[6-K] ENI SPA Current Report (Foreign Issuer)

Rhea-AI Filing Summary

Eni S.p.A. reported strong Q3 2025 performance and raised shareholder returns. The Board approved the second tranche of the 2025 dividend provision at €0.26 per share, ex‑dividend on November 24, 2025 and payable on November 26, 2025. Holders of ADRs outstanding at the November 25, 2025 record date will receive €0.52 per ADR on December 5, 2025.

Operationally, production rose 6% year over year to 1.76 million boe/d. Q3 proforma adjusted EBIT was €3.0 billion, adjusted net profit attributable to shareholders was €1.247 billion, and cash flow from operations before working capital was €3.297 billion, with net cash from operations at €3.078 billion. Leverage before lease liabilities was 0.19, with proforma leverage cited at 12% including pending transactions.

2025 outlook improved. Eni lifted its 2025 share buyback by €0.3 billion to €1.8 billion and increased full‑year CFFO guidance to €12 billion. The company raised production guidance to 1.71–1.72 million boe/d and expects GGP proforma adjusted EBIT above €1 billion, while reiterating gross capex below €8.5 billion and year‑end installed renewables of 5.5 GW.

Positive

• Buyback increased by €0.3 bln to €1.8 bln for FY25 (up 20%)
• Q3 cash generation: CFFO before working capital €3.297 bln; net cash from ops €3.078 bln
• Production up 6% to 1.76 mln boe/d, supporting raised FY guidance
• Balance sheet strength: leverage before leases 0.19; proforma leverage 12%

Negative

• None.

Insights

Energy equity analyst

Higher buyback and strong Q3 cash support a shareholder-friendly year.

Eni combined volume growth with cost discipline: Q3 proforma adjusted EBIT was €2.996 bln and adjusted net profit attributable to shareholders was €1.247 bln. Cash flow from operations before working capital reached €3.297 bln, comfortably covering quarterly gross capex of €2.017 bln.

The Board approved a €0.26 per‑share dividend tranche and raised the 2025 buyback by €0.3 bln to €1.8 bln, while leverage before leases stood at 0.19 and proforma leverage at 12%. Upstream delivered +6% production to 1.76 mln boe/d, offsetting weaker crude and FX headwinds.

Guidance increased: FY25 CFFO to €12 bln and production to 1.71–1.72 mln boe/d. Near‑term dated items include the dividend payment on Nov 26, 2025 and ADR payment on Dec 5, 2025. Actual outcomes will hinge on commodity prices, FX, and execution of announced portfolio actions.

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 October 2025

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 second tranche of the provision in place of 2025 dividend: € 0.26 per share
·	Eni: results for the third quarter and nine months of 2025

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: October 24, 2025

Eni’s Board of Directors

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

Rome, 23 October 2025 – Eni’s Board of Directors, chaired by Giuseppe Zafarana, today resolved to distribute to Shareholders the second 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 24 November 2025², payable on 26 November 2025³, as resolved by the Shareholders’ Meeting of 14 May 2025.

Holders of ADRs, outstanding at the record date of 25 November 2025, will receive € 0.52 per ADR, payable on 5 December 2025⁴, 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. 52.

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 25 November 2025 (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 third quarter and nine months of 2025

	·	Strong execution within a clear strategic framework delivered excellent 3Q ‘25 performance combining top line growth and focused cost efficiencies. As a result, Eni is again revising upwards its FY outlook for cash generation despite an unsupportive commodity and currency scenario.
	·	The FY25 share buyback is raised by €0.3 bln, 20% higher, to €1.8 bln, taking into account the healthy financial position with proforma leverage remaining around historic lows, benefiting from an expected €4 bln in cash initiatives, 30% higher than previously targeted.
	·	This has been a notable quarter for our industry leading Upstream, which included:

	o	reported 6% y-o-y production growth as 2024 valorization effects began to roll-off;
	o	reached the FID to develop the Coral North FLNG project off Mozambique;
	o	closed the sale of a 30% stake in Baleine oilfield offshore Côte d’Ivoire;
	o	made significant progress towards our fourth and largest E&P satellite built around Indonesian portfolio and focused on Asian LNG, on track to be finalized by 2025 YE in combination with Petronas.

· The development of our transition related strategy continues alongside our traditional businesses:

	o	we began actions to upgrade the hubs of Brindisi, Sannazzaro and Priolo;
	o	we are nearing completion of a 20% investment by Ares Fund in Plenitude for €2 bln;
	o	a new satellite is being set up with GIP to enhance and unlock value from our CCUS business.

Rome, October 24, 2025 - Eni's Board of Directors, chaired by Giuseppe Zafarana, yesterday approved the unaudited consolidated results for the third quarter and nine months of 2025. Eni CEO Claudio Descalzi said:

“In the third quarter all the main operational and economic and financial metrics exceeded expectations. Strong production growth to 1.76 mln barrels/day (+6% compared to last year) allows us to raise our annual guidance towards 1.72 mln barrels/day, confirming the acceleration trend continuing in the coming months thanks to the new fields under development in Congo, UAE, Qatar and Libya, and the start of the business combination in Indonesia and Malaysia which will create one of the main players on the LNG market in the Asian continent. The enhancement of our portfolio continues with the completion of the sale of 30% of the Baleine field in Côte d’Ivoire, according to the well-established dual exploration model, and with the progress of the process of selling 20% of the share of Plenitude to the Ares fund, for which all the conditions precedent have been completed. In the last two years with Enilive and Plenitude valorization we cashed in around €6.5 bln. The execution of the transition strategy also proceeds in line with plan: the upgrade of the Sannazzaro hub and the conversion of Priolo mark new biorefining development projects and contribute to the transformation of our downstream; at the same time, Plenitude has reached 4.8 GW of installed renewable capacity, in line with the target of 5.5 GW by the end of the year. In addition, the partnership with GIP has been launched to maximize the growth potential of the CCUS business in our portfolio. In a context of weaker oil prices and a strengthening euro, the economic and financial performance confirms the effectiveness of our strategy and satellite model, which allows us to ensure accelerated growth and stable dividends. Proforma EBIT was robust at €3 bln, while net profit at €1.2 bln was +20% higher than expectations. Equally significant was the cash performance with a CFFO of €3.3 bln. Proforma leverage stands at 12%, a level that remains at our historic lows, and with a year-end outlook of 15-18%. Against the backdrop of weaker prices, we are the only company in the peer group that, thanks to the increase in operating cash estimates and stronger results, is able to increase distribution with a larger buyback of €300 mln to €1.8 bln, reducing at the same time net borrowings. Essentially, Q3 represents all the major elements of our distinctive strategy in action in one place: we are competitively growing our key businesses; we are launching new projects while also securing further opportunities through our industry-leading exploration and technological know-how in the upstream; and opening up new opportunities in the Transition. Meanwhile we are managing risk/reward - realizing value through our Dual Exploration and Satellite strategies allowing us to bring down debt and share upside with shareholders.”

Key operating and financial results

Q2			Q3				Nine months
2025			2025	2024	% Ch.		2025	2024	% Ch.
1,668	Hydrocarbon production	kboe/d	1,756	1,661	6		1,691	1,704	(1)
4.5	Installed capacity from renewables at period end	GW	4.8	3.1	55		4.8	3.1	55
2,681	Proforma adjusted EBIT (a)	€ million	2,996	3,400	(12)		9,358	11,623	(19)
1,889	subsidiaries		2,073	2,442	(15)		6,562	8,654	(24)
792	main JV/Associates (b)		923	958	(4)		2,796	2,969	(6)
	Proforma adjusted EBIT (by segment) (a)
2,422	E&P		2,638	3,259	(19)		8,368	10,242	(18)
387	Global Gas & LNG Portfolio (GGP) and Power		346	286	21		1,206	995	21
262	Enilive and Plenitude		331	306	8		929	1,010	(8)
(193)	Refining and Chemicals		(53)	(192)	72		(580)	(438)	(32)
(197)	Corporate, other activities and consolidation adjustments		(266)	(259)			(565)	(186)
2,200	Adjusted net profit before taxes (a)		2,273	2,656	(14)		7,222	9,200	(22)
1,134	Adjusted net profit (loss) (a)(c)		1,247	1,271	(2)		3,793	4,372	(13)
543	Net profit (loss) (c)		803	522	54		2,518	2,394	5
2,775	Cash flow from operations before changes in working capital at replacement cost (a)		3,297	2,898	14		9,486	10,701	(11)
3,517	Net cash from operations		3,078	2,997	3		8,980	9,472	(5)
2,029	Organic capital expenditure (d)		1,990	1,995	(0)		5,904	6,111	(3)
10,198	Net borrowings before lease liabilities ex IFRS 16		9,931	11,627	(15)		9,931	11,627	(15)
53,405	Shareholders' equity including non-controlling interest		52,966	53,478	(1)		52,966	53,478	(1)
0.19	Leverage before lease liabilities ex IFRS 16		0.19	0.22			0.19	0.22

(a) Non-GAAP measures. For further information see the paragraph "Non-GAAP measures" on pages 18 and subsequent.

(b) The main JV/associates are listed in the "Reconciliation of Group proforma adjusted EBIT" on page 24.

(c) Attributable to Eni's shareholders.

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

1

Strategic and financial highlights

Accretive oil&gas production growth and excellent base performance underpinned strong E&P results in 3Q ‘25.

	·	3Q ‘25 oil&gas production growth rose significantly, up 6% y-o-y and 5% sequentially to 1.76 mln boe/d, thanks to accelerated and smooth start-ups and ramp-ups, strong operational continuity and optimized turnaround activity.
	·	FID to develop the major Coral North FLNG project offshore Mozambique was reached. Completion is expected in just three years, leveraging our fast-track approach and successful experience on Coral South, to bring on the market 3.6 MTPA of production capacity.
	·	The sail away of the Nguya FLNG marks a decisive step towards the start of Ph. 2 of the Congo LNG project, expected by 2025 YE with a target plateau of 3 MTPA, from the current 0.6 MTPA.
	·	The quarter was especially notable for the contribution coming from our upstream satellites. Azule Energy, our 50%-owned satellite in Angola, began production at the operated Agogo West Hub project, 10 months ahead of schedule. First gas at the operated NGC project is also imminent. Meanwhile Vår Energi, our 63%-owned satellite in Norway, reached 400 kboe/d in 3Q ‘25, a quarter ahead of schedule, benefiting from the fast ramp-ups at Johan Castberg and the operated Balder X fields. Our UK-focused satellite, Ithaca Energy (Eni 36%), has almost doubled its share price since its inception, and raised production guidance via value accretive bolt on acquisitions and top tier operational performance.
	·	A fourth upstream satellite, our largest to date, combining Eni's and Petronas' activities in Indonesia/Malaysia, is on track to be finalized by 2025 YE. It represents significant value creation and growth potential, with a particular focus on Asian LNG markets.
	·	Eni and YPF have signed an agreement on the next required steps to reach final investment decision in the large-scale integrated upstream/midstream Argentina LNG project developing the vast Vaca Muerta resources, entailing a phased approach to export up to 30 mln tons/y of LNG in the long-term.

Significant growth ahead for our transition-related satellites; progressing the transformation of Versalis

	·	With the regulatory approval of the reconversion plan of the Sannazzaro hub, Eni and Enilive are currently engaged in four ongoing projects (in Livorno and in South Korea/Malaysia) to materially expand biofuels manufacturing capacity.
	·	Plenitude's installed renewable capacity has reached 4.8 GW and is on track to achieve the year-end target of 5.5 GW. The customer base will also be enlarged and strengthened through the pending acquisition of Acea Energia.
	·	As a result of Versalis cracking plant closure in Brindisi, started the process to convert the site into a static battery manufacturing in JV with Seri Industrial. Started also a project to convert the Priolo hub to the production of biofuels and recycled plastics.

Dual Exploration model and aligned investment into our transition-related satellites catalyzes value generation

	·	Closed the divestment of 30% of the Baleine oilfield off Côte d’Ivoire, with proceeds of €1 bln.
	·	Agreed the creation of a JV satellite with GIP to develop and valorize our CCUS business.
	·	Progressed to near completion a 20% investment by Ares Fund into Plenitude for €2 bln.

