Energean Oil and Gas, the oil and gas producer focused on the Mediterranean, has announced its audited full-year results for the year ended 31 December 2019 (“FY 2019”). Having grown its reserve base at 39% year-on-year, Energean is now at its next transition point as the company begins converting this into cash flows and production, de-risking investment case and moving closer to the medium-term goal of paying a sustainable dividend, the company noted in a statement.
Mathios Rigas, Chief Executive Officer, Energean Oil & Gas commented:
“Energean continued its strong growth trajectory in 2019, becoming firmly established as a leading, FTSE 250 E&P independent.
“The COVID-19 pandemic and OPEC+ price war have put us into uncertain times, but we are well-placed to weather the challenges. Once the Edison E&P transaction is completed, around 70% of our production will be sold under long-term gas sales agreements that insulate our future revenues against oil price volatility. Following completion of the Edison E&P transaction, we will continue to own and operate the majority of our asset base, and are well-funded for all of our projects. This will ensure that we can respond quickly and appropriately to the macro environment and take the right decisions to protect our business and our shareholders, as demonstrated by the $155 million cut to our 2020 capex guidance. The crisis finds Energean well prepared with full discretion on our non-Israeli capex programme and a very strong balance sheet further strengthened only recently by a further $175 million committed funding for our Karish project, demonstrating the strength of our banking relationships and the commitment of our lenders to the project.
“In the coming weeks, you will see our FPSO hull sailaway from China to Singapore, a key milestone in the delivery of first gas from Karish, which is on track for 1H 2021. During 2019 we completed the drilling of the three development wells of Karish, confirmed excellent productivity rates from the wells and made a new discovery (Karish North) in Israel that we intend to develop in 2021. We continued to gain market share in Israel securing additional long-term gas contracts and bringing us closer to our target to maximise capacity utilisation of our FPSO. We expect the Edison E&P transaction to close during 2020, which, based on the agreed locked-box date of 1 January 2019, allows us to benefit from the robust results delivered by the business during 2019, including $152 million of Free Cash Flow from the assets to be acquired. This, combined with the receivables recovered in Egypt, exclusion of the Algerian assets from the transaction perimeter and our onward disposal of the North Sea assets to Neptune Energy, contributes to a low effective purchase price.
“Fully committed to lead also on the ESG front, Energean became the first E&P company globally to commit to net zero emissions by 2050, and we have a firm plan to reduce carbon intensity by 70% over the next three years.
“I look forward to continuing to deliver positive momentum and sustainable growth to maximise value for all of our stakeholders”.
Highlights
- Karish was 72% physically complete at 31 December 2019 and remains on track to deliver first gas in 1H 2021. Firm gas sales of 5.0 bcm/yr with a further 0.6 bcm/yr to be converted to a firm basis immediately on publication of a satisfactory Karish North CPR, expected at the end of March 2020.
- Post-period end, two of the three Karish development wells successfully flowed during clean-up operations, confirming that each will be capable of delivering up to the design limit of 300 mmscf/d (c.3 bcm/yr). The third development well is currently in the clean-up phase and production performance is expected to be similar, confirming that the three wells will be able to produce to the 8 bcm/yr capacity of the FPSO.
- Increased 2P reserves and 2C resources to 558 MMboe, representing a 39% year-on-year increase, before any contribution from the Edison E&P acquisition. Energean is at a transition point in its history, from which it will convert this growth in reserves to growth in production and cash flow.
- 2019 average Working Interest production was 3.3 kbopd from the Prinos field. Cost of production was approximately $21.5 /bbl.
- 2019 full year revenue was $76 million. Adjusted EBITDAX was $36 million. Capital expenditure was $685 million.
- Recognised a $71 million impairment charge on the Prinos area, reflecting a reduction in Energean’s oil price assumptions and a change in the Group’s Prinos field production forecast.
- Energean retains significant liquidity. At 31 December 2019, Energean had cash and undrawn facilities of $834 million, excluding the undrawn $600 million acquisition bridge facility.
- Became the first E&P company globally to commit to net zero emissions by 2050 and have a firm plan to reduce carbon intensity by 70% over the next three years.
Financial Summary
|
|
FY 2019
|
FY 2018
|
|
|
$m
|
$m
|
|
Sales revenue
|
75.7
|
90.3
|
|
Cost of production ($/boe)
|
21.5
|
17.6
|
|
Operating profit / (loss)
|
(93.9)
|
23.8
|
|
Adjusted EBITDAX
|
35.6
|
52.4
|
|
Operating cash flow
|
36.3
|
62.7
|
|
Capital expenditure
|
685.1
|
494.6
|
|
Cash capital expenditure
|
954.6
|
293.6
|
|
Net debt (cash)
|
561.6
|
(75.6)
|
Edison E&P Acquisition (subject to closing)
- In July 2019, Energean agreed to acquire Edison E&P for $750 million of up-front consideration, adding immediate cash flows, EBITDAX and incremental growth opportunities. In October 2019, Energean agreed to sell Edison E&P’s UK and Norwegian subsidiaries to Neptune Energy for $250 million of up-front consideration.
- Raised $265 million of equity and $600 million of bridge financing to fund the acquisition. The take-out of the bridge facility using a Reserve Based Lending (“RBL”) Facility of up to $525 million plus a bridge to disposal of up to $250 million for the UK and Norway Assets is progressing as expected.
- Carve out of the Algerian assets from the transaction perimeter has been agreed in principle at an effective price of $155 million, based on an effective transaction date of 1 January 2019; the carve out remains subject to a signed, amended SPA.
- Excluding Algeria, UK and Norwegian subsidiaries, Edison E&P delivered Free Cash Flow of $152 million during 2019.
- Exclusive of Algeria and the UK and Norwegian subsidiaries, 2019 average Edison E&P working interest production was 56 kboe/d (64 kboe/d inclusive of these assets).
- In January 2020, Edison E&P received the updated Environmental Impact Assessment (“EIA”) approval on the Cassiopea development, offshore Italy. The development is progressing as planned with first gas expected in early 2023.
Outlook
- Closing of the Edison E&P acquisition and subsequent sale of the UK and Norwegian subsidiaries to Neptune Energy will occur once the remaining conditions precedent to the transaction are fulfilled, which is expected during 2020. Energean is working with Edison E&P to fulfil these conditions precedent as soon as possible.
- The Energean Power FPSO hull for the Karish gas project is expected to sailaway from China to Singapore in the coming weeks, and from Singapore to Israel around YE 2020.
- Energean expects to issue an updated CPR for the successfully appraised Karish North discovery, around end 1Q 2020. An updated Field Development Plan (“FDP”) will be submitted to the Israeli government in 2Q 2020.
