Energean plc

("Energean" or the "Company")

 

2022 Full Year Results

 

London, 23 March 2023 - Energean plc (LSE: ENOG, TASE: אנאג) is pleased to announce its audited full-year results for the year ended 31 December 2022 ("FY 2022").

 

Mathios Rigas, Chief Executive of Energean, commented:

"2022 was a year of transformation for Energean - where a long-held vision became an operational reality. It was a year of positive delivery. We commenced production from the only FPSO in the strategically vital Eastern Mediterranean region, paid dividends to our shareholders, and laid the foundation for our future growth through the discovery and de-risking of new natural gas resources adjacent to our infrastructure. Energean was the sole owner-operator of five deepwater wells, which drove a 20% increase in our reserve base, and marked the 15^th consecutive year of reserve and resource base increases for Energean. We are proud to be on track to deliver between 4.5 and 5.5 bcm of gas into the Israeli domestic gas market this year, contributing towards the security of energy supply of the region and improving the living conditions of the Israeli public through the reduction of emissions from the displacement of coal-fired power generation.

"The first quarter of 2023 has continued the positive trend. Production from Karish is in line with our expectations, and in February we supplied the first Israeli hydrocarbon liquids export cargo to international markets. In Egypt, we achieved first gas at NEA/NI with three further wells due to come onstream during the year. In Italy, we are the third largest producer of natural gas and look forward to increasing our contribution towards the country's energy supply. And in Greece, we are continuing our efforts to explore the untapped resources of the country.

"The remainder of 2023 will see us present the development concept for the Olympus Area, offshore Israel, and increase the capacity of the Energean Power FPSO to 8 bcm/yr. This is alongside delivery of production in line with guidance plus on-target returns, as promised, to our shareholder base. Through our gas contracting strategy we are in a unique position to have a very predictable and stable cashflow despite turbulence and challenges in the international financial markets.

"We are committed to investing in projects where we can create value for all stakeholders. The global energy crisis is not over - the global gas market remains dangerously tight and benefitted from a mild European winter, but thousands of industrial jobs are now at risk not just to price but also to availability. We therefore hope that governments understand the value of enhanced domestic and regional energy production, that can only be delivered through long-term investment."

Highlights

·      Delivered first gas from Karish in October 2022

o  Production and ramp up in line with expectations

o  Energean is now sequentially notifying gas buyers that the commissioning period under the gas sales and purchase agreements ("GSPAs") has ended and the start date for commercial obligations has commenced. The Company expects to have completed this process for all gas buyers by the end of March 2023

·      Initiated hydrocarbon liquid exports from Karish field to international markets

·      Delivered first production from NEA/NI, Egypt, in March 2023

·      On track to deliver 200 kboed production target in 2H 2024

·      Confirmed year-end 2P reserves of 1,161 mmboe (+20% increase versus end-2021) representing a reserve replacement ratio of 1400%

o  Including the addition of 31 bcm (approximately 206 mmboe) of 2P reserves in the Olympus Area, offshore Israel, that have now been certified by Energean's reserves auditor, Degolyer and McNaughton ("D&M")

·      Delivered strong financial performance, underpinned by strong commodity prices

o  2022 revenues of $737.1 million, represented a 48.3% increase (2021: $497.0 million)

o  2022 EBITDAX of $421.6 million, represented a 98.8% increase (2021: $212.1 million)

o  2022 profit-after-tax of $17.3 million was an improvement on last year's loss (2021: $(96.2) million). Profit after tax was negatively impacted by $119.4 million of windfall taxes in Italy[1], which we expect have been applied on a one-off basis

o  Group cash as of 31 December 2022 was $502.7 million (including restricted amounts of $74.8 million) and total liquidity was $720.0 million. In March 2023, Energean signed a $350 million term loan which, although expected to remain undrawn, provides additional financial flexibility

·      Announced dividend strategy and initiated dividend payments

o  Cumulative dividends paid of 60 US$ cents with a further 30 US$ cents declared and will be paid on 30 March 2023, representing an annualised yield of approximately 9%[2].

