Half-year Report

Source Press Release
Company Energean plcEdison SpAEGPCNeptune Energy GroupTechnipFMC plc 
Tags Hydrogen, Carbon Capture (CCS/CCUS), Power, Service Contracts, Hedging, Decommissioning, Production/Development, Upstream Activities, Strategy - Upstream, Capital Spending, Environment, ESG/CSR, Guidance, Financial & Operating Data, Strategy - Corporate
Date September 02, 2021

Mathios Rigas, Chief Executive of Energean, commented:

"During 1H 2021, Energean delivered excellent operational and financial progress, reflecting the transformational nature of the acquisition of Edison E&P. Production is outperforming guidance, translating into record financial performance and, through successful execution of our gas- and returns-focused strategy, we have achieved a significant milestone in our transformation into a 200 kboed, $2 billion annual revenue generating, sustainable dividend yielding, energy company. In addition, we further strengthened and de-risked our balance sheet by raising the largest ever EMEA energy international high yield bond and remain fully-funded for all projects across our nine countries of operation."

Despite continued COVID-19 related challenges, we have delivered solid progress on our flagship Karish gas development project, which remains firmly on track to deliver first gas in mid-2022. There are a number of potential acceleration measures under active consideration and, at 31 August 2021, the workforce on the Karish project was in excess of 1,700, an approximate 70% month-on-month increase. Further growth in Israel will be delivered through our (up to) five-well offshore growth programme, with the Stena IceMax drilling rig commencing operations in 1Q-2022. The programme targets an additional 1 billion boe, which has the potential to double our reserve base with high quality resource volumes that can be quickly, economically, and safely monetised. Globally, gas prices are strong and we are assessing several commercial opportunities to access international markets, as well as the growing Israeli domestic market, if (and when) additional gas resources become available to us.

"In the second half of the year, we look forward to continuing to deliver our key gas development projects in Egypt and Italy, which alongside commencement of the revised Epsilon project in Greece, will provide further, substantial near-term growth and value realisation in the Mediterranean region."

The recently published Intergovernmental Panel on Climate Change[1] report on the impacts of global warming made for stark reading and emphasized the need for immediate action. As a business, we have taken full responsibility for our own emissions profile, showcased by publication of our first Climate Change Policy, which outlines the short, medium, and long-term actions we will take as part of our commitment to become a net zero emitter by 2050. In the first half of 2021, we reduced the carbon intensity of our operations by more than 19% versus 2020 levels[2]; representing a 73% reduction versus our base year of 2019. This is a trajectory we are committed to continuing, and we are investigating all options to accelerate our net zero commitment ahead of 2050, in recognition of the need for urgent and immediate action."   

Highlights - Operational

·      1H 2021 average working interest production was 44.0 kboed (72% gas), ahead of full year guidance of 38 - 42 kboed (71% gas)

o  Production outperformed guidance across all countries of operation

o  Demonstrates Energean's ability to maximise value from the ex-Edison E&P assets and to successfully integrate Edison E&P within six-months of transaction close

·      On track to deliver first gas from Karish in mid-2022

o  On 31 July 2021, the project was 91.5% complete[3]

o  Core focus on optimising and accelerating the timetable with options being actively considered (and not reflected in the current timetable)

§ On 31 August 2021, the workforce on the Energean Power FPSO stood at more than 1,700 workers, up approximately 70% month-on-month

·      Rig contract signed with Stena Drilling Limited ("Stena") for 2022-23 growth drilling programme, offshore Israel

o  Targeting the de-risking of prospective recoverable resources of over 1 billion[4] barrels of oil equivalent ("boe")

·      Awarded an Engineering, Procurement, Construction and Installation ("EPCI") contract to TechnipFMC to develop the North East Almeyra ("NEA")/North Idku ("NI") project, shallow-water offshore Egypt, in February 2021

o  Project remains on track to deliver first gas in 2H 2022

o  Project expected to deliver IRRs in excess of 30%

·      Cassiopea gas development project, Italy, 23% complete at 31 July 2021 and on track to deliver first gas in 1H 2024

·      Final Investment Decision ("FID") taken on the revised 53 MMbbls 2P + 2C Epsilon satellite tieback project, offshore Greece

o  First oil expected in 1H 2023 (subject to financing)

o  Financing package expected to be finalised in 3Q 2021

Highlights - Corporate and ESG

·    Issued $2.5 billion of senior secured notes in March 2021 at an average coupon rate of approximately 5.2%

o  Significantly reducing financing risk on the Karish project, as the project finance facility had been due to mature in 2022

o  Extending average life of debt for Energean plc from approximately 2.5 years at 30 June 2020 to approximately 6 years at 31 July 2021

·    Completed the highly accretive acquisition of the 30% minority interest in Energean Israel Limited ("EISL") in February 2021

o  Acquisition transacted at a 49% discount to CPR-derived NPV10

o  Increased 2P reserves across the portfolio to nearly 1 billion boe (79% gas)

·    1H 2021 Scope 1 and 2 carbon emissions of approximately 18 kg/boe, a significant step towards Energean's target of achieving net zero emissions ahead of 2050, representing a:

o  19% reduction versus 2020 levels[5];

o  73% reduction versus 2019; and

o  On track to beat previous 2021 guidance of 21 kg/boe by approximately 15%

Highlights - Financial

·    Substantial year-on-year improvement in financial results, demonstrating the magnitude and significance of the acquisition of Edison E&P

o  Revenues increased to $206 million (1H 2020: $2 million), primarily due to the transformational nature of the acquisition of Edison E&P

o  Unit cost of production reduced by 44% to $15.4/boe (1H 2020: $27.5/boe)

o  Positive EBITDAX6 of $75 million (1H 2020: negative $8.9 million)

o  Positive operating cash flows of $53.1 million (1H 2020: $14.5 million outflow)

·    Cash, cash equivalents and restricted cash  of $1.1 billion at 30 June 2021 (restricted amounts represent $266 million)

o  Providing significant financial flexibility

o  Ensures all planned activities are fully-funded

  1H 2021 $m  1H 2020 $m  Increase / (Decrease) % 
Average working interest production (kboed)  44.0  2.1  1,995% 
Sales and other revenue  205.5  2.1  9,686% 
Cash cost of production[6]  122.4[7]  10.4  1,077% 
Cash cost of production per boe  15.4  27.5  (44%) 
Cash S,G&A6  17.0  5.4  215% 
Adjusted EBITDAX[8]  74.7  (8.9)  939% 
Operating cash flow[9]  53.1  (14.5)  466% 
Development capital expenditure  200.8  243.9  (18%) 
Exploration capital expenditure  29.2  5.3  451% 
Decommissioning expenditure  1.7 
Net debt (including restricted cash)  1,692.6  861.4  96% 

Outlook

·    2021 production guidance re-iterated at 38 - 42 kboed

·    2021 development and production capital expenditure guidance re-iterated as $470 - 550 million and exploration capital expenditure guidance re-iterated as $55 - 70 million

·    2021 emissions intensity guidance reduced by approximately 15% to 18 kg CO2/boe (from 21 kgCO2/boe)

·    Sailaway of the Energean Power FPSO from Singapore to Israel in 1Q 2022 with first gas from Karish expected mid-2022

o  Acceleration measures being considered for implementation

·    Commencement of the high-impact growth drilling campaign in 1Q 2022, starting with Athena

o  First drilling results anticipated during 2Q 2022, marking a catalyst-rich start to 2022

·    Continued progress on key gas development projects in Egypt (NEA / NI) and Italy (Cassiopea)

·    Finalisation of funding for the Epsilon project, Greece, and commencement of the development programme, expected 2H 2021

·    Acceleration of the Green Prinos suite of projects

o  Pre-Front-End Engineering Design ("pre-FEED") on the carbon capture and storage ("CCS") project expected to commence in 2H 2021

·    Future dividend policy to be declared in due course

Conference call

A conference call for analysts and investors will be held at 08:30am BST today. Please register your participation in this morning's conference call at the following link. You will be given the option to either participate via webcast or dial in.

Webcast: https://edge.media-server.com/mmc/p/htkhfoq4
Dial-In: +44 (0) 2071 928338
Dial-in (Israel only): 35308845
Confirmation code: 5530326

The presentation slides will be made available on the website shortly .

Energean Operational Review

Production

1H 2021 average working interest production was 44.0 kboed (72% gas), ahead of full year guidance, which is maintained at 38 - 42 kboed. This represents a substantial year-on-year increase, reflecting the transformational nature of the acquisition of Edison E&P and the successful, quick integration of the Edison E&P portfolio into Energean despite the operational challenges posed by COVID-19.

  1H 2021 actuals Kboed  FY 2021 guidance Kboed  1H 2020 Kboed 
Egypt  31.4  27 - 30 
Italy  10.2  9 - 10 
Greece and Croatia  1.8  1.5  2.1 
UK  0.6  0.5 
Total production  44.0  38 - 42  2.1 

Israel

Karish Project

Energean remains firmly on track to deliver first gas from the Karish gas development project in mid-2022. At 31 July 2021, the project was approximately 91.5% complete[10].  

The next tangible milestone on the development remains sailaway of the FPSO from Singapore to Israel, currently expected in 1Q 2022. The journey from Singapore to Israel is expected to take approximately 35 days, with hook-up and pre-first gas commissioning then expected to take approximately three months.

Energean is actively working with its contractors to identify and implement potential acceleration measures for the FPSO delivery schedule, which are not reflected in the current timetable. Following agreement of an incentivisation payment of $12 million by Energean to Sembcorp in August 2021, workforce numbers on the Energean Power FPSO have increased by approximately 70%, to more than 1,700 at 31 August 2021.

Energean will update the market on whether it expects any acceleration of the delivery timetable as and when it is appropriate to do so.

  % Completion at 31 July 2021[11] 
Production Wells  100.0 
FPSO  96.7 
Subsea  83.0 
Onshore  99.8 
Total  91.5 

Energean has signed 18 gas sales agreements ("Agreements") for the supply of 7.2 Bcm/yr of gas on plateau, representing almost 100% of total gas reserves volumes over the life of those Agreements. All Agreements include provisions for floor pricing and take-or-pay and / or exclusivity, providing a high level of certainty over revenues from the Karish, Karish North and Tanin projects over the next 16 years.

For one Agreement representing 0.2 Bcm/yr and commencing 2024, the buyer has been unable to meet its conditions subsequent under the Agreement and the parties have mutually agreed to terminate the Agreement. This termination is not related to the project schedule. Energean has identified a potential replacement buyer for these volumes and expects to reach an Agreement shortly; Energean's main current restriction to signing further Agreements is that it has sold substantially all of its independently audited gas reserves.

One Agreement, representing 0.8 Bcm/yr of gas supply, is at potential risk of termination; however, if it is terminated, Energean has identified multiple alternative routes to monetise those gas volumes, including both domestic and international markets, and is confident of profitably selling them. Other than that one Agreement, Energean believes that all of its Agreements are robust under the current first gas delivery timetable, notwithstanding the delays experienced due to COVID-19-related circumstances.

Growth Projects

In May 2021, Energean took FID on two high-return growth projects, offshore Israel:

·      $70 million second oil train that will enable increased production of approximately 5 million barrels of hydrocarbon liquids per year at minimal incremental operating costs; and

·      $40 million second gas sales riser, which will enable gas production at the full 8 Bcm/yr capacity of the FPSO

 Both projects are progressing on schedule and are expected onstream in summer 2023.

In June 2021, Energean signed a rig contract with Stena for the drilling of up to five wells that will target derisking of unrisked prospective resources of over 1 Bnboe[12]. The contract consists of three firm wells plus two optional wells, with the first well expected to spud in 1Q 2022. The firm wells are all expected to be drilled during 2022 and consist of:

·      The Athena exploration well, located on Block 12, is situated directly between the Karish and Tanin leases and is expected to be the first well in the programme;

o  Two factors support commercialisation of a Block 12 discovery. Firstly, Block 12 was a new licence award to EISL in 2018; produced volumes will therefore generate no royalty payments in respect of EISL's original acquisition of the block. Secondly, the more proximate location of the potential development to the expected position of the FPSO will reduce like-for-like development costs when compared with Tanin

·      The Karish North development well, a key part of the Karish North development; and

·      The Karish Main-04 appraisal well, which is expected to target further prospective volumes within the Karish Main Block, including the potential oil rim that was identified as part of the Karish Main-03 development well drilling.

Energean is in the process of identifying and working up commercialisation options in the event of discoveries being made as part of the 2022-23 growth drilling programme and monetisation options include both domestic and international markets.

Egypt

Working interest production from the Abu Qir area averaged 31.4 kboed (87% gas) during 1H 2021 with full year production guidance maintained at between 27 - 30 kboed.

The shallow-water NEA/NI satellite tie-back project is progressing in line with expectations, with first gas from one well anticipated in 2H 2022 and from the remaining three wells in 1Q 2023. The project was sanctioned in January 2021 and an EPCI contract for the four subsea wells and the associated tie-back to the Abu Qir platform and associated infrastructure was awarded to TechnipFMC in 1Q 2021.

Around the Abu Qir and NEA/NI assets, Energean is maturing several near-field and infrastructure-led opportunities, including the discovered NI-B field, as potential future drilling candidates. In addition, prospect maturation continues across the wider portfolio to unlock value from the substantial prospective resource volumes identified, including in deeper liquids-rich horizons.

At 30 June 2021, net receivables (after provision for bad and doubtful debts) in Egypt were $158.7 million (31 December 2020: $148.8 million), of which $94.0 million (31 December 2020: $78.7 million) was classified as overdue. Cash collection from EGPC during the period was $74.9 million.

Italy

Working interest production from Italy averaged 10.2 kboed (41% gas) during 1H 2021 with full year production expected to be between 9 - 10 kboed.

Production continues to outperform expectations following robust operational performance across the operated oil portfolio, including the Vega and Rospo Mare fields, in which Energean increased its working interest to 100% in January 2021 following the nil-cost acquisition from ENI.

The Cassiopea (Energean 40%) gas development project was approximately 23% complete at 31 July 2021, with works to date focused on permitting, contracting and procurement, alongside a cost optimisation programme. First gas from the project is expected in 1H 2024. Development of Cassiopea will commercialise 31 MMboe of 2P reserves (100% gas) and achieve peak production of approximately 10 kboed.

