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Energean Oil & Gas plc

�("Energean" or the "Company")

2019 Full Year Results�

On track to deliver first gas from Karish in 1H 2021;

FPSO Hull Sailaway expected in the coming weeks

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London, 19 March 2020 - Energean Oil and Gas plc (LSE: ENOG, TASE:�????), the oil and gas producer focused on the Mediterranean, is pleased to announce its audited full-year results for the year ended 31 December 2019 ("FY 2019")[1]. Having grown its reserve base at 39% year-on-year, Energean is now at its next transition point as we begin converting this into cash flows and production, de-risking our investment case and moving us closer to our medium-term ambition of paying a sustainable dividend.

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Mathios Rigas, Chief Executive Officer, Energean Oil & Gas commented:

"Energean continued its strong growth trajectory in 2019, becoming firmly established as a leading, FTSE 250 E&P independent.

"The COVID-19 pandemic and OPEC+ price war have put us into uncertain times, but we are well-placed to weather the challenges. Once the Edison E&P transaction is completed, around 70% of our production will be sold under long-term gas sales agreements that insulate our future revenues against oil price volatility. Following completion of the Edison E&P transaction, we will continue to own and operate the majority of our asset base, and are well-funded for all of our projects. This will ensure that we can respond quickly and appropriately to the macro environment and take the right decisions to protect our business and our shareholders, as demonstrated by the $155 million cut to our 2020 capex guidance. The crisis finds Energean well prepared with full discretion on our non-Israeli capex programme and a very strong balance sheet further strengthened only recently by a further $175 million committed funding for our Karish project, demonstrating the strength of our banking relationships and the commitment of our lenders to the project.

"In the coming weeks, you will see our FPSO hull sailaway from China to Singapore, a key milestone in the delivery of first gas from Karish, which is on track for 1H 2021. During 2019 we completed the drilling of the three development wells of Karish, confirmed excellent productivity rates from the wells and made a new discovery (Karish North) in Israel that we intend to develop in 2021. We continued to gain market share in Israel securing additional long-term gas contracts and bringing us closer to our target to maximise capacity utilisation of our FPSO. We expect the Edison E&P transaction to close during 2020, which, based on the agreed locked-box date of 1 January 2019, allows us to benefit from the robust results delivered by the business during 2019[2], including $152 million of Free Cash Flow from the assets to be acquired. This, combined with the receivables recovered in Egypt, exclusion of the Algerian assets from the transaction perimeter and our onward disposal of the North Sea assets to Neptune Energy, contributes to a low effective purchase price.

"Fully committed to lead also on the ESG front, Energean became the first E&P company globally to commit to net zero emissions by 2050, and we have a firm plan to reduce carbon intensity by 70% over the next three years.

"I look forward to continuing to deliver positive momentum and sustainable growth to maximise value for all of our stakeholders"

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Highlights

�� Karish was 72% physically complete at 31 December 2019 and remains on track to deliver first gas in 1H 2021.� Firm gas sales of 5.0 bcm/yr with a further 0.6 bcm/yr to be converted to a firm basis immediately on publication of a satisfactory Karish North CPR, expected at the end of March 2020.

�� Post-period end, two of the three Karish development wells successfully flowed during clean-up operations, confirming that each will be capable of delivering up to the design limit of 300 mmscf/d (c.3 bcm/yr). The third development well is currently in the clean-up phase and production performance is expected to be similar, confirming that the three wells will be able to produce to the 8 bcm/yr capacity of the FPSO.

�� Increased 2P reserves and 2C resources to 558 MMboe, representing a 39% year-on-year increase, before any contribution from the Edison E&P acquisition. Energean is at a transition point in its history, from which it will convert this growth in reserves to growth in production and cash flow.

�� 2019 average Working Interest production was 3.3 kbopd from the Prinos field. Cost of production was approximately $21.5 /bbl.

�� 2019 full year revenue �was $76 million. Adjusted EBITDAX was $36 million. Capital expenditure was $685 million.

�� Recognised a $71 million impairment charge on the Prinos area, reflecting a reduction in Energean's oil price assumptions and a change in the Group's Prinos field production forecast.

�� Energean retains significant liquidity. At 31 December 2019, Energean had cash and undrawn facilities of $834 million, excluding the undrawn $600 million acquisition bridge facility.

�� Became the first E&P company globally to commit to net zero emissions by 2050 and have a firm plan to reduce carbon intensity by 70% over the next three years.

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Financial Summary

�	FY 2019	FY 2018
�	$m	$m
Sales revenue	75.7	90.3
Cost of production ($/boe)	21.5	17.6
Operating profit / (loss)	(93.9)	23.8
Adjusted EBITDAX	35.6	52.4
Operating cash flow	36.3	62.7
Capital expenditure	685.1	494.6
Cash capital expenditure	954.6	293.6
Net debt (cash)	561.6	(75.6)

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Edison E&P Acquisition (subject to closing)

�� In July 2019, Energean agreed to acquire Edison E&P for $750 million of up-front consideration, adding immediate cash flows, EBITDAX and incremental growth opportunities. In October 2019, Energean agreed to sell Edison E&P's UK and Norwegian subsidiaries to Neptune Energy for $250 million of up-front consideration.

�� Raised $265 million of equity and $600 million of bridge financing to fund the acquisition. The take-out of the bridge facility using a Reserve Based Lending ("RBL") Facility of up to $525 million plus a bridge to disposal of up to $250 million for the UK and Norway Assets is progressing as expected.

�� Carve out of the Algerian assets from the transaction perimeter has been agreed in principle at an effective price of $155 million, based on an effective transaction date of 1 January 2019; the carve out remains subject to a signed, amended SPA.

�� Excluding Algeria, UK and Norwegian subsidiaries, Edison E&P delivered Free Cash Flow of $152 million during 2019.

�� Exclusive of Algeria and the UK and Norwegian subsidiaries, 2019 average Edison E&P working interest production was 56 kboe/d (64 kboe/d inclusive of these assets).

�� In January 2020, Edison E&P received the updated Environmental Impact Assessment ("EIA") approval on the Cassiopea development, offshore Italy. The development is progressing as planned with first gas expected in early 2023.

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Outlook

�� Closing of the Edison E&P acquisition and subsequent sale of the UK and Norwegian subsidiaries to Neptune Energy will occur once the remaining conditions precedent to the transaction are fulfilled, which is expected during 2020. Energean is working with Edison E&P to fulfil these conditions precedent as soon as possible.

�� The Energean Power FPSO hull for the Karish gas project is expected to sailaway from China to Singapore in the coming weeks, and from Singapore to Israel around YE 2020.

�� Energean expects to issue an updated CPR for the successfully appraised Karish North discovery, around end 1Q 2020. An updated Field Development Plan ("FDP") will be submitted to the Israeli government in 2Q 2020.

�� 2020 pro forma group production (including the assets to be acquired from Edison E&P) is expected to be between 42.5 - 50.0 kboe/d. Production in the first two months of 2020 averaged 52.4 kboe/d.

�� 2020 pro forma consolidated group capital expenditure (including the assets to be acquired from Edison E&P) of $840 million, an adjustment to the net consideration, the quantum of which is being agreed, on previous guidance following actions taken by management in the last two weeks. $580 million will be spent in Israel and $140 million is fully discretionary.

�� Decisions on FID at Katakolo (Greece) and Drill or Drop on both Ioannina (Greece) and Montenegro; outstanding financial commitment across these licences of $1 million.

�� Strategic review of the Prinos Area assets progressed; results expected in 2020. Capital expenditure on the assets, including Epsilon, will be minimised whilst the review is concluded.

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Operational Review

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Business Resilience and Current Response to the Macro Environment

Energean notes the recent fall in global oil prices and highlights its resilience to fluctuations in the global commodity prices. In addition, Energean has not currently suffered any delays due to the Coronavirus.

Defensive Reserve and Production Mix

�� 70% of Energean's 2P reserve and 2C resource base will be gas once the Edison E&P transaction completes.

�� Once the Edison E&P transaction completes, around 70% of 2020 - 2025 expected production and 60% of Energean's 2P and 2C reserve and resource base is gas that will be sold under Gas Sale & Purchase Agreements ("GSPAs") that are largely insulated from fluctuations in the Brent price:

o� Israel gas is expected to account for 34% of 2020 - 2025 expected production and 49% of the reserve and resource base. Israel gas is sold subject to long-term GSPAs with some of the largest domestic independent power plant and industrial customers. All GSPAs have floor pricing and take-or-pay provisions, with no price no re-openers. One contract that has a limited amount of Brent exposure, representing less than 2% of current contracted gas sales.

o� Egypt gas[3] is expected to account for 37% of 2020 - 2025 expected production and 16% of the reserve and resource base. This gas is being sold to EGPC under the concession agreement. In Abu Qir, at prices of between $40 and $72 Brent, the gas price is $3.50 / mmBTU ($3.71/mcf). At $35/bbl, the gas price is $3.16 / mmBTU ($3.35/mcf). In NEA, the gas price has been agreed at a $4.60/mmBTU ($4.77/mcf). At prices between $40 and $25, the gas price gradually reduces to the floor price of $4.45/mmBTU.

Well-Funded for Current Activities and Working Capital

�� The Group retains significant liquidity and at 31 December 2019, Energean had cash of $354 million and undrawn facilities of $480 million, excluding the undrawn $600 million acquisition bridge facility. At 28 February 2020 (and after reflecting the project finance facility increase effected on 16 March 2020), Energean had undrawn facilities of $620 million, excluding the acquisition bridge facility.

Israel Project Finance Facility

�� In Israel, cash and undrawn facilities were US$555 million. On 16 March 2019, the project finance was increased to $1.45 billion, providing an additional $175 million of liquidity for the Karish project and future appraisal activity in Israel. The project finance facility aids the defensive nature of Energean's funding position and is largely unaffected by volatility in the oil price because:

o� It is non-recourse to the parent;

o� There are no redeterminations for the duration of its tenor;

o� Interest payments and other project costs are covered by the sizing of the facility; and

o� Due to the nature of the GSPAs underpinning the Karish and Tanin projects' revenues, fluctuations in the oil price do not materially affect the cashflow covenants in the facility.

�� Energean's Karish development is being executed largely through a lump-sum, turnkey EPCIC contract with TechnipFMC, which helps to protect the Company against capital expenditure overruns.

�� Liquidated damages payable by the Company resulting from any potential delay to the project are broadly back-to-back with any liquidated damages payable to gas buyers that may arise from late delivery of first gas. This limits Energean's commercial exposure to any future delay.

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Funding position ex-Israel

�� Energean's business excluding Israel had cash and undrawn facilities of $279 million at 31 December 2019.

Flexibility over capital investment programme

�� The Prinos Basin and Katakolo assets are fully-owned and operated, providing absolute flexibility over discretionary capital expenditure.

�� Energean's exploration assets have minimal outstanding firm commitments, again giving Energean flexibility over capital expenditure.

�� Energean's 2020 capital expenditure guidance benefits from strong funding and its discretionary nature:

o� 2020 pro forma consolidated group (including the proposed acquisition of Edison E&P) capital expenditure has been reduced to $840 million, from $995 million. The majority of this decrease is due to i) deferral of Cassiopea[4] expenditure; ii) deferral of Epsilon expenditure; and iii) deferral of the $35 million Zeus exploration well; results from the Karish North CPR are expected to be sufficient to ensure that Energean has enough gas to be able to participate in upcoming GSPA opportunities in Israel. This has allowed Energean to defer investment and conserve capital without impacting potential cash flow-driven returns for its shareholders.

o� $580 million relates to Karish development and is funded by the project finance facility.

o� A further $140 million is fully discretionary for 2020, principally relating to capital expenditure in Egypt and various projects in Italy.

