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 2023

2023 AT A GLANCE	2
Main data	4
Eni share performance	7

NATURAL RESOURCES	10
EXPLORATION & PRODUCTION	12
GLOBAL GAS & LNG PORTFOLIO	66

ENERGY EVOLUTION	74
ENILIVE, REFINING AND CHEMICALS	76
PLENITUDE & POWER	94
ENVIRONMENTAL ACTIVITIES	102

ANNEX	105
TABLES	106
Financial Data	106
Employees	122
Quarterly information	123

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, forwardlooking 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.

2023 at a glance

" 2023 was another year of excellent results for Eni in the face of an uncertain and volatile scenario. We delivered strongly on both financial and operational targets and we continued to progress our strategy of generating value while decarbonizing and ensuring secure and affordable energy supplies to markets. Our results were underpinned by our distinctive satellite model that continues to prove to be an effective lever in accelerating growth and value creation. We have completed the acquisition of Neptune which with its gas weighted portfolio strongly synergistic to our assets in North Europe, Indonesia and North Africa will be a core element of our future plans. In 2023 we continued to deliver our organic growth, with the completion on time and on budget of the two flagship, low carbon projects of Baleine in Côte d'Ivoire and Congo FLNG ph.1. We maintained leadership in exploration thanks to outstanding success in Indonesia and elsewhere, while we also hit the upper range of our production target. GGP achieved its historical result thanks to the quality of its portfolio, steady optimization drive and favorable contractual settlements. Delivering gas and low carbon projects is one aspect of our transition plan as we are also materially growing our presence in the new energies. Enilive, our activity dedicated to biofuels and mobility services, has expanded its international presence by purchasing a 50% interest in the Chalmette biorefinery in the USA and by signing a JV agreement in South Korea. Plenitude has now reached 3 GW of renewable capacity. These two businesses already generate an economic performance of around €1 bln EBITDA each. With the recent entry of an institutional investor into the shareholding of Plenitude, we highlighted the value of this business, that is estimated at around €10 bln and accessed additional dedicated capital supporting our growth plan. Our financial results were excellent, with a proforma EBIT of almost €18 bln and an adjusted net profit of more than €8 bln. Cash flow generation at €16.5 bln before working capital movements gave us a significant headroom over the substantial cash returns to shareholders of €4.8 bln, while keeping our leverage at 0.2."

2023 HIGHLIGHTS

STRATEGIC MILESTONES

UPSTREAM RELEVANT START UPS fast track projects delivery (Congo LNG, Baleine)

GENG NORTH DISCOVERY

confirms Eni's exploration leadership; material new gas hub offshore Indonesia also thanks to the Chevron/Neptune deals

NEPTUNE ACQUISITION

strong complementarity to Eni's portfolio

PLENITUDE

EIP transaction supports growth, confirms Eni's value, validating satellite model

ENILIVE LAUNCH

focused on sustainable mobility; multi-energy and multi-service business. Bio build out

NOVAMONT ACQUISITION

a catalyst Versalis' bio chemical transformation

CCS

framework agreements with UK Government for Hynet hub

STRONG EARNINGS

€13.8 BLN	ADJUSTED EBIT significant outperformance
€17.8 BLN	PROFORMA ADJUSTED EBIT strong business performance
€8.3 BLN	ADJUSTED NET PROFIT second best performance in current structure
€16.5 BLN	ADJUSTED CFFO strong cash generation supported by €2.3 bln dividends from investees
€4.8 BLN	CASH RETURNS TO SHAREHOLDERS attractive remuneration yield
20%	LEVERAGE

financial flexibility

NATURAL RESOURCES

EXPLORATION & PRODUCTION	• production 1.66 mboe/d, +3% y-o-y growth • upstream net GHG emissions reduced by 10% y-o-y • higher activity in Algeria, Baleine ramp-up and strong regularity in Kazakhstan • ~900 mln boe of discovered resources
GLOBAL GAS & LNG PORTFOLIO	• all sources RRR 67% (3 year: 73%) • continued asset optimizations and profitable trading activities • positive upside from renegotiations and settlements • additional pipe equity volumes in the EU from the acquisition of Neptune • 6.5 bcm/y (at plateau) of additional contracted LNG volumes from Congo, Indonesia and Qatar • significant outperformance of original fy guidance
	of €1.7 - €2.2 bln adjusted EBIT

ENERGY EVOLUTION
PLENITUDE	• 2023 proforma adjusted EBITDA: €0.9 bln • 3 GW installed capacity (+36% y-o-y) • 10.1 mln customers • ~19,000 owned public charging points
ENILIVE	• 2023 proforma adjusted EBITDA: €1 bln • biorefining capacity 1.65 mln ton/y • 2nd HVO producer in Europe • ramping-up agri-feedstock supply with activities in 8 Countries • expanding biorefining internationally in US, Malaysia and South Korea
TRADITIONAL REFINING	• refinery throughputs of 27.4 mln ton • scenario conditions not fully captured by the SERM with tighter crude and product spreads • continued strong performance of ADNOC refining and dividend contribution
VERSALIS	• 2023 adjusted EBIT €-0.6 bln reflecting exceptionally adverse market conditions • Novamont acquisition completed • weak demand and competitive pressures

Main data

KEY FINANCIAL DATA

(€ million)	2023	2022	2021	2020	2019	2018
Net sales from operations	93,717	132,512	76,575	43,987	69,881	75,822
of which: Exploration & Production	23,903	31,194	21,742	13,590	23,572	25,744
Global Gas & LNG Portfolio	20,139	48,586	20,843	7,051	11,779	14,807
Enilive, Refining and Chemicals	52,558	59,178	40,374	25,340	42,360	46,483
Plenitude & Power	14,256	20,883	11,187	7,536	8,448	8,218
Corporate and other activities	1,972	1,886	1,698	1,559	1,676	1,588
Impact of unrealized intragroup profit elimination and consolidation adjustments	(19,111)	(29,215)	(19,269)	(11,089)	(17,954)	(21,018)
Operating profit (loss)	8,257	17,510	12,341	(3,275)	6,432	9,983
of which: Exploration & Production	8,549	15,963	10,113	(610)	7,417	10,214
Global Gas & LNG Portfolio	2,431	3,730	899	(332)	431	387
Enilive, Refining and Chemicals	(1,397)	460	45	(2,463)	(682)	(501)
Plenitude & Power	(464)	(825)	2,355	660	74	340
Corporate and other activities	(943)	(1,956)	(863)	(563)	(688)	(668)
Impact of unrealized intragroup profit elimination	81	138	(208)	33	(120)	211
Operating profit (loss)	8,257	17,510	12,341	(3,275)	6,432	9,983
Exclusion of special items	4,986	3,440	(1,186)	3,855	2,388	1,161
Exclusion of inventory holding (gains) losses	562	(564)	(1,491)	1,318	(223)	96
Adjusted operating profit (loss)(a)	13,805	20,386	9,664	1,898	8,597	11,240
of which: Exploration & Production	9,934	16,469	9,340	1,547	8,640	10,850
Global Gas & LNG Portfolio	3,247	2,063	580	326	193	278
Enilive, Refining and Chemicals	555	1,929	152	6	21	360
Plenitude & Power	681	615	476	465	370	262
Corporate and other activities	(651)	(680)	(640)	(507)	(602)	(583)
Impact of unrealized intragroup profit elimination and consolidation adjustments	39	(10)	(244)	61	(25)	73
Net profit (loss)(b)	4,771	13,887	5,821	(8,635)	148	4,126
Adjusted net profit (loss)(a)(b)	8,322	13,301	4,330	(758)	2,876	4,583
Net cash flow from operating activities	15,119	17,460	12,861	4,822	12,392	13,647
Capital expenditure	9,215	8,056	5,234	4,644	8,376	9,119
Shareholders' equity including non-controlling interests at year end	53,644	55,230	44,519	37,493	47,900	51,073
Net borrowings at year end before IFRS 16	10,899	7,026	8,987	11,568	11,477	8,289
Net borrowings at year end after IFRS 16	16,235	11,977	14,324	16,586	17,125	n.a.
Leverage before lease liability ex IFRS 16	0.20	0.13	0.20	0.31	0.24	0.16
Leverage after lease liability ex IFRS 16	0.30	0.22	0.32	0.44	0.36	n.a.
Net capital employed at year end	69,879	67,207	58,843	54,079	65,025	59,362
of which: Exploration & Production	51,534	50,732	47,949	45,252	53,358	50,358
Global Gas & LNG Portfolio	1,119	672	(823)	796	1,327	1,742
Enilive, Refining and Chemicals	9,627	9,302	9,815	8,786	10,215	6,960
Plenitude & Power	7,728	7,486	5,474	2,284	1,787	1,869
(a) Non-GAAP measures.

(b) Attributable to Eni's shareholders.

KEY MARKET INDICATORS

		2023	2022	2021	2020	2019	2018
Average price of Brent dated crude oil in US dollars(a)	(\$/barrel)	82.62	101.19	70.73	41.67	64.30	71.04
Average EUR/USD exchange rate(b)		1.081	1.053	1.183	1.142	1.119	1.181
Average price of Brent dated crude oil	(€ barrel)	76.43	96.09	59.80	36.49	57.44	60.15
Standard Eni Refining Margin (SERM)(c)	(\$ barrel)	8.1	8.5	(0.9)	1.7	4.3	3.7
TTF(d)	(€/MWh)	41	121	46	9	13	23
PSV(d)		42	122	46	10	16	25

(a) Source: Platt's Oilgram.

(b) Source: ECB.

(c) Source: In \$/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni's refining system in consideration of material balances and refineries' product yields. From January 1,2024, the benchmark refining margin has been calculated based on a new methodology which considers a revised industrial set-up in connection with the planned restructuring of the Livorno plant and implemented optimizations of utilities consumption, as well as current trends in crude supplies building in a slate of both high-sulfur and low-sulfur crudes. The value of the 2023 SERM indicator has been restated. (d) In €/MWh. Source: ICIS European Spot Gas Markets.

SELECTED OPERATING DATA

Climate(a)		2023	2022	2021	2020	2019	2018
Net Carbon Footprint upstream (Scope 1+2)(b)	(mmtonnes CO2 eq.)	8.9	9.9	11.0	11.4	14.8	14.8
Net Carbon footprint Eni (Scope 1+2)(b)		26.1	29.9	33.6	33.0	37.6	37.2
Indirect GHG emissions (Scope 3) from end use of products sold(c)		174	164	176	185	204	203
Net GHG Emissions (Scope 1+2+3)(b)		200	194	210	218	241	240
Net GHG Lifecycle Emissions (Scope 1+2+3)(b)		398	419	456	439	501	505
Net Carbon Intensity (Scope 1+2+3)(b)	(gCO2 eq./MJ)	66	66	67	68	68	68
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	38.69	39.39	40.08	37.76	41.20	43.35
Indirect GHG emissions (Scope 2)		0.73	0.79	0.81	0.73	0.69	0.67
Methane direct emission (Scope 1)	(ktonnes CH4 )	39.1	49.6	54.5	55.9	65.3	104.1

Health, Safety and Environment(a)		2023	2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.40	0.41	0.34	0.36	0.34	0.35
of which: employees		0.45	0.29	0.40	0.37	0.21	0.37
contractors		0.38	0.47	0.32	0.35	0.39	0.34
Total volume of oil spills (>1 barrel)	(barrels)	12,822	6,139	4,408	6,824	7,278	6,687
of which: due to sabotage and terrorism		5,094	5,253	3,053	5,866	6,245	4,022
operational		7,728	886	1,355	958	1,033	2,665
Freshwater withdrawals	(mmcm)	124	116	117	112	127	117
Reinjected production water	(%)	60	59	58	53	58	60

Innovation		2023	2022	2021	2020	2019	2018
R&D expenditure	(€ million)	166	164	177	157	194	197
First patent filing application	(number)	28	23	30	25	34	43

Employees		2023	2022	2021	2020	2019	2018
Exploration & Production	(number)	8,785	8,689	9,409	9,815	10,272	10,448
Global Gas & LNG Portfolio		669	870	847	700	711	734
Enilive, Refining and Chemicals		14,092	13,132	13,072	11,471	11,626	11,457
Plenitude & Power		3,018	2,794	2,464	2,092	2,056	2,056
Corporate and other activities		6,578	6,703	6,897	7,417	7,388	7,006
Total Group		33,142	32,188	32,689	31,495	32,053	31,701

(a) KPIs refer to 100% of the operated/cooperated assets, unless stated otherwise.

(b) KPIs are calculated on an equity bases.

(c) GHG Protocol Category 11 - Corporate Value Chain (Scope 3) Standard. Estimated on the basis of the upstream production (Eni's share) in line with IPIECA methodologies.

Exploration & Production		2023	2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.30	0.35	0.25	0.28	0.33	0.30
Net proved reserves of hydrocarbons	(mmboe)	6,414	6,614	6,628	6,905	7,268	7,153
Average reserve life index	(years)	10.6	11.3	10.8	10.9	10.6	10.6
Hydrocarbon production	(kboe/d)	1,655	1,610	1,682	1,733	1,871	1,851
Organic reserve replacement ratio	(%)	69	47	55	43	92	100
Profit per boe(d)(f)	(\$/boe)	14.5	9.8	4.8	3.8	7.7	6.7
Opex per boe(e)		8.6	8.4	7.5	6.5	6.4	6.8
Finding & Development cost per boe(f)		26.3	24.3	20.4	17.6	15.5	10.4
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	22.9	21.5	22.3	21.1	22.8	24.1
Volumes of hydrocarbon sent to routine flaring	(billion Sm³)	1.0	1.1	1.2	1.0	1.2	1.4
Methane Intensity (upstream) (m³CH4/m³ marketed gas)	%	0.06	0.08	0.09	0.09	0.10	0.16
Operational oil spills (> 1 barrel)	(barrels)	143	845	436	882	985	1,595
Global Gas & LNG Portfolio		2023	2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.00	0.00	0.00	1.15	0.56	0.51
Natural gas sales	(bcm)	50.51	60.52	70.45	64.99	72.85	76.60
of which: Italy		24.40	30.67	36.88	37.30	37.98	39.17
outside Italy		26.11	29.85	33.57	27.69	34.87	37.43
LNG sales		9.6	9.4	10.9	9.5	10.1	10.3
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	0.69	2.09	1.01	0.36	0.25	0.62

Enilive, Refining and Chemicals		2023	2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.75	0.81	0.80	0.80	0.27	0.56
Capacity of biorefineries	(mmtonnes/year)	1.65	1.10	1.10	1.10	1.10	0.36
Production sold of certified biofuels	(ktonnes)	635	428	585	622	256	219
Retail market share in Italy	(%)	21.4	21.7	22.2	23.2	23.6	24.0
Retail sales of petroleum products in Europe	(mmtonnes)	7.51	7.50	7.23	6.61	8.25	8.39
Service stations in Europe at year end	(number)	5,267	5,243	5,314	5,369	5,411	5,448
Average throughput of service stations in Europe	(kliters)	1,645	1,587	1,521	1,390	1,766	1,776
Balanced capacity of refineries (Eni's share)	(kbbl/d)	528	528	548	548	548	548
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	5.69	6.00	6.72	6.65	7.97	8.19
SOx emissions (sulphur oxide)	(ktonnes SO2 eq.)	2.23	2.34	2.67	2.78	4.16	4.80
Direct GHG emissions/Refinery throughputs (raw and semi-finished materials)	(tonnes CO2 eq./kt)	232	233	228	248	248	253
Production of chemical products	(ktonnes)	5,663	6,856	8,496	8,073	8,068	9,483
Sales of chemical products		3,117	3,752	4,471	4,339	4,295	4,946
Average chemical plant utilization rate	(%)	51	59	66	65	67	76
Plenitude & Power		2023	2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.83	0.31	0.29	0.32	0.62	0.60
Retail and business gas sales	(bcm)	6.06	6.84	7.85	7.68	8.62	9.13
Retail and business power sales to end customers	(TWh)	17.98	18.77	16.49	12.49	10.92	8.39
Thermoelectric production		20.66	21.37	22.31	20.95	21.66	21.62
Electricity sold to hub		19.88	22.37	28.54	25.34	28.28	28.54
EV charging points	(thousand)	19.0	13.1	6.2	3.4	nd	nd
Renewables installed capacity at period end	(GW)	3.0	2.2	1.1	0.3	0.2	0.0
Electricity sold to hub	(TWh)	3.98	2.55	0.99	0.34	0.06	0.12
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	9.36	9.76	10.03	9.63	10.22	10.47
(d) Related to consolidated subsidiaries.

(e) Includes Eni's share in joint ventures and equity-accounted entities.

(f) Three-year average.

SHARE DATA

		2023	2022	2021	2020	2019	2018
Net profit (loss)(a)(b)	(€)	1.40	3.95	1.60	(2.42)	0.04	1.15
Dividend pertaining to the year		0.94	0.88	0.86	0.36	0.86	0.83
Dividend to Eni's shareholders pertaining to the year(c)	(€ million)	3,106	2,972	3,055	1,286	3,078	2,989
Cash dividend to Eni's shareholders		3,046	3,009	2,358	1,965	3,018	2,954
Cash flow(a)	(€)	4.58	5.01	3.61	1.35	3.45	3.79
Dividend yield(d)	(%)	6.2	6.5	7.1	4.2	6.3	5.9
Net profit (loss) per ADR(a)(b)(e)	(\$)	3.03	8.32	3.78	(5.53)	0.09	2.72
Dividend per ADR(e)		2.02	1.84	1.92	0.86	1.89	1.89
Cash flow per ADR(a)(e)	(%)	9.90	10.55	8.54	3.08	7.72	8.95
Dividend yield per ADR(d)(e)		6.2	6.5	7.1	4.2	6.3	5.9
Number of shares outstanding at period-end(f)	(million)	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)		3,303.8	3,483.6	3,566.0	3,572.5	3,592.2	3,601.1
Total Shareholders Return (TSR)	(%)	23	16	52	(34)	7	5

(a) 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.

(b) Pertaining to Eni's shareholders.

(d) Ratio between dividend of the year and average share price in December.

(e) 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.

(f) Calculated by excluding own shares in portfolio.

SHARE INFORMATION

	2023	2022	2021	2020	2019	2018
Share price - Milan Stock Exchange
High (€)	15.70	14.53	12.75	14.32	15.94	16.76
Low	12.16	10.64	8.20	5.89	13.04	13.33
Average	14.06	12.81	10.56	8.96	14.36	15.25
Year end	15.35	13.29	12.22	8.55	13.85	13.75
ADR price(a) - New York Stock Exchange
High (\$)	34.19	32.49	29.70	32.12	36.17	40.09
Low	25.80	20.44	19.97	13.71	28.84	30.00
Average	30.42	27.04	24.98	20.28	32.12	35.98
Year end	34.01	28.66	27.65	20.60	30.92	31.50
Average daily exchanged shares (million shares)	11.44	14.56	17.03	20.40	11.41	12.99
Value (€ million)	160	187	179	178	164	197
Weighted average number of shares outstanding(b) (million shares)	3,303.8	3,483.6	3,566.0	3,572.5	3,592.2	3,601.1
Market capitalization(c)
EUR (billion)	49.6	47.5	44.1	31.1	50.3	50.0
USD	54.8	50.7	49.9	38.2	56.5	57.3

(a) One ADR represents 2 Eni's shares.

(b) Excluding treasury shares.

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, 2023.

ENI SHARE PRICE IN MILAN (December 31, 2020 - May 3, 2024)

Source: Eni calculations based on BLOOMBERG data.

ENI ADR PRICE IN NEW YORK (December 31, 2020 - May 3, 2024)

Dividend (€/share)

CLASS OF SHAREHOLDERS(a)

(%)

5.38

Institutional shareholders

Treasury shares Other Retail investors Public holding

14.21

(a) As of March 13, 2024.

47.94

32.40

0.07

0.88 0.94

6.2

4.6

2022 2023

2018 2019 2020 2021 2022 2023

(Eni vs. Peer Group and benchmark Stock Exchange indexes)

56.2

98.6

66.6 64.8

3.8

companies(*) (%)

Eni's Dividend yield (%)

(*) Refer to: BP, Chevron, Repsol, ExxonMobil, Shell and TotalEnergies.

TSR Eni (%) TSR Ftse Mib (%)

TSR - average Peer Group (%)

TSR - average stock market indices (%)

Dividend yield - average of Oil & Gas petroleum

Source: Eni calculations based on BLOOMBERG data.

