Eni S.p.a.

May 6, 2026 at 3:54 PM UTC

Eni S p A: Fact Book 2025 06 May 2026 Press Release

Fact

2025

Book

Mission

We are an energy company.

We concretely support a just energy transition, with the objective of preserving our planet

and promoting an efficient and sustainable access to energy for all.

Our work is based on passion and innovation,

on our unique strengths and skills,

on the equal dignity of each person,

recognizing diversity as a key value for human development, on the responsibility, integrity and transparency of our actions.

We believe in the value of long-term partnerships with the Countries

and communities where we operate, bringing long-lasting prosperity for all.

Global goals for a sustainable development

The 2030 Agenda for Sustainable Development, presented in September 2015, identifies the 17 Sustainable Development Goals (SDGs) which represent the common targets of sustainable development on the current complex social problems. These goals are an important reference for the international community and Eni in managing activities in those Countries in which it operates.

‌Eni

Fact Book

2025 Eni at a glance

Main data 4

Eni share performance 6

Financial Data 9

Quarterly information 20

Operating review

Exploration & Production 28

Global Gas & LNG Portfolio and Power 57

Enilive and Plenitude 65

Refining and Chemicals 77

Environmental activities 88

Annex

Results by business segment 92

Employees 98

Energy conversion table 99

Disclaimer

Eni's Fact Book is a supplement to Eni's Annual Report and is designed to provide supplemental financial and operating information. It contains certain forward-looking statements regarding capital expenditures, dividends, buy-back programs, allocation of future cash flow from operations, financial structure evolution, future operating performance, targets of production and sale growth 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: possible evolution in respect of the conflict between Russia and Ukraine and in the Middle East; the timing of bringing new oil and gas 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 oil and natural gas pricing; operational problems; general macroeconomic 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.

‌Eni at a glance

A CLEAR STRATEGY

DRIVING GROWTH AND RESILIENCE THROUGH THE CYCLE

STRATEGY EXECUTION & KEY MILESTONES

2025: DELIVERING ON OUR STRATEGY

2025 OUTCOMES

In 2025, Eni achieved significant progress in executing its transformation strategy, which combines the valorization of traditional activities with the development of transition businesses. E&P's outstanding results were driven by accretive production growth and cost management. Enilive and Plenitude delivered material value and growth, further diversifying and strengthening the Group's earnings. These achievements are based on solid pillars: organic growth, diversification, vertical integration, new technology developments, and the adoption of innovative business models. The strengthening of the portfolio, and the application of a disciplined capital allocation, contributed to increase the Group's resilience facing market volatility, also thanks to balance sheet strength and debt reduction, which have enabled increased shareholders' returns. Organic and profitable growth is at the heart of our sustainable value chain, driven by our industry-leading exploration, technological know-how in the upstream with fast time-to-market and our ability to open up new opportunities in the transition. Our growth strategy is balanced in terms of risk-rewards through our unique Dual Exploration and satellite model.

E&P

A DISTINCTIVE GROWTH ENGINE

Outstanding exploration-led portfolio supporting a deep, diversified development pipeline with industry-leading time-to-market.

TRANSITION

CREATING DIVERSIFIED VALUE

Scaling transition platforms delivering material growth and diversification through distinctive, self-funding business models.

TECHNOLOGY

ENABLING DIFFERENTIATION

& NEW OPPORTUNITIES

Technology leadership strengthening E&P competitiveness while enabling new opportunities in CCS, batteries and lower carbon energy.

FINANCIAL MODEL

SATELLITES AND FINANCIAL STRENGTH

Satellite model unlocking value and attracting strategic partners, supported by strong

financial discipline and a robust balance sheet.

GLOBAL NATURAL RESOURCES

UPSTREAM • 4% underlying production growth (6 main

start-ups) top end of guidance (with 4 major FIDs)

900 mmboe new resources discovered
1.0 bbbl proved reserves additions, RRR 167% organic top performer vs. peers
Agreements with YPF and XRG on Argentina LNG
and Indonesia-Malaysia business combination with PETRONAS
GGP • 15 MTPA LNG contracted volumes
New LNG long-term agreements with Venture Global,

TRANSITION & TRANSFORMATION

PLENITUDE • Rising renewables generation integrated with

clients, 5.8 GW (+41% y-o-y)

ENILIVE • Biorefineries construction begun in Livorno, South

Korea and Malaysia

Sannazzaro project approved, Q8 partnership for construction of Priolo biorefinery

VERSALIS • Transformation plan in execution, with closure of

Brindisi and Priolo ahead of plan

Gulf & Botas, and positive contracts renegotiation

CCS • Closing of the transaction with GIP for the

investment in Eni CCUS Holding

CORPORATE

ENI INDUSTRIAL EVOLUTION

Launched new company for transformation

RESULTS AHEAD • Stronger than expected cash generation

NET CAPEX WELL BELOW GUIDANCE • €4.4 bln proforma

ENHANCED BUY-BACK & DIVIDEND • €4.9 bln total distribution (~40% payout). Unique among peers in raising buy-back

REDUCED GEARING • 15% from 18% YE 2024, 14% proforma

PRODUCTION 1.73 mmboe/d

GROUP CFFO ADJ €12.5 bln

GGP PROFORMA ADJ EBIT

ENILIVE PROFORMA ADJ EBITDA

>€1.0 bln

€1.0 bln

CASH INITIATIVES €4 bln

NET CAPEX €4.4 bln

PLENITUDE PROFORMA ADJ EBITDA

€1.1 bln

SHAREHOLDERS REMUNERATION

€1.05 dividend per share

€1.8 bln buy-back

‌Main data

KEY FINANCIAL DATA

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Net sales from operations		82,151	88,797	93,717	132,512	76,575	43,987	69,881	75,822
Operating profit (loss)		5,010	5,238	8,257	17,510	12,341	(3,275)	6,432	9,983
Exclusion of special items		2,589	4,676	4,986	3,440	(1,186)	3,855	2,388	1,161
Exclusion of inventory holding (gains) losses		745	434	562	(564)	(1,491)	1,318	(223)	96
Adjusted operating profit (loss)(a)		8,344	10,348	13,805	20,386	9,664	1,898	8,597	11,240
Proforma adjusted operating profit (loss)(a)		12,223	14,322	17,809	25,333	-	-	-	-
Net profit (loss)(b)		2,608	2,624	4,771	13,887	5,821	(8,635)	148	4,126
Adjusted net profit (loss)(a)(b)		4,989	5,257	8,322	13,301	4,330	(758)	2,876	4,583
Net cash flow from operating activities		13,330	13,092	15,119	17,460	12,861	4,822	12,392	13,647
Capital expenditure		8,647	8,485	9,215	8,056	5,234	4,644	8,376	9,119
Shareholders' equity including non-controlling interests at year end		52,787	55,648	53,644	55,230	44,519	37,493	47,900	51,073
Net borrowings at year end before IFRS 16(a)		9,386	12,175	10,899	7,026	8,987	11,568	11,477	8,289
Net borrowings at year end after IFRS 16(a)		15,086	18,628	16,235	11,977	14,324	16,586	17,125	n.a.
Gearing before lease liability ex IFRS 16(a)	(%)	15	18	17	11	17	24	19	14
Gearing after lease liability ex IFRS 16(a) (%)		22	25	23	18	24	31	26	14
Net capital employed at year end		67,873	74,276	69,879	67,207	58,843	54,079	65,025	59,362
Adjusted ROACE(a) (%)		7.6	7.6	12.3	22.0	8.4	(0.6)	5.3	8.5

Non-GAAP measures.
Attributable to Eni's shareholders.

KEY MARKET INDICATORS

2025 2024 2023 2022 2021 2020 2019 2018

Average price of Brent dated crude oil in U.S. dollars(a) ($/barrel)		69.06	80.76	82.62	101.19	70.73	41.67	64.30	71.04
Average EUR/USD exchange rate(b)		1.130	1.082	1.081	1.053	1.183	1.142	1.119	1.181
Average price of Brent dated crude oil	(€ barrel)	61.12	74.64	76.43	96.09	59.80	36.49	57.44	60.15
Standard Eni Refining Margin (SERM)(c) ($ barrel)		7.3	5.1	8.1	8.1	(0.9)	1.7	4.3	3.7
TTF(d)	(€/MWh)	36	34	41	121	46	9	13	23
PSV(d)	(€/MWh)	39	36	42	122	46	10	16	25

Source: S&P Global Energy.
Source: BCE.
Source: In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations.
In €/MWh. Source: ICIS European Spot Gas Markets.

SELECTED OPERATING DATA

Climate 2025 2024 2023 2022 2021 2020 2019 2018

Net Scope 1+2 Upstream(a)(c) (Mt CO2eq.)		4.7	6.8	9.0	n.a.	n.a.	n.a.	n.a.	14.5
Net Scope 1+2 Eni(a)(c)		21.4	23.8	26.7	n.a.	n.a.	n.a.	n.a.	35.8
Intensity Net Scope 1+2+3(b)(c)	(gCO2eq./MJ)	59.0	59.2	60.1	n.a.	n.a.	n.a.	n.a.	62.7
Direct GHG emissions (Scope 1)(d)	(Mt CO2eq.)	18.6	21.2	22.7	25.0	26.9	25.7	28.3	30.8
Indirect GHG emissions (Scope 2)(d)		0.5	0.6	0.6	0.6	0.7	0.6	0.6	0.6
Methane direct emission (Scope 1)(d)	(ktonnes CH4)	14.8	16.0	16.6	26.4	29.6	33.5	36.1	69.1

Health, Safety and Environment(e) 2025 2024 2023 2022 2021 2020 2019 2018

Total Recordable Injury Rate (TRIR) (total recordable injuries/worked hours) x 1,000,000	0.55	0.70	0.57	0.51	0.49	0.48	0.42	0.40
of which: employees	0.60	0.73	0.66	0.41	0.55	0.51	0.27	0.41
contractors	0.51	0.68	0.52	0.56	0.46	0.46	0.47	0.40
Total volume of oil spills (>1 barrel) (barrels)	217	2,815	12,719	5,628	4,361	5,641	6,665	5,819
of which: due to sabotage and terrorism	0	2,140	5,094	5,253	3,053	4,861	6,245	3,602
operational	217	675	7,625	375	1,308	780	420	2,217
Freshwater withdrawals (mmcm)	114	127	109	101	113	107	122	112
Re-injected produced water (%)	56	51	42	43	46	40	45	46

Innovation 2025 2024 2023 2022 2021 2020 2019 2018

R&D expenditure (€ million)	207	178	166	164	177	157	194	197
First patent filing application (number)	42	39	28	23	30	25	34	43

Employees 2025 2024 2023 2022 2021 2020 2019 2018

Italy (number)	22,006	22,100	21,749	20,878	21,035	21,575	21,488	21,002
Outside Italy	10,343	10,392	11,393	11,310	11,654	9,920	10,565	40,699
Total Group	32,349	32,492	33,142	32,188	32,689	31,495	32,053	61,701
of which: Senior Managers	896	945	960	966	986	982	1,037	1,025
Middle Managers and Senior Staff	9,460	9,346	9,349	9,133	9,196	9,245	9,461	9,227
White collar workers	16,357	16,476	16,557	15,903	15,970	16,285	16,403	16,208
Blue collar workers	5,636	5,725	6,276	6,186	6,537	4,983	5,152	5,241

KPIs calculated on a consolidated basis. The 2024 and 2023 data are reported accordingly.
KPI includes Scope 1+2 emissions (consolidated scope) and Scope 3 emissions from the use of products sold (Cat.11), estimated on the basis of Eni's equity share of upstream production. The 2024 and 2023 data are reported accordingly.
KPIs reported in the Sustainability Report from 2025; data for the 2019-2022 period are not available. The 2018 data are presented solely as a baseline year for calibrating the targets associated with these KPIs.
KPIs refer to 100% of the operated assets, consolidated and unconsolidated, with reference to the operatorship criteria expressed in the standards of the Sustainability Statement.
KPIs refer to 100% of the operated assets, consolidated and unconsolidated.

‌ENI SHARE PERFORMANCE

SHARE DATA

2025 2024 2023 2022 2021 2020 2019 2018

Net profit (loss)(a)(b) (€)		0.78	0.78	1.40	3.95	1.60	(2.42)	0.04	1.15
Dividend pertaining to the year		1.05	1.00	0.94	0.88	0.86	0.36	0.86	0.83
Dividend to Eni's shareholders pertaining to the year(c) (€ million)		3,176	3,094	3,034	2,972	3,055	1,286	3,078	2,989
Cash dividend to Eni's shareholders		3,080	3,068	3,046	3,009	2,358	1,965	3,018	2,954
Cash flow(a) (€)		4.41	4.13	4.58	5.01	3.61	1.35	3.45	3.79
Dividend yield(d)	(%)	6.56	7.6	6.2	6.5	7.1	4.2	6.3	5.9
Net profit (loss) per ADR(a)(b)(e)	($)	1.76	1.69	3.03	8.32	3.78	(5.53)	0.09	2.72
Dividend per ADR(e)		2.42	2.16	2.02	1.84	1.92	0.86	1.89	1.89
Cash flow per ADR(a)(e)	(%)	9.97	8.94	9.90	10.55	8.54	3.08	7.72	8.95
Dividend yield per ADR(d)(e)		6.6	7.6	6.2	6.5	7.1	4.2	6.3	5.9
Number of shares outstanding at period-end(f)	(million)	2,957.7	3,081.4	3,218.8	3,345.4	3,539.8	3,572.5	3,572.5	3,601.1
Weighted average number of shares outstanding(f)		3,024.8	3,167.0	3,303.8	3,483.6	3,566.0	3,572.5	3,592.2	3,601.1
Total Shareholders Return (TSR)	(%)	32	(9)	23	16	52	(34)	7	5

Fully diluted. Ratio of net profit/cash flow and average number of shares outstanding in the period. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by Reuters (WMR) for the period presented.
Pertaining to Eni's shareholders.
The amount of dividend for the year 2025 is based on the Board's proposal.
Ratio between dividend of the year and average share price in December.
One ADR represents 2 shares. Net profit, dividends and cash flow data were converted using average exchange rates. Dividends data were converted at the Noon Buying Rate of the pay-out date.
Calculated by excluding own shares in portfolio.