·      Carbon Disclosure Project ("CDP") rating increased to A- (from B), outperforming the global average for E&Ps of C

 

Outlook

·      2023 production guidance confirmed at 131 - 158 kboed, including 4.5 - 5.5 bcm of gas from Karish

·      Mid-term targets now considered near-term: on track to achieve production, financial targets and leverage targets in 2H 2024[3] through execution of key development projects

o  Karish growth projects to increase the capacity of the Energean Power FPSO are on track for year-end 2023, following which Israel production is expected to be 140 - 155 kboed on plateau

o  Three additional wells to be brought onstream at NEA/NI by year-end 2023, following which production in Egypt is expected to be more than 40 kboed

o  Cassiopea expected to deliver first gas in 2024, following which production in Italy is expected to be approximately 20 kboed

·      Communication of development concept for the Olympus Area expected in the coming months

·      Orion-1X well, Egypt, (Energean 30%, expected to farm down to 18%) expected to spud in late 2023, slightly delayed due to rig availability

·      Declaration of quarterly dividends in line with previously communicated policy

o  $50 million per quarter initially, rising to $100 million per quarter following achievement of near-term targets

o  Cumulative dividends of at least $1 billion by end-2025

o  Post-2025 target to maintain a progressive dividend policy, underpinned by existing reserve volumes

 

Financial Summary

 

		FY 2022	FY 2021	% Change
Average working interest production	kboed	41.2	41.0	0.5%
Sales and other revenue	$ million	737.1	497.0	48.3%
Cash Cost of Production	$ million	284.3	261.6	8.7%
Adjusted EBITDAX[4]	$ million	421.6	212.1	98.8%
Profit/(loss) after tax	$ million	17.3	(96.2)	118.0%
Capital expenditure	$ million	728.8	403.5	80.6%
Exploration expenditure	$ million	141.0	48.7	189.5%
Decommissioning expenditure	$ million	8.9	2.7	229.6%
Cash (including restricted amounts)	$ million	502.7	930.5	(46.0%)
Net debt - consolidated	$ million	2,518.2	2,016.6	24.9%
Net debt - plc excluding Israel	$ million	143.8	102.6	40.2%
Net debt - Israel	$ million	2,374.4	1,914.0	24.1%

 

 

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/o83rjj7h

 

Conference call registration link: https://register.vevent.com/register/BI8d6748462e8b4aa68a4f11f2d7e52ef2

 

After completing your conference call registration you will receive dial-in details on screen and via email. Please note the dial-in pin number is unique and cannot be shared.

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

Enquiries

For capital markets: [email protected]

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

 

For media: [email protected]

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

 

Operational Review

Production and Reserves

Full year 2022 working interest 2P reserves were 1,161 mmboe, a 20% increase versus 2021 (965 mmboe) and representing a reserve replacement ratio of 1400%. The year-on-year changes are due mainly to:

·      Certification of 2P reserves of 31 bcm (approximately 206 mmboe) in the Athena, Zeus and Hera structures in block 12, Olympus Area, Israel

·      Offset by 15 mmboe of production across the portfolio

	2022 2P Reserves mmboe (% gas)	2021 2P Reserves mmboe (% gas)	% increase / (decrease)
Israel	940 (89%)	744 (86%)	26%
Egypt	99 (87%)	103 (87%)	(4%)
Rest of Portfolio	122 (38%)	119 (59%)	3%
Total	1,161 (84%)	965 (81%)	20%

 

Production

 

In 2022, total production was 41.2 kboed

 

·      Production excluding Israel was 35.7 kboed, the mid-point of the guidance range of 34.0 - 37.0 kboed.

 

·      Israel 2022 production was lower than forecast due to the project being in the commissioning phase in 2022, as previously communicated.

 

2023 is expected to be a critical year for Energean and a key step towards its near-term goal of 200 kboed, which it expects to achieve in 2H 2024 (annualised). Energean maintains the guidance range of 131 - 158 kboed that was communicated in its January trading update

 

·      Underlying production (excluding Israel) is expected to increase by approximately 12% at the mid-point of the guidance range (2023: 37.0 - 43.0 kboed), benefitting from contribution by the NEA/NI development, offshore Egypt.

 

·      Israel gas production is expected to be between 4.5 and 5.5 bcm of sales; year-to-date production has ramped up in line with expectations.

Further to the progress of commissioning activities on the Karish Field and the Energean Power FPSO, Energean is now sequentially notifying gas buyers that the commissioning period under the GSPAs has ended and the start date for commercial obligations has commenced. Energean expects to have completed this process for all gas buyers by the end of March 2023.

 

·      The first sale of Karish hydrocarbon liquids was completed in February 2023, and Energean expects Israel to contribute 15 - 18 kboed of hydrocarbon liquids production in 2023, at an estimated one lifting per month.