0.83 0.86 0.86

5.46

9.28

6.3

* TSR % change in the 2015-2023 period.

DIVIDEND PER SHARE

(a) As of March 13, 2024.

52.31

2018 2019 2020 2021

TOTAL SHAREHOLDER RETURN (TSR)*

2015 2016 2017

5.4 5.6 5.1 4.2

0.36

6.5 5.9

7.7

7.1

Rest of world USA and Canada Other EU states UK and Ireland

Other (including treasury shares)

Italy

SHAREHOLDERS DISTRIBUTION BY GEOGRAPHIC AREA(a) (%)

16.39

12.27

4.29

Source: Eni calculations based on BLOOMBERG data.

Eni

US \$

€

Source: Eni calculations based on BLOOMBERG data.

Indexed FTSE MIB to Eni share price

ENI ADR PRICE IN NEW YORK (December 31, 2020 - May 3, 2024)

ENI SHARE PRICE IN MILAN (December 31, 2020 - May 3, 2024)

2021 2022 2023 May 3,

Indexed Euro Stoxx 50 to Eni share price

2024

SHAREHOLDERS DISTRIBUTION BY GEOGRAPHIC AREA(a) (%)

Eni Indexed S&P 500 to Eni ADR price

(a) As of March 13, 2024.

TOTAL SHAREHOLDER RETURN (TSR)* (Eni vs. Peer Group and benchmark Stock Exchange indexes)

* TSR % change in the 2015-2023 period.

DIVIDEND PER SHARE

NATURAL RESOURCES

Exploration & Production Global Gas & LNG Portfolio

Exploration & Production

KEY PERFORMANCE INDICATORS

		2023	2022	2021	2020	2019	2018
Total recordable incident rate (TRIR)(a)	(total recordable injuries/worked hours) x 1,000,000	0.30	0.35	0.25	0.28	0.33	0.30
of which: employees		0.24	0.12	0.09	0.18	0.18	0.29
contractors		0.32	0.42	0.30	0.31	0.37	0.30
Sales from operations(b)	(€ million)	23,903	31,194	21,742	13,590	23,572	25,744
Operating profit (loss)		8,549	15,963	10,113	(610)	7,417	10,214
Adjusted operating profit (loss)		9,934	16,469	9,340	1,547	8,640	10,850
Adjusted net profit (loss)		5,516	10,834	5,593	124	3,436	4,955
Capital expenditure		7,133	6,252	3,824	3,472	6,996	7,901
Profit per boe(c)(d)	(\$/boe)	14.5	9.8	4.8	3.8	7.7	6.7
Opex per boe(e)		8.6	8.4	7.5	6.5	6.4	6.8
Cash Flow per boe		19.4	29.6	20.6	9.8	18.6	22.5
Finding & Development cost per boe(d)(e)		26.3	24.3	20.4	17.6	15.5	10.4
Average hydrocarbons realizations		59.35	73.98	51.49	28.92	43.54	47.48
Hydrocarbons production(e)	(kboe/d)	1,655	1,610	1,682	1,733	1,871	1,851
Net proved hydrocarbon reserves	(mmboe)	6,414	6,614	6,628	6,905	7,268	7,153
Reserves life index	(years)	10.6	11.3	10.8	10.9	10.6	10.6
Organic reserves replacement ratio	(%)	69	47	55	43	92	100
Employees at year end	(number)	8,785	8,689	9,409	9,815	10,272	10,448
of which: outside Italy		5,592	5,497	6,045	6,123	6,781	6,971
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	22.92	21.50	22.30	21.10	22.80	24.10
Methane Intensity (m³ CH4 /m³ gas sold)(a)	(%)	0.06	0.08	0.09	0.09	0.10	0.16
Volumes of hydrocarbon sent to routine flaring(a)	(billion Sm³)	1.0	1.1	1.2	1.0	1.2	1.4
Net carbon footprint upstream (Scope 1+2)(f)	(mmtonnes CO2 eq.)	8.9	9.9	11.0	11.4	14.8	14.8
Oil spills due to operations (>1 barrel)(a)	(barrels)	143	845	436	882	985	1,595
Re-injected production water(a)	(%)	60	59	58	53	58	60

(a) KPIs refer to 100% of the operated/cooperated assets, unless otherwise stated.

(b) Before elimination of intragroup sales.

(d) Three-year average.

(e) Includes Eni's share in joint ventures and equity-accounted entities.

(f) Calculated on equity basis and included carbon sink.

In 2023, the E&P segment delivered outstanding growth. The Baleine oilfield off Côte d'Ivoire, Africa's first Net Zero emissions project (Scope 1 and 2), started production less than two years after discovery, leveraging on our fast-track model to reduce the reserve time-to-market. The Congo Floating LNG project has shipped its first cargo at the end of February 2024, thanks to the use of well-established technologies that have allowed to devise a modular "small-scale" LNG development scheme, the first ever used in Africa, achieving a start-up in record time. In Mozambique, the Coral South project, the world's first example of floating LNG in ultra-deep waters, has reached the production plateau. Exploration recorded yet another successful year with 900 million boe of new resources, mainly gas-focussed, driven by the extraordinary Geng discovery in Indonesia, the largest in the industry in 2023, as well as near-field findings in Egypt, Congo and Mexico. Hydrocarbon production increased by 3% to 1.655 million boe/d, despite continued capital discipline and focus on gas development. M&A activity has represented a key lever for strengthening the upstream portfolio. The acquisition of Neptune Energy, completed in January 2024, is highly synergistic with gas assets portfolio and brings the E&P business significantly closer to its targets of a share of natural gas production of 60% by 2030 and of decarbonization, as the acquired assets, are characterized by low emission intensity.

ACTIVITY AREAS

Italy

Eni has been operating in Italy since 1926. In 2023, Eni's oil and gas production amounted to 69 kboe/d. Eni's activities in Italy are deployed in the Adriatic and Ionian Seas, the Central Southern Apennines, mainland and offshore Sicily, on a total developed and undeveloped acreage of 12,365 square kilometers (10,430 square kilometers net to Eni). Eni's production activities in Italy are regulated by concession contracts (24 operated onshore and 48 operated offshore).

Adriatic and Ionian Seas

Production Main fields are Barbara, Bonaccia, Cervia-Anna, Clara NW (Eni's interest 51%), Luna and Hera Lacinia and related satellites. Those fields accounted for 30% of Eni's domestic gas production in 2023. Production is operated by means of approximately 50 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 In the gas assets of the Adriatic Sea, development activities concerned: (i) maintenance and production optimization intervention at the Hera Lacinia, Luna and Naomi Pandora fields; and (ii) production start-up of the Donata field.

Decommissioning plan to plug-and-abandon depleted wells and remove non-productive platforms progressed during the year in compliance with Italian Ministerial Decree 15 February 2019 "Linee guida nazionali per la dismissione mineraria delle piattaforme per la coltivazione in mare e delle infrastrutture connesse". The decommissioning process is ongoing for 10 platforms in compliance with the above-mentioned Decree. In addition, campaign to plug-and-abandon non-productive onshore and offshore wells is ongoing.

Central Southern Apennines

Production Eni is the operator of the Val d'Agri concession (Eni's interest 61%) 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. In 2023 the Val d'Agri concession accounted for approximately 49% of Eni's domestic hydrocarbon production.

Development In the Val d'Agri concession, activities carried out during the year concerned: (i) sidetrack of existing wells, mainly in the Monte Enoc area, based on the approved "Work Program"; and (ii) production optimization activities to mitigate field decline.

In 2023, activities were launched within the Memorandum of Intent signed in 2022 by Eni, Shell and the Basilicata Region for a sustainable local development associated to the ten-year program of the Val d'Agri concession. In particular, the agreement provides for many "nonoil" initiatives and projects for a total commitment of €90 million by concessionaries. In June 2023 the Basilicata Region selected and approved the following programs: (i) regional development of e-mobility network; (ii) the establishment of the Eni School for Business center (Joule); (iii) initiatives to support the local sustainable development in collaboration with the Fondazione Eni Enrico Mattei (FEEM); and (iv) the development agricultural activities in the biofuels supply chain. In addition an agreement has been defined with the Basilicata Region and Acquedotto Lucano to develop an energy transition project supporting the water sector in the area. The project includes the construction of photovoltaic plants for approximately 50 MW total installed capacity, with energy costs reduction of the Acquedotto Lucano and then reflecting in the bill of lower income groups.

Progressed the "Agricultural Center for Experimentation and Training" project activities in the Energy Valley area nearby the Val d'Agri Oil Center by means of sustainable agricultural initiatives and experimental crops, training programs for schools and technique center as well as biomonitoring programs with innovative techniques.

Sicily

Production Eni operates 11 production concessions onshore and 2 offshore in Sicily. The main fields are Gela, Tresauro (Eni's interest 75%), Giaurone, Fiumetto, Prezioso and Bronte, which in 2023 accounted for approximately 13% of Eni's production in Italy.

Development Within the Memorandum of Understanding for the Gela area, signed with the Ministry of Economic Development in November 2014, the construction activities of the Argo and Cassiopea project (Eni's interest 60%) have progressed. During 2023, the installation of the sealine transporting the gas from the offshore well to the onshore treatment facilities was completed. The onshore plant construction is ongoing and nearing completion. Natural gas production start-up is expected in the first half of 2024. Project configuration and design will support to achieve the carbon neutrality target (Scope 1 and 2).

Within the local support communities' initiatives, according to the ratification of the framework agreement with the Fondazione Banco Alimentare Onlus, Banco Alimentare della Sicilia Onlus and the Municipality of Gela, activities progressed to create a food storage and distribution center for disadvantaged communities. In addition, in 2023, a project was launched to support the logistics and distribution of foodstuffs by the Banco Alimentare della Sicilia Onlus to local people participating in the program.

Rest of Europe

Norway

Eni has been present in Norway since 1965 and the activities are conducted through the Vår Energi associate.

Activities are performed in the Norwegian Sea, in the North Sea and in the Barents Sea, on a total developed and undeveloped acreage of 30,177 square kilometers (8,161 square kilometers net to Eni). Eni's production in Norway amounted to 138 kboe/d in 2023.

The mineral interest portfolio was reloaded: (i) in February 2023 with 12 exploration licenses, 5 of which are operated, following the "Awards in Predefined Areas 2022" (APA) by the Ministry of Petroleum and Energy of Norway; (ii) in February 2024, with 16 exploration licenses, 4 of which are operated, following "2023 APA". The licenses are distributed over the three main sections of the Norwegian continental shelf. The new acquired licenses are located in both near-fields already in production or development areas with high exploration mineral potential.

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 Production comes from operated fields, by Vår Energi, of Goliat (Eni's interest 41%) in the Barents Sea, Marulk (Eni's interest 12.6%) in the Norwegian Sea, as well as Balder & Ringhorne (Eni's interest 56.7%) and Ringhorne East (Eni's interest 44.1%) in the North Sea; as well as non-operated fields in 36 producing licenses across the Norwegian Continental Shelf, including: Åsgard (Eni's interest 14.28%), Mikkel (Eni's interest 30.50'%), Great Ekofisk Area (Eni's interest 7.81%), Snorre (Eni's interest 11.70%), Ormen Lange (Eni's interest 4.00%), Statfjord Unit (Eni's interest 13.47%), Statfjord Satellites East (Eni's interest 12.95%), Statfjord Satellites North (Eni's interest 15.76%), Statfjord Satellites Sygna (Eni's interest 13.24%) and Grane (Eni's interest 17.85%).

In October 2023, production start-up was achieved at the Breidablikk project with the completion of the drilling activities and the linkage to the existing facilities in the area. Leveraging on high energy and operational efficiency technologies, the project development will minimize direct GHG emissions.

Development Main development activities concerned: (i) the Johan Castberg sanctioned project with start-up expected in 2024; and (ii) the Balder X sanctioned project in the PL 001 license, located in the North Sea. The Balder project scheme provides for drilling additional productive wells, to be linked to an upgraded Jotun FPSO unit that will be relocated in the area that will support the development of new discoveries near to the area through upgrading existing infrastructure. The planned activities will allow to extend the Balder hub production until 2045. Production start-up is expected in 2024.

Exploration Exploration activities yielded positive results with: (i) the Countach oil and gas discovery in the Goliat the PL 229 licence located in the Barents Sea; (ii) the Kim oil discovery in the PL 185 license in the North Sea; (iii) the Crino oil and gas discovery in the North Sea; (iv) the Norma gas discovery in the PL 984 license in the North Sea; and (v) the Svalin M Sør oil discovery in the PL 169 license.

United Kingdom

Eni has been present in the United Kingdom since 1964. Eni's activities are carried out in the British section of the North Sea and the Irish Sea, on a total developed and undeveloped acreage of 2,710 square kilometers (2,080 square kilometers net to Eni). In 2023, Eni's oil and gas production averaged 39 kboe/d.

On April 23, 2024, Eni reached an agreement on the combination of substantially all its upstream assets in the UK, excluding East Irish Sea assets and CCUS activities with Ithaca Energy, marking a strategic move to significantly strengthen its presence on the UK Continental Shelf. The combination is being funded through the issue to Eni UK of new ordinary shares representing 38.5% of the enlarged issued share capital of Ithaca. The economic effective date for the combination will be June 30, 2024, with completion expected in Q3 2024, subject to the satisfaction of certain regulatory and other customary conditions precedent. The combination will immediately create an enlarged and stronger combined group with 2024 production greater than 100,000 boe/d and the underlying potential to organically grow to 150,000 boe/d by the early 2030s. The combination is aimed at replicating the previous successful execution of upstream combinations that Eni has formed using its distinctive Satellite Model.

Exploration and production activities in the UK are regulated by concession contracts.

Production Eni holds interests in 3 production areas of which the Liverpool Bay (Eni's interest 100%) is operated. In the two nonoperated areas, main fields are Elgin/Franklin (Eni's interest 21.87%), Glenelg (Eni's interest 8%), J Block (Eni's interest 33%), Jasmine (Eni's interest 33%) and Jade (Eni's interest 7%).

Development Development activities mainly concerned: (i) Talbot development project with first oil in 2024; and (ii) decommissioning planned activity of the Hewett Area.

Exploration As of December 31, 2023, Eni holds interest in 2 exploration licenses, of which one is operated, with interest ranging from 33% to 50%.

North Africa

Algeria

Eni has been present in Algeria since 1981. In 2023, Eni's oil and gas production averaged 126 kboe/d. Developed and undeveloped acreage was 18,077 square kilometers (7,872 square kilometers net to Eni).

Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts.

Production Production mainly comes from the operated blocks: (i) Blocks 403a/d (Eni's interest from 65% to 100%); (ii) Block ROM North (Eni's interest 35%); (iii) Blocks 401a/402a (Eni's interest 100%); (iv) Block 403 (Eni's interest 50%); (v) Block 405b (Eni's interest 75%); (vi) the Sif Fatima II, Zemlet El Arbi and Ourhoud II blocks in the Berkine Nord basin (Eni's interest 49%); (vii) Berkine South block (Eni's interest 75%); and (viii) In Amenas (Eni's interest 45.89%) and In Salah (Eni's interest 33.15%) concessions located in the Southern Sahara, whose acquisition from bp was finalized during 2023. In addition, Eni holds interest in the non-operated blocks 404 and 208, following during the year the finalization of new contracts with Eni's participating interest increasing to 17.5%.

Development The development activities are as follows: (i) infilling program in several fields of 401a/402a blocks, Sif Fatima II, Ourhoud II and Zemlet El Arbi blocks as well as In Amenas and In Salah concessions; (ii) workover activities in 404-208, 405b and 403 blocks as well as the conversion of certain wells into water-alternate-gas (WAG) injectors in block 403; (iii) upgrading of the third treatment train of the BRN plant; (iv) drilling activities and linkage of infilling wells in Berkine South area together with debottlenecking of oil line. Furthermore, a 10 MW photovoltaic plant is under construction at the BRN field in the block 403, in addition to the 10 MW plant already completed in 2020. The construction plans for 12 MW photovoltaic plant at the MLE field in the block 405b currently under evaluation.

In March 2024 Eni Foundation launched a project to support health facilities in the Haut-Plateau region and southern region of Algeria, through the delivery of two mobile clinics. The initiative confirms the Eni's distinctive and integrated approach in the countries in which it operates.

Exploration Exploration activities yielded positive results with the RODE-1 gas discovery in the Sif Fatima II concession. Development activities are expected to start in 2024.

Libya

Eni has been present in Libya since 1959. In 2023, Eni's production amounted to 169 kboe/d. 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).

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

Libya is currently exposed to significant geopolitical risks. In 2023, a relatively stabler sociopolitical environment than in previous years, allowed continuity to production operations creating a favorable backdrop for reaching agreements with the National Oil Company (NOC) for future development projects of natural gas reserves in the Country.

In January 2023, Eni signed an agreement with the NOC for the development of the large gas reserves of A&E Structures, to increase natural gas production to sustain the domestic market and export volumes to Europe. Production is expected to start in the next years. The project foresees an onshore Carbon Capture and Storage (CCS) hub as well, in line with Eni's decarbonization strategy. Furthermore, in May 2023, Eni signed an agreement with NOC to start the development of the Bouri Gas Utilization (BGUP) project.

In June 2023, Eni signed a Memorandum of Understanding with Libyan Government of National Accord to evaluate possible opportunities to reduce GHG emissions and develop sustainable energy in the Country, in line with Eni's strategy and Libyan government targets to accelerate in a decarbonization and transition energy programs.

Production Production mainly comes from 6 contract areas. Onshore contract areas are: (i) Area A, consisting in the former concession 82 (Eni's interest 50%); (ii) Area B, former concessions 100 (Bu-Attifel field) and the NC 125 Block (Eni's interest 50%); (iii) Area E, with the El Feel field (Eni's interest 33.3%); and (iv) Area D with Block NC 169 that feeds the Western Libyan Gas Project (Eni's interest 50%). Offshore contract areas are: (i) Area C, with the Bouri oil field (Eni's interest 50%); and (ii) Area D, with Block NC 41 that feed the Western Libyan Gas Project (Eni's interest 50%).

Development Development activities concerned: (i) the sanctioning of the A&E Structures project following the award of EPCI contract for the WHPA platform; (ii) the sanctioning of the BGUP project to reduce CO² emissions and to valorize associated gas of the Bouri field; (iii) the Sabratha Compression project to support current production of the Bahr Essalam field and additional production of the A Structure development program. During the year the related EPCI contract was awarded, and the project is currently in execution phase; and (iv) maintenance activities at the wastewater treatment plant for the Nalut General Hospital as well as the health personnel training program following the agreements defined with the Country. In 2023 a project for the wastewater treatment plant of the Murzuq hospital was launched. The program includes the installation of a new treatment plant with a capacity of 250 cubic meters/day. In addition, signed an agreement with the International Organization for Migration to increase youth employment in the south of the Country. Exploration Eni operates the onshore Area A and Area B in the Ghadames basin and offshore Area C in the Sirte area with a 42.5% interest.

Tunisia

Eni has been present in Tunisia since 1961. In 2023, Eni's production amounted to 6 kboe/d. 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 6,112 square kilometers (2,187 square kilometers net to Eni).

Exploration and production in this Country are regulated by concessions.

Production Production mainly comes from the offshore Maamoura and Baraka operated fields (Eni's interest 49%) as well as the Adam (Eni's interest 25%) and Oued Zar (Eni's interest 50%) onshore operated fields; and the MLD (Eni's interest 50%) and El Borma (Eni's interest 50%) non operated fields.

Development The activities of the year concerned the completion of the Sabeh-01 and Wissal-01 discoveries wells in the Borj El Khadra exploration permit. Engineering studies are ongoing to define development scheme of the last discoveries wells with the Anbar-01 discovery well, drilled in 2022.

Exploration Exploration activities yielded positive results with the Sabeh-01 and Wissal-01 wells in the Borj El Khadra exploration permit.

Egypt

Eni has been present in Egypt since 1954. In 2023, Eni's production amounted to 318 kboe/d and accounted for approximately 19% of Eni's total annual hydrocarbon production. Developed and undeveloped acreage was 34,038 square kilometers (12,427 square kilometers net to Eni).

In January 2023, Eni signed a Memorandum of Intent (MoI) with EGAS to jointly study opportunities on GHG emissions reduction in the upstream sector in the Country through a plan of initiatives leading additional gas monetization.

