REG - Energean PLC - 2025 Full Year Results
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RNS Number : 2943X Energean PLC 19 March 2026
Energean plc
("Energean" or the "Company")
2025 Full Year Results
London, 19 March 2026 - Energean plc (LSE: ENOG, TASE: אנאג) is pleased to
announce its full-year results for the year ended 31 December 2025 ("FY
2025").
Mathios Rigas, Chief Executive Officer of Energean,
commented:
"In 2025, we demonstrated the underlying resilience of our business, despite
the challenging backdrop. We delivered robust financial and operational
performance, and we further enhanced the long‑term value and cash flow
visibility of our portfolio, signing >$4 billion of new gas sales
agreements and investing in new export infrastructure in Israel.
"Although we had a strong start to 2026, production in Israel is currently
suspended following a government-ordered shutdown in response to the recent
geopolitical situation in the Middle East. The safety of our people remains
our highest priority. We are in close and continuous communication with the
authorities to ensure that operations can be safely restarted as soon as
conditions allow, to continue supporting energy security for Israel and, in
turn, that of the wider region.
"As we move forward, our priorities for our current portfolio remain clear: to
operate safely, efficiently and cost effectively, and to maximise the value of
our current asset base.
"2026 marks an important inflection point for our Company as we enter a new
stage of growth. Our M&A strategy remains focused on long-term growth and
diversification, whilst maintaining strict capital discipline and
value-creation for our shareholders. This is already evident through the
successful completion of ExxonMobil's farm-in to Block 2 in Greece,
post-period end.
"Our entry into offshore Angola represents the first step in this new chapter
of growth in West Africa. It is a region rich in potential, with multiple
opportunities to unlock value both through near‑term cost and production
optimisation and longer‑term development optionality.
"While Angola is an important milestone, it is only the beginning. We continue
to actively evaluate additional opportunities, including in our existing
countries of operations, where we have a competitive advantage as an
experienced operator. I am confident that we are well positioned to deliver
the next phase of our journey, as we have done before."
Results summary
2025 2024 1 Increase/ (Decrease) %
Energean Group Energean Group
Lost Time Injury Frequency (no. per million hours worked) 0.20 0.34 (41%)
Total Recordable Injury Rate (no. per million hours worked) 0.40 0.52 (23%)
Emissions intensity (kgCO2e/boe) 7.5 8.4 (11%)
Average daily working interest production (kboed) 154 153 1%
Total revenue and other income ($m) 1,773 1,780 -%
Realised weighted average liquid price ($/boe) 59 71 (17%)
Realised weighted average gas ($/mcf) 4.9 4.7 4%
Cash cost of production 2 ($m) 563 559 1%
Cash cost of production per barrel ($/boe) 10 10 -%
Cash G&A 3 38 37 3%
Adjusted EBITDAX 4 ($m) 1,117 1,162 (4%)
(Loss)/Profit after tax ($m) (258) 5 127 (303%)
Earnings per share ($ per share) ($1.40) $0.69 (303%)
Dividend per share ($ per share) $1.20 $1.20 -%
Cash flow from operating activities ($m) 1,144 1,122 2%
Capital expenditure ($m) 587 733 (20%)
Decommissioning expenditure ($m) 62 44 41%
2025 2024
Energean Group Energean Group
Total borrowings ($m) 3,585 3,270
Cash and cash equivalents and restricted cash ($m) 330 321
Net debt ($m) (including restricted cash) 3,255 2,949
Leverage Ratio (Net Debt/ Adjusted EBITDAX) 2.9x 2.5x
2025 Review:
Resilient business performance, focused on operational excellence
· Strong safety performance and emissions reduction achieved:
o Lost Time Injury Frequency of 0.20 (2024: 0.35) and Total Recordable
Injury Rate of 0.40 (2024: 0.52), well below the Group's full year targets.
o Scope 1 and 2 emissions intensity of 7.5 kgCO2e/boe, an 11% reduction
year-on-year (2024: 8.4 kgCO2e/boe).
· Group average working interest ("W.I.") production in 2025 was
154 kboed (85% gas), reflecting strong performance in the second half of the
year, particularly in Israel, resulting in Group production at the upper end
of the revised guidance range of 145-155 kboed. Group output remained flat
versus 2024, despite the temporary suspension in Israel in June, following a
directive from the Ministry of Energy and Infrastructure due to regional
geopolitical developments.
· Total revenue and other income of $1,773 million and adjusted
EBITDAX of $1,117 million, in line with the prior year, despite the
aforementioned geopolitical challenges and lower year-on-year Brent prices.
o Loss after tax is reflective of exceptional non-cash items, principally
related to downgrade of Cassiopea reserves and the resulting impairment,
acceleration of depreciation, and its associated tax effects, and foreign
exchange losses driven by euro strengthening against US$. See 'Financial
Review' section and note 8 to the financial statements.
Unlocking full asset potential to maximise cash flow
· In Israel, we signed over $4 billion in new long-term gas
contracts, to supply new build power stations to meet Israel's growing gas
demand, and invested in the new Nitzana export pipeline to increase sales,
with development underway.
· In Egypt, we stabilised our year-on-year receivables position.
Post-period end, EGPC gave Energean notice of its intention to reduce further
the outstanding receivable balance. Energean is in advanced discussions to
merge its three offshore concessions, with agreed terms targeted around
mid-year 2026, with parliament ratification to follow.
Continued discipline on costs and capital allocation
· No near-term maturities following refinancing of project and
corporate bonds during 2025, in addition to a post-period extension of other
third-party borrowings and the re-start of the Prinos field in Greece (refer
to note 13 to the financial statements).
· Efficient operator, with cost of operations (excluding royalties)
maintained at $6/boe year-on-year.
· Disciplined re-investment programme, with $586 million of
development and production expenditure invested over the year, of which $331
million was on Katlan, Energean's principal growth project, and $51 million
was on the Nitzana export pipeline.
· $221 million dividends returned to shareholders.
Focused on disciplined growth:
Launching the next stage of our growth strategy through our entry into
offshore Angola
· As announced on 12 March 2026, Energean has signed an agreement
to acquire Chevron's 31% operated interest in Block 14 and 15.5% non-operated
interest in Block 14K, offshore Angola. The acquired assets include ten
producing oil fields, and the acquisition is in line with the Group's
strategic M&A objectives:
o Expansion into the wider EMEA region.
o Value-creation, which is underpinned by a supportive regulatory
environment, identifiable operating-cost synergies, and multiple low-risk and
near-term opportunities to optimise and maximise existing production.
o Disciplined growth; there is optionality within the acquired acreage,
including the potential PKBB development and additional infill well targets,
and the acquisition provides a platform for long-term growth in Angola and the
wider region.
Further growth opportunities remain under active evaluation
· Beyond this initial step, Energean continues to evaluate
opportunities capable of growing our portfolio over the long term.
· We are actively screening growth opportunities across the EMEA
region, including in our existing countries of operations, where we believe we
have a competitive advantage as an experienced operator.
· Our M&A strategy remains focused on long-term growth and
diversification, underpinned by strict capital discipline, an intention to
reduce leverage over time and a clear focus on creating value for
shareholders.
Actively pursuing multiple opportunities to grow the business and enhance
profitability, with continued capital discipline:
· Angola country entry expected to close by year-end 2026,
conditional inter alia on the timely receipt of approvals and waiver of
pre-emption rights.
· Active pipeline of strategic M&A opportunities under
evaluation.
· East Bir El-Nus ("EBEN"; onshore Egypt) exploration drilling to
begin towards the end of Q2 2026.
· Block 2 (Greece) farm-down agreement complete, with exploration
drilling expected to begin in early 2027, subject to permitting.
· Agreed terms for the Egypt merger concession targeted for around
mid-year 2026, with parliament ratification to follow. The resultant single
concession is expected to improve the commercial and fiscal conditions, unlock
additional reserves and new development and exploration opportunities, and
extend the economic life of the fields.
· Maintain strict cost control, with targeted cost reductions and
disciplined capital allocation.
2026 Guidance:
· Average W.I. production to end-February averaged 155 kboed, of
which 118 kboed was in Israel, in line with the full year 2026 guidance given
in January 2026 6 of 145-155 kboed.
o On 28 February 2026, Energean received notice from the Ministry of Energy
and Infrastructure ordering the temporary suspension of production and
activities of the Energean Power FPSO, following geopolitical escalations in
the region. As of the time of writing, production in Israel remains suspended.
Energean continues to monitor the situation closely, with the safety of its
people its top priority.
o The impact to 2026 Group production guidance will be assessed once the
duration and full impact of the suspension is known; at this time, guidance
for Israel is suspended (see '2026 Guidance' section).
o Rest of Portfolio production guidance of 32-36 kboed remains unchanged.
· Update on development projects:
o As of the time of writing, there is no anticipated change to the Katlan
first gas timetable of H1 2027. The impact, if any, on the timetable will be
assessed once the full extent of the suspension is known.
o Prior to the suspension, commissioning of the second oil train had been on
track to complete by the end of Q1, with hydrocarbon testing through the
module already underway. Following the resumption of operations, Energean
expects commissioning to complete over a few weeks.
Conference Call
A webcast will be held today at 08:30 GMT / 10:30 Israel Time.
Webcast registration, including conference call registration:
https://energean-fy-2025-results-call-march-2026.open-exchange.net/
(https://energean-fy-2025-results-call-march-2026.open-exchange.net/)
Enquiries
For capital markets:
Kyrah McKenzie, Investor Relations Manager Tel: +44 7921 210 862
ir@energean.com (mailto:ir@energean.com)
For media:
Adonis Seferlis, CEO Office Communications Manager Tel: +30 697 2414262
aseferlis@energean.com (mailto:aseferlis@energean.com)
Ben Brewerton, FTI Consulting Tel: +44 2037 271 065
energean@fticonsulting.com (mailto:energean@fticonsulting.com)
Operational Review
Health, Safety and the Environment
In 2025, the Lost Time Injury Frequency ("LTIF") Rate was 0.20 (2024: 0.35)
and the Total Recordable Incident Rate ("TRIR") was 0.40 (2024: 0.52), an
improvement versus the prior year and well below the Group's full year
targets.
Scope 1 and 2 emissions intensity on an equity share basis was 7.5 kgCO2e/boe,
a reduction of 11% from 2024 (8.4 kgCO2e/boe) due to reduced non-routine
flaring in Israel.
Reserves
Group year-end 2025 working interest 2P reserves were 989 mmboe 7 , a 1%
decrease year-on-year before 2025 production volumes (56 mmboe). This reflects
the 25 mmboe downward revision to Cassiopea reserves, as a result of asset
performance that has been lower than the Operator's initial expectations,
which has been partly offset by additions in the rest of Italy, as well as in
Egypt, Greece and the UK.
2024 Revision and discoveries 2025 production 2025 % change before 2025 production % change after 2025 production
2P reserves mmboe mmboe 2P reserves
mmboe mmboe
Israel 864 (89% gas) (5) (41) 818 (90% gas) (1%) (5%)
Egypt 64 (83% gas) 3 (11) 56 (84% gas) 4% (12%)
Italy 79 (52% gas) (13) (4) 62 (22% gas) (17%) (21%)
Greece 44 (2% gas) 2 (0) 45 (2% gas) 3% 3%
UK 3 (17% gas) 2 (0) 4 (19% gas) 63% 49%
Croatia 4 (100% gas) (1) (0) 4 (100% gas) (13%) (13%)
Total 2P reserves 1,058 (82% gas) (13) (56) 989 (81% gas) (1%) (7%)
Production and Operational Update
Group working interest production averaged 154 Kboe/d in 2025 (2024: 153
Kboe/d), with the Karish and Karish North fields in Israel contributing over
70% of total output. Group output was flat versus 2024, despite the temporary
suspension of production in Israel in June, following an order from the
Ministry of Energy and Infrastructure due to regional geopolitical
developments.
2025 2024 % change
Kboed Kboed
Israel 113 (88% gas, equivalent to 5.6 bcm) 112 (87% gas, equivalent to 5.5 bcm) 1%
Egypt 29 (84% gas) 30 (86% gas) (3%)
Rest of portfolio 12 (51% gas) 12 (34% gas) 0%
Total production 154 (85% gas) 153 (83% gas) 1%
This table may not cast due to rounding.
Israel
Karish and Karish North
Production from Israel averaged 113 Kboe/d in 2025, up 1% year-on-year. 2025
production was notably impacted by the temporary suspension of production in
Israel in June 2025, as outlined below. Following the resumption of
production, output rebounded reflecting strong summer gas demand, with Israel
averaging 138 Kboe/d in Q3 2025, up 54% versus Q2 2025 and up 2% versus Q3
2024.
FPSO uptime (excluding planned and government-enforced shutdowns) averaged 99%
for the 12 months to 31 December 2025. On 13 June 2025, the Ministry of Energy
and Infrastructure ordered a temporary suspension of production and activities
of the Energean Power FPSO, including activities related to the second oil
train commissioning. Production was subsequently restarted on 25 June 2025.
Commissioning of the second oil train, which will result in an increase in
liquids production capacity, was subsequently deferred to avoid non-essential
shutdowns during peak demand periods.
Post-period end, on 28 February 2026, Energean received notice from the
Ministry of Energy and Infrastructure ordering the temporary suspension of
production and activities of the Energean Power FPSO, following geopolitical
escalations in the region. As of the time of writing, production in Israel
remains suspended. Energean continues to monitor the situation closely, with
the safety of its staff its top priority.
Prior to the suspension, commissioning of the second oil train commissioning
had been on track to complete by the end of Q1 2026, with hydrocarbon testing
through the module already underway. Following the resumption of operations,
Energean expects commissioning to complete over a few weeks.
Katlan
During 2025, Energean made good progress on the Katlan project, advancing
pre-drilling, subsea and FPSO workstreams.