SHARE INFORMATION

2025 2024 2023 2022 2021 2020 2019 2018

Share price - Milan Stock Exchange
High (€)		16.53	15.73	15.70	14.53	12.75	14.32	15.94	16.76
Low		11.23	12.70	12.16	10.64	8.20	5.89	13.04	13.33
Average		14.36	14.34	14.06	12.81	10.56	8.96	14.36	15.25
Year end		16.14	13.09	15.35	13.29	12.22	8.55	13.85	13.75
ADR price(a) - New York Stock Exchange
High	($)	38.27	34.12	34.19	32.49	29.70	32.12	36.17	40.09
Low		25.19	26.32	25.80	20.44	19.97	13.71	28.84	30.00
Average		32.60	31.00	30.42	27.04	24.98	20.28	32.12	35.98
Year end		37.94	27.36	34.01	28.66	27.65	20.60	30.92	31.50
Average daily exchanged shares (million shares)		11.59	10.63	11.44	14.56	17.03	20.40	11.41	12.99
Value (€ million)		164	152	160	187	179	178	164	197
Weighted average number of shares outstanding(b) (million shares)		2,957.7	3,167.0	3,303.8	3,483.6	3,566.0	3,572.5	3,592.2	3,601.1
Market capitalization(c)
EUR	(billion)	47.7	40.4	49.6	47.5	44.1	31.1	50.3	50.0
USD		56.1	41.9	54.8	50.7	49.9	38.2	56.5	57.3

One ADR represents 2 Eni's shares.
Excluding treasury shares.
Number of outstanding shares by reference price at period end.

DATA ON ENI SHARE PLACEMENT
		2001	1998	1997	1996	1995
Offer price	(€/share)	13.60	11.80	9.90	7.40	5.42
Number of share placed	(million shares)	200.1	608.1	728.4	647.5	601.9
of which: through bonus share		39.6	24.4	15.0	1.9
Percentage of share capital(a)	(%)	5.0	15.2	18.2	16.2	15.0
Proceeds	(€ million)	2,721	6,714	6,869	4,596	3,254
(a) Refers to share capital at December 31, 2025.

ENI SHARE PRICE IN MILAN (DECEMBER 31, 2017 - APRIL 30, 2026)

€

2018

2019

2020 2021

2022

2023

2024

2025 April 30,

2026

Eni Indexed FTSE MIB to Eni share price Indexed Euro Stoxx 50 to Eni share price

Source: Eni calculations based on BLOOMBERG data.

ENI ADR PRICE IN NEW YORK (DECEMBER 31, 2017 - APRIL 30, 2026)

US $ 100

2018

2019

2020 2021

2022

2023

2024

2025 April 30,

2026

Eni Indexed S&P 500 to Eni ADR price

Source: Eni calculations based on BLOOMBERG data.

SHAREHOLDERS DISTRIBUTION BY GEOGRAPHIC AREA(a) (%)

1.45

17.39

5.47

6.94

13.13

55.62

Italy

Other EU states

USA and Canada

Rest of world

Other (including treasury shares)

SHARE CAPITAL STRUCTURE(a) (%)

0.01

45.39

5.46

17.30

31.84

Ministry of Economy and Finance and Cassa Depositi e Prestiti SpA

Retail investors

Identity of shareholders not provided

Treasury shares

Institutional shareholders

(a) The update of the data is based on the nominative notices received as at March 18, 2026, relating to the registered recipients of the second tranche of the 2025 dividend. The figures shown in the graphs above do not take into account the free of charge shares granted to Eni's employees (as provided by the "Employee Stock Ownership Plan" approved by the Eni Shareholders' Meeting of May 15, 2024), the termination of the 2025 buyback program on February 18, 2026, and the subsequent cancellation of 118,782,928 treasury shares with no par value without reduction of share capital, resolved by the Extraordinary Shareholders' Meeting of May 14, 2025, which was executed on March 4, 2026. Therefore, as of the date of publication of this document, Eni's share capital is represented by 3,027,982,186 ordinary shares with no par value. The percentage of total shares held by the Ministry of Economy and Finance and CDP SpA is equal to 33.08% of the share capital, and the percentage of treasury shares held by Eni is equal to 2.87% of the share capital.

DIVIDEND PER SHARE

0.94

1.00

0.83

0.86

6.3

7.7

0.86

7.1

0.88

7.6

6.5

6.6

5.9

6.2

0.36

5.4

5.6

5.4

4.2 5.1

3.8

4.6

5.0

1.05

Eni's Dividend yield (%)

2018

2019

2020

2021

2022

2023

2024

2025

Dividend yield - average of Oil & Gas petroleum companies(a) (%)

Dividend (€/share)

(a) Refers to: BP, Chevron, Repsol, ExxonMobil, Shell and TotalEnergies.

TOTAL SHAREHOLDER RETURN (ENI VS. PEER GROUP AND BENCHMARK STOCK EXCHANGE INDEXES)

113.8

126.6

246.6 TSR Ftse Mib (%)

TSR - average stock market indices (%)

TSR Eni (%)

87.2 TSR - average Peer Group (%)

2015

2016 2017

2018 2019 2020 2021

2022

2023

2024

2025

‌FINANCIAL DATA

PROFIT AND LOSS ACCOUNT

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Sales from operations	82,151	88,797	93,717	132,512	76,575	43,987	69,881	75,822
Other income and revenues	1,478	2,417	1,099	1,175	1,196	960	1,160	1,116
Operating expenses	(70,296)	(74,544)	(77,221)	(105,497)	(58,716)	(36,640)	(54,302)	(59,130)
Other operating income (expense)	641	(352)	478	(1,736)	903	(766)	287	129
Depreciation, depletion, amortization	(7,349)	(7,600)	(7,479)	(7,205)	(7,063)	(7,304)	(8,106)	(6,988)
Net impairment reversals (losses) of tangible and intangible and right-of-use assets	(1,582)	(2,900)	(1,802)	(1,140)	(167)	(3,183)	(2,188)	(866)
Write-off of tangible and intangible assets	(33)	(580)	(535)	(599)	(387)	(329)	(300)	(100)
Operating profit (loss)	5,010	5,238	8,257	17,510	12,341	(3,275)	6,432	9,983
Finance income (expense)	(819)	(599)	(473)	(925)	(788)	(1,045)	(879)	(971)
Income (expense) from investments	1,587	1,850	2,444	5,464	(868)	(1,658)	193	1,095
Profit (loss) before income taxes	5,778	6,489	10,228	22,049	10,685	(5,978)	5,746	10,107
Income taxes	(3,020)	(3,725)	(5,368)	(8,088)	(4,845)	(2,650)	(5,591)	(5,970)
Tax rate (%)	52.3	57.4	52.5	36.7	45.3	..	97.3	59.1
Net profit (loss)	2,758	2,764	4,860	13,961	5,840	(8,628)	155	4,137
Attributable to:
- Eni's shareholders	2,608	2,624	4,771	13,887	5,821	(8,635)	148	4,126
- Non-controlling interest	150	140	89	74	19	7	7	11

SUMMARIZED GROUP BALANCE SHEET

(€ million) Dec. 31, 2025 Dec. 31, 2024 Dec. 31, 2023 Dec. 31, 2022 Dec. 31, 2021 Dec. 31, 2020 Dec. 31, 2019 Dec. 31, 2018

Fixed assets
Property, plant and equipment	50,536	59,864	56,299	56,332	56,299	53,943	62,192	60,302
Right of use	5,184	5,822	4,834	4,446	4,821	4,643	5,349
Intangible assets	6,022	6,434	6,379	5,525	4,799	2,936	3,059	3,170
Inventories - Compulsory stock	1,187	1,595	1,576	1,786	1,053	995	1,371	1,217
Equity-accounted investments and other investments	14,484	15,545	13,886	13,294	7,181	7,706	9,964	7,963
Receivables and securities held for operating purposes	974	1,107	2,335	1,978	1,902	1,037	1,234	1,314
Net payables related to capital expenditure	(1,337)	(1,364)	(2,031)	(2,320)	(1,804)	(1,361)	(2,235)	(2,399)
	77,050	89,003	83,278	81,041	74,251	69,899	80,934	71,567
Net working capital
Inventories	5,143	6,259	6,186	7,709	6,072	3,893	4,734	4,651
Trade receivables	8,986	12,562	13,184	16,556	15,524	7,087	8,519	9,520
Trade payables	(13,901)	(15,170)	(14,231)	(19,527)	(16,795)	(8,679)	(10,480)	(11,645)
Net tax assets (liabilities)	1,506	144	(2,112)	(2,991)	(3,678)	(2,198)	(1,594)	(1,364)
Provisions	(14,580)	(15,774)	(15,533)	(15,267)	(13,593)	(13,438)	(14,106)	(11,626)
Other current assets and liabilities	(1,572)	(2,292)	(892)	316	(2,258)	(1,328)	(1,864)	(860)
	(14,418)	(14,271)	(13,398)	(13,204)	(14,728)	(14,663)	(14,791)	(11,324)
Provisions for employee benefits	(596)	(596)	(748)	(786)	(819)	(1,201)	(1,136)	(1,117)
Assets held for sale including related liabilities	5,837	5,837	747	156	139	44	18	236
CAPITAL EMPLOYED, NET	67,873	79,973	69,879	67,207	58,843	54,079	65,025	59,362
Shareholders' equity
attributable to: - Eni's shareholders	47,940	52,785	53,184	54,759	44,437	37,415	47,839	51,016
- Non-controlling interest	4,847	2,863	460	471	82	78	61	57
Shareholders' equity	52,787	55,648	53,644	55,230	44,519	37,493	47,900	51,073
Net borrowings before lease liabilities ex IFRS 16	9,386	12,175	10,899	7,026	8,987	11,568	11,477	8,289
Lease liabilities	5,700	6,453	5,336	4,951	5,337	5,018	5,648
Net borrowings after lease liabilities ex IFRS 16	15,086	18,628	16,235	11,977	14,324	16,586	17,125	8,289
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	67,873	74,276	69,879	67,207	58,843	54,079	65,025	59,362
Gearing before lease liabilities ex IFRS 16	0.15	0.18	0.17	0.11	0.17	0.24	0.19	0.14
Gearing post lease liabilities ex IFRS 16	0.22	0.25	0.23	0.18	0.24	0.31	0.26	0.14

SUMMARIZED GROUP CASH FLOW STATEMENT

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Net profit (loss)	2,758	2,764	4,860	13,961	5,840	(8,628)	155	4,137
Adjustments to reconcile net proflt (loss) to net cash provided by operating activities:
- depreciation, depletion and amortization and other nnon-monetary items	7,209	9,951	7,781	4,369	8,568	12,641	10,480	7,657
- net gains on disposal of assets	(99)	(601)	(441)	(524)	(102)	(9)	(170)	(474)
- dividends, interest, taxes and other changes	3,590	4,246	5,596	8,611	5,334	3,251	6,224	6,168
Changes in working capital related to operations	2,735	1,286	1,811	(1,279)	(3,146)	(18)	366	1,632
Dividends received by equity investments	1,785	1,946	2,255	1,545	857	509	1,346	275
Taxes paid	(3,737)	(5,826)	(6,283)	(8,488)	(3,726)	(2,049)	(5,068)	(5,226)
Interests (paid) received	(911)	(674)	(460)	(735)	(764)	(875)	(941)	(522)
Net cash provided by operating activities - continuing operations	13,330	13,092	15,119	17,460	12,861	4,822	12,392	13,647
Capital expenditure	(8,647)	(8,485)	(9,215)	(8,056)	(5,234)	(4,644)	(8,376)	(9,119)
Investments and purchase of consolidated subsidiaries and businesses	(878)	(2,593)	(2,592)	(3,311)	(2,738)	(392)	(3,008)	(244)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments	1,383	2,788	596	1,202	404	28	504	1,242
Other cash flow related to investing activities	183	(996)	(348)	2,361	289	(735)	(254)	942
Free cash flow	5,371	3,806	3,560	9,656	5,582	(921)	1,258	6,468
Net cash inflow (outflow) related to financial activities	(1,339)	(531)	2,194	786	(4,743)	1,156	(279)	(357)
Changes in short and long-term financial debt	(2,555)	(1,293)	315	(2,569)	(244)	3,115	(1,540)	320
Repayment of lease liabilities	(1,250)	(1,205)	(963)	(994)	(939)	(869)	(877)
Dividends paid and changes in non-controlling interests and reserves	537	(4,522)	(4,882)	(4,841)	(2,780)	(1,968)	(3,424)	(2,957)
Net issue (repayment) of perpetual hybrid bond	(328)	1,640	(138)	(138)	1,924	2,975
Effect of changes in consolidation and exchange differences of cash and cash equivalent	(198)	83	(62)	16	52	(69)	1	18
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENT	238	(2,022)	24	1,916	(1,148)	3,419	(4,861)	3,492
Adjusted net cash before changes in working capital at replacement cost	12,496	13,590	16,498	20,380	12,711	6,726	11,700	12,529

