6-K 1 form6k-35369_eni.htm 6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________

Form 6-K

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

For the month of February 2026

Eni S.p.A.

(Exact name of Registrant as specified in its charter)

Piazzale Enrico Mattei 1 - 00144 Rome, Italy

(Address of principal executive offices)

_________________________

(Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.)

Form 20-F X Form 40-F

_________________________

(Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2b under the Securities Exchange Act of 1934.)

Yes _ No X

(If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): )

Table of contents

Eni’s Board of Directors. Approval of the third tranche of the provision in place of 2025 dividend: € 0.26 per share

Eni: results for the fourth quarter and full year 2025. Significant strategic progress and financial performance

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorised.


	Eni S.p.A.

	/s/ Paola Mariani
	Name: Paola Mariani
	Title: Head of Corporate
	Secretary’s Staff Office

Date: February 26, 2026

Eni’s Board of Directors

Approval of the third tranche of the provision in place of 2025 dividend: € 0.26 per share

Rome, 25 February 2026 – Eni’s Board of Directors, chaired by Giuseppe Zafarana, today resolved to distribute to Shareholders the third of the four tranches of the provision in place of the 2025 dividend¹ from Eni S.p.A. available reserves of € 0.26 (compared to a total annual provision, in place of the dividend, equal to € 1.05) per share outstanding at the ex-dividend date as of 23 March 2026², payable on 25 March 2026³, as resolved by the Shareholders’ Meeting of 14 May 2025.

Holders of ADRs, outstanding at the record date of 24 March 2026, will receive € 0.52 per ADR, payable on 8 April 2026⁴, with each ADR listed on the New York Stock Exchange representing two Eni shares.

Eni Company Contacts:

Press Office: Tel. +39.0252031875 – +39.0659822030

Freephone for shareholders (from Italy): 800940924
Freephone for shareholders (from abroad): +39.800 11 22 34 56

Switchboard: +39.0659821

ufficio.stampa@eni.com

segreteriasocietaria.azionisti@eni.com

investor.relations@eni.com

Website: www.eni.com

¹ Coupon No. 53.

² Depending on the recipient’s fiscal status the payment is subject to a withholding tax or is treated in part as taxable income.

³ Pursuant to article 83-terdecies of the Italian Legislative Decree no. 58 of February 24, 1998, the right to receive the payment is determined with reference to the entries on the books of the intermediary – as set out in art. 83-quater, paragraph 3 of the Italian Legislative Decree no. 58 of February 24, 1998 – at the end of the accounting day of 24 March 2026 (record date).

⁴ On ADR payment date, Citibank, N.A. will pay net of the amount of the withholding tax under Italian law applicable to all Depository Trust Company Participants.

Eni: results for the fourth quarter and full year 2025

Significant strategic progress and financial performance

Consistent and meaningful execution of strategy evidenced in excellent 4Q and full year financial results.

Operational delivery supports resilient performance mitigating more adverse upstream pricing and currency impacts.

4Q adjusted net income €1.20 bln, up 35% y-o-y. 4Q CFFO of €3 bln, up 4% y-o-y. Cashflow well ahead of plan and active portfolio management contribute to historically low gearing of 14%.

E&P delivers six major projects in the year in Angola, Indonesia, Norway and Congo. Full year production of 1.73 mln boe/d exceeds expectations:

Oil & gas production growth of more than 7% over 2022-2025 to 1.84 mln boe/d in 4Q

Leading reserve replacement ratio 167% organic. Exploration activities add 0.9 bln boe to our resource base

Agreement to launch JV with Petronas across Indonesia/Malaysia; on track to start operating by mid ’26

Significant progress toward FID of Argentina LNG project in partnership with YPF and XRG

GGP expands in the LNG market with new long-term sale contracts in Turkey and Thailand

Significant progress in our Transition activities:

Plenitude adds French renewables with Neoen and new customers with pending Acea Energia acquisition

Robust pipeline of biofuels projects currently executed, aiming to triple our capacity by 2030

20% investment by Ares into Plenitude for €2 bln; JV formed with GIP for our CCS activities.

Rome, February 26, 2026 - Eni's Board of Directors, chaired by Giuseppe Zafarana, yesterday approved the unaudited consolidated results for the fourth quarter and the FY 2025. Eni CEO Claudio Descalzi said:

“In 2025 we proved that the consistent execution of our strategy, developed in the most recent years, is delivering a resilient business with structurally stronger earnings power. We delivered strong operational performance, brought key projects on stream on schedule, and continued to reduce debt while increasing returns to our investors. Exploration & Production results were outstanding, driven by accretive production growth and disciplined costs. We started up six major projects, enabling production to finish above full-year guidance and delivering underlying growth of 4%. We also strengthened the pipeline, taking FIDs on four major projects reinforcing our medium-term outlook. In parallel, we created a new growth platform through our largest business combination with Petronas in Indonesia and Malaysia focused on LNG.

Our Transition businesses delivered material growth and value creation, further diversifying and strengthening earnings. In a challenging market for renewables, we confirmed the resilience of our integrated models, and we highlighted over €23 bln of enterprise value with the transactions we completed with private equity investors.

Our strategic progress translated into exceptional financial delivery: 2025 CFFO reached €12.5 bln, well ahead of plan on a scenario-adjusted basis, and pro-forma gearing ended the year at 14%. With leverage reduced, we increased shareholder distributions, raising the share buy-back by 20%, combining balance sheet strength with enhanced returns. Overall, despite volatile markets, 2025 demonstrated our ability to deliver competitive production growth, disciplined capital allocation and debt reduction coupled with attractive shareholder returns.”

Key operating and financial results


Q3			Q4			Full Year
2025			2025	2024	% Ch.	2025	2024	% Ch.
1,756	Hydrocarbon production	kboe/d	1,839	1,716	7	1,728	1,707	1
4.8	Installed capacity from renewables at period end	GW	5.8	4.1	41	5.8	4.1	41
2,996	Proforma adjusted EBIT ^(a)	€ million	2,865	2,699	6	12,223	14,322	(15)
2,073	subsidiaries		1,782	1,694	5	8,344	10,348	(19)
923	main JV/Associates ^(b)		1,083	1,005	8	3,879	3,974	(2)
	Proforma adjusted EBIT (by segment) ^(a)
2,638	E&P		2,795	2,780	1	11,163	13,022	(14)
346	Global Gas & LNG Portfolio (GGP) and Power		186	279	(33)	1,392	1,274	9
331	Enilive and Plenitude		279	133	110	1,208	1,143	6
(53)	Refining and Chemicals		(109)	(275)	60	(689)	(713)	3
(266)	Corporate, other activities and consolidation adjustments		(286)	(218)		(851)	(404)
2,273	Adjusted net profit before taxes ^(a)		2,011	1,925	4	9,233	11,125	(17)
1,247	Adjusted net profit (loss)^(a)(c)		1,196	885	35	4,989	5,257	(5)
803	Net profit (loss) ^(c)		90	230	(61)	2,608	2,624	(1)
3,297	Cash flow from operations before changes in working capital at replacement cost ^(a)		3,010	2,889	4	12,496	13,590	(8)
3,078	Net cash from operations		4,350	3,620	20	13,330	13,092	2
1,990	Organic capital expenditure ^(d)		2,617	2,693	(3)	8,521	8,804	(3)
9,931	Net borrowings before lease liabilities ex IFRS 16		9,386	12,175	(23)	9,386	12,175	(23)
52,966	Shareholders' equity including non-controlling interest		52,787	55,648	(5)	52,787	55,648	(5)
0.16	Gearing before lease liabilities ex IFRS 16 ^(a)(e)		0.14	0.18		0.14	0.18

(a) Non-GAAP measures. For further information see the paragraph "Non-GAAP measures" on pages 19 and subsequent.

(b) The main JV/associates are listed in the "Reconciliation of Group proforma adjusted EBIT" on page 25.

(d) Net of expenditures relating to business combinations, purchase of minority interests and other non-organic items.

(e) Figure as at Dec. 31, 2025 on a proforma basis, considering ongoing disposals/acquisitions.

Strategic and financial highlights

E&P delivered a very resilient performance. FY production ahead of guidance and Dual Exploration model realizing value

4Q ‘25 oil&gas production rose more than 7% y-o-y and 5% sequentially to 1.84 mln boe/d, enabled by accelerated and smooth start-ups and ramp-ups and excellent base business performance. FY production at 1.73 mln boe/d, 4% underlying growth vs 2024.

Leading 2025 reserve replacement ratio (167% organic, 162% all sources). FY discovered resources of 900 mln boe including in 4Q ’25 the Konta gas discovery in the Kutei Basin finding potential in excess of 1 TCF, close to existing facilities for a fast-track development.

A binding agreement signed with Petronas to establish a jointly-controlled E&P satellite over Indonesia/Malaysia, combining two material gas asset portfolios with rich exploration potential and initial production level of over 300 Kboe/d, expected to quickly ramp up to a sustainable level of over 500 Kboe/d. The entity will commence operations by mid ’26.

Entry into the upstream of Uruguay with the farm-in of 50% and the operatorship of Block OFF-5 in the offshore.

Start-up of Phase 2 of the Congo FLNG project, ahead of plan, raising production capacity to the design target of 3 MTPA (from current 0.6 MTPA). First LNG loading achieved in February ‘26.

Inauguration by Azule of the gas treatment plant for the NGC operated project, the first non-associated gas project in Angola, feeding the Angola LNG export plant and the domestic market. First gas production into plant was reached in February ’26.

