2022 Full Year Results
Energean plc
("Energean" or the "Company")
2022 Full Year Results
London, 23 March 2023 - Energean plc (LSE: ENOG, TASE: א) 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 15th 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: ir@energean.com
Kate Sloan, Head of IR and ECM Tel: +44 7917 608 645
For media: pblewer@energean.com
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, |
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) |
|
||||
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Group Statement of Changes in EquityYEAR ENDED 31 DECEMBER 2022 |
|
||||||||||
|
|
Share capital |
Share premium |
Hedges and Defined Benefit plans reserve1 |
Equity component of convertible bonds2 |
Share based payment reserve3 |
Translation reserve4 |
Retained earnings |
Merger reserves |
Total |
Non-controlling interests |
Total |
|
|
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
|
At 1 January 2021 |
2,367 |
915,388 |
1,792 |
- |
13,419 |
(42) |
(144,734) |
139,903 |
928,093 |
266,299 |
1,194,392 |
|
Loss for the period |
|
|
|
|
|
|
(96,046) |
|
(96,046) |
(108) |
(96,154) |
|
Remeasurement of defined benefit pension plan |
|
|
(125) |
|
|
|
|
|
(125) |
|
(125) |
|
Hedges net of tax |
|
|
(4,638) |
|
|
|
|
|
(4,638) |
2 |
(4,636) |
|
Exchange difference on the translation of foreign operations |
|
|
|
|
|
(12,781) |
|
|
(12,781) |
|
(12,781) |
|
Total comprehensive income |
- |
- |
(4,763) |
- |
- |
(12,781) |
(96,046) |
- |
(113,590) |
(106) |
(113,696) |
|
Transactions with owners of the company |
|
|
|
|
|
|
|
|
|
|
|
|
Share capital increase in subsidiary |
|
|
|
|
5,940 |
|
|
|
5940 |
|
5,940 |
|
Employee share schemes |
7 |
|
|
|
(7) |
|
|
|
- |
|
- |
|
Acquisition of non-controlling Interests |
- |
- |
- |
10,459 |
- |
- |
(113,779) |
- |
(103,320) |
(266,193) |
(369,513) |
|
At 1 January 2022 |
2,374 |
915,388 |
(2,971) |
10,459 |
19,352 |
(12,823) |
(354,559) |
139,903 |
717,123 |
- |
717,123 |
|
Profit for the period |
|
|
|
|
|
|
17,271 |
|
17,271 |
- |
17,271 |
|
Remeasurement of defined benefit pension plan |
|
|
203 |
|
|
|
|
|
203 |
- |
203 |
|
Hedges, net of tax |
|
|
8,866 |
|
|
|
|
|
8,866 |
- |
8,866 |
|
Exchange difference on the translation of foreign operations |
|
|
|
|
|
6,996 |
|
|
6,996 |
|
6,996 |
|
Total comprehensive income |
- |
- |
9,069 |
- |
- |
6,996 |
17,271 |
- |
33,336 |
- |
33,336 |
|
Transactions with owners of the company |
|||||||||||
|
Share based payment charges |
|
|
|
|
6,243 |
|
|
|
6,243 |
|
6,243 |
|
Exercise of Employee Share Options |
6 |
|
|
|
(6) |
|
|
|
- |
|
- |
|
Share Premium Reduction |
|
(500,000) |
|
|
|
|
500,000 |
|
- |
|
- |
|
Dividends (note 18) |
|
|
|
|
|
|
(106,504) |
|
(106,504) |
|
(106,504) |
|
At 31 December 2022 |
2,380 |
415,388 |
6,098 |
10,459 |
25,589 |
(5,827) |
56,208 |
139,903 |
650,198 |
- |
650,198 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1 Reserve is used to recognise remeasurement gain or loss on cash flow hedges and actuarial gain or loss from the defined benefit pension plan. In the Statement of Financial Position this reserve is combined with the 'Equity component of convertible bonds' reserve.
2 Refers to the Equity component of $50million of convertible loan notes, which were issued in February 2021 and have a maturity date of 29 December 2023.
3 Share-based payments reserve is used to recognise the value of equity-settled share-based payments granted to parties including employees and key management personnel, as part of their remuneration.
4 Reserve is used to record unrealised exchange differences arising from the translation of the financial statements of entities within the Group that have a functional currency other than US dollar.
Group Cashflows StatementYEAR ENDED 31 DECEMBER 2022 |
|
|
|
|
|
|
|
2022 |
|
2021 |
|
|
Note |
$'000 |
|
$'000 |
|
Operating activities |
|
|
|
|
|
Profit/ (Loss) before taxation |
|
107,005 |
|
(90,742) |
|
Adjustments to reconcile loss before taxation to net cash provided by operating activities: |
|
|
|
|
|
Depreciation, depletion and amortisation |
8, 9 |
83,360 |
|
97,451 |
|
Impairment loss on property, plant and equipment1 |
8 |
27,628 |
|
- |
|
Loss from the sale of property, plant and equipment |
|
1,102 |
|
36 |
|
Impairment loss on intangible assets |
9 |
65,550 |
|
82,125 |
|
Defined benefit (gain) |
|
(351) |
|
(4,061) |
|
Movement in provisions |
15 |
(4,742) |
|
(4,462) |
|
Compensation to gas buyers |
4 |
18,029 |
|
(22,958) |
|
Change in decommissioning provision estimates |
|
- |
|
(10,198) |
|
Finance income |
6 |
(9,572) |
|
(2,951) |
|
Finance costs |
6 |
107,315 |
|
97,374 |
|
Unrealised loss on derivatives |
17 |
5,203 |
|
21,477 |
|
Expected credit loss (ECL) on trade receivables |
|
565 |
|
(1,853) |
|
Non-cash revenues from Egypt2 |
|
(57,766) |
|
(39,100) |
|
Impairment loss on inventory |
|
1,207 |
|
- |
|
Share-based payment charge |
|
6,044 |
|
5,734 |
|
Net foreign exchange loss |
6 |
22,207 |
|
6,922 |
|
Cash flow from operations before working capital |
|
372,784 |
|
136,648 |
|
(Increase) in inventories |
|
(10,278) |
|
(16,484) |
|
(Increase)/Decrease in trade and other receivables |
|
(74,454) |
|
46,351 |
|
Increase/(Decrease) in trade and other payables |
|
23,405 |
|
(34,726) |
|
Cash from operations |
|
311,457 |
|
131,789 |
|
Income tax (paid)/received |
|
(39,304) |
|
715 |
|
Net cash inflow from operating activities |
|
272,153 |
|
132,503 |
|
Investing activities |
|
|
|
|
|
Payment for purchase of property, plant and equipment |
8 |
(395,753) |
|
(403,503) |
|
Payment for exploration and evaluation, and other intangible assets 9 |
(64,414) |
|
(48,674) |
|
|
Acquisition of a subsidiary, net of cash acquired |
|
- |
|
841 |
|
Movement in restricted cash |
|
124,953 |
|
(199,729) |
|
Proceeds from disposal of property, plant and equipment |
|
227 |
|
- |
|
Amounts received from INGL related to the future transfer 16 of property, plant and equipment |
17,371 |
|
5,673 |
|
|
Interest received |
|
9,675 |
|
2,609 |
|
Net cash outflow for investing activities |
|
(307,941) |
|
(642,783) |
|
Financing activities |
|
|
|
|
|
Drawdown of borrowings |
14 |
63,463 |
|
175,000 |
|
Repayment of borrowings |
14 |
- |
|
(1,807,140) |
|
Senior secured notes Issuance |
14 |
- |
|
3,068,000 |
|
Acquisition of non-controlling interests |
|
(30,000) |
|
(175,000) |
|
Transaction costs related to acquisition of non-controlling interest |
- |
|
(1,677) |
|
|
Repayment of obligations under leases |
|
(14,023) |
|
(10,852) |
|
Debt arrangement fees paid |
|
- |
|
(48,377) |
|
Finance cost paid for deferred license payments |
|
(1,501) |
|
(3,494) |
|
Finance costs paid |
|
(178,914) |
|
(136,694) |
|
Dividends paid |
|
(106,504) |
|
- |
|
Net cash (outflow)/inflow financing activities |
|
(267,479) |
|
1,059,765 |
|
|
|
|
|
|
|
Net (decrease)/increase in cash and cash equivalents |
|
(303,267) |
|
549,485 |
|
Cash and cash equivalents at beginning of the period |
|
730,839 |
|
202,939 |
|
Effect of exchange rate fluctuations on cash held |
|
316 |
|
(21,585) |
|
Cash and cash equivalents at end of the period |
11 |
427,888 |
|
730,839 |
1 The impairment of property, plant and equipment is a result of changes in the decommissioning provision.
2 Non-cash revenues from Egypt arise due to taxes being deducted at source from invoices as such revenue and tax charges are grossed up to reflect this deduction but no cash inflow or outflow results.