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

Production Eni's main producing operated activities are located in: (i) the Shorouk block (Eni's interest 50%) 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 (Eni's interest 100%); (iii) the Western Desert in the Melehia (Eni's interest 76%), East Obayed (Enis' interest 75%) and South West Meleiha (Eni's interest 75%) concessions; and (iv) Baltim (Eni's interest 50%), North El Hammad (Eni's interest 37.5%), Nile Delta (Eni's interest 75%), North Port Said (Eni's interest 100%), and Temsah (Eni's interest 50%) concessions. In addition, Eni participates in the Ras el Barr (Eni's interest 50%) and South Ghara (Eni's interest 25%) 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.

In 2023 production start-up was achieved at the Faramid gas field in the Western Desert concession leveraging on the existing facilities and plants in the area.

Development Development activities of the Zohr production project concerned: (i) water shut-off program for gas production optimization; (ii) EPCI activities for the construction of a news subsea infrastructures; and (iii) development activities to increase water production treatment capacity by means of the facilities upgrading and the installation of two additional treatment units. The Zohr development activities progressed also by means of several local development initiatives. The defined programs with an overall expense expected in \$20 million until 2024, include among the main areas: (i) technical education, with several ongoing projects, including the Zohr Applied Technology School (ATS) that launched training programs for approximately 400 students during the year. In particular, through transition work unit 80 students, 58 of whom are women, obtained a stable employment contract; and (ii) economic diversification, with two projects to improve the community's resilience in high vulnerability to desertification, in particular in the South Sinai and Matrouh areas. In the year a training program for approximately 120 farmers and breeders was completed, while activities progressed to improve water supply and distribution facilities for approximately 2,000 people as well as literacy courses. Development activities also concerned: (i) production optimization in the Sinai concession by means of new wells drilled and workover and water-injection programs; (ii) drilling and completion of an additional production well, already started up, in the Baltimo-Neho area; (iii) drilling of an additional well in the Nile Delta concession and the upgrading of the Nidoco NW transport facilities to the treatment plant with an increased production; and (iv) optimization gas production program in the Rasl el Barr concession leveraging on a new compression unit. In addition, in the Western Desert concession development activities concerned: (i) the Meleiha Phase 2, in early production by 2022, by means of the installation of a new pipeline to existing treatment plant; and (ii) production optimization initiatives leveraging on the drilling program of additional production oil and gas wells.

Exploration Exploration activities yielded positive results with: (i) the Nargis 1X discovery in the East Med area (Eni's interest 45%) with 2.8 TCF of gas resource in place; (ii) the two oil and gas discoveries in the Sinai and Nile Delta concessions, respectively; and (iii) the three oil exploration discoveries in the Western Desert concession. New discoveries confirmed the positive track-record of Eni's exploration in the Country leveraging on the continuous technology progress in exploration activities that allows to re-evaluate the residual mineral potential in mature production areas.

The LNG business in Egypt

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

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 is Angola's largest independent equity oil and gas producer and is a further example of Eni's distinctive satellite model designed to unlock value.

It holds interests in 83 licenses (of which 56 development licenses and 27 exploration licenses) relating to 20 blocks (of which 5 exploration blocks) and also in the Angola LNG JV and Solenova, a solar company jointly held with Sonangol that in March 2023 achieved solar energy production start-up at the 25 MW photovoltaic plant in Caraculo, located near Namibia. In addition the collaboration in the Luanda Refiner progressed.

Activities are performed over a developed and undeveloped acreage of 48,885 square kilometers (7,633 square kilometers net to Eni).

In September 2023 Azule signed a Memorandum of Understanding with Sonangol to jointly collaborate in the decarbonization program in the Country. Agreement includes to assess initiatives in the renewable energy area, low carbon activities and nature-based solutions (Natural Climate Solutions) such as forestry and the promotion of efficient cooking stoves (Improved Cookstoves - ICS). During 2023 Azule achieved an agreement to divest its interest and

operatorship of the Cabinda Norte block.

Exploration and production activities in Angola are regulated by concessions, PSAs, and Risk Service Contract.

Production In 2023 production amounted to 108 kboe/d net to Eni and mainly comes from operated fields of the Block 31 (Eni's interest 13.33%), Block 18 (Eni's interest 23%) and Block 15/06 (Eni's interest 18.42%); and non-operated Block 17 (Eni's interest 7.9%), Block 15 (Eni's interest 21%), Block 0 (Eni's interest 4.90%), Blocks 3 and 3/05- A (Eni's interest 6%), Block 14 (Eni's interest 10%) and Block 14K/A IMI (Eni's interest 5%).

Development Development activities concerned: (i) start-up development activities of the Quiluma and Maboqueiro fields within the New Gas Consortium project. The project, first non-associated gas development in the Country, provides for the installation of two offshore platform production, an onshore treatment plant and linkage facilities to A-LNG liquefaction plant. Production startup is expected in 2026 with an estimated production plateau of approximately 330 mmcf/d; (ii) the Agogo Integrated West Hub project in the western area of the Block 15/06 was sanctioned. Main contracts were already awarded, and production start-up is expected in 2026 with an estimated production peak of 170 kboe/d; (iii) optimization development studies progressed at the PAJ project in the Block 31; (iv) development activities of the Cuica and Cabaça fields and the Ndungu early production project were completed in the Block 15/06. Production started up by means of the linkage to existing facilities in the area; (v) programs to support health services in the Luanda area also by means of the electrification of health centers with photovoltaic plants as well as several initiatives in the Namibe, Huila and Cabinda areas in access to water, education, primary health services and in the agricultural sector also supporting youth employment; and (vi) food safety programs in the Cunene area as well as child protection initiatives in the Zaire area.

Exploration Exploration activities yielded positive results with the Lumpembe-1X oil exploration well in the block 15/06. Development studies are ongoing to possible integration with other discoveries in the southern area of the block. In addition, an extension of exploration agreement was finalized.

Congo

Eni has been present in Congo since 1968. In 2023, production averaged 68 kboe/d net to Eni. 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 2,291 square kilometers (1,299 square kilometers net to Eni).

In March 2024, Eni finalized with Perenco the sale of its participating interest in several production licences in the Country.

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

Production Eni's main operated producing interests are the Néné Marine and Litchendjili (Block Marine XII, Eni's interest 65%), Ikalou (Eni's interest 85%), Djambala (Eni's interest 50%), Foukanda and Mwafi (Eni's interest 58%), Kitina (Eni's interest 52%), Awa Paloukou (Eni's interest 90%) and M'Boundi (Eni's interest 83%) fields with an overall production of approximately 81 kboe/d (60 kboe/d net to Eni) in 2023. Other relevant non-operated producing areas are located in the Pointe-Noire Grand Fond (Eni's interest 29.75%) and Likouala (Eni's interest 35%) permits, with an overall production of approximately 22 kboe/d (8 kboe/d net to Eni).

In December 2023, the Congo LNG project was started up by means of the offshore installation of the Tango FLNG liquefaction plant, with a capacity of approximately 35 bcf/y, and the Excalibur Floating Storage Unit (FSU). Development plan includes the installation of two floating gas liquefaction units (FLNG), one LNG storage unit (FSU), seven new platforms, an onshore treatment plant and drilling of 41 wells. Main contracts were awarded. The second FLNG unit with a capacity of approximately 120 bcf/y is already under construction. Start-up is expected in 2025. The project is expected to monetize the gas volumes of the Marine XII block for the Country's energy needs and by exploiting the surplus gas for LNG production. Development activity is planned to also leverage on the existing assets, through modular and phased program and targeting zero routine flaring. Liquefaction gas capacity is planned to achieve approximately 160 bcf/y at plateau. According to the agreements recently signed, all LNG production will be marketed by Eni.

Development Development activities concerned the completion of the Néné Phase 2B project. In particular, drilling and completion activities of all planned production well were completed. In March 2023, the Oyo Center of Excellence for Renewable Energy and Energy Efficiency was opened, stemming from the agreement by Eni and the Republic of Congo signed in 2016 to enhance the Country's energy sources, promoting the social and economic development. In the 2023-2028 periods the Oyo center will be managed by UNIDO to progressively achieve operation. During the year activities progressed to support the integrated project in the HINDA district. The project includes the socio-economic development of the local communities with education, sanitary service an access to water initiatives as well as in the agricultural sector with the CATREP program.

Exploration Exploration activities yielded positive results with the Poalvou Marine 2 gas and condensates and the Mbenga Marine 1 oil and gas discoveries in the Marine VI Bis (Eni 65%) permit. Both declarations of discovery were notified to the relevant authority.

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 4,523 square kilometers (3,960 square kilometers net to Eni). Eni operates the Exclusive Area Development in the blocks CI-101 AEE and CI-802 AEE (Eni's interest 77,25%) and holds operatorship with a 90% interest in other five exploration areas: CI-802, CI-205, CI-501, CI-401 and CI-801 blocks.

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

Production In August 2023, start-up production was achieved at the Baleine oilfield in the operated offshore CI-101 and CI-802 blocks, with a rapid time-to-market leveraging on the Eni's distinctive phased and fast-tracked development approach, in less two years after discovery and in less one year and half after FID. In 2023 production amounted to 6 kboe/d net to Eni. The project will be a Scope 1 and 2 Net Zero developments, the first of this kind in Africa. Natural gas production will be supplied to the national grid and will support the country's energy needs and access to energy as well as strengthening its role such as regional energy hub in the area.

Development Full field development of the Baleine field includes two additional phases. The Phase 2 sanctioned program is expected to achieve first oil at the end of 2024. Main contracts for the additional facilities constructions were awarded while the drilling and completion of additional wells is expected to start-up in 2024. In 2023 local development programs were launched, with a budget spending of \$20 million until 2027, in the following areas: (i) health, with two projects to support a total of 20 health centers and non-profit clinics; (ii) professional training by means of a project in collaboration with the Iveco Group supporting access to work for 300 young people; (iii) economic diversification, through the kick-off of a partnership with the United Nations for the construction of a textile production centre; and (iv) access to education, with the renovation initiatives of 20 primary schools in the Abidjan district and the South Comoé region, as well as continuing the associated training activities of teacher and school supplies distribution to more than 6,500 students.

Ghana

Eni has been present in Ghana since 2009. Developed and undeveloped acreage in deep offshore was 1,156 square kilometers (495 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 42.45% interest the offshore exploration license Cape Three Points Block 4 (CTP-4).

Production In 2023, production averaged 31 kboe/d net to Eni and comes from the Sankofa field in the OCTP operated project. The OCTP project is the only non-associated gas development project in deep water entirely dedicated to the domestic market in Sub-Saharan Africa. This project will ensure at least 15 years of reliable gas supply, equal to 67% of demand, with an affordable price, significantly supporting the access to energy and economic development of the Country. The project has been developed in compliance with the highest environmental requirements, zero gas flaring and produced water reinjection and associated gas.

Development In the year development activities of the OCTP operated project concerned the completion of: (i) the upgrading activities of the facilities, FPSO unit and onshore gas plant to increase production capacity; (ii) water produced reinjection program; and (iii) additional activities to improve the power generation reliability of the gas-fired power plant. In 2023, programmes were completed in the access to education and economic diversification. In particular, training initiatives for teachers, awareness campaigns on human rights issues for students and families as well as "starter packs" to launch business activities that also including raining, coaching and mentoring activities for the project beneficiaries were finalized.

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 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 8,522 square kilometers (3,260 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 2023 production amounted to 22 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 Coral Sul FLNG's HSE Management System also obtained ISO 14001 (Environment) and 45001 (Occupational health & Safety) certifications in 2023. 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 Additional development phases to put into production the Area 4 reserves, are being evaluated by the delegated operators of Area 4 (Eni and ExxonMobil), which are expected to include offshore development options, based on the expertise achieved with the Coral South FLNG project, and onshore activities also through synergies with Area 1.

Exploration Eni is operator with a 49.55% interest of the exploration block A5-A and with a 60% interest of the exploration block A6-C. Eni also holds a 10% interest of the block A5-B.

Nigeria

Eni has been present in Nigeria since 1962. In 2023, Eni's oil and gas production averaged 63 kboe/d, over a developed and undeveloped acreage of 24,724 square kilometers (6,212 square kilometers net to Eni).

In the development/production phase Eni operates onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni's interest 20%) and offshore OML 125 (Eni's interest 100%) and OPL 245 (Eni's interest 50%). Eni also holds interests in OML 118 (Eni's interest 12.5%) and as partner of SPDC JV, the largest joint venture in the Country, Eni also holds a 5% interest in 15 onshore blocks and in 1 conventional offshore block as well as a 12.86% interest in 2 conventional offshore blocks. In the exploration phase Eni operates offshore OML 134 (Eni's interest 100%) and OPL 2009 (Eni's interest 49%) and onshore OPL 282 (Eni's interest 90%) and OPL 135 (Eni's interest 48%). Eni also holds a 12.5% interest in OML 135.

In September 2023, Eni signed an agreement with the local partner Oando PLC (Nigeria's leading indigenous energy solutions provider) to divest Eni' subsidiary Nigerian Agip Oil Company Ltd (NAOC Ltd), with onshore oil and gas exploration and production activities, as well as the ancillary power generation business. The agreement does not include Eni's interest in the SPDC JV (Eni's interest 5%). Following the transaction completion with Oando PLC, Eni will continue to run activities in the Country, focusing on its operated offshore assets. Participations in not operated assets and Nigeria LNG will remain in Eni portfolio too.

During the year activities to support local communities in the Niger Delta area, in addition to the Green River Project with initiatives for 50 agricultural cooperatives by means of microcredit schemes, included various initiatives relating to access to water, construction and rehabilitation of transportation road for certain communities in the area, scholarships distribution for secondary school students, post-secondary and university.

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

Blocks OMLs 60, 61, 62 and 63

Production Onshore four licenses produced approximately 26 kboe/d net to Eni in 2023. Liquid and gas production are supported by the Obiafu-Obrikom plant with a treatment capacity of approximately 1 bcf/d and by the oil tanker terminal at Brass with a storage capacity of approximately 3,25 mmbbl. A large portion of the gas reserves of these four OMLs is destined to supply the NLNG liquefaction plant (Eni's interet 10.4%) and then exported to the international market. Another portion of gas production is employed in firing the combined cycle power plant at Okpai (capacity of 480 MW) and the open cycle power plant in the River State (capacity of 150 MW).

Development Development activities concerned drilling and completion of one well to increase gas production in the Obiaafu field area in the OML 61 block.

Blocks OML 118

Production The Bonga oil field produced 12 kboe/d net to Eni in 2023. Production is supported by an FPSO unit with a 225 kboe/d treatment capacity and a 2 mmboe storage capacity. Associated gas is delivered through pipeline to the Bonny NLNG liquefaction plant. Development Development activities concerned drilling of one production wells and two injection wells at the Bonga field and the linkage to production facilities existing in the area.

Blocks OML 125

Production Production derived mainly from the Abo field which yielded approximately 9 kboe/d net to Eni in 2023. Production is supported by an FPSO unit with a 40 kboe/d treatment capacity and over 990 kboe storage capacity.

SPDC joint venture (NASE)

Production In 2023, production from the SPDC JV amounted to approximately 16 kboe/d net to Eni.

Development Development activities concerned: (i) drilling, completion, and start-up of seven oil production wells at the Ogbo and Tunu fields; (ii) completion and linkage of four production wells in the Forcados Yokri area; and (iii) production start-up of an additional gas well in the Gbaran area. In addition, during 2023, FID of the Epu Phase 2 project was sanctioned.

The LNG business in Nigeria

Eni holds also a 10.4% interest in the Nigeria LNG Ltd joint venture, which runs the Bonny liquefaction plant located in the Eastern Niger Delta. The plant has a production capacity of 22 mmtonnes/y of LNG associated with approximately 1,270 bcf/y of feed gas. Natural gas supplies to the plant are currently provided under a gas supply agreement from the SPDC JV, TEPNG JV and the NAOC JV (Eni's interest 20%). In 2023, the Bonny liquefaction plant processed approximately 740 bcf. LNG production is sold under long-term contracts and exported mainly to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG, as well as is sold FOB by means of the fleet owned by third parties.

Kazakhstan

Eni has been present in Kazakhstan since 1992, over a developed and undeveloped acreage of 6,244 square kilometers (1,947 square kilometers net to Eni). Eni is co-operator of the Karachaganak field and holds interest in the North Caspian Operating Company (NCOC) which operates the Kashagan field trough the North Capsian Sea Production Sharing Agreement (NCSPSA). In addition, Eni is a 50% partner with State company Kaz-MunayGas (KMG) in the Isatay Operating Company (IOC), which operates the Abay block, located in the Kazakh sector of the Caspian Sea.

Kashagan

Eni holds a 16.81% 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 over an area extending for approximately 3,300 square kilometers (approximately 560 square kilometers net to Eni). The NCSPSA expires at the end of 2041.

Production In 2023, production averaged 85 kboe/d net to Eni. 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 of the Kashagan field 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 management capacity increase of associated gas with: (i) increasing gas reinjection capacity by means of upgrading the existing facilities. Activities were 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 volume.

Karachaganak

Located onshore in West Kazakhstan, Karachaganak (Eni's interest 29.25%) is a liquid and gas giant field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA. Eni and Shell are co-operators of the venture.

Production In 2023, production of the Karachaganak field averaged 78 kboe/d net to Eni. This field is producing 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 During 2023 the additional development phase, sanctioned in 2020, of the Karachaganak field progressed and included: (i) the drilling of three new injection wells; (ii) the construction of a new sixth injection line; (iii) the installation of a fifth compression gas unit. Start-up is expected in 2024; and (iv) the installation of a sixth compression unit, last development phase, sanctioned in 2022. Start-up is expected in 2026.

Eni continues its commitment to support local communities in the nearby area of the Karachaganak field. In particular, initiatives progressed with: (i) professional training; and (ii) realization of kindergartens and schools, roads maintenance, construction of sport centers; and (iii) medical-health support also by means of the materials and equipment distribution to hospitals and clinics.

Rest of Asia

Indonesia

Eni has been present in Indonesia since 2001. In 2023, Eni's production amounted to 79 kboe/d, mainly gas. Activities are concentrated in the offshore of East Kalimantan, offshore Sumatra, as well as offshore and onshore of West Timor and West Papua, over a developed and undeveloped acreage of 19,757 square kilometers (12,128 square kilometers net to Eni); in total, Eni holds interests in 13 blocks.

In 2023, Eni acquired Chevron's development and production assets in offshore Indonesia. The operation will ensure the fast-track development of ongoing projects in the area and the integration with Neptune Energy assets. This acquisition is in line with Eni's energy transition strategy to increase the share of natural gas production to 60% by 2030. Exploration and production activities are regulated by Product Sharing Agreements (PSAs).

Production Production comes mainly from: (i) the operated Muara Bakau block (Eni's interest 55%) with the Jangkrik gas production field. Production in the Jangkrik gas project 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 operated East Sepinggan block (Eni's interest 65%) with the Merakes gas project. Production flows from five subsea wells which are tied-back to the Floating Production Unit (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.

Development Development activities concerned: (i) the Merakes East project in the operated East Sepinggan block, in the deep offshore eastern Kalimantan; (ii) the Maha project in the operated West Ganal offshore block (Eni's interest 40%). Development activities were defined; (iii) upgrading activities of the gas compression facilities in the operated Muara Bakau block; and (iv) many initiatives implemented to support local communities in the primary education, access to water and renewable energy, economic diversification activities and to strength professional skills in the Samboja and Muara Java areas, in the Eastern Kalimantan.

Exploration Exploration activities yielded positive results with the important Geng North-1 gas discovery, in the operated North Ganal offshore license (Eni's interest 50.22%), with a preliminary estimated discovered volume of 5 trillion cubic feet (tcf) of gas and 400 mmbbl condensate in place. This discovery, together with the acquisition of Neptune and Chevron assets, opens up exciting potential in the Indonesia gas sector. Massive natural gas resources will be developed in synergy with the Eni's existing operating fields, new developments and leveraging on the Bontang LNG export terminal, offering the prospect of transforming the Kutei basin into a new world class gas hub.

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 (Eni's interest 41.56%) with a production of 38 kboe/d net to Eni in 2023.

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. 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.

