Earnings Release • Sep 2, 2021
Earnings Release
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London, 2 September 2021 - Energean plc (LSE: ENOG TASE: אנאג (is pleased to announce its half-year results for the six months ended 30 June 2021 ("1H 2021").
"During 1H 2021, Energean delivered excellent operational and financial progress, reflecting the transformational nature of the acquisition of Edison E&P. Production is outperforming guidance, translating into record financial performance and, through successful execution of our gas- and returns-focused strategy, we have achieved a significant milestone in our transformation into a 200 kboed, \$2 billion annual revenue generating, sustainable dividend yielding, energy company. In addition, we further strengthened and de-risked our balance sheet by raising the largest ever EMEA energy international high yield bond and remain fully-funded for all projects across our nine countries of operation.
"Despite continued COVID-19 related challenges, we have delivered solid progress on our flagship Karish gas development project, which remains firmly on track to deliver first gas in mid-2022. There are a number of potential acceleration measures under active consideration and, at 31 August 2021, the workforce on the Karish project was in excess of 1,700, an approximate 70% month-on-month increase. Further growth in Israel will be delivered through our (up to) five-well offshore growth programme, with the Stena IceMax drilling rig commencing operations in 1Q-2022. The programme targets an additional 1 billion boe, which has the potential to double our reserve base with high quality resource volumes that can be quickly, economically, and safely monetised. Globally, gas prices are strong and we are assessing several commercial opportunities to access international markets, as well as the growing Israeli domestic market, if (and when) additional gas resources become available to us.
"In the second half of the year, we look forward to continuing to deliver our key gas development projects in Egypt and Italy, which alongside commencement of the revised Epsilon project in Greece, will provide further, substantial near-term growth and value realisation in the Mediterranean region.
"The recently published Intergovernmental Panel on Climate Change1 report on the impacts of global warming made for stark reading and emphasized the need for immediate action. As a business, we have taken full responsibility for our own emissions profile, showcased by publication of our first Climate Change Policy, which outlines the short, medium, and long-term actions we will take as part of our commitment to become a net zero emitter by 2050. In the first half of 2021, we reduced the carbon intensity of our operations by more than 19% versus 2020 levels2 ; representing a 73% reduction versus our base year of 2019. This is a trajectory we are committed to continuing, and we are investigating all options to accelerate our net zero commitment ahead of 2050, in recognition of the need for urgent and immediate action."
1 The Intergovernmental Panel on Climate Change (IPCC) is the United Nations body for assessing the science related to climate change
2 2020 emissions are quoted on a pro forma basis, i.e. stated as if Energean had owned Edison E&P for the full year. The transaction closed on 17 December 2020.
3 As measured under the TechnipFMC EPCIC
4 The 1bn boe is composed of a combination of CPR-estimated volumes and management estimates
5 2020 emissions are quoted on a pro forma basis, i.e. stated as if Energean had owned Edison E&P for the full year. The transaction closed on 17 December 2020
| 1H 2021 \$m |
1H 2020 \$m |
Increase / (Decrease) % |
|
|---|---|---|---|
| Average working interest production (kboed) |
44.0 | 2.1 | 1,995% |
| Sales and other revenue | 205.5 | 2.1 | 9,686% |
| Cash cost of production6 | 122.47 | 10.4 | 1,077% |
| Cash cost of production per boe | 15.4 | 27.5 | (44%) |
| Cash S,G&A6 | 17.0 | 5.4 | 215% |
| Adjusted EBITDAX8 | 74.7 | (8.9) | 939% |
| Operating cash flow9 | 53.1 | (14.5) | 466% |
| Development capital expenditure | 200.8 | 243.9 | (18%) |
| Exploration capital expenditure | 29.2 | 5.3 | 451% |
| Decommissioning expenditure | 1.7 | - | - |
| Net debt (including restricted cash) | 1,692.6 | 861.4 | 96% |
Kate Sloan, Head of IR, ECM and Communications Tel: +44 7917 608 645
A conference call for analysts and investors will be held at 08:30am BST today. Please register your participation in this morning's conference call at the following link. You will be given the option to either participate via webcast or dial in.
Webcast: https://edge.media-server.com/mmc/p/htkhfoq4 Dial-In: +44 (0) 2071 928338 Dial-in (Israel only): 35308845 Confirmation code: 5530326
6Cash Cost of production is defined in the Financial Review section
7 Including flux of \$10.3 million and purchased oil of \$2.5 million
8Cash SG&A and Adjusted EBITDAX is defined in the Financial Review section
9 After working capital movements
The presentation slides will be made available on the website shortly www.energean.com.
1H 2021 average working interest production was 44.0 kboed (72% gas), ahead of full year guidance, which is maintained at 38 – 42 kboed. This represents a substantial year-on-year increase, reflecting the transformational nature of the acquisition of Edison E&P and the successful, quick integration of the Edison E&P portfolio into Energean despite the operational challenges posed by COVID-19.
| 1H 2021 actuals | FY 2021 guidance | 1H 2020 | ||
|---|---|---|---|---|
| Kboed | Kboed | Kboed | ||
| Egypt | 31.4 | 27 - 30 | - | |
| Italy | 10.2 | 9 - 10 | - | |
| Greece and Croatia | 1.8 | 1.5 | 2.1 | |
| UK | 0.6 | 0.5 | - | |
| Total production | 44.0 | 38 - 42 | 2.1 |
Energean remains firmly on track to deliver first gas from the Karish gas development project in mid-2022. At 31 July 2021, the project was approximately 91.5% complete10 .
The next tangible milestone on the development remains sailaway of the FPSO from Singapore to Israel, currently expected in 1Q 2022. The journey from Singapore to Israel is expected to take approximately 35 days, with hook-up and pre-first gas commissioning then expected to take approximately three months.
Energean is actively working with its contractors to identify and implement potential acceleration measures for the FPSO delivery schedule, which are not reflected in the current timetable. Following agreement of an incentivisation payment of \$12 million by Energean to Sembcorp in August 2021, workforce numbers on the Energean Power FPSO have increased by approximately 70%, to more than 1,700 at 31 August 2021.
Energean will update the market on whether it expects any acceleration of the delivery timetable as and when it is appropriate to do so.
| % Completion at 31 July 202111 | |||
|---|---|---|---|
| Production Wells | 100.0 | ||
| FPSO | 96.7 | ||
| Subsea | 83.0 | ||
| Onshore | 99.8 | ||
| Total | 91.5 |
10 As measured under the TechnipFMC EPCIC
11 As measured under the TechnipFMC EPCIC
Energean has signed 18 gas sales agreements ("Agreements") for the supply of 7.2 Bcm/yr of gas on plateau, representing almost 100% of total gas reserves volumes over the life of those Agreements. All Agreements include provisions for floor pricing and take-or-pay and / or exclusivity, providing a high level of certainty over revenues from the Karish, Karish North and Tanin projects over the next 16 years.
For one Agreement representing 0.2 Bcm/yr and commencing 2024, the buyer has been unable to meet its conditions subsequent under the Agreement and the parties have mutually agreed to terminate the Agreement. This termination is not related to the project schedule. Energean has identified a potential replacement buyer for these volumes and expects to reach an Agreement shortly; Energean's main current restriction to signing further Agreements is that it has sold substantially all of its independently audited gas reserves.
One Agreement, representing 0.8 Bcm/yr of gas supply, is at potential risk of termination; however, if it is terminated, Energean has identified multiple alternative routes to monetise those gas volumes, including both domestic and international markets, and is confident of profitably selling them. Other than that one Agreement, Energean believes that all of its Agreements are robust under the current first gas delivery timetable, notwithstanding the delays experienced due to COVID-19-related circumstances.
In May 2021, Energean took FID on two high-return growth projects, offshore Israel:
In June 2021, Energean signed a rig contract with Stena for the drilling of up to five wells that will target derisking of unrisked prospective resources of over 1 Bnboe12. The contract consists of three firm wells plus two optional wells, with the first well expected to spud in 1Q 2022. The firm wells are all expected to be drilled during 2022 and consist of:
Energean is in the process of identifying and working up commercialisation options in the event of discoveries being made as part of the 2022-23 growth drilling programme and monetisation options include both domestic and international markets.
Working interest production from the Abu Qir area averaged 31.4 kboed (87% gas) during 1H 2021 with full year production guidance maintained at between 27 - 30 kboed.
The shallow-water NEA/NI satellite tie-back project is progressing in line with expectations, with first gas from one well anticipated in 2H 2022 and from the remaining three wells in 1Q 2023. The project was sanctioned in January 2021 and
12 The 1 bn boe is composed of a combination of CPR-estimated volumes and management estimates
an EPCI contract for the four subsea wells and the associated tie-back to the Abu Qir platform and associated infrastructure was awarded to TechnipFMC in 1Q 2021.
Around the Abu Qir and NEA/NI assets, Energean is maturing several near-field and infrastructure-led opportunities, including the discovered NI-B field, as potential future drilling candidates. In addition, prospect maturation continues across the wider portfolio to unlock value from the substantial prospective resource volumes identified, including in deeper liquids-rich horizons.
At 30 June 2021, net receivables (after provision for bad and doubtful debts) in Egypt were \$158.7 million (31 December 2020: \$148.8 million), of which \$94.0 million (31 December 2020: \$78.7 million) was classified as overdue. Cash collection from EGPC during the period was \$74.9 million.
Working interest production from Italy averaged 10.2 kboed (41% gas) during 1H 2021 with full year production expected to be between 9 - 10 kboed.
Production continues to outperform expectations following robust operational performance across the operated oil portfolio, including the Vega and Rospo Mare fields, in which Energean increased its working interest to 100% in January 2021 following the nil-cost acquisition from ENI.
The Cassiopea (Energean 40%) gas development project was approximately 23% complete at 31 July 2021, with works to date focused on permitting, contracting and procurement, alongside a cost optimisation programme. First gas from the project is expected in 1H 2024. Development of Cassiopea will commercialise 31 MMboe of 2P reserves (100% gas) and achieve peak production of approximately 10 kboed.
Working interest production from the Prinos field averaged 1.6 kboed (0% gas) during 1H 2021 with full year production expected to be 1.5 kboed.
In March 2021, the European Commission approved Greek state support for a EUR100 million funding package for the Prinos area, with Greek parliamentary ratification in May 2021. The full funding package is expected to be in place in 3Q 2021 with commencement of investment in the Epsilon project expected shortly thereafter.
In parallel, Energean has been evaluating a project to reinject produced carbon dioxide from Prinos back into the reservoir to reduce Scope 1 emissions from the field. The project has been approved for financial support from the European Commission's European Structural and Investment Funds ("ESIF").
Extending the life of the Prinos production area through the Epsilon development is key to Energean's longer-term ambition of leveraging its subsurface knowledge and expertise in developing CCS and eco-hydrogen projects, which are expected to be key contributors to Energean's net zero strategy.
The Prinos CCS project proposal is to provide long-term storage for carbon dioxide emissions captured from both local and more remote emitters.
In 1H 2021, Energean submitted its CCS proposal to the Greek government, with a view to inclusion within its recovery and resilience plan, projects within which will qualify to receive funding from the Recovery and Resilience fund over the period 2021-26. In June 2021, the European Commission granted approval for the inclusion of the Greek CCS project within the fund.
A pre-FEED study for the CCS project is expected to commence in 2H 2021.
1H 2021 production in the UK North Sea was 0.6 kboed (8% gas), ahead of full year guidance of 0.5 kboed.
Drilling operations at the Glengorm South appraisal well were safely completed in April 2021. The well contained no commercial hydrocarbons and the well has been plugged and abandoned. The existing Glengorm North discovery and the Glengorm Central appraisal well are considered to be independent of the Glengorm South appraisal well; the Glengorm Central appraisal well spudded in May 2021.
Energean has received interest from third parties with respect to the potential sale of its UK assets portfolio and is considering its options.
During 1H 2021, working interest production from the Izabela field averaged 0.2 kboed (100% gas).
Evaluation of the results from the Irena appraisal well are ongoing.
In 1H 2021, Energean published its first Climate Change Policy, which defines the Group's actions to deliver upon its commitment to become a net-zero emitter by 2050.
Energean also took further steps towards this commitment, and is investigating an acceleration of its 2050 net-zero target, reflecting both its commitment and the importance of the global achievement of the goal. Energean's Scope 1 and 2 carbon emissions intensity in 1H 2021 was estimated to be approximately 18 kg/boe, a 19% reduction versus 2020 emissions levels13; a 73% reduction versus the 2019 base measurement year; and approximately 15% below fullyear 2021 guidance of approximately 21 kg/boe.
Actions taken to date in 2021 include:
Energean's 2020 Annual Report and Accounts, published in April 2021, marked Energean's first period of reporting in accordance with the requirements of the Task Force on Climate Related Financial Disclosure ("TCFD").
In June 2021, MSCI updated its rating for energean to AA, up from A in the previous year.
13 2020 emissions are quoted on a pro forma basis, i.e. stated as if Energean had owned Edison E&P for the full year. The transaction closed on 17 December 2020
In July 2021, Energean was rated at gold level by Israel's Maala Index for the second year running. The Maala Index is an ESG rating system and stock market index that rates the largest companies in Israel on an annual basis.
In 1H 2021, Energean issued \$2.5 billion of senior secured notes, maturing in four tranches (2024, 2026, 2028 and 2031) and with an average coupon rate of 5.2% and increasing the average life of debt across Energean plc's portfolio to more than six years.
The funds raised were used to both ensure that Energean's projects in Israel are fully funded and also to refinance the Group's outstanding project finance facility and term loan; drawn amounts under these loans upon refinancing were \$1,270 million and \$175 million, respectively. The refinancings removed a perceived key risk on the Karish project consequent to the upcoming maturities of those facilities. \$266 million of proceeds have been used to pre-fund certain reserve accounts, classified as restricted cash within this report, with remaining proceeds earmarked for capital expenditure on the Karish and Karish North projects, the 2022/2023 Israel exploration programme, to fund bond transaction costs, outstanding amounts due to Kerogen relating to the acquisition of the minority interest in EISL, and for general corporate purposes.
| FY 2021 | |
|---|---|
| Consolidated net debt (\$ million) | 2,000 |
| Cost of Production (Operating Costs plus Royalties) | |
| - Israel (\$ million) |
- |
| - Egypt (\$ million) |
55 – 60 |
| - Italy (\$ million) |
95 – 105 |
| - Greece (\$ million) |
20 – 25 |
| - Croatia (\$ million |
5 |
| - UK North Sea (\$ million) |
20 – 25 |
| Total Cost of Production (\$ million) | 195 – 220 |
| Cash SG&A (\$ million) | 35 – 40 |
| Development and production capital expenditure | |
| - Israel (\$ million) |
350 – 400 |
| - Egypt (\$ million) |
60 – 70 |
| - Italy (\$ million) |
40 – 50 |
| - Greece and Croatia (\$ million) |
5 – 10 |
| - UK North Sea (\$ million) |
15 – 20 |
| Total Development & Production Capital Expenditure (\$ million) | 470 – 550 |
| Exploration Expenditure | |
| - Israel (\$ million) |
10 |
| - Egypt (\$ million) |
0 – 5 |
| - Italy, Greece and Croatia (\$ million) |
5 – 10 |
| - UK North Sea (\$ million) |
40 – 45 |
| Total Exploration Expenditure (\$ million) | 55 – 70 |
| Decommissioning | |
| - UK North Sea |
0 |
| - Italy |
2 - 5 |
| Decommissioning expenditure (\$ million) | 2 - 5 |
| 1H 2021 | 1H 2020 | Change | |
|---|---|---|---|
| Av. daily working interest production (kboed) | 44.0 | 2.1 | 1,995% |
| Sales revenue (\$m) | 205.5 | 2.1 | 9,686% |
| Realised oil price (\$/boe) | 47.3 | 9.1 | 419% |
| Cash cost of production14 (\$m) | 122.4 | 10.4 | 1,077% |
| Cash cost of production per barrel (\$/boe) | 15.4 | 27.5 | (44%) |
| Cash SG&A15 | 17.0 | 5.4 | 215% |
| Adjusted EBITDAX16 (\$m) | 74.7 | (8.8) | 939% |
| (Loss) after tax (\$m) | (35.7) | (77.3) | 54% |
| Cash flow from operating activities (\$m) | 53.1 | (14.5) | 466% |
| Capital expenditure (\$m) | 230.0 | 249.0 | (8%) |
| 1H 2021 | FY 2020 | Change | |
|---|---|---|---|
| Total borrowings (\$m) | 2,838.8 | 1,443.1 | 97% |
| Cash and cash equivalents and restricted cash (\$m) | 1,146.3 | 202.9 | 465% |
| Net debt / (cash) (\$m) (including restricted cash) | 1,692.6 | 1,240.1 | 36% |
| Net debt / equity (%) | 212.3% | 103.8% | 105% |
Group working interest production averaged 44.0 kboed, an increase of 1,990% for the period (1H 2020: 2.1 kboed), with the Abu Qir field, offshore Egypt, accounting for approximately 70% of total output. 1H 2021 revenue was \$205.5 million, a 9,827% increase for the period (1H 2020: \$2.1 million), primarily due to the transformational nature of the acquisition of Edison E&P, which closed on 17 December 2020.