1. Basis of preparation and presentation of financial information
Whilst the financial information in this preliminary announcement has been prepared in accordance with UK-adopted International Accounting Standards (UK-adopted IAS) and with the requirements of the United Kingdom Listing Authority (UKLA) Listing Rules, this announcement does not contain sufficient information to comply with IFRS. The Group will publish full financial statements that comply with IFRS in April 2022. The financial information for the year ended 31 December 2022 does not constitute statutory accounts as defined in sections 435 (1) and (2) of the Companies Act 2006. The group and parent company financial statements for the year ended 31 December 2021 have been delivered to the Registrar of Companies; the auditor's report on these accounts was unqualified, did not include a reference to any matters by way of emphasis and did not contain a statement under Section 498 (2) or Section 498 (3) of the UK Companies Act 2006.
The accounting policies applied are consistent with those adopted and disclosed in the Group's financial statements for the year ended 31 December 2022. There have been a number of amendments to accounting standards and new interpretations issued by the International Accounting Standards Board which were applicable from 1 January 2022, however these have not any impact on the accounting policies, methods of computation or presentation applied by the Group. Further details on new International Financial Reporting Standards adopted will be disclosed in the 2022 Annual Report and Accounts.
Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2022 reporting periods and have not been early adopted by the Group. These standards are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions.
2. Earnings/ (Loss) per share
Basic earnings per ordinary share amounts are calculated by dividing net income for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year. Diluted income per ordinary share amounts are calculated by dividing net income for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued if dilutive employee share options were converted into ordinary shares.
|
|
2022 |
|
2021 |
||
|
|
$'000 |
|
$'000 |
||
|
Total profit/(loss) attributable to equity shareholders |
17,271 |
|
(96,046) |
||
|
Effect of dilutive potential ordinary shares1 |
4,054 |
|
- |
||
|
|
21,325 |
|
(96,046) |
||
|
Basic weighted average number of shares |
177,931,019 |
|
177,278,840 |
||
|
Dilutive potential ordinary shares |
6,714,731 |
|
- |
||
|
Diluted weighted average number of shares |
184,645,750 |
|
177,278,840 |
||
|
Basic earnings/(loss) per share |
$0.10/share |
$(0.54)/share |
|
||
|
Diluted earnings/ (loss) per share |
$0.12/share |
$(0.54)/share |
|
||
1 The $4.1million is the unwinding of the discount on the convertible loan notes (as disclosed in note 9) that will no longer be incurred on conversion to shares.
3. Segmental reporting
The information reported to the Group's Chief Executive Officer and Chief Financial Officer (together the Chief Operating Decision Makers) for the purposes of resource allocation and assessment of segment performance is focused on four operating segments: Europe, (including Greece, Italy, UK, Croatia), Israel, Egypt and New Ventures (Montenegro and Malta).
The Group's reportable segments under IFRS 8 Operating Segments are Europe, Israel and Egypt. Segments that do not exceed the quantitative thresholds for reporting information about operating segments have been included in Other.
Segment revenues, results and reconciliation to profit before tax
The following is an analysis of the Group's revenue, results and reconciliation to profit/(loss) before tax by reportable segment:
|
($'000) |
Europe |
Israel |
Egypt |
Other & inter-segment transactions |
Total |
|
Year ended 31 December 2022 |
|||||
|
Revenue from Oil |
206,959 |
- |
- |
- |
206,959 |
|
Revenue from Gas |
328,506 |
45,153 |
156,264 |
- |
529,923 |
|
Other |
(31,298) |
(18,031) |
57,131 |
(7,603) |
199 |
|
Total revenue |
504,167 |
27,122 |
213,395 |
(7,603) |
737,081 |
|
Adjusted EBITDAX1 |
262,655 |
(4,498) |
164,581 |
(1,125) |
421,613 |
|
Reconciliation to profit before tax: |
|
|
|
|
|
|
Depreciation and amortisation expenses |
(27,199) |
(12,112) |
(43,266) |
(783) |
(83,360) |
|
Share-based payment charge |
(1,423) |
(214) |
(89) |
(4,318) |
(6,044) |
|
Exploration and evaluation expenses |
(61,071) |
(1,819) |
- |
(8,505) |
(71,395) |
|
Impairment loss on property, plant and equipment |
(27,628) |
- |
- |
- |
(27,628) |
|
Other expense |
(5,742) |
(1,102) |
- |
(8,317) |
(15,161) |
|
Other income |
1,284 |
54 |
12,067 |
728 |
14,133 |
|
Finance income |
3,777 |
6,379 |
1,705 |
(2,289) |
9,572 |
|
Finance costs |
(32,395) |
(29,811) |
(858) |
(44,251) |
(107,315) |
|
Unrealised loss on derivatives |
(5,203) |
- |
- |
- |
(5,203) |
|
Net foreign exchange gain/(loss) |
4,065 |
(3,085) |
(7,498) |
(15,689) |
(22,207) |
|
Profit/(loss) before income tax |
111,120 |
(46,208) |
126,642 |
(84,549) |
107,005 |
|
Taxation income / (expense) |
(42,283) |
10,951 |
(57,766) |
(636) |
(89,734) |
|
Profit/(loss) from continuing operations |
68,837 |
(35,257) |
68,876 |
(85,185) |
17,271 |
|
Year ended 31 December 2021 |
|||||
|
Revenue from oil |
165,496 |
- |
- |
144 |
165,640 |
|
Revenue from Gas |
137,468 |
- |
133,503 |
(2) |
270,969 |
|
Other |
12,156 |
- |
55,446 |
(8,226) |
60,376 |
|
Total revenue |
316,120 |
- |
188,949 |
(8,084) |
496,985 |
|
Adjusted EBITDAX1 |
88,288 |
(4,969) |
130,634 |
(1,881) |
212,072 |
|
Reconciliation to profit before tax: |
|
|
|
|
|
|
Depreciation and amortisation expenses |
(55,001) |
(93) |
(41,626) |
(731) |
(97,451) |
|
Share-based payment charge |
(967) |
(231) |
- |
(4,523) |
(5,721) |
|
Exploration and evaluation expenses |
(86,490) |
(50) |
- |
(1,138) |
(87,678) |
|
Other expense |
(2,150) |
(461) |
(1,543) |
(2,865) |
(7,019) |
|
Other income |
16,065 |
19 |
1,851 |
(51) |
17,884 |
|
Finance income |
13,450 |
7,849 |
985 |
(19,334) |
2,950 |
|
Finance costs |
(28,318) |
(18,526) |
(9,059) |
(41,477) |
(97,380) |
|
Unrealised loss on derivatives |
(21,477) |
- |
- |
- |
(21,477) |
|
Net foreign exchange gain/(loss) |
31,000 |
520 |
479 |
(38,921) |
(6,922) |
|
Profit/(Loss) before income tax |
(45,600) |
(15,942) |
81,721 |
(110,921) |
(90,742) |
|
Taxation income / (expense) |
29,026 |
5,017 |
(39,100) |
(355) |
(5,412) |
|
Profit/(Loss) from continuing operations |
(16,574) |
(10,925) |
42,621 |
(111,276) |
(96,154) |
1 Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, share-based payment charge, impairment of property, plant and equipment, other income and expenses (including the impact of derivative financial instruments and foreign exchange), net finance costs and exploration and evaluation expenses.