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Israel

Karish-Tanin development project

Energean is on track to deliver first gas from its Karish project in 1H 2021. As of 31 December 2019, physical progress on the project was approximately 72% complete, the drilling of the three Karish Main development wells had been completed and significant progress had been made on the hull and topsides of the Energean Power FPSO. The FPSO Hull is expected to sailaway from China to Singapore in the coming weeks, signalling delivery of a key intermediate milestone towards delivery of first gas in 1H 2021.

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FPSO progress and key milestones

FPSO keel laying took place successfully at the COSCO Yard, Zhoushan, China, in April 2019 and in October 2019 the hull was undocked and floated out from COSCO Shipyard's dry dock.

To date, in 2020, despite Coronavirus, the workforce in the COSCO yard has been maintained above 550 people. The FPSO Hull sailaway is expected in the coming weeks and it is due to arrive in the Admiralty Yard in Singapore shortly thereafter. Good progress has been made on construction of the topsides in Singapore, and Energean is working with TechnipFMC to mitigate the impact of the deferred sailaway from China on Practical Completion of the project and is on schedule to deliver first gas in 1H 2021.

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Gas sales and purchase agreements

During 2019, Energean agreed an additional 0.8 Bcm/yr of new and increased contracted and unconditional ("firm") GSPAs and 0.4 Bcm/yr of contracted and conditional ("contingent") GSPAs with gas buyers. In early 2020, a further contingent GSPA for up to 0.2 Bcm/yr was signed.

Total contracted gas sales are now as follows:

Contracted and Unconditional GSPAs

�� c.5 Bcm/yr (484 mmcfd)

Contracted and Conditional GSPAs

�� IPM Beer Tuvia: 0.4 Bcm/yr (39 mmcfd) of sales post-2024. Energean may supply additional gas pre-2024 at the option of both counterparties. The IPM contract is conditional, inter alia, on Energean certifying additional 2P reserve volumes and will be converted to firm GSPAs immediately on issuance of the Karish North CPR shortly.

�� New Contract: Up to 0.2 Bcm/yr (19 mmfcd) of sales, under which supply ramps up between 2022 and 2025. The new contract is also conditional, inter alia, on Energean certifying additional 2P reserve volumes. Energean expects the contract to be converted into firm upon publication of the Karish North CPR shortly.

�� Or Contract: 0.7 Bcm/yr (68 mmcfd) of sales to Or Power, which depends on Or Power succeeding in its application to receive a new licence from the Electricity Authority to construct a new power generation plant in Israel and successfully completing this project.

In the medium term, Energean aims to secure both the resource and offtake for the remaining spare capacity in its 8 bcma (775mmcfd) capacity FPSO, whilst bearing in mind the need for capital conservation in the current market environment.

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All GSPAs contain take-or-pay and floor pricing provisions, which reduce the risks associated with Energean's cash flow generation profile and limit Energean's exposure to global commodity price fluctuations.

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Energean is also evaluating gas export monetisation options, including the markets of southern Europe. As part of this strategy, the Company signed a Letter of Intent ("LOI") in January 2020 with the Public Gas Corporation of Greece for the potential sale and purchase of 2 Bcm/yr of natural gas from Energean's fields in Israel through the proposed East Med Pipeline. At this stage, there is no commitment to supply this gas and Energean views the LOI as a longer-term option for monetisation of its gas resources.

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2019 Drilling Campaign

During 2019, Energean drilled the KM-01, KM-02, KM-03 development wells and the Karish North exploration well and sidetrack. Completions and installation of the Christmas Trees on those three development wells was the focus of operations during 1Q 2020; clean-up of two wells is complete and one is ongoing, following which the wells will be ready for integration with the subsea infrastructure and hook up to the FPSO.

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The three development wells are expected to deliver 5.0 bcm/yr (484 MMscfd) of firm contracted gas into the Israeli domestic market commencing in 1H 2021. During 2020, successful results were achieved from production measurement performed during clean-up of the KM-02 and KM-01 development wells. Both wells flowed at a maximum rate of 120 million standard cubic feet per day (MMscf/d) of natural gas, limited only by the capacity of the surface equipment. Performance modelling confirms that each well will be capable of delivering at the 300 MMscf/d design capacity when connected to the FPSO. Clean-up of the third development well, KM-03 has commenced and the results of production measurement, which are expected to be similar, will be announced to the market in due course. Energean is confident that the three development wells can produce at combined rates of 800 mmscf/d, which is sufficient to fill the capacity of the FPSO.

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The Karish North field was discovered in April 2019, with appraisal confirming initial best estimate recoverable resources of 0.9 Tcf (25 bcm) of gas plus 34 MMbbl of light oil/condensate. An independent CPR is being prepared and results will be communicated to the market shortly. On publication of this CPR, 0.6 bcm/yr of contingent GSPAs are expected to be immediately converted to firm GSPAs. The company is preparing a field development plan, envisaging a tie-back to the Energean Power FPSO. A final investment decision on that project, which is estimated to cost circa $125 million, is anticipated during 2020, with first gas during 2022.

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Exploration Programme

Energean has decided to defer its exploration activity on Block 12. Results from the Karish North CPR are expected to be sufficient to ensure that Energean has sufficient gas resources �to be able to participate in upcoming GSPA opportunities in Israel. This has allowed Energean to defer investment and conserve capital without impacting potential cash flow-driven returns for its shareholders.

The Zeus and Athena prospects remain very attractive and Energean intends to re-visit its investment decision in due course.

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Acreage

Energean also added to its Israeli acreage in 2019. The Company, as part of a joint venture with Israel Opportunity, was awarded four new licences - 55, 56, 61 and 62 - in Zone D of the Israeli EEZ. The licences are situated approximately 45 kilometres off the coast of Tel Aviv and represent a strong potential source of upside in Energean's Israel portfolio.

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Greece

Production

At the end of 2019, Energean decided to place its Prinos area assets under strategic review, the results of which will be communicated to the market once complete.� Working interest production from Greece averaged 3,312 boepd during 2019, however, investment in Prinos, Prinos North and Epsilon will continue to be limited whilst this strategic review is concluded and 2020 production is, therefore, expected to be in the range of 2,000 to 2,500 boepd, assuming no contribution from Epsilon. Output from Prinos and Prinos North is to be maintained through rig-less activities requiring limited expenditure.

Due to higher-return capital allocation priorities, Energean no longer carries a medium-term production target for the Prinos area asset; future production will be a function of the level of investment in the assets.

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Development - 2019 Overview

During 2019, all three Epsilon Lamda platform development wells were drilled successfully. As previously announced, additional pay was encountered in the deeper and dolomitic zones of the Epsilon reservoir. This resulted in an NSAI-audited reserve and contingent resource increase of 26 MMboe, to 44 mmboe.

At Katakolo, award of the EIA is expected in 2Q 2020 with potential Final Investment Decision thereafter. NSAI-audited Katakolo reserves are 14 MMboe, a 36% increase on 2018.

The proposed underground gas storage project in South Kavala saw a positive development in 4Q 2019 when an amendment to the law was passed on 10 December 2019, making it possible for the regulating energy authority to regulate the tariff. This paves the way for a tender for the project, which is expected in 2020. On 11 March 2020, the Greek Energy and Finance Ministries signed a decision to allow the country's state-asset sales fund to proceed with an international tender to construct, maintain and operate an underground gas storage facility at the South Kavala field, with the first step a cost-benefit study.� The right to exploit the facility will be 50 years.

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Exploration

In Ioannina, interpretation of the newly acquired seismic lines is ongoing and a drill-or-drop decision will be taken in 1H 2020. The quality of acquired seismic was a major improvement when compared to historic vintages and the lines have identified two prospective trends with multiple analogue prospects. Further, the new 2D seismic has verified the existing geological model, de-risking existing prospectivity. The seismic lines were acquired with minimal environmental impact and Energean and the operator, Repsol, have agreed to plant trees in areas away from the 2D seismic lines. The outstanding net financial commitment on the Ioannina block is less than $0.5 million.

In Aitoloakarnania, the operator, Repsol, is carrying out the necessary environmental studies in preparation for the 2D seismic acquisition campaign, which is expected to commence in 2Q 2020, subject to permitting. The outstanding net financial commitment on the Aitoloakarnania is less than $3 million.

In February 2020, Energean signed an agreement for the acquisition of Total's 50% stake in, and operatorship of, Block 2, offshore Western Greece, providing further material exploration opportunities in its core area of the Eastern Mediterranean with limited financial exposure. Energean's net remaining expenditure (at 50% Working Interest and post including consideration) towards satisfaction of the minimum work obligation, which includes 1800 kilometres of 2D seismic acquisition and processing, is approximately �0.5 million. Energean believes that this is a highly attractive transaction in the context of the early stage prospectivity identified on the block.

Work to date on the licence has identified that Block 2 contains part of a large four-way closure at the Top Jurassic Apulia platform. The prospect is believed to be an analogue to the Vega field, offshore Italy, which Edison E&P operates with a 60% Working Interest. The structure is covered by sparse 2D seismic and could be de-risked through the seismic acquisition programme to be executed as part of the minimum work obligation.

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Montenegro

In February 2019, Energean commissioned PGS for the acquisition of a new 3D seismic survey over Blocks 26 and 30. The PGS Ramform Titan, one of the best seismic acquisition vessels in the world, deployed 14 geo-streamers, 6.5 kilometres for each streamer length, using a triple source array to cover a total area of 338 square kilometres. The 3D seismic survey substantially fulfils the licence commitment for both blocks 26 & 30 with a net outstanding financial commitment of less than $0.5 million.

Results from the seismic survey have identified a number of shallow gas prospects and deeper carbonate prospects have been identified through interpretation of the newly acquired seismic data. Energean is awaiting final data in order to confirm the primary prospect. The Ministry of Economy in Montenegro confirmed that Energean will receive an extension to the first exploration phase to 15 March 2021, with a drill-or-drop decision due by year end 2020.

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Energean Reserves and Resources

Energean increased 2P reserves and 2C resources to 558 MMboe, up 39% year-on-year, before any contribution from the Edison E&P acquisition. Energean's reserves and resources benefitted from two discoveries during 2019, the Karish North discovery in Israel, which added 190 mmboe, and the Epsilon Deeper and Dolomitic Zones, which added 25 mmboe.

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�	�	Israel			�	Greece			�	Total
�	�	Oil	Gas	Total	�	Oil	Gas	Total	�	Oil	Gas	Total
Commercial Reserves	�	mmbbls	Bcf	mmboe	�	mmbbls	Bcf	mmboe	�	mmbbls	Bcf	mmboe
1 January 2019	�	22	1,558	298	�	49	5	49	�	71	1,563	347
Revisions	�	7	(99)	(11)	�	8	1	8	�	15	(98)	(3)
Disposals	�	-	-	-	�	-	-	-	�	-	-	-
Transfer from contingent resources	�	-	-	-	�	(2)	-	(2)	�	-	-	-
Production	�	-	-	-	�	(1)	-	(1)	�	(1)	-	(1)
31 December 2019	�	29	1,460	287	�	54	6	55	�	83	1,465	342
�	�	�	�	�	�	�	�	�	�	�	�	�
Contingent Resources	�	�	�	�	�	�	�	�	�	�	�	�
1 January 2019	�	0.7	133	23	�	33	15	35	�	33	148	58
Additions	�	-	-	-	�	-	-	�	�	-	-	-
Revisions and Discoveries	�	23	618	134	�	20	22	24	�	43	640	156
Disposals and relinquishments	�	-	-	-	�	-	-	-	�	-	-	-
Transfer to commercial reserves	�	-	-	-	�	-	-	-	�	-	-	-
31 December 2019	�	24	751	157	�	53	37	59	�	76	788	216
�	�	�	�	�	�	�	�	�	�	�	�	�
Total Commercial Reserves & Contingent Resources	�	�	�	�	�	�	�	�	�	�	�	�
1 January 2019	�	23	1,692	321	�	81	20	84	�	104	1,711	405
31 December 2019	�	53	2,211	444	�	107	43	114	�	159	2,253	558

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Edison E&P acquisition

In July 2019, Energean agreed to acquire Edison E&P for $750 million plus $100 million of contingent consideration. Energean raised $265 million of new equity and $600 million in bridge financing from leading international banks to fund the deal. Energean is in the process of refinancing the acquisition bridge facility using an RBL, which is expected to be sized at up to $525 million, plus a $250 million bridge to disposal for the UK and Norway assets.

