Energean PLC

National Storage Mechanism | Additional information RNS Number : 4675K Energean PLC 02 September 2021 Energean plc ("Energean" or the "Company") Results for Half Year Ended 30 June 2021 London, 2 September 2021 - Energean plc (LSE: ENOG TASE: ��) is pleased to announce its half-year results for the six months ended 30 June 2021 ("1H 2021"). Mathios Rigas, Chief Executive of Energean, commented: "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 Change[1] 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 levels[2]; 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." Highlights - Operational �� 1H 2021 average working interest production was 44.0 kboed (72% gas), ahead of full year guidance of 38 - 42 kboed (71% gas) o Production outperformed guidance across all countries of operation o Demonstrates Energean's ability to maximise value from the ex-Edison E&P assets and to successfully integrate Edison E&P within six-months of transaction close �� On track to deliver first gas from Karish in mid-2022 o On 31 July 2021, the project was 91.5% complete[3] o Core focus on optimising and accelerating the timetable with options being actively considered (and not reflected in the current timetable) �� On 31 August 2021, the workforce on the Energean Power FPSO stood at more than 1,700 workers, up approximately 70% month-on-month �� Rig contract signed with Stena Drilling Limited ("Stena") for 2022-23 growth drilling programme, offshore Israel o Targeting the de-risking of prospective recoverable resources of over 1 billion[4] barrels of oil equivalent ("boe") �� Awarded an Engineering, Procurement, Construction and Installation ("EPCI") contract to TechnipFMC to develop the North East Almeyra ("NEA")/North Idku ("NI") project, shallow-water offshore Egypt, in February 2021 o Project remains on track to deliver first gas in 2H 2022 o Project expected to deliver IRRs in excess of 30% �� Cassiopea gas development project, Italy, 23% complete at 31 July 2021 and on track to deliver first gas in 1H 2024 �� Final Investment Decision ("FID") taken on the revised 53 MMbbls 2P + 2C Epsilon satellite tieback project, offshore Greece o First oil expected in 1H 2023 (subject to financing) o Financing package expected to be finalised in 3Q 2021 Highlights - Corporate and ESG �� Issued $2.5 billion of senior secured notes in March 2021 at an average coupon rate of approximately 5.2% o Significantly reducing financing risk on the Karish project, as the project finance facility had been due to mature in 2022 o Extending average life of debt for Energean plc from approximately 2.5 years at 30 June 2020 to approximately 6 years at 31 July 2021 �� Completed the highly accretive acquisition of the 30% minority interest in Energean Israel Limited ("EISL") in February 2021 o Acquisition transacted at a 49% discount to CPR-derived NPV10 o Increased 2P reserves across the portfolio to nearly 1 billion boe (79% gas) �� 1H 2021 Scope 1 and 2 carbon emissions of approximately 18 kg/boe, a significant step towards Energean's target of achieving net zero emissions ahead of 2050, representing a: o 19% reduction versus 2020 levels[5]; o 73% reduction versus 2019; and o On track to beat previous 2021 guidance of 21 kg/boe by approximately 15% Highlights - Financial �� Substantial year-on-year improvement in financial results, demonstrating the magnitude and significance of the acquisition of Edison E&P o Revenues increased to $206 million (1H 2020: $2 million), primarily due to the transformational nature of the acquisition of Edison E&P o Unit cost of production reduced by 44% to $15.4/boe (1H 2020: $27.5/boe) o Positive EBITDAX6 of $75 million (1H 2020: negative $8.9 million) o Positive operating cash flows of $53.1 million (1H 2020: $14.5 million outflow) �� Cash, cash equivalents and restricted cash of $1.1 billion at 30 June 2021 (restricted amounts represent $266 million) o Providing significant financial flexibility o Ensures all planned activities are fully-funded 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 production[6] 122.4[7] 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 EBITDAX[8] 74.7 (8.9) 939% Operating cash flow[9] 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% Outlook �� 2021 production guidance re-iterated at 38 - 42 kboed �� 2021 development and production capital expenditure guidance re-iterated as $470 - 550 million and exploration capital expenditure guidance re-iterated as $55 - 70 million �� 2021 emissions intensity guidance reduced by approximately 15% to 18 kg CO2/boe (from 21 kgCO2/boe) �� Sailaway of the Energean Power FPSO from Singapore to Israel in 1Q 2022 with first gas from Karish expected mid-2022 o Acceleration measures being considered for implementation �� Commencement of the high-impact growth drilling campaign in 1Q 2022, starting with Athena o First drilling results anticipated during 2Q 2022, marking a catalyst-rich start to 2022 �� Continued progress on key gas development projects in Egypt (NEA / NI) and Italy (Cassiopea) �� Finalisation of funding for the Epsilon project, Greece, and commencement of the development programme, expected 2H 2021 �� Acceleration of the Green Prinos suite of projects o Pre-Front-End Engineering Design ("pre-FEED") on the carbon capture and storage ("CCS") project expected to commence in 2H 2021 �� Future dividend policy to be declared in due course Enquiries Kate Sloan, Head of IR, ECM and Communications Tel: +44 7917 608 645 Conference call 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 The presentation slides will be made available on the website shortly www.energean.com. Energean Operational Review Production 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 Kboed FY 2021 guidance Kboed 1H 2020 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 Israel Karish Project 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% complete[10]. 