The following table presents assets and liabilities information for the Group's operating segments as at 31 December 2022 and 31 December 2021, respectively :
|
Year ended 31 December 2022 ($'000) |
Europe |
Israel |
Egypt |
Other & inter-segment transactions |
Total |
||||
|
Oil & Gas properties |
536,874 |
3,264,364 |
409,732 |
(14,440) |
4,196,530 |
||||
|
Other fixed assets |
13,365 |
4,750 |
17,325 |
(65) |
35,375 |
||||
|
Intangible assets |
48,249 |
219,354 |
20,639 |
8,136 |
296,378 |
||||
|
Trade and other receivables |
141,509 |
82,611 |
131,453 |
(17,609) |
337,964 |
||||
|
Deferred tax asset |
244,394 |
- |
- |
(2,168) |
242,226 |
||||
|
Other assets |
883,576 |
24,933 |
96,942 |
(382,497) |
622,954 |
||||
|
Total assets |
1,867,967 |
3,596,012 |
676,091 |
(408,643) |
5,731,427 |
||||
|
Trade and other payables |
220,706 |
540,459 |
50,563 |
114,505 |
926,233 |
||||
|
Borrowings |
61,437 |
2,471,030 |
- |
488,429 |
3,020,896 |
||||
|
Decommissioning provision |
724,457 |
84,299 |
- |
- |
808,756 |
||||
|
Current tax payable |
109,468 |
- |
- |
41 |
109,509 |
||||
|
Other liabilities |
124,201 |
40,882 |
18,498 |
32,254 |
215,835 |
||||
|
Total liabilities |
1,240,270 |
3,136,670 |
69,061 |
635,229 |
5,081,229 |
||||
|
Other segment information |
|
|
|
|
|
||||
|
Capital Expenditure2 |
|
|
|
|
|
||||
|
Property, plant and equipment |
85,840 |
537,527 |
105,792 |
(368) |
728,791 |
||||
|
Intangible, exploration |
12,143 |
124,718 |
193 |
3,970 |
141,024 |
||||
|
Year ended 31 December 2021 ($'000) |
|
|
|
|
|
||||
|
Oil & Gas properties |
537,600 |
2,584,828 |
342,528 |
(9,694) |
3,455,262 |
||||
|
Other fixed assets |
16,578 |
3,917 |
24,076 |
(360) |
44,211 |
||||
|
Intangible assets |
74,868 |
95,941 |
20,484 |
36,848 |
228,141 |
||||
|
Trade and other receivables |
164,131 |
22,769 |
102,605 |
(979) |
288,526 |
||||
|
Deferred tax asset |
154,798 |
- |
- |
- |
154,798 |
||||
|
Other assets |
674,157 |
379,248 |
98,720 |
(81,711) |
1,070,414 |
||||
|
Total assets |
1,622,132 |
3,086,703 |
588,413 |
(55,896) |
5,241,352 |
||||
|
Trade and other payables |
197,865 |
74,115 |
25,511 |
152,216 |
449,706 |
||||
|
Current tax payable |
4,932 |
- |
- |
347 |
5,279 |
||||
|
Borrowings |
- |
2,463,524 |
- |
483,602 |
2,947,126 |
||||
|
Decommissioning provision |
766,573 |
35,525 |
- |
|
802,098 |
||||
|
Other liabilities |
113,808 |
180,689 |
24,663 |
858 |
320,018 |
||||
|
Total liabilities |
1,083,178 |
2,753,853 |
50,174 |
637,024 |
4,524,229 |
||||
|
Other segment information |
|
|
|
|
|
||||
|
Capital Expenditure2 |
|
|
|
|
|
||||
|
Property, plant and equipment |
72,782 |
247,463 |
52,085 |
(14,330) |
358,000 |
||||
|
Intangible, exploration |
40,523 |
6,342 |
215 |
3,329 |
50,409 |
||||
2 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.
Segment cash flows
|
Year ended 31 December 2022 ($'000) |
Europe |
Israel |
Egypt |
Other & inter-segment transactions |
Total |
|
Net cash from / (used in) operating activities |
225,780 |
(7,850) |
66,946 |
(12,723) |
272,153 |
|
Cash outflow for investing activities |
(287,490) |
(180,040) |
(54,229) |
213,818 |
(307,941) |
|
Net cash from financing activities |
54,977 |
(133,953) |
(2,528) |
(185,975) |
(267,479) |
|
Net increase/(decrease) in cash and cash equivalents |
(6,733) |
(321,843) |
10,189 |
15,120 |
(303,267) |
|
Cash and cash equivalents at beginning of the period |
71,312 |
349,827 |
19,254 |
290,446 |
730,839 |
|
Effect of exchange rate fluctuations on cash held |
(6,451) |
(3,159) |
(2,617) |
12,543 |
316 |
|
Cash and cash equivalents at end of the period |
58,128 |
24,825 |
26,826 |
318,109 |
427,888 |
|
Year ended 31 December 2021 ($'000) |
|
|
|
|
|
|
Net cash from / (used in) operating activities |
43,394 |
(28,764) |
128,659 |
(10,785) |
132,504 |
|
Cash outflow from investing activities |
(99,040) |
(490,381) |
(53,553) |
191 |
(642,783) |
|
Net cash from financing activities |
120,446 |
831,677 |
(132,414) |
240,056 |
1,059,765 |
|
Net increase/(decrease) in cash and cash equivalents |
64,800 |
312,532 |
(57,308) |
229,462 |
549,486 |
|
Cash and cash equivalents at beginning of the period |
13,609 |
37,421 |
76,240 |
75,669 |
202,939 |
|
Effect of exchange rate fluctuations on cash held |
(7,093) |
(125) |
322 |
(14,690) |
(21,586) |
|
Cash and cash equivalents at end of the period |
71,316 |
349,828 |
19,254 |
290,441 |
730,839 |
4. Revenue
|
|
2022 |
|
2021 |
|
|
$'000 |
|
$'000 |
|
Revenue from crude oil sales |
206,959 |
|
165,924 |
|
Revenue from gas sales |
529,923 |
|
270,969 |
|
Revenue from LPG sales |
21,747 |
|
20,945 |
|
Revenue from condensate sales |
35,384 |
|
34,126 |
|
Compensation to gas buyers |
(18,031) |
|
- |
|
Gain/(Loss) on forward transactions |
(55,189) |
|
(285) |
|
Petroleum products sales |
2,697 |
|
4,618 |
|
Rendering of services |
1,001 |
|
688 |
|
Revenue from contracts with customers |
724,491 |
|
496,985 |
|
Other operating income-lost production insurance proceeds |
12,590 |
|
- |
|
Total revenue |
737,081 |
|
496,985 |
During August 2021 and in accordance with the GSPAs signed with a group of gas buyers, the Group agreed to pay compensation to these counterparties due to the fact the gas supply date is taking place beyond a certain date as defined in the GSPAs (being 30 June 2021). The compensation is accounted as variable purchase consideration and deducted from revenue as gas is delivered to the offtakers.
Proceeds related to lost production under the business interruption insurance policy of $12.6million (2021: $0million).