• All major contracts were signed, including the drilling contract
for the Athena and Zeus development wells;
• Subsea engineering, procurement and manufacturing was c.50%
complete (as at end-February 2026);
• FPSO topside (Monoethylene Glycol ("MEG") unit) manufacturing
was c.55% complete (as at end-February 2026);
• In country offshore execution preparations, including the
logistic base at Haifa, were completed;
As of the time of writing, there is no change to the Katlan first gas
timetable of H1 2027. The impact, if any, on the timetable will be assessed
once the full extent of the suspension is known.
Commercial
Gas
Domestic
Energean has signed over 20 long-term gas sale and purchase agreements
("GSPAs") to customers in Israel, all of which include take-or-pay commitments
or an exclusivity provision and floor pricing, providing a high level of
certainty over revenues from Israel over the next 20 years. Energean also has
around half a dozen spot sales agreements, which provides the ability to boost
sales at pricing above the contracted sales prices.
In line with the Group's target to sign new long-term gas contracts, two new
gas sales agreements, described below, were signed during the period to supply
two new power plants to meet Israel's growing gas demand. Combined, these
contracts amount to over $4 billion in future revenues over the next two
decades, which brings the total contracted revenues over a 20-year period to
around $20 billion. 8
In April 2025, a Gas Sale and Purchase Agreement ("GSPA") was signed with
Kesem Energy Ltd for the supply of ~1 bcm/yr from around the middle of the
2030s until the end of the contract period. Prior to this, Energean Israel
will supply limited quantities of gas intermittently. The contract represents
over $2 billion in revenues and ~12.5 bcm in contracted supply over the ~17
year period.
In November 2025, a GSPA was signed with Dalia Energy Companies Ltd.,
representing over $2 billion in contracted revenues. The contract is for
approximately 0.5 bcm/yr from around January 2030 and then approximately 1.2
bcm/yr from June 2035 onwards, and excludes supply in the summer months (June
to September) between 2030-2034.
Exports
In October 2025, Energean Israel Limited ("Energean Israel") signed a
transmission agreement with Israel Natural Gas Lines Ltd. ("INGL") for
capacity in the Nitzana pipeline, in line with Energean's strategic focus on
long-term value creation. The Nitzana pipeline is a new onshore pipeline that
will be built from Ramat Hovav to the border with Egypt in the Nitzana area.
The agreed terms in the transmission agreement are for the supply of up to 1
bcm/yr for a 15-year period, with provisions for extensions and early
termination. The terms also include rights, during the construction phase, to
access available capacity in the Jordan-North pipeline. Nitzana is expected to
be operational no later than October 2028.
Energean Israel's 16.4% share of the construction costs for the pipeline and
compression station is expected to be approximately $100 million, and is
primarily being funded via an unsecured $70 million nine-year term loan
facility ("Unsecured Term Loan") provided by Bank Hapoalim. During the fourth
quarter of 2025, approximately $50 million was paid, representing around 50%
of the total expected investment. The remaining investment will be made in
accordance with the milestones set out in the agreement with INGL. At 31
December 2025, $33 million was drawn under the Unsecured Term Loan.
Energean has signed a non-binding term sheet with an East Mediterranean client
for the offtake of its exported gas(( 9 )).
Liquids
The FPSO has a hydrocarbon liquids storage capacity of up to 800,000 bbls,
with cargoes exported via tankers every few weeks. Energean has an agreement
with Vitol SA for the offtake of a number of cargoes of its hydrocarbon
liquids.
Egypt
Production
Working interest production from Egypt averaged 29 Kboe/d (84% gas) in 2025,
demonstrating successful arrest of typical natural decline in these assets
following strong performance of the Location B well.
Growth opportunities
Energean is in advanced discussions with the Egyptian authorities to merge
Energean's three production concessions (Abu Qir, NEA and NI) into a single
concession. The resultant single concession is expected to improve the
commercial and fiscal conditions, unlock additional reserves and new
development and exploration opportunities, and extend the economic life of the
fields. Agreed terms are targeted around mid-year 2026, with parliament
ratification to follow.
Exploration drilling on the onshore East Bir El-Nus block is expected to begin
towards the end of Q2 2026.
Receivables
The Group's net receivables position (after provision for expected credit
loss) at 31 December 2025 was $209 million, of which $166 million was
classified as overdue, and flat year-on-year after taking into account the
portion received in the first days of January. In 2025 and in early 2026, EGPC
gave Energean notice of its intention to reduce the outstanding receivable
balance, with $80 million collected around the turn of the year (a portion of
which was collected in the first days of January). Post-period end, EGPC gave
Energean notice of its intention to reduce further the outstanding receivable
balance.
Europe
Production
Working interest production from the Group's European portfolio (Italy,
Greece, the UK and Croatia) averaged 12 Kboe/d (51% gas) in 2025, up 9%
year-on-year due primarily to the contribution of Cassiopea in Italy. Italy
production on a standalone basis averaged 10 Kboe/d in 2025 (2024: 9 Kboe/d),
of which just under 4 kboed was from Cassiopea, which was lower than the
Operator's initial expectations and has led to a downward revision to
remaining 2P reserves. See Note 8 to the financial statements.
Italy
Energean has 46 production and development concessions in Italy, 13 of which
it operates.
A work programme amendment was submitted to the Ministry in July 2025 for the
potential Vega West development, which contains ~10 mmbbl in the first phase
and an additional 23 mmbbl in the full development scenario. Production at
Rospo Mare resumed in October 2025 at rates of 2 kbbl/d following the fire
incident in January 2025. Income from lost production and expenditure incurred
to remediate the damage at this field are covered by Energean Italy's
insurance cover, with $33 million received in 2025.
During the period, formal arbitration proceedings commenced between Energean
Italy S.p.A. ("Energean Italy") and the Operator of the Cassiopea field. Refer
to Note 18 to the financial statements.
Croatia
In July 2025, Energean (70% working interest), alongside its partner INA -
INDUSTRIJA NAFTE d.d. ("INA"), took Final Investment Decision ("FID") for the
development of the Irena gas field. The development plan is for a single
platform tie-back to the existing infrastructure at the Izabela field;
Energean's net share of the capital expenditure is expected to be EUR 50
million. First gas is expected in H1 2027, with peak production anticipated at
around 8-10 mmscfd gross (1,400-1,800 boe/d).
UK
Energean is focused on optimising production from its late-life assets and
effectively managing its decommissioning obligations.
The Wenlock, Garrow and Kilmar well plug and abandonment ("P&A")
campaigns, which Energean is operator for, were safely and successfully
completed on schedule and below budget.
On its non-operated Scott field (W.I. 10%; non-operated), in 2025 one infill
well was brought online and drilling of another well began in Q4, and is
expected to be brought online later this year. Additional infill well drilling
activity is expected in 2026.
Greece
In November 2025, ExxonMobil signed a farm-in agreement for Energean and
HELLENiQ ENERGY Upstream's Block 2 concession, located in the northwestern
Ionian Sea, adjacent to the Italian Exclusive Economic Zone (EEZ). The
transaction was completed post-period end in March 2026. Energean will remain
the operator during the exploration stage, and in the event of a discovery,
ExxonMobil will assume operatorship. The new participating interests are:
Energean (30%, operator), ExxonMobil (60%) and HELLENiQ ENERGY Upstream (10%).
Drilling is anticipated to begin in early 2027, subject to permitting.
In May 2025, production at the Prinos field, which produces small quantities
of oil, was temporarily suspended for economic reasons due to high operating
costs, in particular electricity costs. Operating costs have been restructured
to a leaner cost base, which has resulted in the restart of production in
February 2026.
Financing
In February 2025, the Group signed a 10-year, $750 million senior secured term
loan with Bank Leumi, which was used to refinance the $625 million 4.875%
Senior Secured Notes due 2026 and to provide additional liquidity for the
Katlan development. In addition, the Group issued €400 million of 5.625%
Senior Secured Notes due 2031 to repay the 6.5% $450 million Senior Secured
Notes due 2027. The $300 million Revolving Credit Facility was also extended
to September 2028. Taken together with the post-period extension of other
third-party borrowings and the re-start of the Prinos field in Greece, this
removes near-term debt maturities and increases the weighted average maturity
to six years, with a weighted average cost of debt of 7%.
2026 Guidance
On 28 February 2026, Energean received notice from the Ministry of Energy and
Infrastructure ordering the temporary suspension of production and activities
of the Energean Power FPSO, following geopolitical escalations in the region.
As of the time of writing, production in Israel remains suspended. Energean
continues to monitor the situation closely, with the safety of its people its
top priority.
Due to the ongoing uncertainty of the duration of this suspension of
production and operations in Israel, the Company is unable to provide an
update to its previously issued 2026 Israel production, Cost of Operations
(operating costs plus royalties) and Group net debt guidance. We have
therefore suspended our previously issued guidance given in January 2026.
Rest of Portfolio guidance, in addition to Group cash G&A, exploration
expenditure, and decommissioning expenditure, remains unchanged.
FY 2026 Guidance
Production
Rest of portfolio (kboed) 32 - 36*
Cash Cost of Production (operating costs plus royalties)
Rest of portfolio ($ million)** 190 - 210 (includes 10-15 royalties in Italy)
Group cash G&A ($ million) 35 - 40
Development and production capital expenditure
Rest of portfolio ($ million)*** 90 - 100
Group exploration expenditure ($ million) 5 - 10
Group decommissioning spend ($ million) 60 - 70
* Excludes Cassiopea
** Rest of portfolio guidance includes $20-25 million of flux costs in Italy,
which are not reflected in the production guidance but are included in the
sales revenue actuals.
*** Guidance excludes $130-135 million of contingent Prinos Carbon Storage
expenditure which is expected to be funded by grants.
Financial Review
Financial results summary
The Group delivered a resilient financial performance in 2025, maintaining
production at 154 kboed and generating adjusted EBITDAX of $1,117 million and
operating cash flow of $1,144 million, despite a challenging external
environment that included a temporary suspension of production and operations
at the FPSO in Israel and lower year-on-year realised oil prices. The Group
reported a loss after tax of $258 million (FY 2024: profit of $127 million),
driven mainly by non-cash charges, including a $286 million impairment and
$135 million of higher depreciation of the Cassiopea asset and the associated
$124 million derecognition of deferred tax assets in Italy, following the
reduction in reserves. Adjusting for these non-cash items, the underlying
performance of the Group remained robust.
During the year, the transaction for the sale of the Egypt, Italy and Croatia
portfolio did not complete following the expiry of the longstop date on 20
March 2025. As a result, the assets previously classified as held for sale
have been reclassified to continuing operations, and the 2024 comparative
financial statements have been restated accordingly. Throughout this review,
prior year figures reflect the restated comparatives unless otherwise stated.
Notwithstanding these challenges, the Group continued to deliver on its
capital allocation priorities: investing in the Katlan development, its
principal growth project; refinancing its 2026 and 2027 notes via a new $750
million term loan and €400 million senior secured notes, which, in addition
to post-period events, ensures no near-term maturities; and maintaining a
quarterly dividend of $0.30 per share, totalling $1.20 per share for the year.
FY 2025 FY 2024 Increase/ (Decrease) %
Energean Group Energean Group
Average daily working interest production (kboed) 154 153 1%
Total revenue and other income ($m) 1,773 1,780 -%
Realised weighted average liquid price ($/boe) 59 71 (17%)
Realised weighted average gas price ($/mcf) 4.9 4.7 4%
Realised weighted average PSV gas price (€/MWh) 38 35 9%
Cash cost of production(( 10 )) ($m) 563 559 1%
Cash cost of production per barrel ($/boe) 10 10 -%
Cash G&A(( 11 )) 38 37 3%
Adjusted EBITDAX(( 12 )) ($m) 1,117 1,162 (4%)
(Loss)/Profit after tax ($m) (258) 127 (303%)
(Loss)/Earnings per share (cents per share) ($1.40) $0.69 (303%)
Dividend per share (cents per share) $1.20 $1.20 -%
Cash flow from operating activities ($m) 1,144 1,122 2%
Capital expenditure ($m) 587 733 (20%)
Revenue, production and commodity prices
Group working-interest production averaged 154 kboed in FY 2025 (FY 2024: 153
kboed). Production was broadly stable year-on-year, with Karish and Karish
North fields continuing to be the main contributors.
In 2025, production in Israel averaged 113 kboed (FY 2024: 112 kboed).
Production in Israel was temporarily suspended for a period in June following
an order from the Ministry of Energy and Infrastructure due to geopolitical
escalations in the region. In Egypt, production averaged 29 kboed (FY 2024: 30
kboed), reflecting natural field decline. In Italy, production increased to 10
kboed (FY 2024: 9 kboed), reflecting the contribution of Cassiopea volumes in
the first three quarters, after which Energean Italy's share of gas production
from the concession was retained by the field operator following a contractual
dispute (see Note 18 to the financial statements). Production from the rest of
the Group's assets in the UK, Greece and Croatia averaged 2 kboed (FY 2024: 2
kboed), around two thirds of which was from the non-operated Scott and Telford
fields in the UK. The Group's production mix continued to be weighted towards
gas, with gas representing 85% of production and liquids 15% (FY 2024: 83% and
17% respectively).
Total revenues from production activities were $1,728 million in FY 2025 (FY
2024: $1,779 million), a 3% decrease year-on-year. The reduction was driven by
lower realised liquids prices and, to a lesser extent, lower liquids volumes.
The Group's realised weighted average gas price was $4.9/mcf, 4% higher than
FY 2024 ($4.7/mcf). In Italy, the average realised PSV gas price increased to
€38.5/MWh (FY 2024: €35.3/MWh), supporting a 6% increase in total gas
revenue to $1,165 million (FY 2024: $1,096 million). Conversely, the realised
weighted average liquids price decreased by 17% to $59.3/boe (FY 2024:
$71.2/boe), reflecting weaker Brent crude pricing, with total liquids revenue
declining by 25% to $492 million (FY 2024: $652 million).