- 2020 pro forma group production (including the assets to be acquired from Edison E&P) is expected to be between 42.5 – 50.0 kboe/d. Production in the first two months of 2020 averaged 52.4 kboe/d.
- 2020 pro forma consolidated group capital expenditure (including the assets to be acquired from Edison E&P) of $840 million, an adjustment to the net consideration, the quantum of which is being agreed, on previous guidance following actions taken by management in the last two weeks. $580 million will be spent in Israel and $140 million is fully discretionary.
- Decisions on FID at Katakolo (Greece) and Drill or Drop on both Ioannina (Greece) and Montenegro; outstanding financial commitment across these licences of $1 million.
- Strategic review of the Prinos Area assets progressed; results expected in 2020. Capital expenditure on the assets, including Epsilon, will be minimised whilst the review is concluded.
Operational Review
Business Resilience and Current Response to the Macro Environment
Energean notes the recent fall in global oil prices and highlights its resilience to fluctuations in the global commodity prices. In addition, Energean has not currently suffered any delays due to the Coronavirus.
Defensive Reserve and Production Mix
- 70% of Energean’s 2P reserve and 2C resource base will be gas once the Edison E&P transaction completes.
- Once the Edison E&P transaction completes, around 70% of 2020 – 2025 expected production and 60% of Energean’s 2P and 2C reserve and resource base is gas that will be sold under Gas Sale & Purchase Agreements (“GSPAs”) that are largely insulated from fluctuations in the Brent price:
- Israel gas is expected to account for 34% of 2020 – 2025 expected production and 49% of the reserve and resource base. Israel gas is sold subject to long-term GSPAs with some of the largest domestic independent power plant and industrial customers. All GSPAs have floor pricing and take-or-pay provisions, with no price no re-openers. One contract that has a limited amount of Brent exposure, representing less than 2% of current contracted gas sales.
- Egypt gas[3] is expected to account for 37% of 2020 – 2025 expected production and 16% of the reserve and resource base. This gas is being sold to EGPC under the concession agreement. In Abu Qir, at prices of between $40 and $72 Brent, the gas price is $3.50 / mmBTU ($3.71/mcf). At $35/bbl, the gas price is $3.16 / mmBTU ($3.35/mcf). In NEA, the gas price has been agreed at a $4.60/mmBTU ($4.77/mcf). At prices between $40 and $25, the gas price gradually reduces to the floor price of $4.45/mmBTU.
Well-Funded for Current Activities and Working Capital
- The Group retains significant liquidity and at 31 December 2019, Energean had cash of $354 million and undrawn facilities of $480 million, excluding the undrawn $600 million acquisition bridge facility. At 28 February 2020 (and after reflecting the project finance facility increase effected on 16 March 2020), Energean had undrawn facilities of $620 million, excluding the acquisition bridge facility.
Israel Project Finance Facility
- In Israel, cash and undrawn facilities were US$555 million. On 16 March 2019, the project finance was increased to $1.45 billion, providing an additional $175 million of liquidity for the Karish project and future appraisal activity in Israel. The project finance facility aids the defensive nature of Energean’s funding position and is largely unaffected by volatility in the oil price because:
- It is non-recourse to the parent;
- There are no redeterminations for the duration of its tenor;
- Interest payments and other project costs are covered by the sizing of the facility; and
- Due to the nature of the GSPAs underpinning the Karish and Tanin projects’ revenues, fluctuations in the oil price do not materially affect the cashflow covenants in the facility.
- Energean’s Karish development is being executed largely through a lump-sum, turnkey EPCIC contract with TechnipFMC, which helps to protect the Company against capital expenditure overruns.
- Liquidated damages payable by the Company resulting from any potential delay to the project are broadly back-to-back with any liquidated damages payable to gas buyers that may arise from late delivery of first gas. This limits Energean’s commercial exposure to any future delay.
Funding position ex-Israel
- Energean’s business excluding Israel had cash and undrawn facilities of $279 million at 31 December 2019.
Flexibility over capital investment programme
- The Prinos Basin and Katakolo assets are fully-owned and operated, providing absolute flexibility over discretionary capital expenditure.
- Energean’s exploration assets have minimal outstanding firm commitments, again giving Energean flexibility over capital expenditure.
- Energean’s 2020 capital expenditure guidance benefits from strong funding and its discretionary nature:
- 2020 pro forma consolidated group (including the proposed acquisition of Edison E&P) capital expenditure has been reduced to $840 million, from $995 million. The majority of this decrease is due to i) deferral of Cassiopea[4] expenditure; ii) deferral of Epsilon expenditure; and iii) deferral of the $35 million Zeus exploration well; results from the Karish North CPR are expected to be sufficient to ensure that Energean has enough gas to be able to participate in upcoming GSPA opportunities in Israel. This has allowed Energean to defer investment and conserve capital without impacting potential cash flow-driven returns for its shareholders.
- $580 million relates to Karish development and is funded by the project finance facility.
- A further $140 million is fully discretionary for 2020, principally relating to capital expenditure in Egypt and various projects in Italy.
Israel
Karish-Tanin development project
Energean is on track to deliver first gas from its Karish project in 1H 2021. As of 31 December 2019, physical progress on the project was approximately 72% complete, the drilling of the three Karish Main development wells had been completed and significant progress had been made on the hull and topsides of the Energean Power FPSO. The FPSO Hull is expected to sailaway from China to Singapore in the coming weeks, signalling delivery of a key intermediate milestone towards delivery of first gas in 1H 2021.
FPSO progress and key milestones
FPSO keel laying took place successfully at the COSCO Yard, Zhoushan, China, in April 2019 and in October 2019 the hull was undocked and floated out from COSCO Shipyard’s dry dock.
To date, in 2020, despite Coronavirus, the workforce in the COSCO yard has been maintained above 550 people. The FPSO Hull sailaway is expected in the coming weeks and it is due to arrive in the Admiralty Yard in Singapore shortly thereafter. Good progress has been made on construction of the topsides in Singapore, and Energean is working with TechnipFMC to mitigate the impact of the deferred sailaway from China on Practical Completion of the project and is on schedule to deliver first gas in 1H 2021.
Gas sales and purchase agreements
During 2019, Energean agreed an additional 0.8 Bcm/yr of new and increased contracted and unconditional (“firm”) GSPAs and 0.4 Bcm/yr of contracted and conditional (“contingent”) GSPAs with gas buyers. In early 2020, a further contingent GSPA for up to 0.2 Bcm/yr was signed.