100% of the gas produced at Abu Qir (Egypt) is sold to EGPC under a Brent-linked gas price. The gas price is determined based on Brent prices trading within a certain range, as set out in the agreement, and contains both a floor price and a cap, limiting volatility and exposure to commodity price fluctuations .
|
Sales for the year ended 31 December (Kboe) |
2022 |
2021 |
|
Egypt (net entitlement) |
||
|
Gas |
3,698 |
6,351 |
|
LPG |
244 |
394 |
|
Condensate |
286 |
553 |
|
Italy |
||
|
Oil |
2,440 |
2,083 |
|
Gas |
1,406 |
1,474 |
|
Israel |
||
|
Gas |
1,781 |
|
|
UK |
||
|
Gas |
73 |
40 |
|
Oil |
245 |
271 |
|
Croatia |
||
|
Gas |
38 |
57 |
|
Greece |
|
|
|
Oil |
- |
403 |
|
Total |
10,211 |
11,626 |
5. Operating profit/(loss)
|
|
|
|
2022 |
|
2021 |
|
|
|
|
|
$'000 |
|
$'000 |
|
|
(a) |
Cost of sales |
|
|
|
|
|
|
|
Staff costs |
|
52,904 |
|
64,564 |
|
|
|
Energy cost |
|
15,947 |
|
11,578 |
|
|
|
Flux Cost |
|
36,970 |
|
11,561 |
|
|
|
Royalty payable |
|
45,770 |
|
24,759 |
|
|
|
Other operating costs |
|
132,688 |
|
149,133 |
|
|
|
Depreciation and amortisation |
|
79,362 |
|
94,647 |
|
|
|
Oil stock movement |
|
(1,707) |
|
(15,501) |
|
|
|
Stock overlift/underlift movement |
|
(3,004) |
|
4,371 |
|
|
|
Total cost of sales |
|
358,930 |
|
345,112 |
|
|
(b) |
Administration expenses |
|
|
|
|
|
|
|
Staff costs |
|
17,977 |
|
16,759 |
|
|
|
Other General & Administration expenses |
|
15,960 |
|
15,444 |
|
|
|
Share-based payment charge included in administrative expenses |
|
6,044 |
|
5,714 |
|
|
|
Depreciation and amortization |
|
3,889 |
|
2,480 |
|
|
|
Auditor fees |
|
2,072 |
|
2,273 |
|
|
|
Total a dministration expenses |
|
45,942 |
|
42,973 |
|
|
(c) |
Exploration and evaluation expenses |
|
|
|
|
|
|
|
Staff costs for Exploration and evaluation activities |
|
3,012 |
|
3,695 |
|
|
|
Exploration costs written off (Note 9) |
|
66,371 |
|
82,122 |
|
|
|
Other exploration and evaluation expenses |
|
2,012 |
|
1,861 |
|
|
|
Total e xploration and evaluation expenses |
|
71,395 |
|
87,678 |
|
|
(d) |
Other expenses |
|
|
|
|
|
|
|
Transaction costs in relation to Edison E&P acquisition |
|
- |
|
2,052 |
|
|
|
Intra-group merger costs |
|
3,212 |
|
605 |
|
|
|
Loss from disposal of Property plant & Equipment |
|
1,102 |
|
36 |
|
|
|
Write-down of inventory |
|
1,207 |
|
581 |
|
|
|
Expected credit losses |
|
3,043 |
|
- |
|
|
|
Provision for litigation and claims |
|
1,198 |
|
520 |
|
|
|
Write down of property, plant and equipment costs |
|
- |
|
779 |
|
|
|
Other expenses |
|
5,399 |
|
2,446 |
|
|
|
Total other expenses |
|
15,161 |
|
7,019 |
|
|
(e) |
Other income |
|
|
|
|
|
|
|
Reversal of expected credit loss allowance |
|
10,970 |
|
1,853 |
|
|
|
Profit from sale of inventory |
|
1,643 |
|
- |
|
|
|
Change in estimates of decommissioning provisions |
|
- |
|
7,836 |
|
|
|
Change in estimate of defined benefit obligation |
|
- |
|
3,463 |
|
|
|
Reversal of provision for litigation and claims |
|
- |
|
4,494 |
|
|
|
Other income |
|
1,520 |
|
238 |
|
|
|
Total other income |
|
14,133 |
|
17,884 |
|
6. Net finance cost
|
|
|
2022 |
|
2021 |
|
|
|
Notes |
$'000 |
|
$'000 |
|
|
|
|
|
|
||
|
Interest on bank borrowings |
14 |
1,527 |
|
96,678 |
|
|
Interest on Senior Secure Notes |
14 |
167,372 |
|
106,993 |
|
|
Interest expense on long term payables |
16 |
14,660 |
|
4,101 |
|
|
Interest expense on short term liabilities |
|
54 |
|
55 |
|
|
Less amounts included in the cost of qualifying assets |
8, 9 |
(123,635) |
|
(174,153) |
|
|
|
|
59,978 |
|
33,674 |
|
|
Finance and arrangement fees |
|
11,334 |
|
12,420 |
|
|
Commission charges for bank guarantees |
|
2,118 |
|
2,404 |
|
|
Unamortised financing costs related to Greek RBL and Egypt RBL |
|
- |
|
18,108 |
|
|
Other finance costs and bank charges |
|
2,136 |
|
2,972 |
|
|
Loss on interest rate hedges |
|
- |
|
7,002 |
|
|
Unwinding of discount on right of use asset |
|
2,159 |
|
1,316 |
|
|
Unwinding of discount on provision for decommissioning |
|
21,495 |
|
8,722 |
|
|
Unwinding of discount on deferred consideration |
|
7,098 |
|
12,854 |
|
|
Unwinding of discount on convertible loan |
|
4,054 |
|
3,159 |
|
|
Mark-to-market on contingent consideration |
|
2,667 |
|
1,626 |
|
|
Less amounts included in the cost of qualifying assets |
|
(5,724) |
|
(6,877) |
|
|
Total finance costs |
|
107,315 |
|
97,380 |
|
|
Interest income from time deposits |
|
(9,572) |
|
(2,950) |
|
|
Total finance income |
|
(9,572) |
|
(2,950) |
|
|
Foreign exchange (gain)/losses |
|
22,207 |
|
6,922 |
|
|
Net financing (income)/costs |
|
119,950 |
|
101,352 |
|
7. Taxation
(a) Taxation charge
|
|
2022 |
|
2021 |
|
|
$'000 |
|
$'000 |
|
Corporation tax - current year |
(199,563) |
|
(44,922) |
|
Corporation tax - prior years |
(583) |
|
353 |
|
Deferred tax (Note 10) |
110,412 |
|
39,157 |
|
Total taxation (expense)/income |
(89,734) |
|
(5,412) |
(b) Reconciliation of the total tax charge
The Group calculates its income tax expense by applying a weighted average tax rate calculated based on the statutory tax rates of each country weighted according to the profit or loss before tax earned by the Group in each jurisdiction where deferred tax is recognised or material current tax charge arises.
The effective tax rate for the period is 84% (31 December 2021: -6%).
The tax (charge)/credit of the period can be reconciled to the loss per the consolidated income statement as follows:
|
|
2022 |
|
2021 |
|
|
$'000 |
|
$'000 |
|
Profit/ (Loss) before tax |
107,005 |
|
(90,742) |
|
|
|
|
|
|
Tax calculated at 27.5% weighted average rate (2021: 29.5%)1 |
(29,453) |
|
29,721 |
|
Impact of different tax rates2 |
(9,960) |
|
(5,176) |
|
Utilisation of unrecognised deferred tax/ |
83,737 |
|
2,953 |
|
Permanent differences3 |
(16,341) |
|
(34,470) |
|
Foreign taxes |
(54) |
|
(244) |
|
Windfall tax4 |
(119,425) |
|
- |
|
Tax effect of non-taxable income & allowances |
2,217 |
|
1,348 |
|
Other adjustments |
128 |
|
103 |
|
Prior year tax |
(583) |
|
353 |
|
Taxation (expense) |
(89,734) |
|
(5,412) |
1 For the reconciliation of the tax rate, the weighted average rate of the statutory tax rates in Greece (25%), Cyprus (12.5%) Israel (23%), Italy (24%), United Kingdom (19%/40%/55.07%) and Egypt (40.55%) was used weighted according to the profit or loss before tax earned by the Group in each jurisdiction, excluding fair value uplifts profits.
2 "Impact of different tax rates" mainly consisted of the Italian regional taxes (IRAP).
3 Permanent differences mainly consisted of non-deductible expenses (-$15.0m), consolidation differences ($2.8m) and foreign exchange differences (-$4.1m).