CHANGE IN NET BORROWINGS

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Free cash flow	5,371	3,806	3,560	9,656	5,582	(921)	1,258	6,468
Repayment of lease liabilities	(1,250)	(1,205)	(963)	(994)	(939)	(869)	(877)
Net borrowings of acquired companies	(762)	(631)	(234)	(512)	(777)	(67)		(18)
Net borrowings of divested companies	362		(155)	142			13	(499)
Exchange differences on net borrowings and other changes	(1,141)	(364)	(1,061)	(1,352)	(429)	759	(158)	(367)
Dividends paid and changes in non-controlling interest and reserves	537	(4,522)	(4,882)	(4,841)	(2,780)	(1,968)	(3,424)	(2,957)
Net issue (repayment) of perpetual hybrid bond	(328)	1,640	(138)	(138)	1,924	2,975
CHANGE IN NET BORROWINGS BEFORE LEASE LIABILITIES	2,789	(1,276)	(3,873)	1,961	2,581	(91)	(3,188)	2,627
IFRS 16 first application effect		(5,759)
Repayment of lease liabilities	1,250	1205	963	994	939	869	877
Inception of new leases and other changes	(497)	(2,322)	(1,348)	(608)	(1,258)	(239)	(766)
Change in lease liabilities	753	(1,117)	(385)	386	(319)	630	(5,648)
CHANGE IN NET BORROWINGS AFTER LEASE LIABILITIES	3,542	(2,393)	(4,258)	2,347	2,262	539	(8,836)	2,627

SALES BY GEOGRAPHIC AREA OF DESTINATION

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Italy	28,647	30,994	33,450	60,090	29,968	14,717	23,312	25,279
Other EU Countries	15,979	15,975	18,271	25,413	14,671	9,508	18,567	20,408
Rest of Europe	14,866	16,493	18,476	21,748	12,470	8,191	6,931	7,052
Americas	6,215	7,908	7,004	6,929	4,420	2,426	3,842	5,051
Asia	9,675	9,114	7,404	9,062	7,891	4,182	8,102	9,585
Africa	6,731	8,285	9,057	9,191	7,040	4,842	8,998	8,246
Other areas	38	28	55	79	115	121	129	201
Total outside Italy	53,504	57,803	60,267	72,422	46,607	29,270	46,569	50,543
	82,151	88,797	93,717	132,512	76,575	43,987	69,881	75,822

SALES BY GEOGRAPHIC AREA OF ORIGIN

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Italy	59,076	59,028	62,145	90,479	52,815	29,116	46,763	51,733
Other EU Countries	10,271	10,810	11,405	16,171	9,022	5,508	7,029	8,004
Rest of Europe	437	2,835	3,102	7,157	1,946	1,226	1,909	2,496
Americas	3,930	5,662	5,546	5,329	3,577	1,838	3,290	3,627
Asia	1,513	1,961	1,671	1,931	1,170	846	1,068	1,165
Africa	6,884	8,468	9,776	11,224	7,777	5,271	9,587	8,599
Other areas	40	33	72	221	268	182	235	198
Total outside Italy	23,075	29,769	31,572	42,033	23,760	14,871	23,118	24,089
	82,151	88,797	93,717	132,512	76,575	43,987	69,881	75,822

PURCHASES, SERVICES AND OTHER

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Production costs - raw, ancillary and consumable materials and goods	51,014	54,204	58,170	85,139	41,174	21,432	36,272	41,125
Production costs - services	12,433	12,217	11,512	10,303	10,646	9,710	11,589	10,625
Operating leases and other	1,356	1,512	1,432	2,301	1,233	876	1,478	1,820
Net provisions	1,117	1,397	1,369	2,985	707	349	858	1,120
Other expenses	1,694	2,073	1,746	2,069	1,983	1,317	879	1,130
less:
capitalized direct costs associated with self-constructed tangible and intangible assets	(558)	(289)	(393)	(268)	(194)	(133)	(202)	(198)
	67,056	71,114	73,836	102,529	55,549	33,551	50,874	55,622

PRINCIPAL ACCOUNTANT FEES AND SERVICES

(€ thousand) 2025 2024 2023 2022 2021 2020 2019 2018

Audit fees	29,107	28,235	25,982	23,637	18,858	19,605	15,748	25,445
Audit-related fees	4,627	3,602	3,580	3,563	4,511	1,412	1,045	1,628
	33,734	31,837	29,562	27,200	23,369	21,017	16,793	27,073

PAYROLL AND RELATED COSTS

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Wages and salaries	2,620	2,665 2,427 2,311 2,182 2,193 2,417 2,409
Social security contributions	541	527 497 465 455 458 449 448
Cost related to defined benefit plans and defined contribution plans	64	96 156 174 165 102 85 220
Other costs	135	123 196 194 204 239 213 170
less:
capitalized direct costs associated with self-constructed tangible and intangible assets	(131)	(149) (140) (129) (118) (129) (168) (154)
	3,229	3,262 3,136 3,015 2,888 2,863 2,996 3,093

FINANCE INCOME (EXPENSE)

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Finance income (expense) related to net borrowings	(743)	(656)	(487)	(939)	(849)	(913)	(962)	(627)
- Interest expense on corporate bonds	(774)	(827)	(667)	(507)	(475)	(517)	(618)	(565)
- Net income from financial activities held for trading	243	367	250	(53)	11	31	127	32
	(8)	21	34	(2)
- Interest expense for banks and other financing istitutions	(252)	(358)	(207)	(128)	(94)	(102)	(122)	(120)
- Interest expense for lease liabilities	(348)	(314)	(267)	(315)	(304)	(347)	(378)
- Interest from banks	191	294	356	57	4	10	21	18
- Interest and other income from receivables and securities for non-financing operating activities	205	161	14	9	9	12	8	8
Income (expense) from derivative financial instruments	(80)	278	(61)	13	(306)	351	(14)	(307)
- Derivatives on exchange rate	(86)	310	(63)	(70)	(322)	391	9	(329)
- Derivatives on interest rate	6	(32)	2	81	16	(40)	(23)	22
- Options		2
Exchange differences, net	133	(38)	255	238	476	(460)	250	341
Other finance income (expense)	(251)	(405)	(274)	(275)	(177)	(96)	(246)	(430)
- Interest and other income from receivables and securities for financing operating activities	39	44	153	128	67	97	112	132
- Finance expense due to the passage of time (accretion discount)	(250)	(261)	(341)	(199)	(144)	(190)	(255)	(249)
- Other finance income (expense)	(40)	(188)	(86)	(204)	(100)	(3)	(103)	(313)
	(941)	(821)	(567)	(963)	(856)	(1,118)	(972)	(1,023)
Finance expense capitalized	122	222	94	38	68	73	93	52
	(819)	(599)	(473)	(925)	(788)	(1,045)	(879)	(971)

INCOME (EXPENSE ON) FROM INVESTMENTS

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Share of profit of equity-accounted investments	1,414	1,202	1,622	2,163	202	38	161	409
Share of loss of equity-accounted investments	(252)	(316)	(281)	(285)	(1,294)	(1,733)	(184)	(430)
Gains on disposals	77	562	430	483	1		19	22
Dividends	242	227	255	351	230	150	247	231
Decreases (increases) in the provision for losses on investments from equity accounted investments	(1)	(20)	(5)	(37)	1	(38)	(65)	(47)
Other income (expense), net	107	195	423	2,789	(8)	(75)	15	910
	1,587	1,850	2,444	5,464	(868)	(1,658)	193	1,095

CAPITAL EXPENDITURE BY GEOGRAPHIC AREA OF ORIGIN

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Italy	1,829	2,009	2,006	1,475	1,333	1,198	1,402	1,424
Other European Union Countries	673	673	485	415	199	152	306	267
Rest of Europe	231	308	235	205	202	119	9	538
Africa	3,170	3,276	4,105	3,163	1,604	1,443	3,902	4,533
Americas	260	556	609	1,266	659	441	1,017	534
Asia	2,367	1,519	1,471	1,390	1,203	1,267	1,685	1,782
Other areas	117	144	304	142	34	24	55	41
Total outside Italy	6,818	6,476	7,209	6,581	3,901	3,446	6,974	7,695
Capital expenditure	8,647	8,485	9,215	8,056	5,234	4,644	8,376	9,119

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 report:

Adjusted operating and net profit

Adjusted operating and 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 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.

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.

Proforma adjusted EBITDA

Earnings Before Interest, Taxes, Depreciation and Amortization, is calculated summing up the adjusted operating profit and DD&A, adding the contribution of the equity-accounted entities. Represents the company's profitability as a result of operations management.

Gearing

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

Cash flow from operations before changes in working capital at replacement cost

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

Free cash flow

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

Net borrowings

Net borrowings is calculated as total finance debt less cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Financial activities are qualified as "not related to operations" when these are not strictly related to the business operations.

Adjusted ROACE

Is the return on average capital invested, calculated as the ratio between net income before minority interests, plus net financial charges on net financial debt, less the related tax effect and net average capital employed.

Profit per boe

Measures the return per oil and natural gas barrel produced. It is calculated as the ratio between Results of operations from E&P activities (as defined by FASB Extractive Activities - Oil and Gas Topic 932) and production sold.

Opex per boe

Measures efficiency in the Oil & Gas development activities, calculated as the ratio between operating costs (as defined by FASB Extractive Activities - Oil and Gas Topic 932) and production sold.

Finding & Development cost per boe

Represents Finding & Development cost per boe of new proved or possible reserves. It is calculated as the overall amount of exploration and development expenditure, the consideration for the acquisition of possible and probable reserves as well as additions of proved reserves deriving from improved recovery, extensions, discoveries and revisions of previous estimates (as defined by FASB Extractive Activities - Oil and Gas Topic 932). The following tables report the group operating profit and Group adjusted net profit and their breakdown by segment, as well as is represented the reconciliation with net profit attributable to Eni's shareholders of continuing operations.

Coverage

Financial discipline ratio, calculated as the ratio between operating profit and net finance charges.

Current ratio

Measures the capability of the company to repay short-term debt, calculated as the ratio between current assets and current liabilities.

Debt coverage

Rating companies use the debt coverage ratio to evaluate debt sustainability. It is calculated as the ratio between net cash provided by operating activities and net borrowings, less cash and cash-equivalents, securities held for non-operating purposes and financing receivables for non-operating purposes.

Debt/EBITDA

Net Debt/adjusted EBITDA is the ratio between the profit available to cover the debt before interest, taxes, amortizations and impairment. This index is a measure of the company's ability pay off its debt and gives an indication as to how long a company would need to operate at its current level to pay off all its debt.

BREAKDOWN OF SPECIAL ITEMS

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Special items of operating profit (loss)	2,589	4,676	4,986	3,440	(1,186)	3,855	2,388	1,161
- impairment losses (impairments reversals), net	1,582	2,900	1,802	1,140	167	3,183	2,188	866
- impairment of exploration projects		140 2 247
- environmental charges	560	31	648	2,056	271	(25)	338	325
- gains on disposal of assets	(21)	(38)	(11)	(41)	(100)	(9)	(151)	(452)
- risk provisions	325	44	39	87	142	149	3	380
- provision for redundancy incentives	72	73	158	202	193	123	45	155
- commodity derivatives	(26)	1,056	1,255	(389)	(2,139)	440	(439)	(133)
- exchange rate differences and derivatives	(334)	258	(16)	149	183	(160)	108	107
- reinstatement of Eni Norge amortization charges		(375)
- other	431	212	1,111	234	(150)	154	296	288
Net finance (income) expense	279	(155)	30	(127)	(115)	152	(42)	(85)
of which:
- exchange rate differences and derivatives reclassified to operating profit (loss)	334	(258)	16	(149)	(183)	160	(108)	(107)
Net income (expense) from investments	(158)	(319)	(698)	(2,834)	851	1,655	188	(798)
of which:
- gains on disposals of assets	(78)	(539)	(834)	(2,990)			(46)	(909)
- impairments/revaluation of equity investmentss	(113)				851	1,207	148	67
Income taxes	(790)	(1,941)	(1,180)	(683)	19	1,278	351	110
Total special items of net profit (loss)	1,920	2,261	3,138	(204)	(431)	6,940	2,885	388
attributable to:
- Eni's shareholders	1,873	2,325	3,149	(185)	(431)	6,940	2,885	388
- Non-controlling interest	47	(64)	(11)	(19)

RECONCILIATION TABLE OF NON-GAAP RESULTS VS. TO GAAP RESULTS FOR THE YEARS 2018-2025

(€ million) 2025 2024 2023 2022 2021 2020 2019 2018

Reported operating profit (loss)	5,010	5,238	8,257	17,510	12,341	(3,275)	6,432	9,983
Exclusion of inventory holding (gains) losses	745	434	562	(564)	(1,491)	1,318	(223)	96
Exclusion of special items:
environmental charges	560	31	648	2,056	271	(25)	338	325
impairment losses (impairments reversals), net	1,582	2,900	1,802	1,140	167	3,183	2,188	866
impairment of exploration projects		140		2	247
gains on disposal of assets	(21)	(38)	(11)	(41)	(100)	(9)	(151)	(452)
risk provisions	325	44	39	87	142	149	3	380
provision for redundancy incentives	72	73	158	202	193	123	45	155
commodity derivatives	(26)	1,056	1,255	(389)	(2,139)	440	(439)	(133)
exchange rate differences and derivatives	(334)	258	(16)	149	183	(160)	108	107
other	431	212	1,111	234	(150)	154	296	(87)
Special items of operating profit (loss)	2,589	4,676	4,986	3,440	(1,186)	3,855	2,388	1,161
Adjusted operating profit (loss)	8,344	10,348	13,805	20,386	9,664	1,898	8,597	11,240
Net finance (expense) income(a)	(540)	(754)	(443)	(1,052)	(903)	(893)	(921)	(1,056)
Net income (expense) from investments(a)	1,429	1,531	1,746	2,630	(17)	(3)	381	297
Income taxes(a)	(4,023)	(5,792)	(6,708)	(8,608)	(4,398)	(1,753)	(5,174)	(5,887)
Tax rate (%)	43,6	52,1	44,4	39,2	50,3	175,0	64,2	56,2
Adjusted net profit (loss)	5,210	5,333	8,400	13,356	4,349	(751)	2,883	4,594
of which attributable to:
- Eni's shareholders	4,989	5,257	8,322	13,301	4,330	(758)	2,876	4,583
- non-controlling interest	221	76	78	55	19	7	7	11
Reported net profit (loss) attributable to Eni's shareholders	2,608	2,624	4,771	13,887	5,821	(8,635)	148	4,126
Exclusion of inventory holding (gains) losses	508	308	402	(401)	(1,060)	937	(157)	69
Exclusion of special items	1,873	2,325	3,149	(185)	(431)	6,940	2,885	388
Adjusted net profit (loss) attributable to Eni's shareholders	4,989	5,257	8,322	13,301	4,330	(758)	2,876	4,583

(a) Excluding special items.