Other revenue of $40 million (FY 2024: nil), included within total revenue
from production activities, comprised $27 million insurance proceeds received
for lost production at the Rospo field following a fire incident in Italy, and
$13 million of income recognised in respect of non-cash settlement of
outstanding payables to the Cassiopea operator (refer to note 18 to the
financial statements).
Adjusted EBITDAX was $1,117 million (FY 2024: $1,162 million), a 4% decrease
year-on-year, with the reduction in revenues partially mitigated by stable
operating costs and insurance proceeds. The EBITDAX margin improved to 66% (FY
2024: 65%), reflecting effective cost management across the portfolio.
Underlying cash production costs
Total cash production costs (including royalties) for the period were $563
million (FY 2024: $559 million), broadly stable year-on-year despite
inflationary pressures and the strengthening of the Euro against the US
dollar. Unit costs (including royalties) were $10/boe (FY 2024: $10/boe).
Israel accounted for approximately 60% of the Group's total absolute
production costs, reflecting its substantial share of overall production
volumes and the associated royalties. Excluding royalties, production costs
were $331 million (FY 2024: $320 million), with a representative unit cost of
$6/boe (FY 2024: $6/boe). The modest increase in costs excluding royalties was
driven primarily by higher energy as well as higher operational costs in Italy
following the Cassiopea field coming on stream, partly offset by lower costs
in Greece due to the temporary suspension of production for economic reasons.
Cash general and administrative expenses were $38 million (FY 2024: $37
million), a marginal increase reflecting higher staffing costs in Israel as
the Group invested in their people to support the Katlan development.
Depreciation
Depreciation charges increased significantly to $581 million (FY 2024: $413
million on a restated basis), mainly driven by two key factors: First, In
Italy, a downward revision of reserves at the Cassiopea field during the year
resulted in a substantial increase of $135 million in depreciation. Second, in
Israel, depreciation increased from $278 million to $292 million reflecting
the elevated depreciable base for future capital expenditure related to Tanin
development. On a per barrel basis, depreciation increased to $10.5/boe (FY
2024: $7.4/boe on a restated basis).
Other income
The Group recognised $21 million of insurance proceeds income in Israel and
$23 million of the reversal of prior period accruals no longer needed.
Exploration and evaluation expenses (or write offs) and new ventures
Total exploration and evaluation costs charged to the income statement were
$33 million (FY 2024: $155 million), a significant reduction reflecting the
prior year's write-off of exploration assets in Egypt (Orion X1, $63 million),
Greece (Ioannina, $16 million) and Morocco (Anchois, $65 million). In the
current year, exploration cost write-offs of $22 million related principally
to the Gemini exploration project in Italy, following the non-approval of the
work programme due to the ongoing dispute with the field operator. Staff costs
and other evaluation expenses of $11 million were broadly in line with the
prior year.
Impairment of oil and gas assets
The Group recognised a net impairment charge of $286 million during the period
(FY 2024: $96 million). The principal charge related to the Cassiopea asset in
Italy, where a downward revision of reserves led to a significant impairment
of the field's carrying value.
Expected credit loss
A net expected credit loss reversal of $10 million (FY 2024: charge of $7
million) was recognised, reflecting an improvement in the cash collection
environment in Egypt, where the Group's principal counterparty is the
state-owned Egyptian General Petroleum Corporation (EGPC).
Other operating expenses
Other operating expenses of $1 million (FY 24: $4 million) were materially
lower year on year.
Net finance costs
Total finance costs were $260 million (FY 2024: $272 million). This included
$194 million of interest on Senior Secured Notes, $45 million on bank
borrowings (of which the new Bank Leumi term loan was the main component
following its drawdown in March 2025), $49 million from the unwinding of
discounts (non-cash items) on decommissioning provisions, lease liabilities
and long-term payables, and $11 million in arrangement fees, commissions and
other bank charges. Capitalised borrowing costs of $41 million (FY 2024: $15
million) related primarily to the Katlan development.
Finance income of $6 million (FY 2024: $15 million) comprised interest on time
deposits, with the decrease reflecting lower average cash balances held on
deposit during the period.
Net foreign exchange losses of $38 million (FY 2024: gain of $13 million) were
driven by the strengthening of the Euro against the US dollar over the period,
impacting the Group's Euro-denominated provisions, payables and the new
Euro-denominated Senior Secured Notes issued during the year. A net loss on
derivatives of $3 million (FY 2024: nil) related to the settlement of foreign
exchange hedging instruments during the year.
Taxation
The Group recorded a tax expense of $231 million in FY 2025 (FY 2024: $85
million), notwithstanding a loss before tax of $28 million. The elevated tax
charge was driven mainly by derecognition of previously recognised deferred
tax assets in Italy of $124 million, reflected the absence of sufficient
forecast taxable profits in the Italian jurisdiction driven by the downward
revision of Cassiopea reserves.
The current tax expense includes $84 million of tax expense in Israel (FY
2024: $104 million) reflecting the continued profitability of the Karish and
Karish North operations. Egypt non-cash taxes of $25 million (FY 2024: $35
million) continued to be a significant component of the current tax charge.
The Group is within the scope of the Pillar Two Model Rules from 1 January
2025 and has applied the mandatory temporary exception under IAS 12 from
recognising and disclosing deferred taxes related to Pillar Two income. Based
on the assessment performed, including consideration of transitional safe
harbour provisions, the Group does not expect a material exposure to Pillar
Two top-up taxes.
(Loss)/Profit after tax and earnings per share
The Group reported a loss after tax of $258 million (FY 2024: profit of $127
million). As noted above, the result was heavily impacted by a) the Cassiopea
impairment, higher depreciation and associated tax effects, and b) the foreign
exchange losses. Excluding these items, the underlying operational performance
of the Group remained strong, underpinned by the contribution from Israel.
Loss per share was $(1.40) on both a basic and diluted basis (FY 2024:
earnings of $0.69).The weighted average number of ordinary shares was 184.1
million (FY 2024: 183.5 million).
Operating cash flow
Net cash inflow from operating activities was $1,144 million (FY 2024: $1,122
million), an increase of 2% year on year. The improvement reflected strong
underlying cash generation from Israel, supported by a working capital inflow
of $203 million as well as improved collection of overdue receivables in
Egypt, partially offset by higher income tax payments of $162 million (FY
2024: $6 million). Operating cash flow per boe was $20/boe, consistent with
the prior year.
Capital expenditure
Development and production capital expenditure was $587 million (FY 2024: $733
million), a decrease of 20% reflecting the completion of significant
development milestones in Italy (Cassiopea) and reduced exploration activity.
Development expenditure of $463 million (FY 2024: $561 million) was focused on
the Katlan development in Israel ($331 million), which represented the Group's
largest single capital programme, alongside continued investment in the Second
Oil Train, Cassiopea and Epsilon. Additional investment of $51 million was
directed to the Nitzana export pipeline project in Israel.
Decommissioning expenditure of $62 million (FY 2024: $44 million), comprising
$39 million related to the UK assets (Wenlock and Tors, and associated
infrastructure) and $23 million related to the Italian assets.
Exploration expenditure was negligible at $1 million (FY 2024: $117 million),
reflecting minimal activity versus the prior year which saw drilling campaigns
in Egypt and Morocco.
Cash capital expenditure per the cash flow statement was $860 million (FY
2024: $765 million). The difference compared to the accrual-based measure
primarily reflected a $283 million working capital outflow related to capital
activities.
Decommissioning and other provisions
The total decommissioning provision at 31 December 2025 was $835 million (FY
2024: $811 million). The movement during the year included a decrease of $28
million from changes in estimates primarily in Italy and Israel, payments of
$66 million relating to UK and Italian decommissioning campaigns, an unwinding
of discount charge of $35 million, and an increase of $82 million driven by
Euro/US dollar movements.
A provision for litigation and other claims of $56 million was also recognised
bringing total provisions to $891 million.
Net Debt
Net debt at 31 December 2025 was $3,255 million (FY 2024: $2,949 million). Net
debt excluding Israel was $718 million (FY 2024: $614 million).
Total borrowings of $3,585 million (FY 2024: $3,270 million) comprised:
· the 5.375% Senior Secured Notes due 2028 ($621 million),
· the 5.875% Senior Secured Notes due 2031 ($619 million),
· the 8.50% Senior Secured Notes due 2033 ($736 million),
· the new 5.625% Euro-denominated Senior Secured Notes due 2031
(€400 million, equivalent to $460 million),
· the Bank Leumi term loan ($746 million),
· the BSTDB loan ($104 million),
· the Nitzana special-purpose facility ($33 million),
· the Revolving Credit Facility ($131 million) and
· the other third-party facility ($125 million).
The Group's leverage ratio (Net Debt / Adjusted EBITDAX) increased to 2.9x (FY
2024: 2.5x), reflecting the higher debt balance following the refinance of
existing debt and other facilities obtained during the period including
project-specific financing for Nitzana.
The Group is predominantly exposed to fixed interest rates on its Senior
Secured Notes. Floating rate exposure is limited to the Bank Leumi term loan
(ILS portion at BOI rate + 3.1% and USD portion at SOFR + 4.25%), the BSTDB
loan, the Revolving Credit Facility and 3(rd) party facility.
Shareholder Distributions
In line with the Group's dividend policy, Energean returned $1.20 per share to
shareholders in 2025, totalling $221 million across four quarterly payments of
$0.30 per share. The quarterly dividend on a per share basis has been
maintained at this level since 2022. In 2024, Energean returned $1.20 per
share, totalling $220 million.
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, cash cost of production, cash
G&A, capital expenditure, net debt and leverage. These measures are used
by management to assess business performance, facilitate period-on-period
comparison, and are widely used by investors and analysts covering the oil and
gas sector. Non-IFRS measures should be considered in addition to, and not as
a substitute for, measures of financial performance prepared in accordance
with IFRS.
Adjusted EBITDAX
Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business
performance. It is calculated as profit or loss for the period, adjusted for
discontinued operations, taxation, depreciation and amortisation, share-based
payment charge, impairment of property, plant and equipment, other income and
expenses, net finance costs and exploration 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.
FY 2025 FY 2024
$m $m
Adjusted EBITDAX 1,117 1,162
Reconciliation to profit for the period:
Other operating income 45 -
Depreciation and amortisation (581) (413)
Share-based payment charge (7) (9)
Exploration and evaluation expenses (11) (10)
Exploration cost written off (22) (145)
Change in decommissioning provision 4 (22)
Expected credit loss 10 (7)
Impairment of oil and gas assets (286) (96)
Other operating expenses (1) (4)
Finance income 6 15
Finance costs (260) (272)
Net loss on derivatives (3) -
Net foreign exchange (loss)/ profit (38) 13
Taxation (231) (85)
(Loss)/Profit for the period (258) 127
Cash Cost of Production
Cash Cost of Production is a non-IFRS measure that is used by the Group as a
useful indicator of the Group's underlying cash costs to produce hydrocarbons.
The Group uses the measure to compare operational performance
period-to-period, to monitor cost and assess operational efficiency. Cash cost
of production is calculated as cost of sales, adjusted for depreciation and
hydrocarbon inventory movements.
FY 2025 FY 2024
$m $m
Cost of sales (1,145) (988)
Adjusted for:
Depreciation 572 407
Change in inventory 10 22
Cost of production (563) (559)
Total production for the period (MMboe) 56,049 55,941
Cost of production per boe ($/boe) (10) (10)
Cash General & Administrative Expense (G&A)
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
distribution expenses, excluding depletion and amortisation of assets and
share-based payment charge that are included in G&A.
FY 2025 FY 2024
$m $m
Administrative expenses (54) (51)
Less:
Depreciation 8 6
Share-based payment charge included in G&A 8 8
Cash G&A (38) (37)
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:
FY 2025 FY 2024
$m $m
Additions to property, plant and equipment 523 626
Additions to intangible exploration and evaluation assets 53 117
Less:
Capitalised borrowing costs 41 15
Leased assets additions and modifications (1) 12
Lease payments related to capital activities (23) (20)
Change in decommissioning provision (28) 4
Total capital expenditures 587 733
Movement in working capital 273 33
Cash capital expenditures per the cash flow statement 860 765
Net Debt
Net debt is defined as the Group's total borrowings less cash and cash
equivalents. Management believes that net debt serves as a valuable indicator
of the Group's indebtedness, financial flexibility, and capital structure
because it reflects the level of borrowings after accounting for any cash and
cash equivalents that could be utilised to reduce borrowings.
FY 2025 FY 2024
$m $m
Current borrowings 229 128
Non-current borrowings 3,356 3,142
Total borrowings 3,585 3,270
Less: Cash and cash equivalents (227) (235)
Less: Restricted cash held for loan repayment (103) (86)
Net Debt 13 (#_ftn13) 3,255 2,949
Net Debt Excluding Israel(4) 718 614
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 18 March 2026 to 30 June 2027 'the Assessment Period'.
As of 31 December 2025, the Group's available liquidity was approximately $265
million. In addition to $227 million of cash and cash equivalents held by the
Group at 31 December 2025, this available liquidity figure includes: (i) c. $1
million available under the $300 million Revolving Credit Facility ('RCF')
signed by the Group in September 2025 (with the remainder being utilised to
issue Letters of Credit for the Group's operations) and (ii) $37 million
available under the unsecured loan facility obtained in relation to the
Nitzana project. In addition, the Group holds $103 million of restricted cash,
principally comprising debt service reserve accounts.
The going concern assessment is founded on a cashflow forecast prepared by
management and approved by the Board of Directors, 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 and Reverse stress testing.