Growth and cost and financial discipline mitigated a weaker scenario driving excellent 3Q ‘25 financial results, attractive shareholder returns and maintaining a strong balance sheet position

	·	3Q ‘25 Group proforma adjusted EBIT was robust at €3 bln, despite a 14% decline in crude oil prices and a 6% appreciation in the EUR/USD rate y-o-y, with these negative impacts partly offset by volume growth and cost efficiencies. The Group reported an adjusted net profit of €1.2 bln, with a Group tax rate of 42%.
	-	E&P generated €2.64 bln of proforma adjusted EBIT (down 19% y-o-y, but up about 9% sequentially), 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 €0.35 bln (up 21% y-o-y) driven by continued value maximization from gas portfolio optimization.
	-	Enilive generated €0.23 bln of proforma adjusted EBIT (€0.32 bln EBITDA), 35% higher than 3Q ’24, driven by recovery in bio-margins. Plenitude reported a proforma adjusted EBIT of €0.10 bln (€0.22 bln EBITDA), lower than the quarter 2024.
	-	Refining reverted to profit (€0.14 bln vs breakeven in the comparative quarters) due to improved product crack spreads and higher plant utilization rates. The Chemical business reported a loss of €0.19 bln, impacted by the prolonged downturn in the European sector but beginning to show some improvement through the early effects of the restructuring plan.
	-	Adjusted cash flow before working capital was €3.3 bln, well above gross capex of €2 bln, and was 14% higher y-o-y despite the challenging scenario. The resulting organic free cash flow of €1.3 bln was helped by cash-ins due to several initiatives addressing working capital with overall cash initiatives having delivered a €2.1 bln benefit, year-to-date. Together with proceeds from the portfolio management of around €1.1 bln, mainly relating to the sale of a 30% stake in the Baleine asset plus other non-strategic fields in Congo, this funded €1.3 bln of cash returns to shareholders, comprising the first instalment of the 2025 dividend for €0.78 bln and share repurchases of €0.56 bln as part of the 2025 buy-back program. Net borrowings declined to €9.9 bln from June 30, 2025. This left leverage at 19%, and incorporating agreed but not completed portfolio transactions, proforma leverage at quarter-end was 12%.

2

Outlook 2025

Eni is raising its 2025 share buy-back commitment by €0.3 bln to €1.8 bln thanks to outstanding strategic progress and an improved FY ‘25 CFFO outlook, which we are upgrading for the second time this year despite the headwinds of lower commodity prices and a weaker USD.

Specifically on our financial and operating guidance we are:

• Raising the Group’s expected CFFO before working capital adjustments to €12 bln from the previous €11.5 bln, under our latest scenario¹. This represents a €1.3 bln underlying improvement on the original Plan guidance.

• Raising our expected oil and gas production guidance for 2025 to a 1.71-1.72 mln boe/d range, implying a Q4 level of around 1.8 mln boe/d.

• Raising guidance on GGP’s proforma adjusted EBIT to above €1 bln thanks to better portfolio optimizations.

• Raising to around €4 bln from the previous €3 bln the cash initiatives and other self-help measures aimed at mitigating the scenario effects.

In addition, we:

• Confirm FY gross capex expected below €8.5 bln, down from an initial guidance of below €9 bln; net capex is seen below €5 bln from an initial guidance of €6.5-7 bln.

• Confirm Enilive and Plenitude outlook: FY proforma adjusted EBITDA respectively of around €1 bln and above €1.1 bln;

• Project end of year installed renewable capacity at 5.5 GW (Plenitude @100%); biorefinery capacity at 1.65 MTPA plus 1 MTPA under construction.

Robust balance sheet and leverage continue to be expected within the Plan stated range.

• Proforma leverage at year-end expected in a 0.15 - 0.18 range.

Raising shareholders returns for 2025 compared to the original plan, featuring now the execution of a buy-back program of at least €1.8 bln a 20% increase over the CMU guidance, on top of an already announced 5% dividend increase to €1.05 per share for FY 25.

• The second tranche of the 2025 dividend of €0.26 per share is set to be paid on November 26, 2025 (record date November 25).

¹ 3Q ‘25 outlook was based on the following assumptions for the FY ’25: Brent price at 70 $/bbl (same as in 2Q outlook), TTF spot gas price at €36/MWh, SERM refining margin at 5.8 $/bbl (higher than the 2Q assumption of 4 $/bbl), EUR/USD exch. rate at 1.13, worse than the previous outlook at 1.1.

3

Business segments: operating and financial results

Exploration & Production

Production and prices

Q2			Q3			Nine months
2025			2025	2024	% Ch.	2025	2024	% Ch.
67.82	Brent dated	$/bbl	69.07	80.18	(14)	70.85	82.79	(14)
1.134	Average EUR/USD exchange rate		1.168	1.098	6	1.119	1.087	3
1,668	Hydrocarbons production	kboe/d	1,756	1,661	6	1,691	1,704	(1)
825	Liquids	kbbl/d	860	775	11	824	783	5
4,415	Natural gas	mmcf/d	4,687	4,638	2	4,535	4,821	(7)
50.81	Average realizations (a)	$/boe	52.07	55.95	(7)	52.68	55.74	(5)
62.77	Liquids	$/bbl	64.00	73.88	(13)	65.43	75.27	(13)
7.14	Natural gas	$/kcf	7.40	7.34	1	7.37	7.21	2

(a) Prices related to consolidated subsidiaries.

	•	In Q3 ’25, hydrocarbon production averaged 1.76 mln boe/d, up by 6% compared to the previous year (1.69 mln boe/d in the nine months ’25, down by 1%). Excellent project development performance drove production ramp-ups in Côte d'Ivoire, Congo, Mexico. These were supplemented by project start-ups at our satellites in Angola/Norway and supported by strong operational continuity and optimized turnaround activity in our base. Offsetting these effects were mature fields declines and high-grading asset divestments closed in 2024 in Nigeria, Alaska, and Congo. Underlying year-on-year production growth was 8.5%. Sequentially, hydrocarbon production increased by 5% compared to Q2 ‘25 thanks to the ramp-ups of organic projects in Norway, Indonesia, Mexico and Angola.
	•	Liquids production was 860 kbbl/d in Q3 ’25, up by 11% compared to Q3 ’24 (824 kbbl/d in the nine months ’25, up by 5%). The organic growth in Côte d'Ivoire due to the start of Baleine Phase 2, Mexico and Norway were offset by divestments and mature fields declines.
	•	Natural gas production was 4,687 mmcf/d, up by 2% compared to Q3 ’24 (4,535 mmcf/d in the nine months ’25, down 7%). Organic growth in Congo (Marine XII), Italy (ramp-up of Argo/Cassiopea) and Indonesia (Merakes East) as well as at our satellites in Angola/Norway was partly offset by the divestments and mature fields decline.

Results

Q2		Q3			Nine months
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
4,701	Upstream turnover	4,616	5,703	(19)	14,723	17,637	(17)
2,422	Proforma adjusted EBIT	2,638	3,259	(19)	8,368	10,242	(18)
763	of which: main JV/Associates	838	933	(10)	2,679	2,818	(5)
1,495	Operating profit (loss) of subsidiaries	1,670	2,264	(26)	5,116	6,009	(15)
164	Exclusion of special items	130	62		573	1,415
1,659	Adjusted operating profit (loss) of subsidiaries	1,800	2,326	(23)	5,689	7,424	(23)
1,957	Adjusted profit (loss) before taxes	2,015	2,552	(21)	6,428	8,028	(20)
45.9	tax rate (%)	41.7	49.6		44.8	52.8
1,059	Adjusted net profit (loss)	1,175	1,286	(9)	3,547	3,791	(6)
42	Exploration expenses:	45	113	(60)	131	299	(56)
42	prospecting, geological and geophysical expenses	36	54	(33)	122	135	(10)
	write-off of unsuccessful wells	9	59	(85)	9	164	(95)
1,336	Capital expenditure	1,535	1,384	11	4,310	4,270	1

Q2			Q3			Nine months
2025	Main JV/Associates		2025	2024	% Ch.	2025	2024	% Ch.
763	Adjusted operating profit (Eni's share)	(€ million)	838	933	(10)	2,679	2,818	(5)
412	of which: Vår Energi		479	602	(20)	1,488	1,794	(17)
218	Azule		204	247	(17)	654	818	(20)
167	Adjusted net profit		299	279	7	794	833	(5)
330	Total dividends		306	91	..	903	857	5
432	Hydrocarbon production	(kboe/d)	493	380	30	452	388	16

• In Q3 ’25, Exploration & Production reported a proforma adjusted EBIT of €2,638 mln, down by 19% vs. Q3 ’24 due to lower liquids realizations affected by a decrease in crude oil prices in USD (the Brent marker was down by 14%) as well as the appreciation of the EUR/USD exchange rate (up by 6%) which reduced the operating profits of dollar-denominated subsidiaries. These decreases were partly offset by production growth, positive mix effects due to higher contribution of

4

low breakeven projects following portfolio rationalization and self-help initiatives. In the nine months ’25, proforma adjusted EBIT was €8,368 mln, down 18% compared to the nine months ’24, due to the same drivers as for the Q3.

• In Q3 ’25, the segment reported an adjusted net profit of €1,175 mln, decreasing by 9% compared to Q3 ’24 and includes the contribution from JVs and associates, in particular Vår Energi, Azule Energy and Ithaca Energy. Adjusted net profit was €3,547 mln in the nine months ’25, a decrease of 6% y-o-y.

• In Q3 ’25 the tax rate was around 42% (45% in the nine months ’25) decreasing by approximately 8 percentage points compared to the comparative periods of 2024 mainly driven by a more favorable geographical mix of pretax profit.

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

Strategic developments

• In 2025-to-date, resource additions from exploration activity total about 800 mln boe, extending a more than 10 year run 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. Azule Energy also announced a discovery on Angola’s first dedicated gas exploration well, Gajajeira-01. In 2025 near field discoveries were successfully tested in the UK (through Eni’s 36% owned associate Ithaca Energy) or made in Norway (via Eni’s 63% owned associate Vår Energi) and in Côte d'Ivoire. In Q4 ’25 significant exploration activities are expected, most notably in Angola, Côte d'Ivoire, Libya and Indonesia.

• In July, Eni signed a petroleum contract with Sonatrach for the exploration and development of the Zemoul El Kbar area. The contract, with a duration of 30 years, covers a development and exploration area of about 4,200 sq Km and includes neighboring assets previously under separate contracts. This new agreement follows the recent award, in the context of 2024 Algeria Bid Round, of the Reggane II block to Eni in partnership with PTTEP.

• In August, production started at the Agogo Integrated West Hub project, operated by the JV Azule Energy in block 15/06, offshore Angola. Agogo IWH involves the development of two fields, Agogo and Ndungu, with combined reserves of approximately 450 mln barrels and an expected production plateau of 180 kboe/d.

• In August, the Nguya floating liquefied natural gas (FLNG) unit sailed away, and it is set to significantly boost LNG production as part of Phase 2 of the Congo LNG project in the Marine XII concession, offshore the Republic of Congo. The FLNG was designed and built in only 33 months, from contract award to sail away, setting a record for time-to-market in the entire sector and will increase production capacity to 3 MTPA of LNG (from current 0.6 MTPA).

• In September, Eni and its Offshore Cape Three Points (OCTP) project partners, Vitol and the Ghana National Petroleum Corporation (GNPC), signed a Memorandum of Intent with the Government of Ghana, finalized to the country’s oil and gas production increase and new sustainable initiatives. The collaboration focuses also on the evaluation of exploration activities and the new potential development of the Eban-Akoma field in the Cape Three Points Block 4.

• In September, Eni finalized the sale of a 30% stake in the Baleine project in Côte d’Ivoire, to Vitol. The Baleine project is the country’s main offshore development and is owned by Eni (47.25%), Vitol (30%) and Petroci (22.75%). The transaction is in line with Eni's strategy of optimizing its upstream portfolio by accelerating the monetization of exploration discoveries through the divestment of equity stakes.

• 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 to develop the Coral North FLNG project 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-up in just three years.

• In October, Eni and the Argentina YPF signed the Final Technical Project Description (FTPD), a significant step towards the Final Investment Decision 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.