The 12 MTPA Argentina LNG project moved towards FID with the partners signing the Joint Development Agreement.

After year-end, sold a further 10% stake in the Baleine oilfield in Côte d'Ivoire to Socar with expected closing in 1Q ’26.

GGP signed 1.2 MTPA long-term LNG sale contracts in Thailand and Turkey to continue to diversify its global LNG footprint and to develop strategic commercial partnerships

Transition-related satellites on-track to meet their growth milestones with improving profitability ahead

The binding agreement for the acquisition by Plenitude of Acea Energia was signed in December. Acea will strengthen Plenitude’s presence in its core Italian retail energy market immediately reaching the target of 11 mln clients in Europe, originally planned for 2028. Finalization of the deal, subject to normal approvals, is expected by June 2026.

Plenitude closed the acquisition of Neoen, adding 0.76 GW of installed generating capacity in France. Capacity has topped 5.8 GW with a substantial pipeline of development projects expected to reach 10 GW by 2028.

Construction works began at the Pengerang biorefinery in Malaysia, a JV with Petronas and Euglena, designed to process 650 Ktonnes/y of renewable feedstock. The project is part of Enilive’s portfolio of development initiatives, at various stages of execution, to triple the manufacturing capacity of biofuels by 2030 from current 1.7 MTPA.

Value realized from satellite strategy:

Closed the 20% equity investment in Plenitude by Ares Management for €2 bln, implying an enterprise value in excess of €12 bln.

Closed the investment of a 49.99% stake in Eni CCUS by GIP, forming a strategic partnership to develop and fully valorize Eni’s portfolio of CCS projects.

4Q ‘25 results demonstrate resilience of Eni’s business model underpinned by profitable oil&gas production growth, business diversification and cost and capital discipline

4Q ‘25 Group proforma adjusted EBIT was €2.87 bln above 2024 despite a 15% decline in crude oil prices and a 9% appreciation in the EUR/USD rate, aided by volume growth and cost efficiencies. The Group reported an adjusted net profit of €1.2 bln, up 35% y-o-y in part driven by a tax rate of 37% (giving around 44% for the full year).

E&P reported €2.80 bln of proforma adjusted EBIT (increase y-o-y), with positive effects from production growth and self-help initiatives offsetting lower crude realizations and currency headwinds.

GGP and Power reported proforma adjusted EBIT of €0.19 bln, consistent with our guidance, driven by continued margin improvement from gas and LNG portfolio optimization and asset-backed trading in a weaker market environment.

Enilive generated €0.18 bln of proforma adjusted EBIT (€0.26 bln proforma adjusted EBITDA), more than tripled vs. 4Q ’24, driven by recovery in bio-margins. Plenitude reported a proforma adjusted EBIT of €0.10 bln (€0.23 bln proforma adjusted EBITDA), increasing y-o-y.

Refining reverted to profit (versus a loss in the year-ago quarter) helped by improved product crack spreads. Chemicals reported a loss of €0.2 bln, impacted by the prolonged European industry slump, offsetting restructuring benefits.

Adjusted cash flow before working capital was €3.01 bln, funding gross capex of €2.62 bln. Portfolio management delivered €1.73 bln of net proceeds, mainly relating to the investment by Ares into Plenitude and GIP into CCS. Cash returns to shareholders were €1.4 bln, comprising the second instalment of the 2025 dividend of €0.77 bln and share repurchases of €0.67 bln. Cash flow was supported by initiatives addressing working capital with overall cash initiatives delivering a €4 bln benefit in the FY offsetting the scenario. Net borrowings declined to €9.4 bln from September 30, 2025. This reduced gearing to 15%, and incorporating agreed but not completed portfolio transactions, proforma gearing at quarter-end was 14%.

Outlook 2026

The Company will issue its main financial and operating guidance for 2026 and its strategic plan at a Capital Markets Update scheduled for March 19, 2026. A press release summarizing the Group’s strategy and objectives will be issued before the conference call and disseminated through the Company’s website (eni.com) and other public channels as required by applicable listing standards. In the meantime, however, we are providing the following outlook for 2026:

oil and gas production growth expected to be consistent with the 2025-28 Plan guidance;

gross capex expected to be €7 bln; net capex at around €5 bln;

gearing is expected to be between 10-15%¹.

¹ Assuming Brent price at 62 $/bbl.

Business segments: operating and financial results

Exploration & Production

Production and prices

Q3			Q4			Full Year
2025			2025	2024	% Ch.	2025	2024	% Ch.
69.07	Brent dated	$/bbl	63.69	74.69	(15)	69.06	80.76	(14)
1.168	Average EUR/USD exchange rate		1.163	1.067	9	1.130	1.082	4
1,756	Hydrocarbons production	kboe/d	1,839	1,716	7	1,728	1,707	1
860	Liquids	kbbl/d	890	786	13	840	784	7
4,687	Natural gas	mmcf/d	4,966	4,862	2	4,644	4,831	(4)
52.07	Average realizations ^(a)	$/boe	47.84	54.46	(12)	51.36	55.43	(7)
64.00	Liquids	$/bbl	58.40	69.02	(15)	63.51	73.64	(14)
7.40	Natural gas	$/kcf	6.89	7.35	(6)	7.24	7.24

(a) Prices related to consolidated subsidiaries.

In 4Q ’25, hydrocarbons production averaged 1.84 mln boe/d, up by more than 7% compared to the previous year (1.73 mln boe/d in the FY ’25, up by 1%). Excellent project development performance was delivered in production start-ups and ramp-ups in Norway, Côte d'Ivoire, Mexico, Congo, Angola, Indonesia and Ghana. This was supplemented by excellent base business regularity. Offsetting these effects were mature fields declines and tail asset divestments closed in 2024 in Nigeria, Alaska, and Congo. Quarterly underlying y-o-y production growth was 9.2%. Sequentially, hydrocarbon production increased by 5% compared to Q3 ‘25 thanks to the ramp-ups of organic projects in Norway, Angola, Indonesia and Mexico, as well as higher contribution in Libya.

Liquids production was 890 kbbl/d in 4Q ’25, up by 13% compared to 4Q ’24 (840 kbbl/d in FY ’25, up by 7%). The organic growth in Côte d'Ivoire due to the start of Baleine Phase 2, Mexico, Angola and Norway was partly offset by divestments and mature fields declines.

Natural gas production was 4,966 mmcf/d, up by 2% compared to 4Q ’24 (4,644 mmcf/d in FY ’25, down 4%). Organic growth in Congo (Marine XII) and Indonesia (Merakes East) as well as at our satellites in Angola/Norway was partly offset by the divestments and mature fields decline.

Proved oil&gas reserves – preliminary data

(bboe)
Net proved reserves at December 31, 2024		6.5
Additions		1.0
Production		(0.6)
Net proved reserves at December 31, 2025		6.9
Reserves replacement ratio, all sources	(%)	162

Net additions of proved reserves related to discoveries, extensions and revisions of previous estimates and portfolio activities. These additions drove an all-sources reserve replacement ratio of 162% (167% organic).

The reserves life index was around 11 years as of December 31, 2025.

More information about the Company’s reserves activity for the year will be disclosed in our 2025 Annual Report on Form 20-F.

Results


Q3			Q4			Full Year
2025	(€ million)		2025	2024	% Ch.	2025	2024	% Ch.
4,616	Upstream turnover		4,713	5,416	(13)	19,436	23,053	(16)
2,638	Proforma adjusted EBIT		2,795	2,780	1	11,163	13,022	(14)
838	of which: main JV/Associates		991	984		3,670	3,802	(3)
1,670	Operating profit (loss) of subsidiaries		1,186	706	68	6,302	6,715	(6)
130	Exclusion of special items		618	1,090		1,191	2,505
1,800	Adjusted operating profit (loss) of subsidiaries		1,804	1,796		7,493	9,220	(19)
2,015	Adjusted profit (loss) before taxes		2,036	2,219	(8)	8,464	10,247	(17)
41.7	tax rate (%)		34.8	55.6		42.4	53.4
1,175	Adjusted net profit (loss)		1,328	986	35	4,875	4,777	2
45	Exploration expenses:		80	442	(82)	211	741	(72)
36	prospecting, geological and geophysical expenses		52	51	2	174	186	(6)
9	write-off of unsuccessful wells		28	391	(93)	37	555	(93)
1,535	Capital expenditure		1,943	1,785	9	6,253	6,055	3

Q3			Q4			Full Year
2025	Main JV/Associates		2025	2024	% Ch.	2025	2024	% Ch.
838	Adjusted operating profit (Eni's share)	(€ million)	991	984		3,670	3,802	(3)
479	of which: Vår Energi		681	493	38	2,169	2,287	(5)
204	Azule		163	292	(44)	817	1,110	(26)
299	Adjusted net profit		256	365	(30)	1,050	1,198	(12)
307	Total dividends		303	343	(12)	1,206	1,124	7
493	Hydrocarbon production	(kboe/d)	523	435	20	470	400	18

In 4Q ’25, Exploration & Production reported a proforma adjusted EBIT of €2,795 mln, an increase vs. 4Q ’24 despite the weaker scenario (the Brent marker was down by 15%; the EUR/USD exchange rate up by 9%) due to positive effects from production growth and favorable mix effects, self-help initiatives and lower exploration write-offs. In FY ’25, proforma adjusted EBIT was €11,163 mln, down by 14% compared to FY ’24, driven by the same factors as in 4Q ‘25.