The Base Case scenario assumes Brent at $65/bbl in 2026 and 2027 with prices
for gas sold assumed at contractually agreed prices for Egypt and Israel
throughout the going concern assessment period and PSV at €35/MWh in 2026
and €30/MWh in 2027. Under the Base Case, sufficient liquidity is
maintained throughout the going concern period. The Board also considered, as
a complementary scenario to the Base Case, the impact of the signed agreement
to acquire interests in offshore Angola, with an effective date of 1 January
2026 and closing expected by end of 2026, subject to customary conditions.
Under this scenario, the Group's liquidity position remains adequate
throughout the assessment period, demonstrating that the Angola transaction
does not adversely affect the Group's ability to continue as a going concern.
The Group has considered events occurring after the going concern assessment
period in course of its Viability assessment and has not identified any
matters that would cast significant doubt on the Group's ability to continue
as a going concern.
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. In the light of the
10 year, senior-secured term loan with Bank Leumi as the Facility Agent and
Arranger for $750 million signed by the Group in February 2025 the Group
increased its exposure to the floating interest rates in the assessment
period. 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 and/or management
of operating expenses to improve the liquidity. Under the RWC scenario, after
considering mitigation strategies, liquidity is maintained throughout the
going concern period.
In assessing the Group's resilience, the Board also considered downside
scenario incorporating a prolonged suspension of production in Israel,
reflecting the ongoing geopolitical uncertainty in the Middle East and the
temporary suspension of Israeli production which commenced on 28th of February
2026. This scenario was modelled across the full going concern horizon (until
30 June 2027) and assumes an extended period without Israeli revenues - a
scenario which the Board considers to be remote and unrealistic.
Notwithstanding its remote likelihood, and after taking into account available
mitigating actions, the Group maintains adequate liquidity and covenant
headroom throughout the assessment 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 'natural
hedge' provided by virtue of the Group's fixed-price gas contracts in Israel.
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 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 18 March 2026 to 30 June 2027. For this reason, they
continue to adopt the going concern basis in preparing the group financial
statements.
Subsequent Events
In November 2025, ExxonMobil farmed-in to Block 2, which is located at the
northwest part of the Ionian Sea. The new participating interests are:
Energean (30%, operator), ExxonMobil (60%) and HELLENiQ ENERGY Upstream (10%).
The transaction was completed on 11 March 2026 upon receipt of the government
approval and the extension of the license requested by Energean and HelleniQ.
Energean will remain the Operator of the concession through the exploration
stage, during which an exploratory well is expected to be drilled in 2027,
subject to permitting. Energean's share of past costs were received at the
Closing Date. Energean's share of exploration costs, up to a defined cap, will
be carried as part of the consideration.
On 28 February 2026, the Group received an order from the Israeli Ministry of
Energy and Infrastructure to temporary suspend the production at the FPSO due
to the escalation of geopolitical tensions in the region. At the date of this
report, the timing of the resumption of production remains uncertain, although
the Group expects operations to resume as soon as the situation stabilises.
On 12 March 2026 the Group announced that it had signed an agreement to
acquire Chevron's 31% operated interest in Block 14 and 15.5% non-operated
interest in Block 14K, offshore Angola. The Block 14 assets produce around 42
kbbl/d of oil in total, equivalent to 13 kbbl/d net to the interest to be
acquired. The effective date of the transaction is 1 January 2026, with
closing expected by the end of 2026, subject, inter alia, to government and
regulatory approvals and the waiver of applicable pre-emption rights. The
consideration comprises:
· a base consideration of $260 million subject to closing
adjustments and economic performance of the assets 14 (#_ftn14) between the
effective date and the closing date, and
· $250 million of contingent payments capped at $25 million per
annum.
Risk Management
Effective risk management is fundamental to achieving Energean's strategic
objectives and protecting its personnel, assets, shareholder value and
reputation. Energean's risk management framework and process are described in
detail in its 2025 Annual Report and Accounts. The principal risks and
uncertainties facing the business are monitored on an ongoing basis in line
with the UK Corporate Governance Code 2024. The Board has overall
responsibility for determining the nature and extent of the risks it is
willing to take in achieving the strategic objectives of the Group and
ensuring that such risks are managed effectively.
Principal risks and uncertainties
The Board of Directors have reviewed the principal risks facing the Company
and note that there are no changes to the headline principal risks from those
disclosed in the 2025 Interim results. A full description of Energean's
principal risks is disclosed in the 2025 Annual Report & Accounts.
The Board provides the following update concerning its headline principal
risks.
In reference to 'strategic risk: Geopolitical and security risks in Israel(,)'
On 28 February 2026, Energean received notice from the Ministry of Energy and
Infrastructure ordering the temporary suspension of production and activities
of the Energean Power FPSO, following geopolitical escalations in the region.
As of the time of writing, production in Israel remains suspended. Energean
continues to monitor the situation closely, with the safety of its people its
top priority. The impact to 2026 Group production guidance will be assessed
once the duration and full impact of the suspension is known. As of the time
of writing, there is no anticipated change to the Katlan first gas timetable
of H1 2027. The impact, if any, on the timetable will be assessed once the
full extent of the suspension is known.
In addition, regarding 'non-operated assets and JVs risk' and 'legal and
compliance risk', during the period, formal arbitration proceedings commenced
between Energean Italy and the Operator of the Cassiopea field. Refer to note
18 to the financial statements.
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.
Casting in tables
Numbers outside of the consolidated financial statements, where applicable,
are rounded to the nearest million US$ and therefore totals may differ in the
order of a million US$.
Group Income Statement
Year ended 31 December 2025
2025 2024
(Restated *)
$'000 $'000
Note
Revenue 4 1,728,126 1,779,413
Cost of sales 5 (1,144,906) (988,285)
Gross profit 583,220 791,128
General and administrative expenses 5 (53,638) (50,980)
Other operating income 4 44,591 354
Impairment of oil and gas assets 8 (285,726) (95,607)
Exploration and evaluation expenses and new ventures 9 (11,307) (10,140)
Exploration cost written-off 9 (21,760) (144,782)
Change in decommissioning provision 14 3,867 (22,368)
Expected credit (loss)/ reversal 5 10,228 (7,481)
Other operating expenses 5 (1,488) (4,271)
Operating profit 267,987 455,853
Finance income 6 6,334 15,386
Finance costs 6 (259,629) (271,528)
Net loss on derivatives 6 (2,884) (392)
Net foreign exchange (loss)/gain 6 (38,202) 12,639
(Loss)/Profit before tax (26,934) 211,958
Taxation expense 7 (231,189) (84,511)
(Loss)/Profit for the period after taxation (257,583) 127,447
Basic and diluted earnings per share ($ per share)
Basic 2 ($1.40) $0.69
Diluted 2 ($1.40) $0.69
* Restated for discontinued operation reclassified to continuing operations,
refer to Note 16 for further detail.
Group Statement of Comprehensive Income
Year ended 31 December 2025
2025 2024 (Restated *)
$'000 $'000
(Loss)/Profit for the period after taxation (257,583) 127,447
Other comprehensive income/(loss):
Items that may be reclassified subsequently to profit or loss
Net investment hedge (7,162) -
Cashflow hedges - gains / (losses) recognised in OCI, net of tax 28,848 (266)
Exchange difference on the translation of foreign operations, net of tax 21,936 (25,183)
Net other comprehensive income/(loss) that may be reclassified to profit or 43,622 (25,449)
loss in subsequent periods
Items that will not be reclassified subsequently to profit or loss
Remeasurement of defined benefit plan (96) 116
Income taxes on items that will not be reclassified to profit and loss 24 (29)
Net other comprehensive income/(loss) that will not be reclassified to profit (72) 87
or loss in subsequent periods
Other comprehensive profit/(loss) after tax 43,551 (25,362)
Total comprehensive profit for the period (214,033) 102,085
* Restated for discontinued operation reclassified to continuing operations,
refer to Note 16 for further detail.
Group Statement of Financial Position
As at 31 December 2025
2025 2024
Note $'000 $'000
ASSETS
Non-current assets
Property, plant and equipment 8 4,250,419 4,515,359
Intangible assets 9 249,220 216,378
Equity-accounted investments 4 4
Derivative assets 3,931 -
Other receivables 12 30,861 33,452
Deferred tax asset 10 156,493 254,065
Restricted cash 11 3,345 2,950
4,694,273 5,022,208
Current assets
Inventories 94,193 101,848
Derivative asset 22,390 -
Trade and other receivables 12 451,822 422,247
Restricted cash 11 99,399 82,427
Cash and cash equivalents 11 227,213 235,270
895,017 841,792
Total assets 5,589,290 5,864,000
EQUITY AND LIABILITIES
Equity attributable to owners of the parent
Share capital 2,459 2,449
Share premium 465,331 465,331
Merger reserve 139,903 139,903
Other reserves 26,231 5,796
Foreign currency translation reserve (8,773) (23,547)
Share-based payment reserve 49,340 41,996
Retained earnings (532,869) (54,464)
Total equity 141,622 577,464
Non-current liabilities
Borrowings 13 3,355,741 3,141,904
Deferred tax liabilities 10 145,110 141,403
Retirement benefit liability 1,704 1,551
Provisions 14 777,804 722,016
Trade and other payables 15 36,709 122,384
4,317,068 4,129,258
Current liabilities
Trade and other payables 24 780,062 847,806
Current portion of borrowings 21 229,005 128,000
Current tax liability 8,449 84,847
Derivative liability - 345
Provisions 23 113,084 96,280
1,130,600 1,157,278
Total equity and liabilities 5,589,290 5,864,000
2025
2024
Note
$'000
$'000
ASSETS
Non-current assets
Property, plant and equipment
8
4,250,419
4,515,359
Intangible assets
9
249,220
216,378
Equity-accounted investments
4
4
Derivative assets
3,931
-
Other receivables
12
30,861
33,452
Deferred tax asset
10
156,493
254,065
Restricted cash
11
3,345
2,950
4,694,273
5,022,208
Current assets
Inventories
94,193
101,848
Derivative asset
22,390
-
Trade and other receivables
12
451,822
422,247
Restricted cash
11
99,399
82,427
Cash and cash equivalents
11
227,213
235,270
895,017
841,792
Total assets
5,589,290
5,864,000
EQUITY AND LIABILITIES
Equity attributable to owners of the parent
Share capital
2,459
2,449
Share premium
465,331
465,331
Merger reserve
139,903
139,903
Other reserves
26,231
5,796
Foreign currency translation reserve
(8,773)
(23,547)
Share-based payment reserve
49,340
41,996
Retained earnings
(532,869)
(54,464)
Total equity
141,622
577,464
Non-current liabilities
Borrowings
13
3,355,741
3,141,904
Deferred tax liabilities
10
145,110
141,403
Retirement benefit liability
1,704
1,551
Provisions
14
777,804
722,016
Trade and other payables
15
36,709
122,384
4,317,068
4,129,258
Current liabilities
Trade and other payables
24
780,062
847,806
Current portion of borrowings
21
229,005
128,000
Current tax liability
8,449
84,847
Derivative liability
-
345
Provisions
23
113,084
96,280
1,130,600
1,157,278
Total equity and liabilities
5,589,290
5,864,000
*Restated for discontinued operation reclassified to continuing operations,
refer to Note 16 for further detail.
Approved by the Board on the 18 March 2026:
Matthaios Rigas Panagiotis Benos
Chief Executive Officer Chief Financial Officer
Group Statement of Changes in Equity
Year ended 31 December 2025
Share Capital Share Premium Hedges and defined benefit plans reserve(*) Share based payment reserve(**) Translation reserve(***) Retained earnings Merger reserve Total
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
At 1 January 2024 2,449 465,331 5,975 32,917 1,636 37,904 139,903 686,115
Profit for the period - - - - - 127,447 - 127,447
Cashflow hedge, net of tax - - (266) - - - - (266)
Remeasurement of defined benefit pension plan, net of tax - - 87 - - - - 87
Exchange difference on the translation of foreign operations - - - - (25,183) - - (25,183)
Total comprehensive income - - (179) - (25,183) 127,447 - 102,085
Transactions with owners of the company
Share based payment charges - - - 9,079 - - - 9,079
Dividends - - - - - (219,815) - (219,815)
At 31 December 2024 2,449 465,331 5,796 41,996 (23,547) (54,464) 139,903 577,464
(*) Reserve is used to recognise remeasurement gain or loss on cash flow
hedges and actuarial gain or loss from the defined benefit pension plan.
'Other reserves'.
(**) 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.
(***) 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 and gain or loss on net
investment hedge.
Group Statement of Changes in Equity
Year ended 31 December 2025
Share Capital Share Premium Hedges and defined benefit plans reserve* Share based payment reserve ** Translation reserve** Retained earnings Merger reserve Total
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
At 31 December 2024 2,449 465,331 5,796 41,996 (23,547) (54,464) 139,903 577,464
Profit for the period - - - - (257,583) - (257,583)
Net investment hedge - - - - (7,162) - - (7,162)
Cashflow hedge, net of tax - - 28,848 - - - - 28,848
Remeasurement of defined benefit pension plan, net of tax - - (72) - - - - (72)
Exchange difference on the translation of foreign operations - - - 21,937 - - 21,937
Total comprehensive income - - 28,776 - 14,775 (257,583) - (214,033)
Transactions with owners of the company
Cashflow hedges - basis adjustment transferred to PPE - - (10,833) - - - - (10,833)
Cashflow hedge - deferred tax related to basis adjustment 2,492 2,492
Issuance of shares 10 - - (10) - - - -
Share based payment charges - - - 7,354 - - - 7,354
Dividends - - - - - (220,822) - (220,822)
At 31 December 2025 2,459 465,331 26,231 49,340 (8,772) (532,869) 139,903 141,622
(*) Reserve is used to recognise remeasurement gain or loss on cash flow
hedges and actuarial gain or loss from the defined benefit pension plan.
'Other reserves'.
(**) 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.
(***) 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 and gain or loss on net
investment hedge.