Greece

Working interest production from the Prinos field averaged 1.6 kboed (0% gas) during 1H 2021 with full year production expected to be 1.5 kboed.

Prinos Area Development and Funding

In March 2021, the European Commission approved Greek state support for a EUR100 million funding package for the Prinos area, with Greek parliamentary ratification in May 2021. The full funding package is expected to be in place in 3Q 2021 with commencement of investment in the Epsilon project expected shortly thereafter.

In parallel, Energean has been evaluating a project to reinject produced carbon dioxide from Prinos back into the reservoir to reduce Scope 1 emissions from the field. The project has been approved for financial support from the European Commission's European Structural and Investment Funds ("ESIF")."

Green Prinos"

Extending the life of the Prinos production area through the Epsilon development is key to Energean's longer-term ambition of leveraging its subsurface knowledge and expertise in developing CCS and eco-hydrogen projects, which are expected to be key contributors to Energean's net zero strategy.

The Prinos CCS project proposal is to provide long-term storage for carbon dioxide emissions captured from both local and more remote emitters.

In 1H 2021, Energean submitted its CCS proposal to the Greek government, with a view to inclusion within its recovery and resilience plan, projects within which will qualify to receive funding from the Recovery and Resilience fund over the period 2021-26. In June 2021, the European Commission granted approval for the inclusion of the Greek CCS project within the fund.

A pre-FEED study for the CCS project is expected to commence in 2H 2021.

Rest of Portfolio

United Kingdom

1H 2021 production in the UK North Sea was 0.6 kboed (8% gas), ahead of full year guidance of 0.5 kboed.

Drilling operations at the Glengorm South appraisal well were safely completed in April 2021. The well contained no commercial hydrocarbons and the well has been plugged and abandoned. The existing Glengorm North discovery and the Glengorm Central appraisal well are considered to be independent of the Glengorm South appraisal well; the Glengorm Central appraisal well spudded in May 2021.

Energean has received interest from third parties with respect to the potential sale of its UK assets portfolio and is considering its options.

Croatia

During 1H 2021, working interest production from the Izabela field averaged 0.2 kboed (100% gas).

Evaluation of the results from the Irena appraisal well are ongoing.

Energean Corporate Review

ESG

Net Zero

In 1H 2021, Energean published its first Climate Change Policy, which defines the Group's actions to deliver upon its commitment to become a net-zero emitter by 2050.

Energean also took further steps towards this commitment, and is investigating an acceleration of its 2050 net-zero target, reflecting both its commitment and the importance of the global achievement of the goal. Energean's Scope 1 and 2 carbon emissions intensity in 1H 2021 was estimated to be approximately 18 kg/boe, a 19% reduction versus 2020 emissions levels[13]; a 73% reduction versus the 2019 base measurement year; and approximately 15% below full-year 2021 guidance of approximately 21 kg/boe.

Actions taken to date in 2021 include:

·      Agreements put in place for the purchase of electricity from renewable sources at all operated sites in Italy. Energean sites in Italy, Israel, Greece and Croatia now operate under this policy, which has substantially reduced Energean's scope 2 emissions

·      Zero-routine flaring policy now fully effective across all operated sites

·    Significant progress on the "Green Prinos" suite of initiatives, as described in the Operating Review, above. Energean is assessing the potential to replicate these initiatives across its portfolio

ESG Reporting and Ratings

Energean's 2020 Annual Report and Accounts, published in April 2021, marked Energean's first period of reporting in accordance with the requirements of the Task Force on Climate Related Financial Disclosure ("TCFD").

In June 2021, MSCI updated its rating for energean to AA, up from A in the previous year.

In July 2021, Energean was rated at gold level by Israel's Maala Index for the second year running. The Maala Index is an ESG rating system and stock market index that rates the largest companies in Israel on an annual basis.

Financing

In 1H 2021, Energean issued $2.5 billion of senior secured notes, maturing in four tranches (2024, 2026, 2028 and 2031) and with an average coupon rate of 5.2% and increasing the average life of debt across Energean plc's portfolio to more than six years.

The funds raised were used to both ensure that Energean's projects in Israel are fully funded and also to refinance the Group's outstanding project finance facility and term loan; drawn amounts under these loans upon refinancing were $1,270 million and $175 million, respectively. The refinancings removed a perceived key risk on the Karish project consequent to the upcoming maturities of those facilities. $266 million of proceeds have been used to pre-fund certain reserve accounts, classified as restricted cash within this report, with remaining proceeds earmarked for capital expenditure on the Karish and Karish North projects, the 2022/2023 Israel exploration programme, to fund bond transaction costs, outstanding amounts due to Kerogen relating to the acquisition of the minority interest in EISL, and for general corporate purposes. 

2021 guidance

  FY 2021  
Consolidated net debt ($ million)  2,000 
   
Cost of Production (Operating Costs plus Royalties)   
-     Israel ($ million) 
-     Egypt ($ million)  55 - 60 
-     Italy ($ million)  95 - 105 
-       Greece ($ million)  20 - 25 
-       Croatia ($ million 
-       UK North Sea ($ million)  20 - 25 
Total Cost of Production ($ million)  195 - 220 
   
Cash SG&A ($ million)  35 - 40 
   
Development and production capital expenditure   
-       Israel ($ million)  350 - 400 
-       Egypt ($ million)  60 - 70 
-       Italy ($ million)  40 - 50 
-       Greece and Croatia ($ million)  5 - 10 
-       UK North Sea ($ million)  15 - 20 
Total Development & Production Capital Expenditure ($ million)  470 - 550 
   
Exploration Expenditure   
-       Israel ($ million)  10 
-       Egypt ($ million)  0 - 5 
-       Italy, Greece and Croatia ($ million)  5 - 10 
-       UK North Sea ($ million)  40 - 45 
Total Exploration Expenditure ($ million)  55 - 70 
   
Decommissioning   
-       UK North Sea 
-       Italy  2 - 5 
Decommissioning expenditure ($ million)  2 - 5 



Energean Financial Review

Financial results summary

  1H 2021   1H 2020   Change 
Av. daily working interest production (kboed)  44.0  2.1  1,995% 
Sales revenue ($m)  205.5  2.1  9,686% 
Realised oil price ($/boe)  47.3  9.1  419% 
Cash cost of production[14] ($m)  122.4  10.4  1,077% 
Cash cost of production per barrel ($/boe)  15.4  27.5  (44%) 
Cash SG&A[15]  17.0  5.4  215% 
Adjusted EBITDAX[16] ($m)  74.7  (8.8)  939% 
(Loss) after tax ($m)  (35.7)  (77.3)  54% 
Cash flow from operating activities ($m)  53.1  (14.5)  466% 
Capital expenditure ($m)  230.0  249.0  (8%) 
  1H 2021   FY 2020   Change 
Total borrowings ($m)  2,838.8  1,443.1  97% 
Cash and cash equivalents and restricted cash ($m)  1,146.3  202.9  465% 
Net debt / (cash) ($m) (including restricted cash)  1,692.6  1,240.1  36% 
Net debt / equity (%)  212.3%  103.8%  105% 

Revenue, production and commodity prices

Group working interest production averaged 44.0 kboed, an increase of 1,990% for the period (1H 2020: 2.1 kboed), with the Abu Qir field, offshore Egypt, accounting for approximately 70% of total output. 1H 2021 revenue was $205.5 million, a 9,827% increase for the period (1H 2020: $2.1 million), primarily due to the transformational nature of the acquisition of Edison E&P, which closed on 17 December 2020.

The increase in revenue for the period primarily reflects the increased production levels of the Group following the acquisition of Edison E&P, which closed on 17 December 2020. Revenues also benefitted from a higher commodity price environment:

·      During 1H 2021, the average Brent oil price was $65.2/bbl versus $42.2/bbl in 1H 2020, the average PSV price was EUR21.2/MWH (1H 2020: EUR9.3/MWH) and the average NBP price was GBp55.4/Therm (1H 2020: GBp19.0/Therm)

·    This strength across commodity prices resulted in a 1H 2021 average realised price of $47.3/boe (1H 2020: $9.1/boe)

Depreciation, impairments and write-offs

Depreciation charges on production and development assets before impairments increased by 184% to $36.3 million (1H 2020: $12.8 million) due to the higher production levels generated by the Group following the acquisition of Edison E&P, which closed on 17 December 2020.

On a per barrel of oil equivalent of production basis, this represented an 86% decrease to $4.6/boe (1H 2020: $33.7/boe).

During the period, no impairment charges were recognised (1H 2020: $63.0 million).

Other income and expenses

Other expenses of $3.1 million (1H 2020: $15.8 million) include $1.5 million of one-off transaction costs in relation to the Edison E&P acquisition (1H 2020: $8.4 million), and expected credit losses, as well as losses from disposal of property, plant and equipment of $0.3 million.

Other income of $3.6 million (1H 2020: $8.9 million) includes $3.5 million that relate to reversal of prior period provisions and $0.1 million of other income.

Other income in 1H 2020 included a $5.0 million termination fee that was payable by Neptune Energy in relation to the termination of its sale and purchase agreement to buy the UK North Sea and Norwegian subsidiaries, prior to Energean's acquisition of Edison E&P, and $3.9 million of other income related to waivers obtained for specific accounts payable balances in the Greek subsidiary.

Finance income / costs

Net finance costs in 1H 2021 were $42.2 million (1H 2020: net finance income of $0.8 million), composed of $17.0 million (1H 2020: $3.0 million) of interest on borrowings after capitalisation, $27.9 million (1H 2020: $0.5 million) of other debt arrangement fees and other finance costs and $2.7 million of finance income (1H 2020: $4.4 million). The increase in finance and other arrangement fees is due to arrangement fees for the $700 million term loan, which was fully repaid during the period. The increase in other finance costs is primarily due to unwinding costs on the decommissioning provision, which has increased following the acquisition of Edison E&P, combined with losses incurred on interest rate derivatives.

Crude oil hedging

Energean has no commodity price hedges outstanding as of 30 June 2021 (1H 2020: $nil).

Taxation

Energean recorded tax expenses of $15.2 million in 1H 2021 (1H 2020 $21.8 million tax income), composed of corporation tax charges amount $22.1 million and deferred tax income of $5.9 million. Taxation expenses in the period ended 30 June 2021 include $21.5 million relating to taxes (non-cash in nature) being deducted at source in Egypt plus deferred amounts of $5.9 million.

Operating cash flow

In 1H 20201, Energean recorded a cash inflow from operations before changes in working capital of $48.6 million, versus a cash outflow of $15.2 million in 1H 2020. After working capital movements, the cash inflow in 1H 2021 was $53.1 million versus a cash outflow of $14.5 million in 1H 2020. The year-on-year increase in operating cash flow has been predominantly driven by the growth in revenues delivered between the two periods. As discussed above, the increase in revenues during the period is due to i) the increased production levels of the Group following the acquisition of Edison E&P; and ii) the higher commodity price environment.

Non-IFRS measures

The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include adjusted EBITDAX, underlying cash cost of production and SG&A, capital expenditure, net debt and gearing.

Adjusted EBITDAX

Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, share-based payment charge, impairment of property, plant and equipment, other income and expenses, net finance costs and exploration and evaluation expenses. The Group presents adjusted EBITDAX as it is used in assessing the Group's growth and operational efficiencies as it illustrates the underlying performance of the Group's business by excluding items not considered by management to reflect the underlying operations of the Group.

Adjusted EBITDAX[17]  74.7  (8.9) 
Reconciliation to profit / (loss):     
Depreciation and amortisation  (36.3)  (12.8) 
Share-based payment charge  (2.3)  (1.2) 
Impairment losses  (63.0) 
Exploration and evaluation expense  (1.0)  (0.5) 
Other expenses  (3.1)  (15.8) 
Other income  3.6  8.9 
Finance income  2.7  4.4 
Finance cost  (44.9)  (3.6) 
Net foreign exchange gain/(loss)  (13.9)  (6.6) 
Taxation income / (expense)  (15.2)  21.8 
Profit / (loss) from continuing operations  (35.7)  (77.3) 

Cash Cost of production

Cash Cost of production is a non-IFRS measure that is used by the Group as a useful indicator of the Group's underlying cash costs to produce hydrocarbons. The Group uses the measure to compare operational performance period-to-period, to monitor cost and assess operational efficiency. Cash cost of production is calculated as cost of sales, adjusted for depreciation and hydrocarbon inventory movements.

Cost of sales  147.6  17.9 
Less:     
Depreciation  33.8  11.6 
Change in inventory  (8.6)  (4.1) 
Cost of production  122.4  10.4 
Total production for the period (MMboe)  7.9  0.4 
Cost of production per boe ($/boe)  15.4  27.5 

Cash Selling, General & Administrative Expense (SG&A)

Cash SG&A eliminates certain non-cash accounting adjustments to the Group's SG&A. Underlying cash SG&A is defined as Administrative and Selling and distribution expenses, excluding depletion and amortisation of assets and share-based payment charge that are included in SG&A.

  1H 2021  1H 2020 
$m  $m 
Administrative expenses  21.7  6.9 
Selling and distribution expenses  0.1  0.1 
Less:     
Depreciation  2.5  0.4 
Share-based payment charge included in SG&A  2.3  1.2 
Cash SG&A  17.0  5.4 

Energean incurred Cash S,G&A costs of $17.0 million in 1H 2021. This represents a 216% increase versus the comparable period last year (1H 2020: $5.4 million) and is due to increased staffing and administrative costs following the acquisition of Edison E&P and efforts associated with developing the Group's portfolio of projects.

Capital expenditure

Capital Expenditure is defined as additions to property, plant and equipment and intangible exploration and evaluation assets, cash lease payments made in the period, less lease asset additions, asset additions due to decommissioning provisions, capitalised share-based payment charge, capitalised borrowing costs and certain other non-cash adjustments. The Directors believe that capital expenditure is a useful indicator of the Group's organic expenditure on oil and gas development assets, exploration and evaluation assets incurred during a period because it eliminates certain accounting adjustments such as capitalised borrowing costs and decommissioning asset additions.