In 2023 Eni's commitment progressed with projects in the areas of education, health, environment, and access to water. In particular: (i) the construction of a new school at the Zubair with completion expected in 2024, as well as renovation and material supply initiatives to schools; (ii) construction of a nuclear medicine department and a new pediatric oncology department at the Basra Cancer Children Hospital were completed; and (iii) the completion of the Al-Bardjazia drinking water supply plant in the Zubair area while the construction of the new Al-Buradeiah plant in Bassore is ongoing.

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 four trains with a combined liquefaction capacity of 32 mmtonnes/year. Production start-up is expected by the end of 2025, and development program include 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, in which Eni and other international companies participate. In 2023 Eni signed a long-term LNG supply contract with QatarEnergy for the delivery of up to 1.5 bcm/y of LNG. The volumes will be delivered at the terminal located in Piombino, Italy, starting from 2026 with a duration of 27 years, contributing to Italy's supply security.

Timor Leste

Eni has been present in Timor Leste since 2006 and is performing exploration and development activities over a developed and undeveloped acreage of 6,644 square kilometers (5,960 square kilometers net to Eni).

Eni participates with a 10.99% interest in the production Block PSC-TL-SO-T 19-13. In addition, Eni holds interests in 2 exploration licenses. In December 2023, Eni was awarded the TL-SO-22-23 exploration block in the Timor Sea.

Production Production comes mainly from the Bayu Undan gas and liquid field with a production of 23 kboe/d (approximately 2 kboe/d net to Eni) in 2023. Liquid production is supported by two treatment platforms and an FSO unit. Production of natural gas is treated at the Darwin liquefaction plant which has a capacity of 3.6 mmtonnes/y of LNG (equivalent to approximately 177 bcf/y of feed gas). During the year, the LNG production was sold on a spot basis in international markets. The Bayu Undan production shutdown is expected in 2024; the remaining gas volumes have been sold in the domestic market.

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). In 2023, Eni's production averaged 7 kboe/d.

Exploration and production activities in Turkmenistan are regulated by PSAs.

Production Production 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 gas lift system. The remaining amount is delivered to the national oil company Turkmenneft, via national grid.

Development Development activities mainly concerned drilling of infilling wells to maximize hydrocarbons recovery of the Burun field.

United Arab Emirates

Eni has been present in United Arab Emirates since 2018 over a developed and undeveloped acreage of 32,620 square kilometers (17,830 square kilometers net to Eni).

Eni holds interest in the Lower Zakum (Eni's interest 5%) and Umm Shaif/Nasr (Eni's interest 10%) production concessions. These concessions, with duration of 40 years, are in the offshore Abu Dhabi with oil, condensates and gas production. In addition, Eni participates with a 50% interest in the Mahani-Area B production concession in the Emirate of Sharjah.

Eni also holds a 10% interest in the offshore Ghasha concession, with a duration of 40 years until 2058, under development. The UDR (Undeveloped Discovered Reservoirs) program provides for the development of different fields among which Dalma, Hail and Ghasha.

In the exploration phase Eni operates: (i) Blocks 1, 2 and 3 with a 70% interest, in the offshore Abu Dhabi; (ii) Area A and C onshore concessions with a 50% interest in the Emirate of Sharjah; (iii) Block offshore A and Block onshore 7 with a 90% interest in the Emirate of Ras al Khaimah.

In March 2023 Eni signed a Memorandum of Understanding (MoU) with ADNOC for future joint projects in the areas of energy transition, sustainability and decarbonization. The agreement includes to explore potential opportunities in the sector of renewable energy, blue and green hydrogen, carbon dioxide capture and storage (CCS), in the reduction of GHG and methane gas emissions, energy efficiency, routine gas flaring reduction and the commitment in the Global Methane Pledge, to support global energy security and a sustainable energy transition.

Production In 2023 production averaged 56 kboe/d net to Eni and comes from Lower Zaku and Umm Shaif/Nasr fields as well as Mahani field.

Development Development activities of the year concerned: (i) the Dalma Gas Development sanctioned project in the offshore Ghasha concession (Eni's interest 10%) and the Umm Shaif Long-Term Development Phase 1 sanctioned project in the Umm Shaif and Nasr concession; (ii) development project of the Hali and Ghasha fields in the Ghasha concession was sanctioned and two contracts for the planned construction of treatment plant were awarded; and (iii) studies to develop recent discoveries (2022) in the Block 2 are underway.

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 (3,442 square kilometers net to Eni). Eni's activities are concentrated in 8 blocks, of which 7 are operated, in the Gulf of Mexico.

Eni operates the offshore Area 1 production license (Eni's interest 100%) where are located the the Amoca, Miztón and Tecoalli fields. In the exploration phase, Eni is operator of the Area 10 (Eni's interest 76%), Area 14 (Eni's interest 60%), Area 7 (Eni's interest 64%), Area 24 (Eni's interest 65%) and Area 28 (Eni's interest 75%). In addition, Eni holds interests in the Block OBO AC 12 (Eni's interest 40%).

Based on the Memorandum of Understanding signed in 2022 with the United Nations Educational, Scientific, and Cultural Organization (UNESCO), joint initiatives are being defined to support local economy sustainable development by means of environmental and cultural heritage protection, economic diversification, human rights respect and inclusion.

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

Production In 2023 production comes from the operated Area 1 license and amounted to 26 kboe/d.

Development Development activities of the year concerned the last full field development phase of the operated Area 1 license. In particular, activities provide for the construction and installation of two additional platform in the Amoca and Tecoalli fields. In addition, ongoing drilling activities include the completion of planned wells to achieve production ramp-up.

Within the cooperation agreement with the local Authorities relating to health, education and environment, as well as economic diversification initiatives to support the improvement of living conditions and local development, during the year the activities concerned: (i) restructuring of school buildings; (ii) activities to promote primary education; (iii) initiatives to improve socioeconomic conditions of communities with development programs in particular in fishing activity; (iv) launched a youth development program; and (v) awareness campaigns in the field of access to energy, environmental protection and social issues.

Exploration Exploration activities yielded positive results with the Yatzil discovery in the Area 7 license.

United States

Eni has been present in the United States since 1968. Activities are performed in the Gulf of Mexico and Alaska, over a developed

and undeveloped acreage of 1,137 square kilometers (631 square kilometers net to Eni). In 2023, Eni's oil and gas production was 55 kboe/d.

In February 2023, Eni finalized the divestment of the Alliance area (Eni's interest 27.5%) in the Fort Worth basin, in Texas, containing unconventional gas reserves (shale gas).

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

Gulf of Mexico

Eni holds interests in 45 exploration and development blocks in the conventional and deep offshore of the Gulf of Mexico, of which 15 are operated by Eni.

Production The main fields operated by Eni with a 100% interest are Allegheny, Appaloosa, Pegasus, Devils Towers and Triton; as well as Longhorn (Eni's interest 75%). Eni also holds interests in Europa (Eni's interest 32%), Medusa (Eni's interest 25%), Lucius (Eni's interest 14.45%), K2 (Eni's interest 13.4%), Frontrunner (Eni's interest 37.5%) and Heidelberg (Eni's interest 12.5%) fields. In 2023, production amounted to 35 kboe/d net to Eni.

Alaska

Eni operates 27 exploration and development blocks and holds interest in 1 block.

Production The main operated fields are Nikaitchuq (Eni's interest 100%) and Oooguruk (Eni's interest 100%) with a 2023 overall net production of approximately 20 kbbl/d.

Venezuela

Eni has been present in Venezuela since 1998. In 2023, Eni's production averaged 58 kboe/d. 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 2,804 square kilometers (1,066 square kilometers net to Eni).

Production Eni's production comes from the Perla gas field in the Gulf of Venezuela (Eni's interest 50%), the Junín 5 oil field (Eni's interest 40%) located in the Orinoco Oil Belt and from the Corocoro oil field (Eni's interest 26%) in the Gulfo de Paria.

Australia and Oceania

Australia

Eni has been present in Australia since 2001. In 2023, Eni's production averaged 7 kboe/d. Activities are focused in the offshore of the country, over a developed and undeveloped acreage of 3,336 square kilometers (2,751 square kilometers net to Eni). The main production block in which Eni holds interests is WA-33-L (Eni's interest 100%). In addition, Eni participates in two exploration licenses.

Production Production comes from the Blacktip gas field startedup in 2009. The project is supported by a production platform and carried by a 108-kilometer-long pipeline to an onshore treatment plant with a capacity of 42 bcf/y. Natural gas extracted from this field is sold under a 25-year contract to supply a power plant, signed with Australian society Power & Water Utility Co.

Movements in net proved hydrocarbons reserves

(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2023(a)
Consolidated subsidiaries
Reserves at December 31, 2022	352	78	806	904	813	941	675	285	79	4,933
of which: developed	271	73	329	655	460	881	383	207	43	3,302
undeveloped	81	5	477	249	353	60	292	78	36	1,631
Purchase of minerals in place			44							44
Revisions of previous estimates	47	(4)	223	(95)	56	52	58	5	(39)	303
Improved recovery
Extensions and discoveries				1	1		103			105
Production	(25)	(14)	(109)	(116)	(61)	(60)	(67)	(30)	(3)	(485)
Sales of minerals in place							(36)	(22)		(58)
Reserves at December 31, 2023	374	60	964	694	809	933	733	238	37	4,842
Equity-accounted entities
Reserves at December 31, 2022		473	9		531		383	285		1,681
of which: developed		257	9		338			285		889
undeveloped		216			193		383			792
Purchase of minerals in place					2					2
Revisions of previous estimates		3			8		(5)	3		9
Improved recovery
Extensions and discoveries
Production		(50)	(1)		(47)			(21)		(119)
Sales of minerals in place		(1)								(1)
Reserves at December 31, 2023		425	8		494		378	267		1,572
Reserves at December 31, 2023	374	485	972	694	1,303	933	1,111	505	37	6,414
Developed	261	291	388	555	787	872	379	451	11	3,995
consolidated subsidiaries	261	56	380	555	482	872	379	184	11	3,180
equity-accounted entities		235	8		305			267		815
Undeveloped	113	194	584	139	516	61	732	54	26	2,419
consolidated subsidiaries	113	4	584	139	327	61	354	54	26	1,662
equity-accounted entities		190			189		378			757

(a) Effective January 1, 2023, Eni has updated the conversion rate of gas produced to 5,232 cubic feet of gas equals to 1 barrel of oil (it was 5,263 cubic feet of gas per barrel in previous reporting period). The effect of this update on the change in the initial reserves balance as of January 1, 2023 amounted to 21 mmboe.

(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2022(a)
Consolidated subsidiaries
Reserves at December 31, 2021	369	81	820	992	1,145	1,032	762	288	82	5,571
of which: developed	283	80	373	852	766	963	445	203	51	4,016
undeveloped	86	1	447	140	379	69	317	85	31	1,555
Purchase of minerals in place	1		18					3		22
Revisions of previous estimates	12	9	49	27	(111)	(45)	(23)	17	1	(64)
Improved recovery			3					4		7
Extensions and discoveries		4	13	11	90					118
Production	(30)	(16)	(97)	(126)	(84)	(46)	(63)	(27)	(4)	(493)
Sales of minerals in place					(227)		(1)			(228)
Reserves at December 31, 2022	352	78	806	904	813	941	675	285	79	4,933
Equity-accounted entities
Reserves at December 31, 2021		502	10		263			282		1,057
of which: developed		261	10		39			282		592
undeveloped		241			224					465
Purchase of minerals in place					168		383			551
Revisions of previous estimates		66			64			22		152
Improved recovery					4					4
Extensions and discoveries		7			54					61
Production		(53)	(1)		(22)			(19)		(95)
Sales of minerals in place		(49)								(49)
Reserves at December 31, 2022		473	9		531		383	285		1,681
Reserves at December 31, 2022	352	551	815	904	1,344	941	1,058	570	79	6,614
Developed	271	330	338	655	798	881	383	492	43	4,191
consolidated subsidiaries	271	73	329	655	460	881	383	207	43	3,302
equity-accounted entities		257	9		338			285		889
Undeveloped	81	221	477	249	546	60	675	78	36	2,423
consolidated subsidiaries	81	5	477	249	353	60	292	78	36	1,631
equity-accounted entities		216			193		383			792

(a) Effective January 1, 2022, Eni has updated the conversion rate of gas produced to 5,263 cubic feet of gas equals 1 barrel of oil (it was 5,310 cubic feet of gas per barrel in previous reporting periods). The effect of this update on the change in the initial reserves balance as of January 1, 2022 amounted to 30 mmboe.

(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2021
Consolidated subsidiaries
Reserves at December 31, 2020	243	73	798	1,110	1,352	1,182	879	256	91	5,984
of which: developed	199	68	434	1,022	799	1,093	424	162	60	4,261
undeveloped	44	5	364	88	553	89	455	94	31	1,723
Purchase of minerals in place								2		2
Revisions of previous estimates	156	22	109	11	(149)	(97)	(52)	45	(3)	42
Improved recovery					2			10		12
Extensions and discoveries		1	8	2	51					62
Production	(30)	(15)	(95)	(131)	(106)	(53)	(65)	(25)	(6)	(526)
Sales of minerals in place					(5)					(5)
Reserves at December 31, 2021	369	81	820	992	1,145	1,032	762	288	82	5,571
Equity-accounted entities
Reserves at December 31, 2020		496	14		87			324		921
of which: developed		254	14		47			324		639
undeveloped		242			40					282
Purchase of minerals in place
Revisions of previous estimates		61	(3)		183			(25)		216
Improved recovery
Extensions and discoveries		8								8
Production		(63)	(1)		(7)			(17)		(88)
Sales of minerals in place
Reserves at December 31, 2021		502	10		263			282		1,057
Reserves at December 31, 2021	369	583	830	992	1,408	1,032	762	570	82	6,628
Developed	283	341	383	852	805	963	445	485	51	4,608
consolidated subsidiaries	283	80	373	852	766	963	445	203	51	4,016
equity-accounted entities		261	10		39			282		592
Undeveloped	86	242	447	140	603	69	317	85	31	2,020
consolidated subsidiaries	86	1	447	140	379	69	317	85	31	1,555
equity-accounted entities		241			224					465

2 1

(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2020(a)
Consolidated subsidiaries
Reserves at December 31, 2019	333	89	974	1,225	1,453	1,108	742	268	95	6,287
of which: developed	258	82	553	1,033	863	1,046	372	182	61	4,450
undeveloped	75	7	421	192	590	62	370	86	34	1,837
Purchase of minerals in place
Revisions of previous estimates	(51)	3	(84)	(9)	26	133	185	11	2	216
Improved recovery							5			5
Extensions and discoveries				1			11	5		17
Production	(39)	(19)	(92)	(107)	(127)	(59)	(64)	(28)	(6)	(541)
Sales of minerals in place
Reserves at December 31, 2020	243	73	798	1,110	1,352	1,182	879	256	91	5,984
Equity-accounted entities
Reserves at December 31, 2019		567	16		63			335		981
of which: developed		330	16		23			335		704
undeveloped		237			40					277
Purchase of minerals in place
Revisions of previous estimates		(33)			32			4		3
Improved recovery
Extensions and discoveries		30								30
Production		(68)	(2)		(8)			(15)		(93)
Sales of minerals in place
Reserves at December 31, 2020		496	14		87			324		921
Reserves at December 31, 2020	243	569	812	1,110	1,439	1,182	879	580	91	6,905
Developed	199	322	448	1,022	846	1,093	424	486	60	4,900
consolidated subsidiaries	199	68	434	1,022	799	1,093	424	162	60	4,261
equity-accounted entities		254	14		47			324		639
Undeveloped	44	247	364	88	593	89	455	94	31	2,005
consolidated subsidiaries	44	5	364	88	553	89	455	94	31	1,723
equity-accounted entities		242			40					282

(a) Effective January 1, 2020, Eni has updated the conversion rate of gas produced to 5,310 cubic feet of gas equals 1 barrel of oil (it was 5,408 cubic feet of gas per barrel in previous reporting periods). The effect of this update on the change in the initial reserves balance as of January 1, 2020 amounted to 67 mmboe.

(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2019
Consolidated subsidiaries
Reserves at December 31, 2018	428	106	1,022	1,246	1,361	1,066	700	302	125	6,356
of which: developed	336	99	582	764	895	925	403	170	87	4,261
undeveloped	92	7	440	482	466	141	297	132	38	2,095
Purchase of minerals in place								30		30
Revisions of previous estimates	(50)	2	90	106	190	97	67	(20)	(23)	459
Improved recovery
Extensions and discoveries		1		2	35		53	10		101
Production	(45)	(20)	(138)	(129)	(129)	(55)	(69)	(25)	(7)	(617)
Sales of minerals in place(a)					(4)		(9)	(29)		(42)
Reserves at December 31, 2019	333	89	974	1,225	1,453	1,108	742	268	95	6,287
Equity-accounted entities
Reserves at December 31, 2018		363	14		68			352		797
of which: developed		205	14		17			347		583
undeveloped		158			51			5		214
Purchase of minerals in place		184								184
Revisions of previous estimates		59	3		3			(3)		62
Improved recovery
Extensions and discoveries		6								6
Production		(39)	(1)		(8)			(14)		(62)
Sales of minerals in place		(6)								(6)
Reserves at December 31, 2019		567	16		63			335		981
Reserves at December 31, 2019	333	656	990	1,225	1,516	1,108	742	603	95	7,268
Developed	258	412	569	1,033	886	1,046	372	517	61	5,154
consolidated subsidiaries	258	82	553	1,033	863	1,046	372	182	61	4,450
equity-accounted entities		330	16		23			335		704
Undeveloped	75	244	421	192	630	62	370	86	34	2,114
consolidated subsidiaries	75	7	421	192	590	62	370	86	34	1,837
equity-accounted entities		237			40					277

(a) Includes approximately 4 mmboe as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make-up) the volume paid.

