Energean plc

("Energean" or the "Company")

 

Results for Half Year Ended 30 June 2021

London, 2 September 2021 - Energean plc (LSE: ENOG TASE: אנאג) is pleased to announce its half-year results for the six months ended 30 June 2021 ("1H 2021").

Mathios Rigas, Chief Executive of Energean, commented:

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

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

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

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

 

Highlights - Operational

 

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

o  Production outperformed guidance across all countries of operation

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

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

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

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

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

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

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

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

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

o  Project expected to deliver IRRs in excess of 30%

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

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

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

o  Financing package expected to be finalised in 3Q 2021

 

Highlights - Corporate and ESG

 

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

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

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

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

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

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

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

o  19% reduction versus 2020 levels[5];

o  73% reduction versus 2019; and

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

 

Highlights - Financial

 

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

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

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

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

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

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

o  Providing significant financial flexibility

o  Ensures all planned activities are fully-funded

 

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

 

Outlook

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

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

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

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

o  Acceleration measures being considered for implementation

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

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

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

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

·    Acceleration of the Green Prinos suite of projects

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

·    Future dividend policy to be declared in due course

 

 

Enquiries

 

Kate Sloan, Head of IR, ECM and Communications                                                         Tel: +44 7917 608 645

 

Conference call

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

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

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

 

Energean Operational Review

Production

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

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

 

Israel

Karish Project

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

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

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

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

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

 

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

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

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

 

Growth Projects

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

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

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

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

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

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

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

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

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

 

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

 

Egypt

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

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

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

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

Italy

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

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

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

 

Greece

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

Prinos Area Development and Funding

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

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

"Green Prinos"

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

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

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

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

 

Rest of Portfolio

United Kingdom

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

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

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

Croatia

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

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

 

Energean Corporate Review

ESG

 

Net Zero

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

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

Actions taken to date in 2021 include:

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

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

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

ESG Reporting and Ratings

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

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

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

 

Financing

 

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

 

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

 

 

2021 guidance

 

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

 

 

 

Energean Financial Review

 

Financial results summary

 

	1H 2021	1H 2020	Change
Av. daily working interest production (kboed)	44.0	2.1	1,995%
Sales revenue ($m)	205.5	2.1	9,686%
Realised oil price ($/boe)	47.3	9.1	419%
Cash cost of production[14] ($m)	122.4	10.4	1,077%
Cash cost of production per barrel ($/boe)	15.4	27.5	(44%)
Cash SG&A[15]	17.0	5.4	215%
Adjusted EBITDAX[16] ($m)	74.7	(8.8)	939%
(Loss) after tax ($m)	(35.7)	(77.3)	54%
Cash flow from operating activities ($m)	53.1	(14.5)	466%
Capital expenditure ($m)	230.0	249.0	(8%)

 

	1H 2021	FY 2020	Change
Total borrowings ($m)	2,838.8	1,443.1	97%
Cash and cash equivalents and restricted cash ($m)	1,146.3	202.9	465%
Net debt / (cash) ($m) (including restricted cash)	1,692.6	1,240.1	36%
Net debt / equity (%)	212.3%	103.8%	105%

 

Revenue, production and commodity prices

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

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

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

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

Depreciation, impairments and write-offs

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

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

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

 

Other income and expenses

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

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

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

Finance income / costs

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

Crude oil hedging

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

Taxation

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

Operating cash flow

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

Non-IFRS measures

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

 

Adjusted EBITDAX

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

	1H 2021 $m	1H 2020 $m
Adjusted EBITDAX[17]	74.7	(8.9)
Reconciliation to profit / (loss):
Depreciation and amortisation	(36.3)	(12.8)
Share-based payment charge	(2.3)	(1.2)
Impairment losses	-	(63.0)
Exploration and evaluation expense	(1.0)	(0.5)
Other expenses	(3.1)	(15.8)
Other income	3.6	8.9
Finance income	2.7	4.4
Finance cost	(44.9)	(3.6)
Net foreign exchange gain/(loss)	(13.9)	(6.6)
Taxation income / (expense)	(15.2)	21.8
Profit / (loss) from continuing operations	(35.7)	(77.3)

 

Cash Cost of production

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

	1H 2021 $m	1H 2020 $m
Cost of sales	147.6	17.9
Less:
Depreciation	33.8	11.6
Change in inventory	(8.6)	(4.1)
Cost of production	122.4	10.4
Total production for the period (MMboe)	7.9	0.4
Cost of production per boe ($/boe)	15.4	27.5

 

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

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

 

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

 

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

Capital expenditure

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

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

 

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

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

 

Net cash / debt and gearing ratio

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

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

 

Term Loan

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

Refinancing

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

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

Principal risks and uncertainties

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

Overview of key risks and key changes since 31 December 2020

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

 

Strategic risks

#1 Progress key development projects in Israel

Principal risk: Delay to first gas at Karish.