   
  1H 2021    1H 2020 
  $m    $m 
Additions to property, plant and equipment  317.8    279.8 
Additions to intangible exploration and evaluation assets  30.3    6.8 
Less:       
Capitalised borrowing cost  114.0    40.6 
Leased assets additions and modifications  12.3    0.9 
Lease payments related to capital activities  (5.8)    (4.7) 
Capitalised share-based payment charge  0.2    0.0 
Capitalised depreciation  0.1    0.3 
Change in environmental rehabilitation provision  (2.5)    0.5 
Total capital expenditures  230.0    249.0 
Movement in working capital  (60.0)    (5.8) 
Cash capital expenditures per the cash flow statement  170.0    243.2[18] 

The breakdown of capital expenditures during 1H 2021 and 1H 2020 was as follows:

  1H 2021  1H 2020 
  Capital expenditure $m  Capital expenditure $m 
Development and Production     
Israel  161.8  235.3 
Egypt  17.5 
Italy  11.4 
Greece & Croatia  3.8  2.5 
UK  5.3 
Other  1.0  1.0 
Total  200.8  243.5 
     
Exploration and Appraisal     
Israel  3.7  4.8 
Egypt  0.3 
Italy  2.0 
Greece & Croatia  0.4  0.3 
UK  22.5 
Other  0.3  0.4 
Total  29.2  5.5 

Net cash / debt and gearing ratio

Net debt is defined as the Group's total borrowings less cash and cash equivalents and restricted cash held for loan repayments. Management believes that net debt is a useful indicator of the Group's indebtedness, financial flexibility and capital structure because it indicates the level of borrowings after taking account of any cash and cash equivalents that could be used to reduce borrowings. The Group defines capital as total equity and calculates the gearing ratio as net debt divided by capital.

Net debt reconciliation  1H 2021 $m  1H 2020 $m 
Current borrowings  19.0  38.0 
Non-current borrowings  2,819.8  1,055.8 
Total borrowings  2,838.8  1,093.9 
Less: Cash and cash equivalents  880.0  232.5 
Restricted cash held for loan repayment  266.2 
Net (Funds)/Debt[19]  1,692.6  861.4 
Total equity  797.5  1,184.7 
Gearing ratio  212.3%  72.7% 

Term Loan

On 13 January 2021, Energean signed an 18-month, $700 million term loan facility agreement with J.P. Morgan AG and Morgan Stanley Senior Funding, Inc, the primary uses of which were to accelerate the Karish North development and to fund the up-front consideration for the acquisition of the minority interest in Energean Israel. At the same time, Energean also agreed with the existing lenders of its $1.45 billion project finance facility to extend its maturity by nine months, from December 2021 to September 2022. This term loan was refinanced using proceeds from the bond issuance discussed below.

Refinancing

On 24 March 2021, Energean Israel Finance Limited issued a $2.5 billion bond, split into four equal tranches with maturities in 2024, 2026, 2028 and 2031.

On 29 April 2021, the gross proceeds were released from a segregated escrow account following the satisfaction of release conditions, including the receipt of regulatory approvals and the registration of certain pledges. Part of the proceeds from the issuance were used to refinance the term loan (discussed above) and Energean Israel's $1.45 billion project finance facility. As at the date of refinancing, drawn amounts under the term loan and project finance facility were $175 million and $1,270 million, respectively.

Principal risks and uncertainties

Effective risk management is fundamental to achieving Energean's strategic objectives and protecting its personnel, assets, shareholder value and reputation. The Board has overall responsibility for determining the nature and extent of the risks it is willing to take in achieving the strategic objectives of the Group and ensuring that such risks are managed effectively. A key aspect of this is ensuring the maintenance of a sound system of internal control and risk management. For all the known risks facing the business, Energean attempts to minimise the likelihood and mitigate the impact. Energean has a zero-tolerance approach to financial fraud or ethics non-compliance and ensures that HSE risks are managed to levels that are as low as reasonably practicable.

Overview of key risks and key changes since 31 December 2020

The Group's principal risks for the remaining 6 months of the year and key changes since 31 December 2020 are set out below. For further information on key risks, please refer to Energean's 2020 Annual Report and Accounts:

Strategic risks

#1 Progress key development projects in Israel

Principal risk: Delay to first gas at Karish.

1H 2021 movement: This risk increased in 1H 2021. Following the re-introduction of enhanced COVID-19 related restrictions in Singapore for part of 1H 2021, the Energean Power FPSO is now expected to sailaway from Singapore to Israel in 1Q 2022 with first gas in mid-2022.

Energean is working on a number of contingency measures in the event that there are further outbreaks and variants of COVID-19 in Singapore that lead to the reintroduction of measures that could impact upon the first gas timetable.

Project completion has now reached 91.5% as of 31 July 2021; the closer to completion the project gets, the lower the risk of material delays. Energean is working with its contractors to ensure completion of the project as soon as is possible.

#2 Market risk in Israel

Principal risk: The potential for Israeli gas market oversupply may result in offtake being at the take-or-pay level of existing gas sales and purchase agreements and could result in the failure to secure new GSPAs.

1H 2021 movement: This risk increased in 1H 2021. The market environment is competitive, and the Leviathan field continues to increase its supply of gas, alongside production from Tamar, contributing to market oversupply and a decline in Israeli domestic gas prices towards the price floor set by Energean. Nevertheless, Energean's gas sales and purchase agreements continue to remain the most commercially attractive supply option to domestic gas buyers in Israel, with a weighted average gas price of approximately $4.0/MMbtu.

#3 Progress key development projects

Principal risk: Delayed delivery of future development projects (including NEA / NI in Egypt, Cassiopea in Italy and Karish North in Israel).

1H 2021 movement: This risk decreased in 1H 2021. Energean has made good progress on its Karish North (Israel) and NEA/NI (Egypt) gas developments since taking FID in January 2021, with both projects on schedule and on budget and with no delays envisaged. The Cassiopea project was approximately 23% complete at 31 July 2021 and first gas continues to be expected in 1H 2024. The passage of time and delivery of projects in line with expectations is the key driver of the reduction in this risk.

#4 Deliver exploration success and reserve addition

Principal risk: Lack of new commercial discoveries and reserves replacement.

1H 2021 movement: This risk remained static in 1H 2021. Energean has developed a well-defined exploration plan for its 2022-23 drilling programme, offshore Israel, which will target the derisking of unrisked prospective recoverable resources of over 1 Bnboe. In May 2021, the Company signed a contract with Stena at an attractive day rate for the drilling of three firm wells and two optional wells, with the first well expected to spud in 1Q 2022.

#5 Portfolio integration

Principal risk: Failure to successfully integrate Edison E&P into Energean's day-to-day business activities resulting in limited financial, social and environmental benefits.

1H 2021 movement: This risk decreased in 1H 2021. Energean continues to successfully implement its integration roadmap and has identified areas of synergy across the combined business. Implementation of the end-state operating model remains on target for year-end 2021.

Operational risks

#1 Production performance

Principal risk: Underperformance at core producing assets in Egypt and Italy.

1H 2021 movement: This risk decreased in 1H 2021. Production continues to outperform following robust operational performance across Energean's combined portfolio. Working interest production averaged 44.0 kboed in 1H 2021, around 10% above the mid-point of guidance of 38 - 42 kboed.

#2 JV misalignment

Principal risk: Misalignment with JV operators.

1H 2021 movement: This risk decreased in 1H 2021, due to Energean's increased working interest position in the Vega and Rospo Mare fields, offshore Italy, following the acquisition from ENI, plus good progress having been made on the Cassiopea project, offshore Italy.

Financial risks

#1 Maintaining liquidity and solvency

Principal risk: Insufficient liquidity and funding capacity.

1H 2021 movement: This risk decreased in 1H 2021. In April 2021, the $1.45 billion project finance facility and $700 million term loan were refinanced following a $2.5 billion issuance of senior secured notes. The bond is split into four equal tranches with maturities in 2024, 2026, 2028 and 2031. This optimised debt structure substantially extends the maturity profiles and provides additional near-term flexibility to the Group. Strengthening of commodity prices also helped to decrease this risk.

#2 Egypt receivables

Principal risk: Recoverability of revenues and receivables in Egypt.

1H 2021 movement: This risk remained static in 1H 2021. Cash collection from EGPC during the period was $74.9 million. This was approximately $10 million lower than expected cash collection, the difference being primarily due to timing of collection.

#3 Decommissioning liability

Principal risk: Higher than expected decommissioning costs and acceleration of abandonment schedules

1H 2021 movement: This risk remained static in 1H 2021. No additional decommissioning liabilities were incurred year-to-date and Energean is working on reducing decommissioning liabilities

Climate change risks

#1 Failure to manage the risk of climate change and to adapt to the energy transition

Principal risk: Climate change policy, technological development, changing consumer behaviour and reputational damage.

1H 2021 movement: This risk increased in 1H 2021. The climate change agenda is an ever-increasing area of focus globally and is of critical importance to Energean as it evolves the business and works towards achieving its 2050 net zero target with respect to Scope 1 and 2 emissions. Failure to progress this target could impact the commerciality of the portfolio, lead to loss of licence to operate and result in limited access to/increased cost of capital.

Energean mitigates this risk through ongoing monitoring of key performance indicators by Management. Progress demonstrated in 2021 includes:

·      ESG ratings maintained in the top quartile.

·      Awarded 'Gold' by Maala in July 2021 for a second consecutive year.

·      Three core initiatives being rolled out across all operated sites, including switching to purchasing of 'green' electricity, introduction of a zero-routine-faring policy and establishment of procedures to reduce methane emissions.

·      Technical feasibility studies are ongoing for carbon capture and storage, and eco-hydrogen projects in Prinos in Greece, in conjunction with evaluation of the wider portfolio for such projects.

#2 Physical risks related to climate change

Principal risk: Disruption to operations and/or development projects due to severe weather (both acute and chronic).

1H 2021 movement: This risk remained static in 1H 2021.

External risks

#1 Geopolitical events

Principal risk: Political and fiscal uncertainties in the Eastern Mediterranean.

1H 2021 movement: This risk remained static in 1H 2021.

#2 Global pandemic

Principal risk: Operational uncertainties and HSE incidents due to COVID-19 pandemic.

1H 2021 movement: This risk remained static in 1H 2021.

Emerging risks

Energean faces a number of uncertainties that have the potential to be material to its long-term strategy but cannot be fully defined as a specific risk at present, and therefore cannot be fully assessed or managed. These emerging risks typically have a long-time horizon, such as earlier and increased decommissioning liabilities in the UK and Italy, and elsewhere where the Company operates; increased calls for cash or letter of credit guarantees to be put in place; inadequate management of reserves and production risk resulting in poor returns and impairment.

In 1H 2021, the Group identified the increasing threat from misalignment of national and regional energy transition legislation and direct impacts from unanticipated business interruption, for example due to production downtime or one-off events, emerging risks that will be actively assessed and monitored.

Events since 30 June 2020

Compensation to gas buyers due to late supply:

During August 2021 and in accordance with the GSPAs signed with a group of gas buyers, the Group has agreed to pay compensation to these counterparties due to the fact the gas supply date is taking place beyond a certain date as defined in the GSPAs (being 30 June 2021). The compensation will be paid on a monthly basis starting on August 2021 and is estimated at approx. US$23 million. The compensation is accounted as variable purchase consideration under IFRS 15 hence recognised once production commences and gas is delivered to the offtakers

Gas buyer request for arbitration:

During August 2021 a gas buyer sent a request to the International Court of Arbitration ("ICC") asking for arbitration on its rights of termination due to the fact the gas supply date is taking place beyond a certain date which defined in the GSPA. If the agreement it is terminated, the Group has identified multiple alternative routes to monetise those gas volumes (being 0.8 Bcm/yr), including both domestic and international markets, and hence is confident of profitably selling them

Going Concern Statement

The Group carefully manages its risk to a shortage of funds by monitoring its funding position and its liquidity risk. The going concern assessment covers for the period to 30 September 2022 'the Forecast Period'.

Cash forecasts are regularly produced based on, inter alia, the Group's latest life of field production and budgeted expenditure forecasts, management's best estimate of future commodity prices (based on recent published forward curves) and the Group's borrowing facilities.  The Base Case conservatively assumes first gas from Karish in July 2022, Brent at $70/bbl for the period 1 September to 31 December 2021 and $65/bbl for the period 1 January to 30 September 2022, PSV (Italian gas price) at an average of EUR25/MWH for the period 1 September 2021 to 31 December 2021 and EUR20/MWH for the period January 2022 to 30 September 2022.

In addition, on a regular basis, the Group performs sensitivity tests of its liquidity position for negative impacts that may result from changes to the macro-economic environment such as a fall in commodity price or increase in interest rate. The Group also looks at the impact of changes or deferral of key projects and/or portfolio rationalisation. This is done to identify risks to liquidity and covenant compliance and enable management to formulate appropriate and timely mitigation strategies in order to manage the risk of funding shortfalls or covenant breaches and to safeguard the Group's ability to continue as a going concern.

Specifically, the Group tested the following sensitivities:

·      Reduction in Commodity Prices over the Forecast Period (10% applied to PSV prices and 7.5% to Brent prices)

·      decrease in projected collection of EGPC receivables over the Forecast Period

·      delay in Israel first gas by 3 months to October 2022, which Energean management believes has a low probability of occurring given the acceleration and mitigation measures currently under consideration and the evolution of the COVID-19 situation

A reasonable worst case including a combination of all above sensitivities

The Group also ran a reverse stress test to stress the combination of lower Brent price, lower PSV (Italian Gas Price) and reduced collection of EGPC receivables and assess the impact of this combination on the Group's liquidity and covenants associated with its banking facilities. Energean believes that this combination of scenarios holds a low probability of occurrence.

Should a more extreme downside scenario occur, appropriate mitigating actions that are in management's control and can be executed in the necessary timeframe could be taken such as a tightening of operating cost and reductions/postponement of other discretionary exploration and development expenditures. The Group's cash and cash equivalents at 30 June 2021 were $880 million (excluding restricted cash amounts of $266 million).

In terms of the Group's Borrowing Facilities, the following was considered in the context of the Group's liquidity and covenant compliance over the Forecast Period.

