Energean PLC

Earnings Release • Mar 24, 2022

National Storage Mechanism | Additional information RNS Number : 8836F Energean PLC 24 March 2022 Energean plc ("Energean" or the "Company") 2021 Full Year Results London, 24 March 2022 - Energean plc (LSE: ENOG, TASE: ��������) is pleased to announce its audited full-year results for the year ended 31 December 2021 ("FY 2021"). Mathios Rigas, Chief Executive of Energean, commented: "2021 was an outstanding year for Energean, one in which we delivered excellent operational and record financial results. Production came in above initial expectations and we also benefitted from an elevated market price environment. As a result, we generated full year revenues of $497 million and Adjusted EBITDAX of $212 million. "Our flagship project, Karish, is on track for first gas in Q3 2022. Earlier this month, we commenced the largest 2022 drilling programme in the East Med and spudded the Athena exploration well which is targeting 21 Bcm (totaling 140 mmboe). Positive results from this high-impact programme would be an important catalyst for the growth of our operations in Israel and the region where security of supply is being increasingly prioritised. " Elsewhere, first gas from NEA/NI in Egypt is anticipated in H2 2022 and the remainder of our development projects in Israel, Italy and Greece remain on track. We are well positioned to reach our medium-term targets of over 200 kboed production, $2 billion annual revenue and $1.4 billion Adjusted EBITDAX. "As such we are pleased to announce our inaugural dividend policy. It is our goal to make reliable, recurring and sector-leading returns to shareholders, targeting a first dividend to be paid no later than during Q4 2022, following first gas from Karish (Q3 2022). This is made possible by our ongoing operational and financial success and represents an important new phase in Energean's corporate development. "Energean is focused on reducing its carbon emissions and we are working towards our 2050 net zero target. In 2021, we delivered a 8% year-on-year reduction in carbon emissions intensity to 18.3 kgCO2/boe[1]. Actions taken to achieve this reduction included implementing a zero routine flaring policy across our operated sites and switching to renewable-sourced electricity in Italy - having already put green electricity contracts in place for Israel and Greece in 2020. The latter has resulted in a 100% y-o-y reduction in Scope 2 emission at our operated sites. We continue to progress on our journey to net zero with key actions identified for this year. "2022 will be a landmark year for Energean. It will be the year of first production from our major project, Karish. It will be the year that brings us one step closer to our Net Zero Target. It will be the year we target to add a sustainable and reliable dividend stream to the total return to shareholders." Highlights �� Announcement of Inaugural Dividend Policy �� First gas from Karish on track for Q3 2022, development was 92.5% complete as at 31 December 2021 �� Revenues of $497 million ($336 million 2020 pro forma[2]) and Adjusted EBITDAX of $212 million ($108 million 2020 pro forma2), representing record full year results and the transition to net operating profit. Capital expenditure was $408 million ($565 2020 pro forma2) �� Reduced EGPC receivables to $95 million as at 31 December 2021 (c.40% y-o-y reduction) �� Average working interest production of 41.0 kboed (72% gas) was above initial guidance[3], with cost of production of $17.5/boe �� Spudded the Athena exploration well, offshore Israel. First drilling results expected during Q2 2022 �� Entered into a spot sales agreement with Israel Electricity Company ("IEC"), the biggest natural gas consumer in Israel for Karish gas �� Increased the weighted average debt maturity to six years, pushed out the first major repayment until 2024 and achieved blended fixed rate of 5.5%, removing exposure to floating rates �� Signed funding package backed by the Greek State for the Epsilon development project in Greece, due onstream in H1 2023 �� 8% year-on-year reduction in carbon emissions intensity when considering 2021 Energean data versus 2020 pro forma performance data Outlook �� First gas from Karish in Q3 2022 �� Payment of the inaugural dividend, targeted for no later than Q4 2022, following first gas from Karish (Q3 2022) �� 2022 average working interest production, excluding Israel, is expected to be 35.0 - 40.0 kboed. Israel production rate in 2022 is expected to average 25.0 - 30.0 kboed and will be a function of both the first gas date and the commercial ramp up achieved in the initial days and weeks of production �� 2022 development and production capital expenditure is expected to be $710 - 760 million[4] �� First gas from the first well at NEA/NI (Egypt) expected in H2 2022 �� Complete Pre-Front-End Engineering Design ("pre-FEED") on the carbon capture and storage ("CCS") project in Greece �� Secure additional Gas Sales Agreements in Israel and the region Financial Summary FY 2021 Pro Forma2 FY 2020 Consolidated Results FY 2020 $m $m $m Sales revenue 497.0 335.9 28.0 Cost of production ($/boe)[5] 17.5 11.3 21.4 Operating profit/(loss) 32.1 (422.2) (124.5) Adjusted EBITDAX 212.1 107.7 (8.3) Operating cash flow 132.5 137.0 1.5 Total capital expenditure[6] 407.9 565.4 429.0 Net debt (cash)[7] 2,016.6 1,240.1 1,240.1 Webcast & conference call A webcast will be held today at 08:30 GMT / 10:30 Israel Time Webcast: https://edge.media-server.com/mmc/p/fkryxi6m Dial-In: +44 (0) 2071 928338 Dial-in (Israel only): 035308845 Confirmation code: 2576809 The presentation slides will be made available on the website shortly at www.energean.com. Enquiries For capital markets: ir@energean.com Maria Martin, Head of Corporate Finance Tel: +44 7917 573 354 For media: pblewer@energean.com Paddy Blewer, Head of Corporate Communications Tel: +44 7765 250 857 Dividend Policy ��� Energean is targeting launch of its inaugural dividend, to be paid no later than during Q4 2022, following first gas from Karish (Q3 2022). ��� It is the Company's goal that shareholders will receive a sector - leading return on their investment through dividends and continued organic growth, while maintaining a disciplined capital allocation policy. ��� Energean targets paying dividends of at least $1 billion by the end of 2025. This is underpinned by predictable cashflows, largely insulated from commodity price fluctuation, thanks to long-term gas contracts with floor-price protection and high take-or-pay provisions. ��� The Company expects to begin with a quarterly dividend of at least $50 million. This amount will ramp-up in line with Energean's medium-term production and revenue targets to at least $100 million per quarter, as the Company's fully sanctioned and funded developments come onstream during the next 30 months. ��� The Board and Management will ensure that sufficient liquidity remains within the Group, to continue Energean's organic growth strategy and opportunistic M&A. ��� Post first gas from Karish, the Company expects a rapid deleveraging on a Group consolidated basis to levels below 1.5x (Net Debt/EBITDAX) and sees this being met no later than 2024. Corporate Review Financing During the course of 2021, Energean optimised its capital structure by refinancing through the debt capital markets. This resulted in a year end liquidity position in excess of $1 billion. Debt repayments have now been pushed out to 2024 and the weighted average debt maturity has increased to approximately six years as of 31 December 2021. In accessing the bond markets, Energean has also converted floating interest rate exposure to fixed rates giving a blended average interest rate of approximately 5.5%. Energean Israel Senior Secured Notes - non-recourse to PLC On 24 March 2021, Energean's subsidiary, Energean Israel Finance Limited completed the issuance of $2.5 billion aggregate principal of senior secured notes, split into four equal tranches with maturities in 2024, 2026, 2028 and 2031. This is non-recourse to the Group and was used, inter alia, to refinance the Company's $1.45 billion project finance facility and its $700 million term loan, to fund certain reserve accounts, and for transaction expenses and general corporate purposes. Energean PLC Senior Secured Notes On 18 November 2021, Energean plc completed the issuance of $450 million principal amount of senior secured notes due 2027, with a fixed annual interest rate of 6.5%. The proceeds were used to repay and cancel all amounts under the Egypt reserve based lending facility and the Greek reserve based lending facility plus subordinated debt, and for transaction expenses and general corporate purposes. Greek State-Backed Loan On 27 December 2021, the EUR 100 million funding package, backed by the Greek State, for the Epsilon and Prinos area development was finalised. EUR 90.5 million was provided by the Black Sea Trade and Development Bank ("BSTDB") and EUR 9.5 million directly by the Greek State. The tenor is seven and eight years respectively with first repayment not due until 2027. The blended interest rate is 2%. This facility is non-recourse to the Group. M&A Acquisition of the minority interest in Energean Israel Ltd On 25 February 2021, Energean closed the acquisition of the 30% minority interest in Energean Israel Ltd, held by Kerogen, for between $380 million and $405 million. The acquisition added 2P reserves of 20.5 billion cubic metres ("Bcm") of gas and 30 million barrels of liquids, representing approximately 219 MMboe in total, to the Company, included within the pro forma 2020 reserve position. The total consideration for the acquisition included i) $175 million of upfront consideration that was funded through partial drawdown of the $700 million term loan facility that was signed on 14 January 2021, ii) between $125 million and $150 million of deferred consideration, which is expected to be funded from the proceeds of the $2.5 billion bond issued and discussed above, iii) $30 million of deferred consideration payable at end-2022 and expected to be funded from free cash flows from the Karish project, and iv) $50 million of bilateral convertible loan notes that have been issued to Kerogen and have a maturity date of 29 December 2023, a strike price of GBP 9.50 and a zero-coupon rate. ESG and Climate Change Energean is committed to net zero emissions by 2050 and industry-leading disclosure of its energy transition intentions. Emissions reduction Energean maintains a rolling carbon intensity reduction plan and currently anticipates a reduction in carbon emissions intensity of 7.7 kgCO2/boe by 2025, a reduction of more than 85% versus 2019. The Group recorded full-year 2021 emissions intensity of 18.3 kgCO2/boe, a 8% y-o-y decrease. The difference in these figures versus those reported previously are due to reporting changes, as Energean has aligned with industry standards and now reports emissions based on an equity share accounting approach. During the year, Energean published its first Climate Change Policy, implemented a zero routine flaring policy across its operated sites and rolled out 'Green electricity' in Israel, Greece and Italy. The latter led to a 100% decrease y-o-y in Scope 2 emissions intensity at operated sites. The Prinos CCS project proposal is to provide long-term storage for carbon dioxide emissions captured from both local and more remote emitters. Energean estimates that the Prinos subsurface volumes are sufficient to sequester up to 100 million tonnes of CO2, representing up to around 50% of total annual emissions from the Greek manufacturing sector for 20 years. During 2021, the European Commission granted approval for the inclusion of the Greek CCS project within the Resilience and Recovery Fund. In H2 2021, Energean commenced pre-FEED for the Prinos CCS project. In March 2022, Energean signed a service contract with Halliburton for a carbon storage subsurface study in Greece. ESG awards In December 2021, the Carbon Disclosure Project ("CDP") upgraded its Climate Change rating for Energean to B, from B- in the previous year (this compares to a flat y-o-y sector average of C). In February 2022, the CDP also upgraded its Supplier Engagement rating to A- from B in the previous year. Energean was also awarded 'Best ESG Energy Growth Strategy - Europe 2021' by CFI and moved to the highest ranking 'Leader' on Overall ESG Score by Sustainalytics. Energean has also continued to comply with the Task Force on Climate Related Financial Disclosure ("TCFD") recommendations, full disclosure on which will be provided in the Annual Report and Accounts. Operational Review HSE In 2021 Energean delivered another excellent HSE record with improved Loss Time Injury Frequency ("LTIF") of 0.33 (0.65) and Total Recordable Incident Rate ("TRIR") of 0.77 (1.31). Production and Reserves Full year 2021 working interest 2P reserves were 965[8] MMboe, a 27% year-on-year increase vs. 2020[9], changes are due mainly to: �� The acquisition of Kerogen's 30% holding in Energean Israel Ltd. The transaction closed on 25 February 2021 and added 219 mmboe of 2P reserves. �� The increased equity interest in the producing Rospo Mare and Vega fields in early 2021, offshore Italy, to 100% for zero consideration, adding approximately 12 MMboe of 2P oil reserves and offsetting 2021 production. 