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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Soco International Plc | LSE:SIA | London | Ordinary Share | GB00B572ZV91 | ORD 5P |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 61.80 | 61.90 | 62.40 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From May 2019 to May 2024
TIDMSIA
RNS Number : 5332I
Soco International PLC
22 March 2018
SOCO International plc
("SOCO" or the "Company" or, together with its subsidiaries, the "Group")
2017 PRELIMINARY RESULTS
SOCO, an international oil and gas exploration and production company, today announces its preliminary results for the year ended 31 December 2017.
Ed Story, President and Chief Executive Officer of SOCO, commented,
"2017 saw the further return of cash to shareholders, stable production, and a renewed focus on SOCO's business strategy. Combined with a strong balance sheet, low operating costs and continued financial discipline the Company is well positioned for growth. The two key achievements this year were the approval of an updated FFDP for the TGT field and securing the PSC for Blocks 125 & 126, offshore central Vietnam. We continue to have a core belief in delivering total shareholder value and we are today announcing a recommended final dividend for 2017 of 5.25 pence per share. To add to the commitment to an annual dividend, a business development team was established in 2017 to emphasise the Company's commitment to capital growth. In 2017 the team considered a number of opportunities and, although the merger with Kuwait Energy did not materialise, SOCO continues to pursue growth opportunities of scale, which meet our investment criteria. We have the right people and the right financial strength to create opportunities to grow the business and we look forward to delivering in 2018".
2017 FINANCIAL HIGHLIGHTS
-- Strong and robust balance sheet, zero debt, solid cash flow, and low cash operating costs:
o Revenue of $156.2m (2016: $154.6m), an average realised crude oil price of $56/bbl (2016: $45/bbl), a premium to Brent of over $2/bbl
o $45.0m of cash generated from operations (2016: $46.0m)
o Loss of $157.3m (2016: $4.2m restated), including E&E write offs of $152.3m (2016: $2.2m write back restated). Loss prior to E&E impact of $5.0m (2016: $6.4m restated)
o Year-end cash and liquid investment balance of $137.7m (2016: $100.3m) and no debt
o Receipt of the remaining proceeds of $42.7m associated with the disposal of our Mongolia assets
o Low cash operating expenditure of $13.73/boe (2016: $11.70/boe)*
o 2017 cash capital expenditure of $29.3m (2016: $40.1m), was fully funded from existing cash resources
-- Recommended dividend of 5.25 pence per share (approx. $24.3m)
o Dividends to shareholders during 2017 of $21.0m (2016: $17.5m)
*See Non-IFRS measures note 12
2017 OPERATIONAL HIGHLIGHTS
-- Low cost net production average of 8,276 BOEPD (2016: 9,883 BOEPD) in line with guidance - TGT production averaged 6,724 BOEPD (2016: 8,330 BOEPD) and CNV production averaged 1,552 BOEPD (2016: 1,553 BOEPD)
-- Updated FFDP for the TGT field, offshore southern Vietnam, which was approved in February 2017 allowing for:
o Installation of new processing equipment on the TGT H1-WHP, completed to allow for higher levels of liquid handling
o Two infill wells, TGT-30P on the H1-WHP and TGT-29P on the H5-WHP, which were executed on time and within budget
-- A PSC for Blocks 125 & 126, offshore central Vietnam, was signed in October 2017, awarding SOCO a 70% operated interest over the two blocks
-- New 25-year PEXs awarded over each of the Viodo, Lideka and Loubana areas within the former Marine XI Block, offshore Congo (Brazzaville)
-- Group year-end 2017 commercial (2P) reserves of 28.1 MMboe (2016: 33.3 MMboe)
OUTLOOK FOR 2018
-- Production guidance of 8,000 to 9,000 BOEPD net with production levels above this dependent upon the outcome of the 2018 drilling programme on TGT and CNV
-- 2018 capex of approx. $40m fully funded from existing cash resources, to cover the development drilling and infrastructure upgrade on our existing Vietnam assets and purchase, processing and interpretation of seismic data for our new venture Blocks 125 & 126 offshore Vietnam
-- Maintaining commitment to sustainable cash flow generation and returns to shareholders
-- Continued pursuit of new business opportunities to transform the business in line with our financial strategy of capital discipline, capital allocation and capital return
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
Georgia Edmonds
Owen Roberts
NOTES TO EDITORS
SOCO is an international oil and gas exploration and production company headquartered in London, admitted to the premium listing segment of the Official List and traded on the main market of the London Stock Exchange. The Group has field development and production interests in Vietnam and exploration and appraisal interests in the Republic of Congo (Brazzaville) and Angola.
CHAIRMAN AND CHieF EXECUTIVE Officer'S STATEMENT
poised for growth
2017 saw a year where SOCO retained its stable financial position with a renewed focus and commitment on actively pursuing growth opportunities being emphasised with the establishment of a business development team. This combination places the Group on a robust platform from which to materially grow the business.
Operations in 2017 centred on optimising production efficiency on the TGT and CNV fields in our core business area, offshore southern Vietnam. Formal approval of the updated FFDP for TGT in February 2017 signalled a positive realignment amongst partners and a halt to the production decline. Group production was 8,276 BOEPD (2016: 9,883 BOEPD) net to SOCO's working interest. Group year-end 2017 commercial (2P) reserves are 28.1 MMboe (2016: 33.3 MMboe).
SOCO continues to achieve a stable operational and financial base with the balance sheet remaining strong throughout 2017 with solid cash flow and low cash operating costs. The Group finished the year with no debt and $137.7m in Cash after fully funding its operating and capital expenditure programme and returning $21.0m to shareholders through a 5 pence per share dividend, bringing the total return to shareholders since 2006 to $476m. In March 2017, the Group received $42.7m as the final payment from the 2005 sale of its Mongolia assets.
Capex in 2017, fully funded from existing cash resources, was $29.3m (2016: $40.1m). Net cash generated from operations fell slightly to $45.0m in 2017, from $46.0m in 2016, reflecting higher oil prices offset by a decrease in production and timing of working capital movements and cash tax. An average crude oil sales price of $56/bbl as realised during 2017, representing a premium of over $2/bbl to Brent and generating revenues of $156.2m (2016: $154.6m), against low cash operating expenditure of $13.73/bbl (2016: $11.70/bbl). SOCO's full operating cost break-even oil price per barrel is below $30. The Group posted a loss of $157.3m (2016: $4.2m restated), which included E&E impairments of $152.3m (2016: $2.2m write back restated), the loss being $5.0m (2016: $6.4m loss restated) prior to the impairment. As announced in our Trading statement in January we have determined that there will be no substantive activity on our African assets and accordingly they have been fully impaired. Prior year comparatives have been restated to reflect our decision to change our E&E policy from modified full cost to successful efforts to better align with our peer group.
Vietnam is the core asset in SOCO's portfolio and since 1997 we have invested over $1.1 billion in the region, making SOCO one of the largest British investors in Vietnam. The ultimate goal of any successful development is to achieve production in a safe, responsible and cost effective way to benefit all stakeholders, including the countries where we operate. Safety will always be of the highest priority within the business and SOCO's joint-operations have achieved an outstanding record of safety and have demonstrated commitment to local sourcing, employment, training and industry upskilling. Our interests in the TGT and CNV fields are operated by the HLJOC and HVJOC respectively. We are delighted by HLHVJOC's extremely high level of safe operations, with zero LTIs in almost 22.9 million man-hours worked since project inception, representing six production years on TGT and nine production years on CNV.
Our goal is to be a positive presence in the regions in which we operate, by providing responsible and sustainable development, resulting in value for the host countries and local communities as well as for our own shareholders. SOCO continually strives to select and finance social projects which are sustainable and will outlast the company's involvement in the project. In Vietnam, community projects are selected by HLHVJOC and during 2017, the HLHVJOC Charitable Donation programme focused on projects assisting infrastructure development, investing in healthcare, education, and disaster relief for flood victims.
This year SOCO reinvigorated its corporate focus to further strengthen the business through inorganic and organic growth opportunities, with the potential to upscale the business underpinned by our historical focus on financial discipline and shareholder return.