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 2021[11] Production Wells 100.0 FPSO 96.7 Subsea 83.0 Onshore 99.8 Total 91.5 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. Growth Projects In May 2021, Energean took FID on two high-return growth projects, offshore Israel: �� $70 million second oil train that will enable increased production of approximately 5 million barrels of hydrocarbon liquids per year at minimal incremental operating costs; and �� $40 million second gas sales riser, which will enable gas production at the full 8 Bcm/yr capacity of the FPSO Both projects are progressing on schedule and are expected onstream in summer 2023. 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 Bnboe[12]. 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: �� The Athena exploration well, located on Block 12, is situated directly between the Karish and Tanin leases and is expected to be the first well in the programme; o Two factors support commercialisation of a Block 12 discovery. Firstly, Block 12 was a new licence award to EISL in 2018; produced volumes will therefore generate no royalty payments in respect of EISL's original acquisition of the block. Secondly, the more proximate location of the potential development to the expected position of the FPSO will reduce like-for-like development costs when compared with Tanin �� The Karish North development well, a key part of the Karish North development; and �� The Karish Main-04 appraisal well, which is expected to target further prospective volumes within the Karish Main Block, including the potential oil rim that was identified as part of the Karish Main-03 development well drilling. 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. Egypt 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 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. Italy 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. Greece 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. Prinos Area Development and Funding 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"). "Green Prinos" 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. Rest of Portfolio United Kingdom 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. Croatia 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. Energean Corporate Review ESG Net Zero 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 levels[13]; a 73% reduction versus the 2019 base measurement year; and approximately 15% below full-year 2021 guidance of approximately 21 kg/boe. Actions taken to date in 2021 include: �� Agreements put in place for the purchase of electricity from renewable sources at all operated sites in Italy. Energean sites in Italy, Israel, Greece and Croatia now operate under this policy, which has substantially reduced Energean's scope 2 emissions �� Zero-routine flaring policy now fully effective across all operated sites �� Significant progress on the "Green Prinos" suite of initiatives, as described in the Operating Review, above. Energean is assessing the potential to replicate these initiatives across its portfolio ESG Reporting and Ratings 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. 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. Financing 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. $266 million of proceeds have been used to pre-fund certain reserve accounts, classified as restricted cash within this report, with remaining proceeds earmarked for capital expenditure on the Karish and Karish North projects, the 2022/2023 Israel exploration programme, to fund bond transaction costs, outstanding amounts due to Kerogen relating to the acquisition of the minority interest in EISL, and for general corporate purposes. 2021 guidance FY 2021 Consolidated net debt ($ 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 Energean Financial Review Financial results summary 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 production[14] ($m) 122.4 10.4 1,077% Cash cost of production per barrel ($/boe) 15.4 27.5 (44%) Cash SG&A[15] 17.0 5.4 215% Adjusted EBITDAX[16] ($m) 74.7 (8.8) 939% (Loss) after tax ($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% Revenue, production and commodity prices 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: �� During 1H 2021, the average Brent oil price was $65.2/bbl versus $42.2/bbl in 1H 2020, the average PSV price was EUR21.2/MWH (1H 2020: EUR9.3/MWH) and the average NBP price was GBp55.4/Therm (1H 2020: GBp19.0/Therm) �� This strength across commodity prices resulted in a 1H 2021 average realised price of $47.3/boe (1H 2020: $9.1/boe) Depreciation, impairments and write-offs 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). During the period, no impairment charges were recognised (1H 2020: $63.0 