2021 2P Reserves MMboe (% gas) 2020 pro forma 2P Reserves MMboe (% gas) 2020 2P Reserves MMboe (% gas) Israel 744 (86%) 730 (86%)[10] 511 (86%) Egypt 103 (87%) 114 (88%) 114 (88%) Italy 78 (55%) 79 (54%) 79 (54%) Greece 37[11] (3%) 53 (2%) 53 (2%) Croatia 2 (100%) 2 (100%) 2 (100%) UK 2 (14%) 2 (22%) 2 (22%) Total 965 (81%) 982 (79%) 762 (77%) 2021 working interest production was 41.0 kboed, which was above initial guidance[12] and 15% lower than 2020 pro forma as a result of natural decline in Abu Qir and scheduled maintenance downtime in UK and Greece. 2021 Kboed (% gas) 2020 Pro forma Kboed (% gas) 2020 Consolidated Kboed (% gas) Egypt 29.1 (87%) 35.4 (86%) 1.4 (87%) Italy 9.9 (41%) 9.1 (52%) 0.3 (53%) Greece & Croatia 1.3 (12%) 2.0 (10%) 1.8 (8%) UK 0.7 (16%) 1.8 (29%) 0.1 (100%) Total 41.0 (72%) 48.3 (74%) 3.6 (39%) Israel Karish Gas Development Summary On 31 December 2021, the Karish Project was approximately 92.5% complete, as measured under the Group's contract with TechnipFMC. In early March 2022, the onshore pipeline was connected to the Israeli grid. The FPSO entered dry-dock on 14 March 2022 to be cleaned and prepared for sail-away and entry into Israeli waters. First gas remains on track for Q3 2022. 2021 Progress % Completion at 31 December 2021[13] Production Wells 100.0 FPSO 98.4 Subsea 83.6 Onshore 99.9 Total 92.5 Energean Power FPSO Progress and Key Milestones The Energean Power FPSO was approximately 98.4% complete, at year end 2021. In early 2021, all the remaining minor lifting work (flare stack, helicopter-deck and portside crane boom) was completed. The rest of H1 2021 was spent completing the connection between the topsides and the hull and completing the marine systems in the hull. In H2 2021, the focus was on commissioning activities ahead of sail-away. In December 2021, the penultimate major technical milestone associated with the construction of the Energean Power FPSO was successfully completed. This involved testing the telescopic design of the emergency flare stack which will allow the vessel to pass under the Suez Canal Bridge, hence avoiding the need to either sail around Africa or to install the system in the Mediterranean Sea. This has further reduced the environmental footprint of the construction phase whilst shortening the schedule. The FPSO entered dry-dock on 14 March 2022 to be cleaned and prepared for sail-away and entry into Israeli waters. Subsea and Onshore Progress Subsea works were approximately 83.6% complete at year-end 2021, with the risers, spools metrology and 90-kilometre gas sales pipeline finished. The export pipeline was also successfully hydrotested during this period, to ensure no leaks throughout the length of the pipe. Onshore work was substantially complete at year end (99.9% under the Technip FMC EPCIC), with construction and civil works completed. The remaining outstanding work is to finish the site restoration work (e.g. replanting cleared trees). The onshore pipeline was connected to the national grid in March 2022. Gas from the Karish field will flow to the Energean Power FPSO, located 90 km offshore, where production output will be processed and separated. The treated gas will then be delivered from an underwater pipeline to the land-based system at the Dor Station before entering the national pipeline on its way to distribution companies and end consumers. The outstanding work is to hook-up the risers to the FPSO, upon its arrival in Israel in Q2 this year. Israel Growth Projects 1. Karish North In January 2021, Energean reached FID at the 1.2 Tcf (33 Bcm[14]) Karish North field, 21-months after the announcement of the discovery. The KN-01 exploration well will be re-entered, side-tracked and completed as a production well as part of the Israel growth drilling campaign, expected during the summer 2022 following completion of the Athena (Block 12) exploration well and the Karish Main-04 appraisal well. Karish North is expected to commence production in H2 2023. A second well is expected to be drilled in 2026 and, combined with later life workovers to both wells, is expected to be sufficient to fully develop the 244 MMboe of 2P reserves. 2. Second oil train & riser In May 2021, Energean took FID on two high-return growth projects. The first, a second oil train on the FPSO that will increase the liquids capacity from 18 kboed to 32 kboed. The second, a second gas sales riser, will enable gas production at the full 8 Bcm/yr capacity of the FPSO. In December 2021, Energean signed an EPC contract with KANFA AS for the second oil train. Both projects made good progress in 2021 and are expected onstream in H2 2023 as planned. The total cost of Karish North and the second oil train & riser is expected to be $275 million, which includes the cost of the Karish North development well. 3. Growth drilling programme In March, the Athena exploration well (Block 12) was spudded. This well is targeting 21 Bcm (totalling 140 mmboe). Success at Athena is economically significant, de-risking the remaining prospects in the block. It can be monetised on an expedited basis due to its proximity to the FPSO. After Athena the following wells will be drilled, in order of sequence: �� Karish Main 4 - Appraisal - Firm �� Karish North - Development - Firm �� Hermes (Block 31) - Exploration - Optional �� Hercules (Block 23) - Exploration - Optional A decision on whether to drill the optional wells, as part of this drilling campaign, will be made in Q2 2022. Local Israeli market opportunities, as well as export commercialisation routes, are being matured to access international gas prices if (and when) additional volumes become available. Gas Contracts Existing GSPAs Energean has signed 18[15] 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. In 2021, for one agreement representing 0.2 Bcm/yr and commencing 2024, the buyer was 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. In addition, in November 2021, further to its initiation of arbitration proceedings, Dalia sent notices to Energean purporting to terminate its gas sales agreement (which represents 0.8 bcm/yr of contracted gas sales), whilst also attempting to reserve its rights by claiming that should the notices be determined to be invalid or wrongly issued, the gas sales agreement would not have been terminated. Energean believes that the notices served by Dalia are invalid and constitute a material breach of contract, giving it the right to terminate the contract. Energean has exercised this right and, as part of the same arbitration proceedings, is seeking to recover damages suffered by it as a result of such termination. The amount of the damages will ultimately depend on the price which Energean is able to achieve for the gas that would have been sold to Dalia. This is currently estimated to be between $105-407 million. Alternative commercialisation opportunities Energean has identified a number of incremental buyers for its gas reserves and prospective resources. In Israel, the third gas fired power plant auctioned as part of the IEC privatisation process (Hagit) was awarded. The winning consortium is now seeking gas supply. In December 2021, Energean signed an MOU with EGAS for the sale and purchase of up to 3 Bcm/yr of natural gas on average for a period of 10 years, commencing with initial volumes of up to 1 Bcm/yr. This represents a commercialisation option for gas resources discovered in the 2022/23 drilling campaign. Energean and EGAS have identified existing transportation routes for the delivery of these volumes. Energean is confident of selling all volumes into strong domestic and regional markets and commercial discussions are underway with a number of domestic and international buyers. In March 2022, Energean signed a supply agreement with the Israel Electric Company ("IEC"), the largest natural gas consumer in Israel for Karish Gas. The gas price will be determined month ahead, with volumes determined on a daily basis. Starting upon the commencement of first gas production from Karish, the agreement will be valid for an initial one-year period with an option to extend subject to ratification by both parties. The agreement will optimise Energean's gas sales portfolio. Liquids Marketing Agreement In March 2022, Energean signed a limited term exclusivity agreement and term sheet for the marketing of its Karish liquids with Vitol SA. While the parties are still negotiating the related binding SPA contract, including technical aspects to be clarified, and the exclusivity does not bind the parties to finalise such a contract, Energean is looking forward to furthering its cooperation with Vitol, with whom the Company enjoys a valuable working relationship. Egypt Production In the 12-months to 31 December 2021, working interest production from the Abu Qir area averaged 29.1 kboed (87% gas), around the mid-point of full year production guidance (28.5 - 30.0 kboed). Q4 production was impacted by scheduled work-over activities, which ultimately enhanced the year end exit rate. NEA/NI In January 2021, Energean sanctioned the North East Almeyra ("NEA")/North Idku ("NI") project, shallow-water offshore Egypt and neighbouring the Abu Qir concession. An Engineering, Procurement, Construction and Installation ("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 February 2021. NEA/NI is progressing on budget and on schedule, being 37.0% complete as of 31 December 2021. Onshore fabrication of the subsea kit is progressing well. First gas from one well is anticipated in H2 2022, with the remaining three wells expected online in H1 2023. The project contains an estimated 29 MMboe of 2P reserves and 23 MMboe of 2C reserves according to D&M. Peak working interest production is expected to be approximately 69 MMscfd plus 1.7 kbopd of condensate and LPG (around 15 kboed in total). On 9 January 2022, the rig contract for the four well drilling campaign was signed with EDC for the El Qaher-1 jack-up rig. Drilling is anticipated to begin in H2 2022. Receivables As at 31 December 2021, net receivables (after provision for bad and doubtful debts) in Egypt were $95 million, of which $51 million was classified as overdue. Energean has reduced its net EGPC receivables balance by over 75% compared to the balance prevailing at the economic reference date of the Edison E&P acquisition (1 January 2019: $240 million), highlighting the successful outcome of Energean's strategy