The increase in revenue for the period primarily reflects the increased production levels of the Group following the acquisition of Edison E&P, which closed on 17 December 2020. Revenues also benefitted from a higher commodity price environment:
Depreciation charges on production and development assets before impairments increased by 184% to \$36.3 million (1H 2020: \$12.8 million) due to the higher production levels generated by the Group following the acquisition of Edison E&P, which closed on 17 December 2020.
On a per barrel of oil equivalent of production basis, this represented an 86% decrease to \$4.6/boe (1H 2020: \$33.7/boe).
14 Cash cost of production is defined later in the financial review
15 Cash SG&A is defined later in the financial review
16 Adjusted EBITDAX is defined later in the financial review. Energean uses Adjusted EBITDAX as a core business KPI.
During the period, no impairment charges were recognised (1H 2020: \$63.0 million).
Other expenses of \$3.1 million (1H 2020: \$15.8 million) include \$1.5 million of one-off transaction costs in relation to the Edison E&P acquisition (1H 2020: \$8.4 million), and expected credit losses, as well as losses from disposal of property, plant and equipment of \$0.3 million.
Other income of \$3.6 million (1H 2020: \$8.9 million) includes \$3.5 million that relate to reversal of prior period provisions and \$0.1 million of other income.
Other income in 1H 2020 included a \$5.0 million termination fee that was payable by Neptune Energy in relation to the termination of its sale and purchase agreement to buy the UK North Sea and Norwegian subsidiaries, prior to Energean's acquisition of Edison E&P, and \$3.9 million of other income related to waivers obtained for specific accounts payable balances in the Greek subsidiary.
Net finance costs in 1H 2021 were \$42.2 million (1H 2020: net finance income of \$0.8 million), composed of \$17.0 million (1H 2020: \$3.0 million) of interest on borrowings after capitalisation, \$27.9 million (1H 2020: \$0.5 million) of other debt arrangement fees and other finance costs and \$2.7 million of finance income (1H 2020: \$4.4 million). The increase in finance and other arrangement fees is due to arrangement fees for the \$700 million term loan, which was fully repaid during the period. The increase in other finance costs is primarily due to unwinding costs on the decommissioning provision, which has increased following the acquisition of Edison E&P, combined with losses incurred on interest rate derivatives.
Energean has no commodity price hedges outstanding as of 30 June 2021 (1H 2020: \$nil).
Energean recorded tax expenses of \$15.2 million in 1H 2021 (1H 2020 \$21.8 million tax income), composed of corporation tax charges amount \$22.1 million and deferred tax income of \$5.9 million. Taxation expenses in the period ended 30 June 2021 include \$21.5 million relating to taxes (non-cash in nature) being deducted at source in Egypt plus deferred amounts of \$5.9 million.
In 1H 20201, Energean recorded a cash inflow from operations before changes in working capital of \$48.6 million, versus a cash outflow of \$15.2 million in 1H 2020. After working capital movements, the cash inflow in 1H 2021 was \$53.1 million versus a cash outflow of \$14.5 million in 1H 2020. The year-on-year increase in operating cash flow has been predominantly driven by the growth in revenues delivered between the two periods. As discussed above, the increase in revenues during the period is due to i) the increased production levels of the Group following the acquisition of Edison E&P; and ii) the higher commodity price environment.
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, underlying cash cost of production and SG&A, capital expenditure, net debt and gearing.
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, share-based payment charge, impairment of property, plant and equipment, other income and expenses, net finance costs and exploration and evaluation expenses. The Group presents adjusted EBITDAX as it is used in assessing the Group's growth and operational efficiencies as 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.
| 1H 2021 \$m |
1H 2020 \$m |
|
|---|---|---|
| Adjusted EBITDAX17 | 74.7 | (8.9) |
| Reconciliation to profit / (loss): | ||
| Depreciation and amortisation | (36.3) | (12.8) |
| Share-based payment charge | (2.3) | (1.2) |
| Impairment losses | - | (63.0) |
| Exploration and evaluation expense | (1.0) | (0.5) |
| Other expenses | (3.1) | (15.8) |
| Other income | 3.6 | 8.9 |
| Finance income | 2.7 | 4.4 |
| Finance cost | (44.9) | (3.6) |
| Net foreign exchange gain/(loss) | (13.9) | (6.6) |
| Taxation income / (expense) | (15.2) | 21.8 |
| Profit / (loss) from continuing operations | (35.7) | (77.3) |
Cash Cost of 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-toperiod, to monitor cost and assess operational efficiency. Cash cost of production is calculated as cost of sales, adjusted for depreciation and hydrocarbon inventory movements.
| 1H 2021 \$m |
1H 2020 \$m |
|
|---|---|---|
| Cost of sales | 147.6 | 17.9 |
| Less: | ||
| Depreciation | 33.8 | 11.6 |
| Change in inventory | (8.6) | (4.1) |
| Cost of production | 122.4 | 10.4 |
| Total production for the period (MMboe) | 7.9 | 0.4 |
| Cost of production per boe (\$/boe) | 15.4 | 27.5 |
Cash SG&A eliminates certain non-cash accounting adjustments to the Group's SG&A. Underlying cash SG&A is defined as Administrative and Selling and distribution expenses, excluding depletion and amortisation of assets and share-based payment charge that are included in SG&A.
| 1H 2021 | 1H 2020 | |
|---|---|---|
| \$m | \$m | |
| Administrative expenses | 21.7 | 6.9 |
| Selling and distribution expenses | 0.1 | 0.1 |
| Less: | ||
| Depreciation | 2.5 | 0.4 |
| Share-based payment charge included in SG&A | 2.3 | 1.2 |
| Cash SG&A | 17.0 | 5.4 |
17 Adjusted EBITDAX calculation has been changed to exclude the impact of the non-cash item of share-based payment charges. This adjustment is aligned with the underlying Group's adjusted EBITDAX calculation which excludes the impact of costs which tend to be one-off in nature and the non-cash costs. Comparative EBITDAX has been restated accordingly.
Energean incurred Cash S,G&A costs of \$17.0 million in 1H 2021. This represents a 216% increase versus the comparable period last year (1H 2020: \$5.4 million) and is due to increased staffing and administrative costs following the acquisition of Edison E&P and efforts associated with developing the Group's portfolio of projects.
Capital Expenditure is defined as additions to property, plant and equipment and intangible exploration and evaluation assets, cash lease payments made in the period, less lease asset additions, asset additions due to decommissioning provisions, capitalised share-based payment charge, capitalised borrowing costs and certain other non-cash adjustments. The Directors believe that capital expenditure is a useful indicator of the Group's organic expenditure on oil and gas development assets, exploration and evaluation assets incurred during a period because it eliminates certain accounting adjustments such as capitalised borrowing costs and decommissioning asset additions.
| 1H 2021 | 1H 2020 | |
|---|---|---|
| \$m | \$m | |
| Additions to property, plant and equipment | 317.8 | 279.8 |
| Additions to intangible exploration and evaluation assets | 30.3 | 6.8 |
| Less: | ||
| Capitalised borrowing cost | 114.0 | 40.6 |
| Leased assets additions and modifications | 12.3 | 0.9 |
| Lease payments related to capital activities | (5.8) | (4.7) |
| Capitalised share-based payment charge | 0.2 | 0.0 |
| Capitalised depreciation | 0.1 | 0.3 |
| Change in environmental rehabilitation provision | (2.5) | 0.5 |
| Total capital expenditures | 230.0 | 249.0 |
| Movement in working capital | (60.0) | (5.8) |
| Cash capital expenditures per the cash flow statement | 170.0 | 243.218 |
The breakdown of capital expenditures during 1H 2021 and 1H 2020 was as follows:
| 1H 2021 | 1H 2020 | |
|---|---|---|
| Capital expenditure | Capital expenditure | |
| \$m | \$m | |
| Development and Production | ||
| Israel | 161.8 | 235.3 |
| Egypt | 17.5 | - |
| Italy | 11.4 | - |
| Greece & Croatia | 3.8 | 2.5 |
| UK | 5.3 | - |
| Other | 1.0 | 1.0 |
| Total | 200.8 | 243.5 |
| Exploration and Appraisal | ||
| Israel | 3.7 | 4.8 |
| Egypt | 0.3 | - |
| Italy | 2.0 | - |
| Greece & Croatia | 0.4 | 0.3 |
| UK | 22.5 | - |
| Other | 0.3 | 0.4 |
| Total | 29.2 | 5.5 |
18 Numbers may not sum due to rounding
Net debt is defined as the Group's total borrowings less cash and cash equivalents and restricted cash held for loan repayments. 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 | 1H 2021 | 1H 2020 |
|---|---|---|
| \$m | \$m | |
| Current borrowings | 19.0 | 38.0 |
| Non-current borrowings | 2,819.8 | 1,055.8 |
| Total borrowings | 2,838.8 | 1,093.9 |
| Less: Cash and cash equivalents | 880.0 | 232.5 |
| Restricted cash held for loan repayment | 266.2 | - |
| Net (Funds)/Debt19 | 1,692.6 | 861.4 |
| Total equity | 797.5 | 1,184.7 |
| Gearing ratio | 212.3% | 72.7% |
On 13 January 2021, Energean signed an 18-month, \$700 million term loan facility agreement with J.P. Morgan AG and Morgan Stanley Senior Funding, Inc, the primary uses of which were to accelerate the Karish North development and to fund the up-front consideration for the acquisition of the minority interest in Energean Israel. At the same time, Energean also agreed with the existing lenders of its \$1.45 billion project finance facility to extend its maturity by nine months, from December 2021 to September 2022. This term loan was refinanced using proceeds from the bond issuance discussed below.
On 24 March 2021, Energean Israel Finance Limited issued a \$2.5 billion bond, split into four equal tranches with maturities in 2024, 2026, 2028 and 2031.
On 29 April 2021, the gross proceeds were released from a segregated escrow account following the satisfaction of release conditions, including the receipt of regulatory approvals and the registration of certain pledges. Part of the proceeds from the issuance were used to refinance the term loan (discussed above) and Energean Israel's \$1.45 billion project finance facility. As at the date of refinancing, drawn amounts under the term loan and project finance facility were \$175 million and \$1,270 million, respectively.
Effective risk management is fundamental to achieving Energean's strategic objectives and protecting its personnel, assets, shareholder value and reputation. The Board has overall responsibility for determining the nature and extent of the risks it is willing to take in achieving the strategic objectives of the Group and ensuring that such risks are managed effectively. A key aspect of this is ensuring the maintenance of a sound system of internal control and risk management. For all the known risks facing the business, Energean attempts to minimise the likelihood and mitigate the impact. Energean has a zero-tolerance approach to financial fraud or ethics non-compliance and ensures that HSE risks are managed to levels that are as low as reasonably practicable.
The Group's principal risks for the remaining 6 months of the year and key changes since 31 December 2020 are set out below. For further information on key risks, please refer to Energean's 2020 Annual Report and Accounts:
#1 Progress key development projects in Israel
19 Inclusive of restricted cash
Principal risk: Delay to first gas at Karish.
1H 2021 movement: This risk increased in 1H 2021. Following the re-introduction of enhanced COVID-19 related restrictions in Singapore for part of 1H 2021, the Energean Power FPSO is now expected to sailaway from Singapore to Israel in 1Q 2022 with first gas in mid-2022.
Energean is working on a number of contingency measures in the event that there are further outbreaks and variants of COVID-19 in Singapore that lead to the reintroduction of measures that could impact upon the first gas timetable.
Project completion has now reached 91.5% as of 31 July 2021; the closer to completion the project gets, the lower the risk of material delays. Energean is working with its contractors to ensure completion of the project as soon as is possible.
Principal risk: The potential for Israeli gas market oversupply may result in offtake being at the take-or-pay level of existing gas sales and purchase agreements and could result in the failure to secure new GSPAs.
1H 2021 movement: This risk increased in 1H 2021. The market environment is competitive, and the Leviathan field continues to increase its supply of gas, alongside production from Tamar, contributing to market oversupply and a decline in Israeli domestic gas prices towards the price floor set by Energean. Nevertheless, Energean's gas sales and purchase agreements continue to remain the most commercially attractive supply option to domestic gas buyers in Israel, with a weighted average gas price of approximately \$4.0/MMbtu.
Principal risk: Delayed delivery of future development projects (including NEA / NI in Egypt, Cassiopea in Italy and Karish North in Israel).
1H 2021 movement: This risk decreased in 1H 2021. Energean has made good progress on its Karish North (Israel) and NEA/NI (Egypt) gas developments since taking FID in January 2021, with both projects on schedule and on budget and with no delays envisaged. The Cassiopea project was approximately 23% complete at 31 July 2021 and first gas continues to be expected in 1H 2024. The passage of time and delivery of projects in line with expectations is the key driver of the reduction in this risk.
Principal risk: Lack of new commercial discoveries and reserves replacement.
1H 2021 movement: This risk remained static in 1H 2021. Energean has developed a well-defined exploration plan for its 2022-23 drilling programme, offshore Israel, which will target the derisking of unrisked prospective recoverable resources of over 1 Bnboe. In May 2021, the Company signed a contract with Stena at an attractive day rate for the drilling of three firm wells and two optional wells, with the first well expected to spud in 1Q 2022.
Principal risk: Failure to successfully integrate Edison E&P into Energean's day-to-day business activities resulting in limited financial, social and environmental benefits.
1H 2021 movement: This risk decreased in 1H 2021. Energean continues to successfully implement its integration roadmap and has identified areas of synergy across the combined business. Implementation of the end-state operating model remains on target for year-end 2021.
Principal risk: Underperformance at core producing assets in Egypt and Italy.
1H 2021 movement: This risk decreased in 1H 2021. Production continues to outperform following robust operational performance across Energean's combined portfolio. Working interest production averaged 44.0 kboed in 1H 2021, around 10% above the mid-point of guidance of 38 - 42 kboed.
Principal risk: Misalignment with JV operators.
1H 2021 movement: This risk decreased in 1H 2021, due to Energean's increased working interest position in the Vega and Rospo Mare fields, offshore Italy, following the acquisition from ENI, plus good progress having been made on the Cassiopea project, offshore Italy.
Principal risk: Insufficient liquidity and funding capacity.
1H 2021 movement: This risk decreased in 1H 2021. In April 2021, the \$1.45 billion project finance facility and \$700 million term loan were refinanced following a \$2.5 billion issuance of senior secured notes. The bond is split into four equal tranches with maturities in 2024, 2026, 2028 and 2031. This optimised debt structure substantially extends the maturity profiles and provides additional near-term flexibility to the Group. Strengthening of commodity prices also helped to decrease this risk.
Principal risk: Recoverability of revenues and receivables in Egypt.
1H 2021 movement: This risk remained static in 1H 2021. Cash collection from EGPC during the period was \$74.9 million. This was approximately \$10 million lower than expected cash collection, the difference being primarily due to timing of collection.
Principal risk: Higher than expected decommissioning costs and acceleration of abandonment schedules
1H 2021 movement: This risk remained static in 1H 2021. No additional decommissioning liabilities were incurred yearto-date and Energean is working on reducing decommissioning liabilities
#1 Failure to manage the risk of climate change and to adapt to the energy transition
Principal risk: Climate change policy, technological development, changing consumer behaviour and reputational damage.