In 4Q ’25, the segment reported an adjusted net profit of €1,328 mln, increasing by 35% compared to 4Q ’24 and includes the contribution from JVs and associates, in particular Vår Energi, Azule Energy and Ithaca Energy. Adjusted net profit was €4,875 mln in FY ’25, increasing compared to FY ‘24.

In 4Q ’25 the tax rate was 35% (42% in FY ’25) decreasing by approximately 20 percentage points from 4Q ’24 (about 10 percentage points from FY ’24) mainly driven by a more favorable geographical mix of pretax profit and as several exploration projects were matured to FID during the quarter, which enabled the Company to reassess the tax deductibility of exploration expenses.

For the disclosure on business segment special charges, see “Special items” in the Group results section.

Strategic developments

In 2025, resource additions from exploration activity totaled about 900 mln boe, extending a more than 10-year streak of organic replacement of production. We have made high-impact and near field discoveries in several geographies. In April, Eni’s jointly participated Azule Energy (Eni 50%) confirmed a significant discovery at the Capricornus 1-X well, in Namibia's Orange basin, performing a successful production test across a light oil-bearing reservoir, followed in September by a further rich gas and condensate discovery at the Volans-1X well. In December, Eni made a significant gas discovery in Indonesia, in the Kutei Basin, with the Konta discovery. Azule Energy also announced a discovery on Angola’s first dedicated gas exploration well, Gajajeira-01. In 2025 near field discoveries were made in Norway (via Eni’s 63% owned associate Vår Energi) and in Côte d'Ivoire.

In October, Eni signed a new exploration contract in Côte d'Ivoire for the CI-707 offshore block, geologically continuous with the nearby CI-205 block, where Eni announced the discovery of Calao in March 2024. This proximity offers an opportunity for future synergistic developments.

In October, Eni and its partners CNPC, ENH, Kogas, and XRG reached the Final Investment Decision (FID) to develop the Coral North FLNG project in Mozambique, which will put in production the gas volumes from the northern part of Area 4 Coral gas reservoir, in the Rovuma basin, through a floating LNG facility with 3.6 MTPA production capacity. The project will leverage Eni’s fast-track approach and expertise from the Coral South project and is expected to start in just three years.

In October, Eni and the Argentina's YPF signed the Final Technical Project Description (FTPD), a significant step towards the FID for the 12 MTPA integrated upstream-midstream Argentina LNG (ARGLNG) project intended to monetize the gas reserves of the Vaca Muerta basin. Through a phased approach, the project could be scaled up to 30 MTPA in the long-term. In February, Eni and YPF signed a binding Joint Development Agreement (JDA) with XRG, part of the ADNOC Group,

to advance Argentina LNG.

In November, Eni and Petronas signed a binding agreement to establish an independent 50:50 company (NewCo), by combining their respective upstream assets in Indonesia and Malaysia which will leverage a self-funded development of a material resource base to achieve a sustainable, medium-term production plateau of 500 Kboe/d. Through this jointly-controlled Newco, Eni and Petronas will establish a regional LNG leader to deliver long-term value creation, operational excellence, and leadership in the energy transition.

In November, Eni, through its subsidiary Nigeria Agip Exploration Limited (NAE), acquired from TotalEnergies EP Nigeria Limited an additional 2.5% stake in the Production Sharing Contract (PSC) OML 118, exercising its pre-emption right. NAE's share in OML 118 PSC increased from 12.5% to 15%.

In November, Eni signed an agreement for the acquisition from YPF of a 50% share and operatorship in the exploration Block OFF-5 in Uruguay’s offshore, leveraging the framework of the integrated upstream-midstream project Argentina LNG (ARGLNG). The agreement is subject to the approval of the Uruguayan authorities.

In November, Eni, through its satellite Azule Energy started the operations at the NGC (New Gas Consortium) Gas Treatment Plant in Soyo, Northern Angola. The NGC is the Angola’s first non-associated gas development project with a processing capacity of approximately 400 mmscf/d of gas and 20 kbbl/d of condensate.

In December, Eni launched the Phase 2 of Congo LNG ahead of schedule, with the goal of exporting the first LNG cargo in early 2026. Congo LNG Phase 2 features three production platforms, the Scarabeo 5 unit dedicated to gas treatment and compression and the Nguya FLNG for liquefaction and export, bringing the overall project’s capacity to 3 MTPA, equivalent to 4.5 bcm/y.

In January 2026, Eni signed a binding agreement with SOCAR for the sale of a 10% stake in the Baleine Project in Côte d’Ivoire. The closing is subject to appropriate regulatory approvals and other customary terms and conditions.

In February 2026, in Libya Eni was awarded the O1 offshore exploration license through a consortium with other partners. Eni will operate the concession.

In February 2026, exploration activities yielded positive results: (i) in Angola, where Azule Energy confirms a significant oil discovery in the Algaita-01 exploration well in the offshore Block 15/06; and (ii) in Côte d'Ivoire, with a significant gas and condensate discovery, successfully drilling the Murene South-1X well, in the Block CI-501.

Global Gas & LNG Portfolio and Power

Sales and production

Q3			Q4			Full Year
2025			2025	2024	% Ch.	2025	2024	% Ch.
	Global Gas & LNG Portfolio
36	Spot Gas price at Italian PSV	€/MWh	32	45	(28)	39	36	6
32	TTF		30	43	(30)	36	34	5
3	Spread PSV vs. TTF		2	2		2	2
	Natural gas sales	bcm
4.26	Italy		6.30	6.67	(6)	21.00	24.40	(14)
3.72	Rest of Europe		5.94	7.78	(24)	18.73	23.40	(20)
0.09	Importers in Italy		0.32	0.31	3	0.91	1.26	(28)
3.63	European markets		5.62	7.47	(25)	17.82	22.14	(20)
1.20	Rest of World		1.17	0.81	44	3.99	3.08	30
9.18	Worldwide gas sales ^(a)		13.41	15.26	(12)	43.72	50.88	(14)
3.3	LNG sales		3.2	2.7	19	12.1	9.8	23
	Power
4.83	Thermoelectric production	TWh	5.76	5.60	3	20.53	20.16	2

(a) Data include intercompany sales.

In 4Q ’25, natural gas sales were 13.41 bcm, a decrease of 12% from the comparative period. Sales in Italy declined by 6% vs. 4Q ’24, with lower volumes sold in the wholesale market. Sales in the European market amounted to 5.62 bcm, a decrease of 25% vs. 4Q ’24, reflecting lower sales in Turkey. In FY ’25, natural gas sales amounted to 43.72 bcm, down by 14% y-o-y, mainly driven by lower volumes marketed in Italy (down by 14% or 3.40 bcm vs. the FY ’24) and in the European markets (down by 20% or 4.32 bcm vs. the FY ’24), in particular in Turkey following the termination of the gas sale contract on BlueStream at the end of 2024. Sales in the Rest of World reported a positive performance, increasing by 44% and 30%, vs. 4Q ’24 and FY ’24, respectively, sustained by increasing LNG sales.

Thermoelectric production amounted to 5.76 TWh in 4Q ’25, up by 3% vs. 4Q ’24 with a higher plant utilization rate. In FY ‘25, production reported a slight increase of 2% y-o-y, in order to seize market opportunities (20.53 TWh in FY ’25 vs. 20.16 TWh in FY ’24).

Results

Q3		Q4			Full Year
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
3,503	Sales from operations	4,583	6,185	(26)	17,120	18,876	(9)
346	Proforma adjusted EBIT	186	279	(33)	1,392	1,274	9
279	GGP	135	226	(40)	1,045	1,138	(8)
4	of which: main JV/Associates	7	8	(13)	30	39	(23)
67	Power	51	53	(4)	347	136	..
227	Operating profit (loss) of subsidiaries	185	(130)	..	1,770	(909)	..
115	Exclusion of special items	(6)	401		(408)	2,144
342	Adjusted operating profit (loss) of subsidiaries	179	271	(34)	1,362	1,235	10
348	Adjusted profit (loss) before taxes	178	277	(36)	1,378	1,272	8
37.9	tax rate (%)	47.8	31.0		38.2	38.1
216	Adjusted net profit (loss)	93	191	(51)	851	787	8
14	Capital expenditure	58	43	35	109	110	(1)

In 4Q ’25, the Global Gas & LNG Portfolio business achieved a proforma adjusted EBIT of €135 mln, a decrease of 40% from the comparative period, due to a weaker market scenario especially in terms of volatility, spreads and overall lower price environment. Additionally, the comparative quarter benefitted from positive one-off benefits from commercial agreements. In the FY ’25, proforma adjusted EBIT amounted to €1,045 mln, down by 8% compared to FY ’24, due to weaker market scenario and lower benefits of contractual renegotiations and settlements.

In 4Q ’25, the Power generation business reported a proforma adjusted EBIT of €51 mln, substantially in line. In FY ‘25, proforma adjusted EBIT was €347 mln, increasing by €211 mln compared to FY ’24 driven by a one-off gain relating to contractual renegotiation.

For the disclosure on business segment special charges, see “Special items” in the Group results section.

Strategic developments

In December, Eni signed a long-term LNG sale agreement with Botas for the supply of approximately 0.4 MTPA of LNG for 10 years, starting from 2028. This contract follows a 3-year deal signed by the two corporations in September 2025.

In December, Eni entered into a long-term LNG sale agreement with Thailand’s Gulf Development Company to supply 0.8 MTPA of LNG for 10 years to Gulf, one of Thailand's largest private power producers, from 2027. The agreement represents Eni’s first long term LNG supply to Thailand.