Energean is working actively to close the acquisition as soon as possible, with approval from Italian regulatory authorities anticipated soon. Formal approval from Egyptian regulatory authorities is expected soon after shareholder approval at the EGM. As announced on 23 December 2019, the transaction will now exclude the Algerian assets. Carve out of the Algerian assets from the transaction perimeter has been agreed in principle at an effective price of $155 million, based on an effective transaction date of 1 January 2019; the carve out remains subject to a signed, amended SPA.

In October 2019, Energean agreed to sell Edison E&P's UK North Sea and Norway assets to Neptune Energy for $250 million (plus up to $30 million contingent consideration). The deal is aligned with Energean's strategy of optimising its portfolio and the stated goal of disposing of non-core assets. The onward sale is expected to complete as soon as is practicable following the close of the acquisition of Edison E&P.

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Edison E&P financials

During 2019, Edison E&P delivered the following financial results. These results have been prepared on the basis of Edison E&P's accounting policies and are subject to adjustments when included in Energean's upcoming Circular and Prospectus.

Edison E&P financials are presented on a pro forma basis and are unaudited.

�	Edison E&P � 2019 - $ million	Edison E&P exclusive UK North Sea, Norway & Algeria 2019 - $ million
Revenue	531	433
Operating Costs (including G&A)	255	196
EBITDAX	276	237
Operating Cash Flow	252	212
Development and Production Capital Expenditure	136	33
Exploration Expenditure	49	28

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At 31 December 2019, net receivables (after provision for bad and doubtful debts) in Egypt were $222 million, of which $126 million were classified as overdue (31 December 2018: $240 million net receivables, of which $106 million were classified as overdue). A further payment for $55 million was received in January 2020.

Edison E&P production

Average Working Interest production from the Edison E&P portfolio during 2019 was 64.2 kboed. Average 2019 production from the assets to be retained by Energean was 56.4 kboe/d and, for this set of assets, pro forma 2020 production guidance is a range of 42.5 - 50.0 kboe/d. Average Working Interest production in the first two months of 2020 is estimated to have been 52.4 kboe/d.

During 2020, Energean expects Egyptian production to average 32 - 37 kboe/d, Italy to average 8 - 10 kboe/d and Croatia to average 0.5 kboe/d. After an initial reduction during 2020 due to the natural depletion of the fields, production is expected to rise again in the medium term mainly due to new developments; Cassiopea in Italy, Yazzi/NEA/NI in Egypt and, potentially, Irena in Croatia. Production is also expected to be enhanced through the drilling of additional wells at Abu Qir; four locations have been identified for near-to-medium term drilling that, if sanctioned (noting that these wells represent discretionary capital expenditure), would target a combined 30 mmboe of reserves for a total budget of c.$90 million

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Country	2020 Pro Forma Production Guidance -�� kboe/d	2019 Average Working Interest Production - kboe/d[5]
Italy	8 - 10	10.4
Egypt	32 - 37	45.5
Croatia	0.5	0.5
Edison E&P Assets to be Acquired	42.5 - 50.0	56.4
Algeria	�	5.2
UK	�	2.5
Total	�	64.2

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Edison E&P reserves

As at 30 June 2018, the Edison E&P assets to be acquired had 2P reserves of 239 mmboe of working interest 2P reserves according to an independent CPR prepared by DeGolyer and MacNaughton. The reserves report is currently being updated to reflect an effective date of 31 December 2019 and will be published in the Shareholder Circular, to be sent to shareholders in connection with the acquisition. The new CPR is expected to reflect a corresponding decrease in reserves as a result of 18 months of production. Reserve replacement has been limited over the period due to limited investment associated with the disposals process and change of control.

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Edison E&P Development

Italy �- Argo Cassiopea

In December 2019, ENI and Edison E&P received the renewal of the Italian EIA approval on Cassiopea (ENI 60% Op., Edison E&P 40%). The development consists of four subsea wells (two new wells and two re-completed wells) and uses a subsea production system with a 60 kilometre pipeline to shore, where gas compression and treatment will be performed inside the existing Gela refinery. The drilling campaign is expected to be undertaken between 1Q and 3Q 2022 and the subsea installation campaign 2Q to 4Q 2022, with first gas expected in early 2023. The development is expected to add an estimated 60 mmscf/d (10 kboe/d) of net production.

Egypt - NEA/NI

The NEA and NI assets are satellite fields of the Abu Qir gas-condensate asset. Edison E&P has a 100% working interest in both accumulations. The development concept includes four subsea wells, to be drilled in water depths ranging from 30 to 85 metres, and tied back to the North Abu Qir III platform. A final investment decision is expected in mid-2020 with first gas expected 18 months later. The development will target an estimated 52 million barrels of working interest 2P reserves at a total cost of approximately $200 million. �.

The development will add limited operating costs to the Abu Qir complex, resulting in attractive netbacks.

Expected peak production from the NEA / NI development is an incremental 90 mmscf/d plus 1 kbopd of condensate.

Croatia

Edison E&P expects to spud the Irena-2 appraisal well in 2Q 2020. It will target the same gas-bearing horizon that was successful in Irena-1 and, in the event of a success, the well will be suspended for future production.

Edison E&P Exploration

In Egypt, the Ameeq well, which is being drilled on the North Thekah Offshore Block, spudded on 18 January 2020.

In Italy, an additional two firm exploration wells will be drilled into the Gemini and Centauro prospects, which are adjacent to the Cassiopea field, in 2022. These wells will target a combined c.9.7 mmboe of gross prospective resources and each has a Geological Chance of Success of 90%. If successful, the wells would be tied back to the Cassiopea subsea system.

�

2020 Guidance - pro forma for the combined business, includes Edison E&P

The production and financial data below reflects the Edison E&P forecasts for the full year. Edison E&P will be consolidated into Energean's financial statements from the date of transaction completion, which is expected later in 2020. Energean will benefit from net cash flows between the locked-box date of 1 January 2019 and the date of transaction completion through an adjustment to the variable consideration.

�	2020 �	Jan & Feb 2020 Performance	�
Production	�	�	�
�� Egypt (kboe/d)	32 - 37	40.2	�
�� Italy (kboe/d)	8 - 10	9.7	�
�� Greece (kboe/d)	2 - 2.5	2.2	�
�� Croatia (kboe/d)	0.5	0.3	�
Total Pro Forma Production (kboe/d)	42.5 - 50.0	52.4	�
�	�	�	�
Financials	2020	Discretionary Amount	�
Operating Costs & G&A ($ million)	225 - 250	-	-
�	�	�	�
Development and Production Capital Expenditure	�	�	�
-�� Israel ($ million)	580	-	Funded by project finance facility
-�� Egypt ($ million)	100	100	70 million NEA/NI; $20 million Abu Qir facilities; $8 million Abu Qir wells
-�� Italy ($ million)	75	40	All discretionary apart from $25 million investment in Cassiopea and $10 million in Leoni
-�� Greece ($ million)	5	-	100% owned and operated, Epsilon investment deferred
-�� Croatia ($ million)	10	-	Appraisal well committed, capacity to delay exists
Total Pro Forma Development & Production Capital Expenditure ($ million)	770	140	�
�	�	�	�
Exploration Capital Expenditure (Firm)	�	�	�
-�� Israel ($ million)	5	-	�
-�� Egypt ($ million)	60	-	�
-�� Italy ($ million)	-	-	�
-�� Greece ($ million)	5	-	�
-�� Croatia ($ million)	-	-	�
-�� Other ($ million)	-	-	�
Total Pro Forma Exploration Capital Expenditure ($ million)	70	-	�

�

Financial review

Focused on maintaining strong financial discipline

Revenue, production and commodity prices

Working interest crude production from Greece averaged 3,312 bopd, a decrease of 18% for the period (2018: 4,053 bopd). The decrease in production was due to the decision to put the Prinos Area assets under strategic review following the review of capital allocation that was initiated earlier in the year. As a result, investment in Prinos and Prinos North was limited to $14.0 million during the period, while this process was being undertaken.

Prinos crude is sold at a $6.6/bbl. discount to Urals Med blend, adjusted for final cargo API. In 2019 the average sales price achieved was $58/bbl.

Depreciation, impairments and write-offs

�

Depreciation charges before impairment on production and development assets increased by 15% to $39.1 million (2018: $34.3 million) due to increased capital expenditure invested in Greece during 2018, along with finance lease assets' depreciation recorded for the first time in 2019 (IFRS 16 adoption). The Group recognised a gross impairment charge of $71.1 million in 2019 (2018: $nil). In the 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 $71.1 million in the carrying value of the Prinos CGU.�

�

Selling, general and administrative (SG&A) expenses

�

Energean incurred SG&A costs of $13.7 million in 2019. This represents a 13% increase on the previous year (2018: $12.1 million) and is due to the additional staffing and administrative costs associated with the continued growth of the Group's portfolio and the efforts associated with developing the Karish project.

For the full year 2020 Energean expects stand-alone SG&A costs to be $15.0 million. Edison E&P adds an estimated additional $30 million on a pro forma basis.

Other expenses

Other expenses of $21.6 million (2018: $1.1 million) consist predominantly of the direct costs incurred in 2019 relating to the proposed acquisition of Edison's E&P business.

Finance costs

Financing costs before capitalisation for the period were $48.9 million (2018: $22.7 million). Included within this balance is $34.4 million of interest (2018: $12.2 million), of which $7.0 million relates to interest incurred on the RBL facility and $27.4 million on the Karish project finance facility. In addition, there was $7.2 million (2018: $5.7 million) of interest expenses relating to long term payables representing future payments to the previous Karish/Tanin licence holders. This was offset by capitalised borrowing costs of $39.9 million (2018: $9.3 million). The remainder of the total finance costs expensed relate primarily to finance and arrangement fees and other finance costs and bank charges. Total finance cost expensed amounted to $9.0 million (2018: $13.5 million).

Crude oil hedging

Energean had no hedges during the period and has no outstanding crude oil hedges at year-end. Energean will keep its hedging position under review.

Taxation��

Energean recorded tax income of $20.5 million in 2019 (2018: $15.5 million tax income) primarily associated with the deferred tax impact of the impairment losses associated with the Prinos assets.

Operating cash flow

Cash from operations before movements in working capital was $18.5 million (2018: $53.9 million). After adjusting for working capital movements, cash from operations was $36.3 million, a 42.1% decrease on the comparable period (2018: $62.7 million). The decrease is driven by reduced production and revenue in the period and due to $8.1 million of direct transaction costs for the proposed acquisition of Edison E&P in 2019, which have been recorded under operating activities.