Total contracted gas sales are now as follows:
Contracted and Unconditional GSPAs
Contracted and Conditional GSPAs
- IPM Beer Tuvia: 0.4 Bcm/yr (39 mmcfd) of sales post-2024. Energean may supply additional gas pre-2024 at the option of both counterparties. The IPM contract is conditional, inter alia, on Energean certifying additional 2P reserve volumes and will be converted to firm GSPAs immediately on issuance of the Karish North CPR shortly.
- New Contract: Up to 0.2 Bcm/yr (19 mmfcd) of sales, under which supply ramps up between 2022 and 2025. The new contract is also conditional, inter alia, on Energean certifying additional 2P reserve volumes. Energean expects the contract to be converted into firm upon publication of the Karish North CPR shortly.
- Or Contract: 0.7 Bcm/yr (68 mmcfd) of sales to Or Power, which depends on Or Power succeeding in its application to receive a new licence from the Electricity Authority to construct a new power generation plant in Israel and successfully completing this project.
In the medium term, Energean aims to secure both the resource and offtake for the remaining spare capacity in its 8 bcma (775mmcfd) capacity FPSO, whilst bearing in mind the need for capital conservation in the current market environment.
All GSPAs contain take-or-pay and floor pricing provisions, which reduce the risks associated with Energean’s cash flow generation profile and limit Energean’s exposure to global commodity price fluctuations.
Energean is also evaluating gas export monetisation options, including the markets of southern Europe. As part of this strategy, the Company signed a Letter of Intent (“LOI”) in January 2020 with the Public Gas Corporation of Greece for the potential sale and purchase of 2 Bcm/yr of natural gas from Energean’s fields in Israel through the proposed East Med Pipeline. At this stage, there is no commitment to supply this gas and Energean views the LOI as a longer-term option for monetisation of its gas resources.
2019 Drilling Campaign
During 2019, Energean drilled the KM-01, KM-02, KM-03 development wells and the Karish North exploration well and sidetrack. Completions and installation of the Christmas Trees on those three development wells was the focus of operations during 1Q 2020; clean-up of two wells is complete and one is ongoing, following which the wells will be ready for integration with the subsea infrastructure and hook up to the FPSO.
The three development wells are expected to deliver 5.0 bcm/yr (484 MMscfd) of firm contracted gas into the Israeli domestic market commencing in 1H 2021. During 2020, successful results were achieved from production measurement performed during clean-up of the KM-02 and KM-01 development wells. Both wells flowed at a maximum rate of 120 million standard cubic feet per day (MMscf/d) of natural gas, limited only by the capacity of the surface equipment. Performance modelling confirms that each well will be capable of delivering at the 300 MMscf/d design capacity when connected to the FPSO. Clean-up of the third development well, KM-03 has commenced and the results of production measurement, which are expected to be similar, will be announced to the market in due course. Energean is confident that the three development wells can produce at combined rates of 800 mmscf/d, which is sufficient to fill the capacity of the FPSO.
The Karish North field was discovered in April 2019, with appraisal confirming initial best estimate recoverable resources of 0.9 Tcf (25 bcm) of gas plus 34 MMbbl of light oil/condensate. An independent CPR is being prepared and results will be communicated to the market shortly. On publication of this CPR, 0.6 bcm/yr of contingent GSPAs are expected to be immediately converted to firm GSPAs. The company is preparing a field development plan, envisaging a tie-back to the Energean Power FPSO. A final investment decision on that project, which is estimated to cost circa $125 million, is anticipated during 2020, with first gas during 2022.
Exploration Programme
Energean has decided to defer its exploration activity on Block 12. Results from the Karish North CPR are expected to be sufficient to ensure that Energean has sufficient gas resources to be able to participate in upcoming GSPA opportunities in Israel. This has allowed Energean to defer investment and conserve capital without impacting potential cash flow-driven returns for its shareholders.
The Zeus and Athena prospects remain very attractive and Energean intends to re-visit its investment decision in due course.
Acreage
Energean also added to its Israeli acreage in 2019. The Company, as part of a joint venture with Israel Opportunity, was awarded four new licences – 55, 56, 61 and 62 – in Zone D of the Israeli EEZ. The licences are situated approximately 45 kilometres off the coast of Tel Aviv and represent a strong potential source of upside in Energean’s Israel portfolio.
Greece
Production
At the end of 2019, Energean decided to place its Prinos area assets under strategic review, the results of which will be communicated to the market once complete. Working interest production from Greece averaged 3,312 boepd during 2019, however, investment in Prinos, Prinos North and Epsilon will continue to be limited whilst this strategic review is concluded and 2020 production is, therefore, expected to be in the range of 2,000 to 2,500 boepd, assuming no contribution from Epsilon. Output from Prinos and Prinos North is to be maintained through rig-less activities requiring limited expenditure.
Due to higher-return capital allocation priorities, Energean no longer carries a medium-term production target for the Prinos area asset; future production will be a function of the level of investment in the assets.
Development – 2019 Overview
During 2019, all three Epsilon Lamda platform development wells were drilled successfully. As previously announced, additional pay was encountered in the deeper and dolomitic zones of the Epsilon reservoir. This resulted in an NSAI-audited reserve and contingent resource increase of 26 MMboe, to 44 mmboe.
At Katakolo, award of the EIA is expected in 2Q 2020 with potential Final Investment Decision thereafter. NSAI-audited Katakolo reserves are 14 MMboe, a 36% increase on 2018.
The proposed underground gas storage project in South Kavala saw a positive development in 4Q 2019 when an amendment to the law was passed on 10 December 2019, making it possible for the regulating energy authority to regulate the tariff. This paves the way for a tender for the project, which is expected in 2020. On 11 March 2020, the Greek Energy and Finance Ministries signed a decision to allow the country’s state-asset sales fund to proceed with an international tender to construct, maintain and operate an underground gas storage facility at the South Kavala field, with the first step a cost-benefit study. The right to exploit the facility will be 50 years.
Exploration
In Ioannina, interpretation of the newly acquired seismic lines is ongoing and a drill-or-drop decision will be taken in 1H 2020. The quality of acquired seismic was a major improvement when compared to historic vintages and the lines have identified two prospective trends with multiple analogue prospects. Further, the new 2D seismic has verified the existing geological model, de-risking existing prospectivity. The seismic lines were acquired with minimal environmental impact and Energean and the operator, Repsol, have agreed to plant trees in areas away from the 2D seismic lines. The outstanding net financial commitment on the Ioannina block is less than $0.5 million.
In Aitoloakarnania, the operator, Repsol, is carrying out the necessary environmental studies in preparation for the 2D seismic acquisition campaign, which is expected to commence in 2Q 2020, subject to permitting. The outstanding net financial commitment on the Aitoloakarnania is less than $3 million.