 

	2022 kboed (% gas)	2021 kboed (% gas)	% increase / (decrease)
Israel	5.4 (92%)	-	-
Egypt	25.1 (87%)	29.1 (87%)	(14%)
Rest of portfolio	10.7 (40%)	11.9 (36%)	(10%)
Total	41.2 (75%)	41.0 (72%)	0%

 

 

Development

Israel - Karish Growth Projects

During 2023, Energean will complete installation of the second gas export riser and second oil train, whilst also delivering first production from Karish North. Combined, these projects will increase the total capacity of the FPSO to a maximum of 8 bcm/yr.

·      The second export riser and the Karish North flowline were transported from the UK to Israel in March 2023. The riser will be installed shortly and will connect the production facilities on the FPSO to the pipeline-to-shore.

·      Key upcoming activities ahead of Karish North first gas include installation of the Karish North manifold, umbilical and spool, ahead of opening of the well before year-end 2023.

·      Construction of the second oil train is progressing in line with expectations in Dubai. The oil train will be installed and commissioned in-situ, and is expected to be ready to process hydrocarbon liquids by year-end 2023.

Israel - Olympus

D&M has certified 31 bcm (approximately 206 mmboe) of 2P reserves and 37 bcm (approximately 237 mmboe) of unrisked prospective resources in the Olympus Area, which is located in block 12 and the Tanin lease, offshore Israel. The associated Competent Person's Report ("CPR") will be made available on Energean's website.

The addition to Energean's development portfolio was a direct result of its successful 2022 growth drilling campaign. The Zeus and Athena wells, both in block 12, discovered 25 bcm (approximately 167 mmboe) of natural gas resources. D&M's analysis determined that the proximate Hera prospect, was also sufficiently de-risked to be classified as 2P reserves. Together, these total 31 bcm of 2P reserves, as mentioned above.

Energean is finalising the development concept for the combined 68 bcm of reserves and de-risked prospective resources that will underpin this development. Several development concepts are under evaluation, and Energean is focused on delivering the optimal solution to align with its goal of maximising stakeholder returns.

The CPR provides an indicative profile and economics for one of these potential options, although readers should note that D&M includes only the Olympus 2P within the overall profile, whilst the actual development will also envisage the development of the 37 bcm of de-risked prospective resources. The production profile in the CPR envisages the Olympus development being positioned between that of Karish North and Tanin, with block 12 economics benefitting compared to those of Tanin owing to its closer proximity to the FPSO and absence of royalties payable to the original seller of the Karish and Tanin leases.

Energean is also considering development options to access key regional export markets and also to further increase the overall capacity of its infrastructure through the addition of a third gas processing train.

 

Egypt

NEA/NI

In January 2021, Energean sanctioned the NEA/NI project, located in shallow water, offshore Egypt and adjacent to the producing Abu Qir field. First gas from NEA/NI was successfully delivered in March 2023 from the NEA#6 well, approximately two years and two months following final investment decision.

NEA/NI contains an estimated 39 mmboe[5] of 2P reserves (88% gas) with net working interest production expected to peak at 15 - 20 kboed (88% gas) in 2024. The development leverages existing infrastructure and involves the subsea tieback of four wells to Energean's North Abu Qir PIII platform; the first well is now onstream with the remaining three wells expected onstream during 2023.

 

Abu Qir drilling programme

Following the completion of the NEA/NI drilling programme, Energean expects to use the El Qaher-1 rig to drill four production wells on the Abu Qir licence. First gas from these wells is expected throughout 2024. 

Rest of portfolio

Cassiopea, Italy

First gas from Cassiopea (W.I. 40%) is expected in 2024. Onshore work is progressing well and offshore installation activities are expected to begin in Q2 2023. The operator expects to start drilling activities in the summer 2023, which includes two new wells and two recompletions.

Epsilon, Greece

First oil from Epsilon continues to be expected in 2024. The installation of the platform jacket at the field is expected to take place in Q2 2023.

 

Exploration and Appraisal

Egypt

North East Hap'y Offshore

Orion X1 well (Energean, 30%), located on the North East Hap'y block, offshore Egypt, is expected to spud in late 2023, which has been delayed due to rig availability. Energean expects to farm down its interest in the licence to 18% ahead of spudding the well.

Rest of Portfolio

The Izabela-9 well (Energean, 70%) located offshore Croatia, is expected to spud in Q2/Q3 2023.

Energean also expects to participate in two exploration wells (W.I. 40%), offshore Sicily in Italy, with its partner ENI (60%) in 2024. The low-risk Gemini and Centauro prospects are located close to the Cassiopea development, for which the infrastructure contains tie-in points for future discoveries.

