Energean plc

("Energean" or the "Company")

 

2021 Full Year Results

London, 24 March 2022 - Energean plc (LSE: ENOG, TASE: אנאג) is pleased to announce its audited full-year results for the year ended 31 December 2021 ("FY 2021").

 

Mathios Rigas, Chief Executive of Energean, commented:

"2021 was an outstanding year for Energean, one in which we delivered excellent operational and record financial results. Production came in above initial expectations and we also benefitted from an elevated market price environment. As a result, we generated full year revenues of $497 million and Adjusted EBITDAX of $212 million.

"Our flagship project, Karish, is on track for first gas in Q3 2022.  Earlier this month, we commenced the largest 2022 drilling programme in the East Med and spudded the Athena exploration well which is targeting 21 Bcm (totaling 140 mmboe). Positive results from this high-impact programme would be an important catalyst for the growth of our operations in Israel and the region where security of supply is being increasingly prioritised.

" Elsewhere, first gas from NEA/NI in Egypt is anticipated in H2 2022 and the remainder of our development projects in Israel, Italy and Greece remain on track. We are well positioned to reach our medium-term targets of over 200 kboed production, $2 billion annual revenue and $1.4 billion Adjusted EBITDAX.

"As such we are pleased to announce our inaugural dividend policy. It is our goal to make reliable, recurring and sector-leading returns to shareholders, targeting a first dividend to be paid no later than during Q4 2022, following first gas from Karish (Q3 2022). This is made possible by our ongoing operational and financial success and represents an important new phase in Energean's corporate development.

"Energean is focused on reducing its carbon emissions and we are working towards our 2050 net zero target. In 2021, we delivered a 8% year-on-year reduction in carbon emissions intensity to 18.3 kgCO2/boe[1]. Actions taken to achieve this reduction included implementing a zero routine flaring policy across our operated sites and switching to renewable-sourced electricity in Italy - having already put green electricity contracts in place for Israel and Greece in 2020. The latter has resulted in a 100% y-o-y reduction in Scope 2 emission at our operated sites. We continue to progress on our journey to net zero with key actions identified for this year.

"2022 will be a landmark year for Energean. It will be the year of first production from our major project, Karish. It will be the year that brings us one step closer to our Net Zero Target. It will be the year we target to add a sustainable and reliable dividend stream to the total return to shareholders."  

Highlights

·      Announcement of Inaugural Dividend Policy

·      First gas from Karish on track for Q3 2022, development was 92.5% complete as at 31 December 2021

·      Revenues of $497 million ($336 million 2020 pro forma[2]) and Adjusted EBITDAX of $212 million ($108 million 2020 pro forma²), representing record full year results and the transition to net operating profit. Capital expenditure was $408 million ($565 2020 pro forma²)

·      Reduced EGPC receivables to $95 million as at 31 December 2021 (c.40% y-o-y reduction)

·      Average working interest production of 41.0 kboed (72% gas) was above initial guidance[3], with cost of production of $17.5/boe

·      Spudded the Athena exploration well, offshore Israel. First drilling results expected during Q2 2022

·      Entered into a spot sales agreement with Israel Electricity Company ("IEC"), the biggest natural gas consumer in Israel for Karish gas

·      Increased the weighted average debt maturity to six years, pushed out the first major repayment until 2024 and achieved blended fixed rate of 5.5%, removing exposure to floating rates

·      Signed funding package backed by the Greek State for the Epsilon development project in Greece, due onstream in H1 2023

·      8% year-on-year reduction in carbon emissions intensity when considering 2021 Energean data versus 2020 pro forma performance data

 

Outlook

 

·      First gas from Karish in Q3 2022

·      Payment of the inaugural dividend, targeted for no later than Q4 2022, following first gas from Karish (Q3 2022)

·      2022 average working interest production, excluding Israel, is expected to be 35.0 - 40.0 kboed. Israel production rate in 2022 is expected to average 25.0 - 30.0 kboed and will be a function of both the first gas date and the commercial ramp up achieved in the initial days and weeks of production

·      2022 development and production capital expenditure is expected to be $710 - 760 million[4]

·      First gas from the first well at NEA/NI (Egypt) expected in H2 2022

·      Complete Pre-Front-End Engineering Design ("pre-FEED") on the carbon capture and storage ("CCS") project in Greece

·      Secure additional Gas Sales Agreements in Israel and the region

 

 

Financial Summary

	FY 2021	Pro Forma2 FY 2020	Consolidated Results FY 2020
	$m	$m	$m
Sales revenue	497.0	335.9	28.0
Cost of production ($/boe)[5]	17.5	11.3	21.4
Operating profit/(loss)	32.1	(422.2)	(124.5)
Adjusted EBITDAX	212.1	107.7	(8.3)
Operating cash flow	132.5	137.0	1.5
Total capital expenditure[6]	407.9	565.4	429.0
Net debt (cash)[7]	2,016.6	1,240.1	1,240.1

 

 

 

Webcast & conference call

A webcast will be held today at 08:30 GMT / 10:30 Israel Time

Webcast: https://edge.media-server.com/mmc/p/fkryxi6m
Dial-In: +44 (0) 2071 928338
Dial-in (Israel only): 035308845
Confirmation code: 2576809

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

Enquiries

 

For capital markets: ir@energean.com

 

Maria Martin, Head of Corporate Finance                                                                      Tel: +44 7917 573 354

 

For media: pblewer@energean.com

 

Paddy Blewer, Head of Corporate Communications                                                     Tel: +44 7765 250 857

 

 

 

Dividend Policy

•     Energean is targeting launch of its inaugural dividend, to be paid no later than during Q4 2022, following first gas from Karish (Q3 2022).