million). Other income and expenses 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. Finance income / costs 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. Crude oil hedging Energean has no commodity price hedges outstanding as of 30 June 2021 (1H 2020: $nil). Taxation 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. Operating cash flow 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. Non-IFRS measures The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include adjusted EBITDAX, underlying cash cost of production and SG&A, capital expenditure, net debt and gearing. Adjusted EBITDAX Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, 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 EBITDAX[17] 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 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-to-period, 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 Selling, General & Administrative Expense (SG&A) 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 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 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 170.0 243.2[18] The breakdown of capital expenditures during 1H 2021 and 1H 2020 was as follows: 1H 2021 1H 2020 Capital expenditure $m Capital expenditure $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 Net cash / debt and gearing ratio 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 $m 1H 2020 $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)/Debt[19] 1,692.6 861.4 Total equity 797.5 1,184.7 Gearing ratio 212.3% 72.7% Term Loan 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. Refinancing 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. Principal risks and uncertainties 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. Overview of key risks and key changes since 31 December 2020 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: Strategic risks #1 Progress key development projects in Israel 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. #2 Market risk in Israel 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. #3 Progress key development projects 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. #4 Deliver exploration success and reserve addition 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. #5 Portfolio integration 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. Operational risks #1 Production performance 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. #2 JV misalignment 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. Financial risks #1 Maintaining liquidity and solvency 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. #2 Egypt receivables 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. #3 Decommissioning liability 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 year-to-date and Energean is working on reducing decommissioning liabilities Climate change risks #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: �� ESG ratings maintained in the top quartile. �� Awarded 'Gold' by Maala in July 2021 for a second consecutive year. �� Three core initiatives being rolled out across all operated sites, including switching to purchasing of 'green' electricity, introduction of a zero-routine-faring policy and establishment of procedures to reduce methane emissions. �� Technical feasibility studies are ongoing for carbon capture and storage, and eco-hydrogen projects in Prinos in Greece, in conjunction with evaluation of the wider portfolio for such projects. #2 Physical risks related to climate change 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. External risks #1 Geopolitical events Principal risk: Political and fiscal uncertainties in the Eastern Mediterranean. 1H 2021 movement: This risk remained static in 1H 2021. #2 Global pandemic Principal risk: Operational uncertainties and HSE incidents due to COVID-19 pandemic. 1H 2021 movement: This risk remained static in 1H 2021. Emerging risks 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 one-off events, emerging risks that will be actively assessed and monitored. Events since 30 June 2020 Compensation to gas buyers due to late supply: 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 Gas buyer request for arbitration: 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 Going Concern Statement 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: �� Reduction in Commodity Prices over the Forecast Period (10% applied to PSV prices and 7.5% to Brent prices) �� decrease in projected collection of EGPC receivables over the Forecast Period �� 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 A reasonable worst case including a combination of all above 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 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. Karish Field Development, Israel: �� 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. Greek RBL: �� 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. Egypt RBL: 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: �� Reasonable sensitivities appropriate for the current status of the business and the wider macro environment; and the Group's ability to implement the mitigating actions, if required, is within the Group's control, which would 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. Statement of Directors' responsibilities 