NEW VENTURES
SOCO has been present in Vietnam for over 20 years, and because of our experience and presence in the region, we began evaluation of the exploration potential of Blocks 125 & 126 in the Phu Khanh Basin, in 2010. We are delighted to have signed a PSC in 2017 under which the group has acquired 70% operated interest over the two blocks, and this is seen as a strategic extension of our existing core asset. In Africa, activity centred on the award of new PEXs over each of Viodo, Lideka and Loubana, in addition to the already granted PEX for Lidongo. All four new exploitation permits are within what was formerly the contract area of the Marine XI PSC offshore Congo.
In October 2017, the Group signed a PSC for Blocks 125 & 126, in the Phu Khanh Basin offshore central Vietnam, with PetroVietnam and SOCO's co-venturer, SOVICO Holdings Company, under which the Group has acquired 70% operated interest over the two blocks. Blocks 125 & 126 are in moderate to deep water in the Phu Khanh Basin, to the north of the Cuu Long Basin, and have multiple structural and stratigraphic plays observed on the available seismic data. Initial activities will include reprocessing and interpretation of seismic data, with a view to a first exploration well potentially as early as 2020.
In January 2018, SOCO announced that it was in preliminary discussions with the newly-constituted Board of Directors of Kuwait Energy plc ("Kuwait Energy") regarding a potential transaction. On 5 March 2018 we announced that these discussions were terminated, with the Company unable to reach agreement with Kuwait Energy on the basis for an acceptable transaction.
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.
CORPORATE
Corporate Governance
Corporate governance remains a priority and the Company is committed to its programme of Board refreshment. The Directors will continue to review the balance and effectiveness of the Board with a view to adding independent non-executives commensurate with the nature and size of the Group's business.
Non-Executive Directors
In January 2017, Dr. Mike Watts stood down as an independent Non-Executive Director. Rob Gray, the Board's Senior Independent Director, replaced Dr. Mike Watts as Chairman of the Audit & Risk Committee. In December 2017, Rob Gray was appointed as Deputy Chairman of the Company, while remaining as Senior Independent Director, Chairman of the Audit & Risk Committee and member of the Remuneration and Nominations Committees.
Executive Directors
In February 2017, Jann Brown and Dr. Mike Watts joined the Company as full-time executives to co-head the Company's newly formed business development group and on 12 November 2017 were appointed as Executive Directors. Both Jann and Mike were executive directors at Cairn Energy during its rapid growth to become a FTSE 100 company.
Roger Cagle and Cynthia Cagle stepped down as Executive Directors on 12 November 2017 and will retire as employees of the Group as of 11 September 2018 after over 20 years of service. They have each played a crucial role in the success of the business throughout that time. We would like to thank Cynthia and Roger for their immense contribution to SOCO, it has been a privilege to work with them and we wish them all the very best for the future.
Outlook
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 an increased final dividend for 2017 of 5.25 pence per share.
Capital expenditure for 2018 is budgeted at approx. $40m. The 2018 Vietnam work programme includes modification works on the FPSO and infill drilling of 2/3 wells on the TGT field and one well on the CNV field. Production guidance for 2018 is set at a net average 8,000 to 9,000 BOEPD. $6.0m of the capital expenditure is allocated for the purchase, processing and interpretation of seismic data on Blocks 125 & 126.
SOCO differentiates itself amongst its peers by having a consistently strong balance sheet, steady cash flows and low operating costs. This gives us a strong and stable foundation from which to grow the business. Annual cash returns to shareholders have been delivered since 2006 and sustaining these is an objective the Board expects to maintain in the future.
SOCO is strongly focused, reenergised and committed to the organic and inorganic growth of the business. It will continue to seek opportunities of scale, that will complement our existing high quality producing assets, and diversify the portfolio. We aim to build a business focused on sustainable cash flow generation, maximising value creation and total shareholder return. We will only purse opportunities that aim to fit our strategic, financial and operational criteria. We have a strong platform for growth in 2018 and beyond. We look forward to driving the strategy, with a focus on business growth, this year and beyond.
Rui de Sousa
Chairman
Ed Story
President and Chief Executive Officer
REVIEW OF OPERATIONS
Vietnam
In Vietnam, Blocks 16-1 and 9-2, which comprise 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 field in the region which has produced more than 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.
Production summary
The Group's producing assets comprise its interests in the TGT and CNV fields. Total production from these fields averaged 28,506 BOEPD gross (2016: 33,861 BOEPD) and 8,276 BOEPD net to SOCO's working interest (2016: 9,883 BOEPD). TGT gross production averaged 22,300 BOEPD and 6,724 BOEPD net to SOCO's working interest in 2017 (2016: 27,650 BOEPD gross and 8,330 BOEPD net). CNV gross production averaged 6,206 BOEPD and 1,552 BOEPD net to SOCO's working interest in 2017 (2016: 6,211 BOEPD gross and 1,553 BOEPD net).
The average realised crude oil price for 2017 was approximately $56 per bbl, a premium to Brent of over $2 per bbl.
Production by field FY 2017 FY 2016 ===================== ======== ======== TGT Production 6,724 8,330 ===================== ======== ======== Oil 6,299 7,825 ===================== ======== ======== Gas(1) 425 505 ===================== ======== ======== CNV Production 1,552 1,553 ===================== ======== ======== Oil 1,037 1,076 ===================== ======== ======== Gas(1) 515 477 ===================== ======== ======== Total Production 8,276 9,883 ===================== ======== ======== Oil 7,336 8,901 ===================== ======== ======== Gas(1) 940 982 ===================== ======== ========
Figures in BOEPD
(1) Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.
Block 16-1 - TGT Field
(30.5% working interest; operated HLJOC)
The TGT field is located in the north eastern part of Block 16-1 offshore Vietnam and is operated by HLJOC. SOCO signed the PSC in December 1999 and the first commercial discovery was made in 2005.
TGT is a simple structure, with complex production intervals, extending over 16km and with hydrocarbons located in at least five major fault blocks. The producing reservoir is comprised of a complex series of over 80 modelled clastic reservoir intervals of Miocene and Oligocene age. Each interval requires individual reservoir management to optimise field recovery. The TGT field has been a rewarding investment for SOCO, with its attractive fiscal terms and low operating costs.
The first platform, H1-WHP, came on stream in August 2011, followed by the H4-WHP in July 2012. 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 transported by pipeline to the nearby Bach Ho facilities for processing and onward transportation to shore by pipeline to supply the Vietnamese domestic market.
Updated Full Field Development Plan
Formal approval of the updated TGT FFDP was received from the Vietnamese Government in February 2017. Drilling operations on the TGT field resumed in Q1 2017, drilling two additional infill wells. The jack-up drilling rig, PetroVietnam Drilling VI, spudded the TGT-30P well on 8 March 2017, targeting the Miocene and Oligocene reservoir horizons in the crestal part of the H1.1 fault block. TGT-30P came on-line producing approximately 2,500 BOEPD with an as-expected 40% water cut.
On completion of TGT-30P, the rig moved to the H5-WHP in the southern part of the TGT field to drill the TGT-29P infill well. The well utilised smart completion technology to optimise hydrocarbons recovery. The TGT-29P well was tied into the production system in June 2017, after being completed on time and within budget, and came on-line producing at approximately 1,600 BOEPD.
The third and final drilling operation in the 2017 TGT Development Drilling Programme was the resumption of the TGT-14X step-out appraisal well on the H5 south fault block, initially spudded in 2015. The high angle and long reach of the well added complexity to drilling operations. The well was successfully drilled to the target depth; however, poor hole conditions prevented successful completion of the well. Smaller, non-standard drilling equipment will be required to re-drill the reservoir section of the well and, consequently, completion of drilling was deferred to the next campaign. Suspending the well meant it overran the budget and, costs for returning and completing the well have been included in the 2018 budget.
TGT - Production optimisation
Construction and installation of new processing equipment on the H1-WHP has been completed. The start-up of the water handling system on H1-WHP experienced setbacks and delays due to issues resulting from damaged valves and production stabilisation issues. However, the system is now functioning in line with expectations and production guidance has been achieved. The processing equipment will be designed to handle an additional 90,000 BLPD with specific water handling capacity of up to 65,000 BWPD. The increase in the total system handling capacity to approximately 180,000 BLPD allows for higher levels of oil production at the same or higher water cut rate than previously possible.