•     It is the Company's goal that shareholders will receive a sector - leading return on their investment through dividends and continued organic growth, while maintaining a disciplined capital allocation policy.

•     Energean targets paying dividends of at least $1 billion by the end of 2025. This is underpinned by predictable cashflows, largely insulated from commodity price fluctuation, thanks to long-term gas contracts with floor-price protection and high take-or-pay provisions.

•     The Company expects to begin with a quarterly dividend of at least $50 million. This amount will ramp-up in line with Energean's medium-term production and revenue targets to at least $100 million per quarter, as the Company's fully sanctioned and funded developments come onstream during the next 30 months.

•     The Board and Management will ensure that sufficient liquidity remains within the Group, to continue Energean's organic growth strategy and opportunistic M&A.

•     Post first gas from Karish, the Company expects a rapid deleveraging on a Group consolidated basis to levels below 1.5x (Net Debt/EBITDAX) and sees this being met no later than 2024.

 

Corporate Review

Financing

During the course of 2021, Energean optimised its capital structure by refinancing through the debt capital markets. This resulted in a year end liquidity position in excess of $1 billion. Debt repayments have now been pushed out to 2024 and the weighted average debt maturity has increased to approximately six years as of 31 December 2021. In accessing the bond markets, Energean has also converted floating interest rate exposure to fixed rates giving a blended average interest rate of approximately 5.5%. 

Energean Israel Senior Secured Notes - non-recourse to PLC

On 24 March 2021, Energean's subsidiary, Energean Israel Finance Limited completed the issuance of $2.5 billion aggregate principal of senior secured notes, split into four equal tranches with maturities in 2024, 2026, 2028 and 2031. This is non-recourse to the Group and was used, inter alia, to refinance the Company's $1.45 billion project finance facility and its $700 million term loan, to fund certain reserve accounts, and for transaction expenses and general corporate purposes.

Energean PLC Senior Secured Notes

On 18 November 2021, Energean plc completed the issuance of $450 million principal amount of senior secured notes due 2027, with a fixed annual interest rate of 6.5%. The proceeds were used to repay and cancel all amounts under the Egypt reserve based lending facility and the Greek reserve based lending facility plus subordinated debt, and for transaction expenses and general corporate purposes.

Greek State-Backed Loan

On 27 December 2021, the EUR 100 million funding package, backed by the Greek State, for the Epsilon and Prinos area development was finalised. EUR 90.5 million was provided by the Black Sea Trade and Development Bank ("BSTDB") and EUR 9.5 million directly by the Greek State. The tenor is seven and eight years respectively with first repayment not due until 2027. The blended interest rate is 2%. This facility is non-recourse to the Group.

M&A

Acquisition of the minority interest in Energean Israel Ltd

On 25 February 2021, Energean closed the acquisition of the 30% minority interest in Energean Israel Ltd, held by Kerogen, for between $380 million and $405 million. The acquisition added 2P reserves of 20.5 billion cubic metres ("Bcm") of gas and 30 million barrels of liquids, representing approximately 219 MMboe in total, to the Company, included within the pro forma 2020 reserve position.

The total consideration for the acquisition included i) $175 million of upfront consideration that was funded through partial drawdown of the $700 million term loan facility that was signed on 14 January 2021, ii) between $125 million and $150 million of deferred consideration, which is expected to be funded from the proceeds of the $2.5 billion bond issued and discussed above, iii) $30 million of deferred consideration payable at end-2022 and expected to be funded from free cash flows from the Karish project, and iv) $50 million of bilateral convertible loan notes that have been issued to Kerogen and have a maturity date of 29 December 2023, a strike price of GBP 9.50 and a zero-coupon rate.

ESG and Climate Change

Energean is committed to net zero emissions by 2050 and industry-leading disclosure of its energy transition intentions.

Emissions reduction

Energean maintains a rolling carbon intensity reduction plan and currently anticipates a reduction in carbon emissions intensity of 7.7  kgCO2/boe by 2025, a reduction of more than 85% versus 2019. The Group recorded full-year 2021 emissions intensity of 18.3 kgCO2/boe, a 8% y-o-y decrease. The difference in these figures versus those reported previously are due to reporting changes, as Energean has aligned with industry standards and now reports emissions based on an equity share accounting approach.

During the year, Energean published its first Climate Change Policy, implemented a zero routine flaring policy across its operated sites and rolled out 'Green electricity' in Israel, Greece and Italy. The latter led to a 100% decrease y-o-y in Scope 2 emissions intensity at operated sites.

The Prinos CCS project proposal is to provide long-term storage for carbon dioxide emissions captured from both local and more remote emitters. Energean estimates that the Prinos subsurface volumes are sufficient to sequester up to 100 million tonnes of CO2, representing up to around 50% of total annual emissions from the Greek manufacturing sector for 20 years.

During 2021, the European Commission granted approval for the inclusion of the Greek CCS project within the Resilience and Recovery Fund. In H2 2021, Energean commenced pre-FEED for the Prinos CCS project. In March 2022, Energean signed a service contract with Halliburton for a carbon storage subsurface study in Greece.

ESG awards

In December 2021, the Carbon Disclosure Project ("CDP") upgraded its Climate Change rating for Energean to B, from B- in the previous year (this compares to a flat y-o-y sector average of C). In February 2022, the CDP also upgraded its Supplier Engagement rating to A- from B in the previous year. Energean was also awarded 'Best ESG Energy Growth Strategy - Europe 2021' by CFI and moved to the highest ranking 'Leader' on Overall ESG Score by Sustainalytics.