5

Global Gas & LNG Portfolio and Power

Sales and production

Q2			Q3			Nine months
2025			2025	2024	% Ch.	2025	2024	% Ch.
	Global Gas & LNG Portfolio
38	Spot Gas price at Italian PSV	€/MWh	36	38	(7)	41	34	21
35	TTF		32	35	(8)	38	31	21
3	Spread PSV vs. TTF		3	3	13	3	2	17
	Natural gas sales	bcm
4.49	Italy		4.26	5.09	(16)	14.70	17.73	(17)
3.86	Rest of Europe		3.72	4.92	(24)	12.79	15.62	(18)
0.28	Importers in Italy		0.09	0.16	(44)	0.59	0.95	(38)
3.58	European markets		3.63	4.76	(24)	12.20	14.67	(17)
0.66	Rest of World		1.20	0.78	54	2.82	2.27	24
9.01	Worldwide gas sales (a)		9.18	10.79	(15)	30.31	35.62	(15)
2.8	LNG sales		3.3	2.2	50	8.9	7.1	25
	Power
4.53	Thermoelectric production	TWh	4.83	5.33	(9)	14.77	14.56	1

(a) Data include intercompany sales.

• In Q3 ’25, natural gas sales were 9.18 bcm, a decrease of 15% from the comparative period due to lower volumes sold in the wholesales segment in Italy. Sales in the European market (3.63 bcm, down by 24% vs. Q3 ’24) decreased following lower sales in Turkey and Germany, partly balanced by higher sales mainly in France, the UK and the Iberian Peninsula. In the nine months ’25, natural gas sales amounted to 30.31 bcm, down by 15% vs the nine months ‘24, mainly due to lower gas volumes marketed in Italy (down by 17% or 3.03 bcm vs. the nine months ’24) and in the European markets (down by 17% or 2.47 bcm vs. the nine months ’24), in particular in Turkey.

• Thermoelectric production amounted to 4.83 TWh in Q3 ’25, down by 9% vs. Q3 ’24 with a lower plant utilization rate. In the nine months ‘25, production reported a slight increase of 1% compared to the same period in 2024, in order to seize market opportunities (14.77 TWh in the nine months ’25 vs. 14.56 TWh in the nine months ’24).

Results

Q2		Q3			Nine months
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
3,444	Sales from operations	3,503	4,227	(17)	12,537	12,691	(1)
387	Proforma adjusted EBIT	346	286	21	1,206	995	21
321	GGP	279	253	10	910	912	-
9	of which: main JV/Associates	4	8	(50)	23	31	(26)
66	Power	67	33	..	296	83	..
585	Operating profit (loss) of subsidiaries	227	(95)	..	1,585	(779)	..
(207)	Exclusion of special items	115	373		(402)	1,743
378	Adjusted operating profit (loss) of subsidiaries	342	278	23	1,183	964	23
382	Adjusted profit (loss) before taxes	348	286	22	1,200	995	21
38.5	tax rate (%)	37.9	40.2		36.8	40.1
235	Adjusted net profit (loss)	216	171	26	758	596	27
25	Capital expenditure	14	22	(36)	51	67	(24)

• In Q3 ’25, the Global Gas & LNG Portfolio business achieved a proforma adjusted EBIT of €279 mln an increase of 10% from the comparative period, driven by continuing value maximization from the gas portfolio optimization. In the nine months ’25, proforma adjusted EBIT amounted to €910 mln, in line with the nine months ’24, also benefitting from income relating to renegotiations and settlements.

• In Q3 ’25, the Power generation business reported a proforma adjusted EBIT of €67 mln, up by €34 mln from the same quarter of 2024, mainly due to a one-off gain relating to a contractual renegotiation. In the nine months ‘25, proforma adjusted EBIT was €296 mln, up by €213 mln compared to the nine months ’24 due to the same drivers as for the Q3 ‘25.

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

Strategic developments

• In July, Eni signed a long-term liquefied natural gas (LNG) supply agreement with Venture Global for the purchase of 2 MTPA for 20 years from 2030 as part of Venture Global’s Phase 1 of CP 2 LNG project, under development. The agreement is Eni’s first long term LNG supply from the USA and represents a milestone in Eni’s strategy to expand and diversify its global LNG footprint, enhancing portfolio flexibility in order to reach its target of 20 MTPA of contracted LNG supply by 2030.

• In September, Eni signed a 3- years deal with Botas for the sale of total 1.5 bcm of LNG to Turkey.

6

Enilive and Plenitude

Enilive

Q2			Q3			Nine months
2025			2025	2024	% Ch.	2025	2024	% Ch.
	Enilive
852	Spread EU HVO UCO-based vs UCO	$/tonnes	1,143	613	86	899	671	34
444	Spread US RD(a) UCO-based vs UCO		420	758	(45)	449	892	(50)
274	Bio throughputs	ktonnes	315	277	14	881	952	(7)
74	Average bio refineries utilization rate	%	85	74	15	79	85	(7)
5.38	Total Enilive sales	mmtonnes	5.75	6.12	(6)	16.41	17.93	(8)
1.97	Retail sales		2.10	2.07	1	5.85	5.75	2
1.40	of which: Italy		1.49	1.43	4	4.14	4.03	3
2.83	Wholesale sales		3.21	3.44	(7)	8.92	10.40	(14)
2.09	of which: Italy		2.42	2.64	(8)	6.78	7.98	(15)
0.58	Other sales		0.44	0.61	(28)	1.64	1.78	(8)

(a) Renewable Diesel.

• In Q3 ’25, bio throughputs were 0.32 mmtonnes, up by 14% y-o-y, mainly due to higher volumes processed at the Gela and Chalmette biorefineries following maintenance activities occurred in Q3 ‘24. In the nine months ‘25, bio throughputs were 0.88 mmtonnes, decreasing by 7% compared to the same period of 2024, following maintenance shutdowns occurred in the first half of the year.

• In Q3 ’25, retail sales were 2.10 mmtonnes, a slight increase vs Q3 ‘24, due to the higher sales marketed in Italy, particularly gasoline and diesel. In the nine months ‘25, retail sales amounted to 5.85 mmtonnes, up by 2% vs. the nine months ‘24, following the same driver of the quarter.

• In Q3 ’25, wholesale sales were 3.21 mmtonnes, a reduction of 7% y-o-y mainly following lower product availability in specific geographical areas in Italy. A decline in sales was also recorded in the nine months ‘25 with 8.92 mmtonnes: down by 14% vs. the nine months ‘24.

Q2		Q3			Nine months
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
4,779	Sales from operations	5,206	5,476	(5)	14,742	16,215	(9)
209	Proforma adjusted EBITDA	317	252	26	698	716	(3)
129	Proforma adjusted EBIT	233	173	35	457	486	(6)
(9)	of which: main JV/Associates	(8)	(18)	56	(32)	(32)
53	Operating profit (loss) of subsidiaries	219	49	347	393	361	9
61	Exclusion of inventory holding (gains) losses	(8)	114		34	121
24	Exclusion of special items	30	28		62	36
138	Adjusted operating profit (loss) of subsidiaries	241	191	26	489	518	(6)
126	Adjusted profit (loss) before taxes	225	167	35	438	467	(6)
76	Adjusted net profit (loss)	163	116	41	304	317	(4)
176	Cash flow from operations before changes in working capital at replacement cost	283	17	1,565	608	450	35
(1,264)	Net borrowings	(1,338)	(684)	(96)	(1,338)	(684)	(96)
68	Capital expenditure	98	100	(2)	199	224	(11)

• In Q3 ’25 Enilive reported a proforma adjusted EBIT of €233 mln, representing a better performance compared to the same period in 2024, up by 35% (€457 mln in the nine months ’25, compared to €486 mln in the nine months ’24, down by 6%): the positive performance is primarily attributable to the strong results achieved by our biorefineries, both in EU and US.

• Proforma adjusted EBITDA amounted to €317 mln, increasing by 26% compared to the Q3 ’24 (€252 mln). In the nine months ’25, Enilive reported a proforma adjusted EBITDA of €698 mln, compared to a profit of €716 mln in the nine months ’24 (down by 3%).

Strategic developments

• In July, Eni signed with the European Investment Bank (EIB) a €500 mln 15-year finance contract to support the conversion of Eni's Livorno refinery in Tuscany into a biorefinery. Eni's project involves the construction of new plants to produce hydrogenated biofuels at the Livorno refinery site, including a biogenic pre-treatment unit and a 500 ktonnes/year Ecofining™ plant.

• In August, LG-Eni BioRefining, the LG Chem and Enilive joint venture, started construction works for the South Korea’s first hydrotreated vegetable oil (HVO) and Sustainable Aviation Fuel (SAF) production plant in Seoul. The plant is

7

scheduled for completion in 2027 and will annually process approximately 400 ktonnes of renewable bio-feedstock.

• In September, Eni started the authorization process to convert selected units at the Sannazzaro de’ Burgondi (Pavia) refinery into a biorefinery. The project is intended to convert the existing Hydrocracker (HDC2) unit, using Ecofining™ technology and constructing a pre-treatment unit for waste and residues, used by Enilive to produce HVO biofuels. The new biorefinery will have a processing capacity of 550 ktonnes/year, with flexibility to produce SAF-biojet and HVO diesel.

Plenitude

Q2			Q3			Nine months
2025			2025	2024	% Ch.	2025	2024	% Ch.
	Plenitude
102	Italian PUN Index GME	€/MWh	110	119	(8)	117	102	14
10.0	Retail and business customers at period end	mln pod	9.9	10.0	(1)	9.9	10.0	(1)
0.68	Retail and business gas sales to end customers	bcm	0.47	0.49	(5)	3.54	3.78	(6)
4.09	Retail and business power sales to end customers	TWh	4.84	4.88	(1)	13.83	13.66	1
4.5	Installed capacity from renewables at period end	GW	4.8	3.1	55	4.8	3.1	55
1.5	Energy production from renewable sources	TWh	1.6	1.2	35	4.3	3.5	23
21.8	EV charging points at period end	thousand	22.1	21.0	5	22.1	21.0	5

• As of September 30, 2025, retail and business customers were around 10 mln (gas and electricity), a slight decrease compared to September 30, 2024.

• Retail and business gas sales to end customers amounted to 0.47 bcm in Q3 ’25, with a 5% decrease compared to the same period of 2024, mainly reflecting the change in the customer base. In the nine months ‘25, gas sales amounted to 3.54 bcm, decreasing by 6% vs. the comparative period, mainly in Italy due to lower customer base.

• Retail and business power sales to end customers were 4.84 TWh in Q3 ’25, substantially in line compared to Q3 ’24. In the nine months ’25 power sales amounted to 13.83 TWh, benefitting from increasing customer portfolio in the domestic business segment.

• As of September 30, 2025, the installed capacity from renewables was 4.8 GW reflecting the organic development in Spain, the USA, the UK and Italy and the acquisitions in the USA, Spain and Germany.

• Energy production from renewable sources was 1.6 TWh in Q3 ’25, up by 35% year-on-year, mainly thanks to the start-up of organic projects and the contribution from acquired assets (4.3 TWh in the nine months ’25, +23% year-on-year).

• As of September 30, 2025, EV charging points amounted to 22.1 thousand, up by 5% compared to 21 thousand as of September 30, 2024, thanks to network development.

Q2		Q3			Nine months
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
1,885	Sales from operations	1,818	1,987	(9)	7,421	7,194	3
256	Proforma adjusted EBITDA	221	244	(9)	835	853	(2)
133	Proforma adjusted EBIT	98	133	(26)	472	524	(10)
30	Operating profit (loss) of subsidiaries	23	158	(85)	87	992	(91)
94	Exclusion of special items	69	(24)		371	(459)
124	Adjusted operating profit (loss) of subsidiaries	92	134	(31)	458	533	(14)
107	Adjusted profit (loss) before taxes	84	117	(28)	420	481	(13)
68	Adjusted net profit (loss)	53	70	(24)	276	312	(12)
217	Cash flow from operations before changes in working capital at replacement cost	163	247	(34)	743	773	(4)
2,061	Net borrowings	1,967	1,756	12	1,967	1,756	12
196	Capital expenditure	190	190		530	671	(21)

• In Q3 ’25 Plenitude reported a proforma adjusted EBIT of €98 mln, down by 26% from the same period of 2024, reflecting lower results on retail business (mainly related to energy efficiency solutions) partly balanced by the ramp-up in renewable installed capacity and related production volumes. In the nine months ’25 Plenitude reported a proforma adjusted EBIT of €472 mln, a 10% reduction compared to a proforma adjusted EBIT of €524 mln in the nine months ’24.