In January, Eni and its partners, China National Petroleum Corporation (CNPC), ENH, KOGAS and XRG announced the hull launch of the Coral North FLNG that will be the second floating LNG facility to be deployed in the Rovuma Basin waters, North of Mozambique, and will bring to production the gas from the Northern part of Coral gas reservoir. With a capacity of 3.6 MTPA, Coral North will double Mozambique’s total LNG output to 7 MTPA.

Enilive and Plenitude

Enilive

Q3			Q4			Full Year
2025			2025	2024	% Ch.	2025	2024	% Ch.
	Enilive
1,143	Spread EU HVO UCO-based vs UCO	$/tonnes	1,439	866	66	1,034	720	44
420	Spread US RD^(a) UCO-based vs UCO		446	849	(48)	448	881	(49)
315	Bio throughputs	ktonnes	276	163	69	1,157	1,115	4
85	Average bio refineries utilization rate	%	75	43		78	74
5.75	Total Enilive sales	mmtonnes	5.12	4.81	6	21.54	22.73	(5)
2.10	Retail sales		1.95	1.95	0	7.81	7.69	2
1.49	of which: Italy		1.40	1.37	2	5.54	5.40	3
3.21	Wholesale sales		2.21	2.37	(7)	11.12	12.77	(13)
2.42	of which: Italy		1.45	1.92	(24)	8.22	9.90	(17)
0.44	Other sales		0.96	0.49	96	2.61	2.27	15

(a) Renewable Diesel.

In 4Q ’25, bio throughputs were 0.28 mmtonnes, up by 69% y-o-y, driven by higher volumes processed at Venice and Gela biorefineries following planned maintenance shutdowns in the 4Q ‘24. In FY ‘25, bio throughputs were 1.16 mmtonnes, increasing by 4% y-o-y reflecting the same drivers as in the quarter.

In 4Q ’25, retail sales were 1.95 mmtonnes, unchanged vs 4Q ‘24. In FY ‘25, retail sales amounted to 7.81 mmtonnes, an increase (up by 2%) y-o-y, supported by a positive performance recorded mainly in Italy, in the gasoline and diesel sales.

In 4Q ’25, wholesale sales were 2.21 mmtonnes, a reduction of 7% y-o-y mainly following lower product availability in specific geographical areas in Italy. Sales were 11.12 mmtonnes in the FY ‘25, down 13% vs. FY ’24, reflecting the same drivers as in the quarter.

Q3		Q4			Full Year
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
5,206	Sales from operations	4,378	4,924	(11)	19,120	21,139	(10)
317	Proforma adjusted EBITDA	255	136	88	953	852	12
233	Proforma adjusted EBIT	180	53	..	637	539	18
(8)	of which: main JV/Associates	(13)		..	(45)	(32)	(41)
219	Operating profit (loss) of subsidiaries	106	(79)	..	499	282	77
(8)	Exclusion of inventory holding (gains) losses	81	(9)		115	112
30	Exclusion of special items	6	141		68	177
241	Adjusted operating profit (loss) of subsidiaries	193	53	..	682	571	19
225	Adjusted profit (loss) before taxes	173	45	..	611	512	19
163	Adjusted net profit (loss)	152	41	..	456	358	27
283	Cash flow from operations before changes in working capital at replacement cost	229	22	..	837	472	77
(1,338)	Net borrowings	(545)	(386)	(41)	(545)	(386)	(41)
98	Capital expenditure	269	192	40	468	416	13

In 4Q ’25 Enilive reported a proforma adjusted EBIT of €180 mln, representing a more than three-fold increase compared to 4Q’24 (€637 mln in FY ’25, compared to €539 mln in FY ’24, up by 18%): the positive performance primarily reflects the strong results achieved by our Italian biorefineries, supported by the recovery in EU bio-margins and higher volumes processed.

Proforma adjusted EBITDA amounted to €255 mln, increasing by 88% compared to the 4Q ’24 (€136 mln). In FY ’25, Enilive reported a proforma adjusted EBITDA of €953 mln, compared to a profit of €852 mln in FY ’24 (up by 12%).

Strategic developments

In November, Pengerang Biorefinery Sdn. Bhd., the joint venture between Petronas, Enilive and Euglena, started the construction of a new biorefinery in Pengerang (Malaysia). The biorefinery with a yearly processing capacity of up to 650 ktonnes of renewable feedstock, is projected to produce Sustainable Aviation Fuel (SAF), Hydrogenated Vegetable Oil (HVO) and bio-naphtha. The new facility is targeted to commence operations by the second half of 2028.

In February 2026, Eni announced a strategic investment with Q8 Italy for the construction of a new biorefinery in Priolo, Sicily, as part of the transformation plan for the Versalis site. The Priolo biorefinery with an expected capacity of 500 ktonnes/y will offer extensive operational flexibility for the production of HVO and SAF-Biojet. Completion is expected by the end of 2028.

Plenitude


Q3			Q4			Full Year
2025			2025	2024	% Ch.	2025	2024	% Ch.
	Plenitude
110	Italian PUN Index GME	€/MWh	115	128	(10)	115	109	6
9.9	Retail and business customers at period end	mln pod	10.0	10.0	0	10.0	10.0	0
0.47	Retail and business gas sales to end customers	bcm	1.75	1.73	1	5.29	5.51	(4)
4.84	Retail and business power sales to end customers	TWh	4.80	4.62	4	18.63	18.28	2
4.8	Installed capacity from renewables at period end	GW	5.8	4.1	41	5.8	4.1	41
1.6	Energy production from renewable sources	TWh	1.3	1.2	8	5.6	4.7	19
22.1	EV charging points at period end	thousand	22.8	21.3	7	22.8	21.3	7

As of December 31, 2025, retail and business customers were around 10 mln (gas and electricity), in line with December 31, 2024.

Retail and business gas sales to end customers amounted to 1.75 bcm in 4Q ’25, with a slight increase compared to 4Q ’24. In FY ‘25, gas sales amounted to 5.29 bcm, decreasing by 4% vs. the comparative period, mainly in Italy due to lower gas customers.

Retail and business power sales to end customers were 4.80 TWh in 4Q ’25, reflecting an increase compared to 4Q ’24. In FY ’25 power sales amounted to 18.63 TWh, benefitting from higher volumes sold in the domestic market.

As of December 31, 2025, the installed capacity from renewables² was 5.8 GW reflecting the organic development in Spain, the UK, Italy and Kazakhstan as well as the acquisitions in France and the USA.

Energy production from renewable sources was 1.3 TWh in 4Q ’25, up by 8% y-o-y, mainly thanks to the start-up of organic projects and the contribution from acquired assets (5.6 TWh in FY ’25, up by 19% y-o-y).

As of December 31, 2025, EV charging points amounted to 22.8 thousand, up by 7% compared to 21.3 thousand as of December 31, 2024, thanks to network development, mainly in Italy, France, Germany, Austria and Switzerland.

Q3		Q4			Full Year
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
1,818	Sales from operations	2,747	2,985	(8)	10,168	10,179	(0)
221	Proforma adjusted EBITDA	230	205	12	1,065	1,058	1
98	Proforma adjusted EBIT	99	80	24	571	604	(5)
23	Operating profit (loss) of subsidiaries	66	315	(79)	153	1,307	(88)
69	Exclusion of special items	30	(232)		401	(691)
92	Adjusted operating profit (loss) of subsidiaries	96	83	16	554	616	(10)
84	Adjusted profit (loss) before taxes	90	83	8	510	564	(10)
53	Adjusted net profit (loss)	70	54	30	346	366	(5)
163	Cash flow from operations before changes in working capital at replacement cost	(27)	8	..	716	781	(8)
1,967	Net borrowings	2,123	2,261	(6)	2,123	2,261	(6)
190	Capital expenditure	234	216	8	764	887	(14)

In 4Q ’25 Plenitude reported a proforma adjusted EBIT of €99 mln, up by 24% vs 4Q ’24, reflecting higher results on retail business as well as the ramp-up in renewable installed capacity and related production volumes. In FY ’25 Plenitude reported a proforma adjusted EBIT of €571 mln, a 5% reduction compared to a proforma adjusted EBIT of €604 mln in FY ’24, due to lower results on Retail business, mainly related to a reduced contribution of energy efficiency solutions and increasing competitive pressure.

In 4Q ’25, proforma adjusted EBITDA amounted to €230 mln, up by 12% vs 4Q ’24. In FY ’25, Plenitude reported a proforma adjusted EBITDA of €1,065 mln, a slight increase compared to FY ’24, reflecting the higher capacity in operation, partially offset by lower wind in Europe and negative price scenario in some key countries.

For the disclosure on business segment special charges, see “Special items” in the Group results section.

² As of December 31, 2025, Eni Group installed capacity from renewables totaled 4.1 GW (Eni’s share).

Strategic developments

In November, Plenitude closed the 20% equity investment by Ares Alternative Credit funds, affiliates of Ares Management Corporation, for €2 bln, implying an enterprise value of over €12 bln.

In November, Plenitude signed an agreement to acquire from Neoen, a portfolio of 52 operating assets (photovoltaic plants, wind farms, and one operating battery storage facility), for approximately 760 MW installed capacity located in France, with a production of approximately 1.1 TWh of electricity annually. The deal was completed by year-end.

In November, Plenitude started the construction of the “Tarsia Ovest” wind farm in Italy, with an installed capacity of approximately 13 MW. The wind farm is expected to generate about 30 GWh/y of energy.