Group Statement of Cash Flows
Year ended 31 December 2025
2025 2024 (Restated*)
Note $'000 $'000
Operating activities
Profit before taxation (26,394) 211,958
Adjustments to reconcile profit before taxation to net cash provided by
operating activities:
Depreciation, depletion and amortisation 580,561 412,825
Impairment loss on property, plant and equipment 285,726 95,607
Loss from the sale of property, plant and equipment - 675
Impairment loss on exploration and evaluation assets 21,760 144,669
Impairment loss on inventory - 671
Change in decommissioning provision estimates (3,867) (8,221)
Defined benefit (gain)/ loss (107) (71)
Movement in other provisions (2,665) 704
Finance income (6,334) (15,386)
Finance costs 259,629 271,528
Unrealised loss on derivatives 2,884 392
ECL on trade receivables (10,228) 7,482
Non-cash revenues from Egypt(( 15 )) (24,677) (34,841)
Other income (18,635) (344)
Share-based payment charge 7,354 9,079
Net foreign exchange (income)/ loss 38,202 (12,639)
Working capital adjustments:
(Increase)/ decrease in inventories 13,767 3,210
(Increase)/ decrease in trade and other receivables (6,329) (81,058)
Increase/(Decrease) in trade and other payables 195,401 121,260
Cash inflow from operations 1,306,048 1,127,500
Income tax paid (162,468) (5,733)
Net cash inflow from operating activities 1,143,580 1,121,767
Investing activities
Payment for purchase of property, plant and equipment (750,989) (580,487)
Payment for exploration and evaluation, and other intangible assets (108,574) (184,851)
Payment of deferred consideration for an acquisition of subsidiary (100,701) -
Movement in restricted cash (17,367) (59,954)
Government grant received 24,239 -
Proceeds from disposal of exploration and evaluation and other intangible - 978
Amounts received from INGL related to the transfer of property, plant & - 1,801
equipment
Settlement of foreign exchange hedge (2,884) -
Other investing activities - 2,858
Interest received 6,578 10,236
Net cash outflow for investing activities (949,698) (809,419)
Financing activities
Drawdown of borrowings 1,500,039 118,000
Repayment of borrowings (1,201,000) (70,000)
Debt issue costs (36,718) -
Repayment of obligations under leases (23,400) (20,467)
Finance cost paid for deferred license payments - (4,000)
Finance costs paid (231,905) (229,755)
Dividend Paid (220,822) (219,815)
Net cash outflow from financing activities (213,806) (426,037)
Net increase/(decrease) in cash and cash equivalents (19,924) (113,689)
Cash and cash equivalents at beginning of the period 235,270 346,772
Effect of exchange rate fluctuations on cash held 11,868 2,187
Cash and cash equivalents at end of the period 11 227,213 235,270
* Restated for discontinued operation reclassified to continuing operations,
refer to Note 16 for further detail.
1. Basis of Preparation and Presentation of Financial Information
Whilst the financial information in this preliminary announcement has been
prepared in accordance with the recognition and measurement requirements of
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
UK-adopted IAS. The Group will publish full financial statements that comply
with UK-adopted IAS in April 2026. The financial information set out above
does not constitute the Group's statutory accounts for the years ended 31
December 2025 or 2024 but is derived from those accounts. Statutory accounts
for 2024 have been delivered to the Registrar of Companies, and those for 2025
will be delivered in due course. The auditor has reported on those accounts;
their reports were (i) unqualified, (ii) did not include reference to any
matters to which the auditor drew attention by way of emphasis without
qualifying their report and (iii) did not contain statements under Section
498(2) or (3) of the 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
2024. 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 2025, 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 2025 Annual Report and Accounts.
Certain new accounting standards and interpretations have been published that
are not mandatory for 31 December 2025 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 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 is 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.
($'000) 2025 2024 (Restated 16 )
Total (loss)/ profit attributable to equity shareholders (257,583) 127,447
Effect of dilutive potential ordinary shares - -
(257,583) 127,447
2025 2024
Basic weighted average number of shares including those held by Employee 184,105,617 183,480,959
Benefit Trust
Dilutive potential ordinary shares - 2,282,980
Diluted weighted average number of shares 184,105,617 185,763,939
Basic earnings per share ($1.40)/share $0.69/share
Diluted earnings per share ($1.40)/share $0.69/share
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 and
Croatia), Israel, Egypt and New Ventures. The Group's reportable segments
under IFRS 8 Operating Segments are Europe, Israel and Egypt. New Ventures
segment does not exceed the quantitative thresholds for reporting information
about operating segments and has therefore been included within "Other"
alongside inter-segment transactions.
Information regarding the results of each reportable segment is included below
and prior periods are restated to reflect discontinued operations reclassified
within the continuing operations to provide comparability. Discontinued
operations as disclosed in the 2024 annual consolidated financial statements
consist of the Egypt segment, and the Italian and Croatian operations included
in the Europe reportable segment.
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:
Year ended 31 December 2025, Europe Israel Egypt Other & inter-segment transactions Total
$'000
Revenue from gas sales 173,715 848,887 142,291 - 1,164,893
Revenue from hydrocarbon liquids sales 28,660 316,326 42,679 - 387,665
Revenue from crude oil sales 115,757 - - - 115,757
Revenue from LPG sales 348 - 17,129 - 17,477
Other revenue 17,100 - - (14,843) 2,257
Other revenue - lost production insurance proceeds 27,088 - - - 27,088
Other revenue from production activities 12,989 - - - 12,989
Total revenue from production activities 375,657 1,165,213 202,099 (14,843) 1,728,126
Adjusted EBITDAX 17 149,679 813,199 166,193 (11,574) 1,117,497
Reconciliation to profit before tax:
Other operating income 13,880 9,500 19,686 1,525 44,591
Depreciation and amortisation expenses (194,683) (292,156) (92,737) (985) (580,561)
Share-based payment charge (3,568) (1,354) - (2,432) (7,354)
Exploration and evaluation expenses and new ventures (3,470) - - (7,837) (11,307)
Exploration expenses written off (22,054) (1,994) 2,288 - (21,760)
Change in decommissioning provision 3,867 - - - 3,867
Reversal of expected credit loss 5,147 - 5,081 - 10,228
Impairment of oil and gas assets (285,726) - - - (285,726)
Other operating expenses (2,030) 285 125 132 (1,488)
Finance income 3,391 5,157 803 (3,017) 6,334
Finance costs (48,979) (163,622) (574) (46,454) (259,629)
Net loss on derivative instruments - 233 - (3,117) (2,884)
Net foreign exchange gain/(loss) (34,880) (18,713) (325) 15,716 (38,202)
(Loss)/Profit before income tax (419,426) 350,535 100,540 (58,043) (26,394)
Taxation expense (124,492) (81,930) (24,787) 20 (231,189)
(Loss)/Profit for the year (543,918) 268,605 75,753 (58,023) (257,583)
Year ended 31 December 2024 (Restated(89)), Europe Israel Egypt Other & inter-segment transactions Total
$'000
Revenue from gas sales 99,348 838,881 157,773 - 1,096,002
Revenue from hydrocarbon liquids sales - 400,230 41,581 - 441,811
Revenue from crude oil sales 221,820 - - - 221,820
Revenue from LPG sales 549 - 14,892 - 15,441
Other revenue 15,262 - - (10,923) 4,339
Total revenue from production activities 336,979 1,239,111 214,246 (10,923) 1,779,413
Adjusted EBITDAX(90) 96,452 889,001 176,939 (340) 1,162,052
Reconciliation to profit before tax:
Other operating income 751 - (339) (58) 354
Depreciation and amortisation expenses (44,263) (278,252) (89,731) (579) (412,825)
Share-based payment charge (1,783) (1,207) 216 (6,305) (9,079)
Exploration and evaluation expenses and new ventures (3,824) - - (6,316) (10,140)
Exploration expenses written off (16,507) - (63,045) (65,230) (144,782)
Change in decommissioning provision (22,368) - - - (22,368)
Expected credit (loss) (5,137) - (2,344) - (7,481)
Impairment of oil & gas assets (95,607) - - - (95,607)
Other operating expenses (2,515) (779) 264 (1,241) (4,271)
Finance income 12,111 8,894 637 (6,256) 15,386
Finance costs (48,564) (179,779) (1,186) (41,999) (271,528)
Net loss on derivatives - (392) - - (392)
Net foreign exchange gain/(loss) 17,902 (938) 831 (5,156) 12,639
Profit/(loss) before income tax (113,352) 436,548 22,242 (133,480) 211,958
Taxation expense 51,067 (107,579) (34,843) 6,844 (84,511)
Profit/(loss) for the period (62,285) 328,969 (12,601) (126,636) 127,447
Other & inter-segment transactions column refer to other segments
transactions as well as transactions between the reported reportable segments.
They are eliminated upon consolidation.
Finance costs, finance income, other income and expenses and share - based
payment charge included in "Other & inter-segment transactions" are not
allocated to individual segments as the underlying instruments are managed on
a group basis.
Segment financial position
The following table presents assets and liabilities information for the
Group's operating segments as at 31 December 2025 and 31 December 2024,
respectively:
Year ended 31 December 2025 Europe Israel Egypt Other & inter-segment transactions Total
$'000
Oil & Gas properties 510,733 3,367,761 349,358 (23,280) 4,204,572
Other fixed assets 25,576 9,834 7,071 3,366 45,847
Intangible assets 16,835 223,276 6,662 2,447 249,220
Trade and other receivables 130,631 158,184 214,896 (21,028) 482,683
Derivative asset 685 25,636 - - 26,321
Deferred tax asset 156,442 - - 51 156,493
Cash and cash equivalents 17,007 118,819 73,485 17,902 227,213
Restricted cash 3,345 97,647 1,752 - 102,744
Other assets 964,205 20,991 88,865 (979,864) 94,197
Total assets 1,825,459 4,022,148 742,089 (1,000,406) 5,589,290
Trade and other payables 475,545 315,552 40,038 (5,915) 825,220
Borrowings 343,754 2,744,085 - 496,907 3,584,746
Decommissioning provision 744,967 89,999 - - 834,966
Current tax payable (50) 8,324 - 175 8,449
Deferred tax liability - 145,110 - - 145,110
Other liabilities 6,571 - 1,054 41,552 49,177
Total liabilities 1,570,787 3,303,070 41,092 532,719 5,457,668
Other segment information
Capital Expenditure 18 :
Property, plant and equipment 119,755 397,832 7,647 9,082 534,316
Intangible, exploration and evaluation assets 1,018 53,357 (1,562) (193) 52,620
Year ended 31 December 2024 (Restated 19 ), Europe Israel Egypt Other & inter-segment transactions Total
$'000
Oil & Gas properties 805,927 3,221,617 436,201 (16,326) 4,447,419
Other fixed assets 29,357 10,252 22,565 5,766 67,940
Intangible assets 35,641 171,902 6,043 2,792 216,378
Trade and other receivables 143,395 131,128 203,662 (22,486) 455,699
Deferred tax asset 254,065 - - - 254,065
Cash and cash equivalents 34,405 157,728 27,695 15,442 235,270
Restricted cash 2,950 82,427 - - 85,377
Other assets 800,162 16,714 55,037 (770,061) 101,852
Total assets 2,105,902 3,791,768 751,203 (784,873) 5,864,000
Trade and other payables 404,609 329,969 122,828 112,783 970,189
Borrowings 312,957 2,594,213 - 362,734 3,269,904
Decommissioning provision 725,302 85,357 - - 810,659
Current tax payable 3,813 80,966 - 68 84,847
Deferred tax liability - 141,403 - - 141,403
Other liabilities 7,318 344 1,871 - 9,533
Total liabilities 1,453,999 3,232,252 124,699 475,585 5,286,535
Other segment information
Capital expenditure:
- Property, plant and equipment 260,791 177,377 51,145 564 489,877
- Intangible, exploration and evaluation assets 23,637 132,441 22,162 64,944 243,184
Other & inter-segment transactions column refer to other segments and
transactions between the reportable segments. The oil & gas properties
primarily reflect the fair value assessment by the Group following the
acquisition of Israeli oil & gas assets in 2018. Borrowings balance
retained in Other & intersegment transactions column mainly comprises the
loan balances held by Energean plc. Eliminations of cash management
transactions within the Group are included in Other liabilities line in Other
& intersegment transactions column.