• In Q3 ’25, proforma adjusted EBITDA amounted to €221 mln, down by 9% vs Q3 ’24. In the nine months ’25, Plenitude reported a proforma adjusted EBITDA of €835 mln, down by 2% compared to the nine months ’24 (€853 mln).

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

8

Strategic developments

• In September, GreenIT, the Italian joint venture between Plenitude and CDP Equity (CDP Group), obtained a funding of €370 mln for renewable energy projects, by the European Investment Bank and leading European financial institutions.

• In September, Plenitude started the 50 MW Solar Power Plant in Kazakhstan. The plant is a part of an innovative project led by Eni and KazMunayGas (KMG), the first large-scale of its kind, for the realization of a 247 MW Hybrid Power Plant which integrates solar, wind and gas power generation.

• In October, Plenitude signed with A.N.FI.R (Associazione Nazionale delle Finanziarie Regionali) a Framework Agreement for the construction of plants for renewable energy production.

Refining and Chemicals

Production and sales

Q2			Q3			Nine months
2025			2025	2024	% Ch.	2025	2024	% Ch.
	Refining
4.8	Standard Eni Refining Margin (SERM)	$/bbl	8.9	1.7	..	5.8	5.6	4
3.73	Throughputs in Italy on own account	mmtonnes	3.81	3.29	16	10.88	10.46	4
2.65	Throughputs in the rest of World on own account		2.79	2.68	4	7.95	7.71	3
6.38	Total throughputs on own account		6.60	5.97	11	18.83	18.17	4
84	Average refineries utilization rate	%	84	78		81	78
	Chemicals
0.72	Sales of chemical products	mmtonnes	0.59	0.81	(28)	2.10	2.43	(13)
47	Average plant utilization rate	%	47	52	(10)	50	52	(4)

Refining

• In Q3 ’25, the Standard Eni Refining Margin averaged 8.9 $/barrel vs. 1.7 $/barrel in the comparative period mainly due to more favorable product crack spreads leveraged by a number of plant shutdowns worldwide, notwithstanding a weak demand (5.8 $/barrel in the nine months ‘25, representing a slight increase vs. 5.6 $/barrel reported in the nine months ’24).

• In Q3 ’25, throughputs on own accounts at Eni’s refineries in Italy were 3.81 mmtonnes, up by 16% y-o-y reflecting higher volumes processed at the Sannazzaro and Milazzo refineries, due to lower shutdowns. Throughputs outside Italy increased by 4% compared to Q3 ’24, following higher volumes processed by ADNOC Refineries. In the nine months ’25, throughputs in Italy and in the rest of World reported an increase of 4% and 3% respectively, compared to the same period of 2024.

Chemicals

• Sales of chemical products were 0.59 mmtonnes in Q3 ’25, a 28% decrease y-o-y due to lower demand and plant shutdown. In the nine months ‘25, sales amounted to 2.10 mmtonnes, representing a decrease of 13% from the comparative period.

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

9

Results

Q2		Q3			Nine months
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
4,533	Sales from operations	4,545	5,333	(15)	14,010	16,524	(15)
(193)	Proforma adjusted EBIT	(53)	(192)	72	(580)	(438)	(32)
(9)	Refining	135	1	..	35	145	(76)
20	of which: main JV/Associates	83	36	..	112	161	(30)
(184)	Chemicals	(188)	(193)	3	(615)	(583)	(5)
(843)	Operating profit (loss) of subsidiaries	(291)	(908)	68	(1,593)	(1,081)	(47)
396	Exclusion of inventory holding (gains) losses	69	479		496	254
234	Exclusion of special items	86	201		405	228
(213)	Adjusted operating profit (loss) of subsidiaries	(136)	(228)	40	(692)	(599)	(16)
(207)	Adjusted profit (loss) before taxes	(58)	(207)	72	(608)	(469)	(30)
(197)	Adjusted net profit (loss)	(74)	(158)	53	(581)	(342)	(70)
175	Capital expenditure	142	163	(13)	430	453	(5)

· In Q3 ’25, the Refining business, including contribution from the ADNOC R&GT associate, reported a positive performance of €135 mln, compared to a breakeven Q3 ’24 result, reflecting the recovery in refining margins, improved product crack spreads and the higher average utilization plant rate. In the nine months ’25, the business reported a proforma adjusted profit of €35 mln, below the nine months ’24 results (€145 mln) driven by negative scenario of utilities and other positive one-off of the nine months ’24.

· The Chemical business, managed by Versalis, reported a proforma adjusted loss of €188 mln in Q3 ’25, a slightly better performance compared to the loss in Q3 ’24 (€193 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 the nine months ’25, proforma adjusted loss amounted to €615 mln (€583 mln loss in the nine months ’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 July, Versalis signed a Memorandum of Understanding (MoU) with Acea Ambiente covering initiatives in the field of recycling post-consumer and post-industrial plastics. The agreement foresees the assessment of chemical recycling solutions, including the proprietary Hoop^® technology.

· In September, Versalis signed an agreement with Veritas, an Italian multi-utility, to promote the circular economy, mainly focusing on developing joint initiatives to valorize post-consumer and post-industrial plastics.

· In September, Eni Storage Systems, a joint venture between Eni and Fib, a Seri Industrial subsidiary, started operations to build a plant for the production of stationary lithium batteries as part of the reconversion plan of the Brindisi petrochemicals hub which has undergone shutdown.

· In October, the authorisation 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. In addition to the Ecofining™ plant, the project includes a biogenic feedstock pre-treatment unit and a plant to produce hydrogen. Completion is scheduled by the end of 2028. The Versalis Hoop^® plant will have a processing capacity of 40 ktonnes per year.

10

Sustainability and other developments

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

· In July, as part of the strategic partnership between Italy and the United Arab Emirates, Eni signed with Khazna Data Centers a memorandum to set up a Joint Venture for the development of an “AI Data Center Campus” with a total IT capacity of 500 MW at Eni’s hub of Ferrera Erbognone.

· In August, Eni signed a Sale and Purchase Agreement (SPA) with Global Infrastructure Partners, a leading global infrastructure investor, affiliate of the BlackRock fund, relating to a stake of 49.99% in Eni CCUS Holding, which is expected to establish joint control of the counterparties over the post-close entity. The Eni’s subsidiary operates the Liverpool Bay and Bacton CCS projects in the UK, is committed to the L10-CCS project in the Netherlands, and owns a pre-emptive right to acquire a 50% stake held by Eni in the Ravenna CCS project in Italy. Furthermore, it has access to several options within a broader platform of ongoing CCUS initiatives in the medium to long-term.

· In September, Eni signed with Commonwealth Fusion Systems (CFS) a power offtake agreement worth more than $1 bln, expanding a longstanding strategic partnership between the companies to bring to industrial scale the magnetic fusion to produce power. The power purchase agreement (PPA) covers a share of the decarbonized power which will be generated once CFS’s ARC fusion power plant in Chesterfield County, Virginia becomes operational at the beginning of the next decade as planned by the shareholders of the initiative.

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Group results

Q2		Q3			Nine months
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
18,767	Sales from operations	20,204	20,658	(2)	61,536	65,309	(6)
1,162	Operating profit (loss)	1,344	1,360	(1)	4,834	5,611	(14)
372	Exclusion of inventory holding (gains) losses	117	431	(73)	475	425	12
355	Exclusion of special items (a)	612	651	(6)	1,253	2,618	(52)
1,889	Adjusted operating profit (loss)	2,073	2,442	(15)	6,562	8,654	(24)
792	main JV/Associates adjusted EBIT	923	958	(4)	2,796	2,969	(6)
2,681	Proforma adjusted EBIT	2,996	3,400	(12)	9,358	11,623	(19)
2,422	E&P	2,638	3,259	(19)	8,368	10,242	(18)
387	Global Gas & LNG Portfolio (GGP) and Power	346	286	21	1,206	995	21
262	Enilive and Plenitude	331	306	8	929	1,010	(8)
(193)	Refining and Chemicals	(53)	(192)	72	(580)	(438)	(32)
(197)	Corporate, other activities and consolidation adjustments	(266)	(259)		(565)	(186)
2,200	Adjusted profit (loss) before taxes	2,273	2,656	(14)	7,222	9,200	(22)
1,175	Adjusted net profit (loss)	1,315	1,292	2	3,943	4,429	(11)
561	Net profit (loss)	865	544	59	2,621	2,476	6
543	Net profit (loss) attributable to Eni's shareholders	803	522	54	2,518	2,394	5
256	Exclusion of inventory holding (gains) losses	87	309	(72)	333	305	9
335	Exclusion of special items (a)	357	440	(19)	942	1,673	(44)
1,134	Adjusted net profit (loss) attributable to Eni's shareholders	1,247	1,271	(2)	3,793	4,372	(13)

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

· In Q3 ’25, the Group proforma adjusted EBIT of €3 bln was 12% lower than the year-ago quarter due to a decline in crude oil realized prices in the wake of a 14% reduction in the price of the Brent benchmark and the EUR appreciation vs the USD (up 6% vs Q3 ’24). Unfavorable commodity and currency trends affected the performance of the E&P business at €2.64 bln (down 19% y-o-y), which nonetheless showed 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. Other businesses performed well compared to the year-ago quarter, particularly the refining business which returned to profitability due to improved product crack spreads and better plant utilization rates (€0.14 bln vs breakeven in the year-ago quarter). The performance in the GGP and Power segment, up 21% from the year-ago quarter, was driven by the continuing value maximization of the gas portfolio. The Chemicals business on the backdrop of a continued downturn in the European sector reported a loss of €0.19 bln, but beginning to show some improvement through the early effects of the restructuring plan. The performance of the transition-related satellites Enilive/Plenitude was in line with management’s expectations. In the nine months ‘25, the Group reported a proforma adjusted Ebit of €9.36 bln, down 19% compared to the nine months ’24, due to the same trends as in Q3 ’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 Q3 ’25 adjusted profit before taxes was €2.27 bln, 14% lower than the Q3 ’24, reflecting the trend in the Group adjusted EBIT, partly offset by higher net profits recorded at Eni’s equity-accounted entities driven by better operating and volume performances as well as the inception of Ithaca Energy in the UK, despite the negative commodity scenario. In the nine months ‘25, the Group reported an adjusted profit before taxes of €7.22 bln, down 22% compared to the nine months ’24.

· In Q3 ’25 adjusted net profit attributable to Eni’s shareholders of €1.25 bln was 2% lower than the Q3 ’24, because of the 14% reduction in adjusted profit before taxes, partly offset by a lower tax rate down to 42% from 51%. The reduction in the Group tax rate was 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, as well as higher contribution to pre-tax profit from Italian subsidiaries which are subject to a statutory tax rate (around 28%) well below that of the E&P foreign sector. In the nine months ‘25, the Group reported an adjusted net profit attributable to Eni’s shareholders of €3.79 bln, down 13% compared to the nine months ’24.