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

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

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

#2 Market risk in Israel

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

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

#3 Progress key development projects

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

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

#4 Deliver exploration success and reserve addition

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

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

#5 Portfolio integration

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

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

Operational risks

#1 Production performance

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

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

#2 JV misalignment

Principal risk: Misalignment with JV operators.

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

Financial risks

#1 Maintaining liquidity and solvency

Principal risk: Insufficient liquidity and funding capacity.

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

#2 Egypt receivables

Principal risk: Recoverability of revenues and receivables in Egypt.

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

#3 Decommissioning liability

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

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

Climate change risks

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

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

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

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

·      ESG ratings maintained in the top quartile.

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

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

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

#2 Physical risks related to climate change

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

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

External risks

#1 Geopolitical events

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

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

#2 Global pandemic

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

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

Emerging risks

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

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

 

Events since 30 June 2020

Compensation to gas buyers due to late supply:

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

 

Gas buyer request for arbitration:

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

 

Going Concern Statement

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

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

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

Specifically, the Group tested the following sensitivities:

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

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

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

A reasonable worst case including a combination of all above sensitivities

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

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

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

Karish Field Development, Israel:

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

 

Greek RBL:

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

 

Egypt RBL:

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

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

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

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

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

 

Statement of Directors' responsibilities

The Directors confirm that to the best of their knowledge:

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

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

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

 

Mathios Rigas                                                                                       Panos Benos

Chief Executive Officer                                                                       Chief Financial Officer

01 September 2021                                                                            01 September 2021           

 

 

Forward looking statements

This announcement contains statements that are, or are deemed to be, forward-looking statements. In some instances, forward-looking statements can be identified by the use of terms such as "projects", "forecasts", "anticipates", "expects", "believes", "intends", "may", "will" or "should" or, in each case, their negative or other variations or comparable terminology. Forward-looking statements are subject to a number of known and unknown risks and uncertainties that may cause actual results and events to differ materially from those expressed in or implied by such forward-looking statements, including, but not limited to: general economic and business conditions; demand for the Company's products and services; competitive factors in the industries in which the Company operates; exchange rate fluctuations; legislative, fiscal and regulatory developments; political risks; terrorism, acts of war and pandemics; changes in law and legal interpretations; and the impact of technological change. Forward-looking statements speak only as of the date of such statements and, except as required by applicable law, the Company undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise. The information contained in this announcement is subject to change without notice.

 

INDEPENDENT REVIEW REPORT TO ENERGEAN PLC

 

Conclusion

We have been engaged by Energean plc (the Company) to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2021 which comprises the consolidated income statement, the consolidated statement of comprehensive income, the consolidated statement of financial position, the consolidated statement of changes in equity, the consolidated statement of cash flows and  the related explanatory notes 1 to 29. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2021 is not prepared, in all material respects, in accordance with UK adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Basis for Conclusion

We conducted our review in accordance with International Standard on Review Engagements 2410 (UK and Ireland) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board.  A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

As disclosed in note 2, the annual financial statements of the Group will be prepared in accordance with UK adopted IFRSs. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with UK adopted International Accounting Standard 34, "Interim Financial Reporting".

Responsibilities of the directors

The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Auditor's Responsibilities for the review of the financial information

In reviewing the half-yearly report, we are responsible for expressing to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report. Our conclusion is based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report.

Use of our report

This report is made solely to the Company in accordance with guidance contained in International Standard on Review Engagements 2410 (UK and Ireland) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company, for our work, for this report, or for the conclusions we have formed.

 

Ernst & Young LLP

London

1 September 2021

 

Interim Condensed Consolidated Income Statement Six months ended 30 June 2021

 

		30 June (Unaudited)
		2021		2020
		$'000		$'000
	Notes
Revenue	5	205,466		2,070
Cost of Sales	6(a)	(147,640)		(17,934)
Gross profit/(loss)		57,826		(15,864)
Administrative expenses	6(b)	(21,668)		(6,853)
Selling and distribution expenses	6(c)	(102)		(72)
Exploration and evaluation expenses	6(d)	(1,041)		(529)
Impairment of property, plant and equipment	11	-		(63,005)
Other expenses	6(e)	(3,071)		(15,843)
Other income	6(f)	3,571		8,914
Operating profit/(loss)		35,515		(93,252)
Finance Income	7	2,700		4,383
Finance Costs	7	(44,912)		(3,563)
Net foreign exchange loss	7	(13,787)		(6,637)
Loss before tax		(20,484)		(99,069)
Taxation income / (expense)	9	(15,174)		21,801
Loss from continuing operations		(35,658)		(77,268)
Attributable to:
Owners of the parent		(35,550)		(76,826)
Non-controlling Interests		(108)		(442)
		(35,658)		(77,268)
Basic and diluted total loss per share (cents per share)
Basic	10	($0.20)		($0.43)
Diluted	10	($0.20)		($0.43)

 

 

 

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