Energean has also continued to comply with the Task Force on Climate Related Financial Disclosure ("TCFD") recommendations, full disclosure on which will be provided in the Annual Report and Accounts.

 

 

 

Operational Review

HSE

In 2021 Energean delivered another excellent HSE record with improved Loss Time Injury Frequency ("LTIF") of 0.33 (0.65) and Total Recordable Incident Rate ("TRIR") of 0.77 (1.31).

Production and Reserves

Full year 2021 working interest 2P reserves were 965[8] MMboe, a 27% year-on-year increase vs. 2020^[9], changes are due mainly to:

·      The acquisition of Kerogen's 30% holding in Energean Israel Ltd. The transaction closed on 25 February 2021 and added 219 mmboe of 2P reserves.

·      The increased equity interest in the producing Rospo Mare and Vega fields in early 2021, offshore Italy, to 100% for zero consideration, adding approximately 12 MMboe of 2P oil reserves and offsetting 2021 production.

	2021 2P Reserves MMboe (% gas)	2020 pro forma 2P Reserves MMboe (% gas)	2020 2P Reserves MMboe (% gas)
Israel	744 (86%)	730 (86%)[10]	511 (86%)
Egypt	103 (87%)	114 (88%)	114 (88%)
Italy	78 (55%)	79 (54%)	79 (54%)
Greece	37[11] (3%)	53 (2%)	53 (2%)
Croatia	2 (100%)	2 (100%)	2 (100%)
UK	2 (14%)	2 (22%)	2 (22%)
Total	965 (81%)	982 (79%)	762 (77%)

2021 working interest production was 41.0 kboed, which was above initial guidance[12] and 15% lower than 2020 pro forma as a result of natural decline in Abu Qir and scheduled maintenance downtime in UK and Greece.

	2021 Kboed (% gas)	2020 Pro forma Kboed (% gas)	2020 Consolidated Kboed (% gas)
Egypt	29.1 (87%)	35.4 (86%)	1.4 (87%)
Italy	9.9 (41%)	9.1 (52%)	0.3 (53%)
Greece & Croatia	1.3 (12%)	2.0 (10%)	1.8 (8%)
UK	0.7 (16%)	1.8 (29%)	0.1 (100%)
Total	41.0 (72%)	48.3 (74%)	3.6 (39%)

 

Israel

Karish Gas Development

Summary

On 31 December 2021, the Karish Project was approximately 92.5% complete, as measured under the Group's contract with TechnipFMC.

In early March 2022, the onshore pipeline was connected to the Israeli grid.

The FPSO entered dry-dock on 14 March 2022 to be cleaned and prepared for sail-away and entry into Israeli waters.  First gas remains on track for Q3 2022.
 

2021 Progress

	% Completion at 31 December 2021[13]
Production Wells	100.0
FPSO	98.4
Subsea	83.6
Onshore	99.9
Total	92.5

 

Energean Power FPSO Progress and Key Milestones

The Energean Power FPSO was approximately 98.4% complete, at year end 2021. In early 2021, all the remaining minor lifting work (flare stack, helicopter-deck and portside crane boom) was completed. The rest of H1 2021 was spent completing the connection between the topsides and the hull and completing the marine systems in the hull. In H2 2021, the focus was on commissioning activities ahead of sail-away. In December 2021, the penultimate major technical milestone associated with the construction of the Energean Power FPSO was successfully completed. This involved testing the telescopic design of the emergency flare stack which will allow the vessel to pass under the Suez Canal Bridge, hence avoiding the need to either sail around Africa or to install the system in the Mediterranean Sea. This has further reduced the environmental footprint of the construction phase whilst shortening the schedule.

The FPSO entered dry-dock on 14 March 2022 to be cleaned and prepared for sail-away and entry into Israeli waters. 

 

Subsea and Onshore Progress

Subsea works were approximately 83.6% complete at year-end 2021, with the risers, spools metrology and 90-kilometre gas sales pipeline finished. The export pipeline was also successfully hydrotested during this period, to ensure no leaks throughout the length of the pipe.

 

Onshore work was substantially complete at year end (99.9% under the Technip FMC EPCIC), with construction and civil works completed. The remaining outstanding work is to finish the site restoration work (e.g. replanting cleared trees).

The onshore pipeline was connected to the national grid in March 2022. Gas from the Karish field will flow to the Energean Power FPSO, located 90 km offshore, where production output will be processed and separated. The treated gas will then be delivered from an underwater pipeline to the land-based system at the Dor Station before entering the national pipeline on its way to distribution companies and end consumers.

 

The outstanding work is to hook-up the risers to the FPSO, upon its arrival in Israel in Q2 this year.

 

Israel Growth Projects

1.    Karish North

In January 2021, Energean reached FID at the 1.2 Tcf (33 Bcm[14]) Karish North field, 21-months after the announcement of the discovery.

The KN-01 exploration well will be re-entered, side-tracked and completed as a production well as part of the Israel growth drilling campaign, expected during the summer 2022 following completion of the Athena (Block 12) exploration well and the Karish Main-04 appraisal well.

Karish North is expected to commence production in H2 2023. A second well is expected to be drilled in 2026 and, combined with later life workovers to both wells, is expected to be sufficient to fully develop the 244 MMboe of 2P reserves.

2.    Second oil train & riser

In May 2021, Energean took FID on two high-return growth projects. The first, a second oil train on the FPSO that will increase the liquids capacity from 18 kboed to 32 kboed. The second, a second gas sales riser, will enable gas production at the full 8 Bcm/yr capacity of the FPSO.

In December 2021, Energean signed an EPC contract with KANFA AS for the second oil train.