12

Net borrowings and cash flow from operations

Q2		Q3				Nine months
2025	(€ million)	2025	2024	Change		2025	2024	Change
561	Net profit (loss)	865	544	321		2,621	2,476	145
	Adjustments to reconcile net profit (loss) to net cash provided by operating activities:
1,716	- depreciation, depletion and amortization and other non monetary items	1,505	1,875	(370)		5,063	6,774	(1,711)
(6)	- net gains on disposal of assets	(32)	(382)	350		(38)	(566)	528
950	- dividends, interests and taxes	891	1,263	(372)		3,275	4,428	(1,153)
1,176	Changes in working capital related to operations	195	1,298	(1,103)		387	260	127
512	Dividends received by equity investments	417	305	112		1,296	1,409	(113)
(1,058)	Taxes paid	(572)	(1,735)	1,163		(2,802)	(4,554)	1,752
(334)	Interests (paid) received	(191)	(171)	(20)		(822)	(755)	(67)
3,517	Net cash provided by operating activities	3,078	2,997	81		8,980	9,472	(492)
(1,954)	Capital expenditure	(2,017)	(2,001)	(16)		(5,790)	(5,953)	163
(100)	Investments and acquisitions	(229)	(76)	(153)		(580)	(2,384)	1,804
83	Disposal of consolidated subsidiaries, businesses, tangible and intangible assets and investments	1,275	1,059	216		1,359	1,686	(327)
(275)	Other cash flow related to investing activities	(93)	(852)	759		(268)	(804)	536
1,271	Free cash flow	2,014	1,127	887		3,701	2,017	1,684
10	Net cash inflow (outflow) related to financial activities	(459)	255	(714)		(649)	135	(784)
(317)	Changes in short and long-term financial debt	(97)	(2,063)	1,966		(1,421)	(619)	(802)
(300)	Repayment of lease liabilities	(303)	(262)	(41)		(978)	(933)	(45)
(458)	Dividends paid, share repurchases, changes in non-controlling interests and reserves	(1,371)	(1,370)	(1)		193	(2,856)	3,049
(65)	Issue of perpetual hybrid bond and interest payment	(1)	1,549	(1,550)		125	1,462	(1,337)
(121)	Effect of changes in consolidation and exchange differences of cash and cash equivalent	2	(89)	91		(202)	(44)	(158)
20	NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENT	(215)	(853)	638		769	(838)	1,607
2,775	Adjusted net cash before changes in working capital at replacement cost	3,297	2,898	399		9,486	10,701	(1,215)

Q2		Q3				Nine months
2025	(€ million)	2025	2024	Change		2025	2024	Change
1,271	Free cash flow	2,014	1,127	887		3,701	2,017	1,684
(300)	Repayment of lease liabilities	(303)	(262)	(41)		(978)	(933)	(45)
	Net borrowings of acquired companies		(4)	4			(482)	482
(312)	Exchange differences on net borrowings and other changes	(72)	(554)	482		(797)	(1,275)	478
(458)	Dividends paid and changes in non-controlling interest and reserves	(1,371)	(1,370)	(1)		193	(2,856)	3,049
(65)	Issue of perpetual hybrid bond and interest payment	(1)	1,549	(1,550)		125	1,462	(1,337)
136	CHANGE IN NET BORROWINGS BEFORE LEASE LIABILITIES	267	486	(219)		2,244	(2,067)	4,311
300	Repayment of lease liabilities	303	262	41		978	933	45
193	Inception of new leases and other changes	(113)	(47)	(66)		(43)	(723)	680
629	CHANGE IN NET BORROWINGS AFTER LEASE LIABILITIES	457	701	(244)		3,179	(1,857)	5,036

In the nine months ’25, net cash provided by operating activities was €8,980 mln and included €1,296 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 the Q4 ’24 as part of the Group ongoing initiatives to optimize working capital requirements.

Adjusted net cash before changes in working capital at replacement cost was €9,486 mln in the nine months ’25 (€3,297 mln in the Q3 ’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, as well as non-recurring provisions in connection with certain legal proceedings.

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

Q2		Q3			Nine months
2025	(€ million)	2025	2024	Change	2025	2024	Change
3,517	Net cash provided by operating activities	3,078	2,997	81	8,980	9,472	(492)
(1,176)	Changes in working capital related to operations	(195)	(1,298)	1,103	(387)	(260)	(127)
(28)	Exclusion of commodity derivatives	50	488	(438)	(3)	(46)	43
372	Exclusion of inventory holding (gains) losses	117	431	(314)	475	425	50
2,685	Net cash before changes in working capital at replacement cost	3,050	2,618	432	9,065	9,591	(526)
90	Extraordinary (gains) charges	247	280	(33)	421	1,110	(689)
2,775	Adjusted net cash before changes in working capital at replacement cost	3,297	2,898	399	9,486	10,701	(1,215)

13

In the nine months ’25 organic capex was €5.9 bln (down 3% y-o-y) and excluded the share of capex that will be reimbursed upon closing of ongoing asset disposals, which have been reclassified among other cash flow related to investing activities. Net of organic capex, the free cash flow ante working capital was about €3.58 bln.

Cash inflows from divestments and transactions with owners comprised proceeds from the disposals of noncontrolling interest 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) as well as asset disposals mainly relating to the sale of a 30% stake in the Baleine project and other non-strategic fields in Congo (€1.36 bln). Acquisitions were of little relevance and 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 (€0.12 bln).

Net borrowings before IFRS 16 in the nine months ‘25 decreased by around €2.24 bln. The main inflows comprised the adjusted operating cash flow (€9.49 bln) and transactions with equity owners relating to the divestment of noncontrolling interests at Enilive and Plenitude subsidiaries (€3.78 bln). Furthermore, other positive cash inflows regarded asset disposals for €1.36 bln. The main cash outflows comprised requirements for capital expenditures of €5.9 bln, dividend payments to Eni’s shareholders and share repurchases of €3.54 bln (€2.31 bln of dividend payments and share repurchases of €1.23 bln), repayment of supplier financing agreements (€1 bln), the repayment of lease liabilities and hybrid bond interest (€1.08 bln), as well as other changes of €0.8 bln.

As of October 17, 2025, around 68.4 mln shares have been purchased, for a cash outlay of €980 mln, as part of the share buy-back program authorized by the Shareholders' Meeting held on May 14, 2025, for a total maximum of €3.5 bln through April 2026. Within that limit, management intends to execute share repurchase plan to €1.8 bln.

14

Summarized Group Balance Sheet

(€ million)	Dec. 31, 2024	Sept. 30, 2025	Change
Fixed assets
Property,  plant and equipment	59,864	53,684	(6,180)
Right of use	5,822	5,100	(722)
Intangible assets	6,434	6,020	(414)
Inventories - Compulsory stock	1,595	1,326	(269)
Equity-accounted investments and other investments	15,545	14,583	(962)
Receivables financing and securities held for operating purposes	1,107	1,035	(72)
Net payables related to capital expenditure	(1,364)	(1,194)	170
	89,003	80,554	(8,449)
Net working capital
Inventories	6,259	6,260	1
Trade receivables	12,562	8,462	(4,100)
Trade payables	(15,170)	(11,839)	3,331
Net tax assets (liabilities)	144	(378)	(522)
Provisions	(15,774)	(14,510)	1,264
Other current assets and liabilities	(2,292)	(1,038)	1,254
	(14,271)	(13,043)	1,228
Provisions for employee benefits	(681)	(626)	55
Assets held for sale including related liabilities	225	1,530	1,305
CAPITAL EMPLOYED, NET	74,276	68,415	(5,861)
Eni's shareholders equity	52,785	49,243	(3,542)
Non-controlling interest	2,863	3,723	860
Shareholders' equity	55,648	52,966	(2,682)
Net borrowings before lease liabilities ex IFRS 16	12,175	9,931	(2,244)
Lease liabilities	6,453	5,518	(935)
Net borrowings after lease liabilities ex IFRS 16	18,628	15,449	(3,179)
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	74,276	68,415	(5,861)
Leverage before lease liabilities ex IFRS 16	0.22	0.19
Leverage after lease liabilities ex IFRS 16	0.33	0.29
Gearing before lease liabilities ex IFRS 16	0.18	0.16
Gearing after lease liabilities ex IFRS 16	0.25	0.23

As of September 30, 2025, fixed assets (€80.6 bln) decreased by €8.5 bln from December 31, 2024, mainly due to negative exchange rate translation differences (the period-end exchange rate of EUR vs. USD was 1.174 up 13% compared to 1.039 as of December 31, 2024) thus decreasing the euro book values of dollar-denominated assets. Capital expenditures for the period were offset by asset disposals, mainly the 30% of the Baleine project, and DD&A. Assets held for sale were recognized in connection with the pending disposal of non-controlling interests in certain upstream operated assets and Eni’s business of the CCUS.

Shareholders’ equity (approximately €53 bln) decreased by €2.7 bln from December 31, 2024, mainly due to negative foreign currency translation differences (about €6 bln) reflecting the depreciation of the USD vs. EUR, as well as shareholders remuneration of €3.5 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 interest in the subsidiary Enilive divested to a third party and the consideration received (circa €2.7 bln).

Non-controlling interests of €3.7 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 fund’s interest in Plenitude of €0.7 bln, which was increased in the period by €0.2 bln; ii) a perpetual subordinated hybrid bond (€1.8 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 borrowings² before lease liabilities as of September 30, 2025 of €9.9 bln was down by €2.2 bln from December 31, 2024.

Leverage³ – the ratio of net borrowings to total equity before IFRS 16 – was 19% on September 30, 2025. Considering the disposal transactions underway, particularly the proposed 20% investment by Ares private equity fund into Plenitude, the Group proforma leverage stands at 12%.

² Details on net borrowings are furnished on page 27.

³ 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 18 and subsequent.

15

Special items

The breakdown of pre-tax special items recorded in operating profit by segment (net charges of €1,253 mln and €612 mln in the nine months ’25 and Q3 ’25, respectively) is as follows:

· E&P: net charges of €573 mln in the nine months ’25 (€130 mln in Q3 ‘25) mainly relating to write-downs of oil&gas properties driven by alignment of a disposal group to its fair value (€464 mln), of which two transactions closed in the quarter, as well as an oil asset impairment driven by a downward reserves revision;

· GGP and Power: net gains of €402 mln in the nine months '25 (net charges €115 mln in Q3 '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 €374 mln and €32 mln in the nine months '25 and Q3 '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 €74 mln and €79 mln in the nine months '25 and Q3 '25, respectively).The reclassification of the negative balance of €280 mln (positive of €17 mln in Q3 '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 €433 mln (€99 mln in Q3 '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 (€360 mln and €67 mln in the nine months '25 and Q3 '25, respectively);

· Refining and Chemicals: net charges of €405 mln (€86 mln in Q3 '25) mainly related to the write-down of capital expenditures made for compliance and stay-in-business at certain CGU with expected negative cash flows (€218 mln and €59 mln in the nine months '25 and Q3 '25, respectively), and environmental provision of €136 mln (€19 mln in Q3 '25).

16

Other information, basis of presentation and disclaimer

This press release on Eni’s results for the third quarter and the nine months 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 second and third quarter of 2025, the nine months of 2025 and for the third quarter and the nine months of 2024. Information on the Company’s financial position relates to end of the periods as of September 30, 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.

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 third quarter and the nine months of 2025 results (not subject to audit) is also available on Eni’s website eni.com.

17

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.

Leverage

Leverage is a Non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’ equity, including non-controlling interest. Leverage is the reference ratio to assess the solidity and efficiency of the Group balance sheet in terms of incidence of funding sources including third-party funding and equity as well as to carry out benchmark analysis with industry standards.

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.