NET BORROWINGS

(€ million)	Debt and bonds	Cash and cash equivalents	Financial assets measured at fair value thorugh profit or loss	Financing receivables held for non-operating purposes	Lease Liabilities	Total
2025
Short-term debt	8,363	(8,242)	(6,991)	(3,845)	1,263	(9,452)
Long-term debt	20,101				4,437	24,538
	28,464	(8,242)	(6,991)	(3,845)	5,700	15,086
2024
Short-term debt	8,820	(8,183)	(6,797)	(3,193)	1,279	(8,074)
Long-term debt	21,528				5,174	26,702
	30,348	(8,183)	(6,797)	(3,193)	6,453	18,628
2023
Short-term debt	7,013	(10,193)	(6,782)	(855)	1,128	(9,689)
Long-term debt	21,716				4,208	25,924
	28,729	(10,193)	(6,782)	(855)	5,336	16,235
2022
Short-term debt	7,543	(10,155)	(8,251)	(1,485)	884	(11,464)
Long-term debt	19,374				4,067	23,441
	26,917	(10,155)	(8,251)	(1,485)	4,951	11,977
2021
Short-term debt	4,080	(8,254)	(6,301)	(4,252)	948	(13,779)
Long-term debt	23,714				4,389	28,103
	27,794	(8,254)	(6,301)	(4,252)	5,337	14,324
2020
Short-term debt	4,791	(9,413)	(5,502)	(203)	849	(9,478)
Long-term debt	21,895				4,169	26,064
	26,686	(9,413)	(5,502)	(203)	5,018	16,586
2019
Short-term debt	5,608	(5,994)	(6,760)	(287)	889	(6,544)
Long-term debt	18,910				4,759	23,669
	24,518	(5,994)	(6,760)	(287)	5,648	17,125
2018
Short-term debt	5,783	(10,836)	(6,552)	(188)		(11,793)
Long-term debt 20,082						20,082
	25,865	(10,836)	(6,552)	(188)		8,289

‌QUARTERLY INFORMATION

MAIN FINANCIAL DATA(a)

2025 (€ million) I quarter II quarter III quarter IV quarter Full Year

Net sales from operations	22,565	18,767	20,204	20,615	82,151
Operating profit (loss)	2,328	1,162	1,344	176	5,010
Adjusted operating profit (loss)	2,600	1,889	2,073	1,782	8,344
Net (loss) profit(b)	1,172	543	803	90	2,608
Capital expenditure	1,819	1,954	2,017	2,857	8,647
Investments	251	100	229	298	878
Net borrowings before lease liabilities ex IFRS 16	10,334	10,198	9,931	9,386	9,386
Net borrowings after lease liabilities ex IFRS 16	16,535	15,906	15,449	15,086	15,086

2024 (€ million) I quarter II quarter III quarter IV quarter Full Year

Net sales from operations	22,936	21,715	20,658	23,488	88,797
Operating profit (loss)	2,670	1,581	1,360	(373)	5,238
Adjusted operating profit (loss)	3,027	3,185	2,442	1,694	10,348
Net (loss) profit(b)	1,211	661	522	230	2,624
Capital expenditure	1,931	2,021	2,001	2,532	8,485
Investments	1,761	547	76	209	2,593
Net borrowings before lease liabilities ex IFRS 16	12,882	12,113	11,627	12,175	12,175
Net borrowings after lease liabilities ex IFRS 16	18,296	17,454	16,753	18,628	18,628

2023 (€ million) I quarter II quarter III quarter IV quarter Full Year

Net sales from operations	27,185	19,591	22,319	24,622	93,717
Operating profit (loss)	2,513	1,762	3,126	856	8,257
Adjusted operating profit (loss)	4,641	3,381	3,014	2,769	13,805
Net (loss) profit(b)	2,388	294	1,916	173	4,771
Capital expenditure	2,119	2,557	1,873	2,666	9,215
Investments	645	1,165	60	722	2,592
Net borrowings before lease liabilities ex IFRS 16	7,796	8,215	8,679	10,899	10,899
Net borrowings after lease liabilities ex IFRS 16	12,634	12,941	13,578	16,235	16,235

2022 (€ million) I quarter II quarter III quarter IV quarter Full Year

Net sales from operations	32,129	31,556	37,302	31,525	132,512
Operating profit (loss)	5,352	5,970	6,611	(423)	17,510
Adjusted operating profit (loss)	5,191	5,841	5,772	3,582	20,386
Net (loss) profit(b)	3,583	3,815	5,862	627	13,887
Capital expenditure	1,364	1,829	2,099	2,764	8,056
Investments	1,194	73	978	1,066	3,311
Net borrowings before lease liabilities ex IFRS 16	8,623	7,872	6,444	7,026	7,026
Net borrowings after lease liabilities ex IFRS 16	13,993	12,777	11,533	11,977	11,977

(a) Quarterly data are unaudited.

(b) Net profit attributable to Eni's shareholders.

MAIN FINANCIAL DATA(a)

2021 (€ million) I quarter II quarter III quarter IV quarter Full Year

Net sales from operations	14,494	16,294	19,021	26,766	76,575
Operating profit (loss)	1,862	1,995	2,793	5,691	12,341
Adjusted operating profit (loss)	1,321	2,045	2,492	3,806	9,664
Net (loss) profit(b)	856	247	1,203	3,515	5,821
Capital expenditure	1,139	1,248	1,200	1,647	5,234
Investments	520	351	553	1,314	2,738
Net borrowings before lease liabilities ex IFRS 16	12,239	10,040	11,309	8,987	8,987
Net borrowingsafter lease liabilities ex IFRS 16	17,507	15,323	16,622	14,324	14,324

2020 (€ million) I quarter II quarter III quarter IV quarter Full Year

Net sales from operations	13,873	8,157	10,326	11,631	43,987
Operating profit (loss)	(1,095)	(2,680)	220	280	(3,275)
Adjusted operating profit (loss)	1,307	(434)	537	488	1,898
Net (loss) profit(b)	(2,929)	(4,406)	(503)	(797)	(8,635)
Capital expenditure	1,590	978	889	1,187	4,644
Investments	222	42	95	33	392
Net borrowings before lease liabilities ex IFRS 16	12,920	14,329	14,525	11,568	11,568
Net borrowings after lease liabilities ex IFRS 16	18,681	19,971	19,853	16,586	16,586

2019 (€ million) I quarter II quarter III quarter IV quarter Full Year

Net sales from operations	18,540	18,440	16,686	16,215	69,881
Operating profit (loss)	2,518	2,231	1,861	(178)	6,432
Adjusted operating profit (loss)	2,354	2,279	2,159	1,805	8,597
Net (loss) profit(b)	1,092	424	523	(1,891)	148
Capital expenditure	2,239	1,997	1,899	2,241	8,376
Investments	30	21	2,931	26	3,008
Net borrowings before lease liabilities ex IFRS 16	8,665	7,856	12,714	11,477	11,477
Net borrowings after lease liabilities ex IFRS 16	14,496	13,591	18,517	17,125	17,125

2018 (€ million) I quarter II quarter III quarter IV quarter Full Year

Net sales from operations	17,932	18,139	19,695	20,056	75,822
Operating profit (loss)	2,399	2,639	3,449	1,496	9,983
Adjusted operating profit (loss)	2,380	2,564	3,304	2,992	11,240
Net (loss) profit(b)	946	1,252	1,529	399	4,126
Capital expenditure	2,541	1,961	1,830	2,787	9,119
Investments	37	94	26	87	244
Net borrowings at period end	11,278	9,897	9,005	8,289	8,289

Quarterly data are unaudited.
Net profit attributable to Eni's shareholders.

KEY MARKET INDICATORS

2025 I quarter II quarter III quarter IV quarter Full Year

Average price of Brent dated crude oil(a)	($/barrel)	75.66	67.82	69.07	63.69	69.06
Average EUR/USD exchange rate(b)		1.052	1.134	1.168	1.163	1.130
Average price in euro of Brent dated crude oil	(€/barrel)	71.92	59.81	59.14	54.75	61.12
Standard Eni Refining Margin (SERM)(c)	($/barrel)	3.8	4.8	8.9	11.7	7.3
PSV(d)	(€/MWh)	48	38	36	32	39
TTF(d)		47	35	32	30	36

2024 I quarter II quarter III quarter IV quarter Full Year

Average price of Brent dated crude oil(a)	($/barrel)	83.24	84.94	80.18	74.69	80.76
Average EUR/USD exchange rate(b)		1.086	1.077	1.098	1.067	1.082
Average price in euro of Brent dated crude oil	(€/barrel)	76.65	78.88	73.00	70.00	74.64
Standard Eni Refining Margin (SERM)(c)	($/barrel)	8.7	6.4	1.7	3.7	5.1
PSV(d)	(€/MWh)	29	33	38	45	36
TTF(d)		27	32	35	43	34

2023 I quarter II quarter III quarter IV quarter Full Year

Average price of Brent dated crude oil(a)	($/barrel)	81.27	78.39	86.76	84.05	82.62
Average EUR/USD exchange rate(b)		1.073	1.089	1.088	1.075	1.081
Average price in euro of Brent dated crude oil	(€/barrel)	75.74	71.99	79.71	78.17	76.40
Standard Eni Refining Margin (SERM)(c)	($/barrel)	11.0	5.6	11.7	4.3	8.1
PSV(d)	(€/MWh)	57	37	34	41	42
TTF(d)		54	35	33	41	41

2022 I quarter II quarter III quarter IV quarter Full Year

Average price of Brent dated crude oil(a)	($/barrel)	101.40	113.79	100.85	88.71	101.19
Average EUR/USD exchange rate(b)		1.122	1.065	1.007	1.021	1.053
Average price in euro of Brent dated crude oil	(€/barrel)	90.40	106.84	100.15	86.93	96.09
Standard Eni Refining Margin (SERM)(c)	($/barrel)	(0.9)	17.2	4.1	13.6	8.1
PSV(d)	(€/MWh)	99	97	197	95	122
TTF(d)		96	96	196	94	121

In USD per barrel. Source: S&P Global Energy.
Source: ECB.
In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations.
In €/MWh. Source: ICIS European Spot Gas Markets.

KEY MARKET INDICATORS

2021 I quarter II quarter III quarter IV quarter Full Year

Average price of Brent dated crude oil(a)	($/barrel)	60.90	68.83	73.47	79.73	70.73
Average EUR/USD exchange rate(b)		1.205	1.206	1.179	1.144	1.183
Average price in euro of Brent dated crude oil	(€/barrel)	50.54	57.07	62.33	69.73	59.80
Standard Eni Refining Margin (SERM)(c)	($/barrel)	(0.6)	(0.4)	(0.4)	(2.2)	(0.9)
PSV(d)	(€/MWh)	19	25	46	93	46
TTF(d)		19	25	47	92	46

2020 I quarter II quarter III quarter IV quarter Full Year

Average price of Brent dated crude oil(a)	($/barrel)	50.26	29.20	43.00	44.23	41.67
Average EUR/USD exchange rate(b)		1.103	1.101	1.169	1.193	1.142
Average price in euro of Brent dated crude oil	(€/barrel)	45.56	26.51	36.78	37.08	36.49
Standard Eni Refining Margin (SERM)(c)	($/barrel)	3.6	2.3	0.7	0.2	1.7
PSV(d)	(€/MWh)	11	7	9	14	10
TTF(d)		10	5	8	15	9

2019 I quarter II quarter III quarter IV quarter Full Year

Average price of Brent dated crude oil(a)	($/barrel)	63.20	68.82	61.94	63.25	64.30
Average EUR/USD exchange rate(b)		1.136	1.124	1.112	1.107	1.119
Average price in euro of Brent dated crude oil	(€/barrel)	55.65	61.25	55.70	57.13	57.44
Standard Eni Refining Margin (SERM)(c)	($/barrel)	3.4	3.7	6.0	4.2	4.3
PSV(d)	(€/MWh)	21	17	12	15	16
TTF(d)		18	13	10	13	13

2018 I quarter II quarter III quarter IV quarter Full Year

Average price of Brent dated crude oil(a)	($/barrel)	66.76	74.35	75.27	67.76	71.04
Average EUR/USD exchange rate(b)		1.229	1.191	1.163	1.141	1.181
Average price in euro of Brent dated crude oil	($/barrel)	54.32	62.40	64.72	59.37	60.15
Standard Eni Refining Margin (SERM)(c)	($/barrel)	3.0	4.1	4.5	3.4	3.7
PSV(d)	(€/MWh)	22	23	26	26	25
TTF(d)		21	21	25	25	23

In USD per barrel. Source: S&P Global Energy.
Source: ECB.
In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations.
In €/MWh. Source: ICIS European Spot Gas Markets.