 

2023 Guidance

	FY 2023
Production
Israel (kboed)	94 - 115 (including 4.5 - 5.5 bcm of sales gas)
Egypt (kboed)	28 - 32
Rest of portfolio (kboed)	9 - 11
Total production (including Israel, kboed)	131 - 158
Total production (excluding Israel, kboed)	37 - 43
Consolidated net debt ($ million)	2,600 - 2,800
Cash Cost of Production (operating costs plus royalties)
Israel ($ million)	350 - 400
Egypt ($ million)	50 - 60
Rest of portfolio ($ million)	200 - 240
Total Cash Cost of Production ($ million)	600 - 700
Development and production capital expenditure
Israel ($ million)	140 - 160
Egypt ($ million)	140 - 150
Rest of portfolio ($ million)	300 - 330
Total development & production capital expenditure ($ million)	580 - 640
Exploration expenditure ($ million)	40 - 60
Decommissioning expenditure ($ million)	30 - 40

Corporate Review

HSE

In 2022, Energean delivered another strong HSE record with zero serious injuries recorded. The Loss Time Injury Frequency ("LTIF") Rate of 0.47 (2021: 0.33) and Total Recordable Incident Rate ("TRIR") of 1.18 (2021: 0.77) were lower than their respective targets of 0.50 and 1.20.

 

Financing

Energean ended 2022 with total available liquidity of $720 million (2021: approximately $1 billion), including undrawn amounts of $174 million under the Revolving Credit Facility signed in September 2022[6]. Following the signature of the term loan in March 2023, liquidity has increased to over $1 billion. This position ensures that the Company is well-funded for its projects-under-development.

Energean undertook a series of refinancings in 2021, which fixed nearly all of the Company's exposure to floating rates; Energean's average cost of debt in 2022 was 5.25% and substantially unimpacted by the global rise in interest rates. The only facility within Energean's capital structure that is impacted by global interest rate rises is the €90.5 million Greek facility and therefore the impact of the rate rises on the overall cost of debt has been minimal.

In 2024, the first tranche of Energean Israel Finance Limited's senior secured notes, is set to mature. The note is for an amount of $625 million and carries a coupon rate of 4.5%. Energean is currently considering its options to refinance this note, the preferred option for which is a repeat structure issuance in the debt capital markets.

Energean remains committed to its near-term target of reducing leverage, which it defines as net debt / EBITDAX, to below 1.5x. The company's EBITDAX stream is underpinned by long-term contracts with floor pricing provisions and take-or-pay and/or exclusivity provisions, which gives the Board confidence that, in the absence of additional projects, maintaining gross debt within the business at or around current levels represents an appropriate capital structure.

On the 17 March 2023 Energean also signed an unsecured $350 million two year term loan facility, which offers additional financial flexibility for the Group. The loan is expected to remain undrawn.

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 - 9 kgCO2/boe by 2025, a reduction of more than 85% versus the base year of 2019, the key driver being the influence of Karish, which has a very low carbon emissions intensity of 4 - 5 kgCO2/boe. The Group recorded full-year 2022 emissions intensity of 16.0 kgCO2/boe, a 13% year-on-year reduction, and expects to further reduce emissions intensity to 7 - 9 kgCO2/boe in 2023.

The Prinos CCS project proposal is to provide long-term storage for carbon dioxide emissions captured from both local and more remote emitters, and is proposed to be a scaleable CO2 injection and storage project leveraging existing onshore and offshore infrastructure that is fully owned and operated by Energean.

ESG ratings and affirmation

In December 2022, the Carbon Disclosure Project ("CDP") upgraded its Climate Change rating for Energean to A-, from B in the previous year, outperforming the global average of E&P peers of C. Also in 2022, Energean was rated AA by MSCI (for the second year running), 76 out of 280 for E&Ps by Sustainalytics (top 30%), platinum by the Maala Index (increased from gold) and awarded the "Best ESG Energy Growth Strategy Europe 2022" by CFI for a second year running.

In August 2022, Energean was confirmed as a constituent of the FTSE4Good Index Series, following the its June 2022 review. The FTSE4Good Index Series is designed to measure the performance of companies demonstrating strong ESG practices.

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.