(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2018
Consolidated subsidiaries
Reserves at December 31, 2017	422	525	1,052	1,078	1,436	1,150	427	203	137	6,430
of which: developed	350	360	532	463	856	891	238	176	101	3,967
undeveloped	72	165	520	615	580	259	189	27	36	2,463
Purchase of minerals in place							332			332
Revisions of previous estimates	40	15	114	431	34	(32)	(39)	31	(4)	590
Improved recovery				7			6			13
Extensions and discoveries	16				14		39	100		169
Production	(50)	(71)	(144)	(110)	(123)	(52)	(65)	(27)	(8)	(650)
Sales of minerals in place		(363)		(160)				(5)		(528)
Reserves at December 31, 2018	428	106	1,022	1,246	1,361	1,066	700	302	125	6,356
Equity-accounted entities
Reserves at December 31, 2017			14		75		1	470		560
of which: developed			14		20		1	359		394
undeveloped					55			111		166
Purchase of minerals in place		363								363
Revisions of previous estimates			1					(100)		(99)
Improved recovery
Extensions and discoveries
Production			(1)		(7)			(18)		(26)
Sales of minerals in place							(1)			(1)
Reserves at December 31, 2018		363	14		68			352		797
Reserves at December 31, 2018	428	469	1,036	1,246	1,429	1,066	700	654	125	7,153
Developed	336	304	596	764	912	925	403	517	87	4,844
consolidated subsidiaries	336	99	582	764	895	925	403	170	87	4,261
equity-accounted entities		205	14		17			347		583
Undeveloped	92	165	440	482	517	141	297	137	38	2,309
consolidated subsidiaries	92	7	440	482	466	141	297	132	38	2,095
equity-accounted entities		158			51			5		214

Movements in net proved liquids reserves

(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2023
Consolidated subsidiaries
Reserves at December 31, 2022	188	36	364	167	367	644	433	234	1	2,434
of which: developed	139	32	201	135	212	585	231	171	1	1,707
undeveloped	49	4	163	32	155	59	202	63		727
Purchase of Minerals in Place			4							4
Revisions of Previous Estimates	34	(2)	61	(3)	(2)	35	35	3	(1)	160
Improved Recovery
Extensions and Discoveries							50			50
Production	(11)	(7)	(45)	(25)	(31)	(42)	(31)	(24)		(216)
Sales of Minerals in Place							(2)			(2)
Reserves at December 31, 2023	211	27	384	139	334	637	485	213		2,430
Equity-accounted entities
Reserves at December 31, 2022		350	8		235		100	27		720
of which: developed		173	8		135			27		343
undeveloped		177			100		100			377
Purchase of Minerals in Place					2					2
Revisions of Previous Estimates		9	(1)		2		10			20
Improved Recovery
Extensions and Discoveries
Production		(32)	(1)		(32)			(1)		(66)
Sales of Minerals in Place		(1)								(1)
Reserves at December 31, 2023		326	6		207		110	26		675
Reserves at December 31, 2023	211	353	390	139	541	637	595	239		3,105
Developed	136	191	210	122	332	576	240	189		1,996
consolidated subsidiaries	136	24	204	122	225	576	240	163		1,690
equity-accounted entities		167	6		107			26		306
Undeveloped	75	162	180	17	209	61	355	50		1,109
consolidated subsidiaries	75	3	180	17	109	61	245	50		740
equity-accounted entities		159			100		110			369

(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2022
Consolidated subsidiaries
Reserves at December 31, 2021	197	34	393	210	589	710	476	237	1	2,847
of which: developed	146	34	225	164	435	641	262	164	1	2,072
undeveloped	51		168	46	154	69	214	73		775
Purchase of Minerals in Place	1		17					2		20
Revisions of Previous Estimates	3	6	(8)	(16)	(62)	(34)	(15)	13		(113)
Improved Recovery			2					4		6
Extensions and Discoveries		3	5	1	61					70
Production	(13)	(7)	(45)	(28)	(51)	(32)	(28)	(22)		(226)
Sales of Minerals in Place					(170)					(170)
Reserves at December 31, 2022	188	36	364	167	367	644	433	234	1	2,434
Equity-accounted entities
Reserves at December 31, 2021		378	9		21			6		414
of which: developed		175	9		9			6		199
undeveloped		203			12					215
Purchase of Minerals in Place					132		100			232
Revisions of Previous Estimates		38			37			22		97
Improved Recovery					4					4
Extensions and Discoveries		4			54					58
Production		(33)	(1)		(13)			(1)		(48)
Sales of Minerals in Place		(37)								(37)
Reserves at December 31, 2022		350	8		235		100	27		720
Reserves at December 31, 2022	188	386	372	167	602	644	533	261	1	3,154
Developed	139	205	209	135	347	585	231	198	1	2,050
consolidated subsidiaries	139	32	201	135	212	585	231	171	1	1,707
equity-accounted entities		173	8		135			27		343
Undeveloped	49	181	163	32	255	59	302	63		1,104
consolidated subsidiaries	49	4	163	32	155	59	202	63		727
equity-accounted entities		177			100		100			377

(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2021
Consolidated subsidiaries
Reserves at December 31, 2020	178	34	383	227	624	805	579	224	1	3,055
of which: developed	146	31	243	172	469	716	297	143	1	2,218
undeveloped	32	3	140	55	155	89	282	81		837
Purchase of Minerals in Place								1		1
Revisions of Previous Estimates	32	8	49	11	21	(58)	(74)	21		10
Improved Recovery					2			10		12
Extensions and Discoveries		(1)	6	2	16					23
Production	(13)	(7)	(45)	(30)	(72)	(37)	(29)	(19)		(252)
Sales of Minerals in Place					(2)					(2)
Reserves at December 31, 2021	197	34	393	210	589	710	476	237	1	2,847
Equity-accounted entities
Reserves at December 31, 2020		400	12		18			30		460
of which: developed		176	12		15			30		233
undeveloped		224			3					227
Purchase of Minerals in Place
Revisions of Previous Estimates		17	(2)		4			(23)		(4)
Improved Recovery
Extensions and Discoveries		2								2
Production		(41)	(1)		(1)			(1)		(44)
Sales of Minerals in Place
Reserves at December 31, 2021		378	9		21			6		414
Reserves at December 31, 2021	197	412	402	210	610	710	476	243	1	3,261
Developed	146	209	234	164	444	641	262	170	1	2,271
consolidated subsidiaries	146	34	225	164	435	641	262	164	1	2,072
equity-accounted entities		175	9		9			6		199
Undeveloped	51	203	168	46	166	69	214	73		990
consolidated subsidiaries	51		168	46	154	69	214	73		775
equity-accounted entities		203			12					215

(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2020
Consolidated subsidiaries
Reserves at December 31, 2019	194	41	468	264	694	746	491	225	1	3,124
of which: developed	137	37	301	149	519	682	245	148	1	2,219
undeveloped	57	4	167	115	175	64	246	77		905
Purchase of minerals in place
Revisions of previous estimates	1	1	(44)	(14)	10	100	114	16		184
Improved recovery							5			5
Extensions and discoveries							1	4		5
Production	(17)	(8)	(41)	(23)	(80)	(41)	(32)	(21)		(263)
Sales of minerals in place
Reserves at December 31, 2020	178	34	383	227	624	805	579	224	1	3,055
Equity-accounted entities
Reserves at December 31, 2019		424	12		10			31		477
of which: developed		219	12		7			31		269
undeveloped		205			3					208
Purchase of minerals in place
Revisions of previous estimates		(11)			9					(2)
Improved recovery
Extensions and discoveries		30								30
Production		(43)			(1)			(1)		(45)
Sales of minerals in place
Reserves at December 31, 2020		400	12		18			30		460
Reserves at December 31, 2020	178	434	395	227	642	805	579	254	1	3,515
Developed	146	207	255	172	484	716	297	173	1	2,451
consolidated subsidiaries	146	31	243	172	469	716	297	143	1	2,218
equity-accounted entities		176	12		15			30		233
Undeveloped	32	227	140	55	158	89	282	81		1,064
consolidated subsidiaries	32	3	140	55	155	89	282	81		837
equity-accounted entities		224			3					227

(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2019
Consolidated subsidiaries
Reserves at December 31, 2018	208	48	493	279	718	704	476	252	5	3,183
of which: developed	156	44	317	153	551	587	252	143	5	2,208
undeveloped	52	4	176	126	167	117	224	109		975
Purchase of minerals in place								29		29
Revisions of previous estimates	5	1	37	10	46	79	45	(16)	(4)	203
Improved recovery
Extensions and discoveries				2	21		2	9		34
Production	(19)	(8)	(62)	(27)	(90)	(37)	(32)	(20)		(295)
Sales of minerals in place(a)					(1)			(29)		(30)
Reserves at December 31, 2019	194	41	468	264	694	746	491	225	1	3,124
Equity-accounted entities
Reserves at December 31, 2018		297	11		12			37		357
of which: developed		154	11		8			32		205
undeveloped		143			4			5		152
Purchase of minerals in place		109								109
Revisions of previous estimates		45	2					(5)		42
Improved recovery
Extensions and discoveries		6								6
Production		(27)	(1)		(2)			(1)		(31)
Sales of minerals in place		(6)								(6)
Reserves at December 31, 2019		424	12		10			31		477
Reserves at December 31, 2019	194	465	480	264	704	746	491	256	1	3,601
Developed	137	256	313	149	526	682	245	179	1	2,488
consolidated subsidiaries	137	37	301	149	519	682	245	148	1	2,219
equity-accounted entities		219	12		7			31		269
Undeveloped	57	209	167	115	178	64	246	77		1,113
consolidated subsidiaries	57	4	167	115	175	64	246	77		905
equity-accounted entities		205			3					208

(a) Includes 0.6 mmboe as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make-up) the volume paid.

(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2018
Consolidated subsidiaries
Reserves at December 31, 2017	215	360	476	280	764	766	232	162	7	3,262
of which: developed	169	219	306	203	546	547	81	144	5	2,220
undeveloped	46	141	170	77	218	219	151	18	2	1,042
Purchase of minerals in place							319			319
Revisions of previous estimates	15	6	73	21	30	(27)	(54)	23	(1)	86
Improved recovery				7			6			13
Extensions and discoveries					13		1	86		100
Production	(22)	(40)	(56)	(28)	(89)	(35)	(28)	(19)	(1)	(318)
Sales of minerals in place		(278)		(1)						(279)
Reserves at December 31, 2018	208	48	493	279	718	704	476	252	5	3,183
Equity-accounted entities
Reserves at December 31, 2017			12		12			136		160
of which: developed			12		6			25		43
undeveloped					6			111		117
Purchase of minerals in place		297								297
Revisions of previous estimates					1			(96)		(95)
Improved recovery
Extensions and discoveries
Production			(1)		(1)			(3)		(5)
Sales of minerals in place
Reserves at December 31, 2018		297	11		12			37		357
Reserves at December 31, 2018	208	345	504	279	730	704	476	289	5	3,540
Developed	156	198	328	153	559	587	252	175	5	2,413
consolidated subsidiaries	156	44	317	153	551	587	252	143	5	2,208
equity-accounted entities		154	11		8			32		205
Undeveloped	52	147	176	126	171	117	224	114		1,127
consolidated subsidiaries	52	4	176	126	167	117	224	109		975
equity-accounted entities		143			4			5		152

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2023
Consolidated subsidiaries
Reserves at December 31, 2022	869	223	2,323	3,881	2,341	1,560	1,281	264	408	13,150
of which: developed	695	214	670	2,732	1,306	1,560	796	195	223	8,391
undeveloped	174	9	1,653	1,149	1,035		485	69	185	4,759
Purchase of Minerals in Place			214							214
Revisions of Previous Estimates	67	(10)	832	(506)	294	79	112	5	(202)	671
Improved Recovery
Extensions and Discoveries				4	5		275			284
Production(a)	(77)	(39)	(335)	(478)	(161)	(93)	(187)	(25)	(14)	(1,409)
Sales of Minerals in Place							(178)	(113)		(291)
Reserves at December 31, 2023	859	174	3,034	2,901	2,479	1,546	1,303	131	192	12,619
Equity-accounted entities
Reserves at December 31, 2022		646	9		1,562		1,490	1,355		5,062
of which: developed		444	9		1,070			1,355		2,878
undeveloped		202			492		1,490			2,184
Purchase of Minerals in Place
Revisions of Previous Estimates		(32)	6		22		(84)	7		(81)
Improved Recovery
Extensions and Discoveries
Production(b)		(97)	(1)		(83)			(102)		(283)
Sales of Minerals in Place		(2)								(2)
Reserves at December 31, 2023		515	14		1,501		1,406	1,260		4,696
Reserves at December 31, 2023	859	689	3,048	2,901	3,980	1,546	2,709	1,391	192	17,315
Developed	653	526	933	2,262	2,386	1,546	725	1,367	58	10,456
consolidated subsidiaries	653	167	919	2,262	1,350	1,546	725	107	58	7,787
equity-accounted entities		359	14		1,036			1,260		2,669
Undeveloped	206	163	2,115	639	1,594		1,984	24	134	6,859
consolidated subsidiaries	206	7	2,115	639	1,129		578	24	134	4,832
equity-accounted entities		156			465		1,406			2,027

(a) It includes production volumes consumed in operations equal to 206 bcf.

(b) It includes production volumes consumed in operations equal to 33 bcf.

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2022
Consolidated subsidiaries
Reserves at December 31, 2021	918	247	2,272	4,152	2,953	1,705	1,522	274	428	14,471
of which: developed	729	242	781	3,656	1,759	1,705	971	210	266	10,319
undeveloped	189	5	1,491	496	1,194		551	64	162	4,152
Purchase of Minerals in Place			6					2		8
Revisions of Previous Estimates	39	15	280	193	(285)	(73)	(53)	17	(1)	132
Improved Recovery			1							1
Extensions and Discoveries		7	37	52	154					250
Production(a)	(88)	(46)	(273)	(516)	(176)	(72)	(185)	(29)	(19)	(1,404)
Sales of Minerals in Place					(305)		(3)			(308)
Reserves at December 31, 2022	869	223	2,323	3,881	2,341	1,560	1,281	264	408	13,150
Equity-accounted entities
Reserves at December 31, 2021		654	10		1,285			1,460		3,409
of which: developed		457	10		165			1,460		2,092
undeveloped		197			1,120					1,317
Purchase of Minerals in Place					194		1,490			1,684
Revisions of Previous Estimates		144			127			(10)		261
Improved Recovery
Extensions and Discoveries		19								19
Production(b)		(108)	(1)		(44)			(95)		(248)
Sales of Minerals in Place		(63)								(63)
Reserves at December 31, 2022		646	9		1,562		1,490	1,355		5,062
Reserves at December 31, 2022	869	869	2,332	3,881	3,903	1,560	2,771	1,619	408	18,212
Developed	695	658	679	2,732	2,376	1,560	796	1,550	223	11,269
consolidated subsidiaries	695	214	670	2,732	1,306	1,560	796	195	223	8,391
equity-accounted entities		444	9		1,070			1,355		2,878
Undeveloped	174	211	1,653	1,149	1,527		1,975	69	185	6,943
consolidated subsidiaries	174	9	1,653	1,149	1,035		485	69	185	4,759
equity-accounted entities		202			492		1,490			2,184

(a) It includes production volumes consumed in operations equal to 208 bcf. (b) It includes production volumes consumed in operations equal to 27 bcf.

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2021
Consolidated subsidiaries
Reserves at December 31, 2020	348	208	2,201	4,692	3,864	2,003	1,589	175	474	15,554
of which: developed	280	194	1,014	4,511	1,751	2,003	674	109	315	10,851
undeveloped	68	14	1,187	181	2,113		915	66	159	4,703
Purchase of Minerals in Place								1		1
Revisions of Previous Estimates	661	78	321	(2)	(903)	(213)	120	125	(15)	172
Improved Recovery
Extensions and Discoveries		5	13		186		2			206
Production(a)	(91)	(44)	(263)	(538)	(179)	(85)	(189)	(27)	(31)	(1,447)
Sales of Minerals in Place					(15)					(15)
Reserves at December 31, 2021	918	247	2,272	4,152	2,953	1,705	1,522	274	428	14,471
Equity-accounted entities
Reserves at December 31, 2020		510	14		364			1,559		2,447
of which: developed		415	14		170			1,559		2,158
undeveloped		95			194					289
Purchase of Minerals in Place
Revisions of Previous Estimates		234	(3)		952			(12)		1,171
Improved Recovery
Extensions and Discoveries		28								28
Production(b)		(118)	(1)		(31)			(87)		(237)
Sales of Minerals in Place
Reserves at December 31, 2021		654	10		1,285			1,460		3,409
Reserves at December 31, 2021	918	901	2,282	4,152	4,238	1,705	1,522	1,734	428	17,880
Developed	729	699	791	3,656	1,924	1,705	971	1,670	266	12,411
consolidated subsidiaries	729	242	781	3,656	1,759	1,705	971	210	266	10,319
equity-accounted entities		457	10		165			1,460		2,092
Undeveloped	189	202	1,491	496	2,314		551	64	162	5,469
consolidated subsidiaries	189	5	1,491	496	1,194		551	64	162	4,152
equity-accounted entities		197			1,120					1,317

(a) It includes production volumes consumed in operations equal to 208 bcf.

(b) It includes production volumes consumed in operations equal to 15 bcf.

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2020
Consolidated subsidiaries
Reserves at December 31, 2019	752	262	2,738	5,191	4,103	1,969	1,349	240	507	17,111
of which: developed	657	242	1,374	4,777	1,858	1,969	685	186	322	12,070
undeveloped	95	20	1,364	414	2,245		664	54	185	5,041
Purchase of minerals in place
Revisions of previous estimates	(288)	5	(259)	(65)	9	138	356	(33)		(137)
Improved recovery
Extensions and discoveries				6			54	4		64
Production(a)	(116)	(59)	(278)	(440)	(248)	(104)	(170)	(36)	(33)	(1,484)
Sales of minerals in place
Reserves at December 31, 2020	348	208	2,201	4,692	3,864	2,003	1,589	175	474	15,554
Equity-accounted entities
Reserves at December 31, 2019		772	14		287			1,648		2,721
of which: developed		597	14		88			1,648		2,347
undeveloped		175			199					374
Purchase of minerals in place
Revisions of previous estimates		(128)	1		113			(12)		(26)
Improved recovery
Extensions and discoveries
Production(b)		(134)	(1)		(36)			(77)		(248)
Sales of minerals in place
Reserves at December 31, 2020		510	14		364			1,559		2,447
Reserves at December 31, 2020	348	718	2,215	4,692	4,228	2,003	1,589	1,734	474	18,001
Developed	280	609	1,028	4,511	1,921	2,003	674	1,668	315	13,009
consolidated subsidiaries	280	194	1,014	4,511	1,751	2,003	674	109	315	10,851
equity-accounted entities		415	14		170			1,559		2,158
Undeveloped	68	109	1,187	181	2,307		915	66	159	4,992
consolidated subsidiaries	68	14	1,187	181	2,113		915	66	159	4,703
equity-accounted entities		95			194					289

(a) It includes production volumes consumed in operations equal to 223 bcf.

(b) It includes production volumes consumed in operations equal to 16 bcf.

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2019
Consolidated subsidiaries
Reserves at December 31, 2018	1,199	320	2,890	5,275	3,506	1,989	1,217	277	651	17,324
of which: developed	980	300	1,447	3,331	1,871	1,846	822	154	452	11,203
undeveloped	219	20	1,443	1,944	1,635	143	395	123	199	6,121
Purchase of minerals in place								7		7
Revisions of previous estimates	(310)	4	267	467	747	79	104	(23)	(108)	1,227
Improved recovery
Extensions and discoveries		2			78		274	4		358
Production(a)	(137)	(64)	(419)	(551)	(210)	(99)	(198)	(24)	(36)	(1,738)
Sales of minerals in place(b)					(18)		(48)	(1)		(67)
Reserves at December 31, 2019	752	262	2,738	5,191	4,103	1,969	1,349	240	507	17,111
Equity-accounted entities
Reserves at December 31, 2018		360	14		310			1,716		2,400
of which: developed		276	14		57			1,716		2,063
undeveloped		84			253					337
Purchase of minerals in place		405								405
Revisions of previous estimates		76	1		13			1		91
Improved recovery
Extensions and discoveries		(2)								(2)
Production(c)		(67)	(1)		(36)			(69)		(173)
Sales of minerals in place
Reserves at December 31, 2019		772	14		287			1,648		2,721
Reserves at December 31, 2019	752	1,034	2,752	5,191	4,390	1,969	1,349	1,888	507	19,832
Developed	657	839	1,388	4,777	1,946	1,969	685	1,834	322	14,417
consolidated subsidiaries	657	242	1,374	4,777	1,858	1,969	685	186	322	12,070
equity-accounted entities		597	14		88			1,648		2,347
Undeveloped	95	195	1,364	414	2,444		664	54	185	5,415
consolidated subsidiaries	95	20	1,364	414	2,245		664	54	185	5,041
equity-accounted entities		175			199					374

(a) It includes production volumes consumed in operations equal to 231 bcf.

(b) Includes 17.6 bcf as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2018
Consolidated subsidiaries
Reserves at December 31, 2017	1,131	896	3,145	4,351	3,660	2,108	1,065	225	709	17,290
of which: developed	987	771	1,233	1,421	1,693	1,878	862	171	519	9,535
undeveloped	144	125	1,912	2,930	1,967	230	203	54	190	7,755
Purchase of minerals in place							69			69
Revisions of previous estimates	138	50	219	2,238	23	(22)	81	45	(16)	2,756
Improved recovery
Extensions and discoveries	86				7		205	76		374
Production(a)	(156)	(162)	(474)	(445)	(184)	(97)	(201)	(43)	(42)	(1,804)
Sales of minerals in place		(464)		(869)			(2)	(26)		(1,361)
Reserves at December 31, 2018	1,199	320	2,890	5,275	3,506	1,989	1,217	277	651	17,324
Equity-accounted entities
Reserves at December 31, 2017			14		349			1,819		2,182
of which: developed			14		83			1,819		1,916
undeveloped					266					266
Purchase of minerals in place		360								360
Revisions of previous estimates			2		(6)			(22)		(26)
Improved recovery
Extensions and discoveries
Production(b)			(2)		(33)			(81)		(116)
Sales of minerals in place
Reserves at December 31, 2018		360	14		310			1,716		2,400
Reserves at December 31, 2018	1,199	680	2,904	5,275	3,816	1,989	1,217	1,993	651	19,724
Developed	980	576	1,461	3,331	1,928	1,846	822	1,870	452	13,266
consolidated subsidiaries	980	300	1,447	3,331	1,871	1,846	822	154	452	11,203
equity-accounted entities		276	14		57			1,716		2,063
Undeveloped	219	104	1,443	1,944	1,888	143	395	123	199	6,458
consolidated subsidiaries	219	20	1,443	1,944	1,635	143	395	123	199	6,121

equity-accounted entities 84 253 337

(a) It includes production volumes consumed in operations equal to 222 bcf.