MAIN OPERATING DATA

2025 I quarter II quarter III quarter IV quarter Full Year

Liquids production	(kbbl/d)	786	825	860	890	840
Natural gas production	(mmcf/d)	4,502	4,415	4,687	4,966	4,644
Hydrocarbons production	(kboe/d)	1,647	1,668	1,756	1,839	1.728
Sales of natural gas to third parties	(bcm)	10.69	7.75	7.84	11.87	38.15
Own consumption of natural gas		1.43	1.26	1.34	1.54	5.57
Total sales and own consumption of natural gas (GGP)		12.12	9.01	9.18	13.41	43.72
Gas sales to end customers (Plenitude)		2.39	0.68	0.47	1.75	5.29
Power sales to end customers (Plenitude)	(TWh)	4.90	4.09	4.84	4.80	18.63
Thermoelectric production (Enipower)		5.41	4.53	4.83	5.76	20.53
Sales of refined products - retail in Italy (Enilive)	(mmtonnes)	1.25	1.40	1.49	1.40	5.54

2024 I quarter II quarter III quarter IV quarter Full Year

Liquids production	(kbbl/d)	797	777	775	786	784
Natural gas production	(mmcf/d)	4,937	4,888	4,638	4,862	4,831
Hydrocarbons production	(kboe/d)	1,741	1,712	1,661	1,716	1,707
Sales of natural gas to third parties	(bcm)	14.08	8.24	9.38	13.80	45.50
Own consumption of natural gas		1.37	1.14	1.41	1.46	5.38
Total sales and own consumption of natural gas (GGP)		15.45	9.38	10.79	15.26	50.88
Gas sales to end customers (Plenitude)		2.56	0.73	0.49	1.73	5.51
Power sales to end customers (Plenitude)	(TWh)	4.64	4.14	4.88	4.62	18.28
Thermoelectric production (Enipower)		5.05	4.18	5.33	5.60	20.16
Sales of refined products - retail in Italy (Enilive)	(mmtonnes)	1.26	1.34	1.43	1.37	5.40

2023 I quarter II quarter III quarter IV quarter Full Year

Liquids production	(kbbl/d)	780	757	758	781	769
Natural gas production	(mmcf/d)	4,608	4,491	4,590	4,851	4,635
Hydrocarbons production	(kboe/d)	1,656	1,616	1,635	1,708	1,655
Sales of natural gas to third parties	(bcm)	13.53	9.85	9.57	12.17	45.12
Own consumption of natural gas		1.31	1.30	1.34	1.44	5.39
Total sales and own consumption of natural gas (GGP)		14.84	11.15	10.91	13.61	50.51
Gas sales to end customers (Plenitude)		2.91	0.87	0.53	1.74	6.06
Power sales to end customers (Plenitude)	(TWh)	4.61	4.20	4.57	4.60	17.98
Thermoelectric production (Enipower)		5.27	5.07	5.18	5.14	20.66
Sales of refined products - retail in Italy (Enilive)	(mmtonnes)	1.26	1.32	1.42	1.32	5.32

MAIN OPERATING DATA

2022 I quarter II quarter III quarter IV quarter Full Year

Liquids production	(kbbl/d)	780	740	707	776	751
Natural gas production	(mmcf/d)	4,638	4,447	4,583	4,426	4,523
Hydrocarbons production	(kboe/d)	1,654	1,586	1,578	1,617	1,610
Sales of natural gas to third parties	(bcm)	16.71	12.11	12.02	14.26	55.10
Own consumption of natural gas		1.55	1.27	1.31	1.29	5.42
Total sales and own consumption of natural gas (GGP)		18.26	13.38	13.33	15.55	60.52
Gas sales to end customers (Plenitude)		3.42	0.95	0.61	1.86	6.84
Power sales to end customers (Plenitude)	(TWh)	5.10	4.49	4.77	4.43	18.79
Thermoelectric production (Enipower)		6.07	4.99	5.36	4.95	21.37
Sales of refined products - retail in Italy (Enilive)	(mmtonnes)	1.20	1.35	1.46	1.38	5.39

2021 I quarter II quarter III quarter IV quarter Full Year

Liquids production	(kbbl/d)	814	779	805	852	813
Natural gas production	(mmcf/d)	4,726	4,339	4,688	4,700	4,613
Hydrocarbons production	(kboe/d)	1,704	1,597	1,688	1,737	1,682
Sales of natural gas to third parties	(bcm)	15.51	15.48	15.49	17.14	63.62
Own consumption of natural gas		1.52	1.46	1.65	1.74	6.37
Sales to third parties and own consumption		17.03	16.94	17.14	18.88	69.99
Sales of natural gas of Eni's affiliates (net to Eni)		0.45	0.01	0.00	0.00	0.46
Total sales and own consumption of natural gas (GGP)		17.48	16.95	17.14	18.88	70.45
Gas sales to end customers (Plenitude)		3.52	1.08	0.63	2.62	7.85
Power sales to end customers (Plenitude)	(TWh)	3.66	3.89	4.22	4.72	16.49
Thermoelectric production (Enipower)		5.12	5.08	5.81	6.35	22.36
Sales of refined products - retail in Italy (Enilive)	(mmtonnes)	1.04	1.27	1.45	1.36	5.12

2020 I quarter II quarter III quarter IV quarter Full Year

Liquids production	(kbbl/d)	892	853	817	809	843
Natural gas production	(mmcf/d)	4,768	4,653	4,694	4,800	4,729
Hydrocarbons production	(kboe/d)	1,790	1,729	1,701	1,713	1,733
Sales of natural gas to third parties	(bcm)	14.37	11.95	13.96	16.17	56.45
Own consumption of natural gas		1.53	1.44	1.58	1.58	6.13
Sales to third parties and own consumption		15.90	13.39	15.54	17.75	62.58
Sales of natural gas of Eni's affiliates (net to Eni)		0.69	0.46	0.44	0.82	2.41
Total sales and own consumption of natural gas (GGP)		16.59	13.85	15.98	18.57	64.99
Gas sales to end customers (Plenitude)		3.63	0.88	0.66	2.51	7.68
Power sales to end customers (Plenitude)	(TWh)	3.28	2.74	3.07	3.40	12.49
Thermoelectric production (Enipower)		5.46	4.88	5.43	5.18	20.95
Sales of refined products - retail in Italy (Enilive)	(mmtonnes)	1.12	0.89	1.41	1.14	4.56

MAIN OPERATING DATA

2019 I quarter II quarter III quarter IV quarter Full Year

Liquids production	(kbbl/d)	887	867	893	926	893
Natural gas production	(mmcf/d)	5,157	5,230	5,379	5,379	5,287
Hydrocarbons production	(kboe/d)	1,832	1,825	1,888	1,921	1,871
Sales of natural gas to third parties	(bcm)	18.96	15.75	14.61	14.82	64.14
Own consumption of natural gas		1.62	1.43	1.65	1.55	6.25
Sales to third parties and own consumption		20.58	17.18	16.26	16.37	70.39
Sales of natural gas of Eni's affiliates (net to Eni)		0.75	0.62	0.59	0.72	2.68
Total sales and own consumption of natural gas (GGP)		21.33	17.80	16.85	17.09	73.07
Gas sales to end customers (Plenitude)		3.99	1.41	0.74	2.48	8.62
Power sales to end customers (Plenitude)	(TWh)	2.75	2.47	2.75	2.95	10.92
Thermoelectric production (Enipower)		5.56	5.18	5.86	5.06	21.66
Sales of refined products - retail in Italy (Enilive)	(mmtonnes)	1.38	1.48	1.53	1.42	5.81

2018 I quarter II quarter III quarter IV quarter Full Year

Liquids production	(kbbl/d)	885	881	886	897	887
Natural gas production	(mmcf/d)	5,358	5,359	5,008	5,321	5,261
Hydrocarbons production	(kboe/d)	1,867	1,863	1,803	1,872	1,851
Sales of natural gas to third parties	(bcm)	19.98	16.03	15.20	16.38	67.59
Own consumption of natural gas		1.59	1.34	1.58	1.60	6.11
Sales to third parties and own consumption		21.57	17.37	16.78	17.98	73.70
Sales of natural gas of Eni's affiliates (net to Eni)		0.87	0.71	0.69	0.74	3.01
Total sales and own consumption of natural gas (GGP)		22.44	18.08	17.47	18.72	76.71
Gas sales to end customers (Plenitude)		-	-	-	-	9.13
Power sales to end customers (Plenitude)	(TWh)	-	-	-	-	8.39
Thermoelectric production (Enipower)		5.50	4.67	5.88	5.57	21.62
Sales of refined products - retail in Italy (Enilive)	(mmtonnes)	1.40	1.48	1.55	1.48	5.91

‌ENI FACT BOOK 2025

ENI AT A GLANCE

OPERATING REVIEW

ANNEX 27

Operating review

GLOBAL NATURAL RESOURCES

Exploration & Production 28

Global Gas & LNG Portfolio and Power 57

TRANSITION BUSINESSES

Enilive and Plenitude 65

INDUSTRIAL TRANSFORMATION

Refining and Chemicals 77

Environmental activities 88

‌Exploration & Production

SELECTED OPERATING DATA 2025 2024 2023

TRIR (Total Recordable Injury Rate)(a)	(total recordable injuries/worked hours) x 1,000,000	0.55	0.46	0.43
of which: employees		0.73	0.18	0.48
contractors		0.50	0.52	0.41
Sales from operations(b)	(€ million)	50,367	54,440	55,773
Operating profit (loss) of subsidiaries		6,302	6,715	8,693
Proforma adjusted EBIT		11,163	13,022	13,538
Adjusted net profit (loss)		4,875	4,777	5,648
Capital expenditure		6,253	6,055	7,135
Profit per boe(c)	($/boe)	7.80	3.69	8.58
Opex per boe(e)		9.2	9.2	8.6
Cash Flow per boe		20.5	17.3	19.4
Finding & Development cost per boe(d)(e)		17.0	22.7	26.3
Average hydrocarbons realizations		53.64	57.56	59.35
Hydrocarbons production(e)	(kboe/d)	1,728	1,707	1,655
Net proved hydrocarbon reserves	(mmboe)	6,885	6,497	6,614
Reserves life index	(years)	10.9	10.4	10.6
Organic reserves replacement ratio	(%)	167	124	69
Employees at year end	(number)	9,141	9,188	9,840
of which: outside Italy		5,101	5,171	5,927
Direct GHG emissions (Scope 1)(a)	(Mt CO2eq.)	4.6	6.7	7.6
Volumes of hydrocarbon sent to routine flaring(a)	(billion Sm³)	0.0	0.1	0.2
Total volume of oil spills (>1 barrel)(a)	(barrels)	4	2,163	5,132
Re-injected production water(a)	(%)	56	51	42

KPIs refer to 100% of the operated assets, consolidated and unconsolidated, with reference to the operatorship criteria expressed in the standards for Sustainability Statement.
Before elimination of intragroup sales.
Related to consolidated subsidiaries.
Three-year average.
Includes Eni's share in joint ventures and equity-accounted entities.

In 2025, Exploration & Production delivered excellent results, among the best in the industry, driven by production growth through the addition of more valuable barrels, as well as by selective and strict discipline in capital allocation and operating expenditures. Oil & gas production grew 4% from 2024, leading to an increase of more than 7% over 2022-2025, excluding portfolio effects. The start-up of six major projects in Norway, Indonesia, Angola and Congo enabled production to reach 1.73 million boe/d. We also strengthened the pipeline, taking FIDs on four major projects, three of which are operated, reinforcing our medium-term outlook, thus reaching an organic reserve replacement ratio of more than 160%. Exploration once again confirmed its role as a key value-creation lever, delivering another year of excellent results, with approximately 900 million boe of resources, further reinforcing the Group's global leadership.

Proprietary technologies and know-how are critical enablers of growth also in the upstream business. High-performance computing, including HPC6, together with proprietary algorithms and artificial intelligence applications, supports the Group's ability to effectively manage oil and gas demand.

The business combination with PETRONAS, focused on the LNG market in Indonesia and Malaysia, is underway, with a production target of over 500 thousand boe/day by 2028. The company is on track to start operations by mid-2026.The large-scale integrated Argentina LNG project, developed in partnership with YPF and XRG, is progressing towards the final investment decision. This project will aim at monetizing the shale gas resources of Vaca Muerta.

In line with Eni's strategy focused on the rationalization of the upstream activities by rebalancing its portfolio and divesting non-strategic assets, Eni closed the divestment of an asset in Congo while finalized farm-in agreement with acquisition of additional interest in Norway (via Vår Energi), in the United Kingdom (through Ithaca Energy) as well as in Algeria and Nigeria. In addition, in January 2026 signed a binding agreement with SOCAR, the State Oil Company of the Republic of Azerbaijan, for the sale of an additional 10% stake in the Baleine project in Côte d'Ivoire.