1H 2021 movement: This risk increased in 1H 2021. The climate change agenda is an ever-increasing area of focus globally and is of critical importance to Energean as it evolves the business and works towards achieving its 2050 net zero target with respect to Scope 1 and 2 emissions. Failure to progress this target could impact the commerciality of the portfolio, lead to loss of licence to operate and result in limited access to/increased cost of capital.
Energean mitigates this risk through ongoing monitoring of key performance indicators by Management. Progress demonstrated in 2021 includes:
Principal risk: Disruption to operations and/or development projects due to severe weather (both acute and chronic).
1H 2021 movement: This risk remained static in 1H 2021.
Principal risk: Political and fiscal uncertainties in the Eastern Mediterranean.
1H 2021 movement: This risk remained static in 1H 2021.
Principal risk: Operational uncertainties and HSE incidents due to COVID-19 pandemic.
1H 2021 movement: This risk remained static in 1H 2021.
Energean faces a number of uncertainties that have the potential to be material to its long-term strategy but cannot be fully defined as a specific risk at present, and therefore cannot be fully assessed or managed. These emerging risks typically have a long-time horizon, such as earlier and increased decommissioning liabilities in the UK and Italy, and elsewhere where the Company operates; increased calls for cash or letter of credit guarantees to be put in place; inadequate management of reserves and production risk resulting in poor returns and impairment.
In 1H 2021, the Group identified the increasing threat from misalignment of national and regional energy transition legislation and direct impacts from unanticipated business interruption, for example due to production downtime or oneoff events, emerging risks that will be actively assessed and monitored.
During August 2021 and in accordance with the GSPAs signed with a group of gas buyers, the Group has agreed to pay compensation to these counterparties due to the fact the gas supply date is taking place beyond a certain date as defined in the GSPAs (being 30 June 2021). The compensation will be paid on a monthly basis starting on August 2021 and is estimated at approx. US\$23 million. The compensation is accounted as variable purchase consideration under IFRS 15 hence recognised once production commences and gas is delivered to the offtakers
During August 2021 a gas buyer sent a request to the International Court of Arbitration ("ICC") asking for arbitration on its rights of termination due to the fact the gas supply date is taking place beyond a certain date which defined in the GSPA. If the agreement it is terminated, the Group has identified multiple alternative routes to monetise those gas volumes (being 0.8 Bcm/yr), including both domestic and international markets, and hence is confident of profitably selling them
The Group carefully manages its risk to a shortage of funds by monitoring its funding position and its liquidity risk. The going concern assessment covers for the period to 30 September 2022 'the Forecast Period'.
Cash forecasts are regularly produced based on, inter alia, the Group's latest life of field production and budgeted expenditure forecasts, management's best estimate of future commodity prices (based on recent published forward curves) and the Group's borrowing facilities. The Base Case conservatively assumes first gas from Karish in July 2022, Brent at \$70/bbl for the period 1 September to 31 December 2021 and \$65/bbl for the period 1 January to 30 September 2022, PSV (Italian gas price) at an average of EUR25/MWH for the period 1 September 2021 to 31 December 2021 and EUR20/MWH for the period January 2022 to 30 September 2022.
In addition, on a regular basis, the Group performs sensitivity tests of its liquidity position for negative impacts that may result from changes to the macro-economic environment such as a fall in commodity price or increase in interest rate. The Group also looks at the impact of changes or deferral of key projects and/or portfolio rationalisation. This is done to identify risks to liquidity and covenant compliance and enable management to formulate appropriate and timely mitigation strategies in order to manage the risk of funding shortfalls or covenant breaches and to safeguard the Group's ability to continue as a going concern.
Specifically, the Group tested the following sensitivities:
delay in Israel first gas by 3 months to October 2022, which Energean management believes has a low probability of occurring given the acceleration and mitigation measures currently under consideration and the evolution of the COVID-19 situation
The Group also ran a reverse stress test to stress the combination of lower Brent price, lower PSV (Italian Gas Price) and reduced collection of EGPC receivables and assess the impact of this combination on the Group's liquidity and covenants associated with its banking facilities. Energean believes that this combination of scenarios holds a low probability of occurrence.
Should a more extreme downside scenario occur, appropriate mitigating actions that are in management's control and can be executed in the necessary timeframe could be taken such as a tightening of operating cost and reductions/postponement of other discretionary exploration and development expenditures. The Group's cash and cash equivalents at 30 June 2021 were \$880 million (excluding restricted cash amounts of \$266 million).
In terms of the Group's Borrowing Facilities, the following was considered in the context of the Group's liquidity and covenant compliance over the Forecast Period.
Consistent with the Group's plans to implement new financing as the Karish development approaches first gas in mid-2022, Energean issued a \$2.5 billion Bond to (i) refinance its \$1.45 billion Project Finance Facility (ii) cancel and replace the \$700m Term Loan which was drawn to fund the acquisition of Kerogen's minority interest in Energean Israel, (iii) fund future capital and exploration expenditure in Israel, including Karish and Karish North and (iv) for general corporate purposes of the Group. On 29 April 2021 the Group satisfied the escrow release conditions, as a result the proceeds of the Offering were released from the escrow account.
In March 2021, the Group agreed a waiver with its lenders under the EBRD reserve-based lending facility whereby there are no more Borrowing Base redeterminations and the facility effectively converts to an amortising term loan with repayments weighted towards the second half of 2022 to 2024. Covenants under the Subordinated Loan Agreement are also waived until December 2022.
The current Borrowing Base redetermination is expected to be completed in September 2021. Given the strong commodities prices and the higher production achieved from the Borrowing Base Assets we do not expect any reduction to the Borrowing Base when the redetermination exercise is completed.
In forming an assessment on the Group's ability to continue as a going concern and its review of the forecasted cashflow of the Group over the Forecast Period (from the date of approval of the interim condensed consolidated financial statements) the Board has made significant judgements about:
After careful consideration, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future, for a period up to 30 September 2022. For this reason, they continue to adopt the going concern basis in preparing the consolidated financial statements.
The Directors confirm that to the best of their knowledge:
1) The condensed set of financial statements has been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted in the UK;
Mathios Rigas Panos Benos
Chief Executive Officer Chief Financial Officer 01 September 2021 01 September 2021
This announcement contains statements that are, or are deemed to be, forward-looking statements. In some instances, forward-looking statements can be identified by the use of terms such as "projects", "forecasts", "anticipates", "expects", "believes", "intends", "may", "will" or "should" or, in each case, their negative or other variations or comparable terminology. Forward-looking statements are subject to a number of known and unknown risks and uncertainties that may cause actual results and events to differ materially from those expressed in or implied by such forward-looking statements, including, but not limited to: general economic and business conditions; demand for the Company's products and services; competitive factors in the industries in which the Company operates; exchange rate fluctuations; legislative, fiscal and regulatory developments; political risks; terrorism, acts of war and pandemics; changes in law and legal interpretations; and the impact of technological change. Forward-looking statements speak only as of the date of such statements and, except as required by applicable law, the Company undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise. The information contained in this announcement is subject to change without notice.
We have been engaged by Energean plc (the Company) to review the condensed set of financial statements in the halfyearly financial report for the six months ended 30 June 2021 which comprises the consolidated income statement, the consolidated statement of comprehensive income, the consolidated statement of financial position, the consolidated statement of changes in equity, the consolidated statement of cash flows and the related explanatory notes 1 to 29. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.
Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2021 is not prepared, in all material respects, in accordance with UK adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
We conducted our review in accordance with International Standard on Review Engagements 2410 (UK and Ireland) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
As disclosed in note 2, the annual financial statements of the Group will be prepared in accordance with UK adopted IFRSs. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with UK adopted International Accounting Standard 34, "Interim Financial Reporting".
The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
In reviewing the half-yearly report, we are responsible for expressing to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report. Our conclusion is based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report.
This report is made solely to the Company in accordance with guidance contained in International Standard on Review Engagements 2410 (UK and Ireland) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company, for our work, for this report, or for the conclusions we have formed.
Ernst & Young LLP London 1 September 2021
| 30 June (Unaudited) | |||
|---|---|---|---|
| 2021 | 2020 | ||
| \$'000 | \$'000 | ||
| Notes | |||
| Revenue | 5 | 205,466 | 2,070 |
| Cost of Sales | 6(a) | (147,640) | (17,934) |
| Gross profit/(loss) | 57,826 | (15,864) | |
| Administrative expenses | 6(b) | (21,668) | (6,853) |
| Selling and distribution expenses | 6(c) | (102) | (72) |
| Exploration and evaluation expenses | 6(d) | (1,041) | (529) |
| Impairment of property, plant and equipment | 11 | - | (63,005) |
| Other expenses | 6(e) | (3,071) | (15,843) |
| Other income | 6(f) | 3,571 | 8,914 |
| Operating profit/(loss) | 35,515 | (93,252) | |
| Finance Income | 7 | 2,700 | 4,383 |
| Finance Costs | 7 | (44,912) | (3,563) |
| Net foreign exchange loss | 7 | (13,787) | (6,637) |
| Loss before tax | (20,484) | (99,069) | |
| Taxation income / (expense) | 9 | (15,174) | 21,801 |
| Loss from continuing operations | (35,658) | (77,268) | |
| Attributable to: | |||
| Owners of the parent | (35,550) | (76,826) | |
| Non-controlling Interests | (108) | (442) | |
| (35,658) | (77,268) | ||
| Basic and diluted total loss per share (cents per share) | |||
| Basic | 10 | (\$0.20) | (\$0.43) |
| Diluted | 10 | (\$0.20) | (\$0.43) |
| 2021 2020 \$'000 \$'000 Loss for the period (35,658) (77,268) Other comprehensive income: Items that may be reclassified subsequently to profit or loss Cash Flow hedges Gain/(loss) arising in the period 2,278 (11,530) Reclassification to profit and loss upon repayment of related borrowings 4,641 - Income tax relating to items that may be reclassified to profit or loss (1,591) 2,652 Exchange difference on the translation of foreign operations, net of tax (6,576) (1,075) Other comprehensive profit/(loss) after tax (1,248) (9,953) Total comprehensive loss for the period (36,906) (87,221) Total comprehensive loss attributable to: Owners of the parent (36,800) (84,116) Non-controlling Interests (106) (3,105) |
30 June (Unaudited) | |||
|---|---|---|---|---|
| (36,906) | (87,221) |
| 30 June 2021 (Unaudited) |
31 December 2020 |
|||
|---|---|---|---|---|
| Notes | \$'000 | \$'000 | ||
| ASSETS | ||||
| Non-current assets | ||||
| Property, plant and equipment | 11 | 3,375,231 | 3,107,272 | |
| Intangible assets | 12 | 286,201 | 275,816 | |
| Equity-accounted investments | 4 | 4 | ||
| Other receivables | 17 | 31,552 | 31,568 | |
| Deferred tax asset | 13 | 128,498 | 126,056 | |
| Restricted cash | 15 | 100,000 | - | |
| 3,921,486 | 3,540,716 | |||
| Current assets | ||||
| Inventories | 16 | 78,016 | 73,019 | |
| Trade and other receivables | 17 | 281,985 | 318,339 | |
| Restricted cash | 15 | 166,241 | - | |
| Cash and cash equivalents | 14 | 880,017 | 202,939 | |
| 1,406,259 | 594,297 | |||
| Total assets | 5,327,745 | 4,135,013 | ||
| EQUITY AND LIABILITIES | ||||
| Equity attributable to owners of the parent | ||||
| Share capital | 18 | 2,368 | 2,367 | |
| Share premium | 18 | 915,388 | 915,388 | |
| Merger reserve | 139,903 | 139,903 | ||
| Other reserve | 17,577 | 1,792 | ||
| Foreign currency translation reserve | (6,618) | (42) | ||
| Share-based payment reserve | 15,893 | 13,419 | ||
| Retained earnings | (294,063) | (144,734) | ||
| Equity attributable to equity holders of the parent | 790,448 | 928,093 | ||
| Non-controlling interests | 19 | - | 266,299 | |
| Total equity | 790,448 | 1,194,392 | ||
| Non-current liabilities | ||||
| Borrowings | 20 | 2,819,809 | 330,092 | |
| Deferred tax liabilities | 13 | 70,151 | 68,609 | |
| Retirement benefit liability | 21 | 6,695 | 7,839 | |
| Provisions | 22 | 855,004 | 881,535 | |
| Other payables | 23 | 348,818 | 177,193 | |
| 4,100,477 | 1,465,268 | |||
| Current liabilities | ||||
| Trade and other payables | 23 | 402,420 | 355,454 | |
| Current portion of borrowings | 20 | 19,020 | 1,112,984 | |
| Derivative financial instruments | 8 | 2,405 | 6,915 | |
| Provisions | 22 | 12,975 | - | |
| 436,820 | 1,475,353 | |||
| Total liabilities | 4,537,297 | 2,940,621 | ||
| Total equity and liabilities | 5,327,745 | 4,135,013 |
| Share Capital \$'000 |
Share Premium20 \$'000 |
Other Reserve21 \$'000 |
Equity component of convertible bonds22 \$'000 |
Share based payment reserve23 \$'000 |
Translation Reserve24 \$'000 |
Retained earnings \$'000 |
Merger reserve \$'000 |
Total \$'000 |
Non Controlling Interests \$'000 |
Total \$'000 |
|
|---|---|---|---|---|---|---|---|---|---|---|---|
| At 1 January 2021 | 2,367 | 915,388 | 1,792 | - | 13,419 | (42) | (144,734) | 139,903 | 928,093 | 266,299 | 1,194,392 |
| Loss for the period | - | - | - | - | - | - | (35,550) | - | (35,550) | (108) | (35,658) |
| Hedges, net of tax Exchange difference on the translation of |
- | - | 5,326 | - | - | - | - | - | 5,326 | 2 | 5,328 |
| foreign operations | - | - | - | - | - | (6,576) | - | - | (6,576) | - | (6,576) |
| Total | |||||||||||
| comprehensive income |
- | - | 5,326 | - | - | (6,576) | (35,550) | - | (36,800) | (106) | (36,906) |
| Transactions with owners of the company |
|||||||||||
| Employee share schemes (note 24) Acquisition of non |
1 | - | - | - | 2,474 | - | - | - | 2,475 | 2,475 | |
| controlling Interests25 |
- | - | - | 10,459 | - | - | (113,779) | - | (103,320) | (266,193) | (369,513) |
| At 30 June 2021 | 2,368 | 915,388 | 7,118 | 10,459 | 15,893 | (6,618) | (294,063) | 139,903 | 790,448 | - | 790,448 |
20 The share premium account represents the total net proceeds on issue of the Company's shares in excess of their nominal value of £0.01 per share less amounts transferred to any other reserves.
21 Other reserves are used to recognise remeasurement gain or loss on cash flow hedges and actuarial gain or loss from the defined retirement benefit plan.
22 Refer to note 19
23 The share-based payments reserve is used to recognise the value of equity-settled share-based payments granted to parties including employees and key management personnel, as part of their remuneration.
24 The foreign currency translation reserve is used to record unrealised exchange differences arising from the translation of the financial statements of entities within the Group that have a functional currency other than US dollar.