Both projects made good progress in 2021 and are expected onstream in H2 2023 as planned. The total cost of Karish North and the second oil train & riser is expected to be $275 million, which includes the cost of the Karish North development well.

3.    Growth drilling programme

In March, the Athena exploration well (Block 12) was spudded. This well is targeting 21 Bcm (totalling 140 mmboe). Success at Athena is economically significant, de-risking the remaining prospects in the block.  It can be monetised on an expedited basis due to its proximity to the FPSO.

After Athena the following wells will be drilled, in order of sequence:

·      Karish Main 4 - Appraisal - Firm

·      Karish North - Development - Firm

·      Hermes (Block 31) - Exploration - Optional

·      Hercules (Block 23) - Exploration - Optional

A decision on whether to drill the optional wells, as part of this drilling campaign, will be made in Q2 2022.

Local Israeli market opportunities, as well as export commercialisation routes, are being matured to access international gas prices if (and when) additional volumes become available.

Gas Contracts

Existing GSPAs

Energean has signed 18[15] gas sales agreements ("Agreements") for the supply of 7.2 Bcm/yr of gas on plateau, representing almost 100% of total gas reserves volumes over the life of those Agreements. All Agreements include provisions for floor pricing and take-or-pay and / or exclusivity, providing a high level of certainty over revenues from the Karish, Karish North and Tanin projects over the next 16 years.

In 2021, for one agreement representing 0.2 Bcm/yr and commencing 2024, the buyer was unable to meet its conditions subsequent under the Agreement and the parties have mutually agreed to terminate the Agreement. This termination is not related to the project schedule.

In addition, in November 2021, further to its initiation of arbitration proceedings, Dalia sent notices to Energean purporting to terminate its gas sales agreement (which represents 0.8 bcm/yr of contracted gas sales), whilst also attempting to reserve its rights by claiming that should the notices be determined to be invalid or wrongly issued, the gas sales agreement would not have been terminated.

Energean believes that the notices served by Dalia are invalid and constitute a material breach of contract, giving it the right to terminate the contract. Energean has exercised this right and, as part of the same arbitration proceedings, is seeking to recover damages suffered by it as a result of such termination. The amount of the damages will ultimately depend on the price which Energean is able to achieve for the gas that would have been sold to Dalia. This is currently estimated to be between $105-407 million.

Alternative commercialisation opportunities

Energean has identified a number of incremental buyers for its gas reserves and prospective resources. In Israel, the third gas fired power plant auctioned as part of the IEC privatisation process (Hagit) was awarded. The winning consortium is now seeking gas supply. 

In December 2021, Energean signed an MOU with EGAS for the sale and purchase of up to 3 Bcm/yr of natural gas on average for a period of 10 years, commencing with initial volumes of up to 1 Bcm/yr. This represents a commercialisation option for gas resources discovered in the 2022/23 drilling campaign. Energean and EGAS have identified existing transportation routes for the delivery of these volumes.

Energean is confident of selling all volumes into strong domestic and regional markets and commercial discussions are underway with a number of domestic and international buyers.

In March 2022, Energean signed a supply agreement with the Israel Electric Company ("IEC"), the largest natural gas consumer in Israel for Karish Gas. The gas price will be determined month ahead, with volumes determined on a daily basis. Starting upon the commencement of first gas production from Karish, the agreement will be valid for an initial one-year period with an option to extend subject to ratification by both parties. The agreement will optimise Energean's gas sales portfolio.

Liquids Marketing Agreement

In March 2022, Energean signed a limited term exclusivity agreement and term sheet for the marketing of its Karish liquids with Vitol SA. While the parties are still negotiating the related binding SPA contract, including technical aspects to be clarified, and the exclusivity does not bind the parties to finalise such a contract, Energean is looking forward to furthering its cooperation with Vitol, with whom the Company enjoys a valuable working relationship.

 

Egypt

Production

In the 12-months to 31 December 2021, working interest production from the Abu Qir area averaged 29.1 kboed (87% gas), around the mid-point of full year production guidance (28.5 - 30.0 kboed). Q4 production was impacted by scheduled work-over activities, which ultimately enhanced the year end exit rate.

NEA/NI

In January 2021, Energean sanctioned the North East Almeyra ("NEA")/North Idku ("NI") project, shallow-water offshore Egypt and neighbouring the Abu Qir concession. An Engineering, Procurement, Construction and Installation ("EPCI") contract for the four subsea wells and the associated tie-back to the Abu Qir platform and associated infrastructure was awarded to TechnipFMC in February 2021.

NEA/NI is progressing on budget and on schedule, being 37.0% complete as of 31 December 2021. Onshore fabrication of the subsea kit is progressing well. First gas from one well is anticipated in H2 2022, with the remaining three wells expected online in H1 2023. The project contains an estimated 29 MMboe of 2P reserves and 23 MMboe of 2C reserves according to D&M. Peak working interest production is expected to be approximately 69 MMscfd plus 1.7 kbopd of condensate and LPG (around 15 kboed in total).

On 9 January 2022, the rig contract for the four well drilling campaign was signed with EDC for the El Qaher-1 jack-up rig. Drilling is anticipated to begin in H2 2022.

Receivables

As at 31 December 2021, net receivables (after provision for bad and doubtful debts) in Egypt were $95 million, of which $51 million was classified as overdue. Energean has reduced its net EGPC receivables balance by over 75% compared to the balance prevailing at the economic reference date of the Edison E&P acquisition (1 January 2019: $240 million), highlighting the successful outcome of Energean's strategy to reduce the receivables balance and generating additional value from the acquisition.

