur of: i. first commercial production of oil or condensate from any of the exploitation permits; and ii. 31 December 2019.

Each element of the cash consideration is subject to potential adjustment by reference to the 30 June 2018 Statement.

In addition, SOCO will retain the right to an overriding royalty interest on all barrels of oil or condensate produced and sold from any of the four exploitation permits. The royalty payable on each barrel of oil or condensate produced and sold will be determined by reference to the prevailing price of North Sea Dated Brent (the Benchmark Price), as summarised below:

·      $0.50 on each barrel where the Benchmark Price is at or under $52.25 per barrel; or

·      $1.00 on each barrel where the Benchmark Price is over $52.25 per barrel.

The fair value of the above consideration (including the overriding royalty) at 31 December 2018 was estimated at $0.49m. The fair value of the consideration will be reassessed at each balance sheet date, with movements recorded in the income statement. The fair value of this financial asset is included in current and non-current assets at $0.18m and $0.31m respectively. It 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 13 'Fair Value Measurement'). To arrive at the estimated fair value, we have applied a discount rate and a probability of success for each of the four elements set out above. The discount rate is 12% and represents a rate which reflects the time value of money, country risk and the credit risk of Coastal Energy group. The probability of success, being the probability that the conditions relating to each element of consideration are both met and enforceable, ranges from 20% for Tranche 1 to 2% for Tranches 2 and 3, with the figures reflecting the high estimation uncertainty due to the short time which has elapsed since completion, as well as the requirement for the PEX bonus criteria to be met (Tranche 1) before it is possible to comply with the criteria in respect of the remaining elements of the consideration.

In determining the fair value of the royalty, the key inputs include the probability of future oil prices being above $52.25 per barrel as well as estimated future production, as well as a 2% probability of commercial production being achieved. A summary of the fair values attributed to each element of the consideration at 31 December 2018 is outlined below.

 

 

 

 

 

 

 

 

 

 

 

 

 

List of four elements of consideration

 

 

 

Undiscounted/ unrisked value

 

Discounted risked value

Tranche 1 - PEX bonus agreement signed

$1m

 

$0.8m

Tranche 2 - first development plan approval

$5m

 

$0.08m

Tranche 3 - first commercial production

$4m

 

$0.06m

Overriding royalty interest

 

 

 

 

 

 

$0.17m

Total

 

 

 

 

 

 

               $0.49m

The fair value of the consideration is most sensitive to changes in the probability of success applied to each element, with the key triggering events considered to represent the PEX bonus signature and, following on from this, the approval of the first development plan. A change in the discount rate by 1% would increase/decrease the fair value by $0.01 million. The fair value will be retested at each reporting date.

As the Group's Congo asset is now classified as part of the Group's discontinued Africa operations, the profit and loss attributable to the Congo interest up to the date of completion have been removed from continuing operations.

For the first half of 2018, the Congo Brazzaville interest, generated an operating and post-tax loss of $1.5m (full year 2017: $104m). No revenue arose for any of the years. Immediately prior to the sale the Group's share of net assets held by the Congo interest was $0.34m comprising current assets of $0.69m, cash of $4.5m and current liabilities of $4.85m. Immediately after completion of the sale the Group recognised a gain on disposal of $0.15m based on the fair value of the financial asset of $0.49m.

Disposal of Angola interest

On 29th June 2018, SOCO Exploration Limited entered into a Sale and Purchase Agreement (the SPA) with Quill Trading Corporation and WMLC Resources Limited to sell its entire shareholding in SOCO Cabinda Limited (SOCO Cabinda), for a total cash consideration of up to $5m. SOCO Cabinda holds the Group's exploration interest in Angola.

The completion of the SPA was conditional, inter alia, upon receipt of customary approvals which were obtained on the second half of 2018. As 30 June 2018, SOCO Cabinda was recognised as disposal assets classified as held for sale and part of the Group's discontinued Africa operations.

For the first half of 2018, SOCO Cabinda generated an operating and post-tax loss of $0.7m (full year 2017: $48.3m,). No revenue arose for any of the years.

In October 2018 the sale was completed as SOCO has received the total cash consideration of $5m together with a minor further payment to cover funding requirements after 30 June 2018.

Immediately prior to the sale the Group's share of net liabilities held by the Angola interest was liabilities associated with assets classified as held for sale of $1.6m with intangible assets fully impaired as of 31 December 2017. Immediately after completion of the sale the Group recognised a gain on disposal of $5.7m.

 

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, together with notice of the 2019 AGM, will be posted to shareholders in due course.

 

 

 

 

 

Non-IFRS measures

The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures are cash operating cost per barrel, depreciation, depletion and amortisation costs per barrel; and breakeven price per barrel, which are defined below:

 

Cash-operating costs per barrel

 

Cash operating costs are defined as cost of sales less depreciation, depletion and amortisation, production based taxes, movement in inventories and certain other immaterial cost of sales.

Cash operating costs for the period is then divided by barrels of oil equivalent produced. This is a useful indicator of cash operating costs incurred to produce oil and gas from the Group's producing assets.