Following installation, the operator identified a sub-optimal performance issue affecting two gas compressors on the FPSO. Evaluation of the technical solutions and requirements for further investment in the gas compression issues is ongoing and these costs will be included in the 2018 work programme and budget.
Block 9-2 - CNV Field
(25% working interest; HVJOC)
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 highly 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. 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.
CNV - Production and optimisation
The CNV field has performed steadily throughout the year. CNV production averaged 6,206 BOEPD gross and 1,552 BOEPD net to SOCO's working interest in 2017 (2016: 6,211 BOEPD gross and 1,553 BOEPD, respectively).
During the execution of the well conversion from injection to production on CNV-6PST1, wireline was left in the completion. Fishing operations during 1H 2017 to recover the stuck wireline were unsuccessful. Alternative operations to work over the well are being considered for execution in 2018, alongside a side-track to an existing well to enhance recovery from the field. Discussions with the Bach Ho owners are ongoing to establish the most effective means of enhancing performance through modifications at the reception terminal.
Vietnam New Ventures
A PSC for Blocks 125 & 126, offshore central Vietnam, between PetroVietnam, SOVICO Holdings and SOCO's wholly owned subsidiary SOCO Exploration (Vietnam) Limited, was formally signed in October 2017, under which the Group has acquired a 70% operated interest over the two blocks.
Blocks 125 & 126 are in moderate to deep waters in the Phu Khanh Basin, north of the Cuu Long Basin, and have multiple structural and stratigraphic plays observed on the available 2D seismic data. Interpretation of the available data indicates there is good potential for source, expulsion and migration of oil with numerous reservoir and seal intervals likely.
The Group's forecast capex for 2018 includes the purchase of existing seismic data, reprocessing and interpretation of seismic data, with a view to drilling the first exploration well potentially as early as 2020.
REPUBLIC OF CONGO (BRAZZAVILLE)
Lidongo, Loubana, Lideka and Viodo Prospect Areas, offshore Congo (Brazzaville)
(40.39% working interest; SOCO-operated)
The Group holds its interests in the former Marine XI contract area, located offshore Congo (Brazzaville) in the shallow water Lower Congo Basin, through an 85% owned Congolese subsidiary, SOCO Exploration and Production Congo SA. The area exists going forward as four distinct exploitation permits following the expiry of the exploration phase of the Marine XI PSC in March 2017. Loubana is located in the north west section of the former contract area, Lideka in the south west, Viodo in the centre and south east and Lidongo in the north east.
Activity in 2016 and 2017 focused on securing long term PEXs over each of the four prospect areas beyond the expiry of the exploration phase of the PSC. The PEX over the Lidongo prospect area commenced in October 2016 and has a duration of 20 years. Discussions with the authorities and the Marine XII partners on commercialisation of Lidongo continue. In Q1 2017, SOCO submitted three further PEX applications over the remaining prospect areas, Loubana, Lideka and Viodo. Each of these PEXs has now been awarded with a 25-year duration, effective from 28 December 2017.
ANGOLA
Cabinda North Block
(22% working interest*, Non-operated)
SOCO's 85% owned subsidiary, SOCO Cabinda Limited, holds a 22% working interest in the PSC for the Cabinda North Block, onshore the Angolan Cabinda enclave. Following discussions amongst the partners and the Angolan authorities to agree a change of operatorship and a reassignment of interests amongst the block partners, SOCO has agreed to increase its non-operating working interest in the Cabinda North PSC from 17% to 22% pursuant to the same series of transactions that will involve assumption of operatorship by Eni. The legal documents to complete the changes were signed by the contractor parties in November 2017. Final details and timing of the formal governmental Executive Decree to approve the change of operator and the reassignment of interests are expected shortly.
* Pending formal government approval; paying interest 27.5% pending formal government approval taking into account Sonangol exploration carry under Cabinda North joint operating agreement. Current SOCO working interest 17% and paying interest 21.25%.
GROUP RESERVES AND CONTINGENT RESOURCES
An independent audit of management estimates of Reserves and Contingent Resources for TGT and CNV, as of 1 October 2017, was completed by Senergy International Sdn Bhd as part of Lloyd's Register Group Limited ("LR Senergy") in January 2018.
TGT Reserves and Contingent Resources
The October 2017 TGT estimated Reserves were based on the current producing wells and scope of the wells being considered for approval to be drilled in 2018 at end-September 2017, with consideration given to a small number of additional likely near-term wells in 2019, optimal field management and the increased liquid handling capacity at the H1-WHP. The 2017 TGT estimated Reserves do not take into account the fully approved programme in the updated FFDP. This conservative approach will be reviewed following the interpretation and incorporation of the results of the 2018 infill drilling programme into the static and dynamic models. All volumes beyond the approved scope outlined above were classified as Contingent Resources.
The range of Reserves and Contingent Resources volumes continue to capture management's view of the full potential of the TGT field. The estimates are grounded in the results of the revised ERCE Dynamic Simulation Model and the current field performance and reflect the degree of uncertainty around the oil-in-place estimates.
The initial ERCE static and dynamic models, developed in 2013-14, have been updated and matched with the additional production from the field. With the approved updated FFDP which includes a significant upgrade to the fluid processing capacity of the H1 platform, and the anticipated 2018 drilling campaign, after subtracting production during 2017, there is only a minor revision to the Reserves compared to year-end 2016.
Hot Features
Premium
TGT Field Oil-In-Place Estimates (MMbbl)
=====================================================
P90 P50 P10
=================================== ==== ==== ====
Stock Tank Oil Initially In Place 376 585 880
=================================== ==== ==== ====
TGT Field Estimated Ultimate Recovery
=================================================
Reserves + Production 1P 2P 3P
========================= ====== ====== ======
Oil(1) 126.5 147.7 165.9
========================= ====== ====== ======
Gas(2) 7.6 8.9 10.4
========================= ====== ====== ======
Total 134.1 156.6 176.3
========================= ====== ====== ======
Contingent Resources 1C 2C 3C
========================= ====== ====== ======
Oil 25.0 40.6 56.1
========================= ====== ====== ======
Gas(2) 4.7 8.5 12.5
========================= ====== ====== ======
Total 29.7 49.1 68.6
========================= ====== ====== ======
Total Ultimate Recovery
========================= ====== ====== ======
Oil 151.5 188.3 222.0
========================= ====== ====== ======
Gas(2) 12.3 17.4 22.9
========================= ====== ====== ======
Total 163.8 205.7 244.9
========================= ====== ====== ======
Figures in MMboe
(1) Volumes include previously produced oil and gas plus estimated remaining recoverable hydrocarbons.
(2) Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.
(3) This table has been derived by SOCO from the audited figures.
SOCO Working Interest Reserves and Resources
TGT Field at 31 December 2017
==============================================================================
Reserves(1) 1P 2P 3P
================================================ ======== ======== ========
Oil 15.5 21.8 27.3
================================================ ======== ======== ========
Gas(2) 0.9 1.3 1.7
================================================ ======== ======== ========
Total 16.4 23.1 29.0
================================================ ======== ======== ========
Contingent Resources 1C 2C 3C
================================================ ======== ======== ========
Oil 7.5 12.3 16.9
================================================ ======== ======== ========
Gas(2) 1.4 2.6 3.8
================================================ ======== ======== ========
Total 8.9 14.9 20.7
================================================ ======== ======== ========
Sum of Reserves and Contingent Resources(3, 4) 1P & 1C 2P & 2C 3P & 3C
================================================ ======== ======== ========
Oil 23.0 34.1 44.2
================================================ ======== ======== ========
Gas(2) 2.3 3.9 5.5
================================================ ======== ======== ========
Total 25.3 38.0 49.7
================================================ ======== ======== ========
Figures in MMboe
(1) This table has been derived by the Company by deducting the produced volumes between 1 October 2017 to 31 December 2017 inclusive from the LR Senergy audited figures.
(2) Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.
(3) The summation of Reserves and Contingent Resources has been prepared by the Company.
(4) Contingent Resources are subject to Chance of Commercialisation estimated by LR Senergy at 70%.
CNV Reserves and Contingent Resources
Re-evaluation of the field performance dynamics has led to the HVJOC partners ceasing water injection and agreeing to convert the CNV-6P-ST1 injection well to production. This change to the drive mechanism from "bottom-up" water drive to "top-down" gas drive, due to the volatile nature of the oil, will liberate gas in the well bore. This gas will rise to the crest of the reservoir, expanding and therefore displacing oil into the wells. Extensive simulation has demonstrated the benefit of this approach.