Financial Review

Financial results summary

	2022	2021	Change from 2021
Average working interest production (kboepd)	41.2	41.0	0.5%
Revenue ($m)	737.1	497.0	48.3%
Cash cost of production ($m)	284.3	261.6	8.7%
Cost of production ($/boe)	18.9	17.5	8.1%
Administrative & selling expenses ($m)	45.9	43.0	6.7%
Operating profit ($m)	232.2	32.1	623.4%
Adjusted EBITDAX ($m)	421.6	212.1	98.8%
Profit/ (Loss) after tax ($m)	17.3	(96.2)	118.0%
Cash flow from operating activities ($m)	272.2	132.5	105.4%
Capital expenditure ($m)	869.8	407.9	113.2%
Cash capital expenditure ($m)	460.2	452.2	1.8%
Net debt ($m)	2,518.2	2,016.6	24.9%
Net debt/equity (%)	387.3	281.2	37.7%

 

Revenue, production, and commodity prices

Revenue increased by $240.1 million (2021: $497.0 million) to $737.1 million primarily a result of higher realised commodity prices. The Group's realised weighted average pre-hedging oil and gas price for the year was $81.2/bbl (2021: $57.1/bbl) and $11.2/mcf (2021:5.2 $/mcf), respectively. 

Working interest production averaged 41.2 kboepd in 2022 (2021: 41.0 kboepd), with the Abu Qir gas-condensate field, offshore Egypt, accounting for over 60% of total output.

Adjusted EBITDAX amounted to $421.6 million (2021: $212.1 million). The increase from 2021 was due to higher revenue partially offset by slightly higher operating costs from the enlarged group. Included within revenue is the realised loss on the PSV (Italian gas price) hedges of $55.2 million, excluding this lost revenue would result in an adjusted EBITDA of $476.8 million; which is an increase of $264.7million (124.5%) compared to 2021.

Cash cost of production

Cash production costs for the period were $18.9 /boe (2021: $17.5/boe). The increase in cash unit production cost was primarily driven by increased royalties paid (2022: $45.8 million, 2021:$24.8million) and increased energy costs across the group. The cash production costs excluding royalties are $238.5 million (2021: $236.8million) and the related cost per boe is $15.9 (2021: $:15.8)

Depreciation, impairments and write-offs

Depreciation charges before impairment on production and development assets decreased by 14.6% to $83.3 million (2021: $97.5 million) with the related decrease in the depreciation unit expense to $5.5/boe (2021: $6.5/boe).

The Group recognised a pre-tax impairment charge of $27.6million (2021: $0million) in 2022, a result of revisions to decommissioning estimates on the Group's non-producing assets, in Italy and UK.. The Group performed an impairment assessment at 31 December 2022 and did not identify any cash generating units ("CGU") for which a reasonably possible change in a key assumption would result in impairment or impairment reversal, except for the Vega oil field in Italy. An 8% decrease in Brent prices would eliminate the current headroom of the Vega CGU.   

Management has considered how the Group's identified climate risks and climate related goals may impact the estimation of the recoverable amount of cash-generating units and as part of the impairment assessment has run sensitivity scenarios for the IEA's 2022 WEO climate scenarios (Stated Policies Scenario (STEPS), Announced Pledges Scenario (APS) and Net-Zero Emissions by 2050 Scenario (NZE)). The Groups CGUs in Italy (Vega) and Greece are the most sensitive to the impact of the IEA scenarios, which applied, with no management mitigating actions taken, could result in impairment.

The anticipated extent and nature of the future impact of climate on the Group's operations and future investment, and therefore estimation of recoverable value, is not uniform across all cash-generating units. There is a range of inherent uncertainties in the extent that responses to climate change may impact the recoverable value of the Group's CGUs, with many of these being outside the Group's control. These include the impact of future changes in government policies, legislation and regulation, societal responses to climate change, the future availability of new technologies and changes in supply and demand dynamics.

Exploration and evaluation expenditure and new ventures

During the period the Group expensed $71.4 million (2021: $87.7 million) for exploration and new ventures evaluation activities. This includes impairment costs of $65.7million ($82.1 million) for projects that will not progress to development, primarily Glengorm; Energean will exit the Glengorm licence  within 2023.

In addition, new ventures evaluation expenditure amounted to $5.8 million (2021: $5.6 million), mainly related to pre-licence and time-writing costs.

General and administrative (G&A) expenses

Energean incurred G&A costs of approximately $45.9 million in 2022 (2021: $43.0 million). Cash SG&A was $36.0 million (2021: $34.8 million).

Cash G&A excludes certain non-cash accounting items from the Group's reported G&A. Cash G&A is calculated as follows: Administrative and Selling and distribution expenses, excluding depletion and amortisation of assets and share-based payment charge that are included in G&A.