Karish Field Development, Israel:

·      Consistent with the Group's plans to implement new financing as the Karish development approaches first gas in mid-2022, Energean issued a $2.5 billion Bond to (i) refinance its $1.45 billion Project Finance Facility (ii) cancel and replace the $700m Term Loan which was drawn to fund the acquisition of Kerogen's minority interest in Energean Israel, (iii) fund future capital and exploration expenditure in Israel, including Karish and Karish North and (iv) for general corporate purposes of the Group. On 29 April 2021 the Group satisfied the escrow release conditions, as a result the proceeds of the Offering were released from the escrow account.

Greek RBL:

·      In March 2021, the Group agreed a waiver with its lenders under the EBRD reserve-based lending facility whereby there are no more Borrowing Base redeterminations and the facility effectively converts to an amortising term loan with repayments weighted towards the second half of 2022 to 2024. Covenants under the Subordinated Loan Agreement are also waived until December 2022.

Egypt RBL:

The current Borrowing Base redetermination is expected to be completed in September 2021. Given the strong commodities prices and the higher production achieved from the Borrowing Base Assets we do not expect any reduction to the Borrowing Base when the redetermination exercise is completed.

In forming an assessment on the Group's ability to continue as a going concern and its review of the forecasted cashflow of the Group over the Forecast Period (from the date of approval of the interim condensed consolidated financial statements) the Board has made significant judgements about:

·      Reasonable sensitivities appropriate for the current status of the business and the wider macro environment; and

the Group's ability to implement the mitigating actions, if required, is within the Group's control, which would further safeguard the Group's liquidity and covenant compliance.

After careful consideration, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future, for a period up to 30 September 2022. For this reason, they continue to adopt the going concern basis in preparing the consolidated financial statements.

Statement of Directors' responsibilities

The Directors confirm that to the best of their knowledge:

1)    The condensed set of financial statements has been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted in the UK;

2)    The interim management report contains a fair review of the information required by DTR 4.2.7RR (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year);

3)    The interim management report includes a true and fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein).

Interim Condensed Consolidated Income Statement Six months ended 30 June 2021 
  30 June (Unaudited) 
    2021    2020 
    $'000    $'000 
  Notes       
Revenue  205,466    2,070 
Cost of Sales  6(a)  (147,640)    (17,934) 
Gross profit/(loss)    57,826    (15,864) 
         
Administrative expenses  6(b)  (21,668)    (6,853) 
Selling and distribution expenses  6(c)  (102)    (72) 
Exploration and evaluation expenses  6(d)  (1,041)    (529) 
Impairment of property, plant and equipment  11    (63,005) 
Other expenses  6(e)  (3,071)    (15,843) 
Other income  6(f)  3,571    8,914 
Operating profit/(loss)    35,515    (93,252) 
Finance Income  2,700    4,383 
Finance Costs  (44,912)    (3,563) 
Net foreign exchange loss  (13,787)    (6,637) 
Loss before tax    (20,484)    (99,069) 
         
Taxation income / (expense)  (15,174)    21,801 
Loss from continuing operations    (35,658)    (77,268) 
         
Attributable to:         
Owners of the parent    (35,550)    (76,826) 
Non-controlling Interests    (108)    (442) 
    (35,658)    (77,268) 
         
Basic and diluted total loss per share (cents per share) 
Basic  10  ($0.20)    ($0.43) 
Diluted  10  ($0.20)    ($0.43) 


      30 June (Unaudited) 
      2021    2020 
      $'000    $'000 
         
  Loss for the period    (35,658)    (77,268) 
           
  Other comprehensive income:         
  Items that may be reclassified subsequently to profit or loss         
  Cash Flow hedges         
  Gain/(loss) arising in the period    2,278    (11,530) 
  Reclassification to profit and loss upon repayment of related borrowings    4,641   
  Income tax relating to items that may be reclassified to profit or loss    (1,591)    2,652 
  Exchange difference on the translation of foreign operations, net of tax    (6,576)    (1,075) 
  Other comprehensive profit/(loss) after tax    (1,248)    (9,953) 
           
  Total comprehensive loss for the period    (36,906)    (87,221) 
           
  Total comprehensive loss attributable to:         
  Owners of the parent    (36,800)    (84,116) 
  Non-controlling Interests    (106)    (3,105) 
      (36,906)    (87,221) 
           

    30 June 2021 (Unaudited)     
31 December 2020 
   Notes  $'000      $'000 
ASSETS           
Non-current assets           
Property, plant and equipment  11  3,375,231      3,107,272 
Intangible assets  12  286,201      275,816 
Equity-accounted investments       
Other receivables  17  31,552      31,568 
Deferred tax asset  13  128,498      126,056 
Restricted cash  15  100,000     
    3,921,486      3,540,716 
Current assets           
Inventories  16  78,016      73,019 
Trade and other receivables  17  281,985      318,339 
Restricted cash  15  166,241     
Cash and cash equivalents  14  880,017      202,939 
    1,406,259      594,297 
Total assets    5,327,745      4,135,013 
           
EQUITY AND LIABILITIES           
Equity attributable to owners of the parent           
Share capital  18  2,368      2,367 
Share premium  18  915,388      915,388 
Merger reserve    139,903      139,903 
Other reserve    17,577      1,792 
Foreign currency translation reserve    (6,618)      (42) 
Share-based payment reserve    15,893      13,419 
Retained earnings    (294,063)      (144,734) 
Equity attributable to equity holders of the parent    790,448      928,093 
Non-controlling interests  19      266,299 
Total equity    790,448      1,194,392 
Non-current liabilities           
Borrowings  20  2,819,809      330,092 
Deferred tax liabilities  13  70,151      68,609 
Retirement benefit liability  21  6,695      7,839 
Provisions  22  855,004      881,535 
Other payables  23  348,818      177,193 
    4,100,477      1,465,268 
Current liabilities           
Trade and other payables  23  402,420      355,454 
Current portion of borrowings  20  19,020      1,112,984 
Derivative financial instruments  2,405      6,915 
Provisions  22  12,975     
    436,820      1,475,353 
Total liabilities    4,537,297      2,940,621 
Total equity and liabilities    5,327,745      4,135,013 

Interim Condensed Consolidated Statement of Changes in Equity Six months ended 30 June 2021 
  Share Capital  Share Premium[20]  Other Reserve[21]    Equity component of convertible bonds[22]  Share based payment reserve[23]  Translation Reserve[24]    Retained earnings  Merger reserve  Total  Non Controlling Interests  Total 
  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000 
At 1 January 2021  2,367  915,388  1,792  13,419  (42)  (144,734)  139,903  928,093  266,299  1,194,392 
Loss for the period  (35,550)  (35,550)  (108)  (35,658) 
Hedges, net of tax  5,326  5,326  5,328 
Exchange difference on the translation of foreign operations  (6,576)  (6,576)  (6,576) 
Total comprehensive income  5,326  (6,576)  (35,550)  (36,800)  (106)  (36,906) 
Transactions with owners of the company                       
Employee share schemes (note 24)  2,474  2,475    2,475 
Acquisition of non-controlling Interests[25]  10,459  (113,779)  (103,320)  (266,193)  (369,513) 
At 30 June 2021  2,368  915,388  7,118  10,459  15,893  (6,618)  (294,063)  139,903  790,448  790,448 
Interim Condensed Consolidated Statement of Changes in Equity Six months ended 30 June 2021 
  Share Capital  Share Premium18  Other Reserve19    Share based payment reserve21  Translation Reserve22  Retained earnings  Merger reserve23  Total  Non Controlling Interests  Total 
  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000 
At 1 January 2020  2,367  915,388  5,862  10,094  (19,264)  (53,320)  139,903  1,001,030  259,722  1,260,752 
Loss for the period  (76,825)  (76,825)  (442)  (77,267) 
Cash flow hedge, net of tax  (6,215)  (6,215)  (2,663)  (8,878) 
Exchange difference on the translation of foreign operations  (1,075)  (1,075)  (1,075) 
Total comprehensive income  (6,215)  (1,075)  (76,825)  (84,115)  (3,105)  (87,220) 
Transactions with owners of the company 
Share capital increase in subsidiary  9,750  9,750 
Employee share schemes (note 24)  1,363  1,363  1,363 
At 30 June 2020  2,367  915,388  (353)  11,457  (20,339)  (130,145)  139,903  918,278  266,367  1,184,645 

Operating activities         
Loss before taxation    (20,484)    (99,069) 
Adjustments to reconcile profit/(loss) before taxation to net cash provided by operating activities:         
Depreciation, depletion and amortisation  11, 12  36,343    12,787 
Impairment loss on property, plant and equipment  11    63,005 
Impairment on asset held for sale  11    4,935 
Loss from the sale of property, plant and equipment    36   
Defined benefit expenses  21  (1,120)    (192) 
Finance income  (2,700)    (4,383) 
Finance costs                                            44,912    3,563 
Non-cash revenues from Egypt[26]    (21,577)   
Other liabilities derecognised  6(f)    (3,839) 
Movement in provisions  22  483   
Other income  (3,602)   
Share-based payment charge  24  2,474    1,332 
Net foreign exchange gain/(loss)  13,787    6,637 
Cash flow from/(used in) operations before working capital adjustments    48,552    (15,224) 
Increase in inventories    (5,185)    (4,012) 
Decrease in trade and other receivables    42,392    4,565 
(Decrease)/Increase in trade and other payables    (33,082)    225 
Cash inflow/(outflow) from operations    52,677    (14,446) 
Income tax paid    388    (55) 
Net cash inflow/(outflow) from operating activities    53,065    (14,501) 
Investing activities         
Payment for purchase of property, plant and equipment    (141,182)    (231,178) 
Payment for exploration and evaluation, and other intangible assets    (28,818)    (12,077) 
Acquisition of a subsidiary  (3,335)   
Movement in restricted cash  15  (266,241)   
Proceeds from disposal of property, plant and equipment      150 
Interest received    861    470 
Net cash used in investing activities    (438,715)    (242,635) 
Financing activities         
Drawdown of borrowings  20  293,000    200,000 
Repayment of borrowings  20  (1,452,509)    (19,021) 
Senior secured notes Issuance  20  2,500,000   
Transaction costs related to Senior secured notes paid    (37,218)   
Proceeds from capital increases by non-controlling interests  19    9,750 
Acquisition of non-controlling interests  19  (175,000)   
Transaction costs related to acquisition of non-controlling interest    (1,677)   
Repayment of obligations under leases    (5,875)    (4,713) 
Finance cost paid for deferred license payments    (3,494)    (3,993) 
Finance costs paid    (55,641)    (40,367) 
Net cash inflow from financing activities    1,061,586    141,656 
Net increase / (decrease) in cash and cash equivalents    675,936    (115,480) 
Cash and cash equivalents at beginning of the period    202,939    354,419 
Effect of exchange rate fluctuations on cash held    1,142    (6,480) 
Cash and cash equivalents at end of the period  14  880,017    232,459 

1. Corporate Information 

Energean plc (the 'Company') was incorporated in England & Wales on 8 May 2017 as a public company with limited liability, under the Companies Act 2006. Its registered office is at 44 Baker Street, London W1U 7AL, United Kingdom. The Company and all subsidiaries controlled by the Company, are together referred to as "the Group".

The Group has been established with the objective of exploration, production and commercialisation of crude oil and natural gas in Greece, Israel, North Africa and the wider Eastern Mediterranean.

The Group's core assets and subsidiaries as of 30 June 2021 are presented in note 29.

2. Basis of preparation

2.1 Basis of preparation

As a result of the UK's withdrawal from the European Union on 31 December 2020, the financial statements of the Group for the year ending 31 December 2021 will be prepared under UK-adopted International Accounting Standards. Accordingly, the unaudited condensed consolidated interim financial statements for the six months ended 30 June 2021 included in this interim report have been prepared in accordance with UK-adopted International Accounting Standard 34 'Interim Financial Reporting', and unless otherwise disclosed have been prepared on the basis of the same accounting policies and methods of computation as applied in the Group's Annual Report for the year ended 31 December 2020.

The interim condensed consolidated financial statements have been prepared on a historical cost basis and are presented in US Dollars, which is also the Company's functional currency, rounded to the nearest thousand dollars ($'000) except as otherwise indicated.

The US dollar is the currency that mainly influences sales prices and revenue estimates, and also highly affects the Group's operations. The functional currencies of the Group's main subsidiaries are as follows: for Energean E&P Holdings Ltd, Energean Oil & Gas S.A, Energean Montenegro, Energean Italy Spa and Energean International E&P Spa, is Euro, for Energean International Limited, Energean Capital Ltd, Energean Egypt Ltd and Energean Israel Limited is US$.

Comparative figures for the period to 30 June 2020 and 31 December 2020 are for the period ended on that date.

The interim financial statements do not constitute statutory accounts of the Group within the meaning of Section 435 of the Companies Act 2006 and do not include all the information and disclosures required in the annual financial statements. The interim financial statements should be read in conjunction with the Group's Annual Report and Accounts for the year ended 31 December 2020, which were prepared in accordance with IFRSs in conformity with the requirements of the Companies Act 2006 and which have been filed with the Registrar of Companies. The auditor's report on those financial statements was unqualified with no reference to matters to which the auditor drew attention by way of emphasis and no statement under s498(2) or s498(3) of the Companies Act 2006.

Going concern

The Group carefully manages its risk to a shortage of funds by monitoring its funding position and its liquidity risk. The going concern  assessment covers for the period to 30  September 2022 'the Forecast Period'.

Cash forecasts are regularly produced based on, inter alia, the Group's latest life of field production and budgeted expenditure forecasts, management's best estimate of future commodity prices (based on recent published forward curves) and the Group's borrowing facilities.  The Base Case conservatively assumes first gas from Karish in July 2022, Brent at $70/bbl for the period 1 September to 31 December 2021 and $65/bbl for the period January to September 2022, PSV (Italian gas price) at an average of EUR25/MWH for the period 1 September to 31 December 2021 and EUR20/MWH for the period January to September 2022.

In addition, on a regular basis, the Group performs sensitivity tests of its liquidity position for negative impacts that may result from changes to the macroeconomic environment such as a fall in commodity price or increase in interest rate. The Group also looks at the impact of changes or deferral of key projects and/or portfolio rationalisation. This is done to identify risks to liquidity and covenant compliance and enable management to formulate appropriate and timely mitigation strategies in order to manage the risk of funding shortfalls or covenant breaches and to safeguard the Group's ability to continue as a going concern.