In February 2020, Energean signed an agreement for the acquisition of Total’s 50% stake in, and operatorship of, Block 2, offshore Western Greece, providing further material exploration opportunities in its core area of the Eastern Mediterranean with limited financial exposure. Energean’s net remaining expenditure (at 50% Working Interest and post including consideration) towards satisfaction of the minimum work obligation, which includes 1800 kilometres of 2D seismic acquisition and processing, is approximately €0.5 million. Energean believes that this is a highly attractive transaction in the context of the early stage prospectivity identified on the block.
Work to date on the licence has identified that Block 2 contains part of a large four-way closure at the Top Jurassic Apulia platform. The prospect is believed to be an analogue to the Vega field, offshore Italy, which Edison E&P operates with a 60% Working Interest. The structure is covered by sparse 2D seismic and could be de-risked through the seismic acquisition programme to be executed as part of the minimum work obligation.
Montenegro
In February 2019, Energean commissioned PGS for the acquisition of a new 3D seismic survey over Blocks 26 and 30. The PGS Ramform Titan, one of the best seismic acquisition vessels in the world, deployed 14 geo-streamers, 6.5 kilometres for each streamer length, using a triple source array to cover a total area of 338 square kilometres. The 3D seismic survey substantially fulfils the licence commitment for both blocks 26 & 30 with a net outstanding financial commitment of less than $0.5 million.
Results from the seismic survey have identified a number of shallow gas prospects and deeper carbonate prospects have been identified through interpretation of the newly acquired seismic data. Energean is awaiting final data in order to confirm the primary prospect. The Ministry of Economy in Montenegro confirmed that Energean will receive an extension to the first exploration phase to 15 March 2021, with a drill-or-drop decision due by year end 2020.
Energean Reserves and Resources
Energean increased 2P reserves and 2C resources to 558 MMboe, up 39% year-on-year, before any contribution from the Edison E&P acquisition. Energean’s reserves and resources benefitted from two discoveries during 2019, the Karish North discovery in Israel, which added 190 mmboe, and the Epsilon Deeper and Dolomitic Zones, which added 25 mmboe.
|
|
Israel
|
|
Greece
|
|
Total
|
|
|
Oil
|
Gas
|
Total
|
|
Oil
|
Gas
|
Total
|
|
Oil
|
Gas
|
Total
|
|
Commercial Reserves
|
|
mmbbls
|
Bcf
|
mmboe
|
|
mmbbls
|
Bcf
|
mmboe
|
|
mmbbls
|
Bcf
|
mmboe
|
|
1 January 2019
|
|
22
|
1,558
|
298
|
|
49
|
5
|
49
|
|
71
|
1,563
|
347
|
|
Revisions
|
|
7
|
(99)
|
(11)
|
|
8
|
1
|
8
|
|
15
|
(98)
|
(3)
|
|
Disposals
|
|
–
|
–
|
–
|
|
–
|
–
|
–
|
|
–
|
–
|
–
|
|
Transfer from contingent resources
|
|
–
|
–
|
–
|
|
(2)
|
–
|
(2)
|
|
–
|
–
|
–
|
|
Production
|
|
–
|
–
|
–
|
|
(1)
|
–
|
(1)
|
|
(1)
|
–
|
(1)
|
|
31 December 2019
|
|
29
|
1,460
|
287
|
|
54
|
6
|
55
|
|
83
|
1,465
|
342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contingent Resources
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 January 2019
|
|
0.7
|
133
|
23
|
|
33
|
15
|
35
|
|
33
|
148
|
58
|
|
Additions
|
|
–
|
–
|
–
|
|
–
|
–
|
|
|
–
|
–
|
–
|
|
Revisions and Discoveries
|
|
23
|
618
|
134
|
|
20
|
22
|
24
|
|
43
|
640
|
156
|
|
Disposals and relinquishments
|
|
–
|
–
|
–
|
|
–
|
–
|
–
|
|
–
|
–
|
–
|
|
Transfer to commercial reserves
|
|
–
|
–
|
–
|
|
–
|
–
|
–
|
|
–
|
–
|
–
|
|
31 December 2019
|
|
24
|
751
|
157
|
|
53
|
37
|
59
|
|
76
|
788
|
216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Commercial Reserves & Contingent Resources
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 January 2019
|
|
23
|
1,692
|
321
|
|
81
|
20
|
84
|
|
104
|
1,711
|
405
|
|
31 December 2019
|
|
53
|
2,211
|
444
|
|
107
|
43
|
114
|
|
159
|
2,253
|
558
|
Edison E&P acquisition
In July 2019, Energean agreed to acquire Edison E&P for $750 million plus $100 million of contingent consideration. Energean raised $265 million of new equity and $600 million in bridge financing from leading international banks to fund the deal. Energean is in the process of refinancing the acquisition bridge facility using an RBL, which is expected to be sized at up to $525 million, plus a $250 million bridge to disposal for the UK and Norway assets.
Energean is working actively to close the acquisition as soon as possible, with approval from Italian regulatory authorities anticipated soon. Formal approval from Egyptian regulatory authorities is expected soon after shareholder approval at the EGM. As announced on 23 December 2019, the transaction will now exclude the Algerian assets. Carve out of the Algerian assets from the transaction perimeter has been agreed in principle at an effective price of $155 million, based on an effective transaction date of 1 January 2019; the carve out remains subject to a signed, amended SPA.
In October 2019, Energean agreed to sell Edison E&P’s UK North Sea and Norway assets to Neptune Energy for $250 million (plus up to $30 million contingent consideration). The deal is aligned with Energean’s strategy of optimising its portfolio and the stated goal of disposing of non-core assets. The onward sale is expected to complete as soon as is practicable following the close of the acquisition of Edison E&P.
Edison E&P financials
During 2019, Edison E&P delivered the following financial results. These results have been prepared on the basis of Edison E&P’s accounting policies and are subject to adjustments when included in Energean’s upcoming Circular and Prospectus.
Edison E&P financials are presented on a pro forma basis and are unaudited.
|
|
Edison E&P
2019 – $ million
|
Edison E&P exclusive UK North Sea, Norway & Algeria
2019 – $ million
|
|
Revenue
|
531
|
433
|
|
Operating Costs (including G&A)
|
255
|
196
|
|
EBITDAX
|
276
|
237
|
|
Operating Cash Flow
|
252
|
212
|
|
Development and Production Capital Expenditure
|
136
|
33
|
|
Exploration Expenditure
|
49
|
28
|
At 31 December 2019, net receivables (after provision for bad and doubtful debts) in Egypt were $222 million, of which $126 million were classified as overdue (31 December 2018: $240 million net receivables, of which $106 million were classified as overdue). A further payment for $55 million was received in January 2020.