4 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 $29.3mil 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 $92.8 million ( €87.0 million) in June 2023. In addition, the Energy (Oil and Gas) Profits Levy (EPL) was announced by the UK Government on 26 May 2022 and legislated for in July 2022. This was a new, temporary 25% (to be increased to 35% from 1st January 2023) levy on ring fence profits of oil and gas companies. This was in addition to Ring Fence Corporation Tax which is charged at 30% and the Supplementary Charge which is charged at 10%. The Group's exposure to the EPL is de minimis.
8 Property, plant & equipment
|
Property, Plant & Equipment at Cost ($'000) |
Oil and gas assets1 |
Leased assets2 |
Other property, plant and equipment |
Total |
|
At 1 January 2021 |
3,430,329 |
50,841 |
60,237 |
3,541,407 |
|
Additions |
345,180 |
6,428 |
1,623 |
353,231 |
|
Lease modification |
- |
2,261 |
- |
2,261 |
|
Disposal of assets |
(23) |
- |
(34) |
(57) |
|
Capitalised borrowing cost |
178,891 |
- |
- |
178,891 |
|
Capitalised depreciation |
227 |
- |
- |
227 |
|
Change in decommissioning provision |
(13,174) |
- |
- |
(13,174) |
|
Transfer from Intangible assets |
14,317 |
- |
26 |
14,343 |
|
Foreign exchange impact |
(57,960) |
(2,285) |
(2,806) |
(63,051) |
|
At 31 December 2021 |
3,897,787 |
57,245 |
59,046 |
4,014,078 |
|
Additions |
742,665 |
1,195 |
1,534 |
745,394 |
|
Lease modification |
- |
831 |
- |
831 |
|
Disposal of assets |
(900) |
|
- |
(900) |
|
Capitalised borrowing cost |
109,184 |
- |
- |
109,184 |
|
Capitalised depreciation |
632 |
- |
- |
632 |
|
Change in decommissioning provision |
21,685 |
- |
- |
21,685 |
|
Other movements |
(241) |
37 |
(74) |
(278) |
|
Foreign exchange impact |
(31,388) |
(596) |
(388) |
(32,372) |
|
At 31 December 2022 |
4,739,424 |
58,712 |
60,118 |
4,858,254 |
|
Accumulated Depreciation and Impairment |
||||
|
At 1 January 2021 |
376,643 |
6,979 |
50,513 |
434,135 |
|
Charge for the period |
|
|
|
|
|
Expensed |
81,234 |
12,274 |
1,998 |
95,506 |
|
Impairments |
774 |
- |
- |
774 |
|
Disposal of assets |
- |
- |
21 |
21 |
|
Foreign exchange impact |
(16,129) |
(151) |
449 |
(15,831) |
|
At 31 December 2021 |
442,522 |
19,102 |
52,981 |
514,605 |
|
Charge for the period |
|
|
|
|
|
Expensed |
71,464 |
10,091 |
1,171 |
82,726 |
|
Impairment |
27,878 |
- |
- |
27,878 |
|
Disposal of assets |
- |
- |
- |
- |
|
Foreign exchange impact |
1,030 |
105 |
6 |
1,141 |
|
At 31 December 2022 |
542,895 |
29,298 |
54,157 |
626,350 |
|
Net carrying amount |
||||
|
At 31 December 2021 |
3,455,265 |
38,143 |
6,065 |
3,499,473 |
|
At 31 December 2022 |
4,196,530 |
29,414 |
5,960 |
4,231,904 |
1 Included within the carrying amount of Oil & Gas assets are development costs of the Karish field related to the Sub Sea and On-shore construction. In line with the agreement with Israel Natural Gas Lines ("INGL"), the transfer of title ("hand over") of these assets to INGL is expected to occur in Q1 2023.
2 Included in the carrying amount of leased assets at 31 December 2022 is right of use assets related to Oil and gas properties and Other property, plant and equipment of $21.3 million and $8.1 million respectively. The depreciation charged on these classes for the year ending 31 December 2022 was $7.9 million and $2.1 million respectively.
Borrowing costs capitalised for qualifying assets during the year are calculated by applying a weighted average interest rate of 5.16% for the year ended 31 December 2022 (for the year ended 31 December 2021: 5.49%).
The additions to Oil & Gas properties for the year ended 31 December 2022 are mainly due to development costs of Karish field related to the EPCIC contract (FPSO, Sub Sea and On-shore construction cost) at the amount of $534.5 million, development cost for Cassiopea project in Italy at the amount of $56.7 million and NEA/NI project in Egypt at the amount of $107.9 million.
The impairment recognised above of $27.9 million (2021: $0 million) was a result of a change to the decommissioning estimate on certain fields in Italy and the UK where the recoverable amount was lower than the carrying value, subsequent to recognising the change in estimate. The remaining change in decommissioning provision of $21.7 million was in relation to fields across the group whereby the recoverable amount exceeded the carrying value.
9. Intangible assets
|
($'000) |
Exploration and evaluation assets |
Goodwill |
Other Intangible assets |
Total |
|
Intangibles at Cost |
||||
|
At 1 January 2021 |
158,213 |
101,146 |
22,355 |
281,714 |
|
Additions |
47,995 |
- |
2,413 |
50,408 |
|
Capitalised borrowing costs |
2,202 |
- |
- |
2,202 |
|
Change in decommissioning provision |
2,141 |
|
|
2,141 |
|
Transfers to property, plant and equipment |
(265) |
- |
(14,078) |
(14,343) |
|
Exchange differences |
(4,953) |
- |
(983) |
(5,936) |
|
31 December 2021 |
205,333 |
101,146 |
9,707 |
316,186 |
|
Additions |
139,911 |
- |
1,113 |
141,024 |
|
Other movements |
- |
- |
280 |
280 |
|
Exchange differences |
(6,890) |
- |
(125) |
(7,015) |
|
At 31 December 2022 |
338,354 |
101,146 |
10,975 |
450,475 |
|
Accumulated amortisation and impairments |
||||
|
At 1 January 2021 |
3,004 |
- |
2,894 |
5,898 |
|
Charge for the period |
- |
- |
1,946 |
1,946 |
|
Impairment |
82,125 |
- |
- |
82,125 |
|
Exchange differences |
(1,850) |
- |
(74) |
(1,924) |
|
31 December 2021 |
83,279 |
- |
4,766 |
88,045 |
|
Charge for the period |
39 |
- |
595 |
634 |
|
Impairment |
47,240 |
18,310 |
- |
65,550 |
|
Exchange differences |
(110) |
- |
(22) |
(132) |
|
31 December 2022 |
130,448 |
18,310 |
5,339 |
154,097 |
|
Net carrying amount |
||||
|
At 31 December 2021 |
122,054 |
101,146 |
4,941 |
228,141 |
|
At 31 December 2022 |
207,906 |
82,836 |
5,636 |
296,378 |
10. Net deferred tax (liability)/ asset
|
Deferred tax (liabilities)/asse-ts |
Property, plant and equipment |
Right of use asset IFRS 16 |
Decom |
Prepaid expenses and other receivables |
Inve- ntory |
Tax losses |
Deferred expenses for tax |
Reti-rement benefit liability |
Accrued expenses and other short‑term liabilities |
Total |
||||||||
|
|
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
$'000 |
|
$'000 |
$'000 |
$'000 |
||||||||
|
1 January 2021 |
(123,543) |
(292) |
8,877 |
(4,651) |
695 |
165,841 |
- |
1,050 |
9,470 |
57,447 |
||||||||
|
Increase / (decrease) for the period through: |
|
|
|
|
|
|
|
|
|
|
||||||||
|
profit or loss |
9,848 |
(718) |
50,808 |
890 |
(254) |
(32,501) |
5,020 |
(932) |
6,996
|
39,157 |
||||||||
|
other comprehensive income |
|
|
|
|
|
|
|
|
1,586 |
1,586 |
||||||||
|
Reclassifications in the current period |
(28,442) |
- |
33,644 |
2,025 |
(233) |
(4,903) |
6, 010 |
200 |
(8,301) |
- |
||||||||
|
Exchange difference |
1,584 |
20 |
(3,889) |
165 |
(25) |
(8,257) |
|
(52) |
(363) |
(10,817) |
||||||||
|
31 December 2021 |
(140,553) |
(990) |
89,440 |
(1,571) |
183 |
120,180 |
11,030 |
266 |
9,388 |
87,373 |
||||||||
|
Increase / (decrease) for the period through: |
|
|
|
|
|
|
|
|
|
|
||||||||
|
profit or loss |
(11,836) |
(103) |
41,688 |
1,642 |
265 |
83,814 |
(4,822)
|
(22) |
(214)
|
110,412 |
||||||||
|
other comprehensive income |
|
|
|
|
|
|
|
(64) |
(2,799) |
(2,863) |
||||||||
|
Exchange difference |
3,466 |
15 |
(4,882) |
115 |
(8) |
(6,986) |
|
(15) |
(515) |
(8,810) |
||||||||
|
31 December 2022 |
(148,923) |
(1,078) |
126,246 |
186 |
440 |
197,008 |
6,208 |
165 |
5,860 |
186,112 |
||||||||
|
|
|
|
2022 |
2021 |
|
|
|
|
$'000 |
$'000 |
|
Deferred tax liabilities |
|
|
(56,114) |
(67,425) |
|
Deferred tax assets |
|
|
242,226 |
154,798 |
|
|
|
|
186,112 |
87,373 |
At 31 December 2022 the Group had gross unused tax losses of $1,093.8 million (as of 31 December 2021: $1,123.8 million) available to offset against future profits and other temporary differences. A deferred tax asset of $197.0 million (2021: $120.2 million) has been recognised on tax losses of $799.2 million, based on the forecasted profits. The Group did not recognise deferred tax on tax losses and other differences of total amount of $546.3 million.