to reduce the receivables balance and generating additional value from the acquisition. Abu Qir drilling programme Energean expects to drill an infill well in Q2 2022 to support production in the Abu Qir concession. An additional three wells, currently under technical review, are expected to be drilled following the NEA/NI drilling programme. New onshore exploration acreage On 3 January 2022, an international consortium led by Energean Egypt (50% operator and Croatia's INA, d.d. 50%) was awarded an exploration licence for the East Bir El-Nus concession (Block-8), in the Western Desert of Egypt. The award is in line with Energean's strategy to increase and diversify its presence in Egypt and reinforces its commitment to the country. The work programme for the licence includes a 180 linear km 2D seismic survey, a 200 km2 3D seismic survey plus two exploration wells, which are expected to target estimated resources (in place) of approximately 100 mmboe. Europe Italy A new gas supply agreement ("GSA") was signed with A2A in Italy for the delivery of gas, commencing 1 April 2022 until 30 September 2023. Under the agreement, Energean will sell its full entitlement production to A2A, at PSV day-ahead prices, which agrees to purchase, take and pay for the quantities. Production In the 12-months to 31 December 2021, working interest production from Italy averaged 9.9 kboed (41% gas), at the top end of full year production guidance (9.5 - 10.0 kboed). During early 2021, Energean increased its positions in the Vega and Rospo Mare fields to 100% (from 60% and 62%, respectively) at nil cost and with an economic reference date of 1 January 2021. ENI retains its share of abandonment expenses associated with both fields. Cassiopea First gas from Cassiopea remains on track for 1H 2024, being 24.2% complete as of 31 December 2021. In September 2021, ENI began construction of the gas treatment plant for the Cassiopea project (Energean, 40% non-operated interest). In line with Energean's sustainability strategy, the project will, according to ENI, have close to zero emissions and the installation of 1 MWp of photovoltaic solar panels will allow the project to achieve carbon neutrality. Greece and Croatia In the 12 months to 31 December 2021, working interest production from Greece and Croatia averaged 1.3 kboed (12% gas), slightly lower than the full year production guidance of 1.5 kboed due to downtime for scheduled maintenance and union dispute on the Prinos Assets in Greece. Greece Following the signing of the EUR 100 million funding package (see above Financing section), Energean recommenced work on the Epsilon development which includes the completion of the Lamda platform, tie back to the existing Prinos complex and completion of three wells which were pre-drilled in 2019. First oil from the Epsilon development, which has 2P reserves and 2C resources of 53 mmboe in aggregate, is expected in H1 2023. Fabrication of the jacket and piles is due to be completed in Q2 2022, after which the piles, pipeline and jacket will be installed. Pre-FEED for the Prinos CCS project is progressing well and is expected to complete by the end of Q2 2022. In March 2022, Energean signed a service contract with Halliburton for a carbon storage subsurface study in Greece. Please see the Emissions Reduction section above for more detail. Croatia Energean is currently in FEED for the development of the Irena gas field, located five kilometres north of the Izabela field offshore Croatia, with the target to take FID on the project in Q4 2022. If progressed, first gas is anticipated in Q4 2024. The field has 2P reserves of 0.4 bcm (2.3 mmboe)[16]. Montenegro Technical evaluation of Blocks 26 and 30 has been completed. Energean's focus is on the significant biogenic gas potential identified. The Ministry has agreed to extend the deadline of the first exploration period in Montenegro by four months from the original expiration date of 15 March 2022 to facilitate the obligated introduction of a partner. UK North Sea In the 12-months to 31 December 2021, production in the UK North Sea was 0.7 kboed (16% gas), ahead of full year guidance of 0.5 kboed due to extended production from the Wenlock field. The Glengorm Central appraisal well contained no commercial hydrocarbons and has been plugged and abandoned. A comprehensive data analysis program is underway. The results of the Glengorm appraisal programme will be evaluated to inform forward plans for the P.2215 licence. Energean has received interest from third parties with respect to the potential sale of its UK assets portfolio and is continuing to consider and develop its options. Malta On 17 December 2021, Energean terminated its Malta Exploration Study Agreements (Blocks 1,2, and 3 of Area 3). This marked an exit from operations in the country. 2022 Guidance FY 2022 Production Israel (kboed) 25.0 - 30.0 (including 1.0 - 1.3 bcm of gas) Egypt (kboed) 24.5 - 28.0 Italy (kboed) 9.0 - 10.0 Greece & Croatia (kboed) 1.0 - 1.5 UK North Sea (kboed) 0.5 Total production, including Israel (kboed) 60.0 - 70.0 Total production, excluding Israel (kboed) 35.0 - 40.0 Financials Consolidated net debt ($ million) 2,600 - 2,800[17] Cost of Production (Operating Costs plus Royalties) Israel ($ million)[18] 90-120 Egypt ($ million) 60 Italy ($ million) 150 (including flux costs of approximately $20 million) Greece & Croatia ($ million) 30 UK North Sea ($ million) 30 Total Cost of Production ($ million) 360-390 Cash SG&A ($ million) 35 - 40 Development and production capital expenditure Israel ($ million) 450-500[19] Egypt ($ million) 140 Italy ($ million) 80 Greece and Croatia ($ million) 35 UK North Sea ($ million) 5 Total Development & Production Capital Expenditure ($ million) 710-760 Exploration Expenditure Israel ($ million) 95[20] - Egypt, Italy, Greece and Croatia ($ million) 5 UK North Sea ($ million) 10 Total Exploration Expenditure ($ million) 100 Decommissioning UK North Sea 5 Italy 15 Decommissioning expenditure ($ million) 20 Financial Review 2021 Pro forma 2020 2020 Change from 2020 pro forma Average working interest production (Kboepd) 41.0 48.3 3.6 (15.1%) Sales revenue ($m) 497.0 335.9 28.0 48.0% Cash cost of production ($m) 261.6 198.9 28.5 31.5% Cost of production ($/boe) 17.5 11.3 21.4 54.9% Administrative & selling expenses ($m) 43.0 41.4 15.3 3.8% Operating profit/(loss) ($m) 32.1 (422.2) (124.5) 107.6% Adjusted EBITDAX ($m) 212.1 107.7 (8.3) 96.9% Loss after tax ($m) (96.2) (416.4) (92.9) 74.1% Cash flow from operating activities ($m) 132.5 137.0 1.5 (2.8%) Capital expenditure ($m) 407.9 565.4 429.0 (27.8%) Cash capital expenditure ($m) 452.2 550.8 419.0 (17.9%) Net debt ($m) 2,016.6 1,240.1 1,240.1 62.6% Net debt/equity (%) 285.8 103.8 103.8 175.3% Revenue, production, and commodity prices Sales revenue increased by $469 million ($161.1 million or 48.0%, on a pro forma basis to account for the Edison E&P acquisition) to $497.0 million primarily as a result of higher realised commodity prices and an increase in production volumes for both liquids and gas, due to the Edison E&P acquisition. Our pro forma revenue increase was driven primarily by commodity price strong recovery. The Group's realised oil and gas price for the period was $57.1/bbl and $5.2 $/mcf respectively. Working interest production averaged 41.0 kboepd in 2021 (2020: 3.6 kboepd or 48.3 kboepd on a proforma basis), with the Abu Qir gas-condensate field, offshore Egypt, accounting for over 70% of total output. The decrease in pro forma production was driven primarily by a decrease in production from Abu Qir and UK fields partially offset by the increase of the working interest in the Vega and Rospo fields in Italy. EBITDAX amounted to $212.1 million (2020: $(8.3) million or $107.7 million on a pro forma basis). The increase from 2020 proforma EBITDAX was due to higher revenue partially offset by higher operating costs from the enlarged group. Cash cost of production Cash production costs for the period were $17.5 /boe (2020: $21.4 /boe or $11.3/boe on a pro forma basis). The increase in pro forma cash unit production cost was primarily driven by decreased production and additional planned maintenance during extended summer shut-downs deferred from 2020 as a result of COVID-19. Additionally, production costs were also impacted by the strengthening of Euro against the US Dollar during the period. Depreciation, impairments and write-offs Depreciation charges before impairment on production and development assets increased by 303.9% to $97.5 million (2020: $24.1 million or $166.3 million on a pro forma basis) due to higher DD&A charges on acquired Edison E&P assets. Depreciation unit expense was $6.5/boe (2020: $18.4/boe or $9.4/boe on a pro forma basis). The Group recognised a pre-tax impairment charge of $65.3 million in 2020 for the Prinos CGU as a result of a reduction in both short-term (Brent forward curve) and long-term price assumptions and a change in the production forecasts for the Prinos field. There were no such impairments for the year ended 31 December 2021 Exploration and evaluation expenditure and new ventures During the period the Group expensed $87.7 million (2020: $4.4 million or $164.6 million on a pro forma basis) for exploration and new ventures evaluation activities. This includes costs ($79.8 million) associated with exploration and appraisal activities write-off for Glengorm South and Glengorm Central. In 2021 two appraisal wells were drilled targeting the Glengorm South and Glengorm Central segments. Both wells were unsuccessful and did not find hydrocarbons. All wells have been plugged and abandoned. The remainder of the impairment is as a result of the increase to the decommissioning estimate in Italy. In addition, new ventures evaluation expenditure amounted to $5.6 million (2020: $1.5 million), mainly related to pre-licence and time-writing costs. Selling, general and administrative (SG&A) expenses Energean incurred SG&A costs of approximately $43.0 million in 2021 (2020: $15.3 million or $41.4 million on a pro forma basis). The increase is primary driven from the additional staffing and administrative costs associated with the new acquired Edison E&P business. Cash SG&A was $34.8 million (2020: $11.7 million or $35.5 million on a pro forma basis). Net other income Net other income of $10.9 million in 2021 (2020: $19.1 million expenses) includes $6.8 million of income due to a decrease in estimates of decommissioning provisions for certain UK producing assets, representing the amount of the decrease that was in excess of their book value. Unrealised loss on derivatives The Group has recognised unrealised loss on derivative instruments of $21.5 million related to the Cassiopea contingent consideration. A contingent consideration of up to $100.0 million is payable and determined on the basis of future gas prices (PSV) recorded at the time of the commissioning of the field, which is expected in 2024. As at 31 December 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. The fair value of the Contingent Consideration as at 31 December 2021 was estimated to be $78.5m based on a Monte Carlo simulation (31 December 2020: $55.2 million). Net financing costs Financing costs before capitalisation for the period were $278.4 million (2020: $102.7 million). including $107.0 million of interest expenses incurred on Senior Secured notes (2020: nil), $96.7 million on debt facilities (2020: $90.0 million) and $4.1 million (2020: $6.7 million) of interest expenses relating to long-term payables, representing future payments to the previous Karish & Tanin licence holders. Finance costs include mainly: unwinding of discount on deferred consideration, decommissioning provisions and other liabilities of $27.7million (2020: $1.2million); expensing of the unamortised costs under Greek and Egypt RBL of $18.1 million, due to repayments prior to