Financial results summary

Metric	2019	2018
Av. Daily working interest production (kboed)	3.3	4.1
Sales revenue ($M)	75.7	90.3
Realised oil price ($/boe)	57.6	61.3
Cost of oil production ($m)	25.9	26.0
Cost of production per barrel ($/boe)	21.5	17.6
Administrative & selling expenses ($m)	13.7	12.1
Adjusted EBITDAX ($m)	35.6	52.4
Cash flow from operating activities ($m)	36.3	62.7
Capital expenditure ($m)	685.1	494.6
Cash capital expenditure ($m)	954.6	293.6
Net debt (cash) ($m)	561.6	(75.6)
Net debt/equity (%)	44.5%	(6.95)%

�

Non-IFRS measures

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

Cost of oil production

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

�

�	2019	�	2018
�	$M	�	$M
Cost of sales	65.6	�	58.8
Less	�	�	�
�� Depreciation	(36.6)	�	(33.9)
�� Change in inventory	(2.9)	�	1.1
Cost of oil production	25.9	�	26.0
Total production for the period (boe)	1,208,978	�	1,479,367
Cost of oil production per boe ($)	21.5	�	17.6

�

Prinos production fell by 18% in 2019. This has resulted in a 22% increase in per barrel production costs, from $17.6/bbl. in 2018 to $21.5/bbl.

Adjusted EBITDAX

�

Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, other income and expenses (including the impact of derivative financial instruments and foreign exchange), net finance costs and exploration costs. The Group presents adjusted EBITDAX as it is used in assessing the Group's growth and operational efficiencies, because it illustrates the underlying performance of the Group's business by excluding items not considered by management to reflect the underlying operations of the Group.

�

�	2019	2018
Metric	$M	$M
Adjusted EBITDAX	35.6	52.4
Reconciliation to profit/(loss):	�	�
Depreciation and amortisation	(39.1)	(34.3)
Exploration and evaluation expense	(0.8)	(2.1)
Impairment loss on property, plant and equipment	(71.1)	-
Other expenses	(21.6)	(1.1)
Other income	3.1	8.9
Finance expenses	(9.0)	(13.5)
Finance income	2.5	1.7
Gain on derivative	-	96.7
Net foreign exchange	(3.9)	(23.5)
Taxation income/(expense)	20.5	15.5
(Loss)/income for the year	(83.8)	100.8

�

Capital expenditure

Capital expenditure is a useful indicator of the Group's organic expenditure on oil and gas assets and exploration and appraisal assets incurred during a period. Capital expenditure is defined as additions to property, plant and equipment and intangible exploration and evaluation assets excluding decommissioning, capitalised depreciation, less capitalised borrowing cost.

�	2019	2018
Metric	$M	$M
Additions to property, plant and equipment	670.6	502.0
Additions to intangible exploration and evaluation assets	61.7	6.2
Less	�	�
Capitalised borrowing costs	(39.9)	(9.3)
Capitalised depreciation	(1.9)	(2.6)
Change in decommissioning provision	(5.4)	(1.8)
Total	685.1	494.6

�

Capital expenditure was $685.1 million, of which $611.9 million was invested in Israel, $68.4 million in Greece (Epsilon - $45.2 million) and $4.9 million in Montenegro.

Cash capital expenditure in 2019 was $954.5 million (FY 2018: $293.6 million).

�	2019	2018
Cash Capital Expenditure	$M	$M
Payment for purchase of property, plant and equipment	897.2	290.1
Payment for purchase of intangible assets	57.4	3.5
Total	954.5	293.6

�

Net cash/debt and gearing ratio

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

Net debt reconciliation��

�	�	2019	�	2018
�	�	$M	�	$M
Net Debt	�	�	�	�
Current borrowings	�	38.1	�	-
Non-current borrowings	�	877.9	�	144.3
Total borrowings�	�	916.0	�	144.3
Less: Cash and cash equivalents and bank deposits		(354.4)	(219.9)
Net (Funds)/Debt (1)	�	561.6	�	(75.6)
Total equity� (2)	�	1,260.8	�	1,087.8
Gearing Ratio (1)/(2):	�	44.54%	�	(6.95%)

�

In July 2019, Energean raised $265.1 million through the issuance of new ordinary shares on LSE and TASE. Net of cash transaction costs of $8.2 million this contributed $256.9 million of cash to the Group in 2019�.

Edison E&P acquisition

In July 2019, Energean agreed to acquire Edison Exploration & Production S.p.A. from Edison S.p.A. for $750 million, to be adjusted for working capital, with additional contingent consideration of $100 million payable following first gas from the Cassiopea development (expected early 2023), offshore Italy.

Energean also agreed to sell the UK and Norwegian subsidiaries of Edison E&P to Neptune Energy for $250 million, to be adjusted for working capital, with additional contingent consideration of up to $30 million. The sale is contingent on Energean completing upon its acquisition of Edison E&P and is expected to close as soon as is reasonably practicable after close of the Edison E&P transaction.

On 23 December 2019, Energean announced that Edison S.p.A. had received a letter from the Algerian authorities, which invited Edison to discuss the transaction with Sonatrach. Energean and Edison E&P subsequently agreed to exclude the asset from the transaction perimeter. �Carve out of the Algerian assets from the transaction perimeter has now been agreed in principle at an effective price of $155 million, based on an effective transaction date of 1 January 2019; the carve out remains subject to a signed, amended SPA.

Financing of the acquisition

The initial consideration was supported by a $600 million committed bridge loan facility underwritten by ING and Morgan Stanley, and S$265 million of equity financing. The total debt and equity capital raised was sized to cover both the initial consideration and working capital requirements of the enlarged group.

The bridge loan facility is expected to be replaced in 2020 using a reserve based facility and a bridge facility for the onward sale of the UK and Norwegian assets to Neptune Energy. The $100 million of contingent consideration is expected to be funded by the combined free cash flow of the Enlarged Group as well as any incremental reserve based facility capacity.

Placing

In July 2019, Energean also launched a placing with institutional investors of new ordinary shares of 1 pence each in the capital of Energean to raise up to �211 million (approximately $265 million) before expenses.

Proposed Edison E&P acquisition - 2019 financial results

�	Edison E&P	Edison E&P exclusive of the UK, Norway and Algeria assets[6]
�	2019 - $m	2019 - $m
Revenue	531	433
Operating costs	255	196
EBITDAX	276	237
Operating cash flow	252	212
Development and production capital expenditure	136	33
Exploration expenditure	49	28

�

Liquidity risk management and going concern

The Group carefully manages its risk to a shortage of funds by monitoring its funding position and its liquidity risk. Cash forecast are regularly produced and sensitivities run for different scenarios including change in Brent prices, different production rates and future capital expenditure investment profile.

Short-term cash forecasts have been stress-tested in light of the significant oil price reduction seen in early March 2020, with a primary scenario using an average price of $35.0/bbl for 2020 and $42.5/bbl for 2021, and a downside sensitivity run at $30/bbl average for both 2020 and 2021.

In this scenario, the Group would also target a further rationalisation of its cost base, including cuts to discretionary capital expenditure and operating cost. As at 31 December 2019, the Group had cash and undrawn facilities of $834.2 million million. Post-period end, Energean has also successfully increased its Israel Project Finance Facility by $175million to $1.45 billion (from $1.275 billion), providing additional headroom on its Karish development.

The Group's revised forecasts show that the Group will be able to operate within its current debt facilities and has sufficient financial headroom for the 12 months from the date of approval of the 2019 Annual Report and Accounts. In arriving at this conclusion, the Directors also had regard to the Group's ability to raise necessary funding as and when needed. In 2019, the Group successfully raised gross proceeds of $265.1 million through a private placement on the London and Tel Aviv Stock Exchanges. The Group also raised a $600 million bridge facility to provide funds for its acquisition of Edison E&P. The Group expects to replace this with a Reserve Based Lending ("RBL") Facility (of up to $525m, of which between $400 and $450million is expected to be available) plus a Bridge to Disposal Facility (of up to $250million) for the sale of the UK and Norway assets to Neptune Energy. The purpose of the RBL will be to fund the acquisition, refinance the Greek RBL and provide headroom over the medium term for capital expenditure within the Group (excluding Israel).� �

Based on an assessment of the Group's cash flow forecasts under various scenarios, including the identification of associated risks and mitigants, the Directors have concluded that they have a reasonable expectation that the Group will continue in operational existence for a 12 month period from the date of approval of the 2019 Annual Report and Accounts and have therefore adopted the going concern basis in preparing the Group and parent company financial statements.

Coronavirus

Energean continues to monitor the ongoing COVID-19 outbreak, accessing the advice by the World Health Organisation and Public Health England to ensure that best-practice precautions are being applied. Clear information and health precautions on how employees should protect themselves and reduce exposure to, and transmission of, a range of illnesses along with general advice has been communicated across the organization.

Coronavirus has not yet affected Energean's operations, but in the event that the COVID-19 outbreak escalates, Energean has contingency plans in place that will be followed.

�

Events since 31 December 2019

Energean is exposed to macro-economic risks, including pandemic diseases that could have a material adverse effect on its operations. We continue to monitor the recent Coronavirus outbreak, which is causing global economic disruption and may impact our performance in 2020. To date, the Coronavirus has not had a material impact on Energean's activities. However, at present, it is not possible to predict whether the outbreak will have a material adverse effect on our future earnings, cash flows and financial condition.

On 6 March 2020, OPEC and non-OPEC allies (OPEC+) met to discuss the need to cut oil supply to balance oil markets in the wake of the Coronavirus outbreak, which has had a material adverse impact on oil demand. OPEC+ failed to reach agreement and on 7 March 2020, Saudi Aramco cut its Official Selling Prices, prioritizing market share over pricing. As a result, oil prices have fallen materially, which may have a material adverse impact on the component of Energean's future earnings that are linked to oil prices.

In January 2020, Energean reduced the size of it EBRD Reserve Based Lending Facility to $161 million.

On 16 March 2020, Energean Israel signed a $175 million increase in its project finance facility, which is now sized at $1,450 million, increasing liquidity available to the company.

�

Group Income Statement

�

YEAR ENDED 31 DECEMBER 2019��

�

2019

�

2018

�

Notes

$'000

�

$'000

�

Revenue

75,749

�

90,329

�

Cost of sales

(65,552)

�

(60,019)

�

Gross profit

�

10,197

�

30,310

�

Administrative expenses

(13,305)

�

(11,666)

�

Selling and distribution expenses

�

(345)

�

(453)

�

Exploration and evaluation expenses

�

(801)

�

(2,102)

�

Impairment of property, plant and equipment

(71,115)

�

Other expenses

(21,584)

�

(1,118)

�

Other income

3,095

�

8,869

�

Operating (loss)/profit

�

(93,858)

�

23,840

�

Finance income

2,496

�

1,735

�

Finance costs

(9,002)

�

(13,471)

�

Gain on derivative

�

96,709

�

Net foreign exchange losses

(3,933)

�

(23,521)

�

(Loss)/profit before tax

�

(104,297)

�

85,292

�

Taxation income

20,531

�

15,527

�

(Loss)/profit for the year

�

(83,766)

�

100,819

�

Attributable to:

�

Owners of the parent

�

(83,313)

�

105,279

�

Non-controlling interests

�

(453)

�

(4,460)

�

(83,766)

�

100,819

�

Basic and diluted total (loss)/earnings per share (cents per share)	2	�	�	�	�
Basic	�	($0.50)	�	�	$0.80
Diluted	�	($0.50)	�	�	$0.79

�

Group Statement of Comprehensive Income

�

YEAR ENDED 31 DECEMBER 2019

�

�	�		2019	�	�	2018
�	�		$'000	�	�	$'000
Consolidated statement of comprehensive income		�	�	�	�	�
�	�		�	�	�	�
(Loss)/profit for the year	�		(83,766)	�	�	100,819
�	�		�	�	�	�
Other comprehensive loss:	�		�	�	�	�
Items that may be reclassified subsequently to profit or loss	�		�	�	�	�
Cash Flow Hedge, net of tax	�		434	�	�	-
Exchange difference on the translation of foreign operations	�		(3,751)	�	�	(4,288)
�	�		(3,317)	�	�	(4,288)
�	�		�	�	�	�
Items that will not be reclassified subsequently to profit or loss	�		�	�	�	�
Remeasurement of defined benefit pension plan	�		(466)	�	�	(444)
Income taxes on items that will not be reclassified to profit or loss	�		117	�	�	107
�	�		(349)	�	�	(337)
Other comprehensive loss after tax	�		(3,666)	�	�	(4,625)
�	�		�	�	�	�
Total comprehensive (loss)/income for the year	�		(87,432)	�	�	96,194
�	�		�	�	�	�
Total comprehensive (loss)/income attributable to:	�		�	�	�	�
Owners of the parent	�		(87,109)	�	�	100,856
Non-controlling interests	�		(323)	�	�	(4,662)
�	�		(87,432)	�	�	96,194
�	�	�	�	�	�	�

�

Group Statement of Changes in Equity YEAR ENDED 31 DECEMBER 2019	�
�	Share capital	Share premium¹	Other reserve²�	Share based payment reserve³	Translation reserve⁴ �	Retained earnings	Merger reserves	Total	Non-controlling interests	Total
�	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000
At 1 January 2018	917	-	73,750	-	(11,427)	(138,455)	139,903	64,688	224,294	288,982
Retrospective application of IFRS 9	-	-	-	-	-	(4,337)	-	(4,337)	�	(4,337)
At 1 January 2018 (restated)	917	-	73,750	-	(11,427)	(142,792)	139,903	60,351	224,294	284,645
Profit for the period	-	-	-	-	-	105,279	-	105,279	(4,460)	100,819
Remeasurement of defined benefit pension plan	-	-	(337)	-	-	-	-	(337)	-	(337)
Exchange difference on the translation of foreign operations	-	-	-	-	(4,086)	-	-	(4,086)	(202)	(4,288)
Total comprehensive income	-	-	(337)	-	(4,086)	105,279	-	100,856	(4,662)	96,194
Transactions with owners of the company	�	-	-	-	�	�	�	-	�	-
IPO shares (note 13)	1,009	458,991	-	-	-	-	-	460,000	-	460,000
Issuance of shares for share-based payment transactions	7	-	�	3,110	-	-	-	3,117	-	3,117
Transaction cost in relation to IPO and new share issue (note 13)	-	(24,057)	-	-	-	-	-	(24,057)	-	(24,057)
Employee share schemes	4	-	�	3,507	-	-	-	3,511	-	3,511
Derecognition of derivative asset	-	-	(67,506)	-	-	67,506	-	-	-	-
Share capital increase in subsidiary	-	-	-	-	-	-	-	-	59,613	59,613
Shares issued in settlement of preference shares in subsidiary	129	223,871	-	-	-	-	-	224,000	(224,000)	-
NCI on acquisition of subsidiary (note 5)	-	-	-	-	-	-	-	-	204,800	204,800
At 31 December 2018	2,066	658,805	5,907	6,617	(15,513)	29,993	139,903	827,778	260,045	1,087,823
�	�	�	�	�	�	�	�	�	�	�
�	�	�	�	�	�	�	�	�	�	�	�	�	�

�	�	2019	�	2018
Operating activities	�	�	�	�
(Loss)/profit before taxation	�	(104,297)	�	85,292
Adjustments to reconcile (loss)/profit before taxation to net cash provided by operating activities:	�	�	�	�
Depreciation, depletion and amortisation	10, 11 �	39,054	�	34,258
Impairment loss on property, plant and equipment	10	71,115	�	�
Impairment loss on inventory	�	-	�	992
Gain from disposal on property, plant and equipment	�	-	�	(6)
Increase/(decrease) in provisions	�	730	�	(6,757)
Finance income	8	(2,496)	�	(1,735)
Finance costs��	8	9,002	�	13,471
Fair value gain on derivative	�	-	�	(96,709)
Other bank liabilities written back	�	(1,270)	�	-
Share-based payment charge	�	2,751	�	1,570
Net foreign exchange loss	8	3,933	�	23,521
Cash flow from operations before working capital adjustments	�	18,522	�	53,897
Decrease/(increase) in inventories	�	2,929	�	(1,807)
Decrease/(increase) in trade and other receivables	�	(2,423)	�	10,741
(Decrease)/increase in trade and other payables	�	18,167	�	(3,562)
Cash flow from operations	�	37,195	�	59,269
Tax paid	�	(910)	�	(251)
Receipts in relation to provisions	�	-	�	3,666
Net cash inflow from operating activities	�	36,285	�	62,684
Investing activities	�	�	�	�
Payment for purchase of property, plant and equipment	�	(897,153)	�	(290,123)
Payment for exploration and evaluation, and other intangible assets	�	(57,397)	�	(3,449)
Acquisition of a subsidiary, net of cash acquired	�	-	�	(32,746)
Proceeds� from disposal of property, plant and equipment	�	-	�	63
Interest received	�	2,431	�	1,591
Net cash used in investing activities	�	(952,119)	�	(324,664)
Financing activities	�	�	�	�
Proceeds from issue of share capital	13	265,082	�	460,000
Drawdown of borrowings	14	848,658	�	55,626
Proceeds from capital increases by non-controlling interests	�	-	�	67,613
Transaction costs in relation to IPO and new share issue	�	(8,202)	�	(20,057)
Advance payment from future sale of property, plant and equipment (INGL)	�	5,090	�	-
Repayment of obligations under leases	�	(1,024)	�	-
Debt arrangement fees paid	�	(8,557)	�	(8,237)
Debt arrangement fees for Karish-Tanin facility	16	-	�	(61,496)
Finance cost paid for deferred license payments	�	(4,492)	�	-
Finance costs paid	�	(45,142)	�	(10,919)
Net cash inflow from financing activities	�	1,051,413	�	482,530
Net increase / (decrease) in cash and cash equivalents	�	135,579	�	220,550
Cash and cash equivalents:	� � � �	�	�	�
At beginning of the period	�	219,822	�	15,692
Effect of exchange rate fluctuations on cash held	�	(982)	�	(16,420)
At end of the period	�	354,419	�	219,822

1 Basis of preparation

Whilst the financial information in this preliminary announcement has been prepared in accordance with International Financial Reporting Standards (IFRS) and International Financial Reporting Interpretation Committee (IFRIC) interpretations adopted for use by the European Union, with those parts of the Companies Act 2006 applicable to companies reporting under IFRS and with the requirements of the United Kingdom Listing Authority (UKLA) Listing Rules, this announcement does not contain sufficient information to comply with IFRS. The Group will publish full financial statements that comply with IFRS in April 2020. The financial information for the year ended 31 December 2019 does not constitute statutory accounts as defined in sections 435 (1) and (2) of the Companies Act 2006. The consolidated and parent company financial statements for the year ended 31 December 2018 have been delivered to the Registrar of Companies; the auditor's report on these accounts was unqualified, did not include a reference to any matters by way of emphasis and did not contain a statement under Section 498 (2) or Section 498 (3) of the UK Companies Act 2006.

Except as set out below the Group's accounting policies are consistent with those applied for the year ended 31 December 2018 as set out in the 2018 Annual Report and Accounts.

�

New accounting standards

There have been a number of other amendments to accounting standards and new interpretations issued by the International Accounting Standards Board which were applicable from 1 January 2019, however these have not had a material impact on the accounting policies, methods of computation or presentation applied by the Group, except for IFRS 16 Leases.

IFRS 16 Leases

The standard sets out the principles for the recognition, measurement, presentation and disclosure of leases and requires lessees to recognise most leases on the balance sheet. Lessor accounting under IFRS 16 is substantially unchanged from IAS 17. Lessors will continue to classify leases as either operating or finance leases using similar principles as in IAS 17. Therefore, IFRS 16 does not have an impact for leases where the Group is the lessor.�

The Group adopted IFRS 16 using the modified retrospective method of adoption with the date of initial application of 1 January 2019. Under this method, the standard is applied retrospectively with the cumulative effect of initially applying the standard recognised at the date of initial application.

On adoption of IFRS 16, the Group has recognized lease liabilities in relation to leases which were previously classified as 'operating leases' under the principles of IAS 17 Leases. The Group applied a single recognition and measurement approach for all leases except for short-term leases and leases of low-value assets. The standard provides specific transition requirements and practical expedients, which have been applied by the Group.

The adoption of IFRS 16 in the year resulted in $9.8 million being recorded on the balance sheet as property, plant and equipment right-of-use assets and as lease liabilities. During the current year the effect on income statement was recognised through depreciation charge on the right-of-use asset, interest expense on the lease liability and deferred tax expenses. In the statement of cash flows, the Group separated the total amount of cash paid into principal (presented within financing activities) and interest (presented within operating activities) in accordance with IFRS 16. In prior periods operating lease payments were all presented as operating cash flows under IAS 17

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2019 reporting periods and have not been early adopted by the Group. These standards are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions.

Further details on new International Financial Reporting Standards adopted will be disclosed in the 2019 Annual Report and Accounts.

�

2. Earnings/(loss) per share

Basic earnings/(loss) per ordinary share amounts are calculated by dividing net profit/(loss) for the year attributable to ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year.

Diluted earnings/(loss) per ordinary share amounts are calculated by dividing net profit/(loss) for the year attributable to ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of dilutive ordinary shares that would be issued if employee and other share options or the convertible bonds were converted into ordinary shares.

�

3. Publication of financial statements

It is anticipated that the full Annual Report and Financial Statements will be published in April 2020. Copies will be

available from this date at the Company's head office, Accurist House 44 Baker Street , London W1U 7AL, and on the Company's website (www.energean.com).

�

4. 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: Greece (including the Prinos and Epsilon production asset, Katakolo non-producing assets and Ioannina and Aitoloakarnania exploration assets ), Israel, Montenegro (including two non producing exploration assets) and New Ventures.

The Group's reportable segments under IFRS 8 Operating Segments are Greece and Israel. Segments that do not exceed the quantitative thresholds for reporting information about operating segments have been included in Other.

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:

�	Greece	Israel	Other & intercompany transactions	Total
�	$'000	$'000�	$'000	$'000
Year ended 31 December 2019	�	�	�	�
Revenue¹	79,334	-	(3,585)	75,749
Adjusted EBITDAX²	44,064	(2,932)	(5,531)	35,601
Reconciliation to profit before tax:	�	�	�	�
Depreciation and amortisation expenses	(38,777)	(38)	(239)	(39,054)
Exploration and evaluation expenses	(16)	(55)	(730)	(801)
Impairment loss on property, plant and equipment	(71,115)	-	-	(71,115)
Other expense	(4,418)	(89)	(17,077)	(21,584)
Other income	2,610	37	448	3,095
Finance income	595	1,293	608	2,496
Finance costs	(8,265)	(1,138)	401	(9,002)
Net foreign exchange gain/(loss)	(4,504)	932	(361)	(3,933)
Profit/(loss) before income tax	(79,826)	(1,990)	(22,481)	(104,297)
Taxation income / (expense)	20,283	375	(127)	20,531
Profit/(loss) from continuing operations	(59,543)	(1,615)	(22,608)	(83,766)
Year ended 31 December 2018	�	�	�	�
Revenue¹	90,457	-	(128)	90,329
Adjusted EBITDAX	58,242	(4,724)	(1,069)	52,449
Reconciliation to profit before tax:	�	-	�	�
Depreciation and amortisation expenses	(34,237)	(17)	(4)	(34,258)
Exploration and evaluation expenses	(41)	-	(2,061)	(2,102)
Other income/(expense)	7,835	-	(84)	7,751
Finance income	694	841	200	1,735
Finance costs	(21,026)	(217)	7,772	(13,471)
Gain on derivative	-	�	96,709	96,709
Net foreign exchange gain/(loss)	(10,126)	(15,096)	1,701	(23,521)
Profit before income tax	1,341	(19,213)	103,164	85,292
Taxation income / (expense)	11,660	4,381	(514)	15,527
Profit from continuing operations	13,001	(14,832)	102,650	100,819

¹ The Group supplies 100% of the produced Prinos crude oil to BP Oil International Ltd, until the later of: a) the expiry of the agreement on 1 November 2025 or b) the delivery of twenty-five million barrels

²^�Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, other income and expenses (including the impact of derivative financial instruments and foreign exchange), net finance costs and exploration costs.