Specifically, the Group tested the following sensitivities:

·      Reduction in Commodity Prices over the Forecast Period (10% applied to PSV prices and 7.5% to Brent prices)

·      Decrease in projected collection of EGPC receivables over the Forecast Period

·      Delay in Israel 1st gas by 3 months to October 2022, which Energean management believes has a low probability of occurring given the acceleration and mitigation measures currently under consideration and the evolution of the COVID-19 situation

·      A reasonable worst case including a combination of all above sensitivities

The Group also ran a reverse stress test to stress  the combination of lower Brent price, lower PSV (Italian Gas Price) and reduced collection of EGPC receivables, and assess  the impact of this combination on the Group's liquidity and covenants associated with its banking facilities. Energean believes that this combination of scenarios holds a low probability of occurrence.

Should a more extreme downside scenario occur, appropriate mitigating actions that are in management's control and can be executed in the necessary timeframe could be taken such as a tightening of operating cost and reductions/postponement of other discretionary exploration and development expenditures. The Group's cash and cash equivalents at 30 June 2021 are $880 million.

In terms of the Group's Borrowing Facilities, the following was considered in the context of the Group's liquidity and covenant compliance over the Forecast Period.

Karish Field Development, Israel:

·      Consistent with the Group's plans to implement new financing as the Karish development approaches first gas in mid-2022, Energean issued a $2.5 billion Bond to (i) refinance its $1.45 billion Project Finance Facility (ii) cancel and replace the $700m Term Loan which was drawn to fund the acquisition of Kerogen's minority interest in Energean Israel, (iii) fund future capital and exploration expenditure in Israel, including Karish and Karish North and (iv) for general corporate purposes of the Group. On 29 April 2021 the Group satisfied the escrow release conditions, as a result the proceeds of the Offering were released from the escrow account.

Greek RBL:

·      In March 2021, the Group agreed a waiver with its lenders under the EBRD reserve-based lending facility whereby there are no more Borrowing Base Redeterminations and the facility effectively converts to an amortising term loan with repayments weighted towards the second half of 2022 to 2024. Covenants under the Subordinated Loan Agreement are also waived until December 2022.

Egypt RBL:

·      The current Borrowing Base redetermination is expected to be completed in September 2021. Given the strong commodities prices and the higher production achieved from the Borrowing Base Assets we do not expect any reduction to the Borrowing Base when the redetermination exercise is completed.

In forming an assessment on the Group's ability to continue as a going concern and its review of the forecasted cashflow of the Group over the Forecast Period (from the date of approval of the interim condensed consolidated financial statements) the Board has made significant judgements about:

·      Reasonable sensitivities appropriate for the current status of the business and the wider macro environment; and

·      The Group's ability to implement the mitigating actions, if required, is within the Group's control, which would further safeguard the Group's liquidity and covenant compliance.

After careful consideration, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future, for a period up to 30 September 2022. For this reason, they continue to adopt the going concern basis in preparing the consolidated financial statements.

New and amended accounting standards and interpretations

The accounting policies adopted in the preparation of the unaudited interim condensed consolidated financial statements are consistent with those followed in the preparation of the Group's annual consolidated financial statements for the year ended 31 December 2020, except for the adoption of the new standards and interpretations effective as of 1 January 2021. None of the amendments that are effective as of 1 January 2021 had a significant impact on the Group's interim condensed consolidated financial statements.

The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective as at 1 January 2021. Several amendments and interpretations apply for the first time in 2021, but do not have an impact on the interim condensed consolidated financial statements of the Group.

Interest Rate Benchmark Reform - Phase 2: Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16

The amendments provide temporary reliefs which address the financial reporting effects when an interbank offered rate (IBOR) is replaced with an alternative nearly risk-free interest rate (RFR). The amendments include the following practical expedients:

·      A practical expedient to require contractual changes, or changes to cash flows that are directly required by the reform, to be treated as changes to a floating interest rate, equivalent to a movement in a market rate of interest • Permit changes required by IBOR reform to be made to hedge designations and hedge documentation without the hedging relationship being discontinued

·      Provide temporary relief to entities from having to meet the separately identifiable requirement when an RFR instrument is designated as a hedge of a risk component

The Group intends to use the practical expedients in future periods if they become applicable.

2.2 Approval of accounts

These unaudited condensed interim consolidated financial statements were approved by the Board of Directors on 1 September 2021.

3. Segmental Reporting

The information reported to the Group's Chief Executive Officer and Chief Financial Officer (together the Chief Operating Decision Makers) for the purposes of resource allocation and assessment of segment performance is focused on four operating segments: Europe, (including Greece, Italy, UK, Croatia), Israel, Egypt and New Ventures (Montenegro and Malta).

The Group's reportable segments under IFRS 8 Operating Segments are Europe, Israel and Egypt. Segments that do not exceed the quantitative thresholds for reporting information about operating segments have been included in Other. In 2020, before the acquisition of Edison E&P, the Group had no activities in Egypt and the Europe segment comprised only Greece (including the Prinos and Epsilon production asset, Katakolo non-producing assets and Ioannina and Aitoloakarnania exploration assets).

Segment revenues, results and reconciliation to profit before tax

The following is an analysis of the Group's revenue, results and reconciliation to profit/(loss) before tax by reportable segment:

Six months ended 30 June 2021 (unaudited)           
Revenue from Oil  70,736  27,431  98,167 
Revenue from Gas  34,765  70,929  105,694 
Petroleum products sales  492  492 
Rendering of services  5,228  (4,115)  1,113 
Total revenue  111,221  98,360  (4,115)  205,466 
Adjusted EBITDAX25  9,685   (1,563)  69,113   (2,584)  74,651 
Reconciliation to profit before tax:           
Depreciation and amortisation expenses   (21,586)   (50)   (14,256)   (451)   (36,343) 
Share-based payment charge   (431)  (122)   (1,699)   (2,252) 
Exploration and evaluation expenses   (630)   (411)   (1,041) 
Impairment loss on property, plant and equipment  -  
Other expense   (1,458)   (28)   (88)   (1,497)   (3,071) 
Other income  2,887  641  43  3,571 
Finance income  1,667  1,808  676   (1,451)  2,700 
Finance costs  (10,797)   (9,436)  (624)   (24,055)   (44,912) 
Net foreign exchange gain/(loss)  2,879   (727)  (1,055)   (14,884)   (13,787) 
Profit/(loss) before income tax   (17,784)   (10,118)  54,407   (46,989)   (20,484) 
Taxation income / (expense)   3,342  2,571   (21,535)  448   (15,174) 
Profit/(loss) from continuing operations   (14,442)   (7,547)  32,872   (46,541)   (35,658) 
Six months ended 30 June 2020 (unaudited)           
Revenue from Oil  1,914    1,914 
Revenue from Gas 
Petroleum products sales  3,425   (3,269)  156 
Total revenue  5,339  (3,269)  2,070 
Adjusted EBITDAX[27]   (4,584)   (2,084)   (2,180)   (8,848) 
Reconciliation to profit before tax:         
Depreciation and amortisation expenses   (12,448)   (149)   (190)   (12,787) 
Share-based payment charge   (13)   (39)   (1,102)   (1,154) 
Exploration and evaluation expenses   (183)   (346)   (529) 
Impairment loss on property, plant and equipment   (63,005)   (63,005) 
Other expense   (6,995)   (385)   (8,463)   (15,843) 
Other income  3,913  5,001  8,914 
Finance income  4,094  169  120  4,383 
Finance costs  (3,449)   (26)   (88)   (3,563) 
Net foreign exchange gain/(loss)  (262)  243   (6,618)   (6,637) 
Profit before income tax   (82,932)   (2,271)   (13,866)   (99,069) 
Taxation income / (expense)  20,999  413  389  21,801 
Profit from continuing operations   (61,933)   (1,858)   (13,477)   (77,268) 

The following table presents assets and liabilities information for the Group's operating segments as at 30 June 2021 and 31 December 2020, respectively:

Six months ended 30 June 2021 (unaudited)           
Oil & Gas properties  559,283  2,436,742  332,738   (12,716)  3,316,047 
Other fixed assets  30,043  687  25,343  3,111  59,184 
Intangible assets  137,702  93,337  21,498  33,664  286,201 
Trade and other receivables  108,640  8,652  161,777  2,916  281,985 
Deferred tax asset  103,049  25,448  128,498 
Other assets  940,530  732,623  36,401   (453,724)  1,255,830 
Total assets  1,879,247  3,272,041  603,205  (426,748)  5,327,745 
Trade and other payables  165,465  174,699  58,331  3,925  402,420 
Borrowings  150,923  2,459,910  227,996  2,838,829 
Decommissioning provision  816,153  34,708  850,861 
Other current liabilities  164,508  2,405  (164,509)  2,404 
Other non-current liabilities  4,337  160,580  477,858  (199,992)  442,783 
Total liabilities  1,301,386  2,832,302  536,189  (132,580)  4,537,297 
Other segment information           
Capital Expenditure:           
-  Property, plant and equipment  21,850  162,454  17,019  (508)  200,815 
-  Intangible, exploration and evaluation assets  24,829  3,738  624  29,191 
Year ended 31 December 2020           
Oil & Gas properties  572,834  2,156,236  326,366   (1,728)  3,053,708 
Other fixed assets  21,727  765  27,588  3,484  53,564 
Intangible assets  139,267  89,607  39,219  7,723  275,816 
Trade and other receivables  154,469  1,304  162,222  344  318,339 
Deferred tax asset  103,200  22,856   (0)  126,056 
Other assets  251,240  37,464  247,028   (228,202)  307,530 
Total assets  1,242,737  2,285,376  825,279  (218,379)  4,135,013 
Trade and other payables  187,117  76,146  57,959  34,232  355,454 
Borrowings  121,264  1,093,965  227,847  1,443,076 
Decommissioning provision  826,729  38,399  865,128 
Other current liabilities  140,629  6,914  54,652  (195,280)  6,915 
Other non-current liabilities  25,291  193,920  32,284  18,553  270,048 
Total liabilities  1,301,030  1,409,344  144,895  85,352  2,940,621 
Other segment information         
Capital Expenditure:           
-  Property, plant and equipment  14,117  405,279  860  (197)  420,059 
-  Intangible, exploration and evaluation assets  1,219  6,625  1,147  8,991 
                 

Segment Cash flows

Six months ended 30 June 2021 (unaudited)           
Net cash from / (used in) operating activities  22,329   (2,802)  52,958   (19,420)  53,065 
Net cash (used in) investing activities  (41,614)   (378,265)  (15,695)  (3,141)   (438,715) 
Net cash from financing activities  22,447  1,075,374  (87,054)   50,819  1,061,586 
Net increase/(decrease) in cash and cash equivalents, and restricted cash  3,162  694,307  (49,791)  28,258  675,936 
Cash and cash equivalents at beginning of the period  13,609  37,421  76,240  75,669  202,939 
Effect of exchange rate fluctuations on cash held  409  (146)  (1)  880  1,142 
Cash and cash equivalents at the end of the period  17,180  731,582  26,448  104,807  880,017 
Six months ended 30 June 2020 (unaudited)           
Net cash from / (used in) operating activities  (6,209)  (1,359)  (6,933)  (14,501) 
Net cash (used in) investing activities  (14,380)  (227,713)  (542)  (242,635) 
Net cash from financing activities  19,746  194,484  (72,574)  141,656 
Net increase/(decrease) in cash and cash equivalents  302  (34,588)  (80,049)  (114,335) 
At beginning of the year  6,085  110,488  237,846  354,419 
Effect of exchange rate fluctuations on cash held  (1,114)  (54)  (5,312)   (6,480) 
Cash and cash equivalents at end of the period  5,273  75,846  151,340  232,459 

4. Prior year business combination

Acquisition of Edison E&P

On 17 December 2020, the Group acquired 100 per cent of the issued share capital and obtained control of Edison Exploration & Production S.p.A ("Edison E&P"). Edison E&P contains a portfolio of assets including producing assets in Egypt, Italy, the UK North Sea and Croatia with development assets in Egypt and Italy and balanced-risk exploration opportunities across the portfolio. The acquisition of Edison E&P qualifies as a business combination as defined in IFRS 3.

The fair values of the identifiable assets and liabilities of Edison E&P were provisionally estimated as at the date of acquisition. As of 30 June 2021 no change has been identified to the ascribed fair values of the identifiable assets and liabilities.

The base consideration payable of $398.6 million, which excludes contingent consideration, was agreed as of a locked box date of 1 January 2019 with the impact of economic performance, capital expenditure and working capital movements from this date to completion of 17 December 2020 adjusted within the final consideration payable of $269.9 million from which amount of $266.6 million was paid in December 2020 and amount $3.3 million paid in January 2021.

The contingent consideration arrangement will vary depending on future Italian gas prices at the point in time at which first gas production is delivered from the Cassiopea field in Italy which is expected in 2024. The potential undiscounted amount of all future payments that the Group could be required to make under the contingent consideration arrangement is between $0 and $100 million.

The fair value of the contingent consideration arrangement of $55.2 million was estimated by applying forward gas price curves against the expected date of first gas as at acquisition date.  This resulted in an aggregate fair value of $299.3 million being allocated to the identifiable assets and liabilities acquired, prior to the recognition of a deferred tax liability of $22.9 million as further described below.

Goodwill of $25.3 million has been recognised upon acquisition. An amount of $22.9 million was due to the requirement of IAS 12 to recognise deferred tax assets and liabilities for the difference between the assigned fair values and tax bases of assets acquired and liabilities assumed. The assessment of fair value of such licences is therefore based on cash flows after tax. Hence, goodwill arises as a direct result of the recognition of this deferred tax adjustment ("technical goodwill"). None of the goodwill recognised will be deductible for income tax purposes.