25 Represents the acquisition of the remaining 30% minority interest in Energean Israel Limited from Kerogen Investments No.38 Limited, for more details please refer to note 19
| Share Capital \$'000 |
Share Premium18 \$'000 |
Other Reserve19 \$'000 |
Share based payment reserve21 \$'000 |
Translation Reserve22 \$'000 |
Retained earnings \$'000 |
Merger reserve23 \$'000 |
Total \$'000 |
Non Controlling Interests \$'000 |
Total \$'000 |
|
|---|---|---|---|---|---|---|---|---|---|---|
| At 1 January 2020 | 2,367 | 915,388 | 5,862 | 10,094 | (19,264) | (53,320) | 139,903 | 1,001,030 | 259,722 | 1,260,752 |
| Loss for the period | - | - | - | - | - | (76,825) | - | (76,825) | (442) | (77,267) |
| Cash flow hedge, net of tax Exchange difference on the |
- | - | (6,215) | - | - | - | - | (6,215) | (2,663) | (8,878) |
| translation of foreign operations | - | - | - | - | (1,075) | - | - | (1,075) | - | (1,075) |
| Total comprehensive income | - | - | (6,215) | - | (1,075) | (76,825) | - | (84,115) | (3,105) | (87,220) |
| Transactions with owners of the | ||||||||||
| company Share capital increase in |
- | - | - | - | - | - | - | - | - | - |
| subsidiary | - | - | - | - | - | - | - | - | 9,750 | 9,750 |
| Employee share schemes (note 24) |
- | - | - | 1,363 | - | - | - | 1,363 | - | 1,363 |
| At 30 June 2020 | 2,367 | 915,388 | (353) | 11,457 | (20,339) | (130,145) | 139,903 | 918,278 | 266,367 | 1,184,645 |
| 30 June (Unaudited) | ||||||
|---|---|---|---|---|---|---|
| 2021 | 2020 | |||||
| Note | \$'000 | \$'000 | ||||
| Operating activities | ||||||
| Loss before taxation | (20,484) | (99,069) | ||||
| Adjustments to reconcile profit/(loss) before taxation to net cash provided by operating activities: |
||||||
| Depreciation, depletion and amortisation | 11, 12 | 36,343 | 12,787 | |||
| Impairment loss on property, plant and equipment | 11 | - | 63,005 | |||
| Impairment on asset held for sale | 11 | - | 4,935 | |||
| Loss from the sale of property, plant and equipment | 36 | - | ||||
| Defined benefit expenses | 21 | (1,120) | (192) | |||
| Finance income | 7 | (2,700) | (4,383) | |||
| Finance costs | 7 | 44,912 | 3,563 | |||
| Non-cash revenues from Egypt26 | (21,577) | - | ||||
| Other liabilities derecognised | 6(f) | - | (3,839) | |||
| Movement in provisions | 22 | 483 | - | |||
| Other income | 6 | (3,602) | - | |||
| Share-based payment charge | 24 | 2,474 | 1,332 | |||
| Net foreign exchange gain/(loss) | 7 | 13,787 | 6,637 | |||
| Cash flow from/(used in) operations before working capital adjustments |
48,552 | (15,224) | ||||
| Increase in inventories | (5,185) | (4,012) | ||||
| Decrease in trade and other receivables | 42,392 | 4,565 | ||||
| (Decrease)/Increase in trade and other payables | (33,082) | 225 | ||||
| Cash inflow/(outflow) from operations | 52,677 | (14,446) | ||||
| Income tax paid | 388 | (55) | ||||
| Net cash inflow/(outflow) from operating activities | 53,065 | (14,501) | ||||
| Investing activities | ||||||
| Payment for purchase of property, plant and equipment | (141,182) | (231,178) | ||||
| Payment for exploration and evaluation, and other | (28,818) | (12,077) | ||||
| intangible assets | ||||||
| Acquisition of a subsidiary | 4 | (3,335) | - | |||
| Movement in restricted cash | 15 | (266,241) | - | |||
| Proceeds from disposal of property, plant and | - | 150 | ||||
| equipment | ||||||
| Interest received | 861 | 470 | ||||
| Net cash used in investing activities | (438,715) | (242,635) | ||||
| Financing activities | ||||||
| Drawdown of borrowings | 20 | 293,000 | 200,000 | |||
| Repayment of borrowings | 20 | (1,452,509) | (19,021) | |||
| Senior secured notes Issuance | 20 | 2,500,000 | - | |||
| Transaction costs related to Senior secured notes paid | (37,218) | - | ||||
| Proceeds from capital increases by non-controlling | 19 | - | 9,750 | |||
| interests | ||||||
| Acquisition of non-controlling interests | 19 | (175,000) | - |
26 Non-cash revenues from Egypt arise due to taxes being deducted at source from invoices as such revenue and tax charges are grossed up to reflect this deduction but no cash inflow or outflow results.
| 30 June (Unaudited) | |||||
|---|---|---|---|---|---|
| 2021 | 2020 | ||||
| Note | \$'000 | \$'000 | |||
| Transaction costs related to acquisition of non-controlling interest |
(1,677) | - | |||
| Repayment of obligations under leases | (5,875) | (4,713) | |||
| Finance cost paid for deferred license payments | (3,494) | (3,993) | |||
| Finance costs paid | (55,641) | (40,367) | |||
| Net cash inflow from financing activities | 1,061,586 | 141,656 | |||
| Net increase / (decrease) in cash and cash equivalents | 675,936 | (115,480) | |||
| Cash and cash equivalents at beginning of the period | 202,939 | 354,419 | |||
| Effect of exchange rate fluctuations on cash held | 1,142 | (6,480) | |||
| Cash and cash equivalents at end of the period | 14 | 880,017 | 232,459 |
Energean plc (the 'Company') was incorporated in England & Wales on 8 May 2017 as a public company with limited liability, under the Companies Act 2006. Its registered office is at 44 Baker Street, London W1U 7AL, United Kingdom. The Company and all subsidiaries controlled by the Company, are together referred to as "the Group".
The Group has been established with the objective of exploration, production and commercialisation of crude oil and natural gas in Greece, Israel, North Africa and the wider Eastern Mediterranean.
The Group's core assets and subsidiaries as of 30 June 2021 are presented in note 29.
As a result of the UK's withdrawal from the European Union on 31 December 2020, the financial statements of the Group for the year ending 31 December 2021 will be prepared under UK-adopted International Accounting Standards. Accordingly, the unaudited condensed consolidated interim financial statements for the six months ended 30 June 2021 included in this interim report have been prepared in accordance with UK-adopted International Accounting Standard 34 'Interim Financial Reporting', and unless otherwise disclosed have been prepared on the basis of the same accounting policies and methods of computation as applied in the Group's Annual Report for the year ended 31 December 2020.
The interim condensed consolidated financial statements have been prepared on a historical cost basis and are presented in US Dollars, which is also the Company's functional currency, rounded to the nearest thousand dollars (\$'000) except as otherwise indicated.
The US dollar is the currency that mainly influences sales prices and revenue estimates, and also highly affects the Group's operations. The functional currencies of the Group's main subsidiaries are as follows: for Energean E&P Holdings Ltd, Energean Oil & Gas S.A, Energean Montenegro, Energean Italy Spa and Energean International E&P Spa, is Euro, for Energean International Limited, Energean Capital Ltd, Energean Egypt Ltd and Energean Israel Limited is US\$.
Comparative figures for the period to 30 June 2020 and 31 December 2020 are for the period ended on that date.
The interim financial statements do not constitute statutory accounts of the Group within the meaning of Section 435 of the Companies Act 2006 and do not include all the information and disclosures required in the annual financial statements. The interim financial statements should be read in conjunction with the Group's Annual Report and Accounts for the year ended 31 December 2020, which were prepared in accordance with IFRSs in conformity with the requirements of the Companies Act 2006 and which have been filed with the Registrar of Companies. The auditor's report on those financial statements was unqualified with no reference to matters to which the auditor drew attention by way of emphasis and no statement under s498(2) or s498(3) of the Companies Act 2006.
The Group carefully manages its risk to a shortage of funds by monitoring its funding position and its liquidity risk. The going concern assessment covers for the period to 30 September 2022 'the Forecast Period'.
Cash forecasts are regularly produced based on, inter alia, the Group's latest life of field production and budgeted expenditure forecasts, management's best estimate of future commodity prices (based on recent published forward curves) and the Group's borrowing facilities. The Base Case conservatively assumes first gas from Karish in July 2022, Brent at \$70/bbl for the period 1 September to 31 December 2021 and \$65/bbl for the period January to September 2022, PSV (Italian gas price) at an average of EUR25/MWH for the period 1 September to 31 December 2021 and EUR20/MWH for the period January to September 2022.
In addition, on a regular basis, the Group performs sensitivity tests of its liquidity position for negative impacts that may result from changes to the macroeconomic environment such as a fall in commodity price or increase in interest rate. The Group also looks at the impact of changes or deferral of key projects and/or portfolio rationalisation. This is done to identify risks to liquidity and covenant compliance and enable management to formulate appropriate and timely mitigation strategies in order to manage the risk of funding shortfalls or covenant breaches and to safeguard the Group's ability to continue as a going concern.
Specifically, the Group tested the following sensitivities:
The Group also ran a reverse stress test to stress the combination of lower Brent price, lower PSV (Italian Gas Price) and reduced collection of EGPC receivables, and assess the impact of this combination on the Group's liquidity and covenants associated with its banking facilities. Energean believes that this combination of scenarios holds a low probability of occurrence.
Should a more extreme downside scenario occur, appropriate mitigating actions that are in management's control and can be executed in the necessary timeframe could be taken such as a tightening of operating cost and reductions/postponement of other discretionary exploration and development expenditures. The Group's cash and cash equivalents at 30 June 2021 are \$880 million.
In terms of the Group's Borrowing Facilities, the following was considered in the context of the Group's liquidity and covenant compliance over the Forecast Period.
Consistent with the Group's plans to implement new financing as the Karish development approaches first gas in mid-2022, Energean issued a \$2.5 billion Bond to (i) refinance its \$1.45 billion Project Finance Facility (ii) cancel and replace the \$700m Term Loan which was drawn to fund the acquisition of Kerogen's minority interest in Energean Israel, (iii) fund future capital and exploration expenditure in Israel, including Karish and Karish North and (iv) for general corporate purposes of the Group. On 29 April 2021 the Group satisfied the escrow release conditions, as a result the proceeds of the Offering were released from the escrow account.
In March 2021, the Group agreed a waiver with its lenders under the EBRD reserve-based lending facility whereby there are no more Borrowing Base Redeterminations and the facility effectively converts to an amortising term loan with repayments weighted towards the second half of 2022 to 2024. Covenants under the Subordinated Loan Agreement are also waived until December 2022.
The current Borrowing Base redetermination is expected to be completed in September 2021. Given the strong commodities prices and the higher production achieved from the Borrowing Base Assets we do not expect any reduction to the Borrowing Base when the redetermination exercise is completed.
In forming an assessment on the Group's ability to continue as a going concern and its review of the forecasted cashflow of the Group over the Forecast Period (from the date of approval of the interim condensed consolidated financial statements) the Board has made significant judgements about:
further safeguard the Group's liquidity and covenant compliance.
After careful consideration, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future, for a period up to 30 September 2022. For this reason, they continue to adopt the going concern basis in preparing the consolidated financial statements.
The accounting policies adopted in the preparation of the unaudited interim condensed consolidated financial statements are consistent with those followed in the preparation of the Group's annual consolidated financial statements for the year ended 31 December 2020, except for the adoption of the new standards and interpretations effective as of 1 January 2021. None of the amendments that are effective as of 1 January 2021 had a significant impact on the Group's interim condensed consolidated financial statements.
The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective as at 1 January 2021. Several amendments and interpretations apply for the first time in 2021, but do not have an impact on the interim condensed consolidated financial statements of the Group.
Interest Rate Benchmark Reform – Phase 2: Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16
The amendments provide temporary reliefs which address the financial reporting effects when an interbank offered rate (IBOR) is replaced with an alternative nearly risk-free interest rate (RFR). The amendments include the following practical expedients:
The Group intends to use the practical expedients in future periods if they become applicable.
These unaudited condensed interim consolidated financial statements were approved by the Board of Directors on 1 September 2021.
The information reported to the Group's Chief Executive Officer and Chief Financial Officer (together the Chief Operating Decision Makers) for the purposes of resource allocation and assessment of segment performance is focused on four operating segments: Europe, (including Greece, Italy, UK, Croatia), Israel, Egypt and New Ventures (Montenegro and Malta).
The Group's reportable segments under IFRS 8 Operating Segments are Europe, Israel and Egypt. Segments that do not exceed the quantitative thresholds for reporting information about operating segments have been included in Other. In 2020, before the acquisition of Edison E&P, the Group had no activities in Egypt and the Europe segment comprised only Greece (including the Prinos and Epsilon production asset, Katakolo non-producing assets and Ioannina and Aitoloakarnania exploration assets).
The following is an analysis of the Group's revenue, results and reconciliation to profit/(loss) before tax by reportable segment:
| Other & | |||||
|---|---|---|---|---|---|
| Europe | Israel | Egypt | intercompany transactions |
Total | |
| \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | |
| Six months ended 30 June 2021 | |||||
| (unaudited) | |||||
| Revenue from Oil | 70,736 | - | 27,431 | - | 98,167 |
| Revenue from Gas | 34,765 | - | 70,929 | - | 105,694 |
| Petroleum products sales | 492 | - | - | - | 492 |
| Rendering of services | 5,228 | - | - | (4,115) | 1,113 |
| Total revenue | 111,221 | - | 98,360 | (4,115) | 205,466 |
| Adjusted EBITDAX25 | 9,685 | (1,563) | 69,113 | (2,584) | 74,651 |
| Reconciliation to profit before tax: | |||||
| Depreciation and amortisation | |||||
| expenses | (21,586) | (50) | (14,256) | (451) | (36,343) |
| Share-based payment charge | (431) | (122) | - | (1,699) | (2,252) |
| Exploration and evaluation expenses | (630) | - | - | (411) | (1,041) |
| Impairment loss on property, plant | |||||
| and equipment | - | - | - | - | - |
| Other expense | (1,458) | (28) | (88) | (1,497) | (3,071) |
| Other income | 2,887 | 0 | 641 | 43 | 3,571 |
| Finance income | 1,667 | 1,808 | 676 | (1,451) | 2,700 |
| Finance costs | (10,797) | (9,436) | (624) | (24,055) | (44,912) |
| Net foreign exchange gain/(loss) | 2,879 | (727) | (1,055) | (14,884) | (13,787) |
| Profit/(loss) before income tax | (17,784) | (10,118) | 54,407 | (46,989) | (20,484) |
| Taxation income / (expense) | 3,342 | 2,571 | (21,535) | 448 | (15,174) |
| Profit/(loss) from continuing | |||||
| operations | (14,442) | (7,547) | 32,872 | (46,541) | (35,658) |
| Six months ended 30 June 2020 | |||||
| (unaudited) | |||||
| Revenue from Oil | 1,914 | - | - | 1,914 | |
| Revenue from Gas | - | - | - | - | - |
| Petroleum products sales | 3,425 | - | - | (3,269) | 156 |
| Total revenue | 5,339 | - | - | (3,269) | 2,070 |
| Adjusted EBITDAX27 | (4,584) | (2,084) | - | (2,180) | (8,848) |
| Reconciliation to profit before tax: | - | ||||
| Depreciation and amortisation | |||||
| expenses | (12,448) | (149) | - | (190) | (12,787) |
27 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, share-based payment charge, impairment of property, plant and equipment, other income and expenses (including the impact of derivative financial instruments and foreign exchange), net finance costs and exploration and evaluation expenses.