Segment cash flows
The following tables present cash flow information for the Group's operating
segments for the year ended 31 December:
Year ended 31 December 2025 ($'000) Europe Israel Egypt Other & inter-segment transactions Total
Net cash from / (used in) operating activities 261,171 682,114 144,786 55,5098 1,143,580
Cash outflow for investing activities (220,766) (538,509) (62,687) (127,736) (949,698)
Net cash from financing activities (62,048) (185,507) (36,380) 70,129 (213,806)
Net increase/(decrease) in cash and cash equivalents (21,643) (41,902) 45,719 (2,098) (19,924)
Cash and cash equivalents at beginning of the period 34,405 157,728 27,695 15,442 235,270
Effect of exchange rate fluctuations on cash held 4,246 2,993 71 4,557 11,867
Cash and cash equivalents at end of the period 17,008 118,819 73,485 17,901 227,213
Year ended 31 December 2024 (Restated 20 ) ($'000) Europe Israel Egypt Other & inter-segment transactions Total
Net cash from / (used in) operating activities 133,795 888,988 97,763 1,221 1,121,767
Cash outflow for investing activities (281,963) (436,814) (60,378) (30,264) (809,419)
Net cash from financing activities 165,210 (583,706) (20,077) 12,536 (426,037)
Net increase/(decrease) in cash and cash equivalents 17,042 (131,532) 17,308 (16,507) (113,689)
Cash and cash equivalents at beginning of the period 17,473 286,625 11,232 31,442 346,772
Effect of exchange rate fluctuations on cash held (228) 2,635 (846) 626 2,187
Cash and cash equivalents at end of the period 34,287 157,728 27,694 15,561 235,270
4. Revenue and other income
($'000) 2025 2024 (Restated 21 )
Revenue from gas sales 1,164,893 1,096,002
Revenue from hydrocarbon liquids sales 387,665 441,811
Revenue from crude oil sales 115,757 222,368
Revenue from LPG sales 17,477 14,892
Rendering of services 266 445
Other revenue 1,991 3,895
Revenue from contracts with customers 1,688,049 1,779,413
Other revenue - lost production insurance proceeds 27,088 -
Other revenue from production activities 22 (Note 18) 12,989 -
Total Revenue from production activities 1,728,126 1,779,413
Insurance proceeds 21,290 751
Other income from reversal of prior period accruals 23 23,301 (397)
Total revenue and other income 1,772,717 1,779,767
Sales for the year ended 31 December (Kboe) 2025 2024 (Restated 24 )
Israel
Gas 36,322 35,399
Hydrocarbon liquids 5,065 5,351
Egypt (net entitlement)
Gas 4,638 4,579
Hydrocarbon liquid 862 730
Italy
Gas 2,400 1,362
Crude Oil 1,745 2,034
Croatia
Gas 3 10
UK
Gas 26 26
Crude oil 304 343
Greece
Crude oil 193 572
Total 51,558 50,406
5. Operating profit/(loss)
($'000) 2025 2024 (Restated 25 )
Cost of operations
Staff costs 59,681 60,429
Energy cost 24,136 22,223
Royalty payable 226,291 238,578
Flux cost 28,800 27,681
Maintenance, insurance, transportation and treatment costs 223,976 209,992
Depreciation and amortisation (notes 8,9) 572,138 407,289
Oil stock movement 14,920 16,341
Stock (underlift)/overlift movement (5,036) 5,752
Total cost of operations 1,144,906 988,285
Expected credit (reversal)/ loss (10,228) 7,481
Exploration and evaluation expenses and new ventures 11,307 10,140
Exploration costs written off (note 9) 21,760 144,782
Impairment of oil and gas assets (note 8) and loss on fixed assets disposal 285,726 95,607
Other operating expenses 1,488 4,271
Change in decommissioning provision 3,867 (22,368)
General & administration expenses
Staff costs 24,260 23,542
Other General & Administration expenses 10,783 11,273
Share-based payment charge included in administrative expenses 7,354 8,029
Depreciation and amortisation (notes 8,9) 8,423 5,536
Auditor fees 2,818 2,600
Total general & administration expenses 53,638 50,980
6. Net finance cost
($'000) Notes 2025 2024 (Restated 26 )
Interest on bank and other borrowings 13 45,131 15,957
Interest on Senior Secured Notes 13 194,299 201,254
Interest expense on long term payables 1,647 8,931
Less amounts included in the cost of qualifying assets 8,9 (40,724) (14,626)
200,353 211,516
Finance and arrangement fees 1,163 2,552
Commission charges for bank guarantees 5,131 3,575
Other finance costs and bank charges 4,767 3,861
Unwinding of discount on lease liability 2,403 3,313
Unwinding of discount on long term trade payables 8,969 14,417
Unwinding of discount on provision for decommissioning 35,231 33,016
Unwinding of discount on deferred consideration 2,085 -
Less amounts included in the cost of qualifying assets (473) (722)
Total finance costs 259,629 271,528
Interest income from time deposits (6,319) (10,381)
Other finance income (15) (5,005)
Total finance income (6,334) (15,386)
Net loss/(gain) on derivative instruments 2,884 (392)
Total net loss on derivative instruments 2,884 (392)
Foreign exchange loss / (gain) 38,202 (12,639)
Net financing costs 294,381 243,111
7. Taxation
(a) Taxation charge
($'000) 2025 2024 (Restated 27 )
Current income tax charge (109,064) (120,854)
Adjustments in respect of current income tax of previous year(s) (19) 4,239
Total current tax charge (109,083) (116,615)
Deferred tax relating to origination and reversal of temporary differences (122,106) 32,104
Income tax expense reported in the Income statement (231,189) (84,511)
(b) Reconciliation of the total tax charge
The tax rate applied to the Group's profits in preparing the reconciliation
below is the main corporation tax rate of 25.0% applicable in the United
Kingdom.
The effective tax rate for the period is negative (2024: 40%).
The tax (charge) for the period can be reconciled to the accounting profit per
the Group Income statement as follows:
($'000) 2025 2024 (Restated 28 )
Profit before tax (26,394) 211,958
Tax calculated at 25% UK standard tax rate (2024: 25.0%) 6,599 (52,990)
Impact of different tax rates (11,829) 2,891
Non recognition of deferred tax on current year tax losses and other temporary (38,129) (11,153)
differences 29 (#_ftn29)
Non - deductible Italian assets impairments 30 (#_ftn30) (73,863) -
Recognition of previously unrecognised deferred tax/ Derecognition of (124,861) 15,627
previously recognised deferred tax 31 (#_ftn31)
Permanent differences 4,086 (44,674)
Foreign taxes - (38)
Tax effect of non-taxable income and allowances 6,459 1,359
Other adjustments 200 302
Prior year tax 149 4,165
Total taxation expense (231,189) (84,511)
There are no income tax consequences attached to the payment of dividends in
either 2025 or 2024 by the Group to its shareholders.
The Group is within the scope of the Pillar Two Model Rules starting from 1
January 2025. Legislation implementing these rules has been enacted or
substantively enacted in a number of jurisdictions in which the Group
operates. The Group has applied the mandatory temporary exception under IAS
12 from recognising and disclosing deferred taxes related to Pillar Two income
taxes.
The Group has performed an assessment of its potential exposure to Pillar Two
top-up taxes. Based on the analysis performed using information currently
available, including consideration of transitional safe harbour provisions
where applicable, the Group does not expect a material exposure to arise.
Accordingly, no amount has been recognised in the consolidated financial
statements for the year.
The Group will continue to monitor developments in legislation, guidance and
the geographic mix of earnings, which may impact future periods.
8. Property, plant & equipment
($'000) Oil and gas assets Leased assets Other property, plant and equipment Total
Property, Plant & Equipment at Cost:
At 1 January 2024 5,201,651 108,278 64,103 5,374,032
Additions 460,870 11,360 8,557 480,787
Lease modification - 602 - 602
Disposal of assets (3,167) - (287) (3,454)
Capitalised borrowing cost 15,348 - - 15,348
Change in decommissioning provision 3,535 - - 3,535
Transfer to inventory (448) - - (448)
Transfer from intangible assets 204,590 204,590
Foreign exchange impact (176,628) (4,593) (3,927) (185,148)
At 31 December 2024 (Restated 32 ) 5,705,751 115,647 68,446 5,889,844
Additions 500,033 16,754 10,883 527,670
Lease modification - (17,652) - (17,652)
Disposal of assets (5,844) (11,237) (1) (17,082)
Government grants deducted from asset cost - - (16,021) (16,021)
Capitalised borrowing cost 40,144 - - 40,144
Change in decommissioning provision (27,624) - - (27,624)
Transfer from Intangible assets (30) - - (30)
Foreign exchange impact 407,710 9,931 8,135 425,776
At 31 December 2025 6,620,140 113,443 71,442 6,805,025
Accumulated Depreciation and Impairment:
At 1 January 2024 898,549 46,336 57,822 1,002,707
Charge for the period 331,685 13,630 1,516 346,831
Depreciation catch-up adjustment (note 16) 62,125 1,919 982 65,026
Impairment 95,607 - - 95,607
Disposal - - (170) (170)
Foreign exchange impact (129,634) (2,715) (3,167) (135,516)
At 31 December 2024 (Restated 33 ) 1,258,332 59,170 56,983 1,374,485
Charge for the period 556,057 19,856 2,276 578,189
Impairment 285,726 - - 285,726
Lease modification - (6,308) - (6,308)
Disposal (4,732) (7,190) - (11,922)
Foreign exchange impact 320,185 7,466 6,785 334,436
At 31 December 2025 2,415,568 72,994 66,044 2,554,606
Net carrying amount:
At 31 December 2024 (Restated 34 ) 4,447,419 56,477 11,463 4,515,359
At 31 December 2025 4,204,572 40,449 5,398 4,250,419
Included in the carrying amount of leased assets at 31 December 2025 are right
of use assets related to Oil and gas properties and Other property, plant and
equipment of $37.0 million and $3.5 million respectively (2024: $54.5 million
and $2.0 million). The depreciation charged on these classes for the year
ending 31 December 2025 was $19.0 million and $0.9 million respectively (2024:
$14.8 million and $0.8 million).
Borrowing costs capitalised for qualifying assets during the year are
calculated by applying a weighted average interest rate of 7.02 % for the year
ended 31 December 2025 (for the year ended 31 December 2024: 3.93%).
The additions to Oil & gas properties in 2025 are mainly due to
development costs of Katlan, Karish North and the second oil train in Israel
at the amount of $380 million.
On 21 March 2025, property, plant, and equipment owned by the ECL disposal
group, with a carrying value of $1,196 million (primarily in Italy and Egypt),
were reclassified back to continuing operations. Those assets were recorded at
their carrying value including the depreciation adjustment retrospectively
made for the period they were classified as held for sale.
In 2025, due to a reduction in available commercial reserves, a full
impairment assessment of the Cassiopea CGU was performed. As a result of
this assessment, the Group recorded an impairment of $285.7 million on oil and
gas assets within the Cassiopea CGU (Europe operating segment). The
recoverable amount of the CGU was determined to be $136.5 million as of 31
December 2025, based on a value in use calculation. This calculation utilised
cash flow projections from the annual approved budget and Group's five-year
mid-term plan reviewed by senior management and estimates of proven and
probable reserves which is based on independent competent persons report
(CPR). The forecast period up to 2037 is justified by the economic life of the
Cassiopea gas field, aligning with its expected operational duration and
industry practice for long-term asset evaluation. The key assumptions used in
forecasting future cash flows were:
· A post-tax discount rate of 8.67%;
· A long-term inflation/growth rate of 2% referencing the European
inflation forecast as published by the International Monetary Fund;
· PSV gas prices were identified based on market forecasts
published by leading financial data providers, with projections set at €35.0
per MWh in 2026, decreasing to €30.0 in 2027, €25.0 in 2028-2029, followed
by a 2% annual increase thereafter.
We also considered reasonable potential changes to the assumptions that the
impairment calculation is sensitive to, noting the following impacts:
· A 5% change in the estimated reserves would change the impairment
by $8.0 million;
· A 1% change in the discount rate would change the impairment by
$2.6 million;
· A 1% change in the long-term inflation/growth rate would change
the impairment by $1.4 million;
· A 5% change in PSV gas prices would change the impairment by $8.4
million.
In 2024, due to additional delays in the development of Epsilon, a full
impairment assessment of the Prinos CGU was held. As a result of this
assessment, the Group recorded an impairment of $92.3 million on oil and gas
assets within the Prinos CGU (Europe operating segment). The recoverable
amount of the CGU was determined to be $202.6 million as of 31 December 2024,
based on a value in use calculation. This calculation utilised cash flow
projections from the annual approved budget and Group's five-year mid-term
plan reviewed by senior management and estimates of proven and probable
reserves which is based on independent competent persons report (CPR). The
extended forecast period up to 2049 is justified by the economic life of the
Epsilon oil field, aligning with its expected operational duration and
industry practice for long-term asset evaluation. The key assumptions used in
forecasting future cash flows were:
· A post-tax discount rate of 9.30%;
· Extension of the Epsilon license until 2049 under the local
legislation with first oil expected in H2 2029;
· A long-term inflation/growth rate of 2% referencing the Greek
inflation forecast as published by the International Monetary Fund;
· Brent oil prices were identified based on market forecasts
published by leading financial data providers, with projections set at $73.25
per barrel in 2025, decreasing to $71.00 in 2026, rising to $73.00 in 2027,
and adjusting to $72.30 in 2028, followed by a 2% annual increase thereafter.
We also considered reasonable potential changes to the assumptions that the
impairment calculation is sensitive to, noting the following impacts:
· A 5% change in the estimated reserves would change the impairment
by $42.7 million;
· A 1% change in the discount rate would change the impairment by
$20.0 million;
· A 1% increase in the long-term inflation/growth rate would change
the impairment by $55.9 million, whereas a 1% decrease would result in an
additional impairment of $52.2 million;
· A 5% change in Brent oil prices would change the impairment by
$44.2 million.
The Group assessed the recoverability of its investment in the Katakolo
license due to the lack of progress, resulting in a full impairment of the
accumulated capital expenditure up to the reporting date, totalling $3.3
million.
9. Intangible assets
($'000) Exploration and evaluation assets Goodwill Other Intangible assets Total
Intangible assets at Cost:
At 1 January 2024 397,716 101,146 11,543 510,405
Additions 241,950 - 1,233 243,183
Transfer to property, plant and equipment (205,324) 734 (204,590)
Exchange differences (8,944) - (741) (9,685)
31 December 2024 (Restated 35 ) 425,398 101,146 12,769 539,313
Additions 243 - 52,377 52,620
Capitalised borrowing cost - - 580 580
Transfer to property, plant and equipment 30 - - 30
Exchange differences 24,582 - 1,601 26,183
At 31 December 2025 450,253 101,146 67,327 618,726
Accumulated amortisation and impairments:
At 1 January 2024 158,274 20,485 6,257 185,016
Charge for the period - - 923 923
Amortisation catch-up adjustment (note 16) 45 45
Impairment 144,627 - 42 144,669
Exchange differences (7,442) - (276) (7,718)
31 December 2024 (Restated 36 ) 295,459 20,485 6,991 322,935
Charge for the period 578 - 1,794 2,372
Impairment 21,760 - - 21,760
Exchange differences 21,123 - 1,316 22,439
31 December 2025 338,920 20,485 10,101 369,506
Net carrying amount
At 31 December 2024 (Restated 37 ) 129,939 80,661 5,778 216,378
At 31 December 2025 111,333 80,661 57,226 249,220
On 21 March 2025, intangible assets owned by the ECL disposal group, with a
carrying value of $30.8 million (primarily in Italy and Egypt), were
reclassified back to continuing operations. Those assets were recorded at
their carrying value including the amortisation adjustment retrospectively
made for the period they were classified as held for sale.