In December, Plenitude signed a binding agreement with ACEA S.p.A for the acquisition of a 100% equity stake in ACEA Energia, operating in the energy retail market. The finalization of the transaction, expected by June 2026, is conditional, upon authorization by the relevant Antitrust authorities. This transaction will strengthen Plenitude’s presence in its core Italian energy market, reaching the target of 11 mln customers in Europe originally planned for 2028.

In December, Plenitude inaugurated the Caparacena solar project in Chimeneas (Granada). The project, one of the most significant in the company’s portfolio in Spain, includes three photovoltaic parks of 50 MW each. The complex, with a total installed capacity of 150 MW will be able to generate approximately 320 GWh of electricity annually.

Refining and Chemicals

Production and sales

Q3			Q4			Full Year
2025			2025	2024	% Ch.	2025	2024	% Ch.
	Refining
8.9	Standard Eni Refining Margin (SERM)	$/bbl	11.7	3.7	..	7.3	5.1	43
3.81	Throughputs in Italy on own account	mmtonnes	3.35	3.30	2	14.22	13.76	3
2.79	Throughputs in the rest of World on own account		2.77	2.74	1	10.72	10.45	3
6.60	Total throughputs on own account		6.12	6.04	1	24.94	24.21	3
84	Average refineries utilization rate	%	77	78		80	78
	Chemicals
0.59	Sales of chemical products	mmtonnes	0.62	0.74	(16)	2.72	3.17	(14)
47	Average plant utilization rate	%	48	47	2	49	50	(2)

Refining

In 4Q ’25, the Standard Eni Refining Margin averaged 11.7 $/barrel vs. 3.7 $/barrel in 4Q ’24 mainly due to more favorable middle distillate crack spreads leveraged by supply disruptions (outages and geopolitical risk) against a backdrop of refinery closures in the Atlantic Basin (7.3 $/barrel in FY ‘25, representing an increase vs. 5.1 $/barrel reported in FY ’24).

In 4Q ’25, throughputs on own accounts at Eni’s refineries in Italy amounted to 3.35 mmtonnes, up 2% y-o-y, mainly supported by higher volumes processed at the Milazzo refinery, following lower shutdowns. Throughputs outside Italy increased slightly by 1% vs. 4Q ’24, driven by higher volumes processed by ADNOC. In FY ’25, throughputs both in Italy and in the rest of World reported an increase of 3% compared to FY ‘24.

Chemicals

Sales of chemical products were 0.62 mmtonnes in 4Q ’25, a 16% decrease y-o-y due to lower productions and weaker demand. In the FY ‘25, sales amounted to 2.72 mmtonnes, representing a decrease of 14% from the comparative period.

Margins remained weak across the board as commodity prices did not recover feedstock and energy input expenses due to European industry headwinds, sluggish economic activity, and competitive pressures from players with advantaged cost structure.

Results

Q3		Q4			Full Year
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
4,545	Sales from operations	4,169	4,686	(11)	18,179	21,210	(14)
(53)	Proforma adjusted EBIT	(109)	(275)	60	(689)	(713)	3
135	Refining	95	(44)	..	130	101	29
83	of which: main JV/Associates	95	16	..	207	177	17
(188)	Chemicals	(204)	(231)	12	(819)	(814)	(1)
(291)	Operating profit (loss) of subsidiaries	(892)	(600)	(49)	(2,485)	(1,681)	(48)
69	Exclusion of inventory holding (gains) losses	188	(159)		684	95
86	Exclusion of special items	500	468		905	696
(136)	Adjusted operating profit (loss) of subsidiaries	(204)	(291)	30	(896)	(890)	(1)
(58)	Adjusted profit (loss) before taxes	(106)	(286)	63	(714)	(755)	5
(74)	Adjusted net profit (loss)	(100)	(107)	7	(681)	(449)	(52)
142	Capital expenditure	233	179	30	663	632	5

In 4Q ’25, the Refining business, including contribution from the ADNOC R&GT associate, reported a positive performance of €95 mln, compared to a loss of €44 mln reported in 4Q ’24 results, reflecting the recovery in refining margins following improved product crack spreads. In FY ’25, the business reported a proforma adjusted profit of €130 mln, up by 29% vs. the FY ’24 results (€101 mln) supported also by the higher average utilization plant rate.

The Chemical business, managed by Versalis, reported a proforma adjusted loss of €204 mln in 4Q ’25, a slightly better performance compared to the loss in 4Q ’24 (€231 mln), as the restructuring program has begun to yield some benefits, offsetting the adverse market scenario. The overall picture of the chemical sector remains depressed, driven by macro headwinds impacting commodity demands, and comparatively higher production costs in Europe vs. other geographies, which reduced the competitiveness of Versalis products with respect to US and Asian players in an oversupplied market. In FY ’25, proforma adjusted loss amounted to €819 mln (€814 mln loss in FY ’24) reflecting exceptionally adverse market conditions.

For the disclosure on business segment special charges, see “Special items” in the Group results section.

Strategic developments

In October, the authorization process for the transformation of the Priolo site started. The proposed project includes a new biorefinery and a chemical recycling plant for plastics based on Versalis’ proprietary Hoop^® technology. The new biorefinery will have a production capacity of 500 ktonnes per year, with completion expected by the end of 2028. The Versalis Hoop^® plant will have a processing capacity of 40 ktonnes per year.

In December, Versalis signed a strategic partnership with Prysmian to give new life to plastic cable scrap, through an innovative chemical recycling process, developing a dedicated supply chain.

As of January 1, 2026, the business branch of Eni SpA’s Refining Evolution & Transformation unit has been transferred to the new subsidiary Eni Industrial Evolution (EIE) SpA, engaged in the traditional assets and in the industrial transformation, also with a view to the circular economy, through the development of new industrial supply chains. The transaction is part of Eni’s strategy to ensure a fully decarbonized energy offering both in production processes and to consumers, seizing the opportunities and growth prospects offered by the energy transition, including the industrial transformation of Brindisi and Priolo sites.

Sustainability and other developments

The main achievements of the Group strategy aiming at improving Eni’s ESG performance have been:

In October, Eni and the Bioenergy Association for Sustainable Development, affiliated with the Ministry of Environment of the Arab Republic of Egypt, signed a cooperation agreement to prepare a comprehensive feasibility study for establishing biogas production units based on the treatment of animal and agricultural waste. The biogas produced by biodigestion can generate renewable electricity and heat, while also producing higher-value organic fertilizers for use in agriculture, further contributing to the circular economy.

In November, five agritech startups were awarded at the third edition of the Kenya Agribusiness Entrepreneurship Program (KAEP), the entrepreneurial development initiative promoted by Eni Natural Energies (ENE) Kenya and Joule, Eni’s business school, in collaboration with the E4Impact foundation. These five projects were selected for their potential in terms of scalability and impact, receiving a financial award of €10,000.

In November, Eni inaugurated the photovoltaic plant at the “Lycée de Tataouine” in Southern Tunisia. The plant is part of the company’s program which includes the installation of solar panels in public schools across the Tataouine region, involving 14 primary and secondary institutions, for a total installed capacity of around 200 kW.

In December, Eni and International Labour Organization (ILO) expanded their partnership on safety, health and social protection to the Republic of Congo.

In December, Eni and Global Infrastructure Partners (“GIP”), part of BlackRock, finalized the sale of a 49.99% stake in Eni CCUS Holding, company managing the greatest part of Eni’s decarbonization projects, which will be jointly controlled by the two partners. Eni CCUS Holding operates the Liverpool Bay and Bacton projects in the UK and the L10-CCS project in the Netherlands. Furthermore, the Company has the right to acquire the 50% held by Eni of Ravenna CCS project in Italy and it will be able to include other potential projects within a broader platform of CCS initiatives in the medium to long term.

In January, Eni ranked first in the Corporate Human Rights Benchmark (CHRB) published by the World Benchmarking Alliance (WBA). This assessment is part of a global analysis that has recognised Eni as one of the 2,000 world’s most influential companies with the scale, reach and responsibility to catalyse a meaningful, sustainable change, providing a transparent assessment of how businesses manage and respect human rights across their operations and value chains.

During 4Q ’25, Eni once again confirmed its excellent ranking in the main ESG ratings applied in financial markets: MSCI ESG (“A”), Sustainalytics ESG Risk Rating (“Medium Risk”), ISS ESG (B-/ Prime Status) and CA100+ Net Zero Benchmark.

Group Results

Q3		Q4			Full Year
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
20,204	Sales from operations	20,615	23,488	(12)	82,151	88,797	(7)
1,344	Operating profit (loss)	176	(373)	..	5,010	5,238	(4)
117	Exclusion of inventory holding (gains) losses	270	9	..	745	434	72
612	Exclusion of special items ^(a)	1,336	2,058	(35)	2,589	4,676	(45)
2,073	Adjusted operating profit (loss)	1,782	1,694	5	8,344	10,348	(19)
923	main JV/Associates adjusted EBIT	1,083	1,005	8	3,879	3,974	(2)
2,996	Proforma adjusted EBIT	2,865	2,699	6	12,223	14,322	(15)
2,638	E&P	2,795	2,780	1	11,163	13,022	(14)
346	Global Gas & LNG Portfolio (GGP) and Power	186	279	(33)	1,392	1,274	9
331	Enilive and Plenitude	279	133	110	1,208	1,143	6
(53)	Refining and Chemicals	(109)	(275)	60	(689)	(713)	3
(266)	Corporate, other activities and consolidation adjustments	(286)	(218)		(851)	(404)
2,273	Adjusted profit (loss) before taxes	2,011	1,925	4	9,233	11,125	(17)
1,315	Adjusted net profit (loss)	1,267	904	40	5,210	5,333	(2)
865	Net profit (loss)	137	288	(52)	2,758	2,764	-
803	Net profit (loss) attributable to Eni's shareholders	90	230	(61)	2,608	2,624	(1)
87	Exclusion of inventory holding (gains) losses	175	3	..	508	308	65
357	Exclusion of special items ^(a)	931	652	43	1,873	2,325	(19)
1,247	Adjusted net profit (loss) attributable to Eni's shareholders	1,196	885	35	4,989	5,257	(5)

(a) For further information see table "Breakdown of special items".