ACTIVITY AREAS

Italy

Eni has been operating in Italy since 1926. In 2025, Eni's oil and gas production amounted to 65 kboe/d. Total developed and undeveloped acreage were 10,538 square kilometers (8,838 square kilometers net to Eni).

The cancellation of the PiTESAI in 2024 brought the legislative mining right (Titoli minerari) back to the original text, allowing in 2025 the total or partial reassignment of 10 exploration permits and 3 extension applications.

In addition, in compliance with EU Regulation 2024/1787 on the methane gas emissions reduction in the energy sector, activities to quantify methane emissions were completed in 2025 and reported to the Italian Authority MASE (Ministero dell'Ambiente e della Sicurezza Energetica). This included fugitive emissions monitoring by means of Leak Detection and Repair type 2 for each operational site as well as for shut-in and abandoned wells.

Eni's production activities in Italy are regulated by concession contracts (23 onshore and 43 offshore) and are deployed in the Adriatic and Ionian Seas, the Central Southern Apennines, mainland and offshore Sicily.

In 2025, 30% of Eni's domestic hydrocarbon production came from fields in the Adriatic and Ionian Seas, 45% from the Central Southern Apennines and approximately 25% from Sicily.

ADRIATIC AND IONIAN SEAS

Production Main fields are Cervia-Arianna, Luna, Barbara, Emilio-Donata, Clara NW and Hera Lacinia. Production is operated by means of approximately 40 fixed platforms in use and is carried by sealine to the mainland where it is input in the national gas network. The platforms and sealine facilities are subject continuously to rigorous safety control to assess their integrity.

Development Development activities concerned: (i) the production start-up of new wells in the Cervia Mare (the Cervia field) and Fauzia concessions; (ii) the installation of a new compressor facility in the Falconara gas treatment plant; (iii) optimization activities at the Antonella platform; (iv) a plug-and-abandon campaign for no longer productive wells, including those for the Ravenna CCS project, is ongoing; and

(v) local development initiatives, including the third edition of ORA! Outpost Ravenna for Energy Transition, with open innovation projects and programs in the health and social sectors in partnership with stakeholders and local authorities. In Marina di Ravenna, the collaboration with the Local Health Authority of Romagna area progressed to enhance primary healthcare services.

In addition, district upgrading, economic enhancement, educational support and environmental protection interventions were carried out in the Municipality of Crotone through Eni's voluntary contributions.

CENTRAL SOUTHERN APENNINES

Production Eni is the operator of the Val d'Agri concession in the Basilicata Region. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is treated by the Viggiano Oil Center and is subsequently sent by pipeline to the Taranto Refinery for final processing.

Development The activities of the year in the Val d'Agri Concession concerned: (i) the filing of "Variazione Programma Lavori" to the relevant authorities for the development program of the northern part of the field; and (ii) production optimization actions to mitigate production decline. In addition activities of the New Memorandum of Intent between Eni, Shell and the Basilicata Region progressed and included "non-oil" projects for local development as well as initiatives defined with the agreement with the Basilicata Region within the LucAS (Lucani Ambiente e Salute) project.

SICILY

Production Eni operates 11 production concessions onshore and 3 offshore in Sicily. The main production fields are Argo/Cassiopea, Gela, Giaurone and Bronte.

Development Within the development program of the Argo Cassiopea project in the Sicilian offshore, the activities of the year concerned: (i) the completion of the Cassiopea onshore plants; and (ii) the "Variazione Programma Lavori" for the Gemini development project has been submitted to the relevant authorities. In addition, activities have been launched to assess exploration potential of the permit nearby to the Argo Cassiopea concession, including the Panda discovery.

Within local support initiatives: (i) the Implementation Agreement for renovation program in the Gela area was signed; (ii) the Cooperation Agreement with Banco Alimentare has been renewed, in continuity from 2023, supporting the disadvantages communities; and (iii) the "Musei in Rete - Digitalizzare I Beni Culturali" project was launched in collaboration with the Eni Enrico Mattei Foundation and local stakeholders.

Rest of Europe

NORWAY

Eni has been present in Norway since 1965 and the activities are conducted through the Vår Energi associate (Eni's interest 63.1%). Activities are performed in the Norwegian Sea, in the North Sea and in the Barents Sea, on a total developed and undeveloped acreage of 38,196 square kilometers (9,146 square kilometers net to Eni).

Exploration and production activities are regulated by concession contracts (Production License, PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a given number of years with possible extensions.

Production Eni's production amounted to 214 kboe/d in 2025.

In 2025, an additional participation stake was acquired in the Ekofisk producing project in the PL018F development license and thus Vår Energi's interest to approximately 52% in the Greater Ekofisk Area. The transaction is subject to the necessary approvals.

Development During 2025, production start-up was achieved at: (i) the Johan Castberg oil fields which includes the Skrugard, Havis and Drivis discoveries made between 2011 and 2014. The field will be producing for 30 years, with an expected production peak of 220 kbbl/d; (ii) the Balder-X oil field in Norwegian offshore with a peak production of about 80 kboe/d already reached during 2025; (iii) the Askeladd West gas field to ensure full capacity of the Hammerfest LNG plant in the next years.

Exploration Exploration activity yielded positive results with five commercial discoveries, in particular with: (i) the Vidsyn exploration well in the PL586 license in the Norwegian Sea; (ii) the Drivis Tubåen exploration well in the PL532 license in the Barents Sea nearby to the Johan Castberg field; (iii) the Goliat Ridge discoveries, adjacent to the Goliat producing field in the Barents Sea. Evaluation activities are underway for fast-track development; (iv) the F Sør exploration well in the PL090 license in the North Sea and of the Smørbukk Midt exploration well in the PL094 license in the Norwegian Sea, the latter already in production leveraging on the existing facilities in the area.

NETHERLANDS

Eni has been present in Netherlands since 2024 as part of the Neptune Energy acquisition. Eni's activities are carried out in the North Sea including 29 offshore facilities with 4 major treatment hubs. The total developed and undeveloped acreage was 4,137 square kilometers (1,514 square kilometers net to Eni).

Exploration and production activities are regulated by license contracts (Production License, Exploration License) that authorize the holder to carry out seismic surveys, drilling and production activities until the contractual expiry, with the possibility of renewal.

Production Eni's production amounted to 13 kboe/d in 2025 and mainly comes from the F3, G-blocks, K2b-A, K9ab-B, L12-L15, L10/K12, L5 hub, Q13a-A and K6-D fields.

Development The activities of the year concerned: (i) the Final Investment Decision (FID) of the L7-F gas development project, production start-up is expected in 2026; (ii) the drilling of the L10-M4 development well, with production expected in 2026.

UNITED KINGDOM

Eni has been present in United Kingdom since 1964 and the activities are conducted through the Ithaca Energy joint venture (Eni's interest 35.92%).

Total developed and undeveloped acreage was 9,767 square kilometers (4,178 square kilometers net to Eni). Exploration and production activities in the UK are regulated by concession contracts.

Production Eni's production amounted to 45 kboe/d in 2025. The Ithaca Energy joint venture holds interests in 39 fields, of which 10 operated, located in the North Sea.

Development During 2025, the farm-in agreements were completed in: (i) the Seagull field with acquisition of 15% interest and in the Cygnus field with an additional stake acquisition of 46%; (ii) the Tobermory gas discovery to acquire 50% interest in the West of Shetland basin.

Development activities concerned: (i) production start-up of additional wells at the Captain, Cygnus and Seagull producing fields; (ii) production optimization activities in the J-Area project; and (iii) the development program of the Rosebank project.

North Africa

ALGERIA

Eni has been present in Algeria since 1981. Developed and undeveloped acreage was 59,575 square kilometers (21,309 square kilometers net to Eni).

In 2025, 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 square kilometers 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.

Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts. Production Eni's production amounted to 131 kboe/d in 2025 and mainly comes from the blocks: (i) Blocks 403a/d, Block ROM North, Blocks 401a/402a, Block 403 and Block 405b; (ii) the Sif Fatima II, Zemlet El Arbi and Ourhoud II blocks in the Berkine North basin; (iii) Berkine South block; and (iv) In Amenas and In Salah concessions located in the Southern Sahara, as well as Touat concession in the Western Sahara.

During the year, an additional stake in the Touat license was acquired, increasing Eni's interest to 42.9%.

Development Development activities mainly concerned the start-up of new producing wells and production optimization activities by means of workover program and plant upgrading of existing facilities.

EGYPT

Eni has been present in Egypt since 1954. Developed and undeveloped acreage was 36,486 square kilometers (12,449 square kilometers net to Eni). In 2025 signed agreements with Cyprus and Egypt counterparties to develop gas reserves of the Chronos discovery in the Block 6 offshore Cyprus, to be exported to international markets through Eni's existing facilities located in Egypt. The agreements are an important milestone on the path to the sanctioning of the project, and they foresee treatment and liquefaction through the processing plants facilities of the Zohr field and the liquefaction capacity at the Damietta LNG plant.

Exploration and production activities in Egypt are regulated by Production Sharing Agreements.

Production In 2025, Eni's production amounted to 242 kboe/d and mainly comes from: (i) the Shorouk block in the Mediterranean offshore with the giant Zohr gas field; (ii) the Sinai concession, mainly in the Belayim Marine-Land, Abu Rudeis and Sinai Ras Gharra fields; (iii) the Western Desert in the Melehia, East Obayed and South West Meleiha concessions; and (iv) Baltim, North El Hammad, Nile Delta, North Port Said and Temsah concessions. In addition, Eni participates in the Ras el Barr and South Ghara concessions. Gas production from the Nile Delta, Temsah, North Port Said and Ras el Barr is supplied to the plant owned by United Gas Derivatives Co (Eni 33.33%) where, after condensate extraction, the residual gas is fed back into the GASCO national grid.

Development Development activities mainly concerned: (i) production optimization and drilling activities in the Mediterranean offshore; and

(ii) ongoing construction activities of the gas plant in the Western Desert area as provided by the development plan.

In 2025, Zohr production was optimized through activities of reservoir and network management. The drilling campaign performed in 2025 was successfully executed and new optimization opportunities are under definition for 2026.

Local development initiatives concerned: (i) the University Education project in Energy Engineering Technology, carried out in collaboration with the Politecnico di Milano and Eni Corporate University in the Port Said area; (ii) in the healthcare sector, the Advanced Professional Training Center, established in collaboration with the Ministry of Health and Population (MoHP) in Port Said, provided training of local staff to fill key gaps in medical specialties and to enhance the clinical skills of healthcare staff at the national level; (iii) projects in the agricultural sector in the Governorates of South Sinai and Matrouh for communities in areas with high desertification, as well as the Towards Organic Agriculture project to support small farmers in the transition to organic farming.

Exploration Exploration activity yielded positive results in the Western Desert concessions. The discoveries were already put into production and achieving production ramp-up in the area. In addition, in April 2026, Eni announced a significant gas and condensate discovery with the successful drilling of the Denise W 1 exploration well in the Temsah Concession, located offshore in the Eastern Mediterranean. Preliminary estimates indicate about 2 trillion cubic feet (Tcf) of gas in place and 130 mmbbl of associated condensates. The discovery is nearby existing production facilities providing significant synergies for fast-track development.

LNG business Eni holds interest in the Damietta liquefaction plant with a capacity of 5.2 mmtonnes/y of LNG associated to approximately 283 bcf/y of feed gas.

LIBYA

Eni has been present in Libya since 1959. Exploration and production activity is carried out in the Mediterranean Sea facing Tripoli and in the Libyan Desert area. Developed and undeveloped acreage were 80,048 square kilometers (24,644 square kilometers net to Eni).

In 2025, a relatively stabler sociopolitical environment than in previous years, allowed continuity to production operations and to develop projects, despite the political landscape of the Country has remained split between the Government of National Unity installed in Tripoli and recognized by the UN and the self-appointed National Stability Government installed in the east of the Country and has resulted in several disputes and reciprocal claims. For further information see "Risk factors and uncertainties" in the Annual Report 2025.

Exploration and production activities in Libya are regulated by Exploration and Production Sharing Agreement contracts (EPSA).

Production In 2025, Eni's production amounted to 162 kboe/d and represented approximately 10% of the Group's total production. Production mainly comes from 6 contract areas: (i) Area C, with the Bouri oil field and Area D, with Block NC 41 in the offshore area; and (ii) Area A, consisting in the former concession 82; Area B, former concessions 100 (Bu-Attifel field) and the NC 125 Block; Area E, with the El Feel field; and Area D with Block NC 169 in the onshore area.

Development In 2025 development activities mainly concerned: (i) in the Sabratha Compression project to support current production of the Bahr Essalam field, offshore activities advanced with the installation of the compression unit in the Sabratha platform; (ii) the Bouri Gas Utilization Project is ongoing as provided for the development plan, with start-up expected in 2026; and (iii) the drilling activities at the A&E Structures project as well as the construction activities of the Structure A platform were started. In addition during the year: (i) the professional training project progressed in partnership with the International Organization for Migration to increase employment opportunities; (ii) a project for the preservation and promotion of cultural heritage was launched; (iii) in the healthcare sector, a program was started in the Jalo area to strength and improve the quality of services.