Abu Qir drilling programme

Energean expects to drill an infill well in Q2 2022 to support production in the Abu Qir concession. An additional three wells, currently under technical review, are expected to be drilled following the NEA/NI drilling programme.

New onshore exploration acreage

 

On 3 January 2022, an international consortium led by Energean Egypt (50% operator and Croatia's INA, d.d. 50%) was awarded an exploration licence for the East Bir El-Nus concession (Block-8), in the Western Desert of Egypt. The award is in line with Energean's strategy to increase and diversify its presence in Egypt and reinforces its commitment to the country.

The work programme for the licence includes a 180 linear km 2D seismic survey, a 200 km² 3D seismic survey plus two exploration wells, which are expected to target estimated resources (in place) of approximately 100 mmboe.

 

Europe

Italy

A new gas supply agreement ("GSA") was signed with A2A in Italy for the delivery of gas, commencing 1 April 2022 until 30 September 2023. Under the agreement, Energean will sell its full entitlement production to A2A, at PSV day-ahead prices, which agrees to purchase, take and pay for the quantities.

Production

In the 12-months to 31 December 2021, working interest production from Italy averaged 9.9 kboed (41% gas), at the top end of full year production guidance (9.5 - 10.0 kboed).

During early 2021, Energean increased its positions in the Vega and Rospo Mare fields to 100% (from 60% and 62%, respectively) at nil cost and with an economic reference date of 1 January 2021. ENI retains its share of abandonment expenses associated with both fields.

Cassiopea

First gas from Cassiopea remains on track for 1H 2024, being 24.2% complete as of 31 December 2021.

In September 2021, ENI began construction of the gas treatment plant for the Cassiopea project (Energean, 40% non-operated interest). In line with Energean's sustainability strategy, the project will, according to ENI, have close to zero emissions and the installation of 1 MWp of photovoltaic solar panels will allow the project to achieve carbon neutrality.

Greece and Croatia

In the 12 months to 31 December 2021, working interest production from Greece and Croatia averaged 1.3 kboed (12% gas), slightly lower than the full year production guidance of 1.5 kboed due to downtime for scheduled maintenance and union dispute on the Prinos Assets in Greece.

Greece

Following the signing of the EUR 100 million funding package (see above Financing section), Energean recommenced work on the Epsilon development which includes the completion of the Lamda platform, tie back to the existing Prinos complex and completion of three wells which were pre-drilled in 2019. First oil from the Epsilon development, which has 2P reserves and 2C resources of 53 mmboe in aggregate, is expected in H1 2023. Fabrication of the jacket and piles is due to be completed in Q2 2022, after which the piles, pipeline and jacket will be installed.

Pre-FEED for the Prinos CCS project is progressing well and is expected to complete by the end of Q2 2022. In March 2022, Energean signed a service contract with Halliburton for a carbon storage subsurface study in Greece. Please see the Emissions Reduction section above for more detail.

Croatia

Energean is currently in FEED for the development of the Irena gas field, located five kilometres north of the Izabela field offshore Croatia, with the target to take FID on the project in Q4 2022. If progressed, first gas is anticipated in Q4 2024. The field has 2P reserves of 0.4 bcm (2.3 mmboe)[16].

Montenegro

Technical evaluation of Blocks 26 and 30 has been completed. Energean's focus is on the significant biogenic gas potential identified. The Ministry has agreed to extend the deadline of the first exploration period in Montenegro by four months from the original expiration date of 15 March 2022 to facilitate the obligated introduction of a partner.

UK North Sea

In the 12-months to 31 December 2021, production in the UK North Sea was 0.7 kboed (16% gas), ahead of full year guidance of 0.5 kboed due to extended production from the Wenlock field. 

The Glengorm Central appraisal well contained no commercial hydrocarbons and has been plugged and abandoned. A comprehensive data analysis program is underway. The results of the Glengorm appraisal programme will be evaluated to inform forward plans for the P.2215 licence.

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

Malta

On 17 December 2021, Energean terminated its Malta Exploration Study Agreements (Blocks 1,2, and 3 of Area 3). This marked an exit from operations in the country.
 

2022 Guidance

	FY 2022
Production
Israel (kboed)	25.0 - 30.0 (including 1.0 - 1.3 bcm of gas)
Egypt (kboed)	24.5 - 28.0
Italy (kboed)	9.0 - 10.0
Greece & Croatia (kboed)	1.0 - 1.5
UK North Sea (kboed)	0.5
Total production, including Israel (kboed)	60.0 - 70.0
Total production, excluding Israel (kboed)	35.0 - 40.0
Financials
Consolidated net debt ($ million)	2,600 - 2,800[17]
Cost of Production (Operating Costs plus Royalties)
Israel ($ million)[18]	90-120
Egypt ($ million)	60
Italy ($ million)	150 (including flux costs of approximately $20 million)
Greece & Croatia ($ million)	30
UK North Sea ($ million)	30
Total Cost of Production ($ million)	360-390
Cash SG&A ($ million)	35 - 40
Development and production capital expenditure
Israel ($ million)	450-500[19]
Egypt ($ million)	140
Italy ($ million)	80
Greece and Croatia ($ million)	35
UK North Sea ($ million)	5
Total Development & Production Capital Expenditure ($ million)	710-760
Exploration Expenditure
Israel ($ million)	95[20]
-      Egypt, Italy, Greece and Croatia ($ million)	5
UK North Sea ($ million)	10
Total Exploration Expenditure ($ million)	100
Decommissioning
UK North Sea	5
Italy	15
Decommissioning expenditure ($ million)	20

 