�	Greece	Israel	Other & intercompany transactions	Total
�	$'000	$'000	$'000	$'000
Year ended 31 December 2019	�	�	�	�
Oil & Gas properties	302,327	1,582,202	(878)	1,883,651
Other fixed assets	16,253	558	1,809	18,620
Intangible assets	16,059	125,501	6,116	147,676
Other assets	77,529	145,524	235,169	458,222
Total assets	412,168	1,853,785	242,216	2,508,169
Borrowings	159,768	756,216	-	915,984
Other liabilities	85,705	235,345	10,383	331,433
Total liabilities	245,473	991,561	10,383	1,247,417
Other segment information	�	�	�	�
Capital Expenditure:	�	�	�	�
-� Property, plant and equipment	59,481	565,413	(748)	624,146
-� Intangible, exploration and evaluation assets	8,941	47,085	4,937	60,963
Year ended 31 December 2018	�	�	�	�
Oil & Gas properties	332,783	979,870	(320)	1,312,333
Other fixed assets	28,653	156	563	29,372
Intangible assets	6,632	78,449	1,274	86,355
Other assets	68,426	275,375	6,192	349,993
Total assets	436,494	1,333,850	7,709	1,778,053
Borrowings	144,270	-	-	144,270
Other liabilities	77,085	470,550	(1,675)	545,960
Total liabilities	221,355	470,550	(1,675)	690,230
Other segment information	�	�	�	�
Capital Expenditure:	�	�	�	�
-� Property, plant and equipment	94,734	394,462	190	489,386
-� Intangible, exploration and evaluation assets	2,431	2,033	1,721	6,185

�

Segment cash flows

�	Greece	Israel	Other & intercompany transactions	Total
�	$'000	�$'000	$'000	$'000
Year ended 31 December 2019	�	�	�	�
Net cash from / (used in) operating activities	47,641	(2,314)	(9,042)	36,285
Net cash (used in) investing activities	(71,932)	(875,223)	(4,964)	(952,119)
Net cash from financing activities	18,805	791,254	241,355	1,051,414
Net increase/(decrease) in cash and cash equivalents	(5,488)	(86,283)	227,350	135,579
Cash and cash equivalents at end of the period	6,084	110,488	237,847	354,419
Year ended 31 December 2018	�	�	�	�
Net cash from / (used in) operating activities	71,163	(1,236)	(7,243)	62,684
Net cash (used in) investing activities	(118,121)	(182,900)	(23,643)	(324,664)
Net cash from financing activities	44,515	393,559	44,456	482,530
Net increase/(decrease) in cash and cash equivalents	(2,443)	209,423	13,570	220,550
Cash and cash equivalents at end of the period	11,799	194,456	13,567	219,822

�

5. Prior year business combination

At 31 December 2017, the Group held a commitment to acquire 50% of the preference shares in Energean Israel Limited. The recognition of this commitment, which represented a derivative financial instrument, was based on management's estimate of the likelihood of the triggering events occurring the estimated valuation of the Israel entity and the $10 million exercise price. The value of the Israel entity was estimated based on the price negotiated at a similar time with Kerogen as a transaction between market participants which drove the subscription price of $266.7 million for the Energean Israel share issuance. This sum includes the amount payable in respect of Energean's carry of 20% of Energean Israel for $80 million, together with its 70% proportionate share of funding in respect of such carry. Since completion of this subscription, the Group holds 70% of the shares in Energean Israel, with Kerogen holding the remaining 30%.

On 29 March 2018, the Group, following a final investment decision in respect of the Karish and Tanin assets, subscribed for additional shares in Energean Israel for an aggregate consideration of $266.7 million, payable in cash. Prior to this subscription, Kerogen Capital Limited ("Kerogen") held 50% of the equity voting shares in Energean Israel and Kerogen did not participate in the new share issuance. Since completion of this subscription, the Group holds 70% of the voting shares in Energean Israel, with Kerogen holding the remaining 30%.

From 29 March 2018, Energean Israel has therefore been consolidated into the Group and represents a business combination for which acquisition accounting is required in line with IFRS 3: Business Combinations.

The identifiable assets acquired and liabilities assumed of the acquiree are recognised as of the acquisition date and measured at fair value as at that date. Any non-controlling interest in the acquiree is also recognised at fair value at the acquisition date. The fair value of the business acquired is represented by the Karish and Tanin oil and gas assets, cash and working capital, offset by certain liabilities including the deferred consideration obligation for the oil & gas licences. The fair value allocation, as mentioned above, has been determined by management using the agreement with Kerogen in December 2017 as a transaction between market participants which drove the subscription price of $266.7 million for the Energean Israel share issuance. This resulted in an aggregate fair value of $682.7 million being allocated to the identifiable assets and liabilities acquired, prior to the recognition of a deferred tax liability of $79.0 million as further described below.

The 2018 consolidated financial statements include the results of Energean Israel for the period 29 March to 31 December 2018. Since the acquisition date Energean Israel's loss included in the consolidated statement of comprehensive income for the reporting period amounted to $14.8 million. If the combination had taken place at the beginning of the year, the Group's profit from continuing operations for the period would have been $99.9 million. Following the August 2018 independent Competent Persons Report (CPR), the Group's 70% stake in Energean Israel represents 298 mmboe of 2P reserves and 24 mmboe of 2C resources.

Goodwill of $75.8 million has been recognised upon acquisition. An amount of $79.0 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. Nevertheless, in accordance with IAS 12 Sections 15 and 19, a provision is made for deferred tax corresponding to the tax rate of Israel (23%) multiplied by the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is goodwill. 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.

�

6. Revenue

�	2019	�	2018
�	$'000	�	$'000
Crude oil sales	74,940	�	88,587
Petroleum products sales	809	�	1,659
Rendering of services	-	�	1,398
Loss on forward transactions	-	�	(1,315)
Total revenue	75,749	�	90,329

�

7. Operating (loss)/profit before taxation

�	�	�	2019	�	2018
�	�	�	$'000	�	$'000
(a)	Cost of oil sales	�	�	�	�
�	Staff costs	�	12,643	�	12,825
�	Energy cost	�	7,157	�	5,859
�	Royalty payable	�	553	�	1,024
�	Other operating costs	�	5,590	�	6,257
�	Depreciation and amortisation (note 10)	�	36,645	�	33,904
�	Stock overlift/underlift movement	�	2,964	�	(1,073)
�	Total cost of oil sales	�	65,552	�	58,796
�	�	�	�	�	�
�	Cost of services	�	-	�	1,223
�	Total cost of sales	�	65,552	�	60,019
�	�	�	�	�	�
(b)	General & administration expenses	�	�	�	�
�	Staff costs	�	7,497	�	6,766
�	Depreciation and amortization (note 10, 11)	�	804	�	354
�	Auditor fees	�	1,445	�	804
�	Other general & administration expenses	�	3,559	�	3,742
�	�	�	13,305	�	11,666
�	�	�	�	�	�
(c)	Other expenses	�	�	�	�
�	Transaction costs in relation to future acquisitions¹	�	16,461	�	-
�	Intra-group merger costs	�	4,106	�	-
�	Write-down of inventory	�	-	�	992
�	Other expenses��	�	566	�	80
�	Expected credit losses	�	451	�	46
�	�	�	21,584	�	1,118
(d)	Other income	�	�	�	�
�	Other exceptional income	�	1,825	�	1,622
�	Write-back bank liabilities²	�	1,270	�	-
�	(Reversal of provision)/provision for tax litigations (note 15)	�	-	�	7,248
�	�	�	3,095	�	8,869

¹Direct costs incurred in 2019 relating to the proposed acquisition of Edison's E&P business

²^�Related to old bank liability recognised from 26 March 2013 with Cyprus Popular Bank Public Company Ltd (Greek branch) and Greek subsidiary "Kavala Oil S.A." transacted with on European Emission Allowances credits ("EUAs"). Since then and as of the date this liability was written-back, there has not been any written or oral communication with the Bank and any claim that could arise has now been time-barred, thus the obligation has been removed.

�

8. Net finance cost

�	�	2019	�	2018
�	Notes	$'000	�	$'000
�	�	�	�	�
Interest on bank borrowings	14	34,430	�	12,175
Interest expense on long term payables	16	7,178	�	5,676
Less amounts included in the cost of qualifying assets	10, 11	(39,850)	�	(9,258)
�	�	1,758	�	8,593
Finance and arrangement fees	�	5,139	�	2,931
Other finance costs and bank charges	�	1,349	�	1,548
Interest on obligations for leases	�	436	�	-
Unwinding of discount on decommissioning liabilities	�	320	�	399
Total finance costs	�	9,002	�	13,471
Interest income from time deposits	�	(2,496)	�	(1,735)
Total finance revenue	�	(2,496)	�	(1,735)
Foreign exchange losses/(gain)	�	3,933	�	23,521
Net financing costs	�	10,439	�	35,257

�

9. Taxation

(a) Taxation charge

�	2019	�	2018
�	$'000	�	$'000
Corporation tax - current year	(3)	�	(939)
Corporation tax - prior years	(127)	�	4,343
Deferred tax	20,661	�	12,123
Total taxation income / (expense)	20,531	�	15,527

�

(b) Reconciliation of the total tax charge

�	2019	�	2018
�	$'000	�	$'000
(Loss)/profit� before tax	(104,297)	�	85,292
�	�	�	�
Tax credit/(charge) at the applicable tax rate of 25% (FY18: 25%)¹	26,074	�	(21,323)
Impact of different tax rates	(804)	�	5,600
Tax impact of change of tax rates	-	�	598
Reassessment of recognised deferred tax asset in the current period	725	�	(404)
Permanent differences²	(3,599)	�	(1,318)
Non recognition of deferred tax on current period losses of branches³	� (1,910)	�	(1,259)
Tax effect of non-taxable income⁴	137	�	20,749
Derecognition of deferred tax as a result of capitalisation of loan⁵	-	�	8,367
Other adjustments	35	�	174
Prior year tax⁶	(127)	�	4,343
Taxation income	20,531	�	15,527
�	�	�	�
Effective tax rate	(20%)	�	(18%)

¹For the reconciliation of the effective tax rate, the statutory tax rate of the Greek upstream oil & gas activities of 25% has been used since the majority of the deferred tax comes from the Greek operations

²Permanent differences mainly consisted of non-deductible expenses with the majority relating to transactions costs for the proposed Edison E&P acquisition.

³Tax losses generated from entities which are not expected to generate sufficient taxable profits in the near future and for which deferred tax is not recognised.

⁴In 2018, the Group recognised a gain of $96.7 million from the revaluation of the derivative asset due to the acquisition of 50% of Energean Israel; this gain is non-taxable.�

⁵In 2018 the Group capitalised an intercompany loan liability of $233.0 million which is eliminated for group reporting purposes.� However, because the tax implications differ between the relevant jurisdictions the deferred tax credit impact is recorded in the profit and loss.

⁶^�The Group in FY 2018 reversed a provision of $4.3 million relating to previous years' income taxes.