(b) It includes production volumes consumed in operations equal to 8 bcf.

Hydrocarbons production(a)(b)

(kboe/d)	2023	2022(c)	2021	2020(d)	2019(e)	2018
CONSOLIDATED SUBSIDIARIES
Italy	69	82	83	107	123	138
Rest of Europe	39	44	41	52	55	194
Croatia						2
Norway						134
United Kingdom	39	44	41	52	55	58
North Africa	299	264	259	255	379	392
Algeria	126	95	85	81	83	85
Libya	169	165	168	168	291	302
Tunisia	4	4	6	6	5	5
Egypt	318	346	360	291	354	300
Sub-Saharan Africa	168	230	291	345	363	337
Angola		57	101	100	113	127
Congo	68	78	70	73	87	92
Côte d'Ivoire	6
Ghana	31	32	36	41	42	18
Nigeria	63	63	84	131	121	100
Kazakhstan	163	126	146	163	150	143
Rest of Asia	183	174	177	176	179	177
China	1	1	1	1	1	1
Indonesia	79	62	61	48	59	71
Iraq	38	31	37	45	41	34
Pakistan		11	11	15	19	20
Timor Leste	2	4	9	10
Turkmenistan	7	5	7	9	8	11
United Arab Emirates	56	60	51	48	51	40
Americas	81	74	67	75	68	75
Ecuador					6	12
Mexico	26	17	14	14	4
Trinidad & Tobago						7
United States	55	57	53	61	58	56
Australia and Oceania	7	10	16	17	28	23
Australia	7	10	16	17	28	23
	1,327	1,350	1,440	1,481	1,699	1,779

Equity-accounted entities
Angola	108	53	19	23	23	19
Indonesia						1
Mozambique	22	6
Norway	138	145	172	185	108
Tunisia	2	3	3	2	3	4
Venezuela	58	53	48	42	38	48
	328	260	242	252	172	72

Total 1,655 1,610 1,682 1,733 1,871 1,851 (a) Includes volumes of hydrocarbons consumed in operations (127, 124, 116, 124, 124 and 119 kboe/d in 2023, 2022, 2021, 2020, 2019 and 2018, respectively). (b) Effective January 1, 2023, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,232 cubic feet of gas (it was 1 barrel of oil = 5,263 cubic feet of gas). The effect on production has been

5 kboe/d in the full year 2023. (c) Effective January 1, 2022, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,263 cubic feet of gas (it was 1 barrel of oil = 5,310 cubic feet of gas). The effect on production has been

8 kboe/d in the full year 2022.

(d) Effective January 1, 2020, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,310 cubic feet of gas (it was 1 barrel of oil = 5,408 cubic feet of gas). The effect on production has been 16 kboe/d in the full year 2020.

(e) Cumulative daily production for the full year 2019 includes approximately 10 kboe/d respectively of volumes (mainly gas) as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that the buyer will not redeem its contractual right to lift the pre-paid volumes within the contractual terms. The price collected on such volumes was recognized as revenue in the financial statements in accordance to IFRS 15 because the Company has satisfied its performance obligation under the contract. In the Oil & Gas disclosures prepared on the basis of SFAS 69, this volume is classified in the movements of the reserves as of December 31, 2019, as disposal and the related revenue is excluded from the results of exploration and production of hydrocarbons. The calculation of the price indicators per boe and operating cost per boe is unaffected by this transaction.

Liquids production

(kbbl/d)	2023	2022	2021	2020	2019	2018
CONSOLIDATED SUBSIDIARIES
Italy	29	36	36	47	53	60
Rest of Europe	18	20	19	23	23	113
Norway						89
United Kingdom	18	20	19	23	23	24
North Africa	123	122	124	112	166	154
Algeria	62	62	54	53	62	65
Libya	59	58	67	56	101	86
Tunisia	2	2	3	3	3	3
Egypt	67	77	82	64	75	77
Sub-Saharan Africa	84	139	198	218	249	244
Angola		52	91	89	102	111
Congo	36	40	44	49	59	65
Côte d'Ivoire	4
Ghana	14	16	20	24	24	15
Nigeria	30	31	43	56	64	53
Kazakhstan	115	88	102	110	100	94
Rest of Asia	85	78	80	88	86	77
China	1	1	1	1	1	1
Indonesia	1	1	1	1	2	3
Iraq	23	15	24	31	27	28
Timor Leste		1	1	2
Turkmenistan	6	4	6	7	7	6
United Arab Emirates	54	56	47	46	49	39
Americas	68	59	53	57	55	52
Ecuador					6	12
Mexico	22	14	11	12	4
United States	46	45	42	45	45	40
Australia and Oceania					2	2
Australia					2	2
	589	619	694	719	809	873

Equity-accounted entities
Angola	85	36	3	4	4	3
Mozambique	1
Norway	87	89	111	116	74
Tunisia	2	3	3	2	3	3
Venezuela	5	4	2	2	3	8
	180	132	119	124	84	14

Total	769	751	813	843	893	887

Natural gas production

(mmcf/d)	2023	2022	2021	2020	2019	2018
CONSOLIDATED SUBSIDIARIES
Italy	211.2	242.0	251.0	316.6	376.4	426.2
Rest of Europe	108.9	125.0	119.3	159.1	174.6	444.9
Croatia						11.4
Norway						241.8
United Kingdom	108.9	125.0	119.3	159.1	174.6	191.7
North Africa	917.7	748.6	720.1	758.4	1,149.2	1,299.1
Algeria	333.0	171.5	165.1	152.5	111.8	105.5
Libya	575.4	567.0	541.7	594.4	1,025.8	1,180.3
Tunisia	9.3	10.1	13.3	11.5	11.6	13.3
Egypt	1,310.0	1,413.2	1,474.8	1,203.0	1,509.0	1,218.5
Sub-Saharan Africa	439.7	481.0	489.5	679.0	621.2	505.4
Angola		27.4	53.9	58.2	67.3	84.2
Congo	172.9	197.8	135.5	131.1	147.7	150.3
Côte d'Ivoire	6.5
Ghana	88.4	85.6	83.8	87.6	97.9	19.3
Nigeria	171.9	170.2	216.3	402.1	308.3	251.6
Kazakhstan	254.7	198.6	233.0	282.2	272.4	265.2
Rest of Asia	511.8	507.2	516.5	465.0	502.7	550.7
Indonesia	407.9	323.5	321.2	248.5	308.1	376.5
Iraq	77.5	82.1	70.7	76.3	78.7	36.7
Pakistan		56.2	59.8	76.8	101.2	106.1
Timor Leste	8.5	19.0	42.5	46.8
Turkmenistan	6.6	6.4	6.3	6.2	6.0	27.2
United Arab Emirates	11.3	20.0	16.0	10.4	8.7	4.2
Americas	69.1	80.7	73.0	97.1	66.8	118.9
Mexico	23.1	18.1	14.8	10.9	2.8
Trinidad & Tobago				-	-	35.7
United States	46.0	62.6	58.2	86.2	64.0	83.2
Australia and Oceania	37.7	52.3	85.0	91.0	139.6	114.3
Australia	37.7	52.3	85.0	91.0	139.6 4,811.9 97.3	114.3
	3,860.8	3,848.6	3,962.2	4,051.4		4,943.2
Equity-accounted entities
Angola	117.4	84.6	85.8	98.8		89.2
Mozambique	109.5	32.4
Indonesia						2.2
Norway	265.2	295.3	322.7	365.0	182.4
Tunisia	2.8	2.9	3.2	2.9	3.4	4.4
Venezuela	279.8	259.2	239.2	211.0	192.0	221.7
	774.7	674.4	650.9	677.7	475.1	317.5
Total	4,635.5	4,523.0	4,613.1	4,729.1	5,287.0	5,260.7

Oil and natural gas production sold

		2023	2022	2021	2020	2019	2018
Oil and natural gas production	(mmboe)	604.1	587.8	613.7	634.3	683.0	675.6
Change in inventories other		(12.0)	(10.7)	(4.6)	(13.7)	(7.0)	(7.1)
Own consumption of hydrocarbons		(46.2)	(45.1)	(42.4)	(45.4)	(45.4)	(43.5)
Oil and natural gas production sold(a)		545.9	532.0	566.7	575.2	630.6	625.0
Liquids	(mmbbl)	279.6	269.6	294.9	300.1	325.4	320.0
- of which to downstream		186.3	171.0	183.6	201.6	216.2	221.3
Natural gas	(bcf)	1,394	1,381	1,444	1,461	1,650	1,665
- of which to GGP segment		197	220	237	272	302	349

(a) Includes 113.1 mmboe of equity-accounted entities production sold in 2023 (84.5, 83.3, 86.3 , 60.8 and 25.1 mmboe in 2022, 2021, 2020 , 2019 and 2018, respectively).

Main oil and natural gas interests at December 31, 2023

	Commencement of operations	Number of interests	Gross developed acreage(a)(b)	Net developed acreage(a)(b)	Gross undeveloped acreage(a)	Net undeveloped acreage(a)	Types of fields/acreage	Number of producing fields	Number of other fields
EUROPE		296	13,340	7,774	57,973	27,472		109	41
Italy	1926	111	7,556	6,378	4,809		4,052 Onshore/Offshore	53	34
Rest of Europe		185	5,784	1,396	53,164	23,420		56	7
Albania	2020	1			587	587	Onshore
Cyprus	2013	7			25,474	13,988	Offshore		2
Norway	1965	142	4,838	763	25,339	7,398	Offshore	47
United Kingdom	1964	35	946	633	1,764	1,447	Offshore	9	5
AFRICA		297	51,139	14,098	226,691	99,144		286	132
North Africa		92	15,269	6,360	105,698	35,872		90	50
Algeria	1981	65	10,010	3,919	8,067	3,953	Onshore	59	25
Libya	1959	14	1,963	958	78,085	23,686	Onshore/Offshore	11	15
Morocco	2016	1			16,730	7,529	Offshore
Tunisia	1961	12	3,296	1,483	2,816	704	Onshore/Offshore	20	10
Egypt	1954	53	4,851	1,706	29,187		10,721 Onshore/Offshore	32	22
Sub-Saharan Africa		152	31,019	6,032	91,806	52,551		164	60
Angola	1980	83	10,927	912	34,958	6,721	Onshore/Offshore	88	6
Congo	1968	19	971	586	1,320	713	Onshore/Offshore	16	3
Côte d'Ivoire	2015	7	1,658	1,382	2,865	2,578	Offshore	2
Ghana	2009	3	226	100	930	395	Offshore	1	1
Kenya	2012	3			35,724	35,724	Offshore
Mozambique	2007	7	719	180	7,803	3,080	Offshore	1	5
Nigeria	1962	30	16,518	2,872	8,206	3,340	Onshore/Offshore	56	45
ASIA		52	10,389	3,540	253,595	137,031		14	27
Kazakhstan	1992	7	2,391	442	3,853		1,505 Onshore/Offshore	2	3
Rest of Asia		45	7,998	3,098	249,742	135,526		12	24
China	1984	2	43	7			Offshore	1
Indonesia	2001	12	3,252	2,092	16,505	10,036	Onshore/Offshore	3	10
Iraq	2009	1	1,074	446			Onshore	1
Lebanon	2018	1			1,742	610	Offshore
Oman	2017	3			102,016	58,955	Onshore/Offshore
Qatar	2022	1			1,206	38	Offshore		1
Timor Leste	2006	5	412	122	6,232	5,838	Offshore	1	3
Turkmenistan	2008	1	200	180			Onshore	2
United Arab Emirates	2018	12	3,017	251	29,603	17,579	Onshore/Offshore	4	10
Vietnam	2013	4			23,908	21,251	Offshore
Other countries		3			68,530	21,219	Offshore
AMERICAS		95	2,152	1,023	14,332	8,475		30	8
Mexico	2015	10	34	34	5,198	3,408	Offshore	2	5
United States	1968	73	857	492	280	139	Offshore	25	1
Venezuela	1998	6	1,261	497	1,543	569	Onshore/Offshore	3	1
Other Countries		6			7,311	4,359	Offshore		1
AUSTRALIA AND OCEANIA		4	728	634	2,608	2,117		1	1
Australia	2001	4	728	634	2,608	2,117	Offshore	1	1
Total		744	77,748	27,069	555,199	274,239		440	209

(a) Square kilometers.

(b) Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves.

(square kilometers)	2023	2022	2021	2020	2019	2018
Europe	35,246	33,632	39,858	39,841	38,028	46,332
Italy	10,430	10,884	12,118	13,632	13,732	14,987
Rest of Europe	24,816	22,748	27,740	26,209	24,296	31,345
Africa	113,242	117,396	128,186	129,167	163,625	165,699
North Africa	42,232	43,080	27,775	31,033	31,873	33,932
Egypt	12,427	7,103	6,776	7,384	7,613	5,248
Sub-Saharan Africa	58,583	67,213	93,635	90,750	124,139	126,519
Asia	140,571	145,585	155,482	154,845	142,696	181,414
Kazakhstan	1,947	1,947	1,947	1,947	2,160	1,543
Rest of Asia	138,624	143,638	153,535	152,898	140,536	179,871
Americas	9,498	9,186	9,270	9,719	10,703	9,303
Australia and Oceania	2,751	2,751	2,705	2,877	2,802	3,757
Total	301,308	308,550	335,501	336,449	357,854	406,505

Average realizations

		2023		2022		2021		2020		2019		2018
Liquids (\$/bbl)	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities
Italy	67.76		67.07		61.26		34.58		55.55		61.58
Rest of Europe	72.77	79.33	93.94	97.51	70.60	66.72	32.82	35.23	58.92	58.88	64.51
North Africa	72.62	18.00	92.11	17.82	68.03	17.89	38.33	18.16	57.91	18.06	65.95	17.92
Egypt	71.09		87.64		63.53		36.66		54.78		62.97
Sub-Saharan Africa	81.79	75.26	103.96	85.71	69.12	44.41	39.99	17.13	63.45	23.72	68.76	39.48
Kazakhstan	72.71		86.94		66.92		37.37		59.06		66.78
Rest of Asia	80.19		94.13		68.39		37.69		62.81		68.35	49.86
Americas	75.30	67.62	92.03	88.39	61.93	57.75	33.03	27.20	54.00	59.94	57.22	54.86
Australia and Oceania	54.02		60.89		58.76		17.45		52.93		68.72
	74.87	76.60	92.41	92.97	66.91	65.10	37.56	34.21	59.62	55.93	65.79	45.19
Natural gas (\$/kcf)
Italy	13.67		20.32		15.47		3.16		5.03		8.37
Rest of Europe	14.44	20.53	30.22	31.02	15.75	15.11	3.12	3.25	4.95	5.07	7.99
North Africa	9.44	9.69	10.52	9.67	6.42	5.83	4.33	6.29	6.21	7.23	4.97	3.58
Egypt	5.47		5.50		4.74		4.78		5.11		4.85
Sub-Saharan Africa	5.36	11.94	4.99	33.79	4.32	14.68	2.76	3.94	2.94	6.16	2.38	9.50
Kazakhstan	0.74		0.69		0.54		0.69		0.81		0.77
Rest of Asia	10.38		10.57		6.21		4.09		5.94		6.11	9.32

2023		2022		2021		2020		2019		2018

56.23	71.32	69.07	98.29	49.82	61.11	29.20	27.33	43.73	41.71	48.04	33.63
22.11		22.25		23.03		20.35		26.32		28.99
68.89	30.76	83.45	29.27	55.66	24.99	29.57	23.39	48.37	25.67	46.63	28.59
69.03		76.85		51.48		31.31		50.31		50.98	50.64
54.01		64.59		49.37		27.22		42.21		46.98
60.51	72.12	83.12	108.43	58.24	70.02	32.06	19.97	53.08	30.84	58.59	48.79
37.98		42.64		34.18		28.03		33.67		36.22
60.64	19.31	73.29	19.31	51.51	18.69	30.28	19.36	44.86	19.39	43.34	18.14
74.31	88.95	128.03	121.12	78.48	71.19	23.94	29.17	39.84	49.76	56.07
69.80		87.98		72.42		25.28		40.24		53.01

Natural gas (\$/kcf) 8.14 10.37 6.64 3.76 4.94 5.20 Hydrocarbons (\$/boe) 59.35 73.98 51.49 28.92 43.54 47.48

Americas 3.22 5.22 6.48 4.76 4.06 4.32 2.10 4.37 2.46 4.32 2.38 4.28 Australia and Oceania 4.16 4.10 4.25 3.84 4.41 4.80

7.28 12.18 8.61 19.87 5.93 10.71 3.77 3.73 4.94 4.94 5.17 5.59

Exploratory wells activity

		Wells completed(a)												Wells in progress at of Dec. 31(b)
		2023													2022	2021	2020	2019	2018	2023
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Total	Net
Italy										0.5	1.8
Rest of Europe	0.1	0.4	0.4	1.2	0.1	0.3	0.8	0.4	0.3	1.4		0.5	31.0	7.8
North Africa		1.6	1.0	4.0			0.5	1.5	0.5			0.5	9.0	6.0
Egypt	5.0	4.6	4.4	4.3	5.0	5.0	0.7	1.5	4.5	1.5	1.7	1.5	10.0	7.4
Sub-Saharan Africa	0.3	0.9	3.7	2.4	1.1	0.4	0.1	0.9	0.5	0.9	0.4		35.0	17.5
Kazakhstan								1.1
Rest of Asia	0.9	1.3	0.7	1.0	0.7	1.0	0.8	0.9		1.7	2.2	2.6	15.0	6.8
Americas		1.4				0.7		0.6			4.0		4.0	2.3
Australia and Oceania										0.5			1.0	0.3
	6.3	10.2	10.2	12.9	2.9	6.9	2.9	6.9	5.8	6.5	10.1	5.1	105.0	48.1

Development wells activity

2023 2022 2021 2020 2019 2018

Consolidated subsidiaries

74.87 76.60 92.41 92.97 66.91 65.10 37.56 34.21 59.62 55.93 65.79 45.19

7.28 12.18 8.61 19.87 5.93 10.71 3.77 3.73 4.94 4.94 5.17 5.59

56.23 71.32 69.07 98.29 49.82 61.11 29.20 27.33 43.73 41.71 48.04 33.63

Equityaccounted entities

Consolidated subsidiaries

Equityaccounted entities

Consolidated subsidiaries

Equityaccounted entities

Liquids (\$/bbl)

Natural gas (\$/kcf)

Hydrocarbons (\$/boe)

Consolidated subsidiaries

Equityaccounted entities

Consolidated subsidiaries

Equityaccounted entities

Consolidated subsidiaries

Italy 67.76 67.07 61.26 34.58 55.55 61.58 Rest of Europe 72.77 79.33 93.94 97.51 70.60 66.72 32.82 35.23 58.92 58.88 64.51 North Africa 72.62 18.00 92.11 17.82 68.03 17.89 38.33 18.16 57.91 18.06 65.95 17.92 Egypt 71.09 87.64 63.53 36.66 54.78 62.97 Sub-Saharan Africa 81.79 75.26 103.96 85.71 69.12 44.41 39.99 17.13 63.45 23.72 68.76 39.48 Kazakhstan 72.71 86.94 66.92 37.37 59.06 66.78 Rest of Asia 80.19 94.13 68.39 37.69 62.81 68.35 49.86 Americas 75.30 67.62 92.03 88.39 61.93 57.75 33.03 27.20 54.00 59.94 57.22 54.86 Australia and Oceania 54.02 60.89 58.76 17.45 52.93 68.72

Italy 13.67 20.32 15.47 3.16 5.03 8.37 Rest of Europe 14.44 20.53 30.22 31.02 15.75 15.11 3.12 3.25 4.95 5.07 7.99 North Africa 9.44 9.69 10.52 9.67 6.42 5.83 4.33 6.29 6.21 7.23 4.97 3.58 Egypt 5.47 5.50 4.74 4.78 5.11 4.85 Sub-Saharan Africa 5.36 11.94 4.99 33.79 4.32 14.68 2.76 3.94 2.94 6.16 2.38 9.50 Kazakhstan 0.74 0.69 0.54 0.69 0.81 0.77 Rest of Asia 10.38 10.57 6.21 4.09 5.94 6.11 9.32 Americas 3.22 5.22 6.48 4.76 4.06 4.32 2.10 4.37 2.46 4.32 2.38 4.28 Australia and Oceania 4.16 4.10 4.25 3.84 4.41 4.80