	2022 ($m)	2021 ($m)
Administrative expenses	45.9	43.0
Less:
Depreciation	3.9	2.5
Share-based payment charge included in G&A	6.0	5.7
Cash G&A	36.0	34.8

 

 

Net other expenses

Net other expenses of $1.0 million in 2022 (2021: $10.9 million income) includes restructuring costs ($3.2million), net reversal of expected credit loss  provisions of $7.9 million and other non-recurring items. In 2021 the amount predominantly related to $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 $5.2 million (2021: $21.5million) related to the Cassiopea contingent consideration. A contingent consideration of up to $100.0 million is payable and determined on the basis of future Italian gas prices recorded at the time of the commissioning of the field, which is expected in 2024.

As at 31 December 2022, the two- year Italian gas (PSV) futures curve indicated higher pricing than that at the date of acquisition, with a forward price in excess of €20/Mwh. As a result, the fair value of the Contingent Consideration as at 31 December 2022 was estimated to be $86.3 million based on a Monte Carlo simulation (31 December 2021: $78.5 million).

Net financing costs

Financing costs before capitalisation for the period were $236.7 million (2021: $278.4 million). Finance costs include: $167.4 million of interest expenses incurred on Senior Secured notes (2021: $107.0 million), $1.5million on debt facilities (2021: $96.7 million), $14.7million of interest expenses relating to long-term payables (2021:$4.1 million), $37.4million unwinding of discount on deferred consideration, contingent consideration, convertible loan notes and decommissioning provisions (2021: $27.8 million); $15.6 million commissions for guarantees and other bank charges of (2021: $17.8 million). The 2021 finance costs included $18.1million for unamortised debt issuance costs under the Greek and Egypt RBL, written off due to repayments prior to their maturity dates.

Net finance costs include foreign exchange losses of $22.2 million (2021: $6.9 million) and finance income of $9.6 million (2021: $3.0 million), including Interest income from time deposits.

Taxation

Energean recorded tax charges of $89.7 million in 2022 (2021: $5.4 million), split between a current year tax expense of $200.1 million (2021: $44.6 million), and a deferred tax credit of $110.4 million (2021: credit $39.2 million) and representing an effective tax rate of 84% (2021: 6%).

The increase in current tax from 2021 is primarily a result of the windfall tax in Italy. During 2022, Italy introduced: 1) a windfall tax in the form of a law decree which imposed a 25% one-off tax on profit margins that rose by more than $5.26 million (€5.0 million) between October 2021 and April 2022 compared to the same period a year earlier. The amount of the windfall tax paid by Energean Italy was $29.3million and 2) in November 2022, Italy introduced a new windfall tax that imposed a 50% one-off tax, calculated on 2022 taxable profits that are 10% higher than the average taxable profits between 2018-2021. This amount has a ceiling equal to 25% of the value of the net assets at end-2021. Based on this, Energean would be required to pay an additional one-off tax of $92.8 million (€87.0 million) in June 2023.

Operating cash flow

Cash from operations before tax and movements in working capital was $311.3million (2021: $131.7 million). After adjusting for tax and working capital movements, cash from operations was $272.2 million (2021: $132.5 million).

Capital Expenditure

During the year, the Group incurred capital expenditure of $869.8 million (2021: $407.9 million). Capital expenditure mainly consisted of development expenditure in relation to the Karish Main and Karish North Fields in Israel ($534.5 million) , NEA/NI project in Egypt ($107.9 million), Cassiopea field in Italy ($77.0 million), Scott field in UK ($9.2 million) and exploration expenditures in Athena, Zeus, Hermes and Hercules in Israel ($123.0 million).

Net Debt

As at 31 December 2022, net debt of $2,518.2million (2021: $2,016 million) consisted of $2,500 million Israeli senior secured notes, $450 million of corporate senior secured notes, $63.5million draw down of the Greek loans and $50 million of convertible loan notes, less deferred amortised fees, equity component of convertible loan ($10.5 million) and cash balances of $502.7 million. Net debt excluding Israel is $143.8 million (2021: $102.6 million).

In accessing the debt capital markets, Energean is only exposed to floating interest rates for the Greek loan. Refer to note 26.3 in the financial statements for the interest risk sensitivity.

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.

·      In February 2023 S&P upgraded the ratings from B to B+ for both Energean plc  corporate and the senior secured notes maturing in 2027, with Stable Outlook. This reflects first gas from the Karish field in Israel and associated track record of production.

·      Fitch assigned a B+ corporate credit rating to Energean plc and B+ rating for the senior secured notes maturing in 2027.  In November 2023 the Outlook was upgraded to Positive to reflect the improvement in financial performance since 2021, due to stronger price environment and timely delivery projects including the Karish gas field in Israel.

