2025 Full Year Results

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 Energean Group	2024[1] Energean Group	Increase/ (Decrease) %
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 Energean Group	2024 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/

Enquiries

For capital markets:
Kyrah McKenzie, Investor Relations Manager	Tel: [phone]
[e-mail]
For media:
Adonis Seferlis, CEO Office Communications Manager	Tel: [phone]
[e-mail]
Ben Brewerton, FTI Consulting	Tel: [phone]
[e-mail]

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 2P reserves mmboe	Revision and discoveries mmboe	2025 production mmboe	2025 2P reserves mmboe	% change before 2025 production	% change after 2025 production
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 Kboed	2024 Kboed	% change
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 Energean Group	FY 2024 Energean Group	Increase/ (Decrease) %
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]	3,255	2,949
Net Debt Excluding Israel4	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] 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 loss in subsequent periods	43,622	(25,449)
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 or loss in subsequent periods	(72)	87
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

*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 Chief Executive Officer

Panagiotis Benos 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 & equipment		-	1,801
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 Benefit Trust	184,105,617	183,480,959
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, $'000	Europe	Israel	Egypt	Other & inter-segment transactions	Total
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 (Restated89), $'000	Europe	Israel	Egypt	Other & inter-segment transactions	Total
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 EBITDAX90	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 $'000	Europe	Israel	Egypt	Other & inter-segment transactions	Total
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]), $'000	Europe	Israel	Egypt	Other & inter-segment transactions	Total
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 differences[29]	(38,129)	(11,153)
Non - deductible Italian assets impairments[30]	(73,863)	-
Recognition of previously unrecognised deferred tax/ Derecognition of previously recognised deferred tax[31]	(124,861)	15,627
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 (Note 3.17)	8.75% (2024: 8.87%)	5.93% (2024: 6.24%)
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.

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[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).

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.

 

END