In 4Q ’25, the Group proforma adjusted EBIT of €2.87 bln was 6% higher than the year-ago quarter despite a 15% decline in crude oil prices and a 9% appreciation in the EUR/USD rate y-o-y, with these negative impacts more than offset by volume growth, improved base operating performance at the transition businesses and cost efficiencies. The E&P business reported a proforma adjusted EBIT of €2.80 bln, an increase vs 4Q ’24 despite unfavorable commodity and currency trends due to underlying improvements in connection with oil and gas production growth, an improved production mix due to an increasing contribution of more valuable barrels and cost efficiencies.

The refining business which returned to profitability due to improved product crack spreads (€0.10 bln vs a loss of €0.04 bln in the year-ago quarter). The GGP and Power segment reported proforma adjusted EBIT of €0.19 bln, in line with our guidance, driven by continued value maximization from gas portfolio optimization. The Chemical business on the backdrop of a continued downturn in the European sector reported a loss of €0.20 bln, with improvements from the ongoing restructuring plan expected in coming quarters. Enilive generated €0.18 bln of proforma adjusted EBIT, more than tripled vs. 4Q ’24, driven by a recovery in bio-margins and higher volumes processed. Plenitude reported a proforma adjusted EBIT of €0.10 bln, increasing y-o-y. In FY ‘25, the Group reported a proforma adjusted EBIT of €12.22 bln, down 15% compared to FY ’24, due to the same trends as in 4Q ’25, as well as the circumstance that the comparative period result included a gain on the settlement of certain environmental claims with another Italian company at Italian industrial hubs where Eni took over as successor.

In 4Q ’25 adjusted profit before taxes was €2.01 bln, 4% higher than 4Q ’24, reflecting the trend in the Group adjusted EBIT, partly offset by lower net profits recorded at Eni’s equity-accounted entities driven by the negative commodity scenario partly offset by better operating and volume performances. In FY ‘25, the Group reported an adjusted profit before taxes of €9.23 bln, down 17% compared to FY ’24.

In 4Q ’25 adjusted net profit attributable to Eni’s shareholders of €1.20 bln was 35% higher than 4Q ’24, driven by a lower tax rate down to 37% from 53%, due to increasing operating profit and declining Group tax rate driven by a better geographical mix of profits before taxes in E&P reflecting higher contribution from jurisdictions with lower-than-average tax rates also as result of portfolio rationalization and as several development projects were matured to FID enabling the recognition of the tax benefit associated with previously incurred exploration expenses. In FY ‘25, the Group reported an adjusted net profit attributable to Eni’s shareholders of €4.99 bln, down 5% compared to FY ’24.

Net borrowings and cash flow from operations

Q3		Q4			Full Year
2025	(€ million)	2025	2024	Change	2025	2024	Change
865	Net profit (loss)	137	288	(151)	2,758	2,764	(6)

	Adjustments to reconcile net profit (loss) to net cash provided by operating activities:
1,505	- depreciation, depletion and amortization and other non monetary items	2,146	3,177	(1,031)	7,209	9,951	(2,742)
(32)	- net gains on disposal of assets	(61)	(35)	(26)	(99)	(601)	502
891	- dividends, interests and taxes	315	(182)	497	3,590	4,246	(656)
435	Changes in working capital related to operations	2,108	1,026	1,082	2,735	1,286	1,449
417	Dividends received by equity investments	489	537	(48)	1,785	1,946	(161)
(812)	Taxes paid	(695)	(1,272)	577	(3,737)	(5,826)	2,089
(191)	Interests (paid) received	(89)	81	(170)	(911)	(674)	(237)
3,078	Net cash provided by operating activities	4,350	3,620	730	13,330	13,092	238
(2,017)	Capital expenditure	(2,857)	(2,532)	(325)	(8,647)	(8,485)	(162)
(229)	Investments and acquisitions	(298)	(209)	(89)	(878)	(2,593)	1,715
1,275	Disposal of consolidated subsidiaries, businesses, tangible and intangible assets and investments	24	1,102	(1,078)	1,383	2,788	(1,405)
(93)	Other cash flow related to investing activities	451	(192)	643	183	(996)	1,179
2,014	Free cash flow	1,670	1,789	(119)	5,371	3,806	1,565
(459)	Net cash inflow (outflow) related to financial activities	(690)	(666)	(24)	(1,339)	(531)	(808)
(97)	Changes in short and long-term financial debt	(1,134)	(674)	(460)	(2,555)	(1,293)	(1,262)
(303)	Repayment of lease liabilities	(272)	(272)		(1,250)	(1,205)	(45)
(1,371)	Dividends paid, share repurchases, changes in non-controlling interests and reserves	344	(1,666)	2,010	537	(4,522)	5,059
(1)	Issue of perpetual hybrid bond and interest payment	(453)	178	(631)	(328)	1,640	(1,968)
2	Effect of changes in consolidation and exchange differences of cash and cash equivalent	4	127	(123)	(198)	83	(281)
(215)	NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENT	(531)	(1,184)	653	238	(2,022)	2,260
3,297	Adjusted net cash before changes in working capital at replacement cost	3,010	2,889	121	12,496	13,590	(1,094)

Q3		Q4			Full Year
2025	(€ million)	2025	2024	Change	2025	2024	Change
2,014	Free cash flow	1,670	1,789	(119)	5,371	3,806	1,565
(303)	Repayment of lease liabilities	(272)	(272)		(1,250)	(1,205)	(45)
	Net borrowings of acquired companies	(762)	(149)	(613)	(762)	(631)	(131)
	Net borrowings of divested companies	362		362	362		362
(72)	Exchange differences on net borrowings and other changes	(344)	(428)	84	(1,141)	(364)	(777)
(1,371)	Dividends paid and changes in non-controlling interest and reserves	344	(1,666)	2,010	537	(4,522)	5,059
(1)	Issue of perpetual hybrid bond and interest payment	(453)	178	(631)	(328)	1,640	(1,968)
267	CHANGE IN NET BORROWINGS BEFORE LEASE LIABILITIES	545	(548)	1,093	2,789	(1,276)	4,065
303	Repayment of lease liabilities	272	272		1,250	1,205	45
(113)	Inception of new leases and other changes	(454)	(1,599)	1,145	(497)	(2,322)	1,825
457	CHANGE IN NET BORROWINGS AFTER LEASE LIABILITIES	363	(1,875)	2,238	3,542	(2,393)	5,935

In FY ’25, net cash provided by operating activities was €13,330 mln and included €1,785 mln of dividends received by Eni’s equity-accounted investments, mainly Azule Energy and Vår Energi. The amount of trade receivables discounted as part of non-recourse arrangements with financing institutions was ca. €0.4 bln higher than in 4Q ’24 as part of the Group initiatives to optimize working capital requirements.

Adjusted net cash before changes in working capital at replacement cost was €12,496 mln in FY ’25 (€3,010 mln in 4Q ’25) and was net of the following items: inventory holding gains or losses relating to oil and products, the reversing of timing difference between gas inventories accounted at weighted average cost and management’s own measure of performance leveraging inventories to optimize margins, the fair value of commodity derivatives lacking the formal criteria to be designated as hedges or prorated on an accrual basis, decommissioning provisions related to the reconversion of uncompetitive plants in the transition scenario or to dismantle loss-making activities, non-recurring provisions in connection with certain legal proceedings, as well as in-kind income taxes accrued at PSA petroleum contracts which are assumed to be fully settled in the subsequent quarter.

A reconciliation of adjusted net cash before changes in working capital at replacement cost to net cash provided by operating activities is provided below:

Q3		Q4			Full Year
2025	(€ million)	2025	2024	Change	2025	2024	Change
3,078	Net cash provided by operating activities	4,350	3,620	730	13,330	13,092	238
(435)	Changes in working capital related to operations	(2,108)	(1,026)	(1,082)	(2,735)	(1,286)	(1,449)
50	Exclusion of commodity derivatives	(23)	(19)	(4)	(26)	258	(284)
117	Exclusion of inventory holding (gains) losses	270	9	261	745	434	311
2,810	Net cash before changes in working capital at replacement cost	2,489	2,584	(95)	11,314	12,498	(1,184)
487	Extraordinary (gains) charges and other items	521	305	216	1,182	1,092	90
3,297	Adjusted net cash before changes in working capital at replacement cost	3,010	2,889	121	12,496	13,590	(1,094)

In FY ’25 organic capex was €8.5 bln (down 3% y-o-y) and excluded the share of capex that was already reimbursed or will be reimbursed upon closing of ongoing asset disposals, which have been used to net disposals of the period or reclassified in other cash flows related to investing activities. Net of organic capex, the free cash flow ante working capital was about €4 bln.

Cash inflows from divestments and transactions with owners comprised proceeds from the disposals of noncontrolling interests in consolidated subsidiaries relating to a 30% investment of private equity fund KKR into Enilive for €3.57 bln, a second investment tranche (2.4%) of the EIP fund into Plenitude (€0.21 bln) and a 20% investment by Ares Fund into Plenitude (€2 bln) as well as asset disposals (€1.38 bln) mainly relating to the sale of a 30% stake in the Baleine project and other non-strategic fields in Congo as well as the transaction with GIP to develop and valorize our CCUS business. Acquisitions were of little relevance and mainly related to the expansion of renewable capacity for Plenitude and to the development of the agri-business activity.