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

18

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)
Third 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)							1,670		227	242	(291)	(418)	(86)		1,344
Exclusion of inventory holding (gains) losses										(8)	69		56		117
Exclusion of special items:
environmental charges (expense recovered from third-parties)	2		11	19				32
impairment losses (impairment reversals), net	109		9	59	4			181
impairment of exploration projects
net gains on disposal of assets
risk provisions	38				170			208
provision for redundancy incentives	3	1	2	3	10			19
commodity derivatives	16	(32)	67	(1)				50
exchange rate differences and derivatives	(32)	17		(1)	(1)			(17)
other	(6)	129	10	7	(1)			139
Special items of operating profit (loss)	130	115	99	86	182			612
Adjusted operating profit (loss) of subsidiaries (a)	1,800	342	333	(136)	(236)	(30)		2,073
main JV/Associates adjusted EBIT (b)	838	4	(2)	83				923
Proforma adjusted EBIT (c)=(a)+(b)	2,638	346	331	(53)	(236)	(30)		2,996
Finance expenses and dividends of subsidiaries (d)	(84)	(4)	(12)	3	(75)			(172)
Finance expenses and dividends of main JV/associates (e)	(137)	3	(11)	(19)				(164)
Income taxes of main JV/associates (f)	(402)	3	1	11				(387)
Adjusted net profit (loss) of main JV/associates (g)=(b)+(e)+(f)	299	10	(12)	75				372
Adjusted profit (loss) before taxes (h)=(a)+(d)+(g)	2,015	348	309	(58)	(311)	(30)		2,273
Income taxes (i)	(840)	(132)	(93)	(16)	114	9		(958)
Tax rate (%)								42.1
Adjusted net profit (loss) (j)=(h)+(i)	1,175	216	216	(74)	(197)	(21)		1,315
of which:
- Adjusted net profit (loss) of non-controlling interest								68
- Adjusted net profit (loss) attributable to Eni's shareholders								1,247
Reported net profit (loss) attributable to Eni's shareholders								803
Exclusion of inventory holding (gains) losses								87
Exclusion of special items								357
Adjusted net profit (loss) attributable to Eni's shareholders								1,247

19

(€ million)
Third Quarter 2024	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)							2,264		(95)	207	(908)	(168)	60		1,360
Exclusion of inventory holding (gains) losses										114	479		(162)		431
Exclusion of special items:
environmental charges (expense recovered from third-parties)	16		19	76				111
impairment losses (impairment reversals), net	14		4	116	6			140
impairment of exploration projects
net gains on disposal of assets	(5)		(1)	2				(4)
risk provisions				3				3
provision for redundancy incentives	5		1	5	2			13
commodity derivatives	(18)	520	(26)	12				488
exchange rate differences and derivatives	6	(153)	(1)	(9)	7			(150)
other	44	6	8	(4)	(4)			50
Special items of operating profit (loss)	62	373	4	201	11			651
Adjusted operating profit (loss) of subsidiaries (a)	2,326	278	325	(228)	(157)	(102)		2,442
main JV/Associates adjusted EBIT (b)	933	8	(19)	36				958
Proforma adjusted EBIT (c)=(a)+(b)	3,259	286	306	(192)	(157)	(102)		3,400
Finance expenses and dividends of subsidiaries (d)	(53)		(12)	4				(61)
Finance expenses and dividends of main JV/associates (e)	(111)	2	(6)	(23)				(138)
Income taxes of main JV/associates (f)	(543)	(2)	(4)	4				(545)
Adjusted net profit (loss) of main JV/associates (g)=(b)+(e)+(f)	279	8	(29)	17				275
Adjusted profit (loss) before taxes (h)=(a)+(d)+(g)	2,552	286	284	(207)	(157)	(102)		2,656
Income taxes (i)	(1,266)	(115)	(98)	49	38	28		(1,364)
Tax rate (%)								51.4
Adjusted net profit (loss) (j)=(h)+(i)	1,286	171	186	(158)	(119)	(74)		1,292
of which:
- Adjusted net profit (loss) of non-controlling interest								21
- Adjusted net profit (loss) attributable to Eni's shareholders								1,271
Reported net profit (loss) attributable to Eni's shareholders								522
Exclusion of inventory holding (gains) losses								309
Exclusion of special items								440
Adjusted net profit (loss) attributable to Eni's shareholders								1,271

20

(€ million)
Nine months 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)							5,116		1,585	480	(1,593)	(957)	203		4,834
Exclusion of inventory holding (gains) losses										34	496		(55)		475
Exclusion of special items:
environmental charges (expense recovered from third-parties)			33	136	55			224
impairment losses (impairment reversals), net	578		14	218	12			822
impairment of exploration projects
net gains on disposal of assets	(3)			(3)				(6)
risk provisions	38			16	171			225
provision for redundancy incentives	12	1	3	10	27			53
commodity derivatives	(3)	(374)	360	14				(3)
exchange rate differences and derivatives	(17)	(280)	(1)	2				(296)
other	(32)	251	24	12	(21)			234
Special items of operating profit (loss)	573	(402)	433	405	244			1,253
Adjusted operating profit (loss) of subsidiaries (a)	5,689	1,183	947	(692)	(713)	148		6,562
main JV/Associates adjusted EBIT (b)	2,679	23	(18)	112				2,796
Proforma adjusted EBIT (c)=(a)+(b)	8,368	1,206	929	(580)	(713)	148		9,358
Finance expenses and dividends of subsidiaries (d)	(55)	(13)	(33)	(2)	(91)			(194)
Finance expenses and dividends of main JV/associates (e)	(459)	8	(38)	(60)				(549)
Income taxes of main JV/associates (f)	(1,426)	(1)		34				(1,393)
Adjusted net profit (loss) of main JV/associates (g)=(b)+(e)+(f)	794	30	(56)	86				854
Adjusted profit (loss) before taxes (h)=(a)+(d)+(g)	6,428	1,200	858	(608)	(804)	148		7,222
Income taxes (i)	(2,881)	(442)	(278)	27	336	(41)		(3,279)
Tax rate (%)								45.4
Adjusted net profit (loss) (j)=(h)+(i)	3,547	758	580	(581)	(468)	107		3,943
of which:
- Adjusted net profit (loss) of non-controlling interest								150
- Adjusted net profit (loss) attributable to Eni's shareholders								3,793
Reported net profit (loss) attributable to Eni's shareholders								2,518
Exclusion of inventory holding (gains) losses								333
Exclusion of special items								942
Adjusted net profit (loss) attributable to Eni's shareholders								3,793

21

(€ million)
Nine months 2024	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)							6,009		(779)	1,353	(1,081)	69	40		5,611
Exclusion of inventory holding (gains) losses										121	254		50		425
Exclusion of special items:
environmental charges (expense recovered from third-parties)	18		23	(35)	(385)			(379)
impairment losses (impairment reversals), net	1,329		15	280	19			1,643
net gains on disposal of assets	(6)			4	(1)			(3)
risk provisions	9			3	4			16
provision for redundancy incentives	14		3	12	19			48
commodity derivatives	(55)	1,600	(466)	(4)				1,075
exchange rate differences and derivatives	(7)	(46)	(2)		9			(46)
other	113	189	4	(32)	(10)			264
Special items of operating profit (loss)	1,415	1,743	(423)	228	(345)			2,618
Adjusted operating profit (loss) of subsidiaries (a)	7,424	964	1,051	(599)	(276)	90		8,654
main JV/Associates adjusted EBIT (b)	2,818	31	(41)	161				2,969
Proforma adjusted EBIT (c)=(a)+(b)	10,242	995	1,010	(438)	(276)	90		11,623
Finance expenses and dividends of subsidiaries (d)	(229)	(4)	(37)	9	(116)			(377)
Finance expenses and dividends of main JV/associates (e)	(318)	12	(22)	(53)				(381)
Income taxes of main JV/associates (f)	(1,667)	(8)	(3)	13				(1,665)
Adjusted net profit (loss) of main JV/associates (g)=(b)+(e)+(f)	833	35	(66)	121				923
Adjusted profit (loss) before taxes (h)=(a)+(d)+(g)	8,028	995	948	(469)	(392)	90		9,200
Income taxes (i)	(4,237)	(399)	(319)	127	82	(25)		(4,771)
Tax rate (%)								51.9
Adjusted net profit (loss) (j)=(h)+(i)	3,791	596	629	(342)	(310)	65		4,429
of which:
- Adjusted net profit (loss) of non-controlling interest								57
- Adjusted net profit (loss) attributable to Eni's shareholders								4,372
Reported net profit (loss) attributable to Eni's shareholders								2,394
Exclusion of inventory holding (gains) losses								305
Exclusion of special items								1,673
Adjusted net profit (loss) attributable to Eni's shareholders								4,372

22

(€ million)
Second 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)							1,495		585	83	(843)	(261)	103		1,162
Exclusion of inventory holding (gains) losses										61	396		(85)		372
Exclusion of special items:
environmental charges (expense recovered from third-parties)			6	102	55			163
impairment losses (impairment reversals), net	214		6	99	4			323
impairment of exploration projects
net gains on disposal of assets	(3)			(3)				(6)
risk provisions				16	1			17
provision for redundancy incentives	4			4	5			13
commodity derivatives	(27)	(99)	85	13				(28)
exchange rate differences and derivatives	(9)	(196)		6	1			(198)
other	(15)	88	21	(3)	(20)			71
Special items of operating profit (loss)	164	(207)	118	234	46			355
Adjusted operating profit (loss) of subsidiaries (a)	1,659	378	262	(213)	(215)	18		1,889
main JV/Associates adjusted EBIT (b)	763	9		20				792
Proforma adjusted EBIT (c)=(a)+(b)	2,422	387	262	(193)	(215)	18		2,681
Finance expenses and dividends of subsidiaries (d)	131	(4)	(12)	(5)	32			142
Finance expenses and dividends of main JV/associates (e)	(192)	2	(16)	(21)				(227)
Income taxes of main JV/associates (f)	(404)	(3)	(1)	12				(396)
Adjusted net profit (loss) of main JV/associates (g)=(b)+(e)+(f)	167	8	(17)	11				169
Adjusted profit (loss) before taxes (h)=(a)+(d)+(g)	1,957	382	233	(207)	(183)	18		2,200
Income taxes (i)	(898)	(147)	(89)	10	103	(4)		(1,025)
Tax rate (%)								46.6
Adjusted net profit (loss) (j)=(h)+(i)	1,059	235	144	(197)	(80)	14		1,175
of which:
- Adjusted net profit (loss) of non-controlling interest								41
- Adjusted net profit (loss) attributable to Eni's shareholders								1,134
Reported net profit (loss) attributable to Eni's shareholders								543
Exclusion of inventory holding (gains) losses								256
Exclusion of special items								335
Adjusted net profit (loss) attributable to Eni's shareholders								1,134

23

Breakdown of special items

Q2		Q3		Nine months
2025	(€ million)	2025	2024	2025	2024
163	Environmental charges (expense recovered from third-parties)	32	111	224	(379)
323	Impairment losses (impairment reversals), net	181	140	822	1,643
(6)	Net gains on disposal of assets		(4)	(6)	(3)
17	Risk provisions	208	3	225	16
13	Provisions for redundancy incentives	19	13	53	48
(28)	Commodity derivatives	50	488	(3)	1,075
(198)	Exchange rate differences and derivatives	(17)	(150)	(296)	(46)
71	Other	139	50	234	264
355	Special items of operating profit (loss)	612	651	1,253	2,618
190	Net finance (income) expense	11	242	280	125
	of which:
198	- exchange rate differences and derivatives reclassified to operating profit (loss)	17	150	296	46
(122)	Net income (expense) from investments	(112)	(316)	(266)	(413)
(75)	Income taxes	(145)	(138)	(285)	(682)
348	Total special items of net profit (loss)	366	439	982	1,648
	attributable to:
335	- Eni's shareholders	357	440	942	1,673
13	- Non-controlling interest	9	(1)	40	(25)

Reconciliation of Group proforma adjusted EBIT

Q2		Q3			Nine months
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
1,659	E&P adjusted Ebit of consolidated subsidiaries	1,800	2,326	(23)	5,689	7,424	(23)
763	main JV/Associates adjusted Ebit	838	933	(10)	2,679	2,818	(5)
2,422	E&P proforma adjusted Ebit	2,638	3,259	(19)	8,368	10,242	(18)
378	GGP and Power adjusted Ebit of consolidated subsidiaries	342	278	23	1,183	964	23
9	main JV/Associates adjusted Ebit	4	8	(50)	23	31	(26)
387	GGP and Power proforma adjusted Ebit	346	286	21	1,206	995	21
262	Enilive and Plenitude adjusted Ebit of consolidated subsidiaries	333	325	2	947	1,051	(10)
	main JV/Associates adjusted Ebit	(2)	(19)	89	(18)	(41)	56
262	Enilive and Plenitude proforma adjusted Ebit	331	306	8	929	1,010	(8)
(213)	Refining and Chemicals  adjusted Ebit of consolidated subsidiaries	(136)	(228)	40	(692)	(599)	(16)
20	main JV/Associates adjusted Ebit	83	36	..	112	161	(30)
(193)	Refining and Chemicals proforma adjusted Ebit	(53)	(192)	72	(580)	(438)	(32)
(215)	Other segments adjusted Ebit	(236)	(157)	(50)	(713)	(276)	..
18	Impact of unrealized intragroup profit elimination	(30)	(102)	71	148	90	64
2,681	Group proforma adjusted Ebit(a)	2,996	3,400	(12)	9,358	11,623	(19)

(a) Main JV/Associates are Vår Energi, Azule Energy, Ithaca, Mozambique Rovuma Venture, Neptune Algeria, SeaCorridor, Adnoc R&GT and St. Bernard Renewables Llc.