5. Revenue

Crude oil sales  98,167    1,914 
Gas sales  105,694   
Petroleum products sales  492    156 
Rendering of services  1,113   
Total revenue  205,466    2,070 

6. Operating profit/(loss) before taxation

(a)  Cost of sales         
  Staff costs    32,626    6,153 
  Energy cost    3,475    2,550 
  Royalty payable    5,814   
  Other operating costs    80,503    1,717 
  Depreciation and amortisation    33,845    11,581 
  Stock overlift/(underlift) movement    (8,623)    (4,067) 
  Total cost of sales    147,640    17,934 
           
(b)  Administrative expenses         
  Staff costs    7,329    2,744 
  Other General & administration expenses    8,815    2,309 
  Share-based payment charge included in administrative expenses    2,247    1,154 
  Depreciation and amortisation    2,498    385 
  Auditor fees    779    261 
  Total administrative expenses    21,668    6,853 
(c)  Selling and distribution expense         
  Staff costs    29    22 
  Other Selling and distribution expense    73    50 
  Total selling and distribution expense    102    72 
           
(d)  Exploration and evaluation expenses         
  Staff costs for Exploration and evaluation activities    355    141 
  Other exploration and evaluation expenses    686    388 
  Total exploration and evaluation expenses    1,041    529 
(e)  Other operating expenses         
  Transaction costs in relation to Edison E&P acquisition    1,470    8,405 
  Impairment on asset held for sale      4,935 
  Intra-group merger costs      1,524 
  Loss from disposal of Property plant & Equipment    36   
  Other indemnities      203 
  Write down of inventory      124 
  Expected credit losses    279    267 
  Other expenses    1,286    385 
      3,071    15,843 
(f)  Other income         
  Income from accounts payable written off[28]      3,839 
  Reversal of prior period accruals    3,496   
  Proceeds from termination of agreement with Neptune Energy[29]      5,000 
  Other income    75    75 
      3,571    8,914 

7. Net finance cost

           
Interest on bank borrowings    89,501    37,608   
Interest expense on long term payables  467    3,345   
Interest expense on short term liabilities  28     
Less amounts included in the cost of qualifying assets  (72,969)    (37,932)   
    17,027    3,021   
Finance and arrangement fees    11,869    2,184   
Unamortised financing costs related to the repayment of the Karish project finance[30]    36,200     
Other finance costs and bank charges  2,172    678   
Loss on interest rate hedges  6,988     
Unwinding of discount on right of use asset  837    116   
Unwinding of discount on provision for decommissioning  4,946    180   
Unwinding of discount on deferred consideration  5,124     
Unwinding of discount on contingent consideration  744       
Less amounts included in the cost of qualifying assets    (40,995)    (2,616)   
Total finance costs    44,912    3,563   
Interest income from time deposits  (1,534)    (396)   
Gain from revised estimated loan cash flow  (1,166)    (3,987)   
Total finance revenue    (2,700)    (4,383)   
Foreign exchange losses/(gain)    13,787    6,637   
Net financing costs    55,999    5,817   

8. Fair value measurements

The information set out below provides information about how the Group determines the fair values of various financial assets and liabilities.

The fair values of the Group's non-current liabilities measured at amortised cost are considered to approximate their carrying amounts at the reporting date.

The carrying value less any estimated credit adjustments for financial assets and financial liabilities with a maturity of less than one year are assumed to approximate their fair values due to their short term-nature. The fair value of the group's finance lease obligations is estimated using discounted cash flow analysis based on the group's current incremental borrowing rates for similar types and maturities of borrowing and are consequently categorized in level 2 of the fair value hierarchy.

Contingent consideration

As part of the share purchase agreement (the "SPA") dated 4 July 2019 between Energean and Edison Spa provides for a contingent consideration of up to $100.0 million subject to the commissioning of the Cassiopea development gas project in Italy. The consideration was determined to be contingent on the basis of future gas prices (PSV) recorded at the time of the commissioning of the field, which is expected in 2024. No payment will be due if the arithmetic average of the year one (i.e., the first year after first gas production) and year two (i.e., the second year after first gas production) Italian PSV Natural Gas Futures prices is less than €10/Mwh when first gas production is delivered from the field. US$100 million is payable if that average price exceeds €20/Mwh. The contingent consideration to be payable in 2026 is estimated at acquisition date to amount to $61.7m, which discounted at the selected cost of debt results in a present value of $55.2m as at the acquisition date. The fair value of the consideration payable has been recognized at level 3 in the fair value hierarchy and has been estimated by reference to the sales and purchase agreement and by simulating PSV pricing by reference to the forecasted PSV pricing, historical volatility and a log normal distribution.

As at 30 June 2021, the two year future curve of PSV prices increased from the date of acquisition and indicate an average price in excess of €20/Mwh for 2023 it is probable that the average price will exceed €20/Mwh from 2023. The Group monitors closely the future PSV prices however given the current volatility in the commodity markets, the Group's estimate as at 30 June 2021 of the fair value of the contingent consideration payable in 2026 has not materially changed since the previous reporting date.

At 30 June 2021 the fair value has been increased to $56.1 million (31 December 2020: $55.2 million) for the unwinding cost recognised in income statement within finance cost.

Fair values of derivative financial instruments

The Group held financial instruments at fair value at 30 June 2021 related to interest rate derivatives. All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved. Values recorded are as at the balance sheet date, and will not necessarily be realised.

As at 30 June 2021 the Group's interest rate derivative (Level 2) is not designated as hedging instruments.

The fair value hierarchy of financial assets and financial liabilities that are not measured at fair value (but fair value disclosure is required) is as follows:

Financial assets             
Trade and other receivables (note 17)    237,673  237,673   
Cash and cash equivalents and bank deposits (note 14)  880,017  880,017   
Restricted cash  266,241  266,241   
Total    1,146,258  237,673  1,383,931   
Financial liabilities             
Financial liabilities held at amortised cost:           
Trade and other payables - current  272,207  272,207   
Trade and other payables - non-current  1,435  1,435   
Borrowings (note 20)    2,838,829  2,838,829   
Deferred consideration for acquisition of minority    159,551  159,551   
Net obligations under finance leases (note 23)    53,254  53,254   
Deferred licence payments (note 23)    54,712  54,712   
Convertible loan notes (note 20)    39,590  39,590   
Financial liabilities held at FVTPL:             
Interest rate derivatives    2,405  2,405   
Contingent consideration (note 4)    56,091  56,091   
Total    3,421,983  56,091  3,478,074   
             
                     
Financial assets           
Trade and other receivables (note 17)    246,307  246,307 
Cash and cash equivalents and bank deposits (note 14)                 202,939      202.939 
Total    202,939  246,307  449,246 
Financial liabilities           
Financial liabilities held at amortised cost:         
Borrowings (note 20)    1,443,076  1,443,076 
Net obligations under finance leases (note 23)    47,623  47,623 
Deferred licence payments (note 22)    69,518  69,518 
Financial liabilities held at FVTPL:         
Interest rate derivatives    6,915  6,915 
Contingent consideration (note 4)    55,222  55,222 
Total    1,567,132  55,222  1,622,354 
                 

9. Taxation

  30 June (Unaudited) 
  2021    2020 
  $'000    $'000 
Corporation tax - current period  (21,565)   
Corporation tax - prior years  448    386 
Deferred tax (Note 13)  5,943    21,415 
Total taxation income / (expense)  (15,174)    21,801 

(b) Reconciliation of the total tax charge

The Group calculates its income tax expense as per IAS 34 by applying a weighted average tax rate calculated based on the statutory tax rates in Greece (25%), Israel (23%), Italy (24%) and United Kingdom (40%) weighted according to the profit or loss before tax earned by the Group in each jurisdiction where deferred tax is recognised or material current tax charge arises. The effective tax rate for the period is -74% (30 June 2020: -22%).

The tax (charge)/credit of the period can be reconciled to the loss per the consolidated income statement as follows:

       
Profit/(loss) before tax  (20,484)    (99,069) 
       
Tax calculated at 19.70% weighted average rate (2020: 24.95%)[31]  4,035    24,724 
Impact of different tax rates  13    (19) 
Reassessment of recognised deferred tax asset in the current period  (348)    (90) 
Permanent differences[32]  (1,912)    (2,608) 
Non recognition of deferred tax on current period losses[33]  (4,486)    (1,265) 
Tax effect of non-taxable income    625 
Foreign taxes[34]  (21,535)     
Tax effect of non-taxable income[35]  10,985     
Other adjustments[36]  (2,374)    47 
Prior year tax  448    387 
Taxation income/(expense)  (15,174)    21,801 

10. Loss per share

The earnings per share has been calculated by dividing the net profit or loss for the period by the weighted average number of shares outstanding during the period ended 30 June 2021 and 30 June 2020.

  30 June (Unaudited) 
  2021    2020 
  $'000    $'000 
       
Total loss attributable to equity shareholders  (35,550)    (76,826) 
Effect of dilutive potential ordinary shares   
  (35,550)    (76,826) 
Number of shares       
Basic weighted average number of shares  177,117,612    177,089,406 
Dilutive potential ordinary shares   
Diluted weighted average number of shares  177,117,612    177,089,406 
Basic loss per share  ($0.20)/share    ($0.43)/share 
Diluted loss per share  ($0.20)/share    ($0.43)/share 


11. Property, plant and equipment

At 1 January 2020  2,147,163  9,117  56,699  2,212,979 
Additions  411,932  1,951  1,581  415,464 
Acquisition of subsidiary  646,507  40,549  2,132  689,188 
Lease modification  (1,519)  (1,519) 
Disposal of assets  (4,795)  -   (5,328)  (10,123) 
Capitalized borrowing cost  94,929  94,929 
Capitalized depreciation  576  576 
Change in decommissioning provision  39,620  39,620 
Transfer from Intangible assets  41,822  -   41,822 
Foreign exchange impact  52,575  743  5,153  58,471 
At 31 December 2020  3,430,329  50,841  60,237  3,541,407 
Additions  195,062  2,250  85  197,397 
Lease modifications  10,009  10,009 
Disposal of assets  (23)  (36)  (59) 
Capitalized borrowing cost  112,829  112,829 
Capitalised depreciation  106  106 
Change in environmental rehabilitation provision  (2,500)  (2,500) 
Transfer from Intangible assets  13,787  13,787 
Foreign exchange impact  (40,666)  (1,535)  (1,726)  (43,927) 
At 30 June 2021  3,708,924  61,565  58,560  3,829,049 
         
Accumulated Depreciation         
At 1 January 2020  263,512  3,448  43,748  310,708 
Charge for the period         
Expensed  18,105  3,073  2,149  23,327 
Impairments  64,727  572  65,299 
Foreign exchange impact  30,299  458  4,044  34,801 
At 31 December 2020  376,643  6,979  50,513  434,135 
Charge for the period  28,374  4,550  616  33,540 
Disposal of assets  (23)  (23) 
Foreign exchange impact  (12,140)  (202)  (1,492)  (13,834) 
At 30 June 2021  392,877  11,327  49,614  453,818 
Net carrying amount         
At 31 December 2020  3,053,686  43,862  9,724  3,107,272 
At 30 June 2021  3,316,047  50,238  8,946  3,375,231 

Included in the carrying amount of leased assets at 30 June 2021 is right of use assets related to oil and gas properties and Other property, plant and equipment of $43.3 million and $6.9 million respectively.

The depreciation charged on these classes for the six-month ending 30 June 2021 were $4.1 million and $0.4 million respectively.

The additions to oil & gas properties for the period of six months ended 30 June 2021 is mainly due to development costs of Karish field related to the EPCIC contract (FPSO, Sub Sea and On-shore construction cost) at the amount of $161.8 million, development cost for Cassiopea project in Italy at the amount of $8.4 million and NEA/NI project in Egypt at the amount of $17.5 million.

Borrowing costs capitalised for qualifying assets, included in oil & gas properties, for the six months ended 30 June 2021 amounted to $123.4 million (year ended 31 December 2020: $94.9 million). The weighted average interest rates used:

·      7.66% (for the six months ended 30 June 2021)

·      8.72% (for the year ended 31 December 2020)

During the year 2020 the Group executed an impairment test for the Prinos CGU (Prinos and Epsilon fields). In that period, indicators of impairment were noted for the Prinos CGU, being a reduction in both short-term (Dated Brent forward curve) and long-term price assumptions and a change in the Group's Prinos field production forecast, which have resulted in an impairment of $65.3 million in the carrying value of the Prinos CGU.

12. Intangible assets

Intangibles at Cost           
At 1 January 2020  71,601  75,800  1,941  149,342     
Additions  8,379  612  8,991     
Acquisition of subsidiary  115,438  25,346  18,348  159,132     
Capitalized borrowing costs  2,761  2,761     
Transfers to property, plant and equipment  (41,822)  (41,822)     
Exchange differences  1,856  1,454  3,310     
At 31 December 2020  158,213  101,146  22,355  281,714     
Additions  28,255  937  29,192   
Capitalized borrowing costs  1,134  1,134   
Transfers to property, plant and equipment  (278)  (13,509)  (13,787)   
Exchange differences  (500)    (3,218)  (3,718)   
At 30 June 2021  186,824  101,146  6,565  294,535   
           
Accumulated amortisation and impairments           
At 1 January 2020  261  1,405  1,666     
Charge for the period  1,375  1,375     
Impairment  2,936  2,936     
Exchange differences  (193)  114  (79)     
At 31 December 2020  3,004  2,894  5,898     
Charge for the period  2,031  772  2,803   
Exchange differences  (114)    (253)  (367)   
30 June 2021  4,921  3,413  8,334   
           
Net Carrying Amount           
At 31 December 2020  155,209  101,146  19,461  275,816     
At 30 June 2021  181,903  101,146  3,152  286,201   

Borrowing costs capitalised for qualifying assets for the period ended 30 June 2021 amounted to $1.1 million (31 December 2020: $2.8 million). The weighted average interest rate used was 7.34% (31 December 2020: 8.72%).