their maturity dates and arrangement fees, commissions for guarantees and other bank charges of $17.8 million (2020: $4.8 million). Net finance costs includes foreign exchange losses of $6.9 million (2020: $15.4million foreign exchange gain). Finance income amounted to $3.0 million (2020: $0.5 million), including Interest income from time deposits. Taxation Energean recorded tax charges of $5.4 million in 2021 (2020: $20.5 million tax credit), split between a current and prior year tax expense of $44.5 million (2020: $0.8 million), and a deferred tax credit of $39.2 million (2020: credit $21.5 million) and representing an effective rate of 19 per cent (2020: 18 per cent). Operating cash flow Cash from operations before tax and movements in working capital was $136.7 million (2020: ($25.5) million). After adjusting for tax and working capital movements, cash from operations was $132.5million (2020: $1.5 million or $137.0 million on a pro forma basis). The decrease on a pro forma basis was primarily driven by payments made for buyers compensation in Israel amounting to $23.0 million and cash held on account in relation to the commodity hedges in Italy of $29.4 million. Capital Expenditures During the period, the Group incurred capital expenditures of $407.9 million (2020: $429 million). Capital expenditure mainly consisted of development expenditures in relation to the Karish Main and Karish North Fields in Israel ($243.4 million) , NEA project in Egypt ($52 million), Cassiopea field in Italy ($37.0 million), Scott field in UK ($11.6 million) and exploration expenditures in relation to Glengorm and Isabella in UK ($40.5 million) and Athena, Hercules, Hermes in Israel ($6.0 million). Net Debt As at 31 December 2021, net debt of $2,016 million (2020: $1,240 million) consisted of $2,500 million Israeli senior secured notes,$450 million of corporate senior secured notes and $50 million of convertible loan notes, less deferred amortised fees, equity component of convertible loan ($10.5 million) and cash balances of $930.6 million. The Senior Credit Facility for the Karish-Tanin Development, the EBRD Senior Facility, the EBRD Subordinated Facility and the New Egypt RBL Facility were repaid during the year amounting to a total of $1,807 million. In accessing the bond markets, Energean has converted floating interest rate exposure to fixed rates giving a blended average interest rate of approximately 5% and increased Energean's weighted average debt maturity to approximately six years. Credit Ratings Energean maintains corporate credit ratings with Standard and Poor's (S&P) and Fitch Ratings (Fitch). On 4 November 2021 Energean plc was assigned its first corporate credit ratings from S&P and Fitch, following the issuance of the $450 million senior secured notes which mature in 2027. 1. S&P assigned a B corporate credit rating to Energean plc and B rating for the senior secured notes maturing in 2027, with Positive Outlook. The positive outlook reflects the expectation that Energean will successfully launch the Karish gas field in Israel in 2022, supporting the credit quality of the company. 2. Fitch assigned a B+ corporate credit rating to Energean plc and B+ rating for the senior secured notes maturing in 2027, with a Stable Outlook. Risk management Principal risks There are no significant changes to the headline principal risks from those disclosed in the 2021 Interim results. A full description of Energean's principal risks will be disclosed in its 2021 Annual Report & Accounts. Commodity price risk The Group undertakes hedging activities as part of the ongoing financial risk management to protect against commodity price volatility and to ensure the availability of cash flow for re-investment in capital programmes that are driving business delivery. Commodity hedge contracts entered into in Italy aim to mitigate the risk of changes to the cost of natural gas and that relating to the sale of natural gas. Hedge position 2022 2023 Gas Sales Volume hedged (MWs) 705,000 - Average priced hedged (���/MWs) 55.89 - At 31 December 2021, the Group's financial hedging programme on gas derivative instruments showed a pre-tax negative fair value of $12.5 million (2020: nil) included in other comprehensive income, with no ineffectiveness charge to the income statement. Liquidity risk management and going concern The Group carefully manages the risk of a shortage of funds by closely monitoring its funding position and its liquidity risk. The Going Concern assessment covers the period up to 31 March 2023 'the Forecast Period'. Cash forecasts are regularly produced based on, inter alia, the Group's latest life of field production, budgeted expenditure forecasts, management's best estimate of future commodity prices (based on recent published forward curves) and headroom under its debt facilities. The Base Case cash flow model used for the going concern assessment conservatively assumes first gas from Karish in October 2022, Brent at $80/bbl in 2022 and $75/bbl in 2023 and PSV (Italian gas price) at EUR55/MWH in 2022 and EUR40/MWH in 2023. In addition, on a regular basis, the Group performs sensitivity tests of its liquidity position to evaluate adverse impacts that may result from changes to the macro-economic environment such as a reduction in commodity prices. The Group is not exposed to floating interest rate risk. The Group also looks at the impact of changes or deferral of key projects. This is done to identify risks to liquidity to enable management to formulate appropriate and timely mitigation strategies in order to manage the risk of funds shortfalls and to ensure the Group's ability to continue as a going concern. Such assumptions underpin management's reasonable worst case scenario to further assess the robustness of the Group's liquidity position over the Forecast Period. Reverse stress testing was performed to determine what levels of prices and/or production would need to occur for the liquidity headroom to be eliminated, prior to any mitigating actions; the likelihood of such conditions occurring was concluded to be remote. In the event an extreme downside scenario occurred, prudent mitigating actions could be executed in the necessary timeframe such as a tightening of operating costs and reductions/postponement of other discretionary exploration and development expenditures. There is no material impact of climate change within the Forecast Period therefore it does not form part of the reverse stress testing performed by management. 1. As of 31 December 2021 the Group's available liquidity was approximately $1 billion. In terms of the Group's Borrowing Facilities, the following was considered as part of management's assessment: Energean Israel Project Bond: In March 2021 Energean raised $2.5 billion through the issuance of bonds to (i) refinance its $1.45 billion Israel Project Finance Facility, (ii) cancel and replace the $700 million Term Loan which was drawn to fund the acquisition of Kerogen's minority interest in Energean Israel, (iii) fund capital and exploration expenditure in Israel, including Karish and Karish North, and (iv) for general corporate purposes of the Group. 2. Energean plc Corporate Bond: In November 2021 Energean raised a $450 million Bond to (i) repay all amounts outstanding under the Egypt and Greek RBLs plus subordinated debt, (ii) to pay fees and other expenses related to the Bond, and (iii) for general corporate purposes of the Group. There are no financial maintenance covenants associated with either of the Bonds. 3. Greek State-Backed Loan In December 2021 Energean signed a EUR100 million loan backed by the Greek State which is to be used specifically for the development of the Prinos Area in Greece, including the Epsilon development. In forming its assessment of the Group's ability to continue as a going concern, including its review of the forecasted cashflow of the Group over the Forecast Period, the Board has made 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 within the Group's control, in the event this were required. After careful consideration, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future, for the Forecast Period to 31 March 2023. For this reason, they continue to adopt the going concern basis in preparing the consolidated financial statements. Events since December 2021 On 14 March 2022 - Energean signed a supply agreement with the Israel Electric Company, the largest Israeli buyer of natural gas. IEC will now have the right to purchase natural gas from Energean's fields. The gas price will be determined in each period, with purchased amounts determined on a daily basis. Starting upon the commencement of first gas production from Karish, the agreement will be valid for an initial one-year period with an option to extend subject to ratification by both parties. Non-IFRS measures The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include Adjusted EBITDAX, cost of production, capital expenditure, cash capital expenditure, net debt and gearing ratio and are explained below. 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 costs and to assess operational efficiency. Cash cost of production is calculated as cost of sales, adjusted for depreciation and hydrocarbon inventory movements. 2021 Pro forma 2020 2020 $m $m $m Cost of sales 345.1 364.6 48.4 Less: Depreciation (94.6) (163.1) (22.1) Change in inventory 11.1 (2.6) 2.2 Cost of production 261.6 198.9 28.5 Total production for the period (kboe) 14,963.5 17,621.0 1,331.0 Cash cost of production per boe ($/boe) 17.5 11.3 21.4 Adjusted EBITDAX Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, other income and expenses (including the impact of derivative financial instruments and foreign exchange), net finance costs and exploration costs. The Group presents Adjusted EBITDAX as it is used in assessing the Group's growth and operational efficiencies, because it illustrates the underlying performance of the Group's business by excluding items not considered by management to reflect the underlying operations of the Group. 2021 Pro forma 2020 2020 $m $m $m Adjusted EBITDAX 212.1 107.7 (8.3) Reconciliation to profit/(loss): Depreciation and amortisation (97.5) (166.3) (24.1) Share-based payment (5.7) (3.2) (3.2) Exploration and evaluation expense (87.7) (164.6) (4.4) Impairment loss on property, plant and equipment - (182.9) (65.3) Other expense (7.0) (35.0) (28.3) Other income 17.9 22.1 9.1 Finance expenses (97.4) (16.9) (5.0) Finance income 3.0 1.2 0.4 Unrealised loss on derivatives (21.5) - - Net foreign exchange (6.9) 7.8 15.5 Taxation income/(expense) (5.4) 13.7 20.7 Loss for the year (96.2) (416.4) (92.9) Capital expenditure Capital expenditure is a useful indicator of the Group's organic expenditure on oil and gas assets and exploration and appraisal assets incurred during a period. Capital expenditure is defined as additions to property, plant and equipment and intangible exploration and evaluation assets less decommissioning asset additions, right-of-use asset additions, capitalised share-based payment charge and capitalised borrowing costs: 2021 Pro forma 2020 2020 $m $m $m Additions to property, plant and equipment 521.4 659.1 550.6 Additions to intangible exploration and evaluation assets 54.8 108.1 11.8 Less: 168.2 201.8 133.4 Capitalised borrowing cost 181.0 97.7 97.7 Leased assets additions and modifications 8.7 17.2 2.0 Lease payments related to capital activities (10.9) (12.0) (6.6) Capitalised share-based payment charge 0.2 0.1 0.1 Capitalised depreciation 0.2 0.6 0.6 Change in decommissioning provision (11.0) 98.2 39.6 Total capital expenditures 408.0 565.4 429.0 Movement in working capital 44.3 14.6 10.0 Cash capital expenditures per the cash flow statement 452.3 550.8 419.0 Cash Capital Expenditure 2021 2020 $m $m Payment for purchase of property, plant and equipment 403,503 403,986 Payment for exploration and evaluation, and other intangible assets 48,674 15,041 Total Cash Capital Expenditure 452,177 419,027 Net debt/(cash) and gearing ratio Net debt is defined as the Group's total borrowings less cash and cash equivalents. Management believes that net debt is a useful indicator of the Group's indebtedness, financial flexibility and capital structure because it indicates the level of borrowings after taking account of any cash and cash equivalents that could be used to reduce borrowings. The Group defines capital as total equity and calculates the gearing ratio as net debt divided by total equity. 