 

 

 

 

 

 

 

 

2018

 

 

2017

 

 

 

 

$ million

 

 

$ million

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of sales

104.6

 

 

115.0

Less:

 

 

 

 

Depreciation, depletion and amortisation

(51.8)

 

 

(56.5)

Production based taxes

(15.1)

 

 

(13.6)

Inventories

(0.1)

 

 

(1.5)

Other cost of sales

 

 

 

 

(1.4)

 

 

(1.9)

Total cost of sales

 

 

 

 

36.2

 

 

               41.5

Production (BOEPD)

 

 

 

 

7,274

 

 

8,276

Cash operating cost per BOE

 

 

 

 

$13.63

 

 

$13.73

 

Depreciation, depletion and amortisation costs per barrel

DD&A per barrel is calculated as Net book value of oil and gas assets in production, together with estimated future development costs over the remaining 2P reserves. This is a useful indicator of ongoing rates of depreciation and amortisation of the Group's producing assets.

 

 

 

 

 

 

 

 

 

2018

 

 

2017

 

 

 

 

$ million

 

 

$ million

Depreciation, depletion and amortisation

51.8

 

 

               56.5

Production (BOEPD)

 

 

 

 

7,274

 

 

8,276

DD&A per BOE

 

 

 

 

$19.51

 

 

$18.72

 

Breakeven price per barrel

The Group believes this non-IFRS measurement is useful to investors as it provides a guide price at which the Group covers the costs of operations. It is calculated as the sales price (in $/bbl) which is equal to the sum of the Group's 2018 cash operating costs and production based taxes per barrel and the Group's 2018 corporation tax charge per barrel.

 

Glossary of Terms

$

United States Dollar

 

£

UK Pound Sterling

 

1C

Low estimate scenario of Contingent Resources

 

1P

Equivalent to Prove Reserves; denotes low estimate scenario of Reserves

 

2C

Best estimate scenario of Contingent Resources

 

2C Contingent Resources

Best estimate scenario of Contingent Resources

 

2P Reserves

Equivalent to the sum of Proved plus Probable Reserves; denotes best estimate scenario of Reserves. Also referred to as 2P Commercial Reserves

 

3C

High estimate scenario of Contingent Resources

 

3P

Equivalent to the sum of Proved plus Probable plus Possible Reserves; denotes high estimate scenario of Reserves

 

AGM

Annual General Meeting

 

APIº

American Petroleum Institute gravity

 

bbl

Barrel

 

blpd

Barrels of liquids per day

 

Bn

Billion                                                                            

 

boe

Barrels of oil equivalent

 

BHCPP

Bach Ho Central Processing Platform

 

boepd

Barrels of oil equivalent per day

 

bopd

Barrels of oil per day

 

bwpd

Barrels of water per day

 

CAGR

Compound annual growth rate

 

CASH or cash

Cash, cash equivalent and liquid investments

 

CAPEX or capex

Capital Expenditure

 

CEO

Chief Executive Officer

 

CNV

Ca Ngu Vang

 

Congo (Brazzaville)

The Republic of the Congo

 

Contingent Resources

Those quantities of petroleum to be potentially recoverable from known accumulations by application of development projects but which are not currently considered to be commercially recoverable due to one or more contingencies

 

DD&A

Depreciation, depletion and amortisation

 

E&P

Exploration & Production

 

EBITDAX

Earnings before Interest, Tax, Depreciation, Amortization and Exploration Expenses

 

EBT

Employee benefit trust

 

E&E

Exploration and Evaluation

 

EGP

Egyptian Pound

 

EGPC

Egyptian General Petroleum Corporation

 

FFDP

Full Field Development Plan

 

FPSO

Floating, Production, Storage and Offloading Vessel

 

FY

Full year

 

G&A

General and administration

  

HLHVJOC

Hoang Long and Hoan Vu Joint Operating Companies

 

HLJOC

Hoang Long Joint Operating Company

 

HVJOC

Hoan Vu Joint Operating Company

 

IAS

International Accounting Standards

 

IFRS

International Financial Reporting Standards

 

JOC

Joint Operating Company

 

JV

Joint venture

 

LTI

Lost Time Injury

 

LTIP

Long Term Incentive Plan

 

IMF

International Monetary Fund

 

 

kbopd

Thousand barrels of oil per day

 

Km

Kilometre

km2

Square kilometre

 

m

million

 

M&A

Mergers and Acquisitions

 

MENA

Middle East and North Africa region

 

Merlon

Merlon Petroleum El Fayum Company

 

mmbbl

Million barrels

 

mmboe

Million barrels of oil equivalent

 

OOIP

Original Oil in Place

 

OPECO Vietnam

OPECO Vietnam Limited

 

Opex

Operational expenses

 

Petrosilah

An Egyptian joint stock company to be held 50 / 50 between the SOCO Group and the Egyptian General Petroleum Corporation.

 

PSC

Production sharing contract or production sharing agreement.

 

Petrovietnam

Vietnam Oil and Gas Group

 

PTTEP

PTT Exploration and Production Public Company Limited

 

Reserves

Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial and remaining based on the development projects applied

 

RBL

Reserve Based Lending Facility

 

RISC

RISC Advisory Pty Ltd 

 

Shares

Ordinary Shares

 

SOCO Cabinda

SOCO Cabinda Limited

 

SOCO Congo

SOCO Congo Limited

 

SOCO EPC

SOCO Exploration & Production Congo SA

 

SOCO Vietnam

SOCO Vietnam Ltd

 

STOIIP

Stock Tank Oil Initially In Place

 

TGT

Te Giac Trang

 

TSR

Total shareholder return

 

UK

United Kingdom

 

US

United States of America

 

WHP

Wellhead Platform

 

YTD

Year-to-Date


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