Reserves relate to the current producing wells. Contingent Resources comprise the estimated recoverable volumes from additional wells and/or sidetracks to existing wells.
SOCO Working Interest Reserves and Contingent Resources
CNV Field at 31 December 2017
==============================================================================
Reserves(1) 1P 2P 3P
================================================ ======== ======== ========
Oil 2.6 3.4 4.3
================================================ ======== ======== ========
Gas(2) 1.2 1.6 2.0
================================================ ======== ======== ========
Total 3.8 5.0 6.3
================================================ ======== ======== ========
Contingent Resources 1C 2C 3C
================================================ ======== ======== ========
Oil 2.7 4.0 5.3
================================================ ======== ======== ========
Gas(2) 1.2 1.9 2.5
================================================ ======== ======== ========
Total 3.9 5.9 7.8
================================================ ======== ======== ========
Sum of Reserves and Contingent Resources(3, 4) 1P & 1C 2P & 2C 3P & 3C
================================================ ======== ======== ========
Oil 5.3 7.4 9.6
================================================ ======== ======== ========
Gas(2) 2.4 3.5 4.5
================================================ ======== ======== ========
Total 7.7 10.9 14.1
================================================ ======== ======== ========
Figures in MMboe
(1) This table has been derived by the Company by deducting the produced volumes between 1 October 2017 to 31 December 2017 inclusive from the LR Senergy audited figures.
(2) Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.
(3) The summation of Reserves and Contingent Resources has been prepared by the Company
(4) Contingent Resources are subject to Chance of Commercialisation estimated by LR Senergy at 70%.
FINANCIAL REVIEW
FINANCE STRATEGY
Our finance strategy underpins the Group's business model and goes hand in hand with our core business strategy of building shareholder value through our oil and gas portfolio.
The finance strategy is founded on three core areas of focus - capital discipline, capital allocation and capital return.
During 2017, we generated cash flow from our operations in Vietnam of $87.8m (2016: $85.6m) and also recovered $42.7m, the final amount due following the 2005 sale of our Mongolia interests.
We have a low cost asset base, a robust cash balance and a balance sheet with the capacity to support debt for the right projects.
The Group is positioned for growth and during 2017 increased its business development activities. Our pursuit for growth opportunities will always be positioned within our long standing core strategy of building value for shareholders.
Change of Accounting Policy to successful efforts
During the year, we carried out a full review of our accounting policies, in accordance with best practice, to ensure that the policies we use remain fit for purpose for the next phase of the business. As a result of that review, we have changed our policy on accounting for Exploration and Evaluation assets.
Since the introduction of IFRS in 2005, we have used a modified full cost basis of accounting often associated with companies whose focus is on exploration. Under this policy, we assessed E&E assets for impairment on a geographical cost pooling (typically licence by licence basis). We have now changed our policy to successful efforts under which E&E assets are assessed on a more granular well by well basis. This change in policy reflects the maturity of the business and is used by the majority of our UK listed E&P peer group. Prior year figures have been restated on a successful efforts basis, resulting in a decrease in 31 December 2016 net assets of $185.3m (refer to note 2).
The impact of this change on the current year income statement (other than the changes arising on our African assets, explained below) is to reduce the DD&A charge by $12.7m; and to reduce the deferred tax asset by $1.8m. Both of these changes are a result of the lower cost base held in the balance sheet for the assets in Vietnam, as certain historic E&E costs have now been fully written off as part of the restatement of prior year balances.
Strategic Review - African Assets
As announced in our January trading statement, during 2017 we reviewed our strategic priorities and the Board decided that the African assets, Marine XI (now the Lidongo, Lideka, Loubana and Viodo exploitation permits) and Cabinda North, are no longer a core priority for the Group. Minimal capital will be spent on them in the near future and the associated work programme commitments reflect this position. There has been no change in our assessment of the potential of these assets; however, in the absence of a near term work programme and investment, it is no longer appropriate to carry the costs previously incurred on these assets in the balance sheet. They have therefore been fully impaired.
If no change to our accounting policies had been made, these assets would still have been fully impaired and the resulting impairment charge in the year would have been $219.9m. However, the interaction with the change of policy to successful efforts means that $67.6m of this cost has been recorded through the restatement of prior year balances. The actual charge for the year is therefore $152.3m.
Both of these changes - the move to a successful efforts accounting policy and the impairment of the African assets following the strategic review - are explained in full in notes 2a and 6 to the Financial Information.
OPERATING PERFORMANCE
The Group continued to deliver robust revenue of $156.2m (2016: $154.6m). The slight increase year on year is the result of the higher average realised crude oil price of $56.43/bbl (2016: $45.01/bbl), over $2/bbl premium to Brent, offset by a 16.3% decline in production levels from 9,883 BOEPD to 8,276 BOEPD.
Cash operating costs decreased to $41.5m (2016: $42.3m).
*See note 12 for details
The per barrel cost of both cash operating cost and DD&A have increased due to the allocation of fixed cost over a reduced number of barrels produced in 2017. Prior to the impact of the change in policy to successful efforts, the Group DD&A rate for 2017 was $22.91/boe. The retrospective write off of certain exploration costs from the balance sheet has reduced this by 18.5% to $18.72/boe. This reduction in rates will apply to future periods and, whilst there is no cash impact, it will feature positively in the Income Statement.
General and administrative expenses of $18.3m (2016: $13.5m) includes $4.7m (2016: $1.7m) incurred on M&A activity, leaving underlying G&A expenses of $13.6m (2016: $11.8m) charged to the income statement. This increase is a result of the transition of the executive team, in the handover from the outgoing to the incoming directors.
Taxation
The tax expense during the year increased 6%, from $26.1m (restated) for 2016 to $27.7m in 2017. This increase reflects the higher operating profit for the year prior to exploration expense. The Group's effective tax rate approximates to the statutory tax rate in Vietnam of 50%, after excluding the effect of the $152.3m exploration write off as well as additional non-deductible expenses and unrecognised tax losses (see note 4 of the Financial Information).
Loss for the year
The Group made a loss during the year of $157.3m (2016: $4.2m restated), including E&E write offs of $152.3m (2016: $2.2m write back restated). The loss prior to E&E impact was $5.0m (2016: $6.4m restated).
Cash Flow
Operating cash flow of $45.0m (2016: $46.0m) was generated from our assets in Vietnam.
Capital Cash Expenditure
Total cash capital expenditure for the year, including abandonment, was $29.3m (2016: $40.1m). $23.9m was spent on recommencing the drilling campaign on TGT, funding abandonment commitments and upgrading infrastructure, all in Vietnam. On the intangible assets $0.9m relates to the award of the new PSC in Vietnam over Blocks 125 & 126 and $4.5m was spent on the assets in Africa.
Tax strategy and total tax contribution
Tax is managed proactively and responsibly with the goal of ensuring that the Group is compliant in the 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.
During 2017, the total payments to governments for the Group amounted to $182.1m, of which $176.4m or 97% was related to the Vietnam producing licence areas, of which $117.8m was for indirect taxes based on production entitlement. The breakdown of the contributions, including payroll taxes and other taxes will be contained within the additional information in the 2017 Annual Report & Accounts.
Balance Sheet
Intangible assets decreased during the period to $3.8m (2016: $150.6m (restated)) almost exclusively due to the full impairment of the African assets of $152.3m. During the period $5.5m was added, $1.5m on the newly awarded Blocks 125 & 126 in Vietnam and $4.0m on Africa which was subsequently impaired.
Property, plant and equipment decreased by $48.3m from $554.2m (restated) to $505.9m.
This is made up of: -
Investments in assets $20.4m
Less:
Downward revision to decommissioning asset $11.8m
DD&A $56.9m
Total $48.3m
There are no impairments to the Group's producing assets.
Cash and cash equivalents, including liquid investments, increased by 37.3% to $137.7m (2016: $100.3m).
The $42.7m due on the 2005 sale of our interests in Mongolia, held at 31 December 2016 as a financial asset, was received during the year in full.
Trade and other receivables decreased to $20.7m (2016: $24.7m) largely due to the timing of crude oil cargos.