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; 2) The interim management report contains a fair review of the information required by DTR 4.2.7RR (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); 3) The interim management report includes a true and fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein). Mathios Rigas Panos Benos Chief Executive Officer Chief Financial Officer 01 September 2021 01 September 2021 Forward looking statements 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. INDEPENDENT REVIEW REPORT TO ENERGEAN PLC Conclusion We have been engaged by Energean plc (the Company) to review the condensed set of financial statements in the half-yearly 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. Basis for Conclusion 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". Responsibilities of the directors 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. Auditor's Responsibilities for the review of the financial information 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. Use of our 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 Interim Condensed Consolidated Income Statement Six months ended 30 June 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) Interim Condensed Consolidated Statement of Comprehensive Income Six months ended 30 June 2021 30 June (Unaudited) 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) (36,906) (87,221) Interim Condensed Consolidated Statement of Financial Position As at 30 June 2021 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 Interim Condensed Consolidated Statement of Changes in Equity Six months ended 30 June 2021 Share Capital Share Premium[20] Other Reserve[21] Equity component of convertible bonds[22] Share based payment reserve[23] Translation Reserve[24] Retained earnings Merger reserve Total Non Controlling Interests Total $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'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 - - 5,326 - - - - - 5,326 2 5,328 Exchange difference on the translation of 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) 1 - - - 2,474 - - - 2,475 2,475 Acquisition of non-controlling Interests[25] - - - 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 Interim Condensed Consolidated Statement of Changes in Equity Six months ended 30 June 2021 Share Capital Share Premium18 Other Reserve19 Share based payment reserve21 Translation Reserve22 Retained earnings Merger reserve23 Total Non Controlling Interests Total $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'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 - - (6,215) - - - - (6,215) (2,663) (8,878) Exchange difference on the 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 Interim Condensed Consolidated Statement of Cash Flows Six months ended 30 June 2021 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 Egypt[26] (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 intangible assets (28,818) (12,077) Acquisition of a subsidiary 4 (3,335) - Movement in restricted cash 15 (266,241) - Proceeds from disposal of property, plant and equipment - 150 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 interests 19 - 9,750 Acquisition of non-controlling interests 19 (175,000) - 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 1. Corporate Information 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. 2. Basis of preparation 2.1 Basis of preparation 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. Going concern 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: �� Reduction in Commodity Prices over the Forecast Period (10% applied to PSV prices and 7.5% to Brent prices) �� Decrease in projected collection of EGPC receivables over the Forecast Period �� Delay in Israel 1st 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 �� A reasonable worst case including a combination of all above 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. Karish Field Development, Israel: �� 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. Greek RBL: �� 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. Egypt RBL: �� 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: �� Reasonable sensitivities appropriate for the current status of the business and the wider macro environment; and �� The Group's ability to implement the mitigating actions, if required, is within the Group's control, which would 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. New and amended accounting standards and interpretations 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: �� A practical expedient to require contractual changes, or changes to cash flows that are directly required by the reform, to be treated as changes to a floating interest rate, equivalent to a movement in a market rate of interest �� Permit changes required by IBOR reform to be made to hedge designations and hedge documentation without the hedging relationship being discontinued �� Provide temporary relief to entities from having to meet the separately identifiable requirement when an RFR instrument is designated as a hedge of a risk component The Group intends to use the practical expedients in future periods if they become applicable. 2.2 Approval of accounts These unaudited condensed interim consolidated financial statements were approved by the Board of Directors on 1 September 2021. 