24

Profit and loss reconciliation GAAP vs Non-GAAP

Third Quarter					2025	Nine months
Reported results	Profit on stock	Special items	Finance expense reclassified	Adjusted results	(€ million)	Reported results	Profit on stock	Special items	Finance expense reclassified	Adjusted results
1,344	117	629	(17)	2,073	Operating profit	4,834	475	1,549	(296)	6,562
(258)		(6)	17	(247)	Finance income (expense)	(668)		(16)	296	(388)
559		(112)		447	Income (expense) from investments	1,314		(266)		1,048
(780)	(33)	(145)		(958)	Income taxes	(2,859)	(135)	(285)		(3,279)
865	84	366		1,315	Net profit	2,621	340	982		3,943
62	(3)	9		68	- Non-controlling interest	103	7	40		150
803	87	357		1,247	Net profit attributable to Eni's shareholders	2,518	333	942		3,793

Third Quarter					2024	Nine months
Reported results	Profit on stock	Special items	Finance expense reclassified	Adjusted results	(€ million)	Reported results	Profit on stock	Special items	Finance expense reclassified	Adjusted results
1,360	431	801	(150)	2,442	Operating profit	5,611	425	2,664	(46)	8,654
(346)		92	150	(104)	Finance income (expense)	(664)		79	46	(539)
634		(316)		318	Income (expense) from investments	1,498		(413)		1,085
(1,104)	(122)	(138)		(1,364)	Income taxes	(3,969)	(120)	(682)		(4,771)
544	309	439		1,292	Net profit	2,476	305	1,648		4,429
22		(1)		21	- Non-controlling interest	82		(25)		57
522	309	440		1,271	Net profit attributable to Eni's shareholders	2,394	305	1,673		4,372

2025	Q2
(€ million)	Reported results	Profit on stock	Special items	Finance expense reclassified	Adjusted results
Operating profit	1,162	372	553	(198)	1,889
Finance income (expense)	(161)		(8)	198	29
Income (expense) from investments	404		(122)		282
Income taxes	(844)	(106)	(75)		(1,025)
Net profit	561	266	348		1,175
- Non-controlling interest	18	10	13		41
Net profit attributable to Eni's shareholders	543	256	335		1,134

25

Analysis of Profit and Loss account items

Sales from operations

Q2		Q3			Nine months
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
11,881	Exploration & Production	13,329	12,901	3	38,271	41,060	(7)
3,444	Global Gas & LNG Portfolio and Power	3,503	4,227	(17)	12,537	12,691	(1)
6,662	Enilive and Plenitude	7,021	7,459	(6)	22,156	23,395	(5)
4,533	Refining and Chemicals	4,545	5,333	(15)	14,010	16,524	(15)
510	Corporate and other activities	487	445	9	1,466	1,361	8
(8,263)	Consolidation adjustments	(8,681)	(9,707)	11	(26,904)	(29,722)	9
18,767		20,204	20,658	(2)	61,536	65,309	(6)

Operating expenses

Q2		Q3			Nine months
2025	(€ million)	2025	2024	% Ch.	2025	2024	% Ch.
15,104	Purchases, services and other	16,512	16,833	(2)	49,376	51,281	(4)
58	Impairment losses (impairment reversals) of trade and other receivables, net	(3)	(2)	(50)	147	74	99
824	Payroll and related costs	744	818	(9)	2,438	2,479	(2)
13	of which:   provision for redundancy incentives and other	19	13	46	53	48	10
15,986		17,253	17,649	(2)	51,961	53,834	(3)

DD&A, impairments, reversals and write-off

Q2		Q3			Nine months
2025	(€ million)	2025	2024	var %	2025	2024	% Ch.
1,501	Exploration & Production	1,521	1,519	-	4,586	4,776	(4)
66	Global Gas & LNG Portfolio and Power	64	83	(23)	196	235	(17)
188	Enilive and Plenitude	190	177	7	553	516	7
75	- Enilive	79	72	10	224	209	7
113	- Plenitude	111	105	6	329	307	7
37	Refining and Chemicals	39	37	5	114	119	(4)
39	Corporate and other activities	38	35	9	115	107	7
(8)	Impact of unrealized intragroup profit elimination	(10)	(9)	(11)	(26)	(25)	(4)
1,823	Total depreciation, depletion and amortization	1,842	1,842	-	5,538	5,728	(3)
323	Impairment losses (impairment reversals) of tangible and intangible and right of use assets, net	181	140	29	822	1,643	(50)
2,146	Depreciation, depletion, amortization, impairments and reversals	2,023	1,982	2	6,360	7,371	(14)
(10)	Write-off of tangible and intangible assets	11	57	(81)	(2)	160	..
2,136		2,034	2,039	-	6,358	7,531	(16)

Income (expense) from investments

(€ million)
Nine months 2025	Exploration & Production	Global Gas & LNG Portfolio and Power	Enilive and Plenitude	Refining and Chemicals	Corporate and other activities	Group
Share of profit (loss) from equity-accounted investments	985	30	(52)	58	(13)	1,008
Dividends	144		4	7	32	187
Net gains (losses) on disposals	33					33
Other income (expense), net	92	(7)	5		(4)	86
	1,254	23	(43)	65	15	1,314

26

Leverage and net borrowings

Leverage is a measure used by management to assess the Company’s level of indebtedness. It is calculated as a ratio of net borrowings to shareholders’ equity, including non-controlling interest. Management periodically reviews leverage in order to assess the soundness and efficiency of the Group balance sheet in terms of optimal mix between net borrowings and net equity, and to carry out benchmark analysis with industry standards.

(€ million)	Dec. 31, 2024	Sept. 30, 2025	Change
Total debt	30,348	29,109	(1,239)
-  Short-term debt	8,820	9,502	682
-  Long-term debt	21,528	19,607	(1,921)
Cash and cash equivalents	(8,183)	(8,929)	(746)
Financial assets measured at fair value through profit or loss	(6,797)	(6,820)	(23)
Financing receivables held for non-operating purposes	(3,193)	(3,429)	(236)
Net borrowings before lease liabilities ex IFRS 16	12,175	9,931	(2,244)
Lease Liabilities	6,453	5,518	(935)
Net borrowings after lease liabilities ex IFRS 16	18,628	15,449	(3,179)
Shareholders' equity including non-controlling interest	55,648	52,966	(2,682)
Leverage before lease liability ex IFRS 16	0.22	0.19
Leverage after lease liability ex IFRS 16	0.33	0.29

27

Consolidated financial statements

BALANCE SHEET

(€ million)
	Sept. 30, 2025	Dec. 31, 2024
ASSETS
Current assets
Cash and cash equivalents	8,929	8,183
Financial assets measured at fair value through profit or loss	6,820	6,797
Other financial assets	551	1,085
Trade and other receivables	12,414	16,901
Inventories	6,260	6,259
Income tax assets	798	695
Other assets	3,713	3,662
	39,485	43,582
Non-current assets
Property, plant and equipment	53,684	59,864
Right of use assets	5,100	5,822
Intangible assets	6,020	6,434
Inventory - compulsory stock	1,326	1,595
Equity-accounted investments	13,221	14,150
Other investments	1,362	1,395
Other financial assets	3,913	3,215
Deferred tax assets	6,107	6,322
Income tax assets	127	129
Other assets	2,751	4,011
	93,611	102,937
Assets held for sale	1,890	420
TOTAL ASSETS	134,986	146,939
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	6,000	4,238
Current portion of long-term debt	3,502	4,582
Current portion of long-term lease liabilities	1,047	1,279
Trade and other payables	17,691	22,092
Income taxes payable	693	587
Other liabilities	4,976	5,049
	33,909	37,827
Non-current liabilities
Long-term debt	19,656	21,570
Long-term lease liabilities	4,471	5,174
Provisions for contingencies	14,510	15,774
Provisions for employee benefits	626	681
Deferred tax liabilities	5,222	5,581
Income taxes payable	29	40
Other liabilities	3,237	4,449
	47,751	53,269
Liabilities directly associated with assets held for sale	360	195
TOTAL LIABILITIES	82,020	91,291
Share capital	4,005	4,005
Retained earnings	34,097	32,552
Cumulative currency translation differences	2,181	8,081
Other reserves and equity instruments	8,634	8,406
Treasury shares	(2,192)	(2,883)
Net profit  (loss)	2,518	2,624
Total Eni shareholders' equity	49,243	52,785
Non-controlling interest	3,723	2,863
TOTAL SHAREHOLDERS' EQUITY	52,966	55,648
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	134,986	146,939

28

GROUP PROFIT AND LOSS ACCOUNT

Q2		Q3		Nine months
2025	(€ million)	2025	2024	2025	2024
18,767	Sales from operations	20,204	20,658	61,536	65,309
355	Other income and revenues	342	358	1,096	1,933
19,122	Total revenues	20,546	21,016	62,632	67,242
(15,104)	Purchases, services and other	(16,512)	(16,833)	(49,376)	(51,281)
(58)	Impairment reversals (impairment losses) of trade and other receivables, net	3	2	(147)	(74)
(824)	Payroll and related costs	(744)	(818)	(2,438)	(2,479)
162	Other operating (expense) income	85	32	521	(266)
(1,823)	Depreciation, Depletion and Amortization	(1,842)	(1,842)	(5,538)	(5,728)
(323)	Impairment reversals (impairment losses) of tangible, intangible and right of use assets, net	(181)	(140)	(822)	(1,643)
10	Write-off of tangible and intangible assets	(11)	(57)	2	(160)
1,162	OPERATING PROFIT (LOSS)	1,344	1,360	4,834	5,611
3,113	Finance income	839	1,650	6,200	4,480
(3,325)	Finance expense	(1,150)	(2,054)	(6,962)	(5,489)
54	Net finance income (expense) from financial assets measured at fair value through profit or loss	71	117	182	319
(3)	Derivative financial instruments	(18)	(59)	(88)	26
(161)	FINANCE INCOME (EXPENSE)	(258)	(346)	(668)	(664)
303	Share of profit (loss) of equity-accounted investments	359	180	1,008	791
101	Other gain (loss) from investments	200	454	306	707
404	INCOME (EXPENSE) FROM INVESTMENTS	559	634	1,314	1,498
1,405	PROFIT (LOSS) BEFORE INCOME TAXES	1,645	1,648	5,480	6,445
(844)	Income taxes	(780)	(1,104)	(2,859)	(3,969)
561	Net profit (loss)	865	544	2,621	2,476
	attributable to:
543	- Eni's shareholders	803	522	2,518	2,394
18	- Non-controlling interest	62	22	103	82
	Earnings per share (€ per share)
0.16	- basic	0.25	0.16	0.77	0.73
0.16	- diluted	0.24	0.16	0.76	0.72
	Weighted average number of shares outstanding (million)
3,049.7	- basic	3,011.2	3,160.1	3,041.0	3,184.2
3,112.3	- diluted	3,073.8	3,223.1	3,103.6	3,247.1

29

COMPREHENSIVE INCOME (LOSS)

	Q3		Nine months
(€ million)	2025	2024	2025	2024
Net profit (loss)	865	544	2,621	2,476
Items that are not reclassified to profit or loss in later periods			5	(3)
Remeasurements of defined benefit plans				8
Share of other comprehensive income on equity accounted entities				1
Change in the fair value of interests with effects on other comprehensive income		1	5	(10)
Taxation		(1)		(2)
Items that may be reclassified to profit in later periods	38	(2,553)	(5,481)	(944)
Currency translation differences	(90)	(2,383)	(6,153)	(682)
Change in the fair value of cash flow hedging derivatives	132	(280)	864	(344)
Share of other comprehensive income on equity-accounted entities	31	28	55	(18)
Taxation	(35)	82	(247)	100
Total other items of comprehensive income (loss)	38	(2,553)	(5,476)	(947)
Total comprehensive income (loss)	903	(2,009)	(2,855)	1,529
attributable to:
- Eni's shareholders	845	(1,982)	(2,704)	1,494
- Non-controlling interest	58	(27)	(151)	35