Edison E&P production
Average Working Interest production from the Edison E&P portfolio during 2019 was 64.2 kboed. Average 2019 production from the assets to be retained by Energean was 56.4 kboe/d and, for this set of assets, pro forma 2020 production guidance is a range of 42.5 – 50.0 kboe/d. Average Working Interest production in the first two months of 2020 is estimated to have been 52.4 kboe/d.
During 2020, Energean expects Egyptian production to average 32 – 37 kboe/d, Italy to average 8 – 10 kboe/d and Croatia to average 0.5 kboe/d. After an initial reduction during 2020 due to the natural depletion of the fields, production is expected to rise again in the medium term mainly due to new developments; Cassiopea in Italy, Yazzi/NEA/NI in Egypt and, potentially, Irena in Croatia. Production is also expected to be enhanced through the drilling of additional wells at Abu Qir; four locations have been identified for near-to-medium term drilling that, if sanctioned (noting that these wells represent discretionary capital expenditure), would target a combined 30 mmboe of reserves for a total budget of c.$90 million.
|
Country
|
2020 Pro Forma Production Guidance
|
2019 Average Working Interest Production – kboe/d[5]
|
|
Italy
|
8 – 10
|
10.4
|
|
Egypt
|
32 – 37
|
45.5
|
|
Croatia
|
0.5
|
0.5
|
|
Edison E&P Assets to be Acquired
|
42.5 – 50.0
|
56.4
|
|
Algeria
|
|
5.2
|
|
UK
|
|
2.5
|
|
Total
|
|
64.2
|
Edison E&P reserves
As at 30 June 2018, the Edison E&P assets to be acquired had 2P reserves of 239 mmboe of working interest 2P reserves according to an independent CPR prepared by DeGolyer and MacNaughton. The reserves report is currently being updated to reflect an effective date of 31 December 2019 and will be published in the Shareholder Circular, to be sent to shareholders in connection with the acquisition. The new CPR is expected to reflect a corresponding decrease in reserves as a result of 18 months of production. Reserve replacement has been limited over the period due to limited investment associated with the disposals process and change of control.
Edison E&P Development
Italy – Argo Cassiopea
In December 2019, ENI and Edison E&P received the renewal of the Italian EIA approval on Cassiopea (ENI 60% Op., Edison E&P 40%). The development consists of four subsea wells (two new wells and two re-completed wells) and uses a subsea production system with a 60 kilometre pipeline to shore, where gas compression and treatment will be performed inside the existing Gela refinery. The drilling campaign is expected to be undertaken between 1Q and 3Q 2022 and the subsea installation campaign 2Q to 4Q 2022, with first gas expected in early 2023. The development is expected to add an estimated 60 mmscf/d (10 kboe/d) of net production.
Egypt – NEA/NI
The NEA and NI assets are satellite fields of the Abu Qir gas-condensate asset. Edison E&P has a 100% working interest in both accumulations. The development concept includes four subsea wells, to be drilled in water depths ranging from 30 to 85 metres, and tied back to the North Abu Qir III platform. A final investment decision is expected in mid-2020 with first gas expected 18 months later. The development will target an estimated 52 million barrels of working interest 2P reserves at a total cost of approximately $200 million.
The development will add limited operating costs to the Abu Qir complex, resulting in attractive netbacks.
Expected peak production from the NEA / NI development is an incremental 90 mmscf/d plus 1 kbopd of condensate.
Croatia
Edison E&P expects to spud the Irena-2 appraisal well in 2Q 2020. It will target the same gas-bearing horizon that was successful in Irena-1 and, in the event of a success, the well will be suspended for future production.
Edison E&P Exploration
In Egypt, the Ameeq well, which is being drilled on the North Thekah Offshore Block, spudded on 18 January 2020.
In Italy, an additional two firm exploration wells will be drilled into the Gemini and Centauro prospects, which are adjacent to the Cassiopea field, in 2022. These wells will target a combined c.9.7 mmboe of gross prospective resources and each has a Geological Chance of Success of 90%. If successful, the wells would be tied back to the Cassiopea subsea system.
2020 Guidance – pro forma for the combined business, includes Edison E&P
The production and financial data below reflects the Edison E&P forecasts for the full year. Edison E&P will be consolidated into Energean’s financial statements from the date of transaction completion, which is expected later in 2020. Energean will benefit from net cash flows between the locked-box date of 1 January 2019 and the date of transaction completion through an adjustment to the variable consideration.
|
|
2020
|
Jan & Feb 2020 Performance
|
|
|
Production
|
|
|
|
|
Egypt (kboe/d)
|
32 – 37
|
40.2
|
|
|
Italy (kboe/d)
|
8 – 10
|
9.7
|
|
|
Greece (kboe/d)
|
2 – 2.5
|
2.2
|
|
|
Croatia (kboe/d)
|
0.5
|
0.3
|
|
|
Total Pro Forma Production (kboe/d)
|
42.5 – 50.0
|
52.4
|
|
|
|
|
|
|
|
Financials
|
2020
|
Discretionary Amount
|
|
|
Operating Costs & G&A ($ million)
|
225 – 250
|
–
|
–
|
|
|
|
|
|
|
Development and Production Capital Expenditure
|
|
|
|
|
|
580
|
–
|
Funded by project finance facility
|
|
|
100
|
100
|
70 million NEA/NI; $20 million Abu Qir facilities; $8 million Abu Qir wells
|
|
|
75
|
40
|
All discretionary apart from $25 million investment in Cassiopea and $10 million in Leoni
|
|
|
5
|
–
|
100% owned and operated, Epsilon investment deferred
|
|
|
10
|
–
|
Appraisal well committed, capacity to delay exists
|
|
Total Pro Forma Development & Production Capital Expenditure ($ million)
|
770
|
140
|
|
|
|
|
|
|
|
Exploration Capital Expenditure (Firm)
|
|
|
|
|
|
5
|
–
|
|
|
|
60
|
–
|
|
|
|
–
|
–
|
|
|
|
5
|
–
|
|
|
|
–
|
–
|
|
|
|
–
|
–
|
|
|
Total Pro Forma Exploration Capital Expenditure ($ million)
|
70
|
–
|
|
Financial review
Focused on maintaining strong financial discipline
Revenue, production and commodity prices
Working interest crude production from Greece averaged 3,312 bopd, a decrease of 18% for the period (2018: 4,053 bopd). The decrease in production was due to the decision to put the Prinos Area assets under strategic review following the review of capital allocation that was initiated earlier in the year. As a result, investment in Prinos and Prinos North was limited to $14.0 million during the period, while this process was being undertaken.