| Other & | |||||
|---|---|---|---|---|---|
| Europe | Israel | Egypt | intercompany transactions |
Total | |
| \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | |
| Share-based payment charge | (13) | (39) | - | (1,102) | (1,154) |
| Exploration and evaluation expenses | (183) | - | - | (346) | (529) |
| Impairment loss on property, plant and equipment |
(63,005) | - | - | - | (63,005) |
| Other expense | (6,995) | (385) | - | (8,463) | (15,843) |
| Other income | 3,913 | - | - | 5,001 | 8,914 |
| Finance income | 4,094 | 169 | - | 120 | 4,383 |
| Finance costs | (3,449) | (26) | - | (88) | (3,563) |
| Net foreign exchange gain/(loss) | (262) | 243 | - | (6,618) | (6,637) |
| Profit before income tax | (82,932) | (2,271) | - | (13,866) | (99,069) |
| Taxation income / (expense) | 20,999 | 413 | - | 389 | 21,801 |
| Profit from continuing operations | (61,933) | (1,858) | - | (13,477) | (77,268) |
The following table presents assets and liabilities information for the Group's operating segments as at 30 June 2021 and 31 December 2020, respectively:
| Other & | |||||
|---|---|---|---|---|---|
| Europe | Israel | Egypt | intercompany transactions |
Total | |
| \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | |
| Six months ended 30 June | |||||
| 2021 (unaudited) | |||||
| Oil & Gas properties | 559,283 | 2,436,742 | 332,738 | (12,716) | 3,316,047 |
| Other fixed assets | 30,043 | 687 | 25,343 | 3,111 | 59,184 |
| Intangible assets | 137,702 | 93,337 | 21,498 | 33,664 | 286,201 |
| Trade and other receivables | 108,640 | 8,652 | 161,777 | 2,916 | 281,985 |
| Deferred tax asset | 103,049 | 0 | 25,448 | 1 | 128,498 |
| Other assets | 940,530 | 732,623 | 36,401 | (453,724) | 1,255,830 |
| Total assets | 1,879,247 | 3,272,041 | 603,205 | (426,748) | 5,327,745 |
| Trade and other payables | 165,465 | 174,699 | 58,331 | 3,925 | 402,420 |
| Borrowings | 150,923 | 2,459,910 | 0 | 227,996 | 2,838,829 |
| Decommissioning provision | 816,153 | 34,708 | - | 0 | 850,861 |
| Other current liabilities | 164,508 | 2,405 | - | (164,509) | 2,404 |
| Other non-current liabilities | 4,337 | 160,580 | 477,858 | (199,992) | 442,783 |
| Total liabilities | 1,301,386 | 2,832,302 | 536,189 | (132,580) | 4,537,297 |
| Other segment information | |||||
| Capital Expenditure: | |||||
| - Property, plant and | |||||
| equipment | 21,850 | 162,454 | 17,019 | (508) | 200,815 |
| - Intangible, exploration and | 24,829 | 3,738 | - | 624 | 29,191 |
| evaluation assets | |||||
| Year ended 31 December | |||||
| 2020 | |||||
| Oil & Gas properties | 572,834 | 2,156,236 | 326,366 | (1,728) | 3,053,708 |
| Other fixed assets | 21,727 | 765 | 27,588 | 3,484 | 53,564 |
| Intangible assets | 139,267 | 89,607 | 39,219 | 7,723 | 275,816 |
| Trade and other receivables | 154,469 | 1,304 | 162,222 | 344 | 318,339 |
| Deferred tax asset | 103,200 | 0 | 22,856 | (0) | 126,056 |
| Other assets | 251,240 | 37,464 | 247,028 | (228,202) | 307,530 |
| Total assets | 1,242,737 | 2,285,376 | 825,279 | (218,379) | 4,135,013 |
| Trade and other payables | 187,117 | 76,146 | 57,959 | 34,232 | 355,454 |
| Page 32 |
| Other & | |||||
|---|---|---|---|---|---|
| Europe | Israel | Egypt | intercompany transactions |
Total | |
| \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | |
| Borrowings | 121,264 | 1,093,965 | - | 227,847 | 1,443,076 |
| Decommissioning provision | 826,729 | 38,399 | - | - | 865,128 |
| Other current liabilities | 140,629 | 6,914 | 54,652 | (195,280) | 6,915 |
| Other non-current liabilities | 25,291 | 193,920 | 32,284 | 18,553 | 270,048 |
| Total liabilities | 1,301,030 | 1,409,344 | 144,895 | 85,352 | 2,940,621 |
| Other segment information | |||||
| Capital Expenditure: | |||||
| - Property, plant and | 14,117 | 405,279 | 860 | (197) | 420,059 |
| equipment | |||||
| - Intangible, exploration and | 1,219 | 6,625 | - | 1,147 | 8,991 |
| evaluation assets |
| Other & | |||||
|---|---|---|---|---|---|
| Europe | Israel | Egypt | intercompany transactions |
Total | |
| \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | |
| Six months ended 30 June | |||||
| 2021 (unaudited) | |||||
| Net cash from / (used in) | |||||
| operating activities | 22,329 | (2,802) | 52,958 | (19,420) | 53,065 |
| Net cash (used in) investing | |||||
| activities | (41,614) | (378,265) | (15,695) | (3,141) | (438,715) |
| Net cash from financing | |||||
| activities | 22,447 | 1,075,374 | (87,054) | 50,819 | 1,061,586 |
| Net increase/(decrease) in cash | |||||
| and cash equivalents, and | |||||
| restricted cash | 3,162 | 694,307 | (49,791) | 28,258 | 675,936 |
| Cash and cash equivalents at | |||||
| beginning of the period | 13,609 | 37,421 | 76,240 | 75,669 | 202,939 |
| Effect of exchange rate | |||||
| fluctuations on cash held | 409 | (146) | (1) | 880 | 1,142 |
| Cash and cash equivalents at | |||||
| the end of the period | 17,180 | 731,582 | 26,448 | 104,807 | 880,017 |
| Six months ended 30 June | |||||
| 2020 (unaudited) | |||||
| Net cash from / (used in) | |||||
| operating activities | (6,209) | (1,359) | - | (6,933) | (14,501) |
| Net cash (used in) investing | |||||
| activities | (14,380) | (227,713) | - | (542) | (242,635) |
| Net cash from financing | |||||
| activities | 19,746 | 194,484 | - | (72,574) | 141,656 |
| Net increase/(decrease) in cash | |||||
| and cash equivalents | 302 | (34,588) | - | (80,049) | (114,335) |
| At beginning of the year | 6,085 | 110,488 | - | 237,846 | 354,419 |
| Effect of exchange rate | |||||
| fluctuations on cash held | (1,114) | (54) | - | (5,312) | (6,480) |
| Cash and cash equivalents at | |||||
| end of the period | 5,273 | 75,846 | - | 151,340 | 232,459 |
On 17 December 2020, the Group acquired 100 per cent of the issued share capital and obtained control of Edison Exploration & Production S.p.A ("Edison E&P"). Edison E&P contains a portfolio of assets including producing assets in Egypt, Italy, the UK North Sea and Croatia with development assets in Egypt and Italy and balanced-risk exploration opportunities across the portfolio. The acquisition of Edison E&P qualifies as a business combination as defined in IFRS 3.
The fair values of the identifiable assets and liabilities of Edison E&P were provisionally estimated as at the date of acquisition. As of 30 June 2021 no change has been identified to the ascribed fair values of the identifiable assets and liabilities.
The base consideration payable of \$398.6 million, which excludes contingent consideration, was agreed as of a locked box date of 1 January 2019 with the impact of economic performance, capital expenditure and working capital movements from this date to completion of 17 December 2020 adjusted within the final consideration payable of \$269.9 million from which amount of \$266.6 million was paid in December 2020 and amount \$3.3 million paid in January 2021.
The contingent consideration arrangement will vary depending on future Italian gas prices at the point in time at which first gas production is delivered from the Cassiopea field in Italy which is expected in 2024. The potential undiscounted amount of all future payments that the Group could be required to make under the contingent consideration arrangement is between \$0 and \$100 million.
The fair value of the contingent consideration arrangement of \$55.2 million was estimated by applying forward gas price curves against the expected date of first gas as at acquisition date. This resulted in an aggregate fair value of \$299.3 million being allocated to the identifiable assets and liabilities acquired, prior to the recognition of a deferred tax liability of \$22.9 million as further described below.
Goodwill of \$25.3 million has been recognised upon acquisition. An amount of \$22.9 million was due to the requirement of IAS 12 to recognise deferred tax assets and liabilities for the difference between the assigned fair values and tax bases of assets acquired and liabilities assumed. The assessment of fair value of such licences is therefore based on cash flows after tax. Hence, goodwill arises as a direct result of the recognition of this deferred tax adjustment ("technical goodwill"). None of the goodwill recognised will be deductible for income tax purposes.
| 30 June (Unaudited) | |||
|---|---|---|---|
| 2021 | 2020 | ||
| \$'000 | \$'000 | ||
| Crude oil sales | 98,167 | 1,914 | |
| Gas sales | 105,694 | - | |
| Petroleum products sales | 492 | 156 | |
| Rendering of services | 1,113 | - | |
| Total revenue | 205,466 | 2,070 |
| 30 June (Unaudited) | ||||
|---|---|---|---|---|
| 2021 | 2020 | |||
| \$'000 | \$'000 | |||
| (a) | Cost of sales | |||
| Staff costs | 32,626 | 6,153 | ||
| Energy cost | 3,475 | 2,550 | ||
| Royalty payable | 5,814 | - | ||
| Other operating costs | 80,503 | 1,717 | ||
| Depreciation and amortisation | 33,845 | 11,581 | ||
| Stock overlift/(underlift) movement | (8,623) | (4,067) |
| 30 June (Unaudited) | ||||
|---|---|---|---|---|
| 2021 | 2020 | |||
| \$'000 | \$'000 | |||
| Total cost of sales | 147,640 | 17,934 | ||
| (b) | Administrative expenses | |||
| Staff costs | 7,329 | 2,744 | ||
| Other General & administration expenses Share-based payment charge included in |
8,815 | 2,309 | ||
| administrative expenses | 2,247 | 1,154 | ||
| Depreciation and amortisation | 2,498 | 385 | ||
| Auditor fees | 779 | 261 | ||
| Total administrative expenses | 21,668 | 6,853 | ||
| (c) | Selling and distribution expense | |||
| Staff costs | 29 | 22 | ||
| Other Selling and distribution expense | 73 | 50 | ||
| Total selling and distribution expense | 102 | 72 | ||
| (d) | Exploration and evaluation expenses | |||
| Staff costs for Exploration and evaluation | ||||
| activities | 355 | 141 | ||
| Other exploration and evaluation expenses | 686 | 388 | ||
| Total exploration and evaluation expenses | 1,041 | 529 | ||
| (e) | Other operating expenses | |||
| Transaction costs in relation to Edison E&P | ||||
| acquisition | 1,470 | 8,405 | ||
| Impairment on asset held for sale | - | 4,935 | ||
| Intra-group merger costs | - | 1,524 | ||
| Loss from disposal of Property plant & Equipment | 36 | - | ||
| Other indemnities | - | 203 | ||
| Write down of inventory | - | 124 | ||
| Expected credit losses | 279 | 267 | ||
| Other expenses | 1,286 | 385 | ||
| 3,071 | 15,843 | |||
| (f) | Other income | |||
| Income from accounts payable written off28 | - | 3,839 | ||
| Reversal of prior period accruals | 3,496 | - | ||
| Proceeds from termination of agreement with Neptune Energy29 |
- | 5,000 | ||
| Other income | 75 | 75 | ||
| 3,571 | 8,914 |
28 Related to derecognition of specific accounts payables balances in the Greek subsidiary following waiver agreements with creditors
29 Related to termination fees paid from Neptune Energy following the termination of the agreement for Neptune Energy to acquire Edison E&P's UK and Norwegian subsidiaries from the Group.
| 2021 \$'000 |
2020 \$'000 |
|
|---|---|---|
| Interest on bank borrowings | 89,501 | 37,608 |
| Interest expense on long term payables | 467 | 3,345 |
| Interest expense on short term liabilities | 28 | - |
| Less amounts included in the cost of qualifying assets | (72,969) | (37,932) |
| 17,027 | 3,021 | |
| Finance and arrangement fees | 11,869 | 2,184 |
| Unamortised financing costs related to the | ||
| repayment of the Karish project finance30 | 36,200 | - |
| Other finance costs and bank charges | 2,172 | 678 |
| Loss on interest rate hedges | 6,988 | - |
| Unwinding of discount on right of use asset | 837 | 116 |
| Unwinding of discount on provision for decommissioning | 4,946 | 180 |
| Unwinding of discount on deferred consideration | 5,124 | - |
| Unwinding of discount on contingent consideration | 744 | |
| Less amounts included in the cost of | (2,616) | |
| qualifying assets | (40,995) | |
| Total finance costs | 44,912 | 3,563 |
| Interest income from time deposits | (1,534) | (396) |
| Gain from revised estimated loan cash flow | (1,166) | (3,987) |
| Total finance revenue | (2,700) | (4,383) |
| Foreign exchange losses/(gain) | 13,787 | 6,637 |
| Net financing costs | 55,999 | 5,817 |
The information set out below provides information about how the Group determines the fair values of various financial assets and liabilities.
The fair values of the Group's non-current liabilities measured at amortised cost are considered to approximate their carrying amounts at the reporting date.
The carrying value less any estimated credit adjustments for financial assets and financial liabilities with a maturity of less than one year are assumed to approximate their fair values due to their short term-nature. The fair value of the group's finance lease obligations is estimated using discounted cash flow analysis based on the group's current incremental borrowing rates for similar types and maturities of borrowing and are consequently categorized in level 2 of the fair value hierarchy.
As part of the share purchase agreement (the "SPA") dated 4 July 2019 between Energean and Edison Spa provides for a contingent consideration of up to \$100.0 million subject to the commissioning of the Cassiopea development gas project in Italy. The consideration was determined to be contingent on the basis of future gas prices (PSV) recorded at the time of the commissioning of the field, which is expected in 2024. No payment will be due if the arithmetic average of the year one (i.e., the first year after first gas production) and year two (i.e., the second year after first gas production) Italian PSV Natural Gas Futures prices is less than €10/Mwh when first gas production is delivered from the field. US\$100 million is payable if that average price exceeds €20/Mwh. The contingent consideration to be payable in 2026 is estimated at acquisition date to amount to \$61.7m, which discounted at the selected cost of debt results in a present value of \$55.2m as at the acquisition date. The fair value of the consideration payable has been recognized at level 3 in the fair value hierarchy and has been estimated by reference to the sales and purchase agreement and by simulating PSV pricing by reference to the forecasted PSV pricing, historical volatility and a log normal distribution.
As at 30 June 2021, the two year future curve of PSV prices increased from the date of acquisition and indicate an average price in excess of €20/Mwh for 2023 it is probable that the average price will exceed €20/Mwh from 2023. The Group monitors closely
30 On 29 April 2021, the Group fully repaid the Israel Project Finance Facility before the maturity date of 31 December 2021 and, as such, the unamortised financing costs have been expensed in the period.
the future PSV prices however given the current volatility in the commodity markets, the Group's estimate as at 30 June 2021 of the fair value of the contingent consideration payable in 2026 has not materially changed since the previous reporting date.
At 30 June 2021 the fair value has been increased to \$56.1 million (31 December 2020: \$55.2 million) for the unwinding cost recognised in income statement within finance cost.
The Group held financial instruments at fair value at 30 June 2021 related to interest rate derivatives. All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved. Values recorded are as at the balance sheet date, and will not necessarily be realised.
As at 30 June 2021 the Group's interest rate derivative (Level 2) is not designated as hedging instruments.