Italy 69.80 87.98 72.42 25.28 40.24 53.01 Rest of Europe 74.31 88.95 128.03 121.12 78.48 71.19 23.94 29.17 39.84 49.76 56.07 North Africa 60.64 19.31 73.29 19.31 51.51 18.69 30.28 19.36 44.86 19.39 43.34 18.14 Egypt 37.98 42.64 34.18 28.03 33.67 36.22 Sub-Saharan Africa 60.51 72.12 83.12 108.43 58.24 70.02 32.06 19.97 53.08 30.84 58.59 48.79 Kazakhstan 54.01 64.59 49.37 27.22 42.21 46.98 Rest of Asia 69.03 76.85 51.48 31.31 50.31 50.98 50.64 Americas 68.89 30.76 83.45 29.27 55.66 24.99 29.57 23.39 48.37 25.67 46.63 28.59 Australia and Oceania 22.11 22.25 23.03 20.35 26.32 28.99

ENI's GROUP 2023 2022 2021 2020 2019 2018 Liquids (\$/bbl) 78.25 92.49 66.62 37.06 59.26 65.47 Natural gas (\$/kcf) 8.14 10.37 6.64 3.76 4.94 5.20 Hydrocarbons (\$/boe) 59.35 73.98 51.49 28.92 43.54 47.48

	Wells completed(a)											at of Dec. 31	Wells in progress
	2023							2022	2021		2020		2019		2018	2023
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Total	Net
Italy	1.0		1.0						3.0		3.0		2.0	1.2
Rest of Europe	4.8		4.6		4.8		2.8		3.3		2.8	0.3	16.0	2.2
North Africa	9.3		5.7	0.5	2.5		4.3		5.0	1.1	9.6	0.5	6.0	3.9
Egypt	30.1		19.9		17.0	0.8	23.2		33.5		30.7		9.0	6.8
Sub-Saharan Africa	5.6		8.5		3.8		1.2		7.0		7.3	0.1	13.0	4.5
Kazakhstan	2.0		0.6				0.3		0.9		0.9		1.0	0.3
Rest of Asia	22.9		22.1		14.9		23.2	0.4	27.3	2.2	21.9		27.0	7.7
Americas	6.9		8.2		3.9		2.0		2.1		2.3		2.0	1.0
Australia and Oceania	1.0										0.8
	83.6		70.6	0.5	46.9	0.8	57.0	0.4	82.1	3.3	79.3	0.9	76.0	27.6

Productive oil and gas wells(d)

		2023
	Oil wells		Natural gas wells
(units)	Gross	Net	Gross	Net
Italy	130.0	117.2	327.0	289.4
Rest of Europe	456.0	78.7	226.0	47.9
North Africa	644.0	292.1	260.0	123.5
Egypt	1093.0	499.1	150.0	51.3
Sub-Saharan Africa	2297.0	387.5	174.0	24.5
Kazakhstan	211.0	57.7	1.0	0.3
Rest of Asia	1030.0	370.9	100.0	41.4
Americas	257.0	143.1	14.0	6.9
Australia and Oceania			3.0	3.0
	6,118.0	1,946.3	1,255.0	588.2

(a) Number of wells net to Eni.

⁽b) Includes temporary suspended wells pending further evaluation.

⁽c) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well.

⁽d) Includes 997 gross (303.2 net) multiple completion wells (more than one producing into the same well bore). Productive wells are producing wells and wells capable of production. One or more completions in the same bore hole are counted as one well.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2023
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	1,475	862	1,477		1,745	1,845	2,970	1,661	1	12,036
- sales to third parties		18	4,032	3,904	903	897	532	135	51	10,472
Total revenues	1,475	880	5,509	3,904	2,648	2,742	3,502	1,796	52	22,508
Production costs	(348)	(202)	(518)	(434)	(656)	(267)	(304)	(469)	(25)	(3,223)
Transportation costs	(3)	(43)	(59)	(9)	(10)	(178)	(6)	(19)		(327)
Production taxes	(152)		(300)		(294)		(326)	(73)		(1,145)
Exploration expenses	(12)	(14)	(82)	(163)	(121)	(2)	(140)	(152)	(1)	(687)
D.D. & A. and Provision for abandonment(b)	(886)	(166)	(923)	(1,056)	(716)	(601)	(1,093)	(1,531)	(95)	(7,067)
Other income (expenses)	(347)	(117)	58	(418)	(128)	(148)	(263)	(108)	(7)	(1,478)
Pretax income from producing activities	(273)	338	3,685	1,824	723	1,546	1,370	(556)	(76)	8,581
Income taxes	169	(292)	(2,498)	(870)	(391)	(503)	(1,150)	369	19	(5,147)
Results of operations from E&P activities of consolidated subsidiaries	(104)	46	1,187	954	332	1,043	220	(187)	(57)	3,434
Equity-accounted entities
Revenues:
- sales to consolidated entities		2,911			958					3,869
- sales to third parties		1,063	10		1,905			604		3,582
Total revenues		3,974	10		2,863			604		7,451
Production costs		(562)	(6)		(535)			(20)		(1,123)
Transportation costs		(102)	(1)		(26)			(3)		(132)
Production taxes			(2)		(54)			(126)		(182)
Exploration expenses		(50)			(37)					(87)
D.D. & A. and Provision for abandonment		(1,116)	(5)		(1,314)		(1)	(68)		(2,504)
Other income (expenses)		(78)	(1)		24		(4)	(372)		(431)
Pretax income from producing activities		2,066	(5)		921		(5)	15		2,992
Income taxes		(1,614)	6		(273)		1	(56)		(1,936)
Results of operations from E&P activities of equity-accounted entities		452	1		648		(4)	(41)		1,056

Results of operations from oil and gas producing activities(a)

(a) Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni's share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to fulfil Eni's PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni's share of oil and gas production. (b) Includes asset net impairment amounting to €1,036 million.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2022
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	1,952	1,854	2,095		4,434	1,602	2,982	1,683	3	16,605
- sales to third parties	329	23	3,946	4,897	1,216	1,001	837	307	72	12,628
Total revenues	2,281	1,877	6,041	4,897	5,650	2,603	3,819	1,990	75	29,233
Production costs	(387)	(189)	(486)	(484)	(871)	(241)	(326)	(410)	(21)	(3,415)
Transportation costs	(3)	(42)	(50)	(5)	(29)	(147)	(3)	(16)		(295)
Production taxes	(286)		(330)		(478)		(421)	(63)		(1,578)
Exploration expenses	(11)	(25)	(162)	(106)	(150)	(6)	(123)	(21)	(1)	(605)
D.D. & A. and Provision for abandonment(a)	(449)	(158)	(839)	(1,156)	(1,488)	(434)	(727)	(707)	(90)	(6,048)
Other income (expenses)	(1,987)	(98)	1,955	(378)	(196)	(127)	(292)	2	(4)	(1,125)
Pretax income from producing activities	(842)	1,365	6,129	2,768	2,438	1,648	1,927	775	(41)	16,167
Income taxes	337	(665)	(2,740)	(1,192)	(979)	(524)	(1,457)	(41)	47	(7,214)
Results of operations from E&P activities of consolidated subsidiaries	(505)	700	3,389	1,576	1,459	1,124	470	734	6	8,953
Equity-accounted entities
Revenues:
- sales to consolidated entities		2,937			572					3,509
- sales to third parties		3,039	14		1,327			533		4,913
Total revenues		5,976	14		1,899			533		8,422
Production costs		(567)	(6)		(244)			(24)		(841)
Transportation costs		(131)	(1)		(9)					(141)
Production taxes			(2)		(15)			(123)		(140)
Exploration expenses		(44)			(7)		(13)			(64)
D.D. & A. and Provision for abandonment		(1,121)	(6)		(628)		(1)	(63)		(1,819)
Other income (expenses)		(64)			(271)		1	(234)		(568)
Pretax income from producing activities		4,049	(1)		725		(13)	89		4,849
Income taxes		(3,076)	3		(21)			(105)		(3,199)
Results of operations from E&P activities of equity-accounted entities		973	2		704		(13)	(16)		1,650

(a) Includes asset net impairment amounting to €279 million.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2021
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	1,680	790	1,133		3,782	1,391	2,020	734	4	11,534
- sales to third parties		36	2,602	3,637	930	704	380	351	108	8,748
Total revenues	1,680	826	3,735	3,637	4,712	2,095	2,400	1,085	112	20,282
Production costs	(326)	(147)	(581)	(399)	(816)	(211)	(251)	(288)	(17)	(3,036)
Transportation costs	(4)	(35)	(45)	(10)	(20)	(150)	(5)	(11)		(280)
Production taxes	(128)		(192)		(379)		(230)	(28)		(957)
Exploration expenses	(16)	(72)	(27)	(47)	(238)	(1)	(135)	(21)	(1)	(558)
D.D. & A. and Provision for abandonment(a)	(31)	(196)	(357)	(990)	(1,468)	(431)	(665)	(243)	(69)	(4,450)
Other income (expenses)	(395)	11	557	(310)	(330)	(120)	(173)	(132)	(2)	(894)
Pretax income from producing activities	780	387	3,090	1,881	1,461	1,182	941	362	23	10,107
Income taxes	(198)	(156)	(1,450)	(848)	(708)	(394)	(739)	(17)	(15)	(4,525)
Results of operations from E&P activities of consolidated subsidiaries	582	231	1,640	1,033	753	788	202	345	8	5,582
Equity-accounted entities
Revenues:
- sales to consolidated entities		1,831								1,831
- sales to third parties		1,756	12		365			367		2,500
Total revenues		3,587	12		365			367		4,331
Production costs		(388)	(6)		(25)			(15)		(434)
Transportation costs		(140)	(1)		(12)					(153)
Production taxes			(2)		(112)			(88)		(202)
Exploration expenses		(35)								(35)
D.D. & A. and Provision for abandonment		(879)	(3)		42			(154)		(994)
Other income (expenses)		(287)			(158)		(1)	(197)		(643)
Pretax income from producing activities		1,858			100		(1)	(87)		1,870
Income taxes		(1,237)						(66)		(1,303)
Results of operations from E&P activities of equity-accounted entities		621			100		(1)	(153)		567

(a) Includes asset net reversal amounting to €1,263 million.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2020
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	799	334	616		2,315	788	1,333	434	1	6,620
- sales to third parties		53	1,610	2,478	784	547	179	204	109	5,964
Total revenues	799	387	2,226	2,478	3,099	1,335	1,512	638	110	12,584
Production costs	(332)	(139)	(371)	(367)	(782)	(246)	(236)	(272)	(17)	(2,762)
Transportation costs	(4)	(30)	(39)	(11)	(21)	(164)	(4)	(12)		(285)
Production taxes	(111)		(135)		(295)		(133)	(13)		(687)
Exploration expenses	(19)	(14)	(124)	(56)	(77)	(3)	(104)	(112)	(1)	(510)
D.D. & A. and Provision for abandonment(a)	(1,149)	(252)	(1,158)	(848)	(2,187)	(454)	(1,070)	(678)	(65)	(7,861)
Other income (expenses)	(255)	(45)	(360)	(204)	25	(153)	(90)	(71)	6	(1,147)
Pretax income from producing activities	(1,071)	(93)	39	992	(238)	315	(125)	(520)	33	(668)
Income taxes	219	69	(671)	(519)	(33)	(134)	(193)	86	(11)	(1,187)
Results of operations from E&P activities of consolidated subsidiaries	(852)	(24)	(632)	473	(271)	181	(318)	(434)	22	(1,855)
Equity-accounted entities
Revenues:
- sales to consolidated entities		862								862
- sales to third parties		782	10		131			307		1,230
Total revenues		1,644	10		131			307		2,092
Production costs		(350)	(7)		(23)			(18)		(398)
Transportation costs		(161)	(1)		(11)					(173)
Production taxes			(2)		(3)			(76)		(81)
Exploration expenses		(35)								(35)
D.D. & A. and Provision for abandonment		(1,163)	(1)		(69)			(50)		(1,283)
Other income (expenses)		(90)	(1)		(35)		(2)	(146)		(274)
Pretax income from producing activities		(155)	(2)		(10)		(2)	17		(152)
Income taxes		469	1					(29)		441
Results of operations from E&P activities of equity-accounted entities		314	(1)		(10)		(2)	(12)		289

(a) Includes asset net impairment amounting to €1,865 million.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2019
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	1,493	618	1,081		4,576	1,195	2,367	825	5	12,160
- sales to third parties		30	4,084	3,715	944	766	149	180	227	10,095
Total revenues	1,493	648	5,165	3,715	5,520	1,961	2,516	1,005	232	22,255
Production costs	(391)	(181)	(520)	(330)	(847)	(255)	(256)	(273)	(43)	(3,096)
Transportation costs	(5)	(31)	(60)	(10)	(39)	(158)	(4)	(15)		(322)
Production taxes	(183)		(263)		(483)		(252)	(7)	(6)	(1,194)
Exploration expenses	(25)	(51)	(30)	(10)	(90)	(39)	(170)	(31)	(43)	(489)
DD&A and provision for abandonment(a)	(944)	(201)	(839)	(978)	(3,060)	(444)	(820)	(607)	(97)	(7,990)
Other income (expenses)	(337)	(16)	(452)	(433)	(502)	(71)	(76)	(86)	(1)	(1,974)
Pretax income from producing activities	(392)	168	3,001	1,954	499	994	938	(14)	42	7,190
Income taxes	148	(11)	(2,561)	(839)	(268)	(326)	(719)	(5)	(31)	(4,612)
Results of operations from E&P activities of consolidated subsidiaries(b)	(244)	157	440	1,115	231	668	219	(19)	11	2,578
Equity-accounted entities
Revenues:
- sales to consolidated entities		1,080								1,080
- sales to third parties		677	15		207			315		1,214
Total revenues		1,757	15		207			315		2,294
Production costs		(336)	(8)		(24)			(25)		(393)
Transportation costs		(84)	(1)		(11)					(96)
Production taxes			(2)		(7)			(81)		(90)
Exploration expenses		(47)								(47)
DD&A and provision for abandonment		(722)	(1)		(70)			(51)		(844)
Other income (expenses)		(237)	(1)		(28)		(3)	(133)		(402)
Pretax income from producing activities		331	2		67		(3)	25		422
Income taxes		(179)	(2)					(54)		(235)
Results of operations from E&P activities of equity-accounted entities		152			67		(3)	(29)		187

(a) Includes asset net impairment amounting to €1,217 million.

(b) Results of operations exclude revenues, DD&A and income taxes associated with 3.8 million boe as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause. The price collected by the buyer has been recognized as revenues in the segment information of the E&P sector prepared in accord-ance with IFRS and DD&A and income taxes have been accrued accordingly, because the Group performance obligation under the contract has been fulfilled and it is very likely that the buyer will not redeem its contractual right to lift within the contractual terms.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2018
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	2,120	2,740	1,277		4,701	1,140	1,902	934	4	14,818
- sales to third parties		494	3,741	3,207	830	769	493	50	190	9,774
Total revenues	2,120	3,234	5,018	3,207	5,531	1,909	2,395	984	194	24,592
Production costs	(402)	(488)	(363)	(343)	(974)	(269)	(220)	(234)	(48)	(3,341)
Transportation costs	(8)	(142)	(50)	(11)	(42)	(136)	(7)	(16)		(412)
Production taxes	(171)		(243)		(435)		(191)		(6)	(1,046)
Exploration expenses	(25)	(85)	(48)	(22)	(44)	(3)	(79)	(69)	(5)	(380)
DD&A and provision for abandonment(a)	(281)	(664)	(582)	(795)	(2,490)	(387)	(941)	(594)	(67)	(6,801)
Other income (expenses)	(442)	(193)	(101)	(239)	(1,126)	(67)	(135)	(54)		(2,357)
Pretax income from producing activities	791	1,662	3,631	1,797	420	1,047	822	17	68	10,255
Income taxes	(170)	(1,070)	(2,494)	(542)	(264)	(308)	(678)	7	(26)	(5,545)
Results of operations from E&P activities of consolidated subsidiaries	621	592	1,137	1,255	156	739	144	24	42	4,710
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties			15		257		6	420		698
Total revenues			15		257		6	420		698
Production costs			(7)		(34)		(2)	(36)		(79)
Transportation costs			(1)		(28)			(2)		(31)
Production taxes			(3)		(26)			(114)		(143)
Exploration expenses		(6)					(235)			(241)
DD&A and provision for abandonment			(1)		224		(3)	(222)		(2)
Other income (expenses)		(1)	2		(27)		(25)	(122)		(173)
Pretax income from producing activities		(7)	5		366		(259)	(76)		29
Income taxes			(3)				(2)	(35)		(40)
Results of operations from E&P activities of equity-accounted entities		(7)	2		366		(261)	(111)		(11)

(a) Includes asset net impairment amounting to €726 million.

Capitalized cost(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2023
Consolidated subsidiaries
Proved property	19,073	6,802	17,812	22,617	30,058	13,360	13,048	19,106	1,608	143,484
Unproved property	22	325	603	48	2,280	7	1,480	859	197	5,821
Support equipment and facilities	310	27	1,596	272	1,102	128	12	24	12	3,483
Incomplete wells and other	1,006	354	1,319	827	2,510	1,062	1,834	511	83	9,506
Gross Capitalized Costs	20,411	7,508	21,330	23,764	35,950	14,557	16,374	20,500	1,900	162,294
Accumulated depreciation, depletion and amortization	(16,515)	(6,390)	(15,880)	(16,679)	(24,796)	(4,578)	(10,853)	(16,042)		(1,060) (112,793)
Net Capitalized Costs consolidated subsidiaries(b)(c)	3,896	1,118	5,450	7,085	11,154	9,979	5,521	4,458	840	49,501
Equity-accounted entities
Proved property		8,585	119		27,267		278	2,030		38,279
Unproved property		835			69					904
Support equipment and facilities		50	8		257			7		322
Incomplete wells and other		3,790	9		1,823		193	233		6,048
Gross Capitalized Costs		13,260	136		29,416		471	2,270		45,553
Accumulated depreciation, depletion and amortization		(4,364)	(73)		(20,707)			(1,480)		(26,624)
Net Capitalized Costs equity-accounted entities(b)		8,896	63		8,709		471	790		18,929

2022
Consolidated subsidiaries
Proved property	18,687	6,629	17,490	22,969	29,784	13,705	12,846	19,192	1,480	142,782
Unproved property	22	330	613	44	2,411	7	1,462	931	204	6,024
Support equipment and facilities	309	24	1,645	270	1,128	132	13	24	12	3,557
Incomplete wells and other	767	237	1,282	543	1,970	936	1,457	379	115	7,686
Gross Capitalized Costs	19,785	7,220	21,030	23,826	35,293	14,780	15,778	20,526	1,811	160,049
Accumulated depreciation, depletion and amortization	(15,677)	(6,214)	(15,949)	(16,212)	(25,024)	(4,147)	(10,133)	(15,341)		(1,001) (109,698)
Net Capitalized Costs consolidated subsidiaries(b)	4,108	1,006	5,081	7,614	10,269	10,633	5,645	5,185	810	50,351
Equity-accounted entities
Proved property		7,387	118		27,959		287	2,100		37,851
Unproved property		996			91					1,087
Support equipment and facilities		31	8		262			8		309
Incomplete wells and other		3,872	9		1,530		48	241		5,700
Gross Capitalized Costs		12,286	135		29,842		335	2,349		44,947
Accumulated depreciation, depletion and amortization		(3,492)	(68)		(20,280)			(1,466)		(25,306)
Net Capitalized Costs equity-accounted entities(b)(d)		8,794	67		9,562		335	883		19,641

(a) Capitalized costs represent the total expenditures for proved and unproved mineral properties and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization.

(b) The amounts include net capitalized financial charges totalling €709 million in 2023 and €725 million in 2022 for the consolidates subsidiaries and €658 million in 2023 and €565 million in 2022 for equity-accounted entities. (c) Includes allocation at fair value of the assets of the companies acquired by Chevron in Indonesia and by bp in Algeria.