In Greece, Italy and the UK, the net DTA for carried forward losses recognised in excess of the other net taxable temporary differences was $69.2 million, $33.0 million and $16.7 million (2021: $59.3 million, $0.19 million and $13.8 million) respectively. An additional DTA of $124.6 million (2021: $81.4 million) arose primarily in respect of deductible temporary differences related to property, plant and equipment, decommissioning provisions and accrued expenses, resulting in a total DTA of $242.3 million (2021: $154.9 million). During the period, Italy recognised a DTA of $33.4million on tax losses of $139.0 million in accordance with its latest tax losses utilisation forecast.
Greek tax losses (Prinos area) can be carried forward without limitation up until the relevant concession agreement expires (by 2039), whereas the tax losses in Israel, Italy and the United Kingdom can be carried forward indefinitely. Based on the Prinos area forecasts (including the Epsilon development), the deferred tax asset is fully utilised by 2030. In Italy, deferred tax asset of $111.2 million recognised on decommissioning costs scheduled up to the year the Italian assets expect to enter into a declining phase assuming available profits from Cassiopea and other long lived assets. In the UK, decommissioning losses are expected to benefit from tax relief up until 2027 in accordance with the latest taxable profits forecasts.
On 3 March 2021 it was announced in the UK budget that the UK non-ring fence corporation tax rate will increase from 19% to 25% with effect from April 2023. The Group does not currently recognise any deferred tax assets in respect of UK non-ring fence tax losses and therefore this rate change did not impact the tax disclosures.
Energean UK Limited with activities in the UKCS is subject to the newly introduced UK Energy Profits Levy (EPL) with effect from the 26 May 2022. For the tax reconciliation of Energean UK the weighted average tax rate of 55.07% (40% for the RFCT and 15.07% for the weighted average EPL rate) was used. The company generated EPL losses during 2022.
11. Cash and cash equivalents
|
|
2022 |
|
2021 |
|
|
$'000 |
|
$'000 |
|
Cash at bank |
427,888 |
|
729,390 |
|
Deposits in escrow |
- |
|
1,449 |
|
|
427,888 |
|
730,839 |
Bank demand deposits comprise deposits and other short-term money market deposit accounts that are readily convertible into known amounts of cash. The effective interest rate on short‑term bank deposits was 1.716% for the year ended 31 December 2022 (year ended 31 December 2021: 0.386%).
Deposits in escrow comprise mainly cash retained as a bank security pledge for the Group's performance guarantees in its exploration blocks. These deposits can be used for funding the exploration activities of the respective blocks.
12. Restricted Cash
Restricted cash comprises cash retained under the Israel Senior Secured Notes and the Greek State Loan requirement as follows:
Current
Total short-term restricted cash at 31 December 2022 was $71.8 million. $3 million for bank guarantees and $68.8 million for the debt payment fund which will be used for the March 2023 coupon payment of $64.4 million.
Non-Current
$2.8 million: $2.2 million required to be restricted in Interest Service Reserve Account ('ISRA') in relation to the Greek Loan Notes and $0.6 million for Prinos Guarantee.
13. Trade and other receivables
|
|
2022 ($'000) |
2021 ($'000) |
|
Trade and other receivables - Current |
||
|
Financial items |
|
|
|
Trade receivables |
215,215 |
178,804 |
|
Receivables from partners under JOA |
4,539 |
5,138 |
|
Other receivables |
2,344 |
38,683 |
|
Government subsidies1 |
3,025 |
3,212 |
|
Refundable VAT |
89,400 |
42,376 |
|
Receivables from related parties (note 27) |
- |
1 |
|
|
314,523 |
268,214 |
|
Non-financial items |
|
|
|
Deposits and prepayments2 |
15,084 |
17,139 |
|
Deferred insurance expenses |
1,983 |
2,095 |
|
Other deferred expenses3 |
4,929 |
|
|
Accrued interest income |
1,445 |
1,078 |
|
|
23,441 |
20,312 |
|
|
337,964 |
288,526 |
|
Trade and other receivables - Non-Current |
||
|
Financial items |
|
|
|
Other tax recoverable |
14,701 |
16,478 |
|
|
14,701 |
16,478 |
|
Non-financial items |
|
|
|
Deposits and prepayments |
11,726 |
12,337 |
|
Other deferred expenses3 |
|
22,958 |
|
Other non-current assets |
513 |
866 |
|
|
12,239 |
36,161 |
|
Total trade and other receivables |
26,940 |
52,639 |
1 Government subsidies relate to grants from Greek Public Body for Employment and Social Inclusion (OAED) to financially support the Kavala Oil S.A. labour cost from manufacturing under the action plan for promoting sustainable employment in underdeveloped or deprived districts of Greece, such as the area of Kavala. In September 2020, the Greek Government issued a law and a subsequent ministerial decision whereby any legal person who has launched legal proceedings in relation to the aforementioned employment costs, may set off such receivables against tax liabilities provided the judicial proceedings already commenced are abandoned. Energeaninvestigated the process and potential benefits of this approach decided to apply for the set off which has been approved and the first offset was in January 2023 of €587k ($626k).
2 Included in deposits and prepayments, are mainly prepayments for goods and services under the GSP Engineering, Procurement, Construction and Installation Contract (EPCIC) for Epsilon project.
3. In accordance with the GSPAs signed with a group of gas buyers, the Company has agreed to pay compensation to these counterparties due to the fact the gas supply date is taking place beyond a certain date as defined in the GSPAs (being 30 June 2021). The compensation, amounting to $23 million) has been fully paid in 2021. The compensation presented as a non-current asset (under the caption deferred expenses) and will be accounted for as variable consideration and deducted from revenue as gas is delivered to the offtakers.