The fair value hierarchy of financial assets and financial liabilities that are not measured at fair value (but fair value disclosure is required) is as follows:
| Fair value hierarchy as at 30 June 2021 (Unaudited) | ||||
|---|---|---|---|---|
| Level 1 \$'000 |
Level 2 \$'000 |
Level 3 \$'000 |
Total \$'000 |
|
| Financial assets | ||||
| Trade and other receivables (note 17) | - | 237,673 | - | 237,673 |
| Cash and cash equivalents and bank deposits (note 14) |
880,017 | - | - | 880,017 |
| Restricted cash | 266,241 | - | - | 266,241 |
| Total | 1,146,258 | 237,673 | - | 1,383,931 |
| Financial liabilities | ||||
| Financial liabilities held at amortised cost: | ||||
| Trade and other payables - current | - | 272,207 | - | 272,207 |
| Trade and other payables - non-current | - | 1,435 | - | 1,435 |
| Borrowings (note 20) | - | 2,838,829 | - | 2,838,829 |
| Deferred consideration for acquisition of minority |
- | 159,551 | - | 159,551 |
| Net obligations under finance leases (note 23) |
- | 53,254 | - | 53,254 |
| Deferred licence payments (note 23) | - | 54,712 | - | 54,712 |
| Convertible loan notes (note 20) | - | 39,590 | - | 39,590 |
| Financial liabilities held at FVTPL: | ||||
| Interest rate derivatives | - | 2,405 | - | 2,405 |
| Contingent consideration (note 4) | - | - | 56,091 | 56,091 |
| Total | - | 3,421,983 | 56,091 | 3,478,074 |
| Fair value hierarchy as at 31 December 2020 | ||||
|---|---|---|---|---|
| Level 1 \$'000 |
Level 2 \$'000 |
Level 3 \$'000 |
Total \$'000 |
|
| Financial assets | ||||
| Trade and other receivables (note 17) | - | 246,307 | - | 246,307 |
| Cash and cash equivalents and bank | 202,939 | - | - | 202.939 |
| Fair value hierarchy as at 31 December 2020 | ||||
|---|---|---|---|---|
| Level 1 \$'000 |
Level 2 \$'000 |
Level 3 \$'000 |
Total \$'000 |
|
| deposits (note 14) | ||||
| Total | 202,939 | 246,307 | - | 449,246 |
| Financial liabilities Financial liabilities held at amortised cost: |
||||
| Borrowings (note 20) | - | 1,443,076 | - | 1,443,076 |
| Net obligations under finance leases (note 23) |
- | 47,623 | - | 47,623 |
| Deferred licence payments (note 22) | - | 69,518 | - | 69,518 |
| Financial liabilities held at FVTPL: | - | |||
| Interest rate derivatives | - | 6,915 | - | 6,915 |
| Contingent consideration (note 4) | - | - | 55,222 | 55,222 |
| Total | - | 1,567,132 | 55,222 | 1,622,354 |
| 30 June (Unaudited) | |||
|---|---|---|---|
| 2021 | 2020 | ||
| \$'000 | \$'000 | ||
| Corporation tax – current period | (21,565) | - | |
| Corporation tax - prior years | 448 | 386 | |
| Deferred tax (Note 13) | 5,943 | 21,415 | |
| Total taxation income / (expense) | (15,174) | 21,801 |
The Group calculates its income tax expense as per IAS 34 by applying a weighted average tax rate calculated based on the statutory tax rates in Greece (25%), Israel (23%), Italy (24%) and United Kingdom (40%) weighted according to the profit or loss before tax earned by the Group in each jurisdiction where deferred tax is recognised or material current tax charge arises. The effective tax rate for the period is -74% (30 June 2020: -22%).
The tax (charge)/credit of the period can be reconciled to the loss per the consolidated income statement as follows:
| 30 June (Unaudited) | |||
|---|---|---|---|
| 2021 | 2020 | ||
| \$'000 | \$'000 | ||
| Profit/(loss) before tax | (20,484) | (99,069) | |
| Tax calculated at 19.70% weighted average rate (2020: 24.95%)31 | 4,035 | 24,724 | |
| Impact of different tax rates | 13 | (19) | |
| Reassessment of recognised deferred tax asset in the current period | (348) | (90) | |
| Permanent differences32 | (1,912) | (2,608) |
31 For the reconciliation of the tax rate, the weighted average rate of the statutory tax rates in Greece (25%), Israel (23%), Italy (24%) and United Kingdom (40%) was used weighted according to the profit or loss before tax earned by the Group in each jurisdiction. These are jurisdictions where current and/or deferred tax is recognised.
32 Permanent differences mainly consisted of non-deductible expenses.
| 30 June (Unaudited) | |||
|---|---|---|---|
| 2021 | 2020 | ||
| \$'000 | \$'000 | ||
| Non recognition of deferred tax on current period losses33 | (4,486) | (1,265) | |
| Tax effect of non-taxable income | - | 625 | |
| Foreign taxes34 | (21,535) | ||
| Tax effect of non-taxable income35 | 10,985 | ||
| Other adjustments36 | (2,374) | 47 | |
| Prior year tax | 448 | 387 | |
| Taxation income/(expense) | (15,174) | 21,801 |
The earnings per share has been calculated by dividing the net profit or loss for the period by the weighted average number of shares outstanding during the period ended 30 June 2021 and 30 June 2020.
| 30 June (Unaudited) | |||
|---|---|---|---|
| 2021 \$'000 |
2020 \$'000 |
||
| Total loss attributable to equity shareholders | (35,550) | (76,826) | |
| Effect of dilutive potential ordinary shares | - | - | |
| (35,550) | (76,826) | ||
| Number of shares | |||
| Basic weighted average number of shares | 177,117,612 | 177,089,406 | |
| Dilutive potential ordinary shares | - | - | |
| Diluted weighted average number of shares | 177,117,612 | 177,089,406 | |
| Basic loss per share | (\$0.20)/share | (\$0.43)/share | |
| Diluted loss per share | (\$0.20)/share | (\$0.43)/share |
33 Tax losses generated from entities which are not expected to generate sufficient taxable profits in the near future and for which deferred tax is not recognised.
34 Income tax paid in Egypt branch based on the Production Sharing Agreement (PSA) regime
35 Utilisation of foreign tax credits in Italy to offset taxable profits arising from the operations in the Egyptian branch
36 Other adjustments mainly related to the tax effect of consolidation differences due to the elimination of intra-group transactions.
| Oil and gas properties |
Leased assets | Other property, plant and equipment |
Total | |
|---|---|---|---|---|
| Property, plant and equipment at Cost |
\$'000 | \$'000 | \$'000 | \$'000 |
| At 1 January 2020 | 2,147,163 | 9,117 | 56,699 | 2,212,979 |
| Additions | 411,932 | 1,951 | 1,581 | 415,464 |
| Acquisition of subsidiary | 646,507 | 40,549 | 2,132 | 689,188 |
| Lease modification | - | (1,519) | - | (1,519) |
| Disposal of assets | (4,795) | - | (5,328) | (10,123) |
| Capitalized borrowing cost | 94,929 | - | - | 94,929 |
| Capitalized depreciation | 576 | - | - | 576 |
| Change in decommissioning provision |
39,620 | - | - | 39,620 |
| Transfer from Intangible assets | 41,822 | - | - | 41,822 |
| Foreign exchange impact | 52,575 | 743 | 5,153 | 58,471 |
| At 31 December 2020 | 3,430,329 | 50,841 | 60,237 | 3,541,407 |
| Additions | 195,062 | 2,250 | 85 | 197,397 |
| Lease modifications | - | 10,009 | - | 10,009 |
| Disposal of assets | (23) | - | (36) | (59) |
| Capitalized borrowing cost | 112,829 | - | - | 112,829 |
| Capitalised depreciation | 106 | - | - | 106 |
| Change in environmental rehabilitation provision |
(2,500) | - | - | (2,500) |
| Transfer from Intangible assets | 13,787 | - | - | 13,787 |
| Foreign exchange impact | (40,666) | (1,535) | (1,726) | (43,927) |
| At 30 June 2021 | 3,708,924 | 61,565 | 58,560 | 3,829,049 |
| Accumulated Depreciation | ||||
| At 1 January 2020 | 263,512 | 3,448 | 43,748 | 310,708 |
| Charge for the period | ||||
| Expensed | 18,105 | 3,073 | 2,149 | 23,327 |
| Impairments | 64,727 | - | 572 | 65,299 |
| Foreign exchange impact | 30,299 | 458 | 4,044 | 34,801 |
| At 31 December 2020 | 376,643 | 6,979 | 50,513 | 434,135 |
| Charge for the period | 28,374 | 4,550 | 616 | 33,540 |
| Disposal of assets | - | - | (23) | (23) |
| Foreign exchange impact | (12,140) | (202) | (1,492) | (13,834) |
| At 30 June 2021 | 392,877 | 11,327 | 49,614 | 453,818 |
| Net carrying amount | ||||
| At 31 December 2020 | 3,053,686 | 43,862 | 9,724 | 3,107,272 |
| At 30 June 2021 | 3,316,047 | 50,238 | 8,946 | 3,375,231 |
Included in the carrying amount of leased assets at 30 June 2021 is right of use assets related to oil and gas properties and Other property, plant and equipment of \$43.3 million and \$6.9 million respectively.
The depreciation charged on these classes for the six-month ending 30 June 2021 were \$4.1 million and \$0.4 million respectively. The additions to oil & gas properties for the period of six months ended 30 June 2021 is mainly due to development costs of Karish field related to the EPCIC contract (FPSO, Sub Sea and On-shore construction cost) at the amount of \$161.8 million, development cost for Cassiopea project in Italy at the amount of \$8.4 million and NEA/NI project in Egypt at the amount of \$17.5 million.
Borrowing costs capitalised for qualifying assets, included in oil & gas properties, for the six months ended 30 June 2021 amounted to \$123.4 million (year ended 31 December 2020: \$94.9 million). The weighted average interest rates used:
During the year 2020 the Group executed an impairment test for the Prinos CGU (Prinos and Epsilon fields). In that 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 \$65.3 million in the carrying value of the Prinos CGU.
| Exploration and evaluation assets |
Goodwill | Other Intangible assets | Total | |
|---|---|---|---|---|
| \$'000 | \$'000 | \$'000 | \$'000 | |
| Intangibles at Cost | ||||
| At 1 January 2020 | 71,601 | 75,800 | 1,941 | 149,342 |
| Additions | 8,379 | - | 612 | 8,991 |
| Acquisition of subsidiary | 115,438 | 25,346 | 18,348 | 159,132 |
| Capitalized borrowing costs | 2,761 | - | - | 2,761 |
| Transfers to property, plant and | ||||
| equipment | (41,822) | - | - | (41,822) |
| Exchange differences | 1,856 | - | 1,454 | 3,310 |
| At 31 December 2020 | 158,213 | 101,146 | 22,355 | 281,714 |
| Additions | 28,255 | - | 937 | 29,192 |
| Capitalized borrowing costs | 1,134 | - | - | 1,134 |
| Transfers to property, plant and | - | |||
| equipment | (278) | (13,509) | (13,787) | |
| Exchange differences | (500) | (3,218) | (3,718) | |
| At 30 June 2021 | 186,824 | 101,146 | 6,565 | 294,535 |
| Accumulated amortisation and impairments |
||||
| At 1 January 2020 | 261 | - | 1,405 | 1,666 |
| Charge for the period | - | - | 1,375 | 1,375 |
| Impairment | 2,936 | - | - | 2,936 |
| Exchange differences | (193) | - | 114 | (79) |
At 31 December 2020 3,004 - 2,894 5,898 Charge for the period 2,031 - 772 2,803 Exchange differences (114) (253) (367) 30 June 2021 4,921 - 3,413 8,334 Net Carrying Amount At 31 December 2020 155,209 101,146 19,461 275,816
| Exploration and evaluation |
|||||
|---|---|---|---|---|---|
| assets | Goodwill \$'000 |
Other Intangible assets | Total | ||
| \$'000 | \$'000 | \$'000 | |||
| At 30 June 2021 | 181,903 | 101,146 | 3,152 | 286,201 | |
Borrowing costs capitalised for qualifying assets for the period ended 30 June 2021 amounted to \$1.1 million (31 December 2020: \$2.8 million). The weighted average interest rate used was 7.34% (31 December 2020: 8.72%).
| Deferred tax (liabilities)/assets |
Property, plant and equipme nt |
Right of use asset IFRS 16 |
Deco m missio ning |
Prepaid expenses and other receivables |
Inven tory |
Tax losses |
Deferred expenses for tax1 |
Retirem ent benefit liability |
Accrued expenses and other short-ter m liabilities |
Total |
|---|---|---|---|---|---|---|---|---|---|---|
| \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | \$'000 | |
| At 1 January 2020 | (137,998) | (1,078) | - | (971) | 733 | 90,412 | - | 913 | 7,646 | (40,343) |
| Acquisition of subsidiary (Note 4) Increase / (decrease) for the |
10,080 | 60,752 | - | 70,832 | ||||||
| period through: profit or loss (Note 9) other |
8,381 | 819 | 8,877 | (3,474) | (98) | 7,384 | - | 53 | (434) | 21,508 |
| comprehensive income |
- | - | - | 130 | - | - | - | - | 1,603 | 1,733 |
| Exchange difference |
(4,006) | (33) | - | (336) | 60 | 7,293 | - | 84 | 655 | 3,717 |
| 31 December 2020 |
(123,543) | (292) | 8,877 | (4,651) | 695 | 165,841 | - | 1,050 | 9,470 | 57,447 |
| Increase / (decrease) for the period through: profit or loss (Note 9) other comprehensive income Reclassifications in the current |
(14,853) (28,442) |
67 - |
(774) 33,644 |
1,053 2,025 |
(659) (233) |
12,261 (4,903) |
1,908 6,010 |
43 200 |
6,897 (1,591) (8,301) |
5,943 (1,591) - |
| period37 Exchange difference |
(243) | 6 | (421) | 132 | (13) | (2,742) | (32) | (139) | (3,452) | |
| 30 June 2021 | (167,081) | (219) | 41,326 | (1,441) | (210) | 170,457 | 7,918 | 1,261 | 6,336 | 58,347 |
| 30 June 2021 \$'000 |
31 December 2020 | \$'000 | ||||||||
| Deferred tax liabilities | (70,151) | (68,609) | ||||||||
| Deferred tax assets | 128,498 | 126,056 | ||||||||
| Net deferred tax assets / (liabilities) | 58,347 | 57,447 |
37 These reclassifications primarily relate to the assets and liabilities acquired in the Edison E&P acquisition which completed in December 2020 and reflect updated information on the allocation of the deferred taxes across the relevant categories.
At 30 June 2021 the Group has gross unused tax losses of \$757.3 million (as of 31 December 2020: \$783.6 million) available to offset against future profits. Out of the total tax losses, \$380.4 million come from the Greek operations whereas amount of \$18.1 million comes from the Israeli operations and specifically the Karish licence which is in the development phase and expected to commence production by 2021. Tax losses of \$329.6 million comes from the Italian and UK operations of the former Edison E&P Group.
With respect to the Greek tax losses carried forward, the majority of them (\$374.3 million) come from the Prinos exploitation area, whereas an amount of \$1.5 million comes from Ioannina and Katakolo areas which are in the exploration and development phase respectively.
A deferred tax asset of \$170.5 million has been recognised as of 30 June 2021 (as of 31 December 2020: \$165.8 million) in respect of such tax losses. This represents the losses which are expected to be utilised based on Group's projection of future taxable profits in the jurisdictions in which the losses reside. It is considered probable based on business forecasts that such profits will be available.
| 30 June | 31 December 2020 \$'000 |
||
|---|---|---|---|
| 2021 (Unaudited) \$'000 |
|||
| Cash at bank | 878,580 | 197,514 | |
| Deposits in escrow | 1,437 | 5,425 | |
| 880,017 | 202,939 |
Bank demand deposits comprise deposits and other short-term money market deposit accounts that are readily convertible into known amounts of cash. The effective interest rate on short-term bank deposits was 0.3% for the six months period ended 30 June 2021 (year ended 31 December 2020: 1.07%).
Deposits in escrow comprise mainly cash retained as a bank security pledge for the Group's performance guarantees in its exploration blocks. These deposits can be used for funding the exploration activities of the respective blocks.
Restricted cash comprise mainly cash retained under the Senior Secured Notes requirement as follows:
The remaining amount of \$2.96 included in restricted cash is related to cash collateral provided under a letter of credit facility for issuing bank guarantees for Group's activities in Israel up to \$75 million.
| 30 June 20201 (Unaudited) \$'000 |
31 December 2020 \$'000 |
|
|---|---|---|
| Raw materials and supplies | 53,057 | 56,073 |
| Crude oil | 24,959 | 16,946 |
| Total inventories | 78,016 | 73,019 |
In the period ended 30 June 2021 the write-down of crude oil inventory to net realisable value amounted to \$nil million (six months ended 30 June 2020: \$5.6 million) which is included in "cost of sales".