Exploration Exploration activities yielded positive results in March 2026 with the Bahr Essalam South 2 (BESS 2) and Bahr Essalam South 3 (BESS 3) offshore discoveries. Preliminary estimates indicate that these discoveries jointly contain more than 1 Tcf of gas in place. Their proximity to the existing production facilities of the Bahr Essalam field will ensure a fast-track development.

In February 2026 Eni was awarded the O1 offshore exploration license through a consortium with another partner. Eni will be the operator.

TUNISIA

Eni has been present in Tunisia since 1961. Eni's activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet, over a developed and undeveloped acreage of 5,776 square kilometers (2,106 square kilometers net to Eni).

Exploration and production in this Country are regulated by concessions.

Production In 2025, Eni's production amounted to 6 kboe/d and mainly comes from the Adam, Oued Zar and Djebel Grouz onshore concessions. In addition, Eni holds interest in the MLD and El Borma concessions.

Development In 2025, Eni was awarded a 35% stake in the Sabeh concession.

The activities of the year mainly concerned: (i) the development activities of the Sabeh concession; (ii) a production optimization program in the Adam, MLD and El Borma concessions; (iii) the start of development drilling activities in the Djebel Grouz concession; and (iv) the program to support local development, mainly with the installation of photovoltaic panels in 14 public schools.

Sub-Saharan Africa

ANGOLA

Eni has been present in Angola since 1980 and operates through Azule Energy, the equally owned joint venture by bp and Eni.

Azule Energy holds interests in 17 blocks (of which 9 exploration blocks) and one exploration license in Namibia as well as in the Angola LNG JV and Solenova, a solar company jointly held with Sonangol which is operating in the renewable energy business and in decarbonization initiatives. In particular, Solenova operates the 25 MW photovoltaic plant in Caraculo, located in the province of Namibe.

Activities are performed over a developed and undeveloped acreage of 50,890 square kilometers (9,421 square kilometers net to Eni). Exploration and production activities in Angola are regulated by concessions, PSAs, and Risk Service Contract.

Production In 2025 production amounted to 106 kboe/d net to Eni.

In 2025, Azule signed a farm-out agreement to sell its 20% stake in Block 14 and 10% in Block 14K/A-IMI. The transaction is subject to approval by the relevant authorities.

In the year, production started at the operated Agogo Integrated West Hub project, in block 15/06, offshore Angola. The project consists in the development of two fields, Agogo and Ndungu, with an expected production plateau of 180 kboe/d. In February 2026 full-field production start-up was achieved at the Ndungu field, just six months after Agogo FPSO first oil. The project comprises seven production wells and four injection wells, with an expected oil production peak of 60 kbbl/d.

Development The development activities concerned: (i) the NGC (New Gas Consortium) project to develop the Quiluma and Maboqueiro fields. The project, the first non-associated gas development in the Country, completed the installation and commissioning of two offshore production platforms as well as the gas and condensate treatment and export plant to the A-LNG plant. The estimated production plateau is approximately 330 mmCF/d and 18 kbbl/d of condensates. First gas production into plant was reached in February 2026 and in March 2026 the start of gas delivery from the Quiluma field; (ii) the Greater PAJ project to develop the southern area of the two operated blocks 31 and 31/21. The project's final approval by the partners is expected in 2026.

During 2025, programs to support local development progressed by means of certain initiatives on promoting access to water and sanitation, community health, education, social inclusion, economic diversification, access to solar energy, environmental protection and demining. In particular: (i) in the educational field, 3 new schools were opened and 10 schools were renovated; (ii) extension agreement was signed to support the cardiological care improvement in the country's healthcare facilities, as well as 2 new medical facilities were inaugurated while the renovation of 9 others was completed; (iii) international healthcare capacity building programs progressed to enhance the skills of hospital healthcare staff by means of specialized training activities in five hospitals in Luanda, involving Italian Centers of Excellence; and (iii) projects for environmental protection have been implemented.

Exploration The exploration activity yielded positive results: (i) with the first dedicated gas exploration well, Gajajeira-01; and (ii) in February 2026, with the Algaita-01 oil well in the offshore Block 15/06. Preliminary estimates indicate oil in place of around 500 million barrels. Existing production facilities further enhance the value of this discovery.

CONGO

Eni has been present in Congo since 1968. Eni's activities are concentrated in the conventional and deep offshore facing Pointe-Noire and onshore Koilou region over a developed and undeveloped acreage of 1,838 square kilometers (978 square kilometers net to Eni).

In March 2025, Eni and Vitol agreed on the economic terms of the possible farm-out of a 25% stake held by Eni in the operated Congo FLNG project. The closing of the transaction is subject to customary regulatory approvals and other conditions.

During the year, Eni closed the divestment of onshore producing licenses in the country, in line with strategy of rationalizing the upstream portfolio. Exploration and production activities in Congo are regulated by Production Sharing Agreements.

Production In 2025, Eni's production amounted to 69 kboe/d and mainly comes from the Néné-Banga Marine and Litchendjili (Block Marine XII), Kitina and Yanga Sendji fields as well as the Congo LNG project to monetize the Block Marine XII resources.

Development It was inaugurated the new Yasika logistics platform, a strategic infrastructure within the Phase 2 development program of the Congo LNG project. The platform supports the operations for the two floating liquefaction units: Tango FLNG (0.6 mmtonnes/year), which began production in December 2023, and Nguya FLNG (2.4 mmtonnes/year), with production start-up achieved at the end of 2025, marking the completion of the Phase 2 to enhance the gas potential of the Marine XII permit and to increase the production capacity to 3 MTPA. Within the local development initiatives: (i) the Oyo Center of Excellence for Renewable Energy and Energy Efficiency (CEO) reached full operational capacity during the year; (ii) awareness programs on the deployment of renewable energy technologies progressed to support the Country's socio economic development; (iii) the integrated program in the HINDA district progressed targeting interventions for rural communities by means of education and health initiatives, access to water resources, and supporting the agricultural sector.

CÔTE D'IVOIRE

Eni has been present in Côte d'Ivoire since 2015 and activities are concentrated in the offshore of the Country, with a developed and undeveloped acreage of 13,183 square kilometers (10,760 square kilometers net to Eni).

Within Eni's strategy of optimizing its upstream portfolio by accelerating the monetization of exploration discoveries through the divestment of equity stakes, in September 2025 Eni finalized the sale of a 30% stake in the Baleine project to Vitol and in January 2026 Eni signed a binding agreement with SOCAR, the State Oil Company of the Republic of Azerbaijan, for the sale of an additional 10% stake in the project. In October 2025, Eni signed an exploration contract 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 2025 Eni and Petroci announced a significant increase in gas supply for Côte d'Ivoire's power generation system. The produced gas, up to 70 mmcf/d, will be entirely allocated to meet local demand, ensuring a reliable supply for the Country's power generation needs and further reinforcing Côte d'Ivoire's role as a regional energy hub.

Exploration and production activities in the Country are regulated by Production Sharing Agreements.

Production In 2025 Eni's production amounted to 50 kboe/d and comes from the Baleine offshore project which is located in the CI-101 and CI-802 blocks.

Development The development activities of the year included: (i) the completion of the Phase 2 project at the Baleine field; and (ii) the Phase 3 concept definition activities of the Baleine development program. The final investment decision (FID) is expected to be sanctioned in 2026. The Phase 3 project provides for increasing production capacity to an expected peak of 150 kbbl/d and approximately 200 mmcf/d of associated gas for domestic needs.

In addition, within the Baleine project, local development activities concerned: (i) initiatives to support 20 healthcare centers including facilities renovation, energy infrastructure development, and medical and equipment supply; (ii) professional training programs to promote youth employment, particularly through collaboration with the Iveco Group; (iii) economic diversification, access to education, and school equipment supply initiatives.

Exploration Exploration activity yielded positive results: (i) with the drilling of the Cachalot-1X well, which confirmed the eastern extension of the Baleine field; and (ii) in February 2026, with the offshore Murene South-1X gas and condensate well (Eni operator with a 90% interest) confirming the exploration potential of the Calao gas complex with estimated volumes of 5 Tcf of gas and 450 million barrels of condensates.

GHANA

Eni has been present in Ghana since 2009. Developed and undeveloped acreage in deep offshore was 1,172 square kilometers (502 square kilometers net to Eni). Eni is the operator with a 44.44% interest of the Offshore Cape Three Points (OCTP) permit which is regulated by a concession agreement and also operates with a 42.47% interest the offshore exploration license Cape Three Points Block 4 (CTP-4).

Production In 2025 Eni's production amounted to 35 kboe/d and comes from the Sankofa field in the OCTP permit.

In September 2025, 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 particular, the development project provides for the linkage to the existing facilities in the OCTP permit and was submitted for approval by the Country's authorities at the end of 2025.

Development Development activities of the year mainly concerned the OCTP producing permit: (i) workover activities at the wells of the Sankofa East field; (ii) the debottlenecking activities of the non-associated gas system were completed and thus increasing capacity; (iii) tenders were launched for awarding contracts of the linkage of the new GyeNyame non-associated gas well to existing FPSO; (iv) the Afforestation Project progressed within environmental protection initiatives; and (v) access to water and sanitation programs as well as healthcare initiatives including community awareness campaigns, particularly in the western area of the Country.

Exploration Exploration yielded positive results with the Eban 2A well and thus marking the close of the appraisal campaign Eban-Akoma field in the Cape Three Points 4 block with the formalization to the Government.

MOZAMBIQUE

Eni has been present in Mozambique since 2006, following the award of the exploration license relating to Area 4 offshore the Rovuma Basin block, located in the north of the Country. The Rovuma Basin represents a new frontier in the oil and gas industry thanks to extraordinary gas discoveries made during intense only three-year exploration campaign. To date, resource base reached 85 Tcf.

Developed and undeveloped acreage is 3,912 square kilometers (916 square kilometers net to Eni).

Production Production comes from the Coral South project located in the Area 4 block, first production start-up in the Country to develop gas discovery in the Rovuma offshore area. In 2025 production amounted to 25 kboe/d net to Eni. Production is sent to the Coral Sul Floating

Liquefied Natural Gas (FLNG) vessel for the treatment, liquefaction, storage and export, with a capacity of approximately 3.4 mmtonnes/y of LNG. The Coral Sul FLNG was designed to high standards in terms of safety and sustainability, demonstrating Eni's commitment to ensure the safety of people, the protection of the surrounding environment and local communities as well as asset integrity. The vessel was implemented with an energy-efficiency approach and CO2 emission reduction. In particular, the Coral Sul FLNG achieves also zero flaring during normal operations and uses gas efficient turbines to power generation.

Development In October 2025, Eni and its partners reached the Final Investment Decision (FID) 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 January 2026, the sail away of the Coral North floating LNG was achieved, fully in line with the project schedule, with 3.6 MTPA production capacity, bringing the Country's total LNG production to 7 MTPA.The project will leverage Eni's fast-track approach and expertise from the Coral South project and is expected to achieve start-up at the end of 2028.

During the year initiatives to support local communities progressed with: (i) programs to promote schooling and youth employment in the Pemba district, as well as initiatives to improve access to drinking water in the districts of Pemba, Mecufi, and Metuge; (ii) activities to enhance social and health services, also by means of training programs. In particular, a new Intensive Care unit and a CT scanner were put into operation in the Cabo Delgado Province, and renovation activities progressed with two maternity wards and facilities providing accommodation for pregnant women, and three ambulances were supplied in the Maputo Province; and (iii) economic development programs in the agricultural and fisheries sectors in the provinces of Cabo Delgado and Manica, as well as biodiversity protection initiatives in the Mecufi district.

NIGERIA

Eni has been present in Nigeria since 1962. Total developed and undeveloped acreage was 18,306 square kilometers (4,358 square kilometers net to Eni).

In March 2026, Eni signed an agreement between the Federal Government of Nigeria and Eni on the conversion of Oil Prospecting Licence 245 (OPL 245). The agreement includes the mutually satisfactory settlement of all claims related to OPL 245 and the discontinuation of the international arbitration proceeding; as a consequence, it allows the conversion of the existing license into two development licences, Petroleum Mining Leases (PML) 102 and 103, and two exploration licences, Petroleum Prospecting Leases (PPL) 2011 and 2012, to Nigerian Agip Exploration Limited (NAE) as operator, alongside its partners Nigerian National Petroleum Company Limited (NNPC) and Shell Nigeria Exploration and Production Company Limited (SNEPCO).

Exploration and production activities in Nigeria are regulated by Production Sharing Agreements and concession contracts.

Production In 2025 Eni's production amounted to 48 kboe/d and comes from the Abo field (OML 125), the Bonga field (OML 118) and as partners of Renaissance Africa Energy Company Limited JV (RAEC JV; former SPDC JV), Eni holds a 5% interest in 18 blocks.

In November 2025, Eni acquired an additional 2.5% stake in the Production Sharing Contract (PSC) OML 118, exercising its preemption right. Development The development activities of the year concerned the Bonga North project in the OML 118 block, which includes the linkage of new subsea wells to the existing FPSO.

LNG business Eni holds a 10.4% stake in Nigeria LNG Ltd, which owns and runs the Bonny natural gas liquefaction plant in the Eastern Niger Delta. The plant has a production capacity of 22 mmtonnes/y of LNG associated, corresponding to approximately 1,270 bcf/y of feed gas. The natural gas supplies to the plant are currently provided under a gas supply agreement from the RAEC JV (former SPDC JV), TEPNG JV and Oando Energy Resources Nigeria Limited JV. The volumes treated by the plant during 2025 amounted to approximately 830 bcf. LNG production is sold under long-term contracts in the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Ltd as well as is sold FOB by means of the fleet owned by third parties.