CHANGES IN SHAREHOLDERS’ EQUITY

(€ million)
Shareholders' equity at January 1, 2024			53,644
Total comprehensive income (loss)		1,529
Dividends paid to Eni's shareholders		(2,288)
Dividends distributed by consolidated subsidiaries		(50)
Issue of perpetual hybrid bonds		1,610
Coupon of perpetual subordinated bonds		(87)
Put option on Plenitude		(387)
Net purchase of treasury shares		(1,117)
Plenitude operation- disposal to EIP		588
Costs for the issue of perpetual hybrid bonds		(25)
Tax on hybrid bond coupon		25
Other changes		36
Total changes			(166)
Shareholders' equity at September 30, 2024			53,478
attributable to:
- Eni's shareholders			51,037
- Non-controlling interest			2,441
Shareholders' equity at January 1, 2025			55,648
Total comprehensive income (loss)		(2,855)
Dividends paid to Eni's shareholders		(2,307)
Dividends distributed by consolidated subsidiaries		(63)
Net purchase of treasury shares		(1,217)
Issue of perpetual hybrid bonds		1,500
Repurchase of perpetual hybrid bonds		(1,251)
Coupon of perpetual subordinated bonds		(105)
Taxes on disposal of Enilive and Plenitude		(26)
Taxes on hybrid bond coupon and costs		9
Plenitude operation - disposal to EIP		209
Put option on Plenitude		(139)
Enilive operation - disposal to KKR		3,569
Other changes		(6)
Total changes			(2,682)
Shareholders' equity at September 30, 2025			52,966
attributable to:
- Eni's shareholders			49,243
- Non-controlling interest			3,723

30

GROUP CASH FLOW STATEMENT

Q2			Q3		Nine months
2025	(€ million)		2025	2024	2025	2024
561	Net profit (loss)		865	544	2,621	2,476
	Adjustments to reconcile net profit (loss) to net cash provided by operating activities:
1,823	Depreciation, depletion and amortization		1,842	1,842	5,538	5,728
323	Impairment losses (impairment reversals) of tangible, intangible and right of use, net		181	140	822	1,643
(10)	Write-off of tangible and intangible assets		11	57	(2)	160
(303)	Share of (profit) loss of equity-accounted investments		(359)	(180)	(1,008)	(791)
(6)	Gains on disposal of assets, net		(32)	(382)	(38)	(566)
(100)	Dividend income		(87)	(45)	(187)	(130)
(94)	Interest income		(121)	(109)	(323)	(347)
300	Interest expense		319	313	926	936
844	Income taxes		780	1,104	2,859	3,969
(103)	Other changes		(107)	80	(232)	129
1,176	Cash flow from changes in working capital		195	1,298	387	260
(38)	- inventories		(405)	113	(4)	(337)
2,868	- trade receivables		1,166	1,615	3,821	4,072
(1,545)	- trade payables		(609)	(1,260)	(3,046)	(3,211)
(276)	- provisions for contingencies		(109)	(57)	(548)	(358)
167	- other assets and liabilities		152	887	164	94
(14)	Net change in the provisions for employee benefits		(63)	(64)	(55)	(95)
512	Dividends received		417	305	1,296	1,409
52	Interest received		51	69	168	239
(386)	Interest paid		(242)	(240)	(990)	(994)
(1,058)	Income taxes paid, net of tax receivables received		(572)	(1,735)	(2,802)	(4,554)
3,517	Net cash provided by operating activities		3,078	2,997	8,980	9,472
(2,433)	Cash flow from investing activities		(2,494)	(2,539)	(7,029)	(8,965)
(2,021)	- tangible assets		(2,061)	(1,884)	(5,768)	(5,605)
	- prepaid right of use			(2)		(5)
(125)	- intangible assets		(117)	(117)	(375)	(348)
	- consolidated subsidiaries and businesses net of cash and cash equivalent acquired			(2)		(1,844)
(100)	- investments		(229)	(74)	(580)	(540)
(23)	- securities and financing receivables held for operating purposes		(8)	(47)	(43)	(96)
(164)	- change in payables in relation to investing activities		(79)	(413)	(263)	(527)
187	Cash flow from disposals		1,430	669	1,750	1,510
65	- tangible assets		1,351	6	1,417	219
	- intangible assets		3	17	3	19
	- consolidated subsidiaries and businesses net of cash and cash equivalent disposed of			991		991
18	- investments		52	45	70	457
4	- securities and financing receivables held for operating purposes		7	23	23	43
100	- change in receivables in relation to disposals		17	(413)	237	(219)
10	Net change in receivables and securities not held for operating purposes		(459)	255	(649)	135
(2,236)	Net cash used in investing activities		(1,523)	(1,615)	(5,928)	(7,320)

31

GROUP CASH FLOW STATEMENT (continued)

Q2			Q3		Nine months
2025	(€ million)		2025	2024	2025	2024
2,223	Increase in long-term debt		1,514	66	5,235	3,366
(1,985)	Payment of long-term debt		(2,908)	(1,030)	(7,711)	(3,618)
(300)	Payment of lease liabilities		(303)	(262)	(978)	(933)
(555)	Increase (decrease) in short-term financial debt		1,297	(1,099)	1,055	(367)
(759)	Dividends paid to Eni's shareholders		(781)	(779)	(2,305)	(2,274)
(20)	Dividends paid to non-controlling interests		(30)	(16)	(63)	(45)
	Net capital issuance from non-controlling interest			(1)	709	589
601	Disposal (acquisition) of additional interests in consolidated subsidiaries			(4)	3,069	(4)
(280)	Net purchase of treasury shares		(560)	(570)	(1,226)	(1,136)
	Issue of perpetual hybrid bonds		(1)	1,549	230	1,549
	Other contributions				9	14
(65)	Interest payment of perpetual hybrid bond				(105)	(87)
(1,140)	Net cash used in financing activities		(1,772)	(2,146)	(2,081)	(2,946)
(121)	Effect of exchange rate changes on cash and cash equivalents and other changes		2	(89)	(202)	(44)
20	Net increase (decrease) in cash and cash equivalents		(215)	(853)	769	(838)
9,147	Cash and cash equivalents - beginning of the period		9,167	10,220	8,183	10,205
9,167	Cash and cash equivalents - end of the period		8,952	9,367	8,952	9,367

Capital expenditure

Q2		Q3			Nine months
2025	(€ million)	2025	2024	var %	2025	2024	% Ch.
1,336	Exploration & Production	1,535	1,384	11	4,310	4,270	1
79	of which: - exploration	63	67	(6)	229	347	(34)
1,241	- oil & gas development	1,345	1,304	3	3,931	3,893	1
25	Global Gas & LNG Portfolio and Power	14	22	(36)	51	67	(24)
9	- Global Gas & LNG Portfolio	2	10	(80)	11	15	(27)
16	- Power	12	12	-	40	52	(23)
264	Enilive and Plenitude	288	290	(1)	729	895	(19)
68	- Enilive	98	100	(2)	199	224	(11)
196	- Plenitude	190	190	-	530	671	(21)
175	Refining and Chemicals	142	163	(13)	430	453	(5)
132	- Refining	97	110	(12)	303	295	3
43	- Chemicals	45	53	(15)	127	158	(20)
153	Corporate and other activities	51	149	(66)	304	285	7
1	Impact of unrealized intragroup profit elimination	(13)	(7)	(86)	(34)	(17)	..
1,954	Capital expenditure (a)	2,017	2,001	1	5,790	5,953	(3)

(a) Expenditures to purchase plant and equipment from suppliers whose payment terms matched classification as financing payables, have been recognized among other changes of the reclassified cash flow statements and are not reported in the table above (€270 mln and €572 mln in the third quarter 2025 and 2024, respectively, €1,023 mln and €1,628 mln in the nine months 2025 and the nine months 2024, respectively, and €327 mln in the second quarter 2025).

In the nine months ’25, capital expenditure amounted to €5,790 mln (€5,953 mln in the nine months ’24) decreasing by 2.7% y-o-y, in particular:

• in the Exploration & Production, capital expenditure (€4,310 mln) was mainly related to oil&gas development activities in particular in the United Arab Emirates, Libya, Indonesia, Egypt, Italy and Congo;

• in the Enilive and Plenitude segment, Plenitude’s capital expenditure (€530 mln) related to development activities in the renewable business, acquisition of new customers, as well as development of electric vehicles network infrastructure, while Enilive capital expenditure (€199 mln) mainly related to biorefineries and marketing activity in Italy and in the rest of Europe, regulation compliance and stay-in-business initiatives in the retail network, as well as HSE initiatives;

• in the Refining and Chemicals segment mainly related to traditional refining in Italy (€303 mln) specifically to the new Livorno biorefinery, maintenance and stay-in-business as well as to the chemical business (€127 mln) and regarded the circular economy and asset integrity;

• in the Corporate and other activities mainly related to the CCUS and agri-business projects (€184 mln).

32

Exploration & Production

PRODUCTION OF OIL AND NATURAL GAS BY REGION

Q2			Q3		Nine months
2025			2025	2024	2025	2024
65	Italy	(kboe/d)	62	60	66	64
243	Rest of Europe		287	225	256	247
515	North Africa		529	576	524	597
336	Sub-Saharan Africa		340	309	333	304
161	Kazakhstan		154	150	163	157
208	Rest of Asia		235	204	214	202
132	Americas		143	134	130	130
8	Australia and Oceania		6	3	5	3
1,668	Production of oil and natural gas (a)(b)		1,756	1,661	1,691	1,704
432	- of which Joint Ventures and associates		493	380	452	388
136	Production sold (a)	(mmboe)	143	138	413	426

PRODUCTION OF LIQUIDS BY REGION

Q2			Q3		Nine months
2025			2025	2024	2025	2024
26	Italy	(kbbl/d)	25	27	26	27
150	Rest of Europe		193	127	161	135
173	North Africa		175	175	173	180
194	Sub-Saharan Africa		193	175	190	174
115	Kazakhstan		112	107	116	111
99	Rest of Asia		85	94	92	90
68	Americas		77	70	66	66
	Australia and Oceania		-		-
825	Production of liquids		860	775	824	783
238	- of which Joint Ventures and associates		283	205	250	210

PRODUCTION OF NATURAL GAS BY REGION

Q2			Q3		Nine months
2025			2025	2024	2025	2024
208	Italy	(mmcf/d)	190	178	212	193
487	Rest of Europe		491	513	497	587
1,786	North Africa		1,851	2,105	1,836	2,186
745	Sub-Saharan Africa		769	698	747	679
240	Kazakhstan		221	222	248	238
571	Rest of Asia		787	576	634	584
338	Americas		346	332	335	339
40	Australia and Oceania		32	14	26	15
4,415	Production of natural gas		4,687	4,638	4,535	4,821
1,019	- of which Joint Ventures and associates		1,096	916	1,060	934

(a) Includes Eni’s share of production of equity-accounted entities.

(b) Includes volumes of hydrocarbons consumed in operation (129 and 125 kboe/d in the third quarter of 2025 and 2024, respectively, 131 and 125 kboe/d in the nine months of 2025 and 2024, respectively, and  133 kboe/d in the second quarter of 2025).

33

FAQ

What dividend did E (Eni) approve and when are the key dates?

Eni approved a €0.26 per share tranche, ex‑dividend Nov 24, 2025, payable Nov 26, 2025. ADRs receive €0.52 on Dec 5, 2025.

How did Eni perform in Q3 2025?

Q3 proforma adjusted EBIT €2.996 bln, adjusted net profit attributable to shareholders €1.247 bln, CFFO before working capital €3.297 bln.

What is Eni’s 2025 buyback plan now?

The FY25 share buyback was raised by €0.3 bln to €1.8 bln, a 20% increase.

What production and cash flow guidance did Eni update?

Eni raised FY25 CFFO guidance to €12 bln and production to 1.71–1.72 mln boe/d.

What were Eni’s leverage metrics?

Leverage before lease liabilities was 0.19, with proforma leverage 12% including pending transactions.

How did Eni’s upstream business perform?

Hydrocarbon production rose 6% year over year to 1.76 mln boe/d, contributing to Q3 results.