Prinos crude is sold at a $6.6/bbl. discount to Urals Med blend, adjusted for final cargo API. In 2019 the average sales price achieved was $58/bbl.
Depreciation, impairments and write-offs
Depreciation charges before impairment on production and development assets increased by 15% to $39.1 million (2018: $34.3 million) due to increased capital expenditure invested in Greece during 2018, along with finance lease assets’ depreciation recorded for the first time in 2019 (IFRS 16 adoption). The Group recognised a gross impairment charge of $71.1 million in 2019 (2018: $nil). In the period, indicators of impairment were noted for the Prinos CGU, being a reduction in both short-term (Dated Brent forward curve) and long-term price assumptions and a change in the Group’s Prinos field production forecast, which have resulted in an impairment of $71.1 million in the carrying value of the Prinos CGU.
Selling, general and administrative (SG&A) expenses
Energean incurred SG&A costs of $13.7 million in 2019. This represents a 13% increase on the previous year (2018: $12.1 million) and is due to the additional staffing and administrative costs associated with the continued growth of the Group’s portfolio and the efforts associated with developing the Karish project.
For the full year 2020 Energean expects stand-alone SG&A costs to be $15.0 million. Edison E&P adds an estimated additional $30 million on a pro forma basis.
Other expenses
Other expenses of $21.6 million (2018: $1.1 million) consist predominantly of the direct costs incurred in 2019 relating to the proposed acquisition of Edison’s E&P business.
Finance costs
Financing costs before capitalisation for the period were $48.9 million (2018: $22.7 million). Included within this balance is $34.4 million of interest (2018: $12.2 million), of which $7.0 million relates to interest incurred on the RBL facility and $27.4 million on the Karish project finance facility. In addition, there was $7.2 million (2018: $5.7 million) of interest expenses relating to long term payables representing future payments to the previous Karish/Tanin licence holders. This was offset by capitalised borrowing costs of $39.9 million (2018: $9.3 million). The remainder of the total finance costs expensed relate primarily to finance and arrangement fees and other finance costs and bank charges. Total finance cost expensed amounted to $9.0 million (2018: $13.5 million).
Crude oil hedging
Energean had no hedges during the period and has no outstanding crude oil hedges at year-end. Energean will keep its hedging position under review.
Taxation
Energean recorded tax income of $20.5 million in 2019 (2018: $15.5 million tax income) primarily associated with the deferred tax impact of the impairment losses associated with the Prinos assets.
Operating cash flow
Cash from operations before movements in working capital was $18.5 million (2018: $53.9 million). After adjusting for working capital movements, cash from operations was $36.3 million, a 42.1% decrease on the comparable period (2018: $62.7 million). The decrease is driven by reduced production and revenue in the period and due to $8.1 million of direct transaction costs for the proposed acquisition of Edison E&P in 2019, which have been recorded under operating activities.
Financial results summary
|
Metric
|
2019
|
2018
|
|
Av. Daily working interest production (kboed)
|
3.3
|
4.1
|
|
Sales revenue ($M)
|
75.7
|
90.3
|
|
Realised oil price ($/boe)
|
57.6
|
61.3
|
|
Cost of oil production ($m)
|
25.9
|
26.0
|
|
Cost of production per barrel ($/boe)
|
21.5
|
17.6
|
|
Administrative & selling expenses ($m)
|
13.7
|
12.1
|
|
Adjusted EBITDAX ($m)
|
35.6
|
52.4
|
|
Cash flow from operating activities ($m)
|
36.3
|
62.7
|
|
Capital expenditure ($m)
|
685.1
|
494.6
|
|
Cash capital expenditure ($m)
|
954.6
|
293.6
|
|
Net debt (cash) ($m)
|
561.6
|
(75.6)
|
|
Net debt/equity (%)
|
44.5%
|
(6.95)%
|
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 include adjusted EBITDAX, cost of oil production, capital expenditure, cash capex, net debt and gearing ratio and are explained below.
Cost of oil production
Cost of oil production is a non-IFRS measure that is used by the Group as a useful indicator of the Group’s underlying cash costs to produce hydrocarbons. The Group uses the measure to compare operational performance period to period, to monitor costs and to assess operational efficiency. Cost of oil production is calculated as cost of sales, adjusted for depreciation and hydrocarbon inventory movements.
|
|
2019
|
|
2018
|
|
$M
|
$M
|
|
Cost of sales
|
65.6
|
|
58.8
|
|
Less
|
|
|
|
|
Depreciation
|
(36.6)
|
|
(33.9)
|
|
Change in inventory
|
(2.9)
|
|
1.1
|
|
Cost of oil production
|
25.9
|
|
26.0
|
|
Total production for the period (boe)
|
1,208,978
|
|
1,479,367
|
|
Cost of oil production per boe ($)
|
21.5
|
|
17.6
|
Prinos production fell by 18% in 2019. This has resulted in a 22% increase in per barrel production costs, from $17.6/bbl. in 2018 to $21.5/bbl.
Adjusted EBITDAX
Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, other income and expenses (including the impact of derivative financial instruments and foreign exchange), net finance costs and exploration costs. The Group presents adjusted EBITDAX as it is used in assessing the Group’s growth and operational efficiencies, because it illustrates the underlying performance of the Group’s business by excluding items not considered by management to reflect the underlying operations of the Group.
|
|
2019
|
2018
|
|
Metric
|
$M
|
$M
|
|
Adjusted EBITDAX
|
35.6
|
52.4
|
|
Reconciliation to profit/(loss):
|
|
|
|
Depreciation and amortisation
|
(39.1)
|
(34.3)
|
|
Exploration and evaluation expense
|
(0.8)
|
(2.1)
|
|
Impairment loss on property, plant and equipment
|
(71.1)
|
–
|
|
Other expenses
|
(21.6)
|
(1.1)
|
|
Other income
|
3.1
|
8.9
|
|
Finance expenses
|
(9.0)
|
(13.5)
|
|
Finance income
|
2.5
|
1.7
|
|
Gain on derivative
|
–
|
96.7
|
|
Net foreign exchange
|
(3.9)
|
(23.5)
|
|
Taxation income/(expense)
|
20.5
|
15.5
|
|
(Loss)/income for the year
|
(83.8)
|
100.8
|
Capital expenditure
Capital expenditure is a useful indicator of the Group’s organic expenditure on oil and gas assets and exploration and appraisal assets incurred during a period. Capital expenditure is defined as additions to property, plant and equipment and intangible exploration and evaluation assets excluding decommissioning, capitalised depreciation, less capitalised borrowing cost.
|
|
2019
|
2018
|
|
Metric
|
$M
|
$M
|
|
Additions to property, plant and equipment
|
670.6
|
502.0
|
|
Additions to intangible exploration and evaluation assets
|
61.7
|
6.2
|
|
Less
|
|
|
|
Capitalised borrowing costs
|
(39.9)
|
(9.3)
|
|
Capitalised depreciation
|
(1.9)
|
(2.6)
|
|
Change in decommissioning provision
|
(5.4)
|
(1.8)
|
|
Total
|
685.1
|
494.6
|
Capital expenditure was $685.1 million, of which $611.9 million was invested in Israel, $68.4 million in Greece (Epsilon – $45.2 million) and $4.9 million in Montenegro.