Kazakhstan

Eni has been present in Kazakhstan since 1992. Eni's activities are performed mainly in the Kashagan and Karachaganak producing fields, over a developed and undeveloped acreage of 4,896 square kilometers (1,273 square kilometers net to Eni). In 2025 Eni's production amounted to 161 kboe/d.

KASHAGAN

Eni holds interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the giant Kashagan field, which was discovered in the Northern section of the contractual area in the year 2000.

Production The liquid production is stabilized at the Bolashak plant and then marketed. Gas production is partly processed and sold to the national oil company, while the raw gas volumes (approximately 50%) is re-injected in the reservoir.

Development Development plans envisage a phased increase in the production capacity. The first development phase provides for a progressive increase up to 450 kbbl/d. The activities, sanctioned in 2020, include the upgrading of management capacity of associated gas by means of: (i) increasing gas reinjection capacity by upgrading existing facilities, which was completed in 2022; and (ii) installation of a new onshore treatment unit operated by a third party, currently under construction, for the remaining part of associated gas volumes.

KARACHAGANAK

Located onshore in West Kazakhstan, Karachaganak is a liquid and gas giant field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA.

Production This field produces liquids from the deeper layers of the reservoir. The gas is delivered (about 45%) to the Russian gas plant of Orenburg; management believes this transaction does not violate the current sanction regime imposed to Russia following the military invasion of Ukraine. The remaining gas volumes are utilized for re-injection in the higher layers of the reservoir and as fuel gas. Almost the entire liquid production is stabilized at the Karachaganak Processing Complex (KPC) and exported to Western markets through the Caspian Pipeline Consortium (Eni's interest 2%) and the Atyrau-Samara pipeline, this latter also a new route opened in 2023 leading to Germany.

Development In 2025 activities progressed with the installation of a sixth compression unit, last development phase, sanctioned in 2022. Start-up is expected in 2026. Local development initiatives included: (i) the construction and opening of a collection and processing center for agricultural products in Aksai; (ii) the project definition for the prevention and mitigation of natural disaster impacts, with implementation expected to begin in 2026; (iii) technical training programs.

Rest of Asia

INDONESIA

Eni has been present in Indonesia since 2001. Activities are concentrated in the offshore of East Kalimantan, over a developed and undeveloped acreage of 17,138 square kilometers (11,871 square kilometers net to Eni).

In November 2025 Eni signed a binding agreement with Petronas, Malaysian state-owned company, to establish a jointly controlled venture to combine the two partners' gas-rich production and development assets of Indonesia and Malaysia. The new company will be financially self-sufficient entity and able to generate operational and financial synergies to deliver one of the main players on the LNG market and plans to grow to over 500 kboe/d of production in the medium term. The transaction completion is subject to governmental, regulatory, and partner approval. Exploration and production activities are regulated by Product Sharing Agreements.

Production In 2025 Eni's production amounted to 92 kboe/d, mainly gas and mainly comes from: (i) the Jangkrik and Jangkrik North gas fields in the Muara Bakau block. Production is ensured by means of twelve subsea wells linked to the Floating Production Unit (FPU). Natural gas production is processed by the FPU and then delivered by pipeline to the onshore plant, which is linked to the East Kalimantan transport system to feed Bontang liquefaction plant. The LNG is sold under long-term contracts, partly to state company Pertamina and to Eni, which will sell over the Asiatic market;

(ii) the Merakes gas field in the East Sepinggan block. Production flows from five subsea wells which are tied-back to the FPU of the Jangkrik producing field. Natural gas production is processed by the FPU and then delivered via pipeline to the onshore plant, which is connected to the East Kalimantan transport system to feed the Bontang liquefaction plant or sold to the domestic market; and (iii) the Merakes East field in the East Sepinggan block where production start-up was achieved in May 2025 with initial rate of approximately 18 kboe/d to Eni's production. Natural gas and condensates production is processed by the FPU of West Seno field and then delivered by pipeline to the Santan onshore plant which is linked to the East Kalimantan transport system to feed the Bontang liquefaction plant or sold to the domestic market.

Development In the year development activities concerned: (i) the definition of integrated project of the Geng North and Gehem fields within the North Hub development, in the Kutei area. These fields will be put into production by means of subsea wells, flowlines and a new FPSO. Natural gas will be treated by the FPSO and will be carried to onshore facilities linked to the East Kalimantan pipeline network. The production will be delivered to the Bontang LNG plant and exported; a part of gas production will be destined to fulfil domestic needs. The condensates production will be stabilized and stored by the FPSO and then lifted; (ii) the definition of the Gendalo and Gandang gas project (South Hub). The development program of two fields provides for the drilling of new subsea wells and the tie-back connection to existing facilities of the Jangkrik production fields; (iii) the execution of the Maha project where two new subsea wells will be put into production by means of tie-back connection to existing facility of Jangkrik field; (iv) projects supporting local communities in the primary education, access to water and renewable energy areas, and economic diversification and training activities in the Samboja and Muara Jawa areas in the Easter Kalimantan; and (v) community health initiatives, including the sanitation facilities renovation, first aid training courses, support for an infectious disease ward development, and the medical equipment supply.

In March 2026, Eni achieved the Final Investment Decisions (FIDs) for the Gendalo and Gandang gas project (South Hub) and for the Geng North and Gehem fields (North Hub), only 18 months after the approval of the Projects of Development (PODs) in 2024. The projects will leverage on the existing infrastructure, including the Jangkrik Floating Production Unit (FPU) and the Bontang liquefaction plant.

Exploration Exploration activities yielded positive results with: (i) the Konta-1 well in the Muara Bakau block with a significant gas and condensates discovery where a production test has been successfully performed. This discovery is nearby existing facilities of the Jangkrik production field, providing significant synergies for the development; and (ii) the Kadal-1 gas well in the East Ganal block (Eni's interest 100%), with an option for a development program in synergy with the Maha project.

In addition, in April 2026, Eni announced a giant gas and condensate discovery, at the Geliga-1 (Eni 82%) well located in the Ganal block in the Kutei basin, offshore Indonesia. Preliminary estimates indicate in-place resources of approximately 5 Tcf and 300 mmbbl of condensate allowing the possible development of a third production hub in the prolific Kutei basin. Geliga is located only 20 km from Geng North, confirming the significant potential in the basin. Also, proximity to existing and planned infrastructure offers potentially significant development cost synergies and an accelerated time-to-market.

IRAQ

Eni has been present in Iraq since 2009 and is performing development activities over a developed acreage of 1,074 square kilometers (446 square kilometers net to Eni).

Development and production activities are regulated by a technical service contract.

Production Production comes from Zubair oil field with a production of 47 kboe/d net to Eni in 2025.

Development Activities comprised the execution of an additional development phase of the ERP (Enhanced Redevelopment Plan) at the Zubair field. Main facilities have already been installed. Ongoing development activities include programs to expand water availability to maintain adequate reservoir pressurization in the long-term and to increase water treatment and re-injection capacity. In particular, at the end of 2025 it has been initiated the phased start-up of the Zubair Mishrif Expansion project. This project includes four oil treatment units for a total capacity of 200 kboe/d to ensure the replacement of existing production facilities and an additional water injection capacity of 750 kboe/d. In addition, a program to achieve technical zero flaring by 2027 is being implemented. The field reserves will be progressively put into production by drilling additional productive wells over the next few years and by means of the collection facilities expansion and the completion of the water reinjection wells.

During the year, Eni continued its commitment to local development through projects in the areas of education, healthcare and access to water. In particular: (i) the second development phase of the Al-Buradeiah plant to supply drinking water was completed in Bassora; and (ii) the construction start-up of two school buildings in Zubair.

QATAR

Eni has been present in Qatar since 2022, following the acquisition of the 3% interest in the giant North Field Est LNG project. The project includes the construction of 4 trains with a combined liquefaction capacity of 32 mmtonnes/year. Production start-up is expected in 2026, and development program includes the most advanced technologies and processes to minimize overall carbon footprint.

Development activities and production and export of LNG and other products are operated by QatarEnergy LNG, a subsidiary of QatarEnergy, partecipated by Eni and other international companies.

In 2023 Eni signed a long-term LNG supply contract with QatarEnergy LNG for the delivery of up to 1.5 bcm/y of LNG.

TURKMENISTAN

Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused on the onshore Nebit Dag Area in the Western part of the Country, over a developed acreage of 200 square kilometers (180 square kilometers net to Eni). Exploration and production activities in Turkmenistan are regulated by Production Sharing Agreement.

Production In 2025 Eni's production amounted to 14 kboe/d and derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receives, by means of a swap arrangement with the Turkmen Authorities, an equivalent amount of oil at the Okarem terminal, close to the South coast of the Caspian Sea. Eni's entitlement is sold FOB. Associated natural gas is used for fuel gas and is delivered to the national oil company Turkmenneft, via national grid.

Development Development activities mainly concerned: (i) the drilling of nine infilling and peripheral wells; and (ii) the conversion of five wells to water injectors to maximize hydrocarbon recovery.

UNITED ARAB EMIRATES

Eni has been present in United Arab Emirates since 2018 over a developed and undeveloped acreage of 20,591 square kilometers (9,140 square kilometers net to Eni).

Production In 2025 Eni's production amounted to 64 kboe/d and mainly comes from the Lower Zakum and the Umm Shaif and Nasr fields in the Abu Dhabi offshore as well as the Mahani field in the Area B concession in the Emirate of Sharjah.

Development In June 2025, the new Production Concession license of the offshore Block 2 to develop the Waset field (Eni's interest 28%) was approved by the Country's Authority.

Activities of the year mainly concerned: (i) the development program of the Ghasha offshore concession to put into production the Dalma, Hail and Ghasha fields. In particular, the Dalma Gas project is being finalized while activities progressed at the Hail & Gasha project, sanctioned in 2023, according to the development plan; and (ii) ongoing development activities to support the increasing production at the Lower Zakum and Umm Shaif/Nasr concessions.

Americas

MEXICO

Eni has been present in Mexico since 2015 and is performing exploration and development activities over a developed and undeveloped acreage of 5,232 square kilometers (3,336 square kilometers net to Eni). Eni's activities are concentrated in 8 blocks, of which 7 are operated, in the offshore Gulf of Mexico.

In 2025 Eni started the relinquishment of the Area 14 and Area 28 licenses in line with strategy of rationalizing the upstream exploration portfolio. Formalization process by the relevant Authorities is ongoing.

Exploration and production activities in Mexico are regulated by PSAs and concession contract for the Area 24 license.

Production In 2025 production amounted to 49 kboe/d net to Eni and comes from the Area 1 production license where are located the Amoca, Miztón and Tecoalli fields.

Development Development activities of the Area 1 producing project concerned: (i) the drilling of five development wells; and (ii) ongoing infilling program to optimize hydrocarbons recovery.

Within the collaboration agreements with national authorities, initiatives supporting local communities progressed with agricultural, fisheries and healthcare programs, including environmental and social awareness campaigns.

UNITED STATES

Eni has been present in the United States since 1968 and activities are performed in the Gulf of Mexico.

At December 31, 2025, Eni holds interests in 39 exploration and development blocks in the conventional and deep offshore of the Gulf of Mexico, of which 16 are operated by Eni, over a developed and undeveloped acreage of 749 square kilometers (348 square kilometers net to Eni).

Exploration and production activities in the United States are regulated by concessions.

Production In 2025 production amounted to 22 kboe/d net to Eni and mainly comes from the Allegheny, Appaloosa, Pegasus, Longhorn, Devils Towers, Triton operated fields as well as the Europa, Medusa, Lucius, Frontrunner and Heidelberg non-operated fields.

Development Activities of the year concerned production optimization at the Devil's Tower and the Lucius and Europa fields.

VENEZUELA

Eni has been present in Venezuela since 1998. Activity is concentrated both offshore (Gulf of Venezuela and Gulf of Paria) and onshore in the Orinoco Oil Belt, over a developed and undeveloped acreage of 2,805 square kilometers (1,066 square kilometers net to Eni). In 2025, Eni's production of oil and natural gas averaged 64 kboe/d and accounted for approximately 4% of Eni's total production.

The political and economic crisis in Venezuela continued for years, influenced by the sanctions imposed by the US on exports crude oil targeting the Venezuelan government and the state oil company PDVSA. Eni's activities in the Country include the Perla offshore gas field, operated by the local joint venture Cardón IV SA, equally participated by Eni and other international oil company, where equity volumes of natural gas supplied to the national oil company of Venezuela. Other petroleum interests held by Eni in the Country comprise oil licenses in the Orinoco Belt, operated under the "Empresa Mixta" regime, where production is declining and their carrying amounts were fully impaired in prior years. Eni is exposed to credit exposure to recover its investment in Cardón IV due to the financial difficulties of PDVSA following the U.S. sanctions regime in force through 2025. However, in early 2026 certain developments were recorded in the relations between Venezuela and the United States, which are expected to improve the outlook for the Country's oil sector. These developments could, compared with the past, partially mitigate the uncertainty of the operating environment in relation to the recovery of Eni's trade receivables from the state-owned oil company PDVSA and may give rise to potential business opportunities, subject to the evolution of the relevant regulatory and operating conditions. At the end of January 2026, the National Assembly approved a partial reform of the Organic Hydrocarbons Law which includes the renegotiation of existing oil contracts in relation to the Empresa Mixta regime, a new taxation system, and the proposal to strengthen legal safeguards for investment by introducing the possibility of resorting to independent mediation and arbitration mechanisms. In addition, the USA Authority issued "general licenses" enabling