3. Segmental Reporting 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). Segment revenues, results and reconciliation to profit before tax The following is an analysis of the Group's revenue, results and reconciliation to profit/(loss) before tax by reportable segment: Europe Israel Egypt Other & 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 EBITDAX[27] (4,584) (2,084) - (2,180) (8,848) Reconciliation to profit before tax: - Depreciation and amortisation expenses (12,448) (149) - (190) (12,787) 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: Europe Israel Egypt Other & 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 evaluation assets 24,829 3,738 - 624 29,191 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 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 equipment 14,117 405,279 860 (197) 420,059 - Intangible, exploration and evaluation assets 1,219 6,625 - 1,147 8,991 Segment Cash flows Europe Israel Egypt Other & 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 4. Prior year business combination Acquisition of Edison E&P 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. 5. Revenue 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 6. Operating profit/(loss) before taxation 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) Total cost of sales 147,640 17,934 (b) Administrative expenses Staff costs 7,329 2,744 Other General & administration expenses 8,815 2,309 Share-based payment charge included in 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 off[28] - 3,839 Reversal of prior period accruals 3,496 - Proceeds from termination of agreement with Neptune Energy[29] - 5,000 Other income 75 75 3,571 8,914 7. Net finance cost 30 June (Unaudited) 2021 2020 $'000 $'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 finance[30] 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 qualifying assets (40,995) (2,616) 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 8. Fair value measurements 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. Contingent consideration 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 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. Fair values of derivative financial instruments 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 deposits (note 14) 202,939 - - 202.939 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 9. Taxation 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 (b) Reconciliation of the total tax charge 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 differences[32] (1,912) (2,608) Non recognition of deferred tax on current period losses[33] (4,486) (1,265) Tax effect of non-taxable income - 625 Foreign taxes[34] (21,535) Tax effect of non-taxable income[35] 10,985 Other adjustments[36] (2,374) 47 Prior year tax 448 387 Taxation income/(expense) (15,174) 21,801 10. Loss per share 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 2020 $'000 $'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 11. Property, plant and equipment 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: �� 7.66% (for the six months ended 30 June 2021) �� 8.72% (for the year ended 31 December 2020) 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. 12. Intangible assets 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 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%). 13. Net deferred tax (liability)/ asset Deferred tax (liabilities)/assets Property, plant and equipment Right of use asset IFRS 16 Decom-missioning Prepaid expenses and other receivables Inventory Tax losses Deferred expenses for tax1 Retirement benefit liability Accrued expenses and other short��term 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) 10,080 60,752 - 70,832 Increase / (decrease) for the period through: profit or loss (Note 9) 8,381 819 8,877 (3,474) (98) 7,384 - 53 (434) 21,508 other 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) (14,853) 67 (774) 1,053 (659) 12,261 1,908 43 6,897 5,943 other comprehensive income (1,591) (1,591) Reclassifications in the current period[37] (28,442) - 33,644 2,025 (233) (4,903) 6,010 200 (8,301) - 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 31 December 2020 $'000 $'000 Deferred tax liabilities (70,151) (68,609) Deferred tax assets 128,498 126,056 Net deferred tax assets / (liabilities) 58,347 57,447 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. 14. Cash and cash equivalents 30 June 31 December 2021 (Unaudited) 2020 $'000 $'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. 15. Restricted Cash Restricted cash comprise mainly cash retained under the Senior Secured Notes requirement as follows: �� Short term - US$163.3 million Interest Payment Account for the accrued interest period until 30 June 2022 (less coupons actually paid) and from 30 June 2022 the Interest Reserve Account will be funded 6 months forward �� Long term - US$100 million Debt Payment Fund that would be released upon achieving three quarters annualized production of 3.8 BCM/year from Karish asset in Israel. 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. 16. Inventories 30 June 20201 (Unaudited) 31 December 2020 $'000 $'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". 