30 June 31 December
| 2021 (Unaudited) \$'000 |
2020 \$'000 |
|
|---|---|---|
| Trade and other receivables-Current | ||
| Financial items: | ||
| Trade receivables | 185,967 | 226,118 |
| Receivables from partners under JOA | 28,190 | - |
| Other receivables | 3,213 | - |
| Government subsidies38 | 3,371 | 3,481 |
| Receivables from related parties (note 24) | - | 22 |
| 220,741 | 229,621 | |
| Non-financial items: | ||
| Deposits and prepayments39 | 26,974 | 38,756 |
| Refundable VAT | 32,747 | 49,414 |
| Other taxes receivable | 209 | - |
| Deferred insurance expenses | 579 | 507 |
| Accrued interest income | 735 | 41 |
| 61,244 | 88,718 | |
| 281,985 | 318,339 | |
| Trade and other receivables-Non Current | ||
| Financial items: | ||
| Accrued interest income | 1 | - |
| Other tax recoverable | 16,931 | 16,686 |
| 16,932 | 16,686 | |
| Non-financial items: | ||
| Deferred borrowing fees | 49 | - |
| Deposits and prepayments | 12,945 | 13,409 |
| Other deferred expenses | 209 | - |
| Other non-current assets | 1,417 | 1,473 |
| 14,620 | 14,882 | |
| 31,552 | 31,568 |
The below tables outline the share capital of the Company.
| Equity share capital allotted and fully paid |
Share capital | Share premium | |
|---|---|---|---|
| Number | \$'000 | \$'000 | |
| Issued and authorized | |||
| At 1 January 2020 | 177,089,406 | 2,367 | 915,388 |
| Issued during the year | |||
| - New shares | - | - | - |
| - Share based payment | - | - | - |
| At 31 December 2020 | 177,089,406 | 2,367 | 915,388 |
| Issued during the period | |||
| - Share based payment | 51,361 | 1 | |
| At 30 June 2021 | 177,140,767 | 2,368 | 915,388 |
38 Government subsidies mainly relate to grants from Greek Public Body for Employment and Social Inclusion (OAED) to financially support the Kavala Oil S.A. labour cost from manufacturing under the action plan for promoting sustainable employment in underdeveloped or deprived districts of Greece, such as the area of Kavala.
39 Included in deposits and prepayments, are mainly prepayments for goods and services under the GSP Engineering, Procurement, Construction and Installation Contract (EPCIC) for Epsilon project.
| 19. Non-controlling interests | ||||||
|---|---|---|---|---|---|---|
| Name of subsidiary | Voting rights | Share of loss | Accumulated balance | |||
| 30 June (Unaudited) |
Year ended 31 December |
30 June (Unaudited) |
Year ended 31 December |
30 June (Unaudited) |
Year ended 31 December |
|
| 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | |
| % | % | \$'000 | \$'000 | \$'000 | \$'000 | |
| Energean Israel Ltd | - | 30.00 | (106) | (3,173) | - | 266,299 |
| Total | - | 30.00 | (106) | (3,173) | - | 266,299 |
On 25 February 2021, the Group completed the acquisition of the remaining 30% minority interest in Energean Israel Limited from Kerogen Investments No.38 Limited, Energean now owns 100% of Energean Israel Limited.
This resulted in a reduction of the Group's reported non-controlling interest balance to \$nil at 30 June 2021.
The Total Consideration includes:
The following is a schedule of additional interest acquired in Energean Israel Limited:
| \$'000 | |
|---|---|
| Cash consideration paid to non-controlling shareholders at completion Deferred cash consideration |
175,000 154,499 |
| Convertible Loan Notes - Liability Component | 38,337 |
| Convertible Loan Notes - Equity Instrument Component | 10,459 |
| Cost related to the transaction | 1,677 |
| Carrying value of the 30% minority interest | (266,193) |
| Difference recognised in retained earnings | 113,779 |
The Acquisition of the remaining 30% minority interest in Energean Israel adds 2P reserves of 29.5 billion cubic metres ("Bcm") of gas and 30 million barrels of liquids, representing approximately 219 million barrels of oil equivalent ("MMboe") in total, to the Group.
| 30 June (Unaudited) |
31 December | ||
|---|---|---|---|
| 2021 | 2020 | ||
| \$'000 | \$'000 | ||
| Non-current | |||
| Bank borrowings - after two years but withing five years | |||
| 4,5% Senior Secured notes due 2024 (\$625 million) | 615,419 | - | |
| 4,875% Senior Secured notes due 2026 (\$625 million) | 615,030 | - | |
| Senior Credit facility (\$237 million) | 229,485 | 227,848 | |
| EBRD Senior Facility Loan (\$180 million) | 75,696 | 84,420 | |
| EBRD Subordinated Facility Loan (\$20 million) | 15,128 | 17,824 | |
| Page 45 |
| 30 June (Unaudited) |
31 December | |
|---|---|---|
| 2021 | 2020 | |
| \$'000 | \$'000 | |
| Convertible loan notes (\$50 million) – (note 19) | 39,590 | - |
| Bank borrowings - more than five years | ||
| 5.375% Senior Secured notes due 2028 (\$625 million) | 614,818 | - |
| 5.875% Senior Secured notes due 2031 (\$625 million) | 614,643 | - |
| Carrying value of non-current borrowings | 2,819,809 | 330,092 |
| Current | ||
| 6,83% EBRD Senior Facility Loan due 2024 (\$97,6 million) | 19,020 | 19,020 |
| Senior Credit Facility for the Karish-Tanin Development (\$1,450 million) | - | 1,093,964 |
| Carrying value of current borrowings | 19,020 | 1,112,984 |
| Carrying value of total borrowings | 2,838,829 | 1,443,076 |
The Group has provided security in respect of certain borrowings in the form of share pledges, as well as fixed and floating charges over certain assets of the Group.
On 24 March 2021, the Group completed the issuance of US\$2.5 billion aggregate principal amount of senior secured notes. The Notes have been issued in four series as follows:
The interest on each series of the Notes will be paid semi-annually, on 30 March and on 30 September of each year, beginning on 30 September 2021.
On 29 April 2021 the Group satisfied the escrow release conditions in respect of its US\$2.5 billion aggregate principal amount of the Notes offering. As a result of satisfying the said escrow release conditions, the proceeds of the Offering were released from escrow.
The Notes are listed for trading on the TACT Institutional of the Tel Aviv Stock Exchange Ltd. (the "TASE"). The use of proceeds from the Offering is as follows :
The Company had undertook to provide the following collateral in favor of the Trustee:
Energean Power FPSO (subject to using commercially reasonable efforts, including obtaining Israel Petroleum Commissioner approval and any other applicable governmental authority).
On 29 April 2021, following the release of the senior secured notes proceeds of \$2.5bn, the Company repaid its existing outstanding facility.
The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders and benefits to stakeholders and to safeguard the Group's ability to continue as a going concern.
| 30 June 2021 (Unaudited) | 31 December 2020 \$'000 |
||
|---|---|---|---|
| \$'000 | |||
| Net Debt | |||
| Current borrowings | 19,020 | 1,112,984 | |
| Non-current borrowings | 2,819,809 | 330,092 | |
| Total borrowings | 2,838,829 | 1,443,076 | |
| Less: Cash and cash equivalents | (880,017) | (202,939) | |
| Restricted cash | (266,241) | - | |
| Net Debt (1) | 1,692,571 | 1,240,137 | |
| Total equity (2) | 790,448 | 1,194,392 | |
| Gearing Ratio (1/2): | 214.13% | 103.83% |
| 1 January 2021 \$'000 |
Cash inflows \$'000 |
Cash outflows \$'000 |
Reclassific ation \$'000 |
Additions \$'000 |
Lease modification \$'000 |
Borrowing costs including amortisation of arrangement fees \$'000 |
Derivatives de designated as cash flow hedges during the period \$'000 |
Gain from revised estimated loan cash flow |
Foreign exchange impact \$'000 |
Fair value changes |
30 June 2021 \$'000 |
|
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 30 June 2021 | 1,622,354 | 2,793,000 | (1,559,213) | (34,676) | 190,776 | 10,055 | 143,102 | 4,641 | (1,146) | 2,864 | (6,915) | 3,164,842 |
| Secured Senior Notes Convertible loan notes (note 19) |
- | 2,500,000 | (37,218) - |
(36,663) - |
38,337 | - | 33,791 1,253 |
- - |
- | - | - | 2,459,910 39,590 |
| Long -term borrowings Current portion of long |
330,092 | 175,000 | (200,131) | (31) | - | - | 16,484 | - | (1,146) | 41 | - | 320,309 |
| term borrowings | 1,112,984 | 118,000 | (1,297,062) | 2,080 | - | - | 82,984 | - | 34 | - | 19,020 | |
| Lease liabilities Deferred licence |
47,623 | - | (5,875) | (62) | 2,250 | 10,055 | 837 | - | (1,574) | - | 53,254 | |
| payments | 69,518 | - | (14,344) | - | - | - | (462) | - | - | - | 54,712 | |
| Contingent consideration Deferred consideration |
55,222 | - | - | - | - | 744 | - | - | - | 55,966 | ||
| for acquisition of minority Derivatives not designated as hedging |
- | - | - | - | 150,189 | - | 5,124 | - | 4,363 | 159,676 | ||
| instruments | 6,915 | - | (4,583) | - | - | - | 2,347 | 4,641 | - | (6,915) | 2,405 | |
| 30 June 2021 | |||
|---|---|---|---|
| (Unaudited) | 31 December 2020 | ||
| \$'000 | \$'000 | ||
| Defined benefit obligation | 6,695 | 7,839 | |
| Provision for retirement benefits recognised | 6,695 | 7,839 | |
| Allocated as: | |||
| Non current portion | 6,695 | 7,839 |
| 30 June 2021 (Unaudited) | 31 December 2020 \$'000 |
||
|---|---|---|---|
| \$'000 | |||
| At 1 January | 7,839 | 4,265 | |
| Acquisition of subsidiary | 3,021 | ||
| Current service cost | 183 | 364 | |
| Interest cost | 21 | 39 | |
| Extra payments or expenses | 69 | 557 | |
| Actuarial losses - from changes in financial | |||
| assumptions | 50 | 49 | |
| Benefits paid | (1,197) | (866) | |
| Transfer in/(out) | (35) | - | |
| Exchange differences | (235) | 410 | |
| At 30 June / 31 December | 6,695 | 7,839 |
| Provision for environment rehabilitation |
Litigation and other provisions |
Total | ||
|---|---|---|---|---|
| \$'000 | \$'000 | \$'000 | ||
| At 1 January 2021 | 865,127 | 16,408 | 881,535 | |
| New provisions | - | 1,227 | 1,227 | |
| Change in estimates | (2,500) | - | (2,500) | |
| Payments | (1,710) | (1,710) | ||
| Unwinding of discount | 4,946 | - | 4,946 | |
| Currency translation adjustment | (15,002) | (517) | (15,519) | |
| At 30 June 2021 | 850,861 | 17,118 | 867,979 | |
| Current provisions | 12,975 | - | 12,975 | |
| Non-current provisions | 837,886 | 17,118 | 855,004 |
The decommissioning provision represents the present value of decommissioning costs relating to oil and gas properties, which are expected to be incurred up to 2040, when the producing oil and gas properties are expected to cease operations. The future costs are based on a combination of estimates from an external study completed at the end of 2019 and internal estimates. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required that will reflect market conditions at the relevant
time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This, in turn, will depend upon future oil and gas prices, which are inherently uncertain.
The decommissioning provision represents the present value of decommissioning costs relating to assets in Italy, Greece, UK, Israel and Croatia. No provision is recognized for Egypt as there is no legal or constructive obligation as at 30 June 2021.
| Inflation assumption 30 June 2021 |
Discount rate assumption 30 June 2021 |
Cessation of production assumption |
30 June 2021 \$'000 |
31 December 2020 \$'000 |
|
|---|---|---|---|---|---|
| Greece | 1.01% – 1.3% | 0.8% | 2034 | 17,186 | 16,082 |
| Italy | 0.6%-1.4% | 1.45% | 2021-2040 | 536,180 | 551,464 |
| UK | 1.9% | 0.35% | 2022-2030 | 243,700 | 239,708 |
| Israel | 1.02%-1.6% | 2.0% | 2040 | 34,708 | 38,399 |
| Croatia | na | na | 2022 | 19,087 | 19,474 |
| Total | 850,861 | 865,127 |
Litigation and other claim provision relates to litigation actions currently open in Italy with the Termoli Port Authority in respect of the fees payable under the marine concession regarding FSO Alba Marina serving the Rospo Mare field in Italy. Energean Italy Spa has appealed these cases to the Campobasso Court of Appeal. None of the other cases has yet had a decision on the substantive issue. The Group contain a provision of €4.7 million against an adverse outcome of these court cases.
Energean Italy Spa has currently open litigations with five municipalities in Italy related to the imposition of real estate municipality taxes (IMU/TASI), interest and related penalties concerning the periods 2016 to 2019. For the years before 2019, Edison SpA bears uncapped liability for any amount assessed according the sale and purchase agreement (SPA) signed between the companies while the Company is liable for any tax liability related to tax year 2019. For all five cases, Energean Italy Spa (together with Edison SpA, as appropriate) filed appeals presenting strong legal and technical arguments for reducing the assessed taxes to the lowest possible level as well as cancelling entirely the imposed penalties. The Group strongly believes based on legal advice received that the outcome of the court decisions will be in its favour with no material exposure expected, therefore the Group recognised a provision of \$1.2 million in respect of this claims.
Amount of \$1.8 million provision relates to leasing cost charged to ENI on the floating storage located in the Leoanis plan. The Group following a claim from ENI accounted for this provision since these overestimated costs were required to be reimbursement.
Other provisions include non-income tax provision and other potential claim in Egypt.
It is not currently possible to accurately predict the timing of the settlement of these claims and therefore the expected timing of the cash flows.
| \$'000 \$'000 |
|
|---|---|
| 30 June 2021 (Unaudited) 31 December 2020 |
Trade and other payables-Current Financial items:
| 30 June 2021 (Unaudited) | 31 December 2020 | |
|---|---|---|
| \$'000 | \$'000 | |
| Trade accounts payable40 | 214,290 | 193,987 |
| Payables to partners under JOA41 | 46,922 | 64,752 |
| Deferred licence payments due within one year42 |
- | 14,344 |
| Other creditors | 10,995 | 12,502 |
| Short term lease liability | 12,247 | 10,561 |
| 284,454 | 296,146 | |
| Non-financial items: | ||
| Accrued Expenses38 | 79,149 | 49,812 |
| Other finance costs accrued | 34,840 | 2,630 |
| Social insurance and other taxes | 3,947 | 5,695 |
| Income taxes | 30 | 1,171 |
| 117,966 | 59,308 | |
| 402,420 | 355,454 | |
| Trade and other payables-Non Current | ||
| Financial items: | ||
| Deferred consideration for acquisition of | ||
| minority (note 19) | 159,551 | - |
| Deferred licence payments40 | 54,712 | 55,174 |
| Contingent consideration (note 4) | 56,091 | 55,222 |
| Long term lease liability | 41,007 | 37,062 |
| Other payables | 1,435 | - |
| 312,796 | 147,458 | |
| Non-financial items: | ||
| Long term prepayment43 | 35,525 | 29,105 |
40 Included in trade payables and accrued expenses in 30 June 2021 and FY2020, are mainly Karish field related development expenditures (mainly FPSO and Sub Sea construction cost) .
41 Payables related to operated Joint operations primarily in Italy
42 In December 2016, Energean Israel acquired the Karish and Tanin offshore gas fields for \$40.0 million closing payment with an obligation to pay additional consideration of \$108.5 million plus interest inflated at an annual rate of 4.6% in ten equal annual payments. As at 30 June 2021 the total discounted deferred consideration was \$54.71 million (as at 31 December 2020: \$69.52 million). The Sale and Purchase Agreement ("SPA") includes provisions in the event of Force Majeure that prevents or delays the implementation of the development plan as approved under one lease for a period of more than ninety (90) days in any year following the final investment decision ("FID") date. In the event of Force Majeure the applicable annual payment of the remaining consideration will be postponed by an equivalent period of time, and no interest will be accrued in that period of time as well. Due to the effects of the COVID-19 pandemic which constitute a Force Majeure event, postponing the deferred payment due in March 2022 by the number of days that such Force Majeure event last. As of 30 June 2021 Force Majeure event length has not been finalised as the COVID-19 pandemic continue to affect the progress of the project, and in such the deferred payment due in March 2022 will be made after 1 July 2022. As at 30 June 2021 the total discounted deferred consideration was \$54.7 million (31 December 2020: \$69.5 million).