13. Net deferred tax (liability)/ asset

At 1 January 2020  (137,998)  (1,078)  (971)  733  90,412  913  7,646  (40,343) 
Acquisition of subsidiary (Note 4)  10,080          60,752      70,832 
Increase / (decrease) for the period through:                     
profit or loss (Note 9)  8,381  819  8,877  (3,474)  (98)  7,384  53  (434)  21,508 
other comprehensive income  130  1,603  1,733 
Exchange difference  (4,006)  (33)  (336)  60  7,293  84  655  3,717 
31 December 2020  (123,543)  (292)  8,877  (4,651)  695  165,841  1,050  9,470  57,447 
Increase / (decrease) for the period through:                     
profit or loss (Note 9)  (14,853)  67  (774)  1,053  (659)  12,261  1,908  43  6,897  5,943 
other comprehensive income                  (1,591)  (1,591) 
Reclassifications in the current period[37]  (28,442)  33,644  2,025  (233)  (4,903)  6,010  200  (8,301) 
Exchange difference  (243)  (421)  132  (13)  (2,742)    (32)  (139)  (3,452) 
30 June 2021  (167,081)  (219)  41,326  (1,441)  (210)  170,457  7,918  1,261  6,336  58,347 
    30 June 2021  31 December 2020   
    $'000  $'000   
Deferred tax liabilities    (70,151)  (68,609)   
Deferred tax assets    128,498  126,056   
Net deferred tax assets / (liabilities)    58,347  57,447   
                         

At 30 June 2021 the Group has gross unused tax losses of $757.3 million (as of 31 December 2020: $783.6 million) available to offset against future profits. Out of the total tax losses, $380.4 million come from the Greek operations whereas amount of $18.1 million comes from the Israeli operations and specifically the Karish licence which is in the development phase and expected to commence production by 2021. Tax losses of $329.6 million comes from the Italian and UK operations of the former Edison E&P Group.

With respect to the Greek tax losses carried forward, the majority of them ($374.3 million) come from the Prinos exploitation area, whereas an amount of $1.5 million comes from Ioannina and Katakolo areas which are in the exploration and development phase respectively.

A deferred tax asset of $170.5 million has been recognised as of 30 June 2021 (as of 31 December 2020: $165.8 million) in respect of such tax losses. This represents the losses which are expected to be utilised based on Group's projection of future taxable profits in the jurisdictions in which the losses reside. It is considered probable based on business forecasts that such profits will be available.

14. Cash and cash equivalents

  30 June    31 December 
  2021 (Unaudited)    2020 
  $'000    $'000 
       
Cash at bank  878,580    197,514 
Deposits in escrow  1,437    5,425 
  880,017    202,939 

Bank demand deposits comprise deposits and other short-term money market deposit accounts that are readily convertible into known amounts of cash. The effective interest rate on short‑term bank deposits was 0.3% for the six months period ended 30 June 2021 (year ended 31 December 2020: 1.07%).

Deposits in escrow comprise mainly cash retained as a bank security pledge for the Group's performance guarantees in its exploration blocks. These deposits can be used for funding the exploration activities of the respective blocks. 

15. Restricted Cash

Restricted cash comprise mainly cash retained under the Senior Secured Notes requirement as follows:

·      Short term - US$163.3 million Interest Payment Account for the accrued interest period until 30 June 2022 (less coupons actually paid) and from 30 June 2022 the Interest Reserve Account will be funded 6 months forward 

·      Long term - US$100 million Debt Payment Fund that would be released upon achieving three quarters annualized production of 3.8 BCM/year from Karish asset in Israel.

The remaining amount of $2.96 included in restricted cash is related to cash collateral provided under a letter of credit facility for issuing bank guarantees for Group's activities in Israel up to $75 million. 

16. Inventories

  30 June 20201 (Unaudited)    31 December 2020 
  $'000    $'000 
Raw materials and supplies  53,057    56,073 
Crude oil  24,959    16,946 
Total inventories  78,016    73,019 

In the period ended 30 June 2021 the write-down of crude oil inventory to net realisable value amounted to $nil million (six months ended 30 June 2020: $5.6 million) which is included in "cost of sales".

17. Trade and other receivables

Trade and other receivables-Current       
Financial items:       
Trade receivables  185,967    226,118 
Receivables from partners under JOA  28,190   
Other receivables  3,213   
Government subsidies[38]  3,371    3,481 
Receivables from related parties (note 24)    22 
  220,741    229,621 
Non-financial items:       
Deposits and prepayments[39]  26,974    38,756 
Refundable VAT  32,747    49,414 
Other taxes receivable  209   
Deferred insurance expenses  579    507 
Accrued interest income  735    41 
  61,244    88,718 
  281,985    318,339 
Trade and other receivables-Non Current       
Financial items:       
Accrued interest income   
Other tax recoverable  16,931    16,686 
  16,932    16,686 
Non-financial items:       
Deferred borrowing fees  49   
Deposits and prepayments  12,945    13,409 
Other deferred expenses  209   
Other non-current assets  1,417    1,473 
  14,620    14,882 
  31,552    31,568 

18. Share capital

The below tables outline the share capital of the Company.

Issued and authorized       
At 1 January 2020  177,089,406  2,367  915,388 
Issued during the year       
- New shares 
- Share based payment 
At 31 December 2020  177,089,406  2,367  915,388 
Issued during the period       
- Share based payment  51,361   
At 30 June 2021  177,140,767  2,368  915,388 

19. Non‑controlling interests

Name of subsidiary  Voting rights  Share of loss  Accumulated balance 
30 June (Unaudited)  Year ended 31 December  30 June (Unaudited)  Year ended 31 December  30 June (Unaudited)  Year ended 31 December 
2021  2020  2021  2020  2021  2020 
$'000  $'000  $'000  $'000 
Energean Israel Ltd  30.00  (106)  (3,173)  266,299 
Total   30.00  (106)  (3,173)  266,299 

On 25 February 2021, the Group completed the acquisition of the remaining 30% minority interest in Energean Israel Limited from Kerogen Investments No.38 Limited, Energean now owns 100% of Energean Israel Limited.

This resulted in a reduction of the Group's reported non-controlling interest balance to $nil at 30 June 2021.

The Total Consideration includes:

·      An up-front payment of $175 million (the "Up-Front Consideration") paid at completion of the transaction

·      Deferred cash consideration amounts totalling $180 million, which are expected to be funded from future cash flows and optimisation of the group capital structure, post-first gas from the Karish project. The deferred consideration is discounted at the selected unsecured liability rate of 9.77%.

·      $50 million of convertible loan notes (the "Convertible Loan Notes"), which have a maturity date of 29 December 2023, a strike price of GBP 9.50 and a zero-coupon rate.

The following is a schedule of additional interest acquired in Energean Israel Limited:

  $'000 
Cash consideration paid to non-controlling shareholders at completion  175,000 
Deferred cash consideration  154,499 
Convertible Loan Notes - Liability Component  38,337 
Convertible Loan Notes - Equity Instrument Component  10,459 
Cost related to the transaction  1,677 
Carrying value of the 30% minority interest  (266,193) 
Difference recognised in retained earnings  113,779 

The Acquisition of the remaining 30% minority interest in Energean Israel adds 2P reserves of 29.5 billion cubic metres ("Bcm") of gas and 30 million barrels of liquids, representing approximately 219 million barrels of oil equivalent ("MMboe") in total, to the Group.

20. Borrowings

Non-current         
Bank borrowings - after two years but withing five years         
4,5% Senior Secured notes due 2024 ($625 million)    615,419   
4,875% Senior Secured notes due 2026 ($625 million)    615,030   
Senior Credit facility ($237 million)    229,485    227,848 
EBRD Senior Facility Loan ($180 million)    75,696    84,420 
EBRD Subordinated Facility Loan ($20 million)    15,128    17,824 
Convertible loan notes ($50 million) - (note 19)    39,590   
Bank borrowings - more than five years         
5.375% Senior Secured notes due 2028 ($625 million)    614,818   
5.875% Senior Secured notes due 2031 ($625 million)    614,643   
Carrying value of non-current borrowings    2,819,809    330,092 
         
Current         
6,83% EBRD Senior Facility Loan due 2024 ($97,6 million)    19,020    19,020 
Senior Credit Facility for the Karish-Tanin Development ($1,450 million)      1,093,964 
Carrying value of current borrowings    19,020    1,112,984 
         
Carrying value of total borrowings    2,838,829    1,443,076 

The Group has provided security in respect of certain borrowings in the form of share pledges, as well as fixed and floating charges over certain assets of the Group.

US$2,500,000,000 senior secured notes:

On 24 March 2021, the Group completed the issuance of US$2.5 billion aggregate principal amount of senior secured notes.

The Notes have been issued in four series as follows:

·      Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2024, with a fixed annual interest rate of 4.500%.

·      Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2026, with a fixed annual interest rate of 4.875%.

·      Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2028, with a fixed annual interest rate of 5.375%.

·      Notes in an aggregate principal amount of US$625 million, maturing on 30 March 2031, with a fixed annual interest rate of 5.875%.

The interest on each series of the Notes will be paid semi-annually, on 30 March and on 30 September of each year, beginning on 30 September 2021.

On 29 April 2021 the Group satisfied the escrow release conditions in respect of its US$2.5 billion aggregate principal amount of the Notes offering. As a result of satisfying the said escrow release conditions, the proceeds of the Offering were released from escrow.

The Notes are listed for trading on the TACT Institutional of the Tel Aviv Stock Exchange Ltd. (the "TASE").

The use of proceeds from the Offering is as follows :

·      To repay outstanding Senior Credit Facility for the Karish-Tanin Development facility and outstanding amount under a US$700 million term loan;

·      To replace the existing undrawn amounts available under those facilities;

·      To fund certain reserve accounts; and

·      For transaction expenses and the Group's general corporate purposes.

The Company had undertook to provide the following collateral in favor of the Trustee:

·      First rank Fixed charges over the shares of Energean Israel Limited, Energean Israel Finance Ltd and Energean Israel Transmission Ltd, the Karish & Tanin Leases, the gas sales purchase agreements ("GSPAs"), several bank accounts, Operating Permits (once issued), Insurance policies, the Company exploration licenses (Block 12, Block 21, Block 23, Block 31 and 80% of the licenses under "Zone D") and the INGL Agreement.

·      Floating charge over all of the present and future assets of Energean Israel Limited and Energean Israel Finance Ltd.

·      Energean Power FPSO (subject to using commercially reasonable efforts, including obtaining Israel Petroleum Commissioner approval and any other applicable governmental authority).

Senior Credit Facility for the Karish-Tanin Development:

On 29 April 2021, following the release of the senior secured notes proceeds of $2.5bn, the Company repaid its existing outstanding facility.

Capital management

The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders and benefits to stakeholders and to safeguard the Group's ability to continue as a going concern.

Net Debt           
Current borrowings    19,020    1,112,984   
Non-current borrowings    2,819,809    330,092   
Total borrowings     2,838,829    1,443,076   
Less: Cash and cash equivalents  (880,017)  (202,939)    (202,939) 
Restricted cash  (266,241)     
Net Debt (1)    1,692,571    1,240,137   
Total equity  (2)    790,448    1,194,392   
Gearing Ratio (1/2):    214.13%    103.83%   
                 

Reconciliation of liabilities arising from financing activities

  1 January 2021  Cash inflows  Cash outflows  Reclassification  Additions  Lease modification  Borrowing costs including amortisation of arrangement fees  Derivatives de-designated as cash flow hedges during the period  Gain from revised estimated loan cash flow  Foreign exchange impact  Fair value changes  30 June 2021 
  $'000  $'000  $'000  $'000  $'000  $'000  $'000  $'000    $'000    $'000 
30 June 2021  1,622,354  2,793,000  (1,559,213)  (34,676)  190,776  10,055  143,102  4,641  (1,146)  2,864  (6,915)  3,164,842 
Secured Senior Notes    2,500,000  (37,218)  (36,663)      33,791        2,459,910 
Convertible loan notes (note 19)    38,337  1,253  39,590 
Long -term borrowings  330,092  175,000  (200,131)  (31)  16,484  (1,146)  41  320,309 
Current portion of long-term borrowings  1,112,984  118,000  (1,297,062)  2,080  82,984    34  19,020 
Lease liabilities  47,623  (5,875)  (62)  2,250  10,055  837    (1,574)  53,254 
Deferred licence payments  69,518  (14,344)  (462)    54,712 
Contingent consideration  55,222    744    55,966 
Deferred consideration for acquisition of minority  150,189  5,124    4,363    159,676 
Derivatives not designated as hedging instruments  6,915  (4,583)  2,347  4,641    (6,915)  2,405 

21. Retirement benefit liability

21.1 Provision for retirement benefits

    30 June 2021 (Unaudited)    31 December 2020 
    $'000    $'000 
Defined benefit obligation    6,695    7,839 
Provision for retirement benefits recognised    6,695    7,839 
Allocated as:         
Non current portion    6,695    7,839 

21.2 Defined benefit obligation

    30 June 2021 (Unaudited)    31 December 2020 
    $'000    $'000 
At 1 January    7,839    4,265 
Acquisition of subsidiary        3,021 
Current service cost    183    364 
Interest cost    21    39 
 Extra payments or expenses    69    557 
Actuarial losses - from changes in financial assumptions    50    49 
Benefits paid    (1,197)    (866) 
Transfer in/(out)    (35)   
Exchange differences    (235)    410 
At 30 June / 31 December    6,695    7,839 

22. Provisions

  Provision for environment rehabilitation  Litigation and other provisions  Total 
  $'000  $'000  $'000 
At 1 January 2021  865,127  16,408  881,535 
New provisions  1,227  1,227 
Change in estimates  (2,500)  (2,500) 
Payments  (1,710)    (1,710) 
Unwinding of discount  4,946  4,946 
Currency translation adjustment  (15,002)  (517)  (15,519) 
At 30 June 2021  850,861  17,118  867,979 
Current provisions  12,975  12,975 
Non-current provisions  837,886  17,118  855,004 

Decommissioning provision

The decommissioning provision represents the present value of decommissioning costs relating to oil and gas properties, which are expected to be incurred up to 2040, when the producing oil and gas properties are expected to cease operations. The future costs are based on a combination of estimates from an external study completed at the end of 2019 and internal estimates. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required that will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This, in turn, will depend upon future oil and gas prices, which are inherently uncertain.

The decommissioning provision represents the present value of decommissioning costs relating to assets in Italy, Greece, UK, Israel and Croatia. No provision is recognized for Egypt as there is no legal or constructive obligation as at 30 June 2021.