Financial Review

	2021	Pro forma 2020	2020	Change from 2020 pro forma
Average working interest production (Kboepd)	41.0	48.3	3.6	(15.1%)
Sales revenue ($m)	497.0	335.9	28.0	48.0%
Cash cost of production ($m)	261.6	198.9	28.5	31.5%
Cost of production ($/boe)	17.5	11.3	21.4	54.9%
Administrative & selling expenses ($m)	43.0	41.4	15.3	3.8%
Operating profit/(loss) ($m)	32.1	(422.2)	(124.5)	107.6%
Adjusted EBITDAX ($m)	212.1	107.7	(8.3)	96.9%
Loss after tax ($m)	(96.2)	(416.4)	(92.9)	74.1%
Cash flow from operating activities ($m)	132.5	137.0	1.5	(2.8%)
Capital expenditure ($m)	407.9	565.4	429.0	(27.8%)
Cash capital expenditure ($m)	452.2	550.8	419.0	(17.9%)
Net debt ($m)	2,016.6	1,240.1	1,240.1	62.6%
Net debt/equity (%)	285.8	103.8	103.8	175.3%

 

Revenue, production, and commodity prices

Sales revenue increased by $469 million ($161.1 million or 48.0%, on a pro forma basis to account for the Edison E&P acquisition) to $497.0 million primarily as a result of higher realised commodity prices and an increase in production volumes for both liquids and gas, due to the Edison E&P acquisition. Our pro forma revenue increase was driven primarily by commodity price strong recovery. The Group's realised oil and gas price for the period was $57.1/bbl and $5.2 $/mcf respectively. 

Working interest production averaged 41.0 kboepd in 2021 (2020: 3.6 kboepd or 48.3 kboepd on a proforma basis), with the Abu Qir gas-condensate field, offshore Egypt, accounting for over 70% of total output. The decrease in pro forma production was driven primarily by a decrease in production from Abu Qir and UK fields partially offset by the increase of the working interest in the Vega and Rospo fields in Italy.  

EBITDAX amounted to $212.1 million (2020: $(8.3) million or $107.7 million on a pro forma basis). The increase from 2020 proforma EBITDAX was due to higher revenue partially offset by higher operating costs from the enlarged group.

Cash cost of production 

Cash production costs for the period were $17.5 /boe (2020: $21.4 /boe or $11.3/boe on a pro forma basis). The increase in pro forma cash unit production cost was primarily driven by decreased production and additional planned maintenance during extended summer shut-downs deferred from 2020 as a result of COVID-19. Additionally, production costs were also impacted by the strengthening of Euro against the US Dollar during the period.

Depreciation, impairments and write-offs

Depreciation charges before impairment on production and development assets increased by 303.9% to $97.5 million (2020: $24.1 million or $166.3 million on a pro forma basis) due to higher DD&A charges on acquired Edison E&P assets. Depreciation unit expense was $6.5/boe (2020: $18.4/boe or $9.4/boe on a pro forma basis).

The Group recognised a pre-tax impairment charge of $65.3 million in 2020 for the Prinos CGU as a result of a reduction in both short-term (Brent forward curve) and long-term price assumptions and a change in the production forecasts for the Prinos field.  There were no such impairments for the year ended 31 December 2021

Exploration and evaluation expenditure and new ventures

During the period the Group expensed $87.7 million (2020: $4.4 million or $164.6 million on a pro forma basis) for exploration and new ventures evaluation activities. This includes costs ($79.8 million) associated with exploration and appraisal activities write-off for Glengorm South and Glengorm Central.  In 2021 two appraisal wells were drilled targeting the Glengorm South and Glengorm Central segments. Both wells were unsuccessful and did not find hydrocarbons. All wells have been plugged and abandoned. The remainder of the impairment is as a result of the increase to the decommissioning estimate in Italy.

In addition, new ventures evaluation expenditure amounted to $5.6 million (2020: $1.5 million), mainly related to pre-licence and time-writing costs.

Selling, general and administrative (SG&A) expenses

Energean incurred SG&A costs of approximately $43.0 million in 2021 (2020: $15.3 million or $41.4 million on a pro forma basis). The increase is primary driven from the additional staffing and administrative costs associated with the new acquired Edison E&P business. Cash SG&A was $34.8 million (2020: $11.7 million or $35.5 million on a pro forma basis).

Net other income

Net other income of $10.9 million in 2021 (2020: $19.1 million expenses) includes $6.8 million of income due to a decrease in estimates of decommissioning provisions for certain UK producing assets, representing the amount of the decrease that was in excess of their book value.

Unrealised loss on derivatives

The Group has recognised unrealised loss on derivative instruments of $21.5 million related to the Cassiopea contingent consideration. A contingent consideration of up to $100.0 million is payable and determined on the basis of future gas prices (PSV) recorded at the time of the commissioning of the field, which is expected in 2024.

As at 31 December 2021, the two year future curve of PSV prices increased from the date of acquisition and indicate an average price in excess of €20/Mwh. The fair value of the Contingent Consideration as at 31 December 2021 was estimated to be $78.5m based on a Monte Carlo simulation (31 December 2020: $55.2 million).

Net financing costs

Financing costs before capitalisation for the period were $278.4 million (2020: $102.7 million). including $107.0 million of interest expenses incurred on Senior Secured notes (2020: nil), $96.7 million on debt facilities (2020: $90.0 million) and $4.1 million (2020: $6.7 million) of interest expenses relating to long-term payables, representing future payments to the previous Karish & Tanin licence holders. Finance costs include mainly: unwinding of discount on deferred consideration, decommissioning provisions and other liabilities of $27.7million (2020: $1.2million);  expensing of the unamortised costs under Greek and Egypt RBL of $18.1 million, due to repayments prior to their maturity dates and arrangement fees, commissions for guarantees and other bank charges of $17.8 million (2020: $4.8 million).