Trade and other payables increased slightly to $23.1m (2016: $22.4m) as a result of increased M&A activity over the year end.
Own Shares
The SOCO EBT holds ordinary shares of the Company for the purposes of satisfying long term incentive awards for senior management. At the end of 2017, the Trust held 2,114,596 (2016: 2,299,767) Shares, representing 0.64% (2016: 0.67%) of the issued share capital.
In addition, as at 31 December 2017, the Company held 9,122,268 (2016: 9,122,268) treasury shares, representing 2.67% (2016: 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 assets in Vietnam, 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 twelve months from the date of approval of the 2017 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 & company distributable reserves
SOCO remains committed to paying an annual dividend. During the year the Company paid a dividend to shareholders of 5 pence per Ordinary Share (2016: 4 pence), at a cost to the company of $21.0m (2016: $17.5m).
In 2017, the change in accounting policy for E&E assets and the write down of the African assets, positions the balance sheet well for the future. The lower carrying cost of our asset base has reduced the depletion and tax charges this year and the positive impact will also be felt in future years. After taking account of the results for the year, the company currently has distributable reserves of over $157m, which provides cover for dividends in line with the proposal for 2017 of approximately 8 years.
The Directors are recommending a final dividend of 5.25 pence per Ordinary Share, subject to approval at the AGM on 7 June 2018.
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. In future, we look to add another strand to the story - capital growth - to underpin the sustainability of the dividends over the longer term.
INDEPENT 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 2017.
The preliminary statement of annual results for the year ended 31 December 2017 includes the 2017 preliminary results, chairman and chief executive officer's statement, review of operations, financial review, the consolidated income statement, the consolidated and parent company balance sheets, the consolidated and parent company statements of changes in equity, the consolidated and parent company cash flow statements, the related notes 1 to 12 and the glossary of terms.
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 21 March 2018. 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:
Change in Exploration & Evaluation ("E&E")
Accounting Policy
-----------------------------------------------------------------------------------
Key audit During the year management have voluntarily
matter description elected to change the unit of account
(cash generating unit) applied in
assessing their E&E assets for impairment
under IFRS 6 Exploration for and Evaluation
of Mineral Resources. In previous
periods they assessed E&E assets for
impairment on a geographical cost
pool basis, which in practice was
applied at the licence level. In the
current year, management has changed
the unit of account such that impairment
is now assessed on a well-by-well
basis. This represents a change in
accounting policy and has therefore
resulted in a restatement of the group's
prior year results, including a reduction
in net assets at 1 January 2016 of
$199.4 million, as disclosed in note
2(a).
Under IAS 8 Accounting Policies, Changes
in Accounting Estimates and Errors,
voluntary changes in accounting policy
can only be made if they result in
more relevant and reliable information
about the effect of transactions on
an entity's financial position.
We have identified a key audit matter
associated with the appropriateness
of the change in accounting policy
as well as the accuracy and completeness
of the resulting restatement of prior
year balances and related disclosures.
Further details of this matter are
provided in note 2(a) of the financial
information.
-------------------- -------------------------------------------------------------
How the Our procedures included:
scope of * understanding the basis for management's conclusion
our audit that the change in accounting policy resulted in more
responded relevant and reliable information about the entity's
to the key financial position; this assessment took into account
audit matter our knowledge of the industry as well as a comparison
of the revised unit of account with reference to a
selection of the company's peer group;
* assessing the process applied by management to
calculate the impact of the change in accounting
policy on prior periods;
* validating the accuracy and completeness of the
restatement of prior period balances; this included
obtaining a supporting schedule of adjustments from
Management and verifying key inputs to appropriate
supporting evidence, including past annual reports,
press releases, joint operator reports and evidence
obtained in prior year audits; and
* assessing the completeness and accuracy of the
associated disclosure for compliance with IAS 8.
-------------------- -------------------------------------------------------------
Key observations We are satisfied that management's
revised policy is in accordance with
the principles of IAS 8 and that the
related impact on prior period balances
has been appropriately calculated
and disclosed.
-------------------- -------------------------------------------------------------
Impairment of Producing Oil & Gas Assets
-----------------------------------------------------------------------------------
Key audit The value of property, plant and equipment
matter description relating to the Group's producing
oil and gas assets as at 31 December
2017 was $505.4 million (2016 restated:
$553.6 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 fraud risk in this area.
Management reviewed both of its producing
fields in Vietnam for indicators of
impairment, with no indicators identified
for Te Giac Trang ('TGT') but an indicator
identified in relation to Ca Ngu Vang
('CNV'), primarily due to a reduction
in reserves. Management has estimated
the fair values less costs of disposal
of each field and compared these to
the carrying amount of each field
on the balance sheet. For TGT whilst
Management concluded there were no
impairment indicators, the recoverable
value was nonetheless calculated to
demonstrate the existence of significant
available headroom. Management's fair
value estimate is based on key assumptions
which include:
* oil and gas prices;
* reserves estimates and production profiles;
* the incremental value of contingent resources for
CNV; and
* the discount rate adopted, which was unchanged for
TGT at 10% but for CNV was reduced from 12.5% to 10%.
The carrying value of property, plant
and equipment is considered by management
as a critical accounting judgement
and key source of estimation uncertainty.
No impairment charges or impairment
reversals were recorded during the
year. Further details of the key assumptions
used by management in their impairment
evaluation are provided in note 7
of the financial information.
-------------------- -------------------------------------------------------------
How the As well as our work on reserves as
scope of noted below;
our audit * we understood the basis for management's conclusion
responded as to the existence or otherwise of impairment
to the key triggers for TGT and CNV;
audit matter
* we compared oil and gas price assumptions with third
party forecasts and publicly available forward
curves;
* we understood the basis for management's decision to
reduce the CNV discount rate to 10% and 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 considered whether the incremental value
attributed to contingent resource estimates for CNV
was appropriate;
* we completed a scenario analysis for 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 there were no
indicators of impairment for TGT.
For CNV we are satisfied that, based
on the scenario analysis outlined
above, neither an additional impairment
charge nor an impairment reversal
are required and that the related
disclosures in note 7 of the financial
information are appropriate.
-------------------- -------------------------------------------------------------
Impairment of Intangible Exploration & Evaluation
Assets
-----------------------------------------------------------------------------------
Key audit The total value of E&E assets as at
matter description 31 December 2017 held by the Group
was $3.8 million (2016 restated: $150.6
million), after recording an impairment
of $152.3 million. The Group's principal
E&E interests, being the Marine XI
licence in the Republic of Congo (Brazzaville)
and the Cabinda licence in Angola,
were both impaired in full during
the year. The remaining capitalised
exploration balance as at 31 December
2017 relates to Blocks 125 & 126 in
Vietnam.
In accordance with relevant accounting
standards, E&E assets are assessed
for impairment at least annually.
This is considered a key audit matter
due to the significant judgments that
are required and the material carrying
values of E&E assets that were previously
recorded in the financial statements.
These judgements include the effect
of the significant and prolonged fall
in oil price on the viability of the
Group's E&E projects.
Management assesses whether there
were any indicators of impairment
of the Group's E&E assets by reference
to IFRS 6 Exploration for and evaluation
of mineral resources, such as;
-- expiry or relinquishment of exploration
and evaluation licences;
* substantive expenditure for further exploration and
evaluation in the specific area is neither budgeted
nor planned;
* whether exploration and evaluation activities have
not led to the discovery of commercially viable
quantities of mineral resources and the entity has
decided to discontinue activities in the area; or
* whether data exists to suggest that the carrying
amount of the E&E asset is unlikely to be recovered
in full from successful development or by sale.
The carrying value of E&E assets is
considered by management as a critical
accounting judgement and key source
of estimation uncertainty.
The current status of the Marine XI
and Cabinda licences together with
activity during the year is summarised
in the review of operations. As outlined
in the financial review, in January
2018 the company announced that following
a review of its strategic priorities
the directors had decided that its
African E&E asset portfolio was no
longer a core priority for the group,
with minimal capital due to be spent
on the related assets in the near
future. Therefore these assets were
fully impaired in the 2017 financial
year. Further details of the group's
E&E assets and the related impairment
judgements are given in note 6 of
the financial information.