2021 2020 $m $m Current borrowings - 1,113.0 Non-current borrowings 2,947.1 330.0 Total borrowings 2,947.1 1,443.0 Less: Cash and cash equivalents and bank deposits (730.8) (202.9) Restricted cash (199.7) - Net Debt (1) 2,016.6 1,240.1 Total equity (2) 717.1 1,194.4 Gearing Ratio (1)/(2) 281.2% 103.8% 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. Group Income Statement YEAR ENDED 31 DECEMBER 2021 2021 2020 Notes $'000 $'000 Revenue 4 496,985 28,014 Cost of sales 5a (345,112) (48,416) Gross profit/(loss) 151,873 (20,402) Administrative and selling expenses 5b/c (42,973) (15,283) Exploration and evaluation expenses 5d (87,678) (4,424) Impairment of property, plant and equipment 8 - (65,299) Other expenses 5e (7,019) (28,329) Other income 5f 17,884 9,186 Operating profit/ (loss) 32,087 (124,551) Finance income 6 2,950 493 Finance costs 6 (97,380) (4,986) Unrealised loss on derivatives 18 (21,477) - Net foreign exchange gain/(losses) 6 (6,922) 15,445 Loss before tax (90,742) (113,599) Taxation income / (expense) 11 (5,412) 20,741 Loss for the year (96,154) (92,858) Attributable to: Owners of the parent (96,046) (91,414) Non-controlling interests (108) (1,444) (96,154) (92,858) Basic and diluted loss per share (cents per share) Basic 2 ($0.54) ($0.52) Diluted 2 ($0.54) ($0.52) Group Statement of Comprehensive Income YEAR ENDED 31 DECEMBER 2021 2021 2020 $'000 $'000 Loss for the year (96,154) (92,858) Other comprehensive profit/(loss): Items that may be reclassified subsequently to profit or loss Cash Flow hedges Gain/(loss) arising in the period (6,182) (7,483) Income tax relating to items that may be reclassified to profit or loss 1,546 1,721 Exchange difference on the translation of foreign operations, net of tax (12,781) 19,222 (17,417) 13,460 Items that will not be reclassified subsequently to profit or loss Remeasurement of defined benefit pension plan (165) (49) Income taxes on items that will not be reclassified to profit or loss 40 12 (125) (37) Other comprehensive profit/(loss) after tax (17,542) 13,423 Total comprehensive loss for the year (113,696) (79,435) Total comprehensive loss attributable to: Owners of the parent (113,590) (76,262) Non-controlling interests (106) (3,173) (113,696) (79,435) Group Statement of Financial Position YEAR ENDED 31 DECEMBER 2021 2021 2020 Notes $'000 $'000 ASSETS Non-current assets Property, plant and equipment 8 3,499,473 3,107,272 Intangible assets 9 228,141 275,816 Equity-accounted investments 4 4 Other receivables 13 52,639 31,568 Deferred tax asset 10 154,798 126,056 Restricted cash 12 100,000 - 4,035,055 3,540,716 Current assets Inventories 87,203 73,019 Trade and other receivables 13 288,526 318,339 Restricted cash 12 99,729 - Cash and cash equivalents 11 730,839 202,939 1,206,297 594,297 Total assets 5,241,352 4,135,013 EQUITY AND LIABILITIES Equity attributable to owners of the parent Share capital 2,374 2,367 Share premium 915,388 915,388 Merger reserve 139,903 139,903 Other reserves 7,488 1,792 Foreign currency translation reserve (12,823) (42) Share-based payment reserve 19,352 13,419 Retained earnings (354,559) (144,734) Equity attributable to equity holders of the parent 717,123 928,093 Non-controlling interests 14 - 266,299 Total equity 717,123 1,194,392 Non-current liabilities Borrowings 15 2,947,126 330,092 Deferred tax liabilities 10 67,425 68,609 Retirement benefit liability 2,767 7,839 Provisions 16 801,026 881,535 Other payables 17 225,987 177,193 4,044,331 1,465,268 Current liabilities Trade and other payables 17 454,986 355,454 Current portion of borrowings 15 - 1,112,984 Derivative financial instruments 12,546 6,915 Provisions 16 12,366 - 479,898 1,475,353 Total liabilities 4,524,229 2,940,621 Total equity and liabilities 5,241,352 4,135,013 Group Statement of Changes in Equity YEAR ENDED 31 DECEMBER 2021 Share capital Share premium[21] Other reserve[22] Equity component of convertible bonds[23] Share based payment reserve[24] Translation reserve[25] Retained earnings Merger reserves Total Non-controlling interests Total $'000 $'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 - - - - - - (91,414) - (91,414) (1,444) (92,858) Remeasurement of defined benefit pension plan (37) - (37) (37) Hedges net of tax - - (4,033) - - - - - (4,033) (1,729) (5,762) Exchange difference on the translation of foreign operations - - - - - 19,222 - - 19,222 - 19,222 Total comprehensive income - - (4,070) - - 19,222 (91,414) - (76,262) (3,173) (79,435) Transactions with owners of the company Share capital increase in subsidiary - - - - - - - - - 9,750 9,750 Employee share schemes - - - - 3,325 - - - 3,325 - 3,325 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 (96,046) (96,046) (108) (96,154) Remeasurement of defined benefit pension plan (125) (125) (125) Hedges, net of tax (4,638) (4,638) 2 (4,636) Exchange difference on the translation of foreign operations (12,781) (12,781) (12,781) Total comprehensive income - - (4,763) - - (12,781) (96,046) - (113,590) (106) (113,696) Transactions with owners of the company Share based payment charges 5,940 5940 5,940 Exercise of Employee Share Options 7 (7) - - Acquisition of non-controlling Interests[26] - - - 10,459 - - (113,779) - (103,320) (266,193) (369,513) At 31 December 2021 2,374 915,388 (2,971) 10,459 19,352 (12,823) (354,559) 139,903 717,123 - 717,123 Group Statement of Changes in Equity YEAR ENDED 31 DECEMBER 2021 2021 2020 Note $'000 $'000 Operating activities Loss before taxation (90,742) (113,599) Adjustments to reconcile loss before taxation to net cash provided by operating activities: Depreciation, depletion and amortisation 8, 9 97,451 24,125 Impairment loss on property, plant and equipment 8 65,299 Loss from the sale of property, plant and equipment 36 7,568 Impairment loss on intangible assets 9 82,125 2,936 Defined benefit (gain)/expenses (4,061) 104 Movement in provisions 16 (4,462) (204) Payments for buyers compensation[27] (22,958) - Change in decommissioning provision estimates (10,198) - Finance income 6 (2,951) (493) Finance costs 6 97,374 4,986 Unrealised loss on derivatives 18 21,477 - Non-cash revenues from Egypt[28] (39,100) - Other liabilities derecognised 7(f) - (4,094) Share-based payment charge 5,734 3,325 Net foreign exchange loss/(gain) 6 6,922 (15,445) Cash flow from/(used in) operations before working capital 136,648 (25,492) (Increase)/decrease in inventories (16,484) 1,944 Decrease in trade and other receivables 46,351 24,936 (Decrease)/increase in trade and other payables (34,726) 136 Cash from operations 131,789 1,524 Income tax received/(paid) 715 (55) Inflow from operating activities 132,503 1,469 Investing activities Payment for purchase of property, plant and equipment 8 (403,503) (403,968) Payment for exploration and evaluation, and other intangible assets 9 (48,674) (15,041) Acquisition of a subsidiary, net of cash acquired 841 (203,204) Movement in restricted cash (199,729) - Proceeds from disposal of property, plant and equipment - 1,879 Amounts received from INGL related to the future transfer 17 of property, plant and equipment[29] 5,673 22,229 Interest received 2,608 542 Net cash used in investing activities (642,783) (597,563) Financing activities Drawdown of borrowings 15 175,000 557,000 Repayment of borrowings 15 (1,807,140) (38,040) Senior secured notes Issuance 15 3,068,000 Proceeds from capital increases by non-controlling interests - 9,750 Acquisition of non-controlling interests 14 (175,000) - Transaction costs related to acquisition of non-controlling interest (1,677) - Repayment of obligations under leases (10,852) (6,645) Debt arrangement fees paid (48,377) (11,563) Finance cost paid for deferred license payments (3,494) (3,993) Finance costs paid (136,694) (70,463) Net cash inflow financing activities 1,059,765 436,045 Net increase / (decrease) in cash and cash equivalents 549,485 (160,049) Cash and cash equivalents at beginning of the period 202,939 354,419 Effect of exchange rate fluctuations on cash held (21,585) 8,568 Cash and cash equivalents at end of the period 11 730,839 202,939 1. Basis of preparation and presentation of financial information Whilst the financial information in this preliminary announcement has been prepared in accordance with UK-adopted International Accounting Standards (UK-adopted IAS) and with the requirements of the United Kingdom Listing Authority (UKLA) Listing Rules, this announcement does not contain sufficient information to comply with IFRS. The Group will publish full financial statements that comply with IFRS in April 2021. The financial information for the year ended 31 December 2021 does not constitute statutory accounts as defined in sections 435 (1) and (2) of the Companies Act 2006. The consolidated and parent company financial statements for the year ended 31 December 2020 have been delivered to the Registrar of Companies; the auditor's report on these accounts was unqualified, did not include a reference to any matters by way of emphasis and did not contain a statement under Section 498 (2) or Section 498 (3) of the UK Companies Act 2006. Following a review of the Group's 2020 Annual Report by the Directors subsequent to correspondence with the Financial Reporting Council ('FRC'), the Group has changed the classification of the amounts received from INGL from financing activities to investing activities. These cash inflows represent the contribution received from INGL in relation to the onshore section of the Karish and Tanin infrastructure and the near shore section of pipeline extending to approximately 10km offshore. For further information on the INGL transaction refer to note 17. The Group previously presented the contributions from INGL as financing activities as this was reflective of the length of time between their receipt from INGL and when Energean is expected to complete the construction of this infrastructure. Following the review performed, the Group has reconsidered the treatment and considers that the cash inflows from INGL should be classified as investing activities in accordance with IAS 7 as they do not meet the definition of a financing activity, which is 'activities that result in changes in the size and contribution of the contributed equity and borrowings of the entity'. Comparative figures for the 2020 financial year have been restated as follows. As previously Stated ($'000) Reclassification of prepayments from INGL ($'000) Restated ($'000) Amounts received from INGL related to the future transfer of property, plant & equipment - 22,229 22,229 Net Cash USED in Investing activities (619,792) 22,229 (597,563) Advance payment from future sale of property, plant and equipment (INGL) 22,229 (22,229) - Net cash inflow from financing Activities 458,275 (22,229) 436,046 The FRC has confirmed that the matter is now closed. The FRC's question was originally contained in a letter issued in respect of our 2020 Annual Report & Accounts. The FRC's role is to consider compliance with reporting standards and is not to verify the information provided to them. Therefore, given the scope and inherent limitations of their review, which does not benefit from any detailed knowledge of the Group, it would not be appropriate to infer any assurance from their review that our 2020 Annual Report and Accounts was correct in all material respects. The accounting policies applied are consistent with those adopted and disclosed in the Group's financial statements for the year ended 31 December 2021. There have been a number of amendments to accounting standards and new interpretations issued by the International Accounting Standards Board which were applicable from 1 January 2021, however these have not any impact on the accounting policies, methods of computation or presentation applied by the Group. Further details on new International Financial Reporting Standards adopted will be disclosed in the 2021 Annual Report and Accounts. Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2021 reporting periods and have not been early adopted by the Group. These standards are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions. 2. Loss per share Basic loss per ordinary share amounts are calculated by dividing net loss for the year attributable to ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year. Diluted loss per ordinary share amounts are calculated by dividing net loss for the year attributable to ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of dilutive ordinary shares that would be issued if employee and other share options or the convertible bonds were converted into ordinary shares. 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. Before the acquisition of Edison E&P on 17 December 2020, 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 & inter-segment transactions Total $'000 $'000 $'000 $'000 $'000 Year ended 31 December 2021 Revenue from Oil 165,496 - - 144 165,640 Revenue from Gas 137,468 - 133,503 (2) 270,969 Other 13,156 - 55,446 (8,226) 60,376 Total revenue 316,120 - 188,949 (8,084) 496,985 Adjusted EBITDAX[30] 88,288 (4,969) 130,634 (1,881) 212,072 Reconciliation to profit before tax: Depreciation and amortisation expenses (55,001) (93) (41,626) (731) (97,451) Share-based payment charge (967) (231) - (4,523) (5,721) Exploration and evaluation expenses (86,490) (50) - (1,138) (87,678) Other expense (2,150) (461) (1,543) (2,865) (7,019) Other income 16,065 19 1,851 (51) 17,884 Finance income 13,450 7,849 985 (19,334) 2,950 Finance costs (28,318) (18,526) (9,059) (41,477) (97,380) Unrealised loss on derivatives (21,477) - - - (21,477) Net foreign exchange gain/(loss) 31,000 520 479 (38,921) (6,922) Profit/(loss) before income tax (45,600) (15,942) 81,721 (110,921) (90,742) Taxation income / (expense) 29,026 5,017 (39,100) (355) (5,412) Profit/(loss) from continuing operations (16,574) (10,925) 42,621 (111,276) (96,154) Year ended 31 December 2020 Revenue from oil 17,987 - 1,580 - 19,567 Revenue from Gas 2,250 - 5,097 - 7,347 Petroleum products sales 326 - - - 326 Rendering of services 6,800 - 92 (6,118) 774 Total revenue 27,363 - 6,769 (6,118) 28,014 Adjusted EBITDAX (4,874) (3,574) 4,143 (4,030) (8,335) Reconciliation to profit before tax: Depreciation and amortisation expenses (21,399) (294) (1,989) (443) (24,125) Share-based payment charge (471) (42) - (2,712) (3,225) Exploration and evaluation expenses (2,942) (502) - (980) (4,424) Impairment loss on property, plant and equipment (65,299) - - - (65,299) Other expense (1,137) (2,700) - (24,492) (28,329) Other income 4,154 - 689 4,343 9,186 Finance income 224 201 64 4 493 Finance costs (3,619) (326) 175 (1,216) (4,986) Net foreign exchange gain/(loss) 10,769 1,862 (967) 3,781 15,445 Profit before income tax (84,594) (5,375) 2,115 (25,745) (113,599) Taxation income / (expense) 21,009 495 (1,081) 318 20,741 Profit from continuing operations (63,585) (4,880) 1,034 (25,427) (92,858) The following table presents assets and liabilities information for the Group's operating segments as at 31 December 2021 and 31 December 2020, respectively: Europe Israel Egypt Other & inter-segment transactions Total $'000 $'000 $'000 $'000 $'000 Year ended 31 December 2021 Oil & Gas properties 537,600 2,584,828 342,528 (9,694) 3,455,262 Other fixed assets 16,578 3,917 24,076 (360) 44,211 Intangible assets 74,868 95,941 20,484 36,848 228,141 Trade and other receivables 164,131 22,769 102,605 (979) 288,526 Deferred tax asset 154,798 - - - 154,798 Other assets 674,157 379,248 98,720 (81,711) 1,070,414 Total assets 1,622,132 3,086,703 588,413 (55,896) 5,241,352 Trade and other payables 202,797 74,115 25,511 152,563 454,986 Borrowings - 2,463,524 - 483,602 2,947,126 Decommissioning provision 766,573 35,525 - 802,098 Other current liabilities (20,395) - - 32,941 12,546 Other non-current liabilities 134,203 180,689 24,663 (32,082) 307,473 Total liabilities 1,083,178 2,753,853 50,174 637,024 4,524,229 Other segment information Capital Expenditure: - Property, plant and equipment 72,782 247,463 52,085 (14,330) 358,000 - Intangible, exploration and evaluation assets 40,523 6,342 215 3,329 50,409 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 - 22,856 - 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 & inter-segment transactions Total $'000 $'000 $'000 $'000 $'000 Year ended 31 December 2021 Net cash from / (used in) operating activities 43,394 (28,764) 128,659 (10,785) 132,504 Net cash (used in) investing activities (99,040) (490,381) (53,553) 191 (642,783) Net cash from financing activities 120,446 831,677 (132,414) 240,056 1,059,765 Net increase/(decrease) in cash and cash equivalents 64,800 312,532 (57,308) 229,462 549,486 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 (7,093) (125) 322 (14,690) (21,586) Cash and cash equivalents at end of the period 71,316 349,828 19,254 290,441 730,839 Year ended 31 December 2020 (Restated) Net cash from / (used in) operating activities (5,442) (2,469) 22,808 (13,428) 1,469 Net cash (used in) investing activities (18,626) (370,007) (925) (208,005) (597,563) Net cash from financing activities 19,164 297,987 (174) 119,069 436,046 Net increase/(decrease) in cash and cash equivalents (4,904) (74,489) 21,709 (102,364) (160,048) At beginning of the year 6,084 110,488 - 237,847 354,419 Cash acquired from business Acquisition 7,234 - 55,650 (62,884) - Effect of exchange rate fluctuations on cash held 5,195 1,422 (1,119) 3,070 8,568 Cash and cash equivalents at end of the period 13,609 37,421 76,240 75,669 202,939 4. Revenue 2021 2020 $'000 $'000 Revenue from crude oil sales 165,924 17,987 Revenue from gas sales 270,969 7,347 Revenue from LPG sales 20,945 538 Revenue from condensate sales 34,126 1,042 Gain/(Loss) on forward transactions (285) - Petroleum products sales 4,618 326 Rendering of services 688 774 Total revenue 496,985 28,014 100% of the gas produced at Abu Qir (Egypt) is sold to EGPC under a Brent-linked gas price. At Brent prices of between US$40/bbl and US$72/bbl the gas price is US$3.5/mmBTU, limiting volatility and exposure to commodity price fluctuations. For Brent prices above US$72/bbl the gas price increases until it reaches a cap of US$5.88/mmBTU at Brent prices in excess of US$100/bbl. For Brent prices below US$40/bbl the gas price decreases until it reaches a gas price floor of US$1.29/mmBTU at a Brent price of US$0/bbl. 2021 2020 Sales for the year ended 31 December Kboe Kboe Greece Oil 403 639 Egypt (net entitlement) Gas 6,351 425 LPG 394 32 Condensate 553 64 Italy Oil 2,083 62 Gas 1,474 65 UK Gas 40 5 Oil 271 17 Croatia Gas 57 3 Total 11,626 1,312 5. Operating profit/(loss) 2021 2020 $'000 $'000 (a) Cost of sales Staff costs 64,564 14,562 Energy cost 11,578 5,310 Flux Cost 11,561 - Royalty payable 24,759 430 Other operating costs[31] 149,133 8,227 Depreciation and amortisation 94,647 22,052 Stock overlift/underlift movement (11,130) (2,165) Total cost of sales 345,112 48,416 (b) Administration expenses Staff costs (note 9) 16,759 5,745 Other General & Administration expenses 15,444 4,584 Share-based payment charge included in administrative expenses 5,714 2,776 Depreciation and amortization 2,480 780 Auditor fees 2,273 1,251 42,670 15,136 (c) Selling and distribution expense Staff costs 80 29 Other selling and distribution expenses 223 118 303 147 (d) Exploration and evaluation expenses Staff costs for Exploration and evaluation activities 3,695 1,175 Exploration costs written off (Note 9) 82,122 2,936 Other exploration and evaluation expenses 1,861 313 87,678 4,424 (e) Other expenses Transaction costs in relation to Edison E&P acquisition[32] 2,052 17,914 Intra-group merger costs 605 2,188 Loss from disposal of Property plant & Equipment 36 7,568 Other indemnities - 210 Write-down of inventory 581 101 Provision for litigation and claims 520 - Write down of property, plant and equipment costs 779 - Other expenses 2,446 348 7,019 28,329 (f) Other income Income from accounts payable written off[33] - 4,094 Reversal of expected credit loss allowance 1,853 2 Change in estimates of decommissioning provisions[34] 7,836 - Change in estimate of defined benefit obligation 3,463 - Reversal of provision for litigation and claims 4,494 - Proceeds from termination of agreement with Neptune Energy[35] - 5,000 Other income 238 (94) 17,884 9,002 6. Net finance cost 2021 2020 Notes $'000 $'000 Interest on bank borrowings 15 96,678 90,008 Interest on Senior Secure Notes 15 106,993 - Interest expense on long term payables 17 4,101 6,716 Interest expense on short term liabilities 55 - Less amounts included in the cost of qualifying assets 8, 9 (174,153) (93,581) 33,674 3,143 Finance and arrangement fees 12,420 4,042 Commission charges for bank guarantees 2,404 - Unamortised financing costs related to Greek RBL and Egypt RBL[36] 18,108 - Other finance costs and bank charges 2,972 744 Loss on interest rate hedges 7,002 - Unwinding of discount on right of use asset 1,316 919 Unwinding of discount on provision for decommissioning 8,722 247 Unwinding of discount on deferred consideration 12,854 - Unwinding of discount on convertible loan 3,159 - Mark-to-market on contingent consideration 1,626 - Less amounts included in the cost of qualifying assets (6,877) (4,109) Total finance costs 97,380 4,986 Interest income from time deposits (2,950) (493) Total finance income (2,950) (493) Foreign exchange (gain)/losses 6,922 (15,445) Net financing (income)/costs 101,352 (10,952) 7. Taxation (a) Taxation charge 2021 2020 $'000 $'000 Corporation tax - current year (44,922) (1,171) Corporation tax - prior years 353 404 Deferred tax (Note 10) 39,157 21,508 Total taxation (expense)/income (5,412) 20,741 (b) Reconciliation of the total tax charge The Group calculates its income tax expense by applying a weighted average tax rate calculated based on the statutory tax rates of each country 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 6% (31 December 2020: 18%). The tax (charge)/credit of the period can be reconciled to the loss per the consolidated income statement as follows: 2021 2020 $'000 $'000 Loss before tax (90,742) (113,599) Tax calculated at 32.8% weighted average rate (2020: 24.9%)[37] 29,721 28,232 Impact of different tax rates (5,176) 326 Utilisation of unrecognised deferred tax/(Non recognition of deferred tax) 2,953 (2,544) Permanent differences[38] (34,470) (5,251) Foreign taxes (244) (1,081) Tax effect of non-taxable income & allowances 1,348 649 Other adjustments 103 6 Prior year tax 353 404 Taxation (expense)/income (5,412) 20,741 8 Property, plant & equipment Oil and gas assets Leased assets Other property, plant and equipment Total Property, Plant & 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 Capitalised 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 345,180 6,428 1,623 353,231 Lease modification - 2,261 - 2,261 Disposal of assets (23) - (34) (57) Capitalized borrowing cost 178,891 - - 178,891 Capitalised depreciation 227 - - 227 Change in decommissioning provision (13,174) - - (13,174) Transfer from Intangible assets 14,317 - 26 14,343 Foreign exchange impact (57,960) (2,285) (2,806) (63,051) At 31 December 2021 3,897,787 57,245 59,046 4,014,078 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 Expensed 