In 2025, the Group recognised an addition to intangible assets related to the
Nitzana transmission agreement. In September 2025, the Group entered into a
long-term transmission agreement with Israel Natural Gas Lines Ltd. ("INGL")
for capacity in the Nitzana pipeline. In line with the agreement, the Group
made an initial payment of approximately $50.0 million in Q4 2025,
representing around 50% of its expected 16.4% share of total construction
costs. The remaining investment will be incurred in accordance with
contractual milestones. As the Group does not obtain ownership of, or control
over, the physical pipeline asset, but instead acquires a contractual right to
access defined transportation capacity for a period of 15 years, the
arrangement has been recognised as an intangible asset in accordance with IAS
38. The asset will be amortised on a straight-line basis over the 15-year
access period from the date the pipeline becomes operational.
In 2025, due to the ongoing dispute with the operator of the Cassiopea
license, the Group has not approved the work program for the Gemini
exploration project. It resulted in a full write‑off of the related
exploration asset of $22.1 million.
In July 2024, Katlan obtained a final investment decision authorising its
development, and the related asset has accordingly been reclassified to oil
and gas assets (refer to note 8).
In April 2024, the Group entered into a partnership with Chariot Limited in
Morocco to invest in the Anchois gas development. As the farmee, the Group
recognised its expenditure under this arrangement in the same way as directly
incurred expenditure. Since the carry of Chariot's costs was conditional upon
the successful commencement of production, Energean accounted for 100% of the
expenses related to appraisal and other exploration activities concerning the
two licences. In May 2025 the Group sold its rights to Lixus and Risanna
licenses (Anchois gas development) to Chariot Limited for $1 consideration
with any related guarantee issued by the Group being terminated.
In 2024, total impairment of $144.3 million were recognised due to several
non-viable projects. Notably, the Orion X1 exploration well in Egypt, which
reached its target reservoir but failed to discover commercial hydrocarbons,
resulted in a complete impairment of the exploration asset valued at $62.6
million. Additionally, the decision to exit following the expiration of the
exploration license in Ioannina on 2 April 2024 led to a full impairment of
its related asset valued at $16.5 million. Moreover, the Group had the
intention to transfer the license rights in Morocco following exploration
results that identified non-commercial reserves, necessitating a full
impairment of the related exploration asset amounting to $65.2 million.
Goodwill arises principally because of the requirement to recognise deferred
tax assets and liabilities for the difference between the assigned values and
the tax bases of assets acquired and liabilities assumed in a business
combination.
The remaining goodwill balance is in relation to the Israel CGU ($75.8
million), and Sally CGU ($4.8 million). We have performed the annual goodwill
impairment test and note that no reasonably possible change in assumptions
would result in impairment.
The recoverable amount of the goodwill balances was determined as of 31
December 2025, based on a value in use calculation for the CGUs to which they
relate. This calculation utilised cash flow projections from the annual
approved budget and Group's five-year mid-term plan reviewed by senior
management and estimates of proven and probable reserves which is based on
independent competent persons report (CPR) issued for Israel and UK assets.
The key assumptions used in forecasting future cash flows were:
Israel CGU Sally CGU (Scott and Telford)
A post-tax-tax discount rate 8.75% (2024: 8.87%) 5.93% (2024: 6.24%)
(Note 3.17)
Forecasted prices Brent oil prices were identified based on market forecasts published by
leading financial data providers. Where applicable, gas prices reflect the
contractual terms of existing sales agreements, including fixed-price
contracts.
Forecasted period Until 2044, aligned with the life of the assets Until 2033, aligned with the life of the assets
10. Net deferred tax (liability)/asset
Deferred tax (liabilities)/assets ($'000) Property, plant and equipment Right of use asset IFRS 16 Decom-missioning Prepaid expenses and other receivables Inventory Tax losses Deferred expenses for tax Retirement benefit liability Accrued expenses and other short‑term liabilities Total
At 1 January 2024 (163,994) (3,737) 103,560 (2,051) 6 144,866 5,578 369 10,122 94,719
Increase / (decrease) for the period through, restated 38 :
Profit or loss (Note 10) (3,286) 634 17,296 (764) 413 20,580 (633) (39) (2,096) 32,105
Other comprehensive income - - - - - - - 80 10 90
Exchange difference 739 44 (6,315) 35 (17) (8,433) - (7) (298) (14,252)
31 December 2024 (Restated 39 ) (166,541) (3,059) 114,541 (2,780) 402 157,013 4,945 403 7,738 112,662
Increase / (decrease) for the period through:
Profit or loss (13,185) 3,039 (107,890) 18 (213) (3,097) (633) 3 (148) (122,106)
Other comprehensive income - - - - - - - 24 (8,627) (8,603)
Equity 2,492 - - - - - - - - 2,492
Exchange difference (2,078) (76) 9,936 (76) 44 18,487 - 17 684 26,938
31 December 2025 (179,312) (96) 16,587 (2,838) 233 172,403 4,312 447 (353) 11,383
($'000) 2025 2024 (Restated 40 )
Deferred tax liabilities (145,110) (141,403)
Deferred tax assets 156,493 254,065
11,383 112,662
As of December 2025 the Group had gross total unused tax losses of $1,169.2
million (as of 31 December 2024: $957.0 million) available to offset against
future profits and other temporary differences. The Group has not recognised
deferred tax on tax losses and other differences of $1,265.6 million.
In Greece and the UK, the net DTA for carried forward losses recognised in
excess of the other net taxable temporary differences was $121.4 million and
$22.1 million (2024: $101.5 million and $29.8 million) respectively.
Greek tax losses (Prinos area) can be carried forward without limitation up
until the relevant concession agreement expires (by 2049), 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 with first oil expected in 2029, the deferred tax asset is fully
utilised by 2038. Finally, in the UK, decommissioning losses are expected to
be utilised by 2030 in accordance with the latest taxable profits forecasts.
During the period, historic deferred tax assets in Italy (mainly
decommissioning asset) amounting to $124.2 million have been derecognised,
reflecting updated projections of taxable profits, primarily driven by the
downward revision of Cassiopea asset reserves and the corresponding impact on
forecasted taxable profits.
11. Cash and cash equivalents
($'000) 2025 2024 (Restated 41 )
Cash and bank deposits 227,213 235,270
227,213 235,270
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 4.44% for the year
ended 31 December 2025 (2024: 4.82%).
Restricted cash
Restricted cash comprises the following:
Current: The current portion of restricted cash at 31 December 2025 was $99.4
million. It mainly relates to the March 2026 coupon payment on Israeli Senior
Secured Notes (at 31 December 2025 is $97.6 million, 2024: $82.43 million). It
also includes $1.8 million of restricted cash held in Egypt (2024: nil).
Non-Current: The cash restricted for more than 12 months after the reporting
date was $3.3 million (2024: $2.95 million) mainly comprising $2.3 million
(2024: $2.15 million) held on the Interest Service Reserve Account ('ISRA') in
relation to the Greek Loan Notes and $0.8 million (2024: $0.8 million) for
Prinos Guarantee.
12. Trade and other receivables
($'000) 2025 2024 (Restated 42 )
Trade and other receivables, current
Financial items:
Trade receivables 363,963 341,339
Receivables from partners under JOA 2,967 290
Other receivables 22,470 8,131
Refundable VAT 32,120 49,438
Accrued interest income 968 1,048
422,488 400,246
Non-financial items:
Deposits and prepayments 19,375 19,885
Other deferred expense 2,005 2,116
Refundable VAT 7,954 -
29,334 22,001
451,822 422,247
Other non-current assets
Financial items:
Other tax receivable 16,798 15,693
16,798 15,693
Non-financial items:
Deposits and prepayments 12,282 15,399
Deferred borrowing fees 952 -
Other non-current assets 829 2,360
14,063 17,759
30,861 33,452
13. Borrowings
($'000) 2025 2024
Non-current
Bank borrowings - after one year but within five years
4.875% Senior Secured notes due 2026 ($625 million) - 622,102
6.5% Senior Secured notes due 2027 ($450 million) - 445,797
5.375% Senior Secured notes due 2028 ($625 million) 621,144 619,602
Bank borrowings - more than five years
5.625% Senior Secured notes due 2031 (€400 million) 459,663 -
5.875% Senior Secured notes due 2031 ($625 million) 618,673 617,689
8.50% Senior Secured notes due 2033 ($750 million) 735,990 734,820
Nitzana facility 31,848
Bank Leumi Loan 746,033 -
Revolving credit facility 130,567 -
Greek State Loan Notes 11,823 11,398
BSTDB Loan - 90,496
Carrying value of non-current borrowings 3,335,741 3,141,904
Current
Other borrowings 124,543 -
Revolving credit facility - 128,000
BSTDB Loan 104,462 -
Carrying value of current borrowings 229,005 128,000
Carrying value of total borrowings 3,584,746 3,269,904
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.
At 31 December 2025 the Group holds US$2.0 billion in aggregate principal
amount of senior secured notes, issued in three series as follows:
· $625 million, issued on 24 March 2021, maturing on 30 March 2028,
with a fixed annual interest rate of 5.375%.
· $625 million, issued on 24 March 2021, maturing on 30 March 2031,
with a fixed annual interest rate of 5.875%.
· $750 million, issued on 11 July 2023, maturing on 30 September
2033, with a fixed annual interest rate of 8.5%.
The interest on each series is paid semi-annually on 30 March and 30
September. The notes are listed for trading on the TACT Institutional of the
Tel Aviv Stock Exchange Ltd (TASE), and the TASE-UP for the 2023 issuance.
Additionally, on 10 November 2025 the Group issued €400 million senior
secured notes, maturing in 2031 with a fixed annual interest rate of 5.625%.
These notes are listed on the Official List of the Euronext Dublin and traded
on the Global Exchange Market (GEM), with interest paid semi-annually on 15
May and 15 November. The proceeds were used to refinance the $450 million
senior secured notes maturing on 30 April 2027 with a fixed annual interest
rate of 6.5% and to pay related fees and expenses. The security package
remains the same as it was for the $450 million senior secured notes.
In February 2025, the Group signed a 10-year, senior-secured term loan with
Bank Leumi as the Facility Agent and Arranger for $750 million. The term loan
proceeds were used to refinance the 2026 Energean Israel Limited Notes ($625
million maturing in March 2026) and to provide additional liquidity for the
Katlan development. The interest rate for the loan is floating. The term loan
is secured on the assets of Energean Israel, pari passu with the Energean
Israel Limited notes, non-recourse to Energean and has a bullet repayment in
2035.
Energean Oil and Gas SA entered into a loan agreement on 27 December 2021 with
Black Sea Trade and Development Bank for €90.5 million for the development
of the Epsilon Oil Field, with an interest rate of EURIBOR plus margin, and
another agreement with the Greek State for €9.5 million maturing in 8 years
with a fixed rate plus margin.
In October 2025 the Group entered into a new $70.0 million unsecured nine-year
term loan facility with Bank Hapoalim to fund its share of construction costs
in Nitzana project in Israel. It is subject to SOFR + 3.9% interest charge. An
initial drawdown of $33.3 million was made during the reporting period, with
the remaining balance expected to be drawn as project payments progress.
Finally, the Group signed a three-year $275 million Revolving Credit Facility
(RCF) on 8 September 2022, increased to $300 million in May 2023. The RCF
provides additional liquidity for corporate needs, including for issuing LCs
for decommissioning in the UK, with an interest rate on loans of 5% plus SOFR
on drawn amounts. In March 2025, the Group signed new documentation to extend
the $300 million Revolving Credit Facility by three years until September
2028. The loan extension was conditional upon certain precedents, all of which
were satisfied in August 2025.
Current and non-current classification of borrowings
At 31 December 2025, the temporary suspension of production at Prinos affected
the assessment of certain covenant conditions under the Black Sea Trade and
Development Bank facility. As a result, and in accordance with IAS 1, the
related borrowing has been presented as current at the reporting date.
Subsequent to year end, production resumed and the facility continues in line
with its contractual maturity to 2030.
On 29 April 2025, the company signed a $ 125 million unsecured facility
agreement with a third party. The interest rate applied is set at 3.95% plus
SOFR rate. In 2025, the Company drew $125 million in full at an average
interest rate of 8.24%. In February 2026 the loan was amended by the parties
to extend its maturity to 15 March 2027, with an option exercisable at the
Company's discretion to extend to 15 September 2027. The amendment resulted in
the loan being reclassified as non-current borrowings in 2026.
Capital management
The Group defines capital as the total equity and net debt of the Group.
Capital is managed in order to provide returns for shareholders and benefits
to stakeholders and to safeguard the Group's ability to continue as a going
concern.
The Group is not subject to any externally imposed capital requirements. To
maintain or adjust the capital structure, the Group may put in place new debt
facilities, issue new shares for cash, repay debt, engage in active portfolio
management, adjust the dividend payment to shareholders, or undertake other
such restructuring activities as appropriate.