-------------------- -------------------------------------------------------------
How the Our procedures were focused on challenging
scope of management's conclusions that the
our audit Marine XI and Cabinda licences should
responded be impaired in full. This included:
to the key * participating in meetings with key operational and
audit matter finance staff to understand the future intention for
each asset;
* confirming that substantive expenditure for these
assets is neither budgeted nor planned;
* understanding the basis for management's conclusion
that there is currently limited ability to realise
value from these assets; this included understanding
the extent to which material value was attributed to
these licences during recent New Business
discussions.
-------------------- -------------------------------------------------------------
Key observations Management do still plan on conducting
some limited work in future periods
on these assets, primarily to retain
legal title and hence enable them
to continue marketing these assets
for disposal. However, based on information
gathered through recent New Business
discussions, there is no reliable
evidence that the group will be able
to realise material value from these
assets. Accordingly, also taking into
consideration that these assets are
no longer a core priority, we are
satisfied that the full impairment
of the Marine XI and Cabinda E&E assets
in the current year is appropriate.
-------------------- -------------------------------------------------------------
Oil & Gas Reserves and Contingent Resource
Estimates
-----------------------------------------------------------------------------------
Key audit This was considered to be a key audit
matter description matter due to the subjective nature
of reserves and contingent resource
estimates, their impact on the Financial
Statements as key inputs within the
assessment of impairment and the depreciation,
depletion and amortisation ('DD&A')
calculations, and because both the
TGT and CNV fields are complex fields
contributing all of the value of the
Group's recognised reserves.
Management has engaged a third party
reservoir engineering expert to provide
an independent report on the Group's
reserves and contingent resource estimates
using standard industry reserve estimation
methods and definitions for both the
CNV and TGT fields.
Management's reserves and contingent
resource estimates are included in
the review of operations. In addition,
management has explained the scope
of work of the third party expert
and their findings in the review of
operations.
-------------------- -------------------------------------------------------------
How the For both TGT and CNV assets:
scope of * we understood the process used by management to
our audit derive their estimates of reserves and contingent
responded resources and how they provide information to, and
to the key interact with, the third party expert;
audit matter
* we reviewed the third party expert's report on SOCO's
reserves and contingent resource estimates as
summarised in the review of operations and checked
that these estimates were used consistently
throughout the accounting calculations reflected in
the financial information; and
* we communicated directly with the third party experts
to discuss and assess their scope of work, expertise
and objectivity.
-------------------- -------------------------------------------------------------
Key observations We are satisfied that the reserves
and contingent resources figures used
by SOCO in the group's DD&A and impairment
calculations are appropriate and consistent
with those reported by the third party
experts.
-------------------- -------------------------------------------------------------
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:
(a) checked that the figures in the preliminary announcement covering the full year have been accurately extracted from the audited financial statements and reflect the presentation to be adopted in the audited financial statements;
(b) considered whether the information (including the management commentary) is consistent with other expected contents of the annual report;
(c) considered whether the financial information in the preliminary announcement is misstated;
(d) 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;
(e) 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.
(f) read the management commentary and 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.
David Paterson ACA (Senior statutory auditor)
For and on behalf of Deloitte LLP
Statutory Auditor
London, United Kingdom
21 March 2018
Consolidated Income Statement
for the year to 31
December 2017 (Restated(1)
2017 2016
Notes $ million $ million
---------- ---------------
Revenue 3 156.2 154.6
Cost of sales (115.0) (119.9)
---------- ---------------
Gross profit 41.2 34.7
Administrative expenses (18.3) (13.5)
Exploration (expense)
write back 6 (152.3) 2.2
Operating (loss) profit (129.4) 23.4
Investment revenue 1.4 0.5
Finance costs (1.6) (2.0)
---------- ---------------
(Loss) profit before
tax 3 (129.6) 21.9
Tax 3,4 (27.7) (26.1)
---------- ---------------
Loss for the year (157.3) (4.2)
---------- ---------------
Loss per share (cents)
Basic 5 (47.7) (1.3)
---------- ---------------
Diluted 5 (47.7) (1.3)
---------- ---------------
Consolidated Statement of Comprehensive
Income
for the year to 31
December 2017 (Restated(1)
2017 2016
$ million $ million
---------- -------------
Loss for the year (157.3) (4.2)
Items that may be subsequently
reclassified to profit or
loss:
Unrealised currency
translation differences (0.4) (0.2)
Total comprehensive
loss for the year (157.7) (4.4)
---------- -------------
(1) In 2017, the Group changed its accounting policy for intangible exploration and evaluation assets and has adopted the successful efforts method of accounting. This change in accounting policy has been applied retrospectively and consolidated income statement, balance sheet and cash flow statement and related notes of the financial statements have been restated accordingly. Full details are provided in Note 2 (a).
Balance Sheets
as at 31 December (Restated) (Restated)
2017
Group Company
2017 2016 As at 2017 2016
1 January
2016
Notes $ million $ million $ million $ million $ million
---------- ------------------ ----------- ---------- ------------------
Non-current
assets
Intangible
assets 3.8 150.6 142.8 - -
Property, plant
and equipment 7 505.9 554.2 609.0 0.5 0.6
Investments - - - 388.2 530.6
Other
receivables 36.9 33.8 29.5 - -
546.6 738.6 781.3 388.7 531.2
---------- ------------------ ----------- ---------- ------------------
Current assets
Inventories 4.2 5.7 3.1 - -
Trade and other
receivables 20.7 24.7 19.5 0.7 0.8
Tax receivables 0.6 0.7 0.7 0.1 0.3
Financial asset 8 - 42.7 52.7 - -
Liquid
investments 25.3 15.3 - - -
Cash and cash
equivalents 112.4 85.0 103.6 1.0 0.5
---------- ------------------ ----------- ---------- ------------------
163.2 174.1 179.6 1.8 1.6
Total assets 709.8 912.7 960.9 390.5 532.8
---------- ------------------ ----------- ---------- ------------------
Current
liabilities
Trade and other
payables (23.1) (22.4) (37.2) (9.6) (6.7)
Tax payable (6.8) (9.2) (7.8) (0.2) (0.1)
---------- ------------------ ----------- ---------- ------------------
(29.9) (31.6) (45.0) (9.8) (6.8)
---------- ------------------ ----------- ---------- ------------------
Net current
assets
(liabilities) 133.3 142.5 134.6 (8.0) (5.2)
----------- ---------- ------------------
Non-current
liabilities
Deferred tax
liabilities (132.6) (147.0) (162.9) - -
Long term
provisions (52.7) (62.9) (59.9) - -
---------- ------------------ ----------- ---------- ------------------
(185.3) (209.9) (222.8) - -
Total
liabilities (215.2) (241.5) (267.8) (9.8) (6.8)
Net assets 494.6 671.2 693.1 380.7 526.0
---------- ------------------ ----------- ---------- ------------------
Equity
Share capital 27.6 27.6 27.6 27.6 27.6
Other reserves 245.9 243.8 242.3 195.8 194.5
Retained
earnings 221.1 399.8 423.2 157.3 303.9
Total equity 494.6 671.2 693.1 380.7 526.0
---------- ------------------ ----------- ---------- ------------------
Statements of Changes in
Equity
for the year to 31
December 2017
Group
------------------- --------------------- ---------------------- -----------------
Called
up share Other Retained
capital reserves earnings Total
$ million $ million $ million $ million
------------------- --------------------- ---------------------- -----------------
As at 1 January 2016
(as previously
reported) 27.6 242.3 622.6 892.5
Effect of change in
accounting policy for
intangible exploration
and evaluation assets
(Note 2 (a)) - - (199.4) (199.4)
------------------- --------------------- ---------------------- -----------------
As restated 27.6 242.3 423.2 693.1
Loss for the year - - (4.2) (4.2)
Unrealised currency
translation differences - (0.2) (0.2) (0.4)
Distributions - - (17.5) (17.5)
Share-based payments - 0.2 - 0.2
Transfer relating to
share-based payments - 1.5 (1.5) -