Cash capital expenditure in 2019 was $954.5 million (FY 2018: $293.6 million).
|
|
2019
|
2018
|
|
Cash Capital Expenditure
|
$M
|
$M
|
|
Payment for purchase of property, plant and equipment
|
897.2
|
290.1
|
|
Payment for purchase of intangible assets
|
57.4
|
3.5
|
|
Total
|
954.5
|
293.6
|
Net cash/debt and gearing ratio
Net debt is defined as the Group’s total borrowings less cash and cash equivalents. Management believes that net debt is a useful indicator of the Group’s indebtedness, financial flexibility and capital structure because it indicates the level of borrowings after taking account of any cash and cash equivalents that could be used to reduce borrowings. The Group defines capital as total equity and calculates the gearing ratio as net debt divided by capital.
Net debt reconciliation
|
|
|
2019
|
|
2018
|
|
|
|
$M
|
|
$M
|
|
Net Debt
|
|
|
|
|
|
Current borrowings
|
|
38.1
|
|
–
|
|
Non-current borrowings
|
|
877.9
|
|
144.3
|
|
Total borrowings
|
|
916.0
|
|
144.3
|
|
Less: Cash and cash equivalents and bank deposits
|
(354.4)
|
(219.9)
|
|
Net (Funds)/Debt (1)
|
|
561.6
|
|
(75.6)
|
|
Total equity (2)
|
|
1,260.8
|
|
1,087.8
|
|
Gearing Ratio (1)/(2):
|
|
44.54%
|
|
(6.95%)
|
In July 2019, Energean raised $265.1 million through the issuance of new ordinary shares on LSE and TASE. Net of cash transaction costs of $8.2 million this contributed $256.9 million of cash to the Group in 2019 .
Edison E&P acquisition
In July 2019, Energean agreed to acquire Edison Exploration & Production S.p.A. from Edison S.p.A. for $750 million, to be adjusted for working capital, with additional contingent consideration of $100 million payable following first gas from the Cassiopea development (expected early 2023), offshore Italy.
Energean also agreed to sell the UK and Norwegian subsidiaries of Edison E&P to Neptune Energy for $250 million, to be adjusted for working capital, with additional contingent consideration of up to $30 million. The sale is contingent on Energean completing upon its acquisition of Edison E&P and is expected to close as soon as is reasonably practicable after close of the Edison E&P transaction.
On 23 December 2019, Energean announced that Edison S.p.A. had received a letter from the Algerian authorities, which invited Edison to discuss the transaction with Sonatrach. Energean and Edison E&P subsequently agreed to exclude the asset from the transaction perimeter. Carve out of the Algerian assets from the transaction perimeter has now been agreed in principle at an effective price of $155 million, based on an effective transaction date of 1 January 2019; the carve out remains subject to a signed, amended SPA.
Financing of the acquisition
The initial consideration was supported by a $600 million committed bridge loan facility underwritten by ING and Morgan Stanley, and S$265 million of equity financing. The total debt and equity capital raised was sized to cover both the initial consideration and working capital requirements of the enlarged group.
The bridge loan facility is expected to be replaced in 2020 using a reserve based facility and a bridge facility for the onward sale of the UK and Norwegian assets to Neptune Energy. The $100 million of contingent consideration is expected to be funded by the combined free cash flow of the Enlarged Group as well as any incremental reserve based facility capacity.
Placing
In July 2019, Energean also launched a placing with institutional investors of new ordinary shares of 1 pence each in the capital of Energean to raise up to £211 million (approximately $265 million) before expenses.
Proposed Edison E&P acquisition – 2019 financial results
During 2019, Edison E&P delivered the following financial results. These results have been prepared on the basis of Edison E&P’s accounting policies and are subject to adjustments when included in Energean’s upcoming Circular and Prospectus.
|
|
Edison E&P
|
Edison E&P exclusive of the UK, Norway and Algeria assets
|
|
|
2019 – $m
|
2019 – $m
|
|
Revenue
|
531
|
433
|
|
Operating costs
|
255
|
196
|
|
EBITDAX
|
276
|
237
|
|
Operating cash flow
|
252
|
212
|
|
Development and production capital expenditure
|
136
|
33
|
|
Exploration expenditure
|
49
|
28
|
Liquidity risk management and going concern
The Group carefully manages its risk to a shortage of funds by monitoring its funding position and its liquidity risk. Cash forecast are regularly produced and sensitivities run for different scenarios including change in Brent prices, different production rates and future capital expenditure investment profile.
Short-term cash forecasts have been stress-tested in light of the significant oil price reduction seen in early March 2020, with a primary scenario using an average price of $35.0/bbl for 2020 and $42.5/bbl for 2021, and a downside sensitivity run at $30/bbl average for both 2020 and 2021.
In this scenario, the Group would also target a further rationalisation of its cost base, including cuts to discretionary capital expenditure and operating cost. As at 31 December 2019, the Group had cash and undrawn facilities of $834.2 million million. Post-period end, Energean has also successfully increased its Israel Project Finance Facility by $175million to $1.45 billion (from $1.275 billion), providing additional headroom on its Karish development.
The Group’s revised forecasts show that the Group will be able to operate within its current debt facilities and has sufficient financial headroom for the 12 months from the date of approval of the 2019 Annual Report and Accounts. In arriving at this conclusion, the Directors also had regard to the Group’s ability to raise necessary funding as and when needed. In 2019, the Group successfully raised gross proceeds of $265.1 million through a private placement on the London and Tel Aviv Stock Exchanges. The Group also raised a $600 million bridge facility to provide funds for its acquisition of Edison E&P. The Group expects to replace this with a Reserve Based Lending (“RBL”) Facility (of up to $525m, of which between $400 and $450million is expected to be available) plus a Bridge to Disposal Facility (of up to $250million) for the sale of the UK and Norway assets to Neptune Energy. The purpose of the RBL will be to fund the acquisition, refinance the Greek RBL and provide headroom over the medium term for capital expenditure within the Group (excluding Israel).