81,234 12,274 1,998 95,506 Impairment 774 - - 774 Disposal of assets - - 21 21 Foreign exchange impact (16,129) (151) 449 (15,831) At 31 December 2021 442,522 19,102 52,981 514,605 Net carrying amount At 31 December 2020 3,053,686 43,862 9,724 3,107,272 At 31 December 2021 3,455,265 38,143 6,065 3,499,473 Included in the carrying amount of leased assets at 31 December 2021 is right of use assets related to Oil and gas properties and Other property, plant and equipment of $25.1 million and $2.9 million respectively. The depreciation charged on these classes for the year ending 31 December 2021 was $11.7 million and $0.6 million respectively ** Included within the carrying amount of Oil & Gas assets are development costs of the Karish field related to the Sub Sea and On-shore construction. In line with the agreement with Israel Natural Gas Lines ("INGL"), shortly after delivery of first gas there will be a transfer of title ("hand over") of these assets to INGL. For further details refer to note 27. Borrowing costs capitalised for qualifying assets during the year are calculated by applying a weighted average interest rate of 5.49% for the year ended 31 December 2021 (for the year ended 31 December 2020: 8.72%). The additions to Oil & Gas properties for the year ended 31 December 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 $247 million, development cost for Cassiopea project in Italy at the amount of $38 million and NEA/NI project in Egypt at the amount of $52 million. Management assessed the CGUs in Egypt, Italy, Israel and the UK for indicators of impairment and none were identified. In Greece management has performed a value in use (VIU) assessment of the Prinos cash generating unit (CGU) following identification of triggers for impairment reversal. Management's assessment noted that Epsilon is currently in the development phase, and although robust technical analysis supports production at the 2P level, given that the production of the first 3 wells has not commenced, there is still significant uncertainty that the relevant production levels will be achieved; EU Emissions Trading System (ETS) prices are set to increase, resulting in higher operational costs in Greece and possible additional taxes for exceeding GHG emissions. These factors together with sensitivity analysis performed resulted in management concluding that no impairment reversal was required. Management will reassess the position once the Epsilon field starts producing. 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 resulted in an impairment of $65.3 million in the carrying value of the Prinos CGU. 9. 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 31 December 2020 158,213 101,146 22,355 281,714 Additions 47,995 - 2,413 50,408 Capitalized borrowing costs 2,202 - - 2,202 Change in decommissioning provision 2,141 2,141 Transfers to property, plant and equipment (265) - (14,078) (14,343) Exchange differences (4,953) - (983) (5,936) At 31 December 2021 205,333 101,146 9,707 316,186 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) 31 December 2020 3,004 - 2,894 5,898 Charge for the period - 1,946 1,946 Impairment 82,125 - - 82,125 Exchange differences (1,850) - (74) (1,924) 31 December 2021 83,279 - 4,766 88,045 Net carrying amount At 31 December 2020 155,209 101,146 19,461 275,816 At 31 December 2021 122,054 101,146 4,941 228,141 Borrowing costs capitalised for qualifying assets for the year ended 31 December 2021 amounted to $2.1 million (31 December 2020: $2.8million). The interest rates used was 5.49% for the year ended 31 December 2021 (31 December 2020: 8.72%). Goodwill arises principally because of the requirement to recognise deferred tax assets and liabilities for the difference between the assigned values and the tax bases of assets acquired and liabilities assumed in a business combination. In 2021 two appraisal wells were drilled targeting Glengorm South and Glengorm Central. Both wells were unsuccessful and did not find hydrocarbons. All wells have been plugged and abandoned. Therefore the related costs of the unsuccessful wells and the associated fair value uplift recognised as part of the Edison E&P acquisition were impaired ($79.8million). 10. 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 tax Retirement benefit liability Accrued expenses and other short���term liabilities Total $'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 10,080 60,752 70,832 Increase / (decrease) for the period through: profit or loss (Note 7) 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 9,848 (718) 50,808 890 (254) (32,501) 5,020 (932) 6,996 39,157 other comprehensive income 1,586 1,586 Reclassifications in the current period[39] (28,442) - 33,644 2,025 (233) (4,903) 6, 010 200 (8,301) - Exchange difference 1,584 20 (3,889) 165 (25) (8,257) (52) (363) (10,817) 31 December 2021 (140,553) (990) 89,440 (1,571) 183 120,180 11,030 266 9,388 87,373 2021 2020 $'000 $'000 Deferred tax liabilities (67,425) (68,609) Deferred tax assets 154,798 126,056 87,373 57,447 At 31 December 2021 the Group had gross unused tax losses of $1,123.8 million (as of 31 December 2020: $783.6 million) available to offset against future profits and other temporary differences. A deferred tax asset of $120.2 million (2020: $165.8 million) has been recognised on tax losses of $449.0 million, based on the forecasted profit models as updated with the 31 December 2021 proved and probable reserve profiles. The Group did not recognise deferred tax on tax losses and other differences of total amount of $1,090.4 million. In Greece, Italy and the UK, the net deferred tax asset for carried forward losses recognised in excess of the other net taxable temporary differences was $59.3 million, $0.19 million and $13.8 million (2020: $58.7 million, $20.6 million and $4.2 million) respectively. An additional deferred tax asset of $81.4 million (2020: $42.6 million) arose primarily in respect of deductible temporary differences related to property, plant and equipment, decommissioning provisions and accrued expenses, resulting in a total deferred tax asset of $154.9 million (2020: $126.1 million). Greek tax losses (Prinos area) can be carried forward without limitation up until the relevant concession agreement expires (by 2039), whereas, the tax losses in Israel, Italy and the United Kingdom can be carried forward indefinitely. Based on the Prinos area forecasts (including the Epsilon development), the deferred tax asset is fully utilised by 2029. In Italy, deferred tax asset of $67.9 million recognised on decommissioning costs scheduled up to 2030 when the Italian assets expect to enter into a declining phase. Finally, in the UK, decommissioning losses is expected to be tax relieved up until 2027, whereas, deferred tax asset recognised on UK tax losses is fully offset against deferred tax liabilities on temporary differences. On 3 March 2021 it was announced in the UK budget that the UK non-ring fence corporation tax rate will increase from 19% to 25% with effect from 2023. The Group does not currently recognise any deferred tax assets in respect of UK non-ring fence tax losses and therefore this rate change did not impact the tax disclosures. 11. Cash and cash equivalents 2021 2020 $'000 $'000 Cash at bank 729,390 197,514 Deposits in escrow 1,449 5,425 730,839 202,939 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 0.386% for the year ended 31 December 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. 12. Restricted Cash Restricted cash comprises mainly cash retained under the Israel Senior Secured Notes requirement as follows: a) Short term - US$96.76 million Interest Payment Account for the accrued interest period until 31 December 2022 (less coupons actually paid) and from 31 December 2022 the Interest Reserve Account will be funded 6 months forward b) 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 million 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. 13. Trade and other receivables 2021 2020 $'000 $'000 Trade and other receivables-Current Financial items: Trade receivables[40] 178,804 226,118 Receivables from partners under JOA 5,138 Other receivables[41] 38,683 Government subsidies[42] 3,212 3,481 Refundable VAT 42,376 49,414 Receivables from related parties 1 22 268,214 279,035 Non-financial items: Deposits and prepayments[43] 17,139 38,756 Deferred insurance expenses 2,095 507 Accrued interest income 1,078 41 20,312 39,304 288,526 318,339 Trade and other receivables-Non Current Financial items: Other tax recoverable 16,478 16,686 16,478 16,686 Non-financial items: Deposits and prepayments 12,337 13,409 Other deferred expenses[44] 22,958 - Other non-current assets 866 1,473 36,161 14,882 52,639 31,568 The table below summarizes the maturity profile of the Group receivables: 14. Non���controlling interests Name of subsidiary Voting rights Share of loss Accumulated balance Year ended 31 December Year ended 31 December Year ended 31 December Year ended 31 December Year ended 31 December 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 Material partly-owned subsidiaries Energean Israel Limited 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 as at that date. 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 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 added 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. 15. Borrowings 2021 2020 $'000 $'000 Non-current Bank borrowings - after two years but within five years 4.5% Senior Secured notes due 2024 ($625 million) 617,060 - 4.875% Senior Secured notes due 2026 ($625 million) 615,966 - Senior Credit facility ($237 million) - 227,848 EBRD Senior Facility Loan ($180 million) - 84,420 EBRD Subordinated Facility Loan ($20 million) - 17,824 Convertible loan notes ($50 million) 41,495 - Bank borrowings - more than five years 6.5% Senior Secured notes due 2027 ($450 million) 442,107 - 5.375% Senior Secured notes due 2028 ($625 million) 615,451 - 5.875% Senior Secured notes due 2031 ($625 million) 615,047 - Carrying value of non-current borrowings 2,947,126 330,092 Current 6.83% EBRD Senior Facility Loan due 2024 ($97,6 million) - 19,020 Senior Credit Facility for the Karish-Tanin Development ($1,450 million) - 1,093,964 Carrying value of current borrowings - 1,112,984 Carrying value of total borrowings 2,947,126 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: 1. Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2024, with a fixed annual interest rate of 4.500%. 2. Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2026, with a fixed annual interest rate of 4.875%. 3. Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2028, with a fixed annual interest rate of 5.375%. 4. 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 is payable 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 undertaken to provide the following collateral in favour of the Trustee: 1. 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. 2. Floating charge over all of the present and future assets of Energean Israel Limited and Energean Israel Finance Ltd. 3. 