------------------- --------------------- ---------------------- -----------------
As at 1 January 2017 27.6 243.8 399.8 671.2
Loss for the year - - (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 31 December 2017 27.6 245.9 221.1 494.6
------------------- --------------------- ---------------------- -----------------
Company
------------------- --------------------- ---------------------- -----------------
Called
up share Other Retained
capital reserves earnings Total
$ million $ million $ million $ million
------------------- --------------------- ---------------------- -----------------
As at 1 January 2016 27.6 195.3 412.6 635.5
Retained profit for
the year - - 17.5 17.5
Unrealised currency
translation differences - (0.2) (107.2) (107.4)
Distributions - - (17.5) (17.5)
Share-based payments - 0.2 - 0.2
Transfer relating to
share-based payments - (0.8) (1.5) (2.3)
------------------- --------------------- ---------------------- -----------------
As at 1 January 2017 27.6 194.5 303.9 526.0
Loss for the year - - (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 31 December 2017 27.6 195.8 157.3 380.7
------------------- --------------------- ---------------------- -----------------
Cash Flow Statements
for the year
to 31 December
2017
Group Company
---------------------- -----------------------------------
2017 2016 2017 2016
Note $ million $ million $ million $ million
---------- ---------- ---------- -----------------------
Net cash from (used
in) operating activities 10 45.0 46.0 (12.9) (7.9)
Investing
activities
Purchase of intangible
assets (5.4) (27.4) - -
Purchase of property,
plant and equipment (20.8) (8.4) (0.1) (0.1)
Increase in liquid
investments (1) (10.0) (15.3) - -
Payment to abandonment
fund (3.1) (4.3) - -
Deferred proceeds
on disposal of Mongolia
assets 42.7 10.0 - -
Investment in subsidiary
undertakings - - (3.1) (2.9)
Dividends received from
subsidiary undertakings - - 37.6 30.0
Net cash from (used
in) investing activities 3.4 (45.4) 34.4 27.0
Financing
activities
Share-based
payments (0.3) (0.9) (0.3) (0.9)
Distributions 9 (21.0) (17.5) (21.0) (17.5)
---------- ---------- ---------- -----------------------
Net cash used in
financing activities (21.3) (18.4) (21.3) (18.4)
Net increase (decrease)
in cash and cash equivalents 27.1 (17.8) 0.2 0.7
Cash and cash equivalents
at beginning of year 85.0 103.6 0.5 0.2
Effect of foreign
exchange rate changes 0.3 (0.8) 0.3 (0.4)
Cash and cash equivalents
at end of year (1) 112.4 85.0 1.0 0.5
---------- ---------- ---------- -----------------------
(1) Liquid investments comprise short term liquid
investments of between three to six months maturity
while cash and cash equivalents comprise cash at
bank and other short term highly liquid investments
of less than three months maturity. The combined
cash and cash equivalents and liquid investments
balance at 31 December 2017 was $137.7 million (2016:
$100.3 million).
Notes to the Consolidated Financial Information
1. General information
The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2017 or 2016, but is derived from those accounts. A copy of the statutory accounts for 2016 has been delivered to the Registrar of Companies and those for 2017 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) Changes in accounting policy
In 2017, the Group has voluntarily changed its accounting policy for intangible exploration and evaluation assets and has adopted the successful efforts method to align with the more prevalent method of accounting for oil and gas assets within its peer group. This has resulted in the Group changing the unit of account used for assessing intangible exploration and evaluation assets for impairment from a licence by licence basis to a well by well basis.
The change in accounting policy has been applied retrospectively and the comparative information has been restated where needed. The table below shows the effect of this change in accounting policy on consolidated income statement, consolidated balance sheet, reported loss for the year, equity, basic and diluted loss per share. There was no impact on the consolidated cash flow statement.
Impact on Consolidated Income 2016
$
million
-----------
Decrease in Costs
of Sales (depreciation) 15.1
Decrease in Exploration
expense 1.1
Increase in Tax (2.1)
Net reduction in loss
for the year 14.1
-----------
Impact on loss per
share (cents)
Decrease in basic 4.3
Decrease in diluted 4.3
-----------
Impact on Consolidated
Balance Sheet 31.12.2016 01.01.2016
$ million $ million
----------- -----------
Decrease in Intangibles
assets (67.6) (68.7)
Decrease in Property,
plant and equipment (136.4) (151.5)
----------- -----------
Net decrease in assets (204.0) (220.2)
----------- -----------
Decrease in Deferred
tax liabilities 18.7 20.8
----------- -----------
Net decrease in liabilities 18.7 20.8
----------- -----------
Net decrease in net
assets (185.3) (199.4)
----------- -----------
(b) 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.
3. Segment information
The Group has one principal business activity being oil and gas exploration and production. The Group's operations are located in South East Asia and Africa (the Group's operating segments) and form the basis on which the Group reports its segment information. There are no inter-segment sales.
2017
---------- ---------- ------------ ----------
Africa
SE Asia (2) Unallocated Group
$ million $ million $ million $ million
---------- ---------- ------------ ----------
Oil and gas sales 156.2 - - 156.2
Depreciation, depletion
and amortisation 56.5 - 0.3 56.8
Exploration expense
(see note 6) - 152.3 - 152.3
Profit (loss) before
tax (1) 39.9 (152.3) (17.2) (129.6)
Tax charge (see
Note 4) 27.7 - - 27.7
---------- ---------- ------------ ----------
(Restated)
2016
------------------- ------------------------ --------------------- -------------------
Africa
SE Asia (2) Unallocated Group
$ million $ million $ million $ million
------------------- ------------------------ ---------------------
Oil and gas sales 154.6 - - 154.6
Depreciation,
depletion
and amortisation 64.7 - 0.2 64.9
Exploration write
back - (2.2) - (2.2)
Profit (loss)
before
tax (1) 32.9 1.7 (12.7) 21.9
Tax charge 25.9 - 0.2 26.1
------------------- ------------------------ --------------------- -------------------
(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) In December 2017, an impairment indicator of
IFRS 6 was triggered following the Group's announcement
that no substantive expenditure for the Africa assets
is either budgeted or planned in the near future.
The remaining costs capitalised associated with exploration
areas in Africa of $152.3m was fully impaired in
the income statement (see Note 6).
Included in revenues arising from South East Asia
are revenues of $102.9m and $21.1m which arose from
the Group's two largest customers who contributed
more than 10% to the Group's oil and gas revenue
(2016: $115.1m and $34.1m 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.
2017 2016
$ million $ million
--------------------- -------------------
Vietnam 105.7 117.2
Thailand 36.3 -
China 3.3 33.4
Other 10.9 4.0
--------------------- -------------------
156.2 154.6
--------------------- -------------------
Non-current assets (Restated)
2017 2016
$ million $ million
----------- -----------
United Kingdom 0.4 0.6
Vietnam 509.3 555.9
Congo - 100.3
Other -
Africa - 48.0
509.7 704.8
----------- -----------
Excludes other receivables.
4. Tax
(Restated)
2017 2016
$ million $ million
------------- ----------------------
Current
tax 42.1 42.0
Deferred tax (14.4) (15.9)
------------- ----------------------
27.7 26.1
------------- ----------------------
The Group's corporation tax is calculated at 50%
(2016: 50%) of the estimated assessable profit for
the year in Vietnam. During 2017 and 2016 both current
and deferred taxation have arisen in overseas jurisdictions
only.
The charge for the year can be reconciled
to the (loss)/profit per the income statement
as follows:
(Restated)
2017 2016
$ million $ million
------------- ----------------------
(Loss)/profit
before tax (129.6) 21.9
(Loss)/profit before
tax at 50% (2016:
50%) (64.8) 11.0
Effects
of:
Non-deductible
expenses 10.1 10.9
Tax losses not
recognised 6.2 5.1
Non-deductible exploration
costs written off/(back) 76.2 (1.1)
Adjustments to tax charge
in respect of previous
years - 0.2
Tax charge for
the year 27.7 26.1
------------- ----------------------
The prevailing tax rate in the jurisdictions in
which the Group produces oil and gas is 50%. The
tax charge in future periods may also be affected
by the factors in the reconciliation above.
The effect of non-deductible exploration costs written
off of $76.2m relates to the impairment of exploration
assets in Africa (2016 restated: ($1.1m).
Non-deductible expenses primarily relate to Vietnam
DD&A charges for costs previously capitalised, which
are non-deductible for Vietnamese tax purposes,
contributing $6.9m (2016 restated: $8.1m) to the
effect of non-deductible expenses. A further $3.2m
(2016: $2.8m) 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.