�

10. Property, plant & equipment

�	Oil and gas assets	Leased assets*	Other property, plant and equipment	Total
Property, Plant & Equipment at Cost	$'000	$'000	$'000	$'000
At 1 January 2018	429,921	�-	54,535	484,456
Additions	484,969	�-	4,417	489,386
Capitalized borrowing cost	8,307	-	-	8,307
Acquisition of subsidiary (Note 5)	579,688	-	80	579,768
Disposals	(372)	-	(57)	(429)
Capitalised depreciation	2,574	�-	-	2,574
Change in environmental rehabilitation provision	1,758	�-	-	1,758
Foreign exchange impact	(19,391)	�-	(2,462)	(21,853)
At 31 December 2018	1,487,454	-	56,513	1,543,967
Additions	622,786	123	1,238	624,147
Adjustment on adoption of IFRS 16 leases	-	9,792	-	9,792
Lease modification	-	(699)	-	(699)
Capitalized borrowing cost	39,095	-	-	39,095
Capitalised depreciation	1,937	-	-	1,937
Change in environmental rehabilitation provision	5,437	-	-	5,437
Foreign exchange impact	(9,546)	(99)	(1,052)	(10,697)
At 31 December 2019	2,147,163	9,117	56,699	2,212,979
�		�	�	�
Accumulated Depreciation	�	�	�	�
At 1 January 2018	149,655	-	24,825	174,480
Charge for the period	�	�	�	�
Expensed	33,194	-	893	34,087
Capitalised to oil and gas properties	-	-	2,574	2,574
Foreign exchange impact	(7,727)	-	(1,151)	(8,878)
At 31 December 2018	175,122	-	27,141	202,263
Charge for the period	�	�	�	�
Expensed	33,206	3,019	2,577	38,802
Capitalised to oil and gas properties	-	418	1,519	1,937
Impairments	58,147	-	12,968	71,115
Foreign exchange impact	(2,963)	11	(457)	(3,409)
At 31 December 2019	263,512	3,448	43,748	310,708
Net carrying amount	�	�	�	�
At 31 December 2018	1,312,332	-	29,372	1,341,704
At 31 December 2019	1,883,651	5,669	12,951	1,902,271

�

Borrowing costs included in the cost of qualifying assets during the year are calculated by applying an interest rate of 9.4% (for the year ended 31 December 2018: 7.0%).

The currency translation adjustments arose due to the movement against the Group's presentation currency, USD, of the Group's Greek assets which have the Euro as their functional currency.

�

In 2019 the Group executed an impairment test for the Prinos CGU (Prinos and Epsilon fields). In the 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 $71.1 million in the carrying value of the Prinos CGU.

Gross production from Prinos averaged 3,312 bbls in 2019. Production levels were most significantly affected by technical issues at the EA-H3, PB-34 and PA-33 wells. Reservoir performance has been evaluated and at year end, Group's field production estimates have been reduced to reflect current performance and planned future capital expenditure investment profile.

During 2019 and 2018 the Group applied the following nominal oil price assumptions for impairment assessment in respect of its production asset of Prinos:

�

Year 1

Year 2

Year 3

Year 4

Year 5

Year 6

Year 7

2019

�forward curve ($61.7/bbl)

�forward curve

($58.6/bbl)

�forward curve

($57.2/bbl)

�forward curve

($56.8/bbl)

�forward curve

($57.0/bbl)

$65.0/bbl
�

$65/bbl inflated at 2% thereafter

2018

�forward curve

$63.6/bbl
average forward curve and forecast median

%63.3/bbl
average forward curve and forecast median

$64.9bbl
average forward curve and forecast median

$66.6/bbl
average forward curve and forecast median

$68.2/bbl
average forward curve and forecast median

$68.2/bbl inflated at 2% thereafter

In 2019 impairment test the Group applied a 11.9% pre-tax discount rate (2018: 10.4%)

�

The Group used the value in use in determining the recoverable amount of the cash-generating unit using discounted future cash flows. A reduction or increase in the five-year forward curve by 10% per barrel , based on the approximate volatility of the oil price over the previous two years, and a reduction or increase in the long-term price assumptions by 10% per barrel, based on the range seen in external oil price market forecasts, are considered to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices specified above would increase the impairment charge by $94.9 million, whilst increases to oil prices specified above would result in a credit to the impairment charge of $55.9 million. A 1 per cent increase in the pre-tax discount rate would increase the impairment by $26.4 million. A 1 per cent decrease in the pre-tax discount rate would decrease the impairment by $28.9 million. The Group believes a 1 per cent change in the pre-tax discount rate to be a reasonable possibility based on historical analysis of the Group's and a peer group of companies' impairment discount rates.

Depreciation for the year has been recognised as follows:

�	2019	�	2018
�	$'000	�	$'000
Cost of sales (note 7a)	36,645	�	33,904
Administration expenses (note 7b)	804	�	183
Other operating (income)/expenses	1,605	�	�
Capitalized depreciation in oil & gas properties	1,937	�	2,574
Total	40,991	�	36,661

�

Cash flow statement reconciliations:

Payment for additions to property, plant and equipment	2019 $'000		�		2018 $'000
Additions to property, plant and equipment	663,242		�		497,693
Associated cash flows	�		�		�
Payment for additions to property, plant and equipment	(897,153)		�		(290,123)
Non-cash movements/presented in other cash flow lines	�	�		�
Borrowing cost capitalized	(39,095)		�		(8,307)
Movement in working capital	273,006		�		(199,262)
�	�	�	�	�	�

�

11. Intangible assets

�	Exploration and evaluation assets	�	Other Intangible assets	�	Total
�	$'000	�	$'000	�	$'000
Intangibles at Cost	�	�	�	�	�
At 1 January 2018	3,611	�	1,662	�	5,273
Additions	5,226	�	8	�	5,234
Capitalized borrowing costs	951	�	-	�	951
Acquisition of subsidiary (note 5)	616	�	-	�	616
Exchange differences	(94)	�	(29)	�	(123)
31 December 2018	10,310	�	1,641	�	11,951
Additions	60,639	�	324	�	60,963
Capitalized borrowing costs	755	�	-	�	755
Exchange differences	(103)	�	(24)	�	(127)
At 31 December 2019	71,601	�	1,941	�	73,542
Accumulated amortisation and impairments	�	�	�	�	�
At 1 January 2018	261	�	1,012	�	1,273
Charge for the period*	-	�	171	�	171
Exchange differences	-	�	(48)	�	(48)
31 December 2018	261	�	1,135	�	1,396
Charge for the period*	-	�	252	�	252
Exchange differences	-	�	18	�	18
31 December 2019	261	�	1,405	�	1,666
�	�	�	�	�	�
Net carrying amount	�	�	�	�	�
At 31 December 2018	10,049	�	506	�	10,555
At 31 December 2019	71,340	�	536	�	71,876

*recognised in administrative expenses

Borrowing costs capitalised for qualifying assets for the year ended 31 December 2019 amounted to $0.8 million (31 December 2018: $0.95 million). The interest rates used was 9.4 % (31 December 2018: 7.0%).

�

Cash flow statement reconciliations:

Payment for additions to intangible assets	2019 $'000	�	2018 $'000
Additions to intangible assets	61,718	�	6,185
Associated cash flows	�	�	�
Payment for additions to intangible assets	(57,397)	�	(3,449)
Non-cash movements/presented in other cash flow lines		�	�
Borrowing cost capitalized	(755)	�	(951)
Movement in working capital	(3,566)	�	(1,785)

12. Trade and other receivables

�	2019	�	2018
�	$'000	�	$'000
Trade and other receivables-Current	�	�	�
Financial items:	�	�	�
Trade receivables	5,383	�	1,462
Derivative asset	564	�	-
Accrued interest income	182	�	-
Receivables from related parties	23	�	24
�	6,152	�	1,486
Non-financial items:	�	�	�
Deposits and prepayments¹	18,155	�	17,422
Deferred insurance expenses	5,338	�	6,139
Government subsidies	-	�	3,248
Refundable VAT	30,247	�	4,187
Reimbursement from insurance contracts	-	�	401
�	53,740	�	31,397
�	59,892	�	32,883
Trade and other receivables-Non Current	�	�	�
Non-financial items:	�	�	�
Deferred borrowing fees² � �	-	�	65,558
Deferred insurance expenses	438	�	5,617
Government subsidies	2,964	�	-
Other non current assets	674	�	670
�	4,076	�	71,845

^1�Included in deposits and prepayments, are mainly prepayments for goods and services under the GSP Engineering, Procurement, Construction and Installation Contract (EPCIC) for Epsilon project.

²^�This item represents arrangement fees and issue costs that the Group has incurred in connection with Karish-Tanin debt raising, which completed on March 2, 2018.

Arrangement fees and issue costs are deducted from the debt proceeds on initial recognition of the liability and are amortised as finance costs over the term of the debt using the effective interest method.

�

13. Share capital

On 21 March 2018, the Company issued 72,592,016 new shares in relation to the placement of its initial public offering of ordinary shares at �4.55 per share.

In July 2019 a total of 23,444,445 new ordinary shares have been placed with institutional investors� at a price of �9.00 per Placing Share, raising proceeds of approximately $265.1 million (approximately �211 million) before expenses. The Placing Shares issued represent approximately 15.4 per cent of the issued share capital of the Company prior to the Placing.

�	Equity share capital allotted and fully paid	Share capital	Share premium
�	Number	$'000	$'000
Issued and authorized	�	�	�
At 1 January 2018	70,643,120	917	-
Issued during the year	�	�	�
- IPO shares	72,592,016	1,009	434,934
- Group Restructuring	9,095,900	129	223,871
- Share based payment	821,727	11	-
At 31 December 2018	153,152,763	2,066	658,805
Issued during the year	�	�	�
- New shares	23,618,583	297	256,583
- Share based payment	318,060	4	-
At 31 December 2019	177,089,406	2,367	915,388

�

14. Borrowings

�	�	2019	�		2018	�
�	�	$'000	�		$'000	�
Net Debt	�	�	�		�	�
Current borrowings	�	38,052	�		-	�
Non-current borrowings	�	877,932	�		144,270	�
Total borrowings�	�	915,984	�		144,270	�
Less: Cash and cash equivalents and bank deposits		(354,419)		(219,822)
Net (Funds)/Debt (1)	�	561,565	�		(75,552)	�
Total equity� (2)	�	1,260,752	�		1,087,823	�
Gearing Ratio (1)/(2):	�	44.54%	�		(6.95%)	�
�	�	�	�	�	�	�

�

EBRD Senior Facility

On 30 January 2018, the Group's existing EBRD Senior Facility Agreement was amended and restated pursuant to the RBL Senior Facility Agreement, giving rise to a modification loss amount of $1.4 million included in Group's finance cost. The RBL Senior Facility Agreement comprises two facilities-a facility of up to $105.0 million with EBRD and the Black Sea Trade and Development Bank as lenders and a $75.0 million facility pursuant to which the Export-Import Bank of Romania Eximbank SA and Banca Comerciala Intesa Sanpaolo Romania S.A. (with 95% insurance cover from the Romanian ECA) as lenders. Proceeds from the Romanian Club Facility will finance exclusively 85% of the value attributable to goods and services under the GSP Engineering, Procurement, Construction and Installation Contract (EPCIC) contract. The facility is secured by substantially all of the assets of the subsidiary company Energean Oil & Gas S.A. and a guarantee from Energean E&P Holdings and a pledge of its shares in Energean Oil & Gas S.A. The facility will have a seven-year tenor and incurs interest on outstanding debt at US dollar LIBOR01 plus an applicable margin (4.9% for the $105.0 million facility and 3.0% for the $75.0 million facility). As at 31 December 2019, $145.2 million has been drawn down from the EBRD Senior Facility (year ended 31 December 2018: $126.6 million).