14. Borrowings
|
|
|
2022 |
|
2021 |
|
|
|
$'000 |
|
$'000 |
|
Non-current |
|
|
|
|
|
Bank borrowings - after two years but within five years |
|
|
|
|
|
4.5% Senior Secured notes due 2024 ($625 million) |
|
620,461 |
|
617,060 |
|
4.875% Senior Secured notes due 2026 ($625 million) |
|
617,912 |
|
615,966 |
|
Convertible loan notes ($50 million) |
|
- |
|
41,495 |
|
Bank borrowings - more than five years |
|
|
|
|
|
6.5% Senior Secured notes due 2027 ($450 million) |
|
442,879 |
|
442,107 |
|
5.375% Senior Secured notes due 2028 ($625 million) |
|
616,767 |
|
615,451 |
|
5.875% Senior Secured notes due 2031 ($625 million) |
|
615,890 |
|
615,047 |
|
BSTDB Loan and Greek State Loan Notes |
|
61,437 |
|
|
|
Carrying value of non-current borrowings |
|
2,975,346 |
|
2,947,126 |
|
|
|
|
|
|
|
Current |
|
|
|
|
|
Convertible loan notes ($50 million) |
|
45,550 |
|
- |
|
Carrying value of current borrowings |
|
45,550 |
|
- |
|
|
|
|
|
|
|
Carrying value of total borrowings |
|
3,020,896 |
|
2,947,126 |
The Group has provided security in respect of certain borrowings in the form of share pledges, as well as fixed and floating charges over certain assets of the Group.
$2,500,000,000 senior secured notes
On 24 March 2021, the Group completed the issuance of $2.5 billion aggregate principal amount of senior secured notes.
The Notes have been issued in four series as follows:
· Notes in an aggregate principal amount of $625 million, maturing on 30 March 2024, with a fixed annual interest rate of 4.500%.
· Notes in an aggregate principal amount of $625 million, maturing on 30 March 2026, with a fixed annual interest rate of 4.875%.
· Notes in an aggregate principal amount of $625 million, maturing on 30 March 2028, with a fixed annual interest rate of 5.375%.
· Notes in an aggregate principal amount of $625 million, maturing on 30 March 2031, with a fixed annual interest rate of 5.875%.
The Notes are listed for trading on the TACT Institutional of the Tel Aviv Stock Exchange Ltd. (the "TASE").
The Company had undertaken to provide the following collateral in favour of the Trustee:
· First rank Fixed charges over the shares of Energean Israel Limited, Energean Israel Finance Ltd and Energean Israel Transmission Ltd, the Karish & Tanin Leases, the gas sales purchase agreements ("GSPAs"), several bank accounts, Operating Permits (once issued), Insurance policies, the Company exploration licenses (Block 12, Block 21, Block 23, Block 31) and the INGL Agreement.
· Floating charge over all of the present and future assets of Energean Israel Limited and Energean Israel Finance Ltd.
· Energean Power FPSO (subject to using commercially reasonable efforts, including obtaining Israel Petroleum Commissioner approval and any other applicable governmental authority).
Kerogen Convertible Loan
On 25 February 2021, the Group completed the acquisition of the remaining 30% minority interest in Energean Israel Limited from Kerogen Investments No.38 Limited, Energean now owns 100% of Energean Israel Limited. This resulted in a reduction of the Group's reported non-controlling interest balance to $nil at 31 December 2021.
The total consideration includes
· An up-front payment of $175 million paid at completion of the transaction
· Deferred cash consideration amounts totalling $180 million (out of which $30 million paid in December 2022). The deferred consideration is discounted at the selected unsecured liability rate of 9.77% (please refer to note 16).
· $50 million of convertible loan notes (the "Convertible loan notes"), which have a maturity date of 29 December 2023, a strike price of £9.50, adjusted for dividend payments up to maturity date, and a zero-coupon rate.
$450,000,000 senior secured notes
On 18th November 2021, the Group completed the issuance of $450 million of senior secured notes, maturing on 30 April 2027 and carrying a fixed annual interest rate of 6.5%.
The interest on the notes is paid semi-annually on 30 April and 30 October of each year, beginning on 30 April 2022.
The notes are listed for trading on the Official List of the International Stock Exchange ("TISE").
The issuer is Energean plc and the Guarantors are Energean E&P Holdings, Energean Capital Ltd, and Energean Egypt Ltd.
The company undertook to provide the following collateral in favour of the Security Trustee:
· Share pledge of Energean Capital Ltd, Energean Egypt Ltd, and Energean Italy Ltd
· Fixed charges over the material bank accounts of the Company and the Guarantors (other than Energean Egypt Services JSC)
· Floating charge over the assets of Energean plc (other than the shares of Energean E&P Holdings)
Energean Oil and Gas SA ('EOGSA') loan for Epsilon/ Prinos Development
On 27 December 2021 EOGSA entered into a loan agreement with Black Sea Trade and Development Bank for €90.5 million to fund the development of Epsilon Oil Field. The loan is subject to an interest rate of EURIBOR plus a margin of 2% on 90% of the loan (guaranteed portion) and 4.9% margin on 10% of the loan (unguaranteed portion). The loan has a final maturity date 7 years and 11 months after first disbursement.
On 27 December 2021 EOGSA entered into an agreement with Greek State to issue €9.5 million of notes maturing in 8 years with fixed rate -0.31% plus margin. The margin commences at 3.0% in year 1 with annual increases, reaching 6.5% in year 8.
At 31 December 2022, $43 million (€40 million) remains undrawn.
Revolving Credit Facility ('RCF')
On 8 September 2022, Energean signed a three-year $275 million RCF with a consortium of four banks, led by ING Bank N.V. The RCF provides additional liquidity for general corporate purposes, if required. Under its current business plan, Energean expects the RCF to remain undrawn, apart from $101 million (as at 31 December 2022) of Letters of Credit ("LCs"), which replace the LCs that relate to certain assets in the UK, Italy, Egypt and Greece that were issued under the previous facility with ING on a one-for-one basis. The interest rate, if drawn by way of loans, is 5% + SOFR.
Capital management
The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders and benefits to stakeholders and to safeguard the Group's ability to continue as a going concern.
Energean is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, the Group may put in place new debt facilities, issue new shares for cash, repay debt, engage in active portfolio management, adjust the dividend payment to shareholders, or undertake other such restructuring activities as appropriate.
|
|
|
2022 |
|
2021 |
|
|
|
$'000 |
|
$'000 |
|
Net Debt |
|
|
|
|
|
Current borrowings |
|
45,550 |
|
- |
|
Non-current borrowings |
|
2,975,346 |
|
2,947,126 |
|
Total borrowings |
|
3,020,896 |
|
2,947,126 |
|
Less: Cash and cash equivalents |
(427,888) |
(202,939) |
||
|
Restricted cash |
(74,776) |
- |
||
|
Net Debt (1) |
|
2,518,232 |
|
2,016,558 |
|
Total equity (2) |
|
650,198 |
|
717,123 |
|
Gearing Ratio (1)/(2): |
|
387.3% |
|
281.2% |
15. Provisions
|
($'000) |
Decommissioning |
Provision for litigation and other claims |
Total |
|
At 1 January 2021 |
865,127 |
16,408 |
881,535 |
|
New provisions |
- |
520 |
520 |
|
Change in estimates |
(18,808) |
(4,494) |
(23,302) |
|
Recognised in property, plant and equipment |
(13,174) |
|
(13,174) |
|
Recognised in Intangible assets |
2,202 |
|
2,202 |
|
Recognised in profit& loss |
(7,836) |
|
(7,836) |
|
Payments |
(2,653) |
- |
(2,653) |
|
Unwinding of discount |
8,722 |
- |
8,722 |
|
Currency translation adjustment |
(50,290) |
(1,140) |
(51,430) |
|
At 31 December 2021 |
802,098 |
11,294 |
813,392 |
|
Current provisions |
12,366 |
- |
12,366 |
|
Non-current provisions |
789,732 |
11,294 |
801,026 |
|
At 1 January 2022 |
|
|
|
|
New provisions |
- |
1,619 |
1,619 |
|
Change in estimates |
49,313 |
(551) |
48,762 |
|
Recognised in property, plant and equipment |
21,685 |
|
21,685 |
|
Recognised in profit& loss |
27,628 |
|
27,628 |
|
Payments |
(8,898) |
(344) |
(9,242) |
|
Reclassification |
- |
(1,568) |
(1,568) |
|
Unwinding of discount |
21,495 |
- |
21,495 |
|
Currency translation adjustment |
(55,251) |
(1,104) |
(56,355) |
|
At 31 December 2022 |
808,757 |
9,346 |
818,103 |
|
Current provisions |
8,376 |
- |
8,376 |
|
Non-current provisions |
800,381 |
9,346 |
809,727 |
Decommissioning provision
The decommissioning provision represents the present value of decommissioning costs relating to oil and gas properties, which are expected to be incurred up to 2042 when the producing oil and gas properties are expected to cease operations. The future costs are based on a combination of estimates from an external study completed in previous years and internal estimates. These estimates are reviewed annually to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required that will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This, in turn, will depend upon future oil and gas prices and the impact of energy transition and the pace at which it progresses which are inherently uncertain. The decommissioning provision represents the present value of decommissioning costs relating to assets in Italy, Greece, UK, Israel and Croatia. No provision is recognised for Egypt as there is no legal or constructive obligation as at 31 December 2022.