5. Loss per share
The calculation of the basic and diluted loss per
share is based on the following data:
(Restated)
2017 2016
$ million $ million
---------- --------------
Loss for the purposes of
basic loss per share (157.3) (4.2)
Effect of dilutive potential
ordinary shares - Cash settled
awards and options (0.7) (0.5)
---------- --------------
Loss for the purposes of
diluted loss per share (158.0) (4.7)
---------- --------------
Number of shares
(million)
2017 2016
---------- --------------
Weighted average number of ordinary
shares for the purpose of basic loss
per share 329.8 329.4
Effect of dilutive potential
ordinary shares - Share awards
and options 3.6 2.8
---------- --------------
Weighted average number of ordinary
shares for the purpose of diluted
loss per share 333.4 332.2
---------- --------------
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 2017 and prior year.
6. Exploration expense/(write back)
(Restated)
2017 2016
$ million $ million
---------- --------------
Exploration expense (write
back) 152.3 (1.1)
Licence commitments (write
back) - (1.1)
---------- --------------
152.3 (2.2)
---------- --------------
In December 2017, an impairment indicator of IFRS 6 was triggered following the Group's announcement that no substantive expenditure for those exploration areas in Africa was neither budgeted or planned in the near future. The remaining costs capitalised of $152.3m, after taking into consideration $67.6m which was separately impaired through the restatement of prior year balances due to the change in accounting policy, was fully impaired in the income statement.
7. Property, plant and equipment
As discussed in the Review of Operations, proved and probable oil and gas reserves, audited by Senergy International Sdn Bhd as part of Lloyds Register Group Limited dated 1 October 2017, show a slight decrease to 2P reserves numbers for TGT and a more significant decrease for CNV. This downward revision triggered an impairment test on the Group's CNV asset in Vietnam. No impairment trigger was identified for TGT. 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. The majority of net book value is supported by the fair value derived from a discounted cash flow valuation of the 2P production profile, but with a further portion supported by the risk adjusted incremental value of 2C contingent resources. The key assumptions to which the fair value measurement is most sensitive are oil price, discount rate and 2P reserves. In 2017, the post tax nominal discount rate was lowered from 12.5% to 10% following a change in management of the reservoir and proven reservoir performance which has led to improved technical confidence and therefore a reduced risk profile. As at 31 December 2017, the fair value of the asset is estimated based on a post tax nominal discount rate of 10.0% (2016: 12.5%) and an oil price reflecting a gradual increase over five years from $61/bbl in 2018 (2016: $57/bbl for 2017), to $71/bbl in 2022 (2016: $69/bbl for 2020) plus inflation of 2% (2016: 2%) thereafter.
Testing of sensitivity cases indicated that neither a $5/bbl reduction in the long term oil price nor a 1% increase in discount rates, used when determining fair value less costs of disposal method, would result in an impairment of our CNV oil and gas assets.
Other fixed assets comprise office fixtures and fittings and computer equipment.
8. Financial asset
In 2005, the Group disposed of its Mongolia interest to Daqing Oilfield Limited Company. Under the terms of the transaction the Group was entitled to receive a subsequent payment amount of up to $52.7m, once cumulative production reached 27.8 million barrels of oil, at the rate of 20% of the average monthly marker price for Daqing crude multiplied by the aggregate production for that month. Daqing notified SOCO that the production threshold of crude oil in excess of 27.8 million barrels was achieved in December 2015. The fair value of the subsequent payment amount was determined using a valuation technique as there was no active market against which direct comparisons can be made (Level 3 as defined in IFRS 13). The Directors expected the full subsequent payment amount to be settled by the end of 2016. On 19 December 2016, the Group received the first payment of $10.0m from Daqing Oilfield Limited Company as partial payment for the subsequent payment amount of $52.7m. The full remainder of $42.7m was received in March 2017.
9. Distribution to Shareholders
In June 2017, the Company paid dividends to shareholders of $21.0m (2016: $17.5m) or 5 pence per Ordinary Share (2016: 4 pence per Ordinary Share in two equal payments of 2 pence per share).
The SOCO EBT which is consolidated within the Group, waived its rights to receive a dividend in 2017 and 2016.
The Board is recommending a final dividend for 2017 of 5.25 pence per share, which amounts to approximately $24.3m, 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 AGM and has not been included as a liability in these Financial Statements. The proposed dividend will be paid on 15 June 2018 to shareholders on the Register of Members at the close of business on 25 May 2018.
10. Reconciliation of operating profit to operating cash flows
Group Company
--------------------------------- -------------------------------------
(Restated)
2017 2016 2017 2016
$ million $ million $ million $ million
---------- --------------------- ---------- -------------------------
Operating (loss) profit (129.4) 23.4 (18.0) (12.5)
Share-based payments 2.0 1.1 2.0 1.1
Depletion and depreciation 56.8 64.9 0.3 0.2
Exploration expense
(write back) (see Note
6) 152.3 (2.2) - -
---------- --------------------- ---------- -------------------------
Operating cash flows before
movements in working capital 81.7 87.2 (15.7) (11.2)
Decrease (increase)
in inventories 1.5 (2.6) - -
Decrease (increase)
in receivables 4.4 (6.8) 0.4 (0.2)
Increase in payables 0.2 7.8 2.4 3.6
---------- --------------------- ---------- -------------------------
Cash generated by (used
in) operations 87.8 85.6 (12.9) (7.8)
Interest received 1.4 0.4 - -
Interest paid - (0.1) - (0.1)
Income taxes paid (44.2) (39.9) - -
---------- ---------------------
Net cash from (used in)
operating activities 45.0 46.0 (12.9) (7.9)
---------- --------------------- ---------- -------------------------
Cash is generated from continuing operating activities only.
11. 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 2018 AGM, will be posted to shareholders in due course.
12. 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.
Refer to the Financial Review for the calculation.
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.
Refer to the Financial Review for the calculation.
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 2017 cash operating costs and production based taxes per barrel and the Group's 2017 corporation tax charge per barrel.
Glossary
of Terms
$ AGM CNV FFDP IFRS OPECO Vietnam SOCO Congo
United Annual Ca Ngu Vang Full International OPECO Vietnam SOCO Congo
States general Field Financial Limited Limited
Dollar meeting Development Reporting
Plan Standards
GBP BBL CAPEX or FPSO JOC PEX SOCO EPC
UK Pound or capex Floating, Joint Petroleum SOCO
Sterling bbl Capital Production, Operating Exploitation Exploration
Barrel Expenditure Storage Company Permit & Production
and Offloading Congo SA
Vessel
1C BHCPP Congo FY LTI Petrovietnam SOCO Vietnam
Low estimate Bach (Brazzaville) Full Lost Vietnam Oil SOCO Vietnam
scenario Ho The Republic year Time and Gas Group Ltd
of Contingent Central of the Congo Injury
Resources Processing
Platform
1P BLPD Contingent G&A LTIP PSC STOIIP
Equivalent or Resources General Long Production Stock Tank
to Proved blpd Those and Term sharing Oil Initially
Reserves; Barrels quantities administration Incentive contract In Place
denotes of of petroleum Plan or production
low estimate liquids to be sharing
scenario per potentially agreement.
of Reserves day 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
2C BOE DD&A HLHVJOC MPS PTTEP TGT
Best estimate or Depreciation, Hoang Mer Profonde PTT Exploration Te Giac
scenario boe depletion Long Sud and Production Trang
of Contingent Barrels and and Hoan Public Company
Resources of amortisation Vu Joint Limited
oil Operating
equivalent Companies
2P BOEPD EBT HLJOC M&A Reserves UK
Equivalent or Employee Hoang Mergers Reserves United
to the boepd benefit Long and are those Kingdom
sum of Barrels trust Joint Acquisitions quantities
Proved of Operating of petroleum
plus Probable oil Company anticipated
Reserves; equivalent to be
denotes per commercially
best estimate day recoverable
scenario by application
of Reserves. of development
Also referred projects
to as 2P to known
Commercial accumulations
Reserves 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
3C BWPD E&E HVJOC MMBBL Shares US
High estimate or Exploration Hoan Million Ordinary United
scenario bwpd and Evaluation Vu Joint barrels Shares States
of Contingent Barrels Operating of America
Resources of Company
water
per
day
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR FKBDKKBKKANB
(END) Dow Jones Newswires
March 22, 2018 03:01 ET (07:01 GMT)
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