Greece    1.01% - 1.3%  0.8%  2034  17,186  16,082 
Italy    0.6%-1.4%  1.45%  2021-2040  536,180  551,464 
UK    1.9%  0.35%  2022-2030  243,700  239,708 
Israel    1.02%-1.6%  2.0%  2040  34,708  38,399 
Croatia    na  na  2022  19,087  19,474 
Total          850,861  865,127 

Litigation and other claims provisions

Litigation and other claim provision relates to litigation actions currently open in Italy with the Termoli Port Authority in respect of the fees payable under the marine concession regarding FSO Alba Marina serving the Rospo Mare field in Italy.  Energean Italy Spa has appealed these cases to the Campobasso Court of Appeal. None of the other cases has yet had a decision on the substantive issue. The Group contain a provision of €4.7 million against an adverse outcome of these court cases.

Energean Italy Spa has currently open litigations with five municipalities in Italy related to the imposition of real estate municipality taxes (IMU/TASI), interest and related penalties concerning the periods 2016 to 2019. For the years before 2019, Edison SpA bears uncapped liability for any amount assessed according the sale and purchase agreement (SPA) signed between the companies while the Company is liable for any tax liability related to tax year 2019. For all five cases, Energean Italy Spa (together with  Edison SpA, as appropriate) filed appeals presenting strong legal and technical arguments for reducing the assessed taxes to the lowest possible level as well as cancelling entirely the imposed penalties. The Group strongly believes based on legal advice received that the outcome of the court decisions will be in its favour with no material exposure expected, therefore the Group recognised a provision of $1.2 million in respect of this claims.

Amount of $1.8 million provision relates to leasing cost charged to ENI on the floating storage located in the Leoanis plan. The Group following a claim from  ENI accounted for this provision since these overestimated costs were required to be reimbursement.

Other provisions include non-income tax provision and other potential claim in Egypt.

It is not currently possible to accurately predict the timing of the settlement of these claims and therefore the expected timing of the cash flows.

23. Trade and other payables

       
Trade and other payables-Current       
Financial items:       
Trade accounts payable[40]  214,290    193,987 
Payables to partners under JOA[41]  46,922    64,752 
Deferred licence payments due within one year[42]    14,344 
Other creditors  10,995    12,502 
Short term lease liability  12,247    10,561 
  284,454    296,146 
Non-financial items:       
Accrued Expenses38  79,149    49,812 
Other finance costs accrued  34,840    2,630 
Social insurance and other taxes  3,947    5,695 
Income taxes  30    1,171 
  117,966    59,308 
  402,420    355,454 
Trade and other payables-Non Current       
Financial items:       
Deferred consideration for acquisition of minority (note 19)  159,551   
Deferred licence payments40  54,712    55,174 
Contingent consideration (note 4)  56,091    55,222 
Long term lease liability  41,007    37,062 
Other payables  1,435   
  312,796    147,458 
Non-financial items:       
Long term prepayment[43]  35,525    29,105 
Social insurance  497    630 
  36,022    29,735 
  348,818    177,193 

24. Share based payments

Analysis of share-based payment charge

       
Energean  DSBP Plan  530    290 
Energean Long Term Incentive Plans  1,944    1,075 
Total share-based payment charge  2,474    1,365 
Capitalised to intangible and tangible assets  207    33 
Expensed as cost of sales     
Expensed as administration expenses  2,247    1,154 
Expensed to exploration and evaluation expenses  14    174 
Expensed as other expenses   
Total share-based payment charge  2,474    1,365 

Energean Long Term Incentive Plan (LTIP)

Under the LTIP, Senior Management can be granted nil exercise price options, normally exercisable from three to ten years following grant provided an individual remains in employment. The size of awards depends on both annual performance measures and Total Shareholder Return (TSR) over a period of up to three years. There are no post-grant performance conditions. No dividends are paid over the vesting period; however, Energean's Board may decide at any time prior to the issue or transfer of the shares in respect of which an award is released that the participant will receive an amount (in cash and/or additional Shares) equal in value to any dividends that would have been paid on those shares on such terms and over such period (ending no later than the Release Date) as the Board may determine. This amount may assume the reinvestment of dividends (on such basis as the Board may determine) and may exclude or include special dividends.

The weighted average remaining contractual life for LTIP awards outstanding at 30 June 2021 was 1.6 years, number of shares outstanding 2,036,982 and weighted average price at grant date £5.99.

Deferred Share Bonus Plan (DSBP)

Under the DSBP, the portion of any annual bonus above 30 per cent of the base salary of a Senior Executive nominated by the Remuneration Committee was deferred into shares.

Deferred awards are usually granted in the form of conditional share awards or nil-cost options (or, exceptionally, as cash-settled equivalents). Deferred awards usually vest two years after award although may vest early on leaving employment or on a change of control.

The weighted average remaining contractual life for DSBP awards outstanding at 30 June 2021 was 1.3 years, number of shares outstanding 234,902 and price at grant date £6.75.

25. Related parties

25a. Related party relationships

Balances and transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note.

The Directors of Energean Plc are considered to be the only key management personnel as defined by IAS 24. The following information is provided in relation to the related party transaction disclosures provided in note 25b below:

·      Adobelero Holdings Co Ltd. is a beneficially owned holding company controlled by Panos Benos, the CFO of the Group.

·      Growthy Holdings Co Ltd is a beneficially owned holding company controlled by Matthaios Rigas, the CEO of the Group.

·      Oil Co Investments Limited is beneficially owned and controlled by Efstathios Topouzoglou, a Non-Executive Director of the Group. The nature of the Group's transactions with the above related parties is mainly financing activities.

·      Kerogen Capital is an independent private equity fund manager specialising in the international oil and gas sector, which until February 2021 held the 30% of Energean Israel ordinary shares not held by the group (please refer to note 19).

·      Seven Maritime Company (Seven Marine) is a related party company controlled by one the Company's shareholder Mr Efstathios Topouzoglou. Seven Marine owns the offshore supply ships Valiant Energy and Energean Wave which support the Group's investment program in northern Greece.

·      Capital Earth:  During the period ended 30 June 2021 the Group received consultancy services from Capital Earth Limited, a consulting company controlled by the spouse of one of Energean's executive directors, for the provision of Group Corporate Social Responsibility Consultancy and Project Management Services.

25b. Related party transactions

Purchases of goods and services

        30 June (Unaudited) 
        2021    2020 
        $'000    $'000 
  Nature of transactions           
Other related party "Seven Marine"  Vessel leasing      993    1,189 
Other related party "Prime Marine Energy Inc"  Construction of field support vessel      3,300   
Other related party "Capital Earth Ltd"  Consulting services      46    63 
        4,339    1,252 

Following a competitive tender process, the Group has entered into an agreement to purchase a Field Support Vessel ("FSV") from Prime Marine Energy Inc., a company controlled by director and shareholder at Energean plc, for US$33.3 million. The FSV is being constructed to meet the Group's specifications and will provide significant in-country capability to support the Karish project, including FPSO re-supply, crew changes, holdback operations for tanker offloading, emergency subsea intervention, drilling support and emergency response. The purchase of this multi-purpose vessel will enhance operational efficiencies and economics when compared to the leasing of multiple different vessels for the various activities.

25c. Related party balances

Payables

        30 June 2021 (Unaudited)    31 December 2020 
        $'000    $'000 
  Nature of balance           
Seven Marine  Vessel leasing      882    407 
        882    407 

26. Commitments and contingencies

In acquiring its oil and gas interests, the Group has pledged that various work programmes will be undertaken on each permit/interest. The exploration commitments in the following table are an estimate of the net cost to the Group of performing these work programmes:

Capital Commitments:       
Due within one year  97,351    102,255 
Due later than one year but within two years  138,665    84,855 
Due later two years but within five years  75,344    200,895 
  311,360    388,005 
Contingent liabilities: Performance guarantees:       
Greece  4,751    6,743 
Israel  64,740    62,101 
UK  98,078    96,655 
Italy  9,455    15,361 
Montenegro  594    614 
  177,618    181,474 
         

28. Subsidiary undertakings

At 30 June 2021, the Group had investments in the following subsidiaries:

Energean E&P Holdings Ltd  22 Lefkonos Street, 2064 Nicosia, Cyprus  Holding Company  100  100 
Energean Capital Ltd  22 Lefkonos Street, 2064 Nicosia, Cyprus  Holding Company  100  100 
Energean MED Limited  44 Baker Street, London W1U 7AL, United Kingdom  Oil and gas exploration, development and production  100  100 
Energean Oil & Gas S.A.  32 Kifissias Ave. 151 25 Marousi Athens, Greece  Oil and gas exploration, development and production  100  100 
Energean International Limited  22 Lefkonos Street, 2064 Nicosia, Cyprus  Oil and gas exploration, development and production  100  100 
Energean Israel Limited (Note 19)  22 Lefkonos Street, 2064 Nicosia, Cyprus  Oil and gas exploration, development and production  100  70 
Energean Montenegro Limited  22 Lefkonos Street, 2064 Nicosia, Cyprus  Oil and gas exploration, development and production  100  100 
Energean Israel Finance SARL  560A rue de Neudorf, L-2220, Luxembourg  Financing activities  100  70 
Energean Israel Transmission LTD  Andre Sakharov 9, Haifa, Israel  Gas transportation license holder  100  70 
Energean Israel Finance LTD  Andre Sakharov 9, Haifa, Israel  Financing activities  100  70 
Energean Egypt Limited  22 Lefkonos Street, 2064 Nicosia, Cyprus  Oil and gas exploration, development and production  100  100 
Energean Hellas Limited  22 Lefkonos Street, 2064 Nicosia, Cyprus  Oil and gas exploration, development and production  100  100 
Energean Italy S.p.a.  Piazza Sigmund Freud 1 20154 Milan,Italy  Oil and gas exploration, development and production  100  100 
Energean International E&P S.p.a.  Piazza Sigmund Freud 1 20154 Milan,Italy  Oil and gas exploration, development and production  100  100 
Energean Sicilia Srl  Via Salvatore Quasimodo 2 - 97100 Ragusa (Ragusa)  Oil and gas exploration, development and production  100  100 
Energean Exploration Limited  44 Baker Street, London W1U 7AL, United Kingdom  Oil and gas exploration, development and production  100  100 
Edison E&P UK Ltd  44 Baker Street, London W1U 7AL, United Kingdom  Oil and gas exploration, development and production  100  100 
Edison Egypt Energy Services JSC  Building 11, 273 Palestine Street  New Maadi , Cairo EGYPT  Oil and gas exploration, development and production  98  98 

29. Exploration, Development and production interests

Israel       
  Karish  Concession  100%  Development 
  Tanin  Concession  100%  Development 
  Blocks 12, 21, 23, 31  Concession  100%  Exploration 
  Four licences Zone D  Concession  80%  Exploration 
Egypt     
  Abu Qir  PSC  100%  Production 
  Abu Qir North  PSC  100%  Production 
  Abu Qir West  PSC  100%  Production 
  Yazzi  PSC  100%  Development 
  Python  PSC  100%  Development 
  Field A (NI-1X)  PSC  100%  Exploration 
  Field B (NI-3X)  PSC  100%  Exploration 
  NI-2X  PSC  100%  Exploration 
  North East Hap'y  PSC  30%  Exploration 
  Viper (NI-4X)  PSC  100%  Exploration 
Greece     
  Prinos  Concession  100%  Production 
  Epsilon  Concession  100%  Development 
  Prinos exploration area  Concession  100%  Exploration 
  South Kavala  Concession  100%  Production 
  Katakolo  Concession  100%  Undeveloped 
  Ioannina  Concession  40%  Exploration 
  West Patraikos  Concession  50%  Exploration 
  Block-2  Concession  75%  Exploration 
Italy     
  Vega A  Concession  100%  Production 
  Vega B  Concession  100%  Production 
  Rospo Mare  Concession  100%  Production 
  Verdicchio  Concession  100%  Production 
  Vongola Mare  Concession  95%  Production 
  Gianna  Concession  100%  Development 
  Accettura  Concession  50%  Production 
  Anemone  Concession  19%  Production 
  Appia  Concession  50%  Production 
  Argo-Cassiopea  Concession  40%  Development 
  Azalea  Concession  16%  Production 
  Calipso  Concession  49%  Production 
  Candela Dolce  Concession  40%  Production 
  Candela Povero  Concession  40%  Production 
  Carlo  Concession  49%  Production 
  Cassiano  Concession  50%  Production 
  Castellaro  Concession  50%  Production 
  Cecilia  Concession  49%  Production 
  Clara East  Concession  49%  Production 
  Clara North  Concession  49%  Production 
  Clara Northwest  Concession  49%  Production 
  Clara West  Concession  49%  Production 
  Comiso  Concession  100%  Production 
  Cozza  Concession  85%  Production 
  Daria  Concession  49%  Production 
  Didone  Concession  49%  Production 
  Emma West  Concession  49%  Production 
  Fauzia  Concession  40%  Production 
  Giovanna  Concession  49%  Production 
  Leoni  Concession  50%  Production 
  Monte Urano-San Lorenzo  Concession  40%  Production 
  Naide  Concession  49%  Production 
  Portocannone  Concession  62%  Production 
  Quarto  Concession  33%  Production 
  Ramona  Concession  49%  Production 
  Regina  Concession  25%  Production 
  Salacaro  Concession  50%  Production 
  San Giorgio Mare  Concession  95%  Production 
  San Marco  Concession  100%  Production 
  Santa Maria Mare  Concession  96%  Production 
  Santo Stefano  Concession  95%  Production 
  Sarago Mare  Concession  85%  Production 
  Sinarca  Concession  40%  Production 
  Talamonti  Concession  50%  Production 
  Tresauro  Concession  25%  Production 
UK     
  Garrow  Concession  68%  Production 
  Kilmar  Concession  68%  Production 
  Scott  Concession  10%  Production 
  Telford  Concession  16%  Production 
  Wenlock  Concession  80%  Production 
  Glengorm  Concession  25%  Exploration 
  Isabella  Concession  10%  Exploration 
Montenegro     
  Block 26, 30  Concession  100%  Exploration 
Croatia     
  Irena  PSC  70%  Exploration 
  Izabela  PSC  70%  Production 
Malta     
  Blocks 1, 2 and 3 of Area 3   Concession  100%  Exploration 

Source: EvaluateEnergy® ©2021 EvaluateEnergy Ltd