Other cash flow relating to investing activities included a cash inflow upon a post-closing adjustment of the business combination with Ithaca Energy Plc (€0.15 bln).

Net borrowings before IFRS 16 in FY ‘25 decreased by around €2.79 bln. The main inflows comprised the adjusted operating cash flow (€12.5 bln) and transactions with equity owners relating to the divestment of noncontrolling interests at Enilive and Plenitude subsidiaries (€5.78 bln). Furthermore, other positive cash inflows regarded asset disposals for €1.38 bln, as well as working capital optimization (€1.1 bln) due to initiatives addressing working capital offsetting the scenario with overall cash initiatives delivering a €4 bln benefit. The main cash outflows comprised capital expenditures of €8.5 bln, dividend payments to Eni’s shareholders and share repurchases of €4.98 bln (€3.08 bln of dividend payments and share repurchases of €1.90 bln), the subscription of new supplier financing agreements (€1 bln), the repayment of lease liabilities and hybrid bond interest (€1.58 bln), changes in consolidation and reclassification as asset held for sale (€0.7 bln) as well as other changes of €1 bln.

As of February 18, 2026, completed the buy-back program of €1.8 bln, corresponding to a total 119 mln share repurchased.

Summarized Group Balance Sheet

(€ million)	Dec. 31, 2024	Dec. 31, 2025	Change


Fixed assets
Property, plant and equipment	59,864	50,536	(9,328)
Right of use	5,822	5,184	(638)
Intangible assets	6,434	6,022	(412)
Inventories - Compulsory stock	1,595	1,187	(408)
Equity-accounted investments and other investments	15,545	14,484	(1,061)
Receivables financing and securities held for operating purposes	1,107	974	(133)
Net payables related to capital expenditure	(1,364)	(1,337)	27
	89,003	77,050	(11,953)
Net working capital
Inventories	6,259	5,143	(1,116)
Trade receivables	12,562	8,986	(3,576)
Trade payables	(15,170)	(13,901)	1,269
Net tax assets (liabilities)	144	1,506	1,362
Provisions	(15,774)	(14,580)	1,194
Other current assets and liabilities	(2,292)	(1,572)	720
	(14,271)	(14,418)	(147)
Provisions for employee benefits	(681)	(596)	85

Assets held for sale including related liabilities	225	5,837	5,612
CAPITAL EMPLOYED, NET	74,276	67,873	(6,403)

Eni's shareholders equity	52,785	47,940	(4,845)
Non-controlling interest	2,863	4,847	1,984
Shareholders' equity	55,648	52,787	(2,861)
Net borrowings before lease liabilities ex IFRS 16	12,175	9,386	(2,789)
Lease liabilities	6,453	5,700	(753)

Net borrowings after lease liabilities ex IFRS 16	18,628	15,086	(3,542)
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	74,276	67,873	(6,403)
Gearing before lease liabilities ex IFRS 16	0.18	0.15
Gearing after lease liabilities ex IFRS 16	0.25	0.22

As of December 31, 2025, fixed assets (€77 bln) decreased by €12 bln from December 31, 2024, mainly due to negative exchange rate translation differences (the period-end exchange rate of EUR vs. USD was 1.176 up 13% compared to 1.039 as of December 31, 2024) thus decreasing the euro book values of dollar-denominated assets as well as asset disposals and the reclassification of certain assets as held for sale. Capital expenditures for the period were offset by DD&A. Assets held for sale were recognized in connection with the proposed business combination of Eni’s oil&gas assets in Indonesia with Petronas’ properties in Malaysia, as well as the pending disposals of minority interests in certain upstream assets and of renewable assets of Plenitude.

Net working capital amount was flat y-o-y at around €14.4 bln. Deferred tax assets, net increased by around €1.4 bln in relation to project FID in E&P driving the recognition of the tax benefit associated with previously incurred exploration expenses, as well as recognition of deferred tax assets at Italian subsidiaries due to recognition of tax-loss carryforwards relating to improved profitability outlook.

Eni’s shareholders equity (€47.9 bln) decreased by €4.9 bln from December 31, 2024, mainly due to negative foreign currency translation differences (€6.1 bln) reflecting the depreciation of the USD vs. EUR, as well as shareholders remuneration of approximately €5 bln (dividend distributions and share buy-back). These reductions were partly offset by net profit for the period (€2.6 bln) and the recognition through retained earnings of the positive difference between the book value of the noncontrolling interests in the subsidiaries Enilive and Plenitude divested to third parties and the consideration received (€3.4 bln).

Non-controlling interests of €4.8 bln included: i) a minority participating interest acquired by the private equity fund KKR in the share capital of Enilive (€0.9 bln) as well as the EIP and Ares fund’s interest in Plenitude of €1.8 bln; ii) a perpetual subordinated hybrid bond (€1.7 bln) issued by a Group subsidiary in 2024, classified as equity since the Group retains an unconditional right to avoid transferring cash or other financial assets to the bondholders.

Net borrowings1F1F³ before lease liabilities as of December 31, 2025 of €9.4 bln was down by approximately €3 bln from December 31, 2024. Gearing⁴ – the ratio of net borrowings to net capital employed before lease liabilities– was 15% on December 31, 2025. Considering the disposal transactions underway, the Group proforma gearing stands at 14%.

Special items

The breakdown of pre-tax special items recorded in operating profit by segment (net charges of €2,589 mln and €1,336 mln in FY ’25 and 4Q ’25, respectively) is as follows:

E&P: net charges of €1,191 mln in FY ’25 (€618 mln in 4Q ‘25) mainly relating to impairment losses at oil&gas properties driven by alignment of a disposal group to its fair value (€511 mln), of which two transactions already closed in the year, reserve revisions as well as price effects (€570 mln);

GGP and Power: net gains of €408 mln in FY '25 (€6 mln in 4Q '25) mainly relating to the accounting effect of certain fair-valued commodity derivatives lacking the formal criteria to be classified as hedges or to be waived from fair value accounting under the own use exemption (net gains of €377 mln and €3 mln in the FY '25 and 4Q '25, respectively) and the difference between the value of gas inventories accounted for under the weighted-average cost method provided by IFRS and management's own measure of inventories, which moves forward at the time of inventory drawdown, the margins captured on volumes in inventories above normal levels leveraging the seasonal spread in gas prices net of the effects of the associated commodity derivatives (net charges of €56 mln and net gains of €18 mln in the FY '25 and 4Q '25, respectively). The reclassification of the negative balance of €292 mln in FY ’25 (€12 mln in 4Q '25) related to derivatives covering margin exposure to foreign currency exchange rate movements and exchange translation differences of commercial payables and receivables;

Enilive and Plenitude: net charges of €469 mln in FY ’25 (€36 mln in 4Q '25) mainly related to the fair values of commodity derivatives lacking the formal criteria to be classified as hedges under IFRS relating exposure to the gas commodity (€368 mln and €8 mln in FY '25 and 4Q '25, respectively) as well as environmental charges (€57 mln and €24 mln in FY '25 and 4Q '25, respectively);

Refining and Chemicals: net charges of €905 mln (€500 mln in 4Q '25) mainly related to impairment losses of chemical plants driven by a reduced profitability outlook because of continuing margins deterioration (€198 mln and €126 mln in FY '25 and 4Q '25, respectively) and the write-down of capital expenditures made for compliance and stay-in-business at certain CGU with expected negative cash flows in Refining business (€253 mln and €107 mln in FY '25 and 4Q '25, respectively). Other charges included environmental provision of €306 mln (€170 mln in 4Q '25) and plant shutdown expenses in the Chemical business (about €77 mln and €47 mln in FY '25 and 4Q '25, respectively).

³ Details on net borrowings are furnished on page 28.

⁴ Non-GAAP financial measures and other alternative performance indicators disclosed throughout this press release are accompanied by explanatory notes and tables in line with guidance provided by ESMA guidelines on alternative performance measures (ESMA/2015/1415), published on October 5, 2015. For further information, see the section “Non-GAAP measures” of this press release. See pages 19 and subsequent.

Other information, basis of presentation and disclaimer

This press release on Eni’s results for the fourth quarter and the full year of 2025 has been prepared on a voluntary basis according to article 82-ter, Regulations on issuers (CONSOB Regulation No. 11971 of May 14, 1999, and subsequent amendments and inclusions). The disclosure of results and business trends on a quarterly basis is consistent with Eni’s policy to provide the market and investors with regular information about the Company’s financial and industrial performances and business prospects considering the reporting policy followed by oil&gas peers who are communicating results on quarterly basis.

Results and cash flow are presented for the third and fourth quarter of 2025, the full year of 2025 and for the 2024 comparative period. Information on the Company’s financial position relates to end of the periods as of December 31, 2025 and December 31, 2024.

Accounts set forth herein have been prepared in accordance with the evaluation and recognition criteria set by the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB) and adopted by the European Commission according to the procedure set forth in Article 6 of the European Regulation (CE) No. 1606/2002 of the European Parliament and European Council of July 19, 2002.

These criteria are unchanged from the 2024 Annual Report on Form 20-F filed with the US SEC on April 4, 2025, which investors are urged to read.