43 In June 2019, Energean signed a Detailed Agreement with Israel Natural Gas Lines ("INGL") for the transfer of title (the "hand over") of the near shore and onshore part of the infrastructure that will deliver gas from the Karish and Tanin FPSO into the Israeli national gas transmission grid. As consideration, INGL will pay Energean 369 million Israeli new shekel (ILS), approximately \$102 million for the infrastructure being built by Energean which will be paid in accordance with milestones detailed in the agreement. The agreement covers the onshore section of the Karish and Tanin infrastructure and the near shore section of pipeline extending to approximately 10km offshore. It is intended that the hand over to INGL will become effective shortly after the delivery of first gas from the Karish
| 30 June 2021 (Unaudited) \$'000 |
31 December 2020 \$'000 |
|
|---|---|---|
| Social insurance | 497 | 630 |
| 36,022 | 29,735 | |
| 348,818 | 177,193 |
Analysis of share-based payment charge
| 30 June (Unaudited) | ||
|---|---|---|
| 2021 | 2020 | |
| \$'000 | \$'000 | |
| Energean DSBP Plan | 530 | 290 |
| Energean Long Term Incentive Plans | 1,944 | 1,075 |
| Total share-based payment charge | 2,474 | 1,365 |
| Capitalised to intangible and tangible assets | 207 | 33 |
| Expensed as cost of sales | 5 | |
| Expensed as administration expenses | 2,247 | 1,154 |
| Expensed to exploration and evaluation expenses | 14 | 174 |
| Expensed as other expenses | 1 | 4 |
| Total share-based payment charge | 2,474 | 1,365 |
Under the LTIP, Senior Management can be granted nil exercise price options, normally exercisable from three to ten years following grant provided an individual remains in employment. The size of awards depends on both annual performance measures and Total Shareholder Return (TSR) over a period of up to three years. There are no post-grant performance conditions. No dividends are paid over the vesting period; however, Energean's Board may decide at any time prior to the issue or transfer of the shares in respect of which an award is released that the participant will receive an amount (in cash and/or additional Shares) equal in value to any dividends that would have been paid on those shares on such terms and over such period (ending no later than the Release Date) as the Board may determine. This amount may assume the reinvestment of dividends (on such basis as the Board may determine) and may exclude or include special dividends.
The weighted average remaining contractual life for LTIP awards outstanding at 30 June 2021 was 1.6 years, number of shares outstanding 2,036,982 and weighted average price at grant date £5.99.
Under the DSBP, the portion of any annual bonus above 30 per cent of the base salary of a Senior Executive nominated by the Remuneration Committee was deferred into shares.
Deferred awards are usually granted in the form of conditional share awards or nil-cost options (or, exceptionally, as cash-settled equivalents). Deferred awards usually vest two years after award although may vest early on leaving employment or on a change of control.
The weighted average remaining contractual life for DSBP awards outstanding at 30 June 2021 was 1.3 years, number of shares outstanding 234,902 and price at grant date £6.75.
field expected in mid-2022 . Following hand over, INGL will be responsible for the operation and maintenance of this part of the infrastructure.
Balances and transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note.
The Directors of Energean Plc are considered to be the only key management personnel as defined by IAS 24. The following information is provided in relation to the related party transaction disclosures provided in note 25b below:
| 30 June (Unaudited) | |||
|---|---|---|---|
| 2021 | 2020 | ||
| \$'000 | \$'000 | ||
| Nature of transactions | |||
| Other related party "Seven Marine" | Vessel leasing | 993 | 1,189 |
| Other related party "Prime Marine | Construction of field | ||
| Energy Inc" | support vessel | 3,300 | - |
| Other related party "Capital Earth | |||
| Ltd" | Consulting services | 46 | 63 |
| 4,339 | 1,252 |
Following a competitive tender process, the Group has entered into an agreement to purchase a Field Support Vessel ("FSV") from Prime Marine Energy Inc., a company controlled by director and shareholder at Energean plc, for US\$33.3 million. The FSV is being constructed to meet the Group's specifications and will provide significant incountry capability to support the Karish project, including FPSO re-supply, crew changes, holdback operations for tanker offloading, emergency subsea intervention, drilling support and emergency response. The purchase of this multi-purpose vessel will enhance operational efficiencies and economics when compared to the leasing of multiple different vessels for the various activities.
| 30 June 2021 (Unaudited) \$'000 |
31 December 2020 \$'000 |
||
|---|---|---|---|
| Nature of balance | |||
| Seven Marine | Vessel leasing | 882 | 407 |
| 882 | 407 |
In acquiring its oil and gas interests, the Group has pledged that various work programmes will be undertaken on each permit/interest. The exploration commitments in the following table are an estimate of the net cost to the Group of performing these work programmes:
| 30 June 2021 (Unaudited) \$'000 |
31 December 2020 \$'000 |
|
|---|---|---|
| Capital Commitments: | ||
| Due within one year | 97,351 | 102,255 |
| Due later than one year but within two years | 138,665 | 84,855 |
| Due later two years but within five years | 75,344 | 200,895 |
| 311,360 | 388,005 | |
| Contingent liabilities: | ||
| Performance guarantees: | ||
| Greece | 4,751 | 6,743 |
| Israel | 64,740 | 62,101 |
| UK | 98,078 | 96,655 |
| Italy | 9,455 | 15,361 |
| Montenegro | 594 | 614 |
| 177,618 | 181,474 |
Performance guarantees are mainly in respect of committed work programmes and certain financial obligations.
Karish and Tanin Leases - As part of the requirements of the Karish and Tanin Lease deeds, the Group provided the Ministry of National Infrastructures, Energy and Water with bank guarantees in the amount of US\$10 million for each lease (total US\$20 million). The bank guarantees were in force until 29 December 2019, and were renewed in March 2021 until 31 March 2022.
Blocks 12, 21, 23 and 31 in Israel - As part of the requirements of the exploration and appraisal licences which granted to the Group during the Israeli offshore BID in December 2017, the Group provided the Ministry of National Infrastructures, Energy and Water in January 2018 with bank guarantees in the amount of US\$6.0 million for all 5 blocks mentioned above. The bank guarantees are in force until 13 January 2023.
Blocks 55, 56, 61 and 62, also known as "ZONE D" - As part of the requirements of the exploration and appraisal licences which granted to the Group during the Israeli 2nd offshore BID in July 2019, the Group provided the Ministry of National Infrastructures, Energy and Water in January 2018 with bank guarantees in the amount of US\$3.2 million for all 4 blocks mentioned above. The bank guarantees are in force until 28 September 2022.
Israeli Natural Gas Lines ("INGL") - As part of the agreement signed with INGL on June 2019 the Group provided INGL bank guarantee at the amount of 92 million ILS (approx. US\$28.6 million) in order to secure the first milestone payment from INGL. The first bank guarantee at the amount of 92 million ILS (approx. US\$28.3 million) was issued on June 2019 and is in force until 21 November 2021. During Q2 2021 an additional bank guarantee was issued to secure INGL's additional milestone payment in total of 18 million ILS (approx. US \$5.6 million). This bank guarantee is in force until 30 June 2022.
Israel Custom Authority - As part of the ongoing importation related Karish development, the Group provided the Israeli Custom authority bank guarantees in 2019 at the amount of 12 million ILS (approx. \$3.7 million). During Q2 2021 total amount of 8 million ILS (approx. \$2.5 millions) of the guarantees was revoked. The remaining bank guarantees at amount of 4 million ILS (approx. US\$1.1 million). The bank guarantees are in force until 28 February 2022.
United Kingdom: Following Edison E&P acquisition the Group issued letters of credit amount \$92.1 million for United Kingdom decommissioning obligations and obligations under the United Kingdom licenses
Italy: Following Edison E&P acquisition the Group issued letters of credit amount \$13.3 million for decommissioning obligations and obligations under the Italian licenses
The Group had no material contingent liabilities as of 30 June 2021 and 31 December 2020.
During August 2021 and in accordance with the GSPAs signed with a group of gas buyers, the Group has agreed to pay compensation to these counterparties due to the fact the gas supply date is taking place beyond a certain date as defined in the GSPAs (being 30 June 2021). The compensation will be paid on a monthly basis starting on August 2021 and is estimated at approx. US\$23 million. The compensation is accounted as variable purchase consideration under IFRS 15 hence recognised once production commences and gas is delivered to the offtakers
During August 2021 a gas buyer sent a request to the International Court of Arbitration ("ICC") asking for arbitration on its rights of termination due to the fact the gas supply date is taking place beyond a certain date which defined in the GSPA. If the agreement it is terminated, the Group has identified multiple alternative routes to monetise those gas volumes (being 0.8 Bcm/yr), including both domestic and international markets, and hence is confident of profitably selling them
| Shareholding | Shareholding | |||
|---|---|---|---|---|
| Country of incorporation / | At 30 June | At 31 December | ||
| Name of subsidiary | registered office | Principal activities | 2021 | 2020 |
| (%) | (%) | |||
| Energean E&P Holdings Ltd | 22 Lefkonos Street, 2064 Nicosia, Cyprus |
Holding Company | 100 | 100 |
| Energean Capital Ltd | 22 Lefkonos Street, 2064 Nicosia, Cyprus |
Holding Company | 100 | 100 |
| Energean MED Limited | 44 Baker Street, London W1U 7AL, United Kingdom |
Oil and gas exploration, development and production |
100 | 100 |
| Energean Oil & Gas S.A. | 32 Kifissias Ave. 151 25 Marousi Athens, Greece |
Oil and gas exploration, development and production |
100 | 100 |
| Energean International Limited |
22 Lefkonos Street, 2064 Nicosia, Cyprus |
Oil and gas exploration, development and production |
100 | 100 |
| Energean Israel Limited (Note 19) |
22 Lefkonos Street, 2064 Nicosia, Cyprus |
Oil and gas exploration, development and production |
100 | 70 |
| Energean Montenegro Limited |
22 Lefkonos Street, 2064 Nicosia, Cyprus |
Oil and gas exploration, development and production |
100 | 100 |
| Energean Israel Finance SARL |
560A rue de Neudorf, L-2220, Luxembourg |
Financing activities | 100 | 70 |
| Energean Israel Transmission LTD |
Andre Sakharov 9, Haifa, Israel | Gas transportation license holder |
100 | 70 |
| Energean Israel Finance LTD | Andre Sakharov 9, Haifa, Israel | Financing activities | 100 | 70 |
| Energean Egypt Limited | 22 Lefkonos Street, 2064 Nicosia, Cyprus |
Oil and gas exploration, development and production |
100 | 100 |
| Energean Hellas Limited | 22 Lefkonos Street, 2064 Nicosia, Cyprus |
Oil and gas exploration, development and production |
100 | 100 |
| Energean Italy S.p.a. | Piazza Sigmund Freud 1 20154 Milan,Italy |
Oil and gas exploration, development and production |
100 | 100 |
| Energean International E&P S.p.a. |
Piazza Sigmund Freud 1 20154 Milan,Italy |
Oil and gas exploration, development and production |
100 | 100 |
| Energean Sicilia Srl | Via Salvatore Quasimodo 2 - 97100 Ragusa (Ragusa) |
Oil and gas exploration, development and production |
100 | 100 |
| Energean Exploration Limited |
44 Baker Street, London W1U 7AL, United Kingdom |
Oil and gas exploration, development and production |
100 | 100 |
| Edison E&P UK Ltd | 44 Baker Street, London W1U 7AL, United Kingdom |
Oil and gas exploration, development and production |
100 | 100 |
At 30 June 2021, the Group had investments in the following subsidiaries:
| Name of subsidiary | Country of incorporation / registered office |
Principal activities | Shareholding At 30 June 2021 (%) |
Shareholding At 31 December 2020 (%) |
|---|---|---|---|---|
| Edison Egypt Energy Services JSC |
Building 11, 273 Palestine Street New Maadi , Cairo EGYPT |
Oil and gas exploration, development and production |
98 | 98 |
| Group's | ||||
|---|---|---|---|---|
| Country | Fields | Fiscal Regime | working | Field Phase |
| interest | ||||
| Israel | ||||
| Karish | Concession | 100% | Development | |
| Tanin | Concession | 100% | Development | |
| Blocks 12, 21, 23, 31 | Concession | 100% | Exploration | |
| Four licences Zone D | Concession | 80% | Exploration | |
| Egypt | ||||
| Abu Qir | PSC | 100% | Production | |
| Abu Qir North | PSC | 100% | Production | |
| Abu Qir West | PSC | 100% | Production | |
| Yazzi | PSC | 100% | Development | |
| Python | PSC | 100% | Development | |
| Field A (NI-1X) | PSC | 100% | Exploration | |
| Field B (NI-3X) | PSC | 100% | Exploration | |
| NI-2X | PSC | 100% | Exploration | |
| North East Hap'y | PSC | 30% | Exploration | |
| Viper (NI-4X) | PSC | 100% | Exploration | |
| Greece | ||||
| Prinos | Concession | 100% | Production | |
| Epsilon | Concession | 100% | Development | |
| Prinos exploration area | Concession | 100% | Exploration | |
| South Kavala | Concession | 100% | Production | |
| Katakolo | Concession | 100% | Undeveloped | |
| Ioannina | Concession | 40% | Exploration | |
| West Patraikos | Concession | 50% | Exploration | |
| Block-2 | Concession | 75% | Exploration | |
| Italy | ||||
| Vega A | Concession | 100% | Production | |
| Vega B | Concession | 100% | Production | |
| Rospo Mare | Concession | 100% | Production | |
| Verdicchio | Concession | 100% | Production | |
| Vongola Mare | Concession | 95% | Production | |
| Gianna | Concession | 100% | Development | |
| Accettura | Concession | 50% | Production | |
| Anemone | Concession | 19% | Production | |
| Appia | Concession | 50% | Production | |
| Argo-Cassiopea | Concession | 40% | Development |
| Group's | ||||
|---|---|---|---|---|
| Country | Fields | Fiscal Regime | working interest |
Field Phase |
| Azalea | Concession | 16% | Production | |
| Calipso | Concession | 49% | Production | |
| Candela Dolce | Concession | 40% | Production | |
| Candela Povero | Concession | 40% | Production | |
| Carlo | Concession | 49% | Production | |
| Cassiano | Concession | 50% | Production | |
| Castellaro | Concession | 50% | Production | |
| Cecilia | Concession | 49% | Production | |
| Clara East | Concession | 49% | Production | |
| Clara North | Concession | 49% | Production | |
| Clara Northwest | Concession | 49% | Production | |
| Clara West | Concession | 49% | Production | |
| Comiso | Concession | 100% | Production | |
| Cozza | Concession | 85% | Production | |
| Daria | Concession | 49% | Production | |
| Didone | Concession | 49% | Production | |
| Emma West | Concession | 49% | Production | |
| Fauzia | Concession | 40% | Production | |
| Giovanna | Concession | 49% | Production | |
| Leoni | Concession | 50% | Production | |
| Monte Urano-San Lorenzo | Concession | 40% | Production | |
| Naide | Concession | 49% | Production | |
| Portocannone | Concession | 62% | Production | |
| Quarto | Concession | 33% | Production | |
| Ramona | Concession | 49% | Production | |
| Regina | Concession | 25% | Production | |
| Salacaro | Concession | 50% | Production | |
| San Giorgio Mare | Concession | 95% | Production | |
| San Marco | Concession | 100% | Production | |
| Santa Maria Mare | Concession | 96% | Production | |
| Santo Stefano | Concession | 95% | Production | |
| Sarago Mare | Concession | 85% | Production | |
| Sinarca | Concession | 40% | Production | |
| Talamonti | Concession | 50% | Production | |
| Tresauro | Concession | 25% | Production | |
| UK | ||||
| Garrow | Concession | 68% | Production | |
| Kilmar | Concession | 68% | Production | |
| Scott | Concession | 10% | Production | |
| Telford | Concession | 16% | Production | |
| Wenlock | Concession | 80% | Production | |
| Glengorm | Concession | 25% | Exploration | |
| Isabella | Concession | 10% | Exploration | |
| Montenegro | ||||
| Block 26, 30 | Concession | 100% | Exploration | |
| Croatia | ||||
| Irena | PSC | 70% | Exploration |
| Country | Fields | Fiscal Regime | Group's working interest |
Field Phase |
|---|---|---|---|---|
| Izabela | PSC | 70% | Production | |
| Malta | ||||
| Blocks 1, 2 and 3 of Area 3 | Concession | 100% | Exploration |
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