Net finance costs includes foreign exchange losses of $6.9 million (2020: $15.4million foreign exchange gain). Finance income amounted to $3.0 million (2020: $0.5 million), including Interest income from time deposits.

Taxation

Energean recorded tax charges of $5.4 million in 2021 (2020: $20.5 million tax credit), split between a current and prior year tax expense of $44.5 million (2020: $0.8 million), and a deferred tax credit of $39.2 million (2020: credit $21.5 million) and representing an effective rate of 19 per cent (2020: 18 per cent).

Operating cash flow

Cash from operations before tax and movements in working capital was $136.7 million (2020: ($25.5) million). After adjusting for tax and working capital movements, cash from operations was $132.5million (2020: $1.5 million or $137.0 million on a pro forma basis). The decrease on a pro forma basis was primarily driven by payments made for buyers compensation in Israel amounting to $23.0 million and cash held on account in relation to the commodity hedges in Italy of $29.4 million.

Capital Expenditures

During the period, the Group incurred capital expenditures of $407.9 million (2020: $429 million). Capital expenditure mainly consisted of development expenditures in relation to the Karish Main and Karish North Fields in Israel ($243.4 million) , NEA project in Egypt ($52 million), Cassiopea field in Italy ($37.0 million), Scott field in UK ($11.6 million) and exploration expenditures in relation to Glengorm and Isabella in UK ($40.5 million) and Athena, Hercules, Hermes in Israel ($6.0 million).

Net Debt

As at 31 December 2021, net debt of $2,016 million (2020: $1,240 million) consisted of $2,500 million  Israeli senior secured notes,$450 million of corporate senior secured notes and $50 million of convertible loan notes, less deferred amortised fees, equity component of convertible loan ($10.5 million) and cash balances of $930.6 million. The Senior Credit Facility for the Karish-Tanin Development, the EBRD Senior Facility, the EBRD Subordinated Facility and the New Egypt RBL Facility were repaid during the year amounting to a total of $1,807 million.

In accessing the bond markets, Energean has converted floating interest rate exposure to fixed rates giving a blended average interest rate of approximately 5% and increased Energean's weighted average debt maturity to approximately six years.

Credit Ratings

Energean maintains corporate credit ratings with Standard and Poor's (S&P) and Fitch Ratings (Fitch).

On 4 November 2021 Energean plc was assigned its first corporate credit ratings from S&P and Fitch, following the issuance of the $450 million senior secured notes which mature in 2027.

1.     S&P assigned a B corporate credit rating to Energean plc and B rating for the senior secured notes maturing in 2027, with Positive Outlook.  The positive outlook reflects the expectation that Energean will successfully launch the Karish gas field in Israel in 2022, supporting the credit quality of the company.

 

2.     Fitch assigned a B+ corporate credit rating to Energean plc and B+ rating for the senior secured notes maturing in 2027, with a Stable Outlook. 

 

Risk management

Principal risks

There are no significant changes to the headline principal risks from those disclosed in the 2021 Interim results. A full description of Energean's principal risks will be disclosed in its 2021 Annual Report & Accounts.

Commodity price risk

The Group undertakes hedging activities as part of the ongoing financial risk management to protect against commodity price volatility and to ensure the availability of cash flow for re-investment in capital programmes that are driving business delivery.  Commodity hedge contracts entered into in Italy aim to mitigate the risk of changes to the cost of natural gas and that relating to the sale of natural gas.

 

Hedge position	2022	2023
Gas
Sales Volume hedged (MWs)	705,000	-
Average priced hedged (€/MWs)	55.89	-

 

At 31 December 2021, the Group's financial hedging programme on gas derivative instruments showed a pre-tax negative fair value of $12.5 million (2020: nil) included in other comprehensive income, with no ineffectiveness charge to the income statement.

 

Liquidity risk management and going concern

The Group carefully manages the risk of a shortage of funds by closely monitoring its funding position and its liquidity risk. The Going Concern assessment covers the period up to 31 March 2023 'the Forecast Period'.

Cash forecasts are regularly produced based on, inter alia, the Group's latest life of field production, budgeted expenditure forecasts, management's best estimate of future commodity prices (based on recent published forward curves) and headroom under its debt facilities.  The Base Case cash flow model used for the going concern assessment conservatively assumes first gas from Karish in October 2022, Brent at $80/bbl in 2022 and $75/bbl in 2023 and PSV (Italian gas price) at EUR55/MWH in 2022 and EUR40/MWH in 2023.

In addition, on a regular basis, the Group performs sensitivity tests of its liquidity position to evaluate adverse impacts that may result from changes to the macro-economic environment such as a reduction in commodity prices.  The Group is not exposed to floating interest rate risk.  The Group also looks at the impact of changes or deferral of key projects.  This is done to identify risks to liquidity to enable management to formulate appropriate and timely mitigation strategies in order to manage the risk of funds shortfalls and to ensure the Group's ability to continue as a going concern.  Such assumptions underpin management's reasonable worst case scenario to further assess the robustness of the Group's liquidity position over the Forecast Period.

Reverse stress testing was performed to determine what levels of prices and/or production would need to occur for the liquidity headroom to be eliminated, prior to any mitigating actions; the likelihood of such conditions occurring was concluded to be remote.  In the event an extreme downside scenario occurred, prudent mitigating actions could be executed in the necessary timeframe such as a tightening of operating costs and reductions/postponement of other discretionary exploration and development expenditures. There is no material impact of climate change within the Forecast Period therefore it does not form part of the reverse stress testing performed by management.