17. Trade and other receivables 30 June 31 December 2021 (Unaudited) 2020 $'000 $'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 subsidies[38] 3,371 3,481 Receivables from related parties (note 24) - 22 220,741 229,621 Non-financial items: Deposits and prepayments[39] 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 18. Share capital 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 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: �� An up-front payment of $175 million (the "Up-Front Consideration") paid at completion of the transaction �� Deferred cash consideration amounts totalling $180 million, which are expected to be funded from future cash flows and optimisation of the group capital structure, post-first gas from the Karish project. The deferred consideration is discounted at the selected unsecured liability rate of 9.77%. �� $50 million of convertible loan notes (the "Convertible Loan Notes"), which have a maturity date of 29 December 2023, a strike price of GBP 9.50 and a zero-coupon rate. The following is a schedule of additional interest acquired in Energean Israel Limited: $'000 Cash consideration paid to non-controlling shareholders at completion 175,000 Deferred cash consideration 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. 20. Borrowings 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 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. US$2,500,000,000 senior secured notes: 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: �� Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2024, with a fixed annual interest rate of 4.500%. �� Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2026, with a fixed annual interest rate of 4.875%. �� Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2028, with a fixed annual interest rate of 5.375%. �� Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2031, with a fixed annual interest rate of 5.875%. 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 : �� To repay outstanding Senior Credit Facility for the Karish-Tanin Development facility and outstanding amount under a US$700 million term loan; �� To replace the existing undrawn amounts available under those facilities; �� To fund certain reserve accounts; and �� For transaction expenses and the Group's general corporate purposes. The Company had undertook to provide the following collateral in favor of the Trustee: �� First rank Fixed charges over the shares of Energean Israel Limited, Energean Israel Finance Ltd and Energean Israel Transmission Ltd, the Karish & Tanin Leases, the gas sales purchase agreements ("GSPAs"), several bank accounts, Operating Permits (once issued), Insurance policies, the Company exploration licenses (Block 12, Block 21, Block 23, Block 31 and 80% of the licenses under "Zone D") and the INGL Agreement. �� Floating charge over all of the present and future assets of Energean Israel Limited and Energean Israel Finance Ltd. �� Energean Power FPSO (subject to using commercially reasonable efforts, including obtaining Israel Petroleum Commissioner approval and any other applicable governmental authority). Senior Credit Facility for the Karish-Tanin Development: On 29 April 2021, following the release of the senior secured notes proceeds of $2.5bn, the Company repaid its existing outstanding facility. Capital management 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) (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% Reconciliation of liabilities arising from financing activities 1 January 2021 Cash inflows Cash outflows Reclassification Additions Lease modification Borrowing costs including amortisation of arrangement fees Derivatives de-designated as cash flow hedges during the period Gain from revised estimated loan cash flow Foreign exchange impact Fair value changes 30 June 2021 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'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 2,500,000 (37,218) (36,663) 33,791 - 2,459,910 Convertible loan notes (note 19) - - - 38,337 - 1,253 - - - - 39,590 Long -term borrowings 330,092 175,000 (200,131) (31) - - 16,484 - (1,146) 41 - 320,309 Current portion of long-term borrowings 1,112,984 118,000 (1,297,062) 2,080 - - 82,984 - 34 - 19,020 Lease liabilities 47,623 - (5,875) (62) 2,250 10,055 837 - (1,574) - 53,254 Deferred licence payments 69,518 - (14,344) - - - (462) - - - 54,712 Contingent consideration 55,222 - - - - 744 - - - 55,966 Deferred consideration for acquisition of minority - - - - 150,189 - 5,124 - 4,363 159,676 Derivatives not designated as hedging instruments 6,915 - (4,583) - - - 2,347 4,641 - (6,915) 2,405 21. Retirement benefit liability 21.1 Provision for retirement benefits 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 21.2 Defined benefit obligation 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 22. Provisions 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 Decommissioning provision 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 claims provisions 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. 23. Trade and other payables 30 June 2021 (Unaudited) 31 December 2020 $'000 $'000 Trade and other payables-Current Financial items: Trade accounts payable[40] 214,290 193,987 Payables to partners under JOA[41] 46,922 64,752 Deferred licence payments due within one year[42] - 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 prepayment[43] 35,525 29,105 Social insurance 497 630 36,022 29,735 348,818 177,193 24. Share based payments 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 Energean Long Term Incentive Plan (LTIP) 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. Deferred Share Bonus Plan (DSBP) 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. 