EBRD Subordinated Facility

In July 2016, the Group signed an EBRD Subordinated Facility Agreement, a subordinated loan agreement with the EBRD, subsequently amended on 8 March 2017, for a $20 million facility to fund the Group's exploration activities. The facility is subject to an interest rate of 4.9% plus LIBOR01, in addition to fees and commission and an EBITDA participation of the Greek subsidiary Energean Oil&Gas S.A. an amount of up to 3.5% of EBITDA (if EBITDA is positive) depending on the amount of the facility drawn.

On 28 February 2018, the Group's existing Subordinated Facility Agreement was amended and restated regarding the Maturity Date (25 August 2025) and EBITDA participation rate increase by 0.5% . EBITDA participation amount accrued in 2019 was $2.1 million (31 December 2018: $2.2 million). As at 31 December 2019 an amount of $20.0 million has been drawn down from the EBRD Subordinated Facility (31 December 2018: $20 million).

Senior Credit Facility for the Karish-Tanin Development:

On 2 March 2018, the Group entered into a senior secured project finance for its Karish-Tanin project amounting to $1,275 million. The loan is held at the Energean Israel Limited level (Energean 70%). Once drawn, interest is to be charged at LIBOR + 3.75% over months 1 to 12, LIBOR + 4.00% over months 13 - 24, LIBOR + 4.25% over months 25 - 36 and LIBOR + 4.75% over months 37 - 45. The facility matures in December 2021 and has a bullet repayment on maturity. There is a commitment fee of 30% of the applicable margin.� As of 31 December 2018 the Group had paid a total amount of $61.5 million for debt arrangement and commitment fees. As at 31 December 2019 an amount of $830.0 million (31 December 2018: $nil) was drawn down from the $1.275 billion Karish-Tanin project finance facility.

�

15. Provisions

�	Decommissioning	Litigation and other claims	Total
�	$'000	$'000	$'000
At 1 January 2018	5,688	9,306	14,994
New provisions and changes in estimates	1,758	(10,989)	(9,231)
Refunds	-	3,666	3,666
Payments	-	(1,887)	(1,887)
Unwinding of discount	351	-	351
Currency translation adjustment	(267)	(96)	(363)
At 31 December 2018	7,530	-	7,530
Current provisions	-	-	-
Non-current provisions	7,530	-	7,530
�	�	�	�
At 1 January 2019	7,530	-	7,530
New provisions and changes in estimates	5,437	133	5,570
Unwinding of discount	320	-	320
Currency translation adjustment	(142)	-	(142)
At 31 December 2019	13,145	133	13,278
Current provisions	-	133	133
Non-current provisions	13,145	-	13,145

�

Decommissioning provision

The decommissioning provision represents the present value of decommissioning costs relating to the Prinos asset in Greece.

According to the Prinos concession agreement ratified by the Greek Law, the Group is obliged to plug only the wells opened resulting from own drilling activities.

The increase of decommissioning liabilities in 2019 is driven by a reduction in the discount rate used to determine the net present value of the decommissioning provision, following the reduction in Greek government debt rates observed in 2019 and by change in the underlying decommissioning cost estimates. The discount rate applied at 31 December 2019 was 2.59% (2018: 4.7%).

�

16. Trade and other payables

�

�	2019	�	2018
�	$'000	�	$'000
Trade and other payables-Current	�	�	�
Financial items:	�	�	�
Trade accounts payable¹	95,919	�	323,953
Accrued expenses	42,026	�	36,341
Other creditors	5,641	�	2,372
Deferred licence payments due within one year²	14,843	�	15,342
Other finance costs accrued	2,306	�	3,148
Current lease liability	3,541	�	-
�	164,276	�	381,156
Non-financial items:	�	�	�
Social insurance and other taxes	3,829	�	3,583
Income taxes	3	�	939
�	3,832	�	4,522
�	168,108	�	385,678
Trade and other payables-Non Current	�	�	�
Financial items:	�	�	�
Deferred licence payments²	63,296	�	71,176
Long term lease liability	2,570	�	-
Sales consideration received in advance (INGL) ³	5,306	�	-
Non-financial items:	�	�	�
Social insurance	1,229	�	1,547
�	72,401	�	72,723

¹The change in trade payables and in other payables represents mainly� timing differences and levels of work activity in Karish project.�Trade and other payables are non-interest bearing. �

²In December 2016, Energean Israel acquired the Karish and Tanin offshore gas fields for $40.0 million closing payment with an obligation to pay additional consideration of $108.5 million plus interest inflated at an annual rate of 4.6% in ten equal annual payments. As at 31 December 2019 the total discounted deferred consideration was $78.1 million (31 December 2018: $86.5 million)

^3�In June 2019, Energean signed a Detailed Agreement with Israel Natural Gas Lines ("INGL") for the transfer of title (the "hand over") of the near shore and onshore part of the infrastructure that will deliver gas from the Karish and Tanin FPSO into the Israeli national gas transmission grid. As consideration, INGL will pay Energean 369 million Israeli new shekel (ILS), approximately $102 million for the infrastructure being built by Energean which will be paid in accordance with milestones detailed in the agreement. The agreement covers the onshore section of the Karish and Tanin infrastructure and the near shore section of pipeline extending to approximately 10km offshore. It is intended that the hand over to INGL will become effective shortly after the delivery of first gas from the Karish field expected in 1Q 2021. Following hand over, INGL will be responsible for the operation and maintenance of this part of the infrastructure.

�

17.Significant transaction

On 4^th July 2019 the Group entered into a conditional sale and purchase agreement to acquire Edison Exploration & Production S.p.A. ("Edison E&P") from Edison S.p.A. for $750 million, to be adjusted for working capital, with additional contingent consideration of $100 million payable following first gas from the Cassiopea development (expected 2022), offshore Italy. Edison E&P's portfolio of assets includes producing assets in Egypt, Italy, Algeria, the UK North Sea and Croatia, development assets in Egypt, Italy and Norway and balanced-risk exploration opportunities across the portfolio. The Edison E&P portfolio will add working interest 2P reserves of 292 mmboe and 2019 net working interest production of 64 kboe/d. As of 31 December 2019 the Edison E&P group generated revenue of $531 million and EBITDAX of $276 million as per Edison E&P year end management report.

On 14 October 2019, the Group conditionally agreed to sell Edison E&P's North Sea Assets, consisting of its UK and Norwegian companies to Neptune Energy Group for $262 million with a further $30m consideration contingent on future trading. At 30 June 2019 the carrying value of total assets to be sold were $549.5 million and net assets of the disposal group was $104.4 million. The companies to be disposed generated revenue of $57.8 million and profit after tax of $12.3 million for the year ended 31 December 2018, as per Edison E&P year end management report.

[1] All Edison E&P 2019 financials are presented on a pro forma unaudited

[2]�Edison E&P financials will be consolidated from the date of transaction close. Energean will benefit from the cash flows from the business between the locked-box date and transaction completion through an adjustment to the variable consideration

[3] The Egyptian assets are owned by Edison E&P, ownership by Energean is subject to Edison E&P transaction completion

[4] Cassiopea is an Edison E&P asset. Ownership by Energean is subject to the Edison E&P transaction completion

[5] Gas has been converted to boe using a conversion factor of 5.8 mcf/boe. Numbers may not sum due to rounding

[6] Energean has agreed to sell the UK and Norway assets to Neptune Energy. Energean and Edison E&P have agreed to exclude the Algerian assets from the transaction perimeter.

Energean	Tel: +44 (0) 7917 608 645
Kate Sloan, Head of IR �	�
Camarco (Financial PR)	Tel: +44 (0) 20 3757 4980
Billy Clegg Owen Roberts Monique Perks	�

� �	Share capital	Share premium¹	Other reserve²�	Share based payment reserve³	Translation reserve⁴ �	Retained earnings	Merger reserves	Total	Non-controlling interests	Total
�	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000
At 1 January 2019	2,066	658,805	5,907	6,617	(15,513)	29,993	139,903	827,778	260,045	1,087,823
Loss for the period	-	-	-	-	-	(83,313)	-	(83,313)	(453)	(83,766)
Remeasurement of defined benefit pension plan	-	-	(349)	-	-	-	-	(349)	-	(349)
Hedges net of tax	-	-	304	-	-	-	-	304	130	434
Exchange difference on the translation of foreign operations	-	-	-	-	(3,751)	-	-	(3,751)	-	(3,751)
Total comprehensive income	-	-	(45)	-	(3,751)	(83,313)	-	(87,109)	(323)	(87,432)
Transactions with owners of the company	�	�	�	�	�	�	�	�	�	�
Issuance of new shares (note 13)	297	264,785	-	-	-	-	-	265,082	-	265,082
Transaction cost in relation to new share issue (note 13)	-	(8,202)	-	-	-	-	-	(8,202)	-	(8,202)
Employee share schemes	4	-	-	3,477	-	-	-	3,481	-	3,481
At 31 December 2019	2,367	915,388	5,862	10,094	(19,264)	(53,320)	139,903	1,001,030	259,722	1,260,752

�	�	2019	�	2018
�	Note	$'000	�	$'000
Operating activities	�	�	�	�
(Loss)/profit before taxation	�	(104,297)	�	85,292
Adjustments to reconcile (loss)/profit before taxation to net cash provided by operating activities:	�	�	�	�
Depreciation, depletion and amortisation	10, 11 �	39,054	�	34,258
Impairment loss on property, plant and equipment	10	71,115	�	�
Impairment loss on inventory	�	-	�	992
Gain from disposal on property, plant and equipment	�	-	�	(6)
Increase/(decrease) in provisions	�	730	�	(6,757)
Finance income	8	(2,496)	�	(1,735)
Finance costs��	8	9,002	�	13,471
Fair value gain on derivative	�	-	�	(96,709)
Other bank liabilities written back	�	(1,270)	�	-
Share-based payment charge	�	2,751	�	1,570
Net foreign exchange loss	8	3,933	�	23,521
Cash flow from operations before working capital adjustments	�	18,522	�	53,897
Decrease/(increase) in inventories	�	2,929	�	(1,807)
Decrease/(increase) in trade and other receivables	�	(2,423)	�	10,741
(Decrease)/increase in trade and other payables	�	18,167	�	(3,562)
Cash flow from operations	�	37,195	�	59,269
Tax paid	�	(910)	�	(251)
Receipts in relation to provisions	�	-	�	3,666
Net cash inflow from operating activities	�	36,285	�	62,684
Investing activities	�	�	�	�
Payment for purchase of property, plant and equipment	�	(897,153)	�	(290,123)
Payment for exploration and evaluation, and other intangible assets	�	(57,397)	�	(3,449)
Acquisition of a subsidiary, net of cash acquired	�	-	�	(32,746)
Proceeds� from disposal of property, plant and equipment	�	-	�	63
Interest received	�	2,431	�	1,591
Net cash used in investing activities	�	(952,119)	�	(324,664)
Financing activities	�	�	�	�
Proceeds from issue of share capital	13	265,082	�	460,000
Drawdown of borrowings	14	848,658	�	55,626
Proceeds from capital increases by non-controlling interests	�	-	�	67,613
Transaction costs in relation to IPO and new share issue	�	(8,202)	�	(20,057)
Advance payment from future sale of property, plant and equipment (INGL)	�	5,090	�	-
Repayment of obligations under leases	�	(1,024)	�	-
Debt arrangement fees paid	�	(8,557)	�	(8,237)
Debt arrangement fees for Karish-Tanin facility	16	-	�	(61,496)
Finance cost paid for deferred license payments	�	(4,492)	�	-
Finance costs paid	�	(45,142)	�	(10,919)
Net cash inflow from financing activities	�	1,051,413	�	482,530
Net increase / (decrease) in cash and cash equivalents	�	135,579	�	220,550
Cash and cash equivalents:	� � � �	�	�	�
At beginning of the period	�	219,822	�	15,692
Effect of exchange rate fluctuations on cash held	�	(982)	�	(16,420)
At end of the period	�	354,419	�	219,822