Risk management

Principal risks

There are no significant changes to the headline principal risks from those disclosed in the 2022 Interim results. A full description of Energean's principal risks is disclosed in the strategic review of the 2022 Annual Report & Accounts.

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 from the date of approval of the Group Financial Statements on 22 March 2023 to 30 June 2024 'the Assessment Period'. The Assessment Period has been extended such that it includes the $625 million bond repayment due in March 2024.

As of 31 December 2022 the Group's available liquidity was approximately $720 million.  This available liquidity figure includes: (i) c. $43 million of undrawn facility under the EUR100 million loan backed by the Greek State signed in December 2021 for the development of the Prinos Area in Greece, including the Epsilon development; and (ii) c. $174 million available under the $275 million Revolving Credit Facility ('RCF') signed by the Group in September 2022 (with the remainder being utilized to issue Letters of Credit for the Group's operations). Subsequent to 31 December 2022, the Group signed a $350 million Term Loan Facility. The Group has a $625 million bond, at the Energean Israel level, maturing in March 2024.  Management expects to refinance this bond during 2023; however, for the purposes of the Going Concern assessment it has been assumed that the bond is repaid in full and not refinanced.

The going concern assessment is founded on a cashflow forecast prepared by management, which is based on a number of assumptions, most notably the Group's latest life of field production forecasts, budgeted expenditure forecasts, estimated of future commodity prices (based on recent published forward curves) and available headroom under the Group's debt facilities.  The going concern assessment contains a 'Base Case' and a 'Reasonable Worst Case' ('RWC') scenario.

 

The Base Case scenario assumes Brent at $80/bbl in 2023 and $75/bbl in 2023 and PSV (Italian gas price) at EUR50/MWH in 2023 and EUR45/MWH in 2024. A reasonable ramp-up of production from the Karish Field is assumed throughout the going concern assessment period, with prices for gas sold assumed at contractually agreed prices. Under the Base Case, sufficient liquidity is maintained throughout the going concern period.

 

The Group also routinely 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. These downsides are considered in the RWC going concern assessment scenario. The Group is not materially exposed to floating interest rate risk since the majority of its borrowings are fixed-rate.  The Group also looks at the impact of changes or deferral of key projects and downside scenarios to budgeted production forecasts in the RWC.

The two primary downside sensitivities considered in the RWC are: (i) reduced commodity prices; (ii) reduced production - these downsides are applied to assess the robustness of the Group's liquidity position over the Assessment Period.  In a RWC downside case, there are appropriate and timely mitigation strategies, within the Group's control, to manage the risk of funding shortfalls and to ensure the Group's ability to continue as a going concern.  Mitigation strategies, within management's control, modelled in the RWC include deferral of capital expenditure on operated assets, deferral or cancellation of exploration and/or discretionary spend and exercise of rights under contractual arrangements to improve liquidity. Under the RWC scenario, after considering mitigation strategies, liquidity is maintained throughout the going concern period.

Reverse stress testing was also performed to determine what commodity price or production shortfall would need to occur for liquidity headroom to be eliminated. The conditions necessary for liquidity headroom to be eliminated are judged to have a remote possibility of occurring, given the diversified nature of the Group's portfolio and the 'natural hedge' provided by virtue of the Group's fixed-price gas contracts in Israel and Egypt.  In the event a remote downside scenario occurred, prudent mitigating strategies, consistent with those described above, could also be executed in the necessary timeframe to preserve liquidity. There is no material impact of climate change within the Assessment Period and therefore it does not form part of the reverse stress testing performed by management.

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 these actions were required.

After careful consideration, the Directors are satisfied that the Group and Company has sufficient financial resources to continue in operation for the foreseeable future, for the Assessment Period from the date of approval of the Group Financial Statements on 22 March 2023 to 30 June 2024. For this reason, they continue to adopt the going concern basis in preparing the consolidated financial statements.

 

Events since December 2022

On the 9 February 2023 Energean declared its 4Q dividend of US$30 cents per share, to be paid on 30 March 2023.

On the 17 March 2023 Energean also signed an unsecured $350 million two year term loan facility, which offers additional financial flexibility for the Group. The loan is expected to remain undrawn.

 

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.

($m)	2022	2021
Cost of sales	358.9	345.1
Less:
Depreciation	(79.4)	(94.6)
Change in inventory	4.7	11.1
Cost of production1	284.3	261.6
Total production for the period (kboe)	15,038.0	14,963.5
Cash cost of production per boe ($/boe)	18.9	17.5

^{1Numbers may not sum due to rounding}

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.