($'000) 2025 2024 (Restated 43 )
Current borrowings 229,005 128,000
Non-current borrowings 3,355,741 3,141,904
Total borrowings 3,584,746 3,269,904
Less: Cash and cash equivalents 227,213 235,270
Restricted cash 102,744 85,377
Net Debt 3,254,789 2,949,257
Total equity 141,622 577,465
14. Provisions
($'000) Decommissioning Provision for litigation and other claims Total
At 1 January 2024 830,676 7,510 838,186
Additions - - -
Change in estimates 25,903 489 26,392
Recognised in property, plant and equipment 3,535 3,535
Recognised in profit or loss 22,368 489 22,857
Spend (12,313) (12,313)
Reclassification (30,588) (30,588)
Unwinding of discount 33,016 - 33,016
Currency translation adjustment (36,035) (362) (36,398)
At 31 December 2024 (Restated 44 ) 810,659 7,637 818,296
Current provisions 96,280 - 96,280
Non-current provisions 714,379 7,637 722,016
At 1 January 2025 (Restated 45 ) 810,659 7,637 818,296
Additions - 50,000 50,000
Change in estimates (31,491) (2,665) (34,156)
Recognised in property, plant and equipment (27,624) (27,624)
Recognised in profit or loss (3,867) (2,665) (6,532)
Spend (54,604) (66,490)
Reclassification to payables (7,120) 4,765
Unwinding of discount 35,231 - 35,231
Currency translation adjustment 82,292 50,950 133,242
At 31 December 2025 834,966 55,922 890,888
Current provisions 62,030 51,054 113,084
Non-current provisions 772,936 4,868 777,804
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 2052 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 Greece, UK, Italy, Croatia and Israel. No
provision has been recognised for Egypt as there is no legal or constructive
obligation as of 31 December 2025.
The principal assumptions used in determining decommissioning obligations for
the Group are shown below:
Inflation assumption Discount rate assumption Cessation of production assumption Spend in 2025 2025 ($'000) 2024 ($'000)
Greece 2.04%-2.00% 3.70% 2045 - 16,021 12,966
Italy 1.66%-2.00% 3.90% 2052 23,046 540,394 496,984
UK 2.11% 4.28% 2033 31,558 166,332 193,972
Israel 2.19%-2.70% 4.78% 2044 - 89,999 85,357
Croatia 1.66%-2.00% 3.90% 2039 - 22,220 21,380
Total 54,604 834,966 810,659
Litigation and other claims provisions
Litigation and other claim provision relates to provision for amounts drawn
under the letter of credit relating to the non-completion payment for the
cancelled transaction (refer to note 16 for further detail) and litigation
actions currently open in Italy and Egypt. It is not currently possible to
accurately predict the timing of the settlement of these claims and therefore
the expected timing of the cash flows.
15. Trade and other payables
($'000) 2025 2024
Trade and other payables, current
Financial items:
Trade accounts payable 244,846 255,495
Payables to partners under JOA 46 182,847 240,876
Other payables 47 66,044 84,971
Deferred consideration - 97,915
Short term lease liability 19,314 16,370
Deferred income 96,430 -
VAT payable 9,778 4,228
619,259 699,855
Non-financial items:
Accrued expenses 48 97,563 91,762
Other finance costs accrued (note 9) 57,790 51,460
Social insurance and other taxes 5,450 4,729
160,803 147,951
780,062 847,806
Other non-current liabilities
Financial items:
Trade and other payables 14,987 80,020
Long term lease liability 21,647 41,572
36,634 121,592
Non-financial items:
Social insurance 75 792
75 792
36,709 122,384
16. Discontinued operations
On 19 June 2024, the Company entered into a binding sale and purchase
agreement for the sale of its portfolio in Egypt, Italy and Croatia (together
referred to as "Energean Capital Limited Group", "ECL" or "ECL Group"), to an
entity controlled by Carlyle International Energy Partners (the "Transaction")
(the "SPA"). The sale of ECL was expected to be completed within 12 months.
At 31 December 2024, ECL Group was classified as a disposal group held for
sale ("HFS") and as a discontinued operation. The business of ECL Group
comprised the entirety of the Group's Egypt operating segment until 20 June
2024. With ECL being classified as discontinued operations, the Egypt segment
was no longer presented in the segment note. ECL operations in Italy and
Croatia were previously included in the Group's Europe operating segment; as a
result of the classification of ECL Group as a discontinued operation, they
were no longer presented within this segment for the period ending 31 December
2024. Completion of the Transaction was conditional upon customary regulatory
approvals in Italy and Egypt together with antitrust approvals in Italy, Egypt
and Common Market for Eastern and Southern Africa, to be satisfied by a
longstop date of 20 March 2025. As of the longstop date, certain regulatory
approvals in Italy and Egypt were not obtained by Carlyle (or waived), in
accordance with the terms of the SPA. Additionally, the Company was not able
to reach agreement with Carlyle to extend the longstop date beyond 20 March
2025. Accordingly, on 21 March 2025, the Company terminated the SPA.
Subsequently, on 25 April 2025, the Company drew the amount of $50 million
under the letter of credit for payment of the Non-Completion Payable pursuant
to the terms of the SPA. The Company fully provided for it on receipt.
Following the cessation of "held for sale" classification, the measurement of
ECL reverted to the basis that would have applied had the classification never
occurred (being lower than the recoverable amount). This resulted in a
catch-up depreciation charge of $65 million, recognised for the period from
the original date of classification, together with the related deferred tax
adjustment. To ensure consistency in presentation and measurement, the
comparative financial information has been restated as if ECL had never met
the criteria to be classified as held for sale. ECL results previously
presented in discontinued operations are reclassified and included in income
from continuing operations for all periods presented. The amounts for twelve
months ended 31 December 2024 have been re-presented. The amounts presented
for the assets and liabilities of disposal groups classified as held for sale
in the comparative statement of financial position have been also restated
accordingly.
There was no impact on reported cashflow financial results. The cessation of
"held for sale" classification resulted in an adjustment between the lines
within Operating activities of the Cashflow statement, between profit before
tax and depreciation adjustment to reconcile profit before taxation to net
cash provided by operating activities.
17. Dividends
In line with its dividend policy, Energean paid dividends of US$1.2 per share
in 2025, covering four quarters of payments. Similarly, in 2024, the company
also distributed US$1.2 per share over four quarters.
US$ cents per share $' 000
2025 2024 2025 2024
Dividends announced and paid in cash
Ordinary shares
March 30 30 54,991 54,844
June 30 30 55,277 54,991
September 30 30 55,277 54,990
December 30 30 55,277 54,990
Total 120 120 220,822 219,815
18. Legal cases and contingent liabilities
The Group holds through its subsidiary Energean Italy S.p.A. ("Energean
Italy") a 40% non-operated participating interest in the Cassiopea gas
concession in Italy. The remaining interest is held by the operator, Eni
Mediterranea Idrocarburi S.p.A. The concession is governed by a Joint
Operating Agreement ("JOA").
During 2025, a dispute arose between Energean Italy and the operator in
relation to certain costs invoiced by the operator. In addition to that, as a
consequence of the operator's conduct - which is contested by Energean Italy -
from 1 October 2025 Energean Italy has not been receiving production from the
field. The Group has accounted for the retention of production by the operator
as a non-cash settlement of outstanding joint operating liabilities, measured
by reference to the contractual valuation mechanism in accordance with the
JOA. The settlement of $13 million has been recognised within other operating
income with a corresponding reduction to trade payables. Arbitration
proceedings between the parties are ongoing at the date of approval of
Energean plc consolidated financial statements.
As at 31 December 2025 the outstanding amounts billed by the operator - and
disputed by Energean Italy - and expenses accrued in relation to Cassiopea
total approximately €144 million and are included within trade payables.
In the arbitration, the operator has asserted claims of up to €153 million
in respect of (i) unpaid and disputed invoices and (ii) amounts relating to
production revenues received by the Group during a certain period of time or
compensation of operating expenses incurred by the operator during the same
period. While the total amount asserted by the operator is broadly comparable
to the aggregate balance recognised by the Group as trade payables in respect
of the Cassiopea asset, the amounts do not represent an agreed net position
between the parties and remain subject to arbitration. The operator's claim
includes additional elements (including alleged revenue-related amounts), and
the Group's recognised balance for costs incurred.
The operator has also asserted in the arbitration proceedings that Energean's
participating interest should be transferred. The Group considers this
assertion to be without legal merit based on external legal advice obtained
and the clarification issued by the Ministry of the Environment and Energy
Security ("MASE").
As of December 2025, Energean Italy has submitted counterclaims totalling
approximately €265 million, including claims for reimbursement of invalid
costs and damages.
In accordance with IAS 37 Provisions, Contingent Liabilities and Contingent
Assets:
· invoices received from the operator, although disputed, have been
recognised as trade payables where they relate to costs incurred;
· counterclaims and claims for damages have not been recognised as
assets, as their realisation is dependent on the outcome of the arbitration
proceedings and therefore represent contingent assets at the reporting date.
Although the claims and counterclaims relate to overlapping subject matters,
they are accounted for separately in accordance with IFRS, and no offsetting
has been applied in the group statement of financial position.
The ultimate outcome of the arbitration proceedings remains uncertain and may
result in adjustments to amounts currently recognised.
19. Subsequent events
In November 2025, ExxonMobil farmed into Block 2, which is located at the
northwest part of the Ionian Sea. The new participating interests are:
Energean (30%, operator), ExxonMobil (60%) and HELLENiQ ENERGY Upstream (10%).
The transaction was completed on 11 March 2026 upon receipt of the government
approval and the extension of the license requested by Energean and HelleniQ.
Energean will remain the Operator of the concession through the exploration
stage, during which an exploratory well is expected to be drilled in early
2027, subject to permitting. Energean's share of past costs were received at
the Closing Date. Energean's share of exploration costs, up to a defined cap,
will be carried as part of the consideration.
On 28 February 2026, the Group received an order from the Israeli Ministry of
Energy and Infrastructure to temporary suspend the production at the FPSO due
to the escalation of geopolitical tensions in the region. At the date of this
report, the timing of the resumption of production remains uncertain, although
the Group expects operations to resume as soon as the situation stabilises.
On 12 March 2026 the Group announced that it had signed an agreement to
acquire Chevron's 31% operated interest in Block 14 and 15.5% non-operated
interest in Block 14K, offshore Angola. The Block 14 assets produce around 42
kbbl/d of oil in total, equivalent to 13 kbbl/d net to the interest to be
acquired. The effective date of the transaction is 1 January 2026, with
closing expected by the end of 2026, subject, inter alia, to government and
regulatory approvals and the waiver of applicable pre-emption rights. The
consideration comprises:
· a base consideration of $260 million subject to closing
adjustments and economic performance of the assets 49 between the effective
date and the closing date, and
· $250 million of contingent payments capped at $25 million per
annum.
1 As described in note 16 to the financial statements, the business
previously classified as discontinued operation was reclassified to continuing
operations and the comparative financial information has been restated as if
that business had never met the criteria to be classified as held for sale.
2 Cash cost of production is defined later in the financial review.
3 Cash G&A is defined later in the financial review.
4 Adjusted EBITDAX is defined later in the financial review. Energean uses
adjusted EBITDAX as a core business KPI.
(( 5 )) See explanation for 2025 result in '2025 Review' and 'Financial
Review'.
6 This guidance is suspended - see '2026 Guidance' section.
7 Per YE25 D&M and NSAI CPRs.
8 Based on the Annual Contracted Quantities over the life of the contract.
Does not assume any price indexation.
9 Subject to the issuance of an export permit by the Petroleum Commissioner.
10 Cash cost of production is defined later in the financial review.
11 Cash G&A is defined later in the financial review.
12 Adjusted EBITDAX is defined later in the financial review. Energean uses
adjusted EBITDAX as a core business KPI.
13 Inclusive of restricted cash
14 This includes an upside sharing mechanism between Chevron and Energean
for realised oil prices over a certain threshold during this period.
15 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.
16 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
17 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.
18 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.
19 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
20 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
21 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
22 Other revenue from production activities relates to the non-cash
settlement of outstanding payables to partners for Cassiopea concession in
Italy.
23 Other income from reversal of prior period accrual mainly relates to
$18.9 million reversed accrued expense no longer required in Egypt, following
the lapse of the statute of limitations period under the Egyptian Commercial
law.
24 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
25 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
26 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
27 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
28 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
29 The Group has not recognised deferred tax assets relating to current-year
tax losses and other temporary differences, predominantly arising in Italy
($98.0 million), the UK ($10.9 million), and Cyprus ($2.2 million), in line
with the latest forecasts and assumptions regarding future taxable profits.
The Italian component primarily reflects the impairment recognised on the
Cassiopea asset ($307.8 million) and the non-recognition of a deferred tax
asset on the current-year tax losses and other temporary differences ($100.7
million), both calculated at the applicable Italian tax rate of 24%.
30 Tax impact of impairments recognised in Italy on the Cassiopea &
Gemini assets of $307.8 million.
31 Historic deferred tax assets in Italy amounting to $124.0 million have
been derecognised, reflecting updated projections of taxable profits,
primarily driven by the downward revision of Cassiopea commercial reserves and
the corresponding impact on forecasted taxable profits.
32 Restated for discontinued operation reclassified to continuing operations
and depreciation catch-up adjustment, refer to Note 16 for further detail.
This amount includes the reclassification of assets from held for sale
following the termination of the transaction.
33 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
34 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
35 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
36 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
37 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
38 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
39 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
40 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
41 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
42 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
43 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
44 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
45 Restated for discontinued operation reclassified to continuing
operations, refer to Note 16 for further detail.
(( 46 )) Payables to partners under the JOA include both payables and working
capital estimates provided by the operators. The decrease in 2024 is due to
the payables to partners for JOAs in Italy and Egypt.
(( 47 )) Other payables primarily consist of royalties accrued in Israel
($36.8 million as of 31 December 2025, $35.5 million as of 31 December 2024)
and in Italy ($27.9 million as of 31 December 2024, $30.3 million as of 31
December 2024).
(#_ftnref48) (56 )Accrued expenses mainly relate to development expenditure
incurred in Israel (Katlan) and Italy (Cassiopea).
49 This includes an upside sharing mechanism between Chevron and Energean
for realised oil prices over a certain threshold during this period.
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