* * *

Non-GAAP financial measures and other alternative performance indicators disclosed throughout this press release are accompanied by explanatory notes and tables in line with guidance provided by ESMA guidelines on alternative performance measures (ESMA/2015/1415), published on October 5, 2015. For further information, see the section “Alternative performance measures (Non-GAAP measures)” of this press release.

The manager responsible for the preparation of the Company’s financial reports, Francesco Esposito, declares pursuant to rule 154-bis paragraph 2 of Legislative Decree No. 58/1998 that data and information disclosed in this press release correspond to the Company’s evidence and accounting books and records.

* * *

Disclaimer

This press release contains certain forward-looking statements particularly those regarding capital expenditure, development and management of oil and gas resources, dividends, share repurchases, allocation of future cash flow from operations, future operating performance, gearing, targets of production and sales growth, new markets and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including the impact of the pandemic disease, the timing of bringing new fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational issues; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document. Due to the seasonality in demand for natural gas and certain refined products and the changes in a number of external factors affecting Eni’s operations, such as prices and margins of hydrocarbons and refined products, Eni’s results from operations and changes in net borrowings for the quarter of the year cannot be extrapolated on an annual basis.

The all sources reserve replacement ratio disclosed elsewhere in this press release is calculated as ratio of changes in proved reserves for the year resulting from revisions of previously reported reserves, improved recovery, extensions, discoveries and sales or purchases of minerals in place, to production for the year. A ratio higher than 100% indicates that more proved reserves were added than produced in a year. The reserves replacement ratio (RRR) is a measure used by management to indicate the extent to which production is replaced by proved oil and gas reserves. The RRR is not an indicator of future production because the ultimate development and production of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks.

Company Contacts

Press Office: Tel. +39.0252031875 - +39.0659822030

Freephone for shareholders (from Italy): 800940924

Freephone for shareholders (from abroad): +80011223456

Switchboard: +39-0659821

ufficio.stampa@eni.com

segreteriasocietaria.azionisti@eni.com

investor.relations@eni.com

website: www.eni.com

Eni

Società per Azioni, Rome, Piazzale Enrico Mattei, 1

Share capital: €4,005,358,876 fully paid.

Tax identification number 00484960588

Tel.: +39 0659821 - Fax: +39 0659822141

This press release for the fourth quarter and the full year of 2025 results (not subject to audit) is also available on Eni’s website eni.com.

Alternative performance indicators (Non-GAAP measures)

Management evaluates underlying business performance on the basis of Non-GAAP financial measures, which are not provided by IFRS (“Alternative performance measures”), such as adjusted operating profit, adjusted net profit, which are arrived at by excluding from reported results certain gains and losses, defined special items, which include, among others, asset impairments, including impairments of deferred tax assets, gains on disposals, risk provisions, restructuring charges, the accounting effect of fair-valued derivatives used to hedge exposure to the commodity, exchange rate and interest rate risks, which lack the formal criteria to be accounted as hedges, and analogously evaluation effects of assets and liabilities utilized in a relation of natural hedge of the above mentioned market risks. Furthermore, in determining the business segments’ adjusted results, finance charges on finance debt and interest income are excluded (see below). In determining adjusted results, inventory holding gains or losses are excluded from base business performance, which is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting as required by IFRS, except in those business segments where inventories are utilized as a lever to optimize margins. Finally, the same special charges/gains are excluded from the Eni’s share of results at JVs and other equity accounted entities, including any profit/loss on inventory holding.

Management is disclosing Non-GAAP measures of performance to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Eni’s trading performance on the basis of their forecasting models.

Non-GAAP financial measures should be read together with information determined by applying IFRS and do not stand in for them. Other companies may adopt different methodologies to determine Non-GAAP measures.

Follows the description of the main alternative performance measures adopted by Eni. The measures reported below refer to the performance of the reporting periods disclosed in this press release:

Adjusted operating and net profit

Adjusted operating profit and adjusted net profit are determined by excluding inventory holding gains or losses, special items and, in determining the business segments’ adjusted results, finance charges on finance debt and interest income. The adjusted operating profit of each business segment reports gains and losses on derivative financial instruments entered into to manage exposure to movements in foreign currency exchange rates, which impact industrial margins and translation of commercial payables and receivables. Accordingly, also currency translation effects recorded through profit and loss are reported within business segments’ adjusted operating profit. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them.

Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents not related to operations. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production segment).

Inventory holding gain or loss

This is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting as required by IFRS.

Special items

These include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones. Exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturally-occurring opposite positions and then dealing with any residual risk exposure in the derivative market. Finally, special items include the accounting effects of fair-valued commodity derivatives relating to commercial exposures, in addition to those which lack the criteria to be designed as hedges, also those which are not eligible for the own use exemption, including the ineffective portion of cash flow hedges, as well as the accounting effects of settled commodity and exchange rates derivatives whenever it is deemed that the underlying transaction is expected to occur in future reporting periods.

Correspondently, special charges/gains also include the evaluation effects relating to assets/liabilities utilized in a natural hedge relation to offset a market risk, as in the case of accrued currency differences at finance debt denominated in a currency other than the reporting currency, where the cash outflows for the reimbursement are matched by highly probable cash inflows in the same currency. The deferral of both the unrealized portion of fair-valued commodity and other derivatives and evaluation effects are reversed to future reporting periods when the underlying transaction occurs.

As provided for in Decision No. 15519 of July 27, 2006 of the Italian market regulator (CONSOB), non-recurring material income or charges are to be clearly reported in the management’s discussion and financial tables.

Gearing

Gearing is calculated as the ratio between net borrowings and capital employed net and measures how much of capital employed net is financed recurring to third-party funding. Gearing ex-IFRS 16 is calculated by excluding lease liabilities from both numerator and denominator.

Cash flow from operations before changes in working capital at replacement cost (Adjusted net cash before changes in working capital at replacement cost)

This is defined as net cash provided from operating activities before changes in working capital at replacement cost. It also excludes certain non-recurring charges such as extraordinary credit allowances and, considering the high market volatility, changes in the fair value of commodity derivatives lacking the formal criteria to be designed as hedges, including derivatives which were not eligible for the own use exemption, the ineffective portion of cash flow hedges, as well as the effects of certain settled commodity derivatives whenever it is deemed that the underlying transaction is expected to occur in future reporting periods.

Free cash flow

Free cash flow represents the link existing between changes in cash and cash equivalents (deriving from the statutory cash flows statement) and in net borrowings (deriving from the summarized cash flow statement) that occurred from the beginning of the period to the end of period. Free cash flow is the cash in excess of capital expenditure needs. Starting from free cash flow it is possible to determine either: (i) changes in cash and cash equivalents for the period by adding/deducting cash flows relating to financing debts/receivables (issuance/repayment of debt and receivables related to financing activities), shareholders’ equity (dividends paid, net repurchase of own shares, capital issuance) and the effect of changes in consolidation and of exchange rate differences; (ii) changes in net borrowings for the period by adding/deducting cash flows relating to shareholders’ equity and the effect of changes in consolidation and of exchange rate differences.

Net borrowings

Net borrowings is calculated as total finance debt less cash, cash equivalents, financial assets measured at fair value through profit or loss and financing receivables held for non-operating purposes. Financial activities are qualified as “not related to operations” when these are not strictly related to the business operations.

Proforma adjusted EBIT

Is the measure adding the operating margin of the equity accounted entities to the adjusted EBIT, introduced by the management to reflect the increasing contribution from the JV/associates also in connection with the Eni satellite model.

Reconciliation tables of Non-GAAP results to the most comparable measures of financial performance determined in accordance to GAAPs

(€ million)
Fourth Quarter 2025	Exploration & Production	Global Gas & LNG Portfolio and Power	Enilive and Plenitude	Refining and Chemicals	Corporate and other activities	Impact of unrealized intragroup profit elimination	GROUP


Reported operating profit (loss)	1,186	185	172	(892)	(542)	67	176
Exclusion of inventory holding (gains) losses			81	188		1	270
Exclusion of special items:
environmental charges	24	1	24	170	117		336
impairment losses (impairment reversals), net	503	(18)	(7)	233	49		760
net gains on disposal of assets	(7)		1	(2)	(7)		(15)
risk provisions	84			20	(4)		100
provision for redundancy incentives	11	1	(1)	1	7		19
commodity derivatives	(6)	(3)	8	(22)			(23)
exchange rate differences and derivatives	(31)	(12)		5			(38)
other	40	25	11	95	26		197
Special items of operating profit (loss)	618	(6)	36	500	188		1,336
Adjusted operating profit (loss) of subsidiaries (a)	1,804	179	289	(204)	(354)	68	1,782
main JV/Associates adjusted EBIT (b)	991	7	(10)	95			1,083
Proforma adjusted EBIT (c)=(a)+(b)	2,795	186	279	(109)	(354)	68	2,865
Finance expenses and dividends of subsidiaries (d)	(24)	(3)	(2)	24	(74)		(79)
Finance expenses and dividends of main JV/associates (e)	(220)	5	(16)	(18)			(249)
Income taxes of main JV/associates (f)	(515)	(10)	2	(3)			(526)
Adjusted net profit (loss) of main JV/associates (g)=(b)+(e)+(f)	256	2	(24)	74			308
Adjusted profit (loss) before taxes (h)=(a)+(d)+(g)	2,036	178	263	(106)	(428)	68	2,011
Income taxes (i)	(708)	(85)	(41)	6	103	(19)	(744)
Tax rate (%)							37.0
Adjusted net profit (loss) (j)=(h)+(i)	1,328	93	222	(100)	(325)

SEC Form 6-K filed by ENI S.p.A.