($m)	2022	2021
Adjusted EBITDAX	421.6	212.1
Reconciliation to profit/(loss):
Depreciation and amortisation	(83.4)	(97.5)
Share-based payment	(6.0)	(5.7)
Exploration and evaluation expense	(71.4)	(87.7)
Impairment loss on property, plant and equipment	(27.6)	-
Other expense	(15.2)	(7.0)
Other income	14.1	17.9
Finance expenses	(107.3)	(97.4)
Finance income	9.6	3.0
Unrealised loss on derivatives	(5.2)	(21.5)
Net foreign exchange	(22.2)	(6.9)
Taxation income/(expense)	(89.7)	(5.4)
Profit/ (Loss) for the year	17.3	(96.2)

 

 

 

 

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:

($m)	2022	2021
Additions to property, plant and equipment	877.7	521.4
Additions to intangible exploration and evaluation assets	141.0	54.8
Less:
Capitalised borrowing cost	109.2	181.0
Impairment of property, plant and equipment	27.9
Leased assets additions and modifications	2.0	8.7
Lease payments related to capital activities	(12.7)	(10.9)
Capitalised share-based payment charge	0.2	0.2
Capitalised depreciation	0.6	0.2
Change in decommissioning provision	21.7	(11.0)
Total capital expenditure	870.0	408.0
Movement in working capital	(409.8)	44.3
Cash capital expenditure per the cash flow statement	460.2	452.3

 

 

Cash Capital Expenditure

($m)	2022	2021
Payment for purchase of property, plant and equipment	395.8	403.5
Payment for exploration and evaluation, and other intangible assets	64.4	48.7
Total Cash Capital Expenditure	460.2	452.2

 

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.

($m)	2022	2021
Current borrowings	45.6	-
Non-current borrowings	2,975.3	2,947.1
Total borrowings	3,020.9	2,947.1
Less: Cash and cash equivalents and bank deposits	(427.9)	(730.8)
Restricted cash	(74.8)	(199.7)
Net Debt	2,518.2	2,016.6
Total equity	650.2	717.1
Gearing Ratio	387.3%	281.2%

 

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

 

 

 

Group Income Statement
YEAR ENDED 31 DECEMBER 2022

 

		2022			2021
	Notes	$'000			$'000
Revenue	4	737,081			496,985
Cost of sales	5a	(358,930)			(345,112)
Gross profit		378,151			151,873
Administrative expenses	5b	(45,942)			(42,973)
Exploration and evaluation expenses	5c	(71,395)			(87,678)
Impairment of property, plant and equipment	8	(27,628)			-
Other expenses	5d	(15,161)			(7,019)
Other income	5e	14,133			17,884
Operating profit		232,158			32,087
Finance income	6	9,572			2,950
Finance costs	6	(107,315)			(97,380)
Unrealised loss on derivatives	17	(5,203)			(21,477)
Net foreign exchange (losses)/gains	6	(22,207)			(6,922)
Loss before tax		107,005			(90,742)
Taxation expense	7	(89,734)			(5,412)
Loss for the year		17,271			(96,154)
Attributable to:
Owners of the parent		17,271			(96,046)
Non-controlling interests		-			(108)
		17,271			(96,154)

 

Basic and diluted earnings/ (loss) per share (cents per share)
Basic	2	$0.10			($0.52)
Diluted	2	$0.12			($0.52)

 

 

Group Statement of Comprehensive Income
YEAR ENDED 31 DECEMBER 2022
		2022					2021
		$'000					$'000
Profit/(Loss) for the year		17,271					(96,154)
Other comprehensive profit/(loss):
Items that may be reclassified subsequently to profit or loss
Cash Flow hedges
Gain/(loss) arising in the period		11,665					(6,182)
Income tax relating to items that may be       reclassified to profit or loss		(2,799)					1,546
Exchange difference on the translation of foreign operations, net of tax		6,996					(12,781)
		15,862					(17,417)
Items that will not be reclassified subsequently to profit or loss
Remeasurement of defined benefit pension plan		267					(165)
Income taxes on items that will not be reclassified to profit or loss		(64)					40
		203					(125)
Other comprehensive profit/(loss) after tax		16,065					(17,542)
Total comprehensive profit/(loss) for the year		33,336					(113,696)
Total comprehensive loss attributable to:
Owners of the parent		33,336					(113,590)
Non-controlling interests		-					(106)
		33,336					(113,696)