Based on an assessment of the Group’s cash flow forecasts under various scenarios, including the identification of associated risks and mitigants, the Directors have concluded that they have a reasonable expectation that the Group will continue in operational existence for a 12 month period from the date of approval of the 2019 Annual Report and Accounts and have therefore adopted the going concern basis in preparing the Group and parent company financial statements.
Coronavirus
Energean continues to monitor the ongoing COVID-19 outbreak, accessing the advice by the World Health Organisation and Public Health England to ensure that best-practice precautions are being applied. Clear information and health precautions on how employees should protect themselves and reduce exposure to, and transmission of, a range of illnesses along with general advice has been communicated across the organization.
Coronavirus has not yet affected Energean’s operations, but in the event that the COVID-19 outbreak escalates, Energean has contingency plans in place that will be followed.
Events since 31 December 2019
Energean is exposed to macro-economic risks, including pandemic diseases that could have a material adverse effect on its operations. We continue to monitor the recent Coronavirus outbreak, which is causing global economic disruption and may impact our performance in 2020. To date, the Coronavirus has not had a material impact on Energean’s activities. However, at present, it is not possible to predict whether the outbreak will have a material adverse effect on our future earnings, cash flows and financial condition.
On 6 March 2020, OPEC and non-OPEC allies (OPEC+) met to discuss the need to cut oil supply to balance oil markets in the wake of the Coronavirus outbreak, which has had a material adverse impact on oil demand. OPEC+ failed to reach agreement and on 7 March 2020, Saudi Aramco cut its Official Selling Prices, prioritizing market share over pricing. As a result, oil prices have fallen materially, which may have a material adverse impact on the component of Energean’s future earnings that are linked to oil prices.
In January 2020, Energean reduced the size of it EBRD Reserve Based Lending Facility to $161 million.
On 16 March 2020, Energean Israel signed a $175 million increase in its project finance facility, which is now sized at $1,450 million, increasing liquidity available to the company.
|
Group Income Statement
|
|
|
|
|
|
|
|
|
|
|
|
YEAR ENDED 31 DECEMBER 2019
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
2018
|
|
|
|
|
|
Notes
|
|
$’000
|
|
|
|
|
|
$’000
|
|
|
|
Revenue
|
|
6
|
|
75,749
|
|
|
|
|
|
90,329
|
|
|
|
Cost of sales
|
|
7a
|
|
(65,552)
|
|
|
|
|
|
(60,019)
|
|
|
|
Gross profit
|
|
|
|
10,197
|
|
|
|
|
|
30,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administrative expenses
|
|
7b
|
|
(13,305)
|
|
|
|
|
|
(11,666)
|
|
|
|
Selling and distribution expenses
|
|
|
|
(345)
|
|
|
|
|
|
(453)
|
|
|
|
Exploration and evaluation expenses
|
|
|
|
(801)
|
|
|
|
|
|
(2,102)
|
|
|
|
Impairment of property, plant and equipment
|
|
10
|
|
(71,115)
|
|
|
|
|
|
–
|
|
|
|
Other expenses
|
|
7c
|
|
(21,584)
|
|
|
|
|
|
(1,118)
|
|
|
|
Other income
|
|
7d
|
|
3,095
|
|
|
|
|
|
8,869
|
|
|
|
Operating (loss)/profit
|
|
|
|
(93,858)
|
|
|
|
|
|
23,840
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Finance income
|
|
8
|
|
2,496
|
|
|
|
|
|
1,735
|
|
|
|
Finance costs
|
|
8
|
|
(9,002)
|
|
|
|
|
|
(13,471)
|
|
|
|
Gain on derivative
|
|
5
|
|
–
|
|
|
|
|
|
96,709
|
|
|
|
Net foreign exchange losses
|
|
8
|
|
(3,933)
|
|
|
|
|
|
(23,521)
|
|
|
|
(Loss)/profit before tax
|
|
|
|
(104,297)
|
|
|
|
|
|
85,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxation income
|
|
9
|
|
20,531
|
|
|
|
|
|
15,527
|
|
|
|
(Loss)/profit for the year
|
|
|
|
(83,766)
|
|
|
|
|
|
100,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attributable to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Owners of the parent
|
|
|
|
(83,313)
|
|
|
|
|
|
105,279
|
|
|
|
Non–controlling interests
|
|
|
|
(453)
|
|
|
|
|
|
(4,460)
|
|
|
|
|
|
|
|
(83,766)
|
|
|
|
|
|
100,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted total (loss)/earnings per share (cents per share)
|
|
2
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
($0.50)
|
|
|
|
|
|
$0.80
|
|
|
Diluted
|
|
|
|
($0.50)
|
|
|
|
|
|
$0.79
|
|
|
Group Statement of Comprehensive Income
|
|
|
|
|
|
|
|
|
YEAR ENDED 31 DECEMBER 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
$’000
|
|
|
|
|
|
$’000
|
|
|
Consolidated statement of comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)/profit for the year
|
|
|
|
(83,766)
|
|
|
|
|
|
100,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
Items that may be reclassified subsequently to profit or loss
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Hedge, net of tax
|
|
|
|
434
|
|
|
|
|
|
–
|
|
|
Exchange difference on the translation of foreign operations
|
|
|
|
(3,751)
|
|
|
|
|
|
(4,288)
|
|
|
|
|
|
|
(3,317)
|
|
|
|
|
|
(4,288)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Items that will not be reclassified subsequently to profit or loss
|
|
|
|
|
|
|
|
|
|
|
|
|
Remeasurement of defined benefit pension plan
|
|
|
|
(466)
|
|
|
|
|
|
(444)
|
|
|
Income taxes on items that will not be reclassified to profit or loss
|
|
|
|
117
|
|
|
|
|
|
107
|
|
|
|
|
|
(349)
|
|
|
|
|
|
(337)
|
|
|
Other comprehensive loss after tax
|
|
|
|
(3,666)
|
|
|
|
|
|
(4,625)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive (loss)/income for the year
|
|
|
|
(87,432)
|
|
|
|
|
|
96,194
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive (loss)/income attributable to:
|
|
|
|
|
|
|
|
|
|
|
|
|
Owners of the parent
|
|
|
|
(87,109)
|
|
|
|
|
|
100,856
|
|
|
Non-controlling interests
|
|
|
|
(323)
|
|
|
|
|
|
(4,662)
|
|
|
|
|
|
|
(87,432)
|
|
|
|
|
|
96,194
|
|
|
|
|
|
|
|
|