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. US$450,000,000 senior secured notes: On 18th November 2021, the Group completed the issuance of $450 million of senior secured notes, maturing on 30 April 2027 and carrying a fixed annual interest rate of 6.5%. The interest on the notes is paid semi-annually on 30 April and 30 October of each year, beginning on 30 April 2022. The notes are listed for trading on the Official List of the International Stock Exchange ("TISE"). The use of proceeds from the Offering is as follows: �� to repay all amounts outstanding under, and cancel all commitments made available pursuant to certain of its existing debt facilities, being the Egypt reserve based lending facility and the Greek reserve based lending facility plus subordinated debt; �� to pay fees and other expenses related to the Offering; and �� for general corporate purposes of the Group The issuer is Energean plc and the Guarantors are Energean E&P Holdings, Energean Capital Ltd, Energean Egypt Ltd, and Energean Egypt Services JSC. The company undertook to provide the following collateral in favour of the Security Trustee: 1. Share pledge of Energean Capital Ltd, Energean Egypt Ltd, Energean Italy Ltd and Energean Egypt Services JSC 2. Fixed charges over the material bank accounts of the Company and the Guarantors (other than Energean Egypt Services JSC) 3. Floating charge over the assets of Energean PLC (other than the shares of Energean E&P Holdings) EBRD Senior Facility, EBRD Subordinated Facility, New Egypt RBL Facility: On 18 November 2021, following the release of the senior secured notes proceeds of $450 million, the Company repaid its existing debt facilities, being the New Egypt reserve based lending facility and the Greek reserve based lending facility plus subordinated debt. Energean Oil and Gas SA ('EOGSA') loan for Epsilon/Prinos Development: On 27 December 2021 EOGSA entered into a loan agreement with Black Sea Trade and Development Bank for ���90.5million to fund the development of Epsilon Oil Field. The loan is subject to an interest rate of 3,45 % plus EURIBOR, in addition to fees and commission and has final maturity date 7 years and 11 months after the First Disbursement Date. On 27 December 2021 EOGSA entered into an agreement with Greek State to issue ���9.5million of notes maturing in 8 years with fix rate 0,31% plus margin as the following table: Year Margin 1 3.0% 2 3.5% 3 3.5% 4 4.5% 5 4.5% 6 4.5% 7 5.5% 8 6.5% 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. Energean is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, the Group may put in place new debt facilities, issue new shares for cash, repay debt, engage in active portfolio management, adjust the dividend payment to shareholders, or undertake other such restructuring activities as appropriate. 2021 2020 $'000 $'000 Net Debt Current borrowings - 1,112,984 Non-current borrowings 2,947,126 330,092 Total borrowings 2,947,126 1,443,076 Less: Cash and cash equivalents (730,839) (202,939) Restricted cash (199,729) - Net Debt (1) 2,016,558 1,240,137 Total equity (2) 717,123 1,194,392 Gearing Ratio (1)/(2): 281.2% 103.8% 16. Provisions Decommissioning Provision for litigation and other claims Total $'000 $'000 $'000 At 1 January 2020 13,145 133 13,278 New provisions 38,125 - 38,125 Change in estimates 1,496 - 1,496 Refunds - (145) (145) Acquisition of subsidiary 808,994 16,375 825,369 Unwinding of discount 919 - 919 Currency translation adjustment 2,448 45 2,493 At 31 December 2020 865,127 16,408 881,535 Current provisions - - - Non-current provisions 865,127 16,408 881,535 At 1 January 2021 New provisions 520 520 Change in estimates (18,808) (4,494) (23,302) Recognised in property, plant and equipment (13,174) Recognised in Intangible assets 2,202 Recognised in profit& loss (7,836) Payments (2,653) - (2,653) Unwinding of discount 8,722 - 8,722 Currency translation adjustment (50,290) (1,140) (51,430) At 31 December 2021 802,098 11,294 813,392 Current provisions 12,366 - 12,366 Non-current provisions 789,732 11,294 801,026 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 and the impact of energy transition and the pace at which it progresses 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 31 December 2021. Inflation assumption Discount rate Assumption Cessation of production assumption 2021 $'000 2020 $'000 Greece 1.2%- 1.6% 0.89% 2034 17,058 16,082 Italy 1.07%- 1.37% 1.23% 2022-2040 527,801 551,464 UK 2.5% 1.49% 2023-2031 203,246 239,708 Israel 2.2% 1.95% 2041 35,525 38,399 Croatia 1.8% 1.25% 2022 18,467 19,474 Total 802,097 865,127 17. Trade and other payables 2021 2020 $'000 $'000 Trade and other payables-Current Financial items: Trade accounts payable 109,525 193,987 Payables to partners under JOA [45] 43,499 64,752 Deferred licence payments due within one year - 14,344 Deferred consideration for acquisition of minority 167,228 - Other creditors 12,043 12,502 Short term lease liability 8,253 10,561 340,548 296,146 Non-financial items: Accrued expenses[46] 64,823 49,812 Other finance costs accrued (note 6) 36,693 2,630 Social insurance and other taxes 7,643 5,695 Income taxes 5,279 1,171 114,438 59,308 454,986 355,454 Trade and other payables-Non Current Financial items: Deferred licence payments[47] 57,230 55,174 Contingent consideration (note 18) 78,450 55,222 Long term lease liability 36,172 37,062 Other payables 171,852 147,458 Non-financial items: Contract Liability[48] 53,537 29,105 Social insurance 598 630 54,135 29,735 225,987 177,193 Trade and other payables are non-interest bearing except for finance leases and deferred licence payments. 18. Contingent consideration 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 fair value of the Contingent Consideration is estimated by reference to the terms of the SPA and the simulated PSV pricing by reference to the forecasted PSV pricing, historical volatility and a log normal distribution, discounted at a cost of debt. Noting the natural gas future prices for PSV are currently in excess of the ���20/MWh (the threshold for payment of ���100m), we estimate the fair value of the Contingent Consideration as at 31 December 2021 to be c. $78.5m based on a Monte Carlo simulation. Contingent consideration 2021 1 January 55,174 Unwinding of discount 1,799 Mark to Market 21,477 31 December 78,450 [1] When considering 2021 data versus 2020 pro forma (includes Edison) performance data on an equity share basis [2] Pro forma production and financial results are presented as if Edison E&P results were consolidated for the entire year; the locked box date of the transaction was 31 December 2018 and therefore all economic results since that date accrue to Energean. Actual results consolidate from the closing date of the transaction, which occurred on 17 December 2020. [3] Guidance given in January 2021 [4] Includes (i) at least $140 million of payments to Technip under the EPCIC which will be deferred (ii) $120 million of underspend carried over from 2021 and (iii) $120 million of Karish North, Second Oil Train and Riser growth expenditure [5] Includes flux costs [6] Includes exploration capital expenditures [7] Less deferred amortised fees [8] Based on 2021 YE CPRs prepared by D&M and NSAI (Greece) [9] Versus the Energean 2020 year-end position (before pro forma adjustment for Kerogen acquisition) [10] Including the Kerogen minority interest position, the acquisition of which closed on 25 February 2021 [11] Decrease in Greece due to transfer of Katakalo from 2P to 2C [12] Guidance given in January 2021 [13] As measured by project milestones under the TechnipFMC EPCIC [14] Based on YE 2021 CPR from D&M [15] Including Dalia [16] YE21 NSAI CPR [17] Forecast net debt is presented on a gross basis. i.e. without amortisation of fees [18] Based on 1.0 - 1.3 bcm of gas sales [19] Includes (i) at least $140 million of payments to Technip under the EPCIC which will be deferred (ii) $120million of underspend carried over from 2021 and (iii) $120 million of Karish North, Second Oil Train and Riser growth expenditure [20] Excludes optional wells, includes $10 million underspend from 2021 [21] 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. [22] Other reserves are used to recognise remeasurement gain or loss on cash flow hedges and actuarial gain or loss from the defined benefit pension plan [23] Refer to note 15 [24] 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. [25] 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. [26] 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 14 [27] 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 is accounted as variable purchase consideration under IFRS 15 hence recognised once production commences and gas is delivered to the offtakers [28] 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. [29] Comparative amounts have been restated to reclassify the amounts received from INGL from financing activities to investing activities. Refer to Note 1 [30] 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. [31] Other operating costs comprise of insurance costs, gas transportation and treatment fees concession fees and planned maintenance costs [32] Direct costs incurred in 2020 and 2021 relating to the acquisition of Edison's E&P business [33] Related to derecognition of specific accounts payables balances in the Greek subsidiary following waiver agreements with creditors. [34] There was a change in the assumptions underpinning the decommissioning provision that resulted in an overall decrease to the provisions recognised [35] Related to termination fees paid by Neptune Energy following the termination of the agreement for Neptune Energy to acquire Edison E&P's UK and Norwegian subsidiaries from the Group. [36] On 18 November 2021 the Group fully repaid the Prinos Project Finance (Greek RBLs) before the maturity date of 31 December 2024 and, as such, the unamortised financing costs have been expensed in the period. [37] For the reconciliation of the tax rate, the weighted average rate of the statutory tax rates in Greece (25%), Israel (23%), Italy (24%), Cyprus (12.5%), United Kingdom (40%) and Egypt (40.55%) was used weighted according to the profit or loss before tax earned by the Group in each jurisdiction, excluding fair value uplifts profits. [38] Permanent differences mainly consisted of non-deductible expenses, consolidation differences, intercompany dividends and foreign exchange differences [39] 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. [40] Included within this balance is an amount of $21.2million receivable from INGL as a result of the relevant milestones being achieved, in line with the agreement. Refer to note 17 for further details on the agreement with INGL [41] Included in other receivables is $29.4million cash on account in relation to the hedges in Italy [42] 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. [43] 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 [44] In accordance with the GSPAs signed with a group of gas buyers, the Company 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, amounting to $23million) has been fully paid as of the reporting date. The compensation presented as a non-current asset (under the caption deferred expenses) and will be accounted for as variable consideration in line with IFRS 15 once production commences and gas is delivered to the offtakers. [45] Payables related to operated Joint operations primarily in Italy [46] Included in trade payables and accrued expenses in FY21 and FY20, are mainly Karish field related development expenditures (mainly FPSO and Sub Sea construction cost), development expenditure for Cassiopea project in Italy and NEA/NI project in Egypt. [47] 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 31 December 2021 the total discounted deferred consideration was $57.23 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, the deferred payment due in March 2022 would be postponed by the number of days that such Force Majeure event last. As of 31 December 2021 Force Majeure event length has not been finalised as the COVID-19 pandemic continues to affect the progress of the project, and as such the deferred payment due in March 2022 will be postponed accordingly. [48] In June 2019, Energean signed a Detailed Agreement with Israel Natural Gas Lines ("INGL") for the transfer of title (the "hand over") of the nearshore 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), c$115 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 at least 90 days after the delivery of first gas from the Karish field which expected in 3Q 2022. 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 rns@lseg.com 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 FR FIFVVVAISFIF