25. Related parties 25a. Related party relationships 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: �� Adobelero Holdings Co Ltd. is a beneficially owned holding company controlled by Panos Benos, the CFO of the Group. �� Growthy Holdings Co Ltd is a beneficially owned holding company controlled by Matthaios Rigas, the CEO of the Group. �� Oil Co Investments Limited is beneficially owned and controlled by Efstathios Topouzoglou, a Non-Executive Director of the Group. The nature of the Group's transactions with the above related parties is mainly financing activities. �� Kerogen Capital is an independent private equity fund manager specialising in the international oil and gas sector, which until February 2021 held the 30% of Energean Israel ordinary shares not held by the group (please refer to note 19). �� Seven Maritime Company (Seven Marine) is a related party company controlled by one the Company's shareholder Mr Efstathios Topouzoglou. Seven Marine owns the offshore supply ships Valiant Energy and Energean Wave which support the Group's investment program in northern Greece. �� Capital Earth: During the period ended 30 June 2021 the Group received consultancy services from Capital Earth Limited, a consulting company controlled by the spouse of one of Energean's executive directors, for the provision of Group Corporate Social Responsibility Consultancy and Project Management Services. 25b. Related party transactions Purchases of goods and services 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 Energy Inc" Construction of field 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 in-country 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. 25c. Related party balances Payables 30 June 2021 (Unaudited) 31 December 2020 $'000 $'000 Nature of balance Seven Marine Vessel leasing 882 407 882 407 26. Commitments and contingencies 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) 31 December 2020 $'000 $'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. Issued guarantees: 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 Legal cases and contingent liabilities The Group had no material contingent liabilities as of 30 June 2021 and 31 December 2020. 27. Subsequent events Compensation to gas buyers due to late supply: 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 Gas buyer request for arbitration: 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 28. Subsidiary undertakings 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 (%) 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 Edison Egypt Energy Services JSC Building 11, 273 Palestine Street New Maadi , Cairo EGYPT Oil and gas exploration, development and production 98 98 29. Exploration, Development and production interests Country Fields Fiscal Regime Group's working interest Field Phase 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 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 Izabela PSC 70% Production Malta Blocks 1, 2 and 3 of Area 3 Concession 100% Exploration [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 [6] Cash Cost of production is defined in the Financial Review section [7] Including flux of $10.3 million and purchased oil of $2.5 million [8] Cash SG&A and Adjusted EBITDAX is defined in the Financial Review section [9] After working capital movements [10] As measured under the TechnipFMC EPCIC [11] As measured under the TechnipFMC EPCIC [12] The 1 bn boe is composed of a combination of CPR-estimated volumes and management estimates [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 [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. [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. [18] Numbers may not sum due to rounding [19] Inclusive of restricted cash [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 [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. [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. [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. [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. [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. [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. [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. [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. [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 field expected in mid-2022 . Following hand over, INGL will be responsible for the operation and maintenance of this part of the infrastructure. This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact [email protected] or visit www.rns.com. RNS may use your IP address to confirm compliance with the terms and conditions, to analyse how you engage with the information contained in this communication, and to share such analysis on an anonymised basis with others as part of our commercial services. For further information about how RNS and the London Stock Exchange use the personal data you provide us, please see our Privacy Policy. END IR UPUAUBUPGPUG

AI Terminal

5342_ir_2021-09-02_3154a389-56be-48b9-8907-cf2c64804488.html

More from Energean PLC

Talk to a Data Expert