1.     As of 31 December 2021 the Group's available liquidity was approximately $1 billion.  In terms of the Group's Borrowing Facilities, the following was considered as part of management's assessment:  Energean Israel Project Bond:

In March 2021 Energean raised $2.5 billion through the issuance of bonds to (i) refinance its $1.45 billion Israel Project Finance Facility, (ii) cancel and replace the $700 million Term Loan which was drawn to fund the acquisition of Kerogen's minority interest in Energean Israel, (iii) fund capital and exploration expenditure in Israel, including Karish and Karish North, and (iv) for general corporate purposes of the Group.

2.     Energean plc Corporate Bond:

In November 2021 Energean raised a $450 million Bond to (i) repay all amounts outstanding under the Egypt and Greek RBLs plus subordinated debt, (ii) to pay fees and other expenses related to the Bond, and (iii) for general corporate purposes of the Group.

There are no financial maintenance covenants associated with either of the Bonds.

3.     Greek State-Backed Loan

In December 2021 Energean signed a EUR100 million loan backed by the Greek State which is to be used specifically for the development of the Prinos Area in Greece, including the Epsilon development.

In forming its assessment of the Group's ability to continue as a going concern, including its review of the forecasted cashflow of the Group over the Forecast Period, the Board has made judgements about:

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

• the Group's ability to implement the mitigating actions within the Group's control, in the event this were required.

After careful consideration, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future, for the Forecast Period to 31 March 2023. For this reason, they continue to adopt the going concern basis in preparing the consolidated financial statements.

 

Events since December 2021

On 14 March 2022 - Energean signed a supply agreement with the Israel Electric Company, the largest Israeli buyer of natural gas. IEC will now have the right to purchase natural gas from Energean's fields. The gas price will be determined in each period, with purchased amounts determined on a daily basis. Starting upon the commencement of first gas production from Karish, the agreement will be valid for an initial one-year period with an option to extend subject to ratification by both parties.

 

 

Non-IFRS measures

The Group uses certain measures of performance that are not specifically defined under IFRS or other

generally accepted accounting principles. These non-IFRS measures include Adjusted EBITDAX, cost

of production, capital expenditure, cash capital expenditure, net debt and gearing ratio and are

explained below.

 

Cash cost of production

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

	2021	Pro forma 2020	2020
	$m	$m	$m
Cost of sales	345.1	364.6	48.4
Less:
Depreciation	(94.6)	(163.1)	(22.1)
Change in inventory	11.1	(2.6)	2.2
Cost of production	261.6	198.9	28.5
Total production for the period (kboe)	14,963.5	17,621.0	1,331.0
Cash cost of production per boe ($/boe)	17.5	11.3	21.4

 

Adjusted EBITDAX

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

	2021	Pro forma 2020	2020
	$m	$m	$m
Adjusted EBITDAX	212.1	107.7	(8.3)
Reconciliation to profit/(loss):
Depreciation and amortisation	(97.5)	(166.3)	(24.1)
Share-based payment	(5.7)	(3.2)	(3.2)
Exploration and evaluation expense	(87.7)	(164.6)	(4.4)
Impairment loss on property, plant and equipment	-	(182.9)	(65.3)
Other expense	(7.0)	(35.0)	(28.3)
Other income	17.9	22.1	9.1
Finance expenses	(97.4)	(16.9)	(5.0)
Finance income	3.0	1.2	0.4
Unrealised loss on derivatives	(21.5)	-	-
Net foreign exchange	(6.9)	7.8	15.5
Taxation income/(expense)	(5.4)	13.7	20.7
Loss for the year	(96.2)	(416.4)	(92.9)

 

Capital expenditure

Capital expenditure is a useful indicator of the Group's organic expenditure on oil and gas assets and exploration and appraisal assets incurred during a period. Capital expenditure is defined as additions to property, plant and equipment and intangible exploration and evaluation assets less decommissioning asset additions, right-of-use asset additions, capitalised share-based payment charge and capitalised borrowing costs:

	2021	Pro forma 2020	2020
	$m	$m	$m
Additions to property, plant and equipment	521.4	659.1	550.6
Additions to intangible exploration and evaluation assets	54.8	108.1	11.8
Less:	168.2	201.8	133.4
Capitalised borrowing cost	181.0	97.7	97.7
Leased assets additions and modifications	8.7	17.2	2.0
Lease payments related to capital activities	(10.9)	(12.0)	(6.6)
Capitalised share-based payment charge	0.2	0.1	0.1
Capitalised depreciation	0.2	0.6	0.6
Change in decommissioning provision	(11.0)	98.2	39.6
Total capital expenditures	408.0	565.4	429.0
Movement in working capital	44.3	14.6	10.0
Cash capital expenditures per the cash flow statement	452.3	550.8	419.0

 

Cash Capital Expenditure

	2021	2020
	$m	$m
Payment for purchase of property, plant and equipment	403,503	403,986
Payment for exploration and evaluation, and other intangible assets	48,674	15,041
Total Cash Capital Expenditure	452,177	419,027

 

 

 

Net debt/(cash) and gearing ratio

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

 

	2021	2020
	$m	$m
Current borrowings	-	1,113.0
Non-current borrowings	2,947.1	330.0
Total borrowings	2,947.1	1,443.0
Less: Cash and cash equivalents and bank deposits	(730.8)	(202.9)
Restricted cash	(199.7)	-
Net Debt (1)	2,016.6	1,240.1
Total equity (2)	717.1	1,194.4
Gearing Ratio (1)/(2)	281.2%	103.8%

 

 

 

Forward looking statements

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