|
|
Inflation assumption |
Discount rate assumption |
Cessation of production assumption |
Spend in 2022 |
2022 ($'000) |
2021 ($'000) |
|
Greece |
1.6%- 2.2% |
4.6% |
2034 |
- |
13,036 |
17,058 |
|
Italy |
5.2%- 2.0% |
3.3% |
2023-2042 |
7,616 |
519,749 |
527,801 |
|
UK |
3.7% |
4.1% |
2023-2031 |
1,281 |
176,063 |
203,246 |
|
Israel |
2.3%-2.7% |
4.1% |
2042 |
- |
84,299 |
35,525 |
|
Croatia |
5.2%- 2.0% |
3.3% |
2032 |
- |
15,610 |
18,467 |
|
Total |
|
|
|
8,897 |
808,757 |
802,097 |
16. Trade and other payables
|
|
2022 ($'000) |
2021 ($'000) |
|
Trade and other payables-Current1 |
||
|
Financial items |
|
|
|
Trade accounts payable |
298,091 |
109,525 |
|
Payables to partners under JOA2 |
58,336 |
43,499 |
|
Deferred licence payments due within one year |
13,345 |
- |
|
Deferred consideration for acquisition of minority |
144,326 |
167,228 |
|
Other creditors |
34,644 |
12,043 |
|
Short term lease liability |
9,208 |
8,253 |
|
|
557,950 |
340,548 |
|
Non-financial items |
|
|
|
Accrued expenses3 |
98,650 |
64,823 |
|
Contract Liability4 |
56,230 |
|
|
Other finance costs accrued |
39,672 |
36,693 |
|
Social insurance and other taxes |
4,372 |
7,643 |
|
|
198,924 |
109,159 |
|
|
756,874 |
449,707 |
|
Trade and other payables-Non-Current |
||
|
Financial items |
|
|
|
Trade and other payables5 |
169,360 |
- |
|
Deferred licence payments6 |
38,488 |
57,230 |
|
Contingent consideration |
86,320 |
78,450 |
|
Long term lease liability |
23,063 |
36,172 |
|
|
317,231 |
171,852 |
|
Non-financial items |
|
|
|
Contract Liability |
- |
53,537 |
|
Social insurance |
827 |
598 |
|
|
827 |
54,135 |
|
|
318,058 |
225,987 |
1The statement of financial position as at 31 December 2022 presents current tax liabilities separately from the current portion of trade and other payables. Comparative amounts of $5,279,000 have been reclassified accordingly.
2 Payables related to operated Joint operations primarily in Italy.
3 Included in trade payables and accrued expenses in 2022 and 2021, are mainly Karish field related development expenditures (mainly FPSO and Sub Sea construction cost), development expenditure for Cassiopea project in Italy and NEA/NI project in Egypt.
4 In June 2019, Energean signed a Detailed Agreement with Israel Natural Gas Lines ("INGL") for the transfer of title (the "hand over") of the nearshore and onshore part of the infrastructure that will deliver gas from the Karish and Tanin FPSO into the Israeli national gas transmission grid. As consideration, INGL will pay Energean 369 million Israeli New Shekels (ILS), which translates to approximately $115 million, for the infrastructure being built by Energean in accordance with milestones detailed in the agreement. The agreement covers the onshore section of the Karish and Tanin infrastructure and the near shore section of pipeline extending to approximately 10km offshore. The amount included in the contract liability line above represents the amount received as of 31 December 2022 from INGL. The handover to INGL is expected to be effective in Q1 2023.
5 The amount represents an amount payable to Technip in respect of costs incurred starting 1 April 2022 until completion, in terms of the EPCIC contract. The amount is payable in eight equal quarterly deferred payments due after practical completion date and therefore has been discounted at 5.831%. p.a. (being the yield rate of the senior secured loan notes, maturing in 2024, at the date of entering into the settlement agreement).
6 In December 2016, Energean Israel acquired the Karish and Tanin offshore gas fields for $40.0 million closing payment with an obligation to pay additional consideration of $108.5 million plus interest inflated at an annual rate of 4.6% in ten equal annual payments. As at 31 December 2022 the total discounted deferred consideration was $51.8 million (as at 31 December 2021: $57.23 million). The Sale and Purchase Agreement ("SPA") includes provisions in the event of Force Majeure that prevents or delays the implementation of the development plan as approved under one lease for a period of more than ninety (90) days in any year following the final investment decision ("FID") date. In the event of Force Majeure the applicable annual payment of the remaining consideration will be postponed by an equivalent period of time, and no interest will be accrued in that period of time as well. Due to the effects of the COVID-19 pandemic which constitute a Force Majeure event, the deferred payment due in March 2022 would be postponed by the number of days that such Force Majeure event last. As of 31 December 2021 Force Majeure event length has not been finalised as the COVID-19 pandemic continues to affect the progress of the project, and as such the deferred payment due in March 2022 was postponed accordingly.
17. Contingent consideration
The share purchase agreement (the "SPA") dated 4 July 2019 between Energean and Edison SpA provides for a contingent consideration of up to $100.0 million subject to the commissioning of the Cassiopea development gas project in Italy. The consideration was determined to be contingent on the basis of future gas prices (PSV) recorded at the time of first gas production at the Cassiopea field, which is expected in 2024. No payment will be due if the arithmetic average of the year one (i.e., the first year after first gas production) and year two (i.e., the second year after first gas production) Italian PSV Natural Gas Futures prices is less than €10/Mwh when first gas production is delivered from the field. US$100 million is payable if that average price exceeds €20/Mwh.
The fair value of the Contingent Consideration is estimated by reference to the terms of the SPA and the simulated PSV pricing by reference to the forecasted PSV pricing, historical volatility and a log normal distribution, discounted at a cost of debt.
Noting the natural gas future prices for PSV are currently in excess of the €20/MWh (the threshold for payment of $100 million), we estimate the fair value of the Contingent Consideration as at 31 December 2021 to be $86.3 million based on a Monte Carlo simulation.
|
|
|
|
|
Contingent consideration |
2022 |
|
|
1 January |
78,450 |
|
|
Fair value adjustment |
7,870 |
|
|
31 December |
86,320 |
|
|
|
|
|
18. Dividends
In September 2022, Energean declared its maiden quarterly dividend. In total, Energean returned US$0.60/share to shareholders in 2022, representing two-quarters of dividend payments. No dividend was proposed in respect of the year ended 31 December 2021.
|
|
US$ Cents per share |
Total dividend paid $'000 |
||
|
|
2022 |
2021 |
2022 |
2021 |
|
Dividends announced and paid in cash |
|
|
|
|
|
Ordinary shares |
|
|
|
|
|
September |
30 |
- |
53,252 |
- |
|
December |
30 |
- |
53,252 |
- |
|
|
60 |
- |
106,504 |
- |
19. Events after the reporting period
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 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.
[1] 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 million euros 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 $29.3 million 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 €87 million in June 2023.
[2] Based on 21 March 2023 share price of GBp 11.00
[3] On an annualised basis
[4] Adjusted EBITDAX is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, share-based payment charge, impairment of property, plant and equipment, other income and expenses, net finance costs and exploration and evaluation expenses.
[5] Including 10 mmboe that is located in the Abu Qir licence, but will be developed through the NEA/NI development
[6] $101 million of the total facility is reserved for the issuance of Letters of Credit
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