(d) Includes allocation at fair value of the assets of Azule Energy Holdings Ltd.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2021
Consolidated subsidiaries
Proved property	18,644	6,953	16,218	21,125	43,947	12,606	12,947	16,407	1,413	150,260
Unproved property	20	322	492	34	2,306	11	1,518	878	193	5,774
Support equipment and facilities	308	22	1,552	248	1,342	121	38	21	12	3,664
Incomplete wells and other	735	133	1,293	237	1,562	958	1,073	719	53	6,763
Gross Capitalized Costs	19,707	7,430	19,555	21,644	49,157	13,696	15,576	18,025	1,671	166,461
Accumulated depreciation, depletion and amortization	(15,506)	(6,194)	(14,244)	(14,209)	(36,317)	(3,514)	(10,443)	(13,874)		(902) (115,203)
Net Capitalized Costs consolidated subsidiaries(a)	4,201	1,236	5,311	7,435	12,840	10,182	5,133	4,151	769	51,258
Equity-accounted entities
Proved property		11,483	128		1,517			1,987		15,115
Unproved property		2,235					12			2,247
Support equipment and facilities		36	8		3			7		54
Incomplete wells and other		3,179	9		1,323			227		4,738
Gross Capitalized Costs		16,933	145		2,843		12	2,221		22,154
Accumulated depreciation, depletion and amortization		(7,387)	(63)		(313)			(1,324)		(9,087)
Net Capitalized Costs equity-accounted entities(a)		9,546	82		2,530		12	897		13,067
2020
Consolidated subsidiaries
Proved property	18,456	6,465	14,596	19,081	39,848	11,278	10,662	14,567	1,359	136,312
Unproved property	20	311	454	33	2,163	10	1,411	896	179	5,477
Support equipment and facilities	300	20	1,424	216	1,226	109	34	20	11	3,360
Incomplete wells and other	671	147	1,094	193	2,551	1,064	1,469	458	39	7,686
Gross Capitalized Costs	19,447	6,943	17,568	19,523	45,788	12,461	13,576	15,941	1,588	152,835
Accumulated depreciation, depletion and amortization	(15,565)	(5,597)	(12,793)	(12,161)	(32,248)	(2,839)	(9,003)	(12,612)		(805) (103,623)
Net Capitalized Costs consolidated subsidiaries(a)	3,882	1,346	4,775	7,362	13,548	9,622	4,573	3,329	783	49,212
Società in joint venture e collegate
Proved property		11,466	68		1,384			1,833		14,751
Unproved property		2,131					11			2,142
Support equipment and facilities		23	8					6		37
Incomplete wells and other		1,566	9		17			209		1,801
Gross Capitalized Costs		15,186	85		1,401		11	2,048		18,731
Accumulated depreciation, depletion and amortization		(6,196)	(59)		(343)			(1,076)		(7,674)
Net Capitalized Costs equity-accounted entities(a)		8,990	26		1,058		11	972		11,057

(a) The amounts include net capitalized financial charges totalling €767 million in 2021 and €843 million in 2020 for the consolidates subsidiaries and €360 million in 2021 and €170 million in 2020 for equity-accounted entities.

		Rest of	North		Sub-Saharan		Rest of		Australia and
(€ million) 2019	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	Asia	Americas	Oceania	Total
Consolidated subsidiaries
Proved property	17,643	6,747	15,512	20,691	43,272	12,118	11,434	15,912	1,360	144,689
Unproved property	18	323	502	34	2,361	11	1,592	979	194	6,014
Support equipment and facilities	384	21	1,549	225	1,328	116	36	23	12	3,694
Incomplete wells and other	635	103	1,362	359	2,541	1,165	1,006	457	43	7,671
Gross Capitalized Costs	18,680	7,194	18,925	21,309	49,502	13,410	14,068	17,371	1,609	162,068
Accumulated depreciation, depletion	(14,604)	(5,778)	(12,802)	(12,879)	(33,237)	(2,652)	(9,100)	(13,465)		(754) (105,271)
and amortization Net Capitalized Costs consolidated
subsidiaries(a)	4,076	1,416	6,123	8,430	16,265	10,758	4,968	3,906	855	56,797
Equity-accounted entities
Proved property		11,223	71		1,511		2	1,987		14,794
Unproved property		2,260					11			2,271
Support equipment and facilities		19	8					7		34
Incomplete wells and other		945	7		15		19	229		1,215
Gross Capitalized Costs		14,447	86		1,526		32	2,223		18,314
Accumulated depreciation, depletion and amortization		(5,287)	(61)		(323)		(20)	(1,124)		(6,815)
Net Capitalized Costs equity-accounted entities(a)(b)		9,160	25		1,203		12	1,099		11,499
2018
Consolidated subsidiaries
Proved property	16,569	6,236	14,140	17,474	40,607	11,240	12,711	15,347	1,967	136,291
Unproved property	18	332	456	56	2,311	3	1,530	861	193	5,760
Support equipment and facilities	369	21	1,516	208	1,281	108	38	52	12	3,605
Incomplete wells and other	653	103	1,554	1,504	2,307	1,382	562	595	127	8,787
Gross Capitalized Costs	17,609	6,692	17,666	19,242	46,506	12,733	14,841	16,855	2,299	154,443
Accumulated depreciation, depletion and amortization	(13,717)	(5,355)	(11,741)	(11,722)	(29,727)	(2,175)	(10,460)	(13,443)	(1,265)	(99,605)
Net Capitalized Costs consolidated subsidiaries(a)	3,892	1,337	5,925	7,520	16,779	10,558	4,381	3,412	1,034	54,838
Equity-accounted entities
Proved property		9,102	58		1,481		2	1,912		12,555
Unproved property		1,045					11			1,056
Support equipment and facilities		25	6					7		38
Incomplete wells and other		364	10		10		19	224		627
Gross Capitalized Costs		10,536	74		1,491		32	2,143		14,276
Accumulated depreciation, depletion and amortization		(4,543)	(54)		(266)		(19)	(1,052)		(5,934)
Net Capitalized Costs equity-accounted entities(a)(b)		5,993	20		1,225		13	1,091		8,342

(a) The amounts include net capitalized financial charges totalling €878 million in 2019 and €831 million in 2018 for the consolidates subsidiaries and €166 million in 2019 and €180 million in 2018 for equity-accounted entities. (b) Includes allocation at fair value of the assets purchased by Vår Energi AS.

Costs incurred(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2023
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration	12	55	91	237	189	9	277	138	1	1,009
Development(b)	798	249	925	708	2,662	296	921	937	151	7,647
Total costs incurred consolidated subsidiaries	810	304	1,016	945	2,851	305	1,198	1,075	152	8,656
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		92			46					138
Development(c)		1,703	4		731		150	2		2,590
Total costs incurred equity-accounted entities		1,795	4		777		150	2		2,728
2022
Consolidated subsidiaries
Proved property acquisitions	4		51					82		137
Unproved property acquisitions	2		111		11					124
Exploration	12	101	68	179	295	4	253	26	1	939
Development(b)	216	(129)	343	795	1,458	277	835	1,292	117	5,204
Total costs incurred consolidated subsidiaries	234	(28)	573	974	1,764	281	1,088	1,400	118	6,404
Equity-accounted entities
Proved property acquisitions							291			291
Unproved property acquisitions
Exploration		73			13					86
Development(c)		1,690	(8)		125		49	(9)		1,847
Total costs incurred equity-accounted entities		1,763	(8)		138		340	(9)		2,224
2021
Consolidated subsidiaries
Proved property acquisitions								8		8
Unproved property acquisitions			6					3		9
Exploration	16	96	33	57	136	3	188	83	1	613
Development(b)	182		497	452	842	185	785	657	27	3,627
Total costs incurred consolidated subsidiaries	198	96	536	509	978	188	973	751	28	4,257
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		92								92
Development(c)		936	59		4			2		1,001
Total costs incurred equity-accounted entities		1,028	59		4			2		1,093

(a) Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. (b) Includes the abandonment costs for €773 million in 2023, decrease of the assets for €307 million in 2022 and costs €62 million in 2021.

(c) Includes the abandonment costs for €163 million in 2023, decrease of the assets for €111 million in 2022 and decrease for €464 million in 2021.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2020
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions			55	2						57
Exploration	19	20	69	67	61	7	176	63	1	483
Development(a)	472	235	278	422	620	196	1,024	437	10	3,694
Total costs incurred consolidated subsidiaries	491	255	402	491	681	203	1,200	500	11	4,234
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		47								47
Development(b)		1,481	3		6			14		1,504
Total costs incurred equity-accounted entities		1,528	3		6			14		1,551
2019
Consolidated subsidiaries
Proved property acquisitions								144		144
Unproved property acquisitions			135	1			23	97		256
Exploration	20	62	101	94	206	15	232	106	39	875
Development(a)	1,098	230	749	1,589	1,959	481	1,199	879	43	8,227
Total costs incurred consolidated subsidiaries	1,118	292	985	1,684	2,165	496	1,454	1,226	82	9,502
Equity-accounted entities
Proved property acquisitions		1,054								1,054
Unproved property acquisitions		1,178								1,178
Exploration		125					(1)			124
Development(b)		1,574	4		5			37		1,620
Total costs incurred equity-accounted entities(c)		3,931	4		5		(1)	37		3,976
2018
Consolidated subsidiaries
Proved property acquisitions							382			382
Unproved property acquisitions							487			487
Exploration	26	106	43	102	66	3	182	215	7	750
Development(a)	382	557	445	2,216	1,379	92	589	340	36	6,036
Total costs incurred consolidated subsidiaries	408	663	488	2,318	1,445	95	1,640	555	43	7,655
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration			2				103			105
Development(b)			3					(16)		(13)
Total costs incurred equity-accounted entities			5				103	(16)		92

(a) Includes the abandonment costs for €516 million in 2020, costs for €2,069 million in 2019 and decrease of the assets for €517 million in 2018.

(b) Includes the abandonment costs for €424 million in 2020, costs for €838 million in 2019 and decrease of the assets for €22 million in 2018.

Standardized measure of discounted future net cash flows(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
December 31, 2023
Consolidated subsidiaries
Future cash inflows	22,724	3,926	49,789	23,046	35,147	40,081	40,622	14,951	707	230,993
Future production costs	(8,848)	(1,227)	(8,361)	(7,078)	(13,512)	(6,475)	(11,042)	(5,852)		(164) (62,559)
Future development and abandonment costs	(4,270)	(824)	(6,664)	(2,719)	(7,757)	(1,814)	(7,437)	(1,954)		(355) (33,794)
Future net inflow before income tax	9,606	1,875	34,764	13,249	13,878	31,792	22,143	7,145		188 134,640
Future income tax	(2,233)	(1,274)	(19,528)	(4,541)	(4,729)	(8,186)	(16,348)	(3,161)		(8) (60,008)
Future net cash flows	7,373	601	15,236	8,708	9,149	23,606	5,795	3,984	180	74,632
10% discount factor	(3,325)	(39)	(7,541)	(2,926)	(4,223)	(11,668)	(3,081)	(1,462)		(58) (34,323)
Standardized measure of discounted future net cash flows	4,048	562	7,695	5,782	4,926	11,938	2,714	2,522	122	40,309
Equity-accounted entities
Future cash inflows		29,387	168		22,954		19,108	7,519		79,136
Future production costs		(7,128)	(122)		(6,202)		(5,880)	(1,925)		(21,257)
Future development and abandonment costs		(5,221)	(54)		(2,972)		(410)	(179)		(8,836)
Future net inflow before income tax		17,038	(8)		13,780		12,818	5,415		49,043
Future income tax		(12,548)	(1)		(3,254)		(9,702)	(2,263)		(27,768)
Future net cash flows		4,490	(9)		10,526		3,116	3,152		21,275
10% discount factor		(1,114)	27		(4,508)		(2,158)	(1,237)		(8,990)
Standardized measure of discounted future net cash flows		3,376	18		6,018		958	1,915		12,285
Total consolidated subsidiaries and equity-accounted entities	4,048	3,938	7,713	5,782	10,944	11,938	3,672	4,437	122	52,594

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
December 31, 2022
Consolidated subsidiaries
Future cash inflows	38,968	7,609	50,838	34,198	48,292	53,529	45,179	21,233	1,525	301,371
Future production costs	(10,267)	(1,752)	(6,675)	(11,171)	(15,823)	(7,844)	(12,181)	(5,950)		(230) (71,893)
Future development and abandonment costs	(4,484)	(1,296)	(4,894)	(2,941)	(10,057)	(1,873)	(4,562)	(3,063)		(377) (33,547)
Future net inflow before income tax	24,217	4,561	39,269	20,086	22,412	43,812	28,436	12,220		918 195,931
Future income tax	(6,388)	(3,087)	(23,766)	(7,119)	(7,990)	(11,568)	(21,227)	(4,903)		(81) (86,129)
Future net cash flows	17,829	1,474	15,503	12,967	14,422	32,244	7,209	7,317		837 109,802
10% discount factor	(7,141)	(344)	(7,176)	(4,562)	(6,456)	(16,087)	(2,980)	(3,443)		(357) (48,546)
Standardized measure of discounted future net cash flows	10,688	1,130	8,327	8,405	7,966	16,157	4,229	3,874	480	61,256
Equity-accounted entities
Future cash inflows		50,468	265		42,450		33,075	8,133		134,391
Future production costs		(7,628)	(123)		(10,579)		(9,749)	(2,083)		(30,162)
Future development and abandonment costs		(6,458)	(57)		(3,508)		(560)	(178)		(10,761)
Future net inflow before income tax		36,382	85		28,363		22,766	5,872		93,468
Future income tax		(27,333)	(3)		(8,117)		(19,393)	(2,469)		(57,315)
Future net cash flows		9,049	82		20,246		3,373	3,403		36,153
10% discount factor		(2,501)	(15)		(9,058)		(2,462)	(1,416)		(15,452)
Standardized measure of discounted future net cash flows		6,548	67		11,188		911	1,987		20,701
Total consolidated subsidiaries and equity-accounted entities	10,688	7,678	8,394	8,405	19,154	16,157	5,140	5,861	480	81,957

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
December 31, 2021
Consolidated subsidiaries
Future cash inflows	18,933	4,679	33,142	31,344	40,929	36,430	32,594	13,607	1,511	213,169
Future production costs	(6,929)	(1,496)	(6,325)	(9,726)	(13,196)	(7,343)	(9,578)	(4,189)		(251) (59,033)
Future development and abandonment costs	(4,104)	(865)	(4,688)	(2,036)	(5,117)	(1,750)	(4,278)	(2,298)		(288) (25,424)
Future net inflow before income tax	7,900	2,318	22,129	19,582	22,616	27,337	18,738	7,120		972 128,712
Future income tax	(2,037)	(1,001)	(12,345)	(6,736)	(8,372)	(6,301)	(12,899)	(2,386)		(75) (52,152)
Future net cash flows	5,863	1,317	9,784	12,846	14,244	21,036	5,839	4,734	897	76,560
10% discount factor	(2,112)	(170)	(4,516)	(4,211)	(5,608)	(10,703)	(2,295)	(1,980)		(350) (31,945)
Standardized measure of discounted future net cash flows	3,751	1,147	5,268	8,635	8,636	10,333	3,544	2,754	547	44,615
Equity-accounted entities
Future cash inflows		28,037	230		8,884			5,971		43,122
Future production costs		(8,316)	(120)		(1,590)			(1,454)		(11,480)
Future development and abandonment costs		(6,566)	(85)		(95)			(77)		(6,823)
Future net inflow before income tax		13,155	25		7,199			4,440		24,819
Future income tax		(8,591)	(9)		(1,286)			(1,309)		(11,195)
Future net cash flows		4,564	16		5,913			3,131		13,624
10% discount factor		(1,462)	16		(3,498)			(1,399)		(6,343)
Standardized measure of discounted future net cash flows		3,102	32		2,415			1,732		7,281
Total consolidated subsidiaries and equity-accounted entities	3,751	4,249	5,300	8,635	11,051	10,333	3,544	4,486	547	51,896

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
December 31, 2020
Consolidated subsidiaries
Future cash inflows	6,120	1,737	19,780	26,003	26,901	21,519	22,528	6,638		1,599 132,825
Future production costs	(3,587)	(753)	(5,431)	(7,515)	(10,909)	(6,224)	(7,241)	(3,382)		(265) (45,307)
Future development and abandonment costs	(1,925)	(756)	(4,378)	(1,638)	(4,257)	(1,743)	(4,511)	(1,786)		(246) (21,240)
Future net inflow before income tax	608	228	9,971	16,850	11,735	13,552	10,776	1,470	1,088	66,278
Future income tax	(170)	(61)	(4,946)	(5,320)	(2,988)	(2,313)	(6,774)	(441)		(140) (23,153)
Future net cash flows	438	167	5,025	11,530	8,747	11,239	4,002	1,029	948	43,125
10% discount factor	(33)	108	(2,413)	(4,101)	(3,714)	(6,040)	(1,681)	(482)		(383) (18,739)
Standardized measure of discounted future net cash flows	405	275	2,612	7,429	5,033	5,199	2,321	547	565	24,386
Equity-accounted entities
Future cash inflows		15,306	251		1,253			6,291		23,101
Future production costs		(5,942)	(98)		(982)			(1,641)		(8,663)
Future development and abandonment costs		(6,244)	(29)		(46)			(137)		(6,456)
Future net inflow before income tax		3,120	124		225			4,513		7,982
Future income tax		(576)	(54)		(3)			(1,375)		(2,008)
Future net cash flows		2,544	70		222			3,138		5,974
10% discount factor		(1,055)	(43)		(110)			(1,460)		(2,668)
Standardized measure of discounted future net cash flows		1,489	27		112			1,678		3,306
Total consolidated subsidiaries and equity-accounted entities	405	1,764	2,639	7,429	5,145	5,199	2,321	2,225	565	27,692

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
December 31, 2019
Consolidated subsidiaries
Future cash inflows	12,363	3,268	38,083	37,020	48,778	36,435	31,220	11,378		1,686 220,231
Future production costs	(5,078)	(1,175)	(6,944)	(10,934)	(15,534)	(8,239)	(8,888)	(5,060)		(293) (62,145)
Future development and abandonment costs	(3,551)	(1,338)	(4,985)	(1,591)	(6,265)	(2,362)	(6,047)	(2,629)		(225) (28,993)
Future net inflow before income tax	3,734	755	26,154	24,495	26,979	25,834	16,285	3,689		1,168 129,093
Future income tax	(796)	(249)	(13,632)	(7,829)	(9,926)	(5,485)	(11,379)	(1,034)		(143) (50,473)
Future net cash flows	2,938	506	12,522	16,666	17,053	20,349	4,906	2,655	1,025	78,620
10% discount factor	(466)	63	(5,852)	(5,822)	(6,604)	(10,832)	(1,990)	(1,187)		(443) (33,133)
Standardized measure of discounted future net cash flows	2,472	569	6,670	10,844	10,449	9,517	2,916	1,468	582	45,487
Equity-accounted entities
Future cash inflows		25,094	380		1,787			7,730		34,991
Future production costs		(6,953)	(113)		(863)			(2,038)		(9,967)
Future development and abandonment costs		(6,519)	(23)		(59)			(145)		(6,746)
Future net inflow before income tax		11,622	244		865			5,547		18,278
Future income tax		(7,020)	(77)		(225)			(1,783)		(9,105)
Future net cash flows		4,602	167		640			3,764		9,173
10% discount factor		(1,544)	(88)		(322)			(1,809)		(3,763)
Standardized measure of discounted future net cash flows		3,058	79		318			1,955		5,410
Total consolidated subsidiaries and equity-accounted entities	2,472	3,627	6,749	10,844	10,767	9,517	2,916	3,423	582	50,897

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
December 31, 2018
Consolidated subsidiaries
Future cash inflows	18,372	4,895	43,578	39,193	53,534	40,698	33,384	14,192		2,319 250,165
Future production costs	(5,659)	(1,438)	(6,653)	(12,193)	(16,417)	(8,276)	(9,492)	(6,038)		(511) (66,677)
Future development and abandonment costs	(4,670)	(1,350)	(4,700)	(2,769)	(6,778)	(2,640)	(5,755)	(2,467)		(291) (31,420)
Future net inflow before income tax	8,043	2,107	32,225	24,231	30,339	29,782	18,137	5,687		1,517 152,068
Future income tax	(1,671)	(798)	(17,514)	(7,829)	(11,566)	(6,524)	(11,980)	(1,791)		(289) (59,962)
Future net cash flows	6,372	1,309	14,711	16,402	18,773	23,258	6,157	3,896	1,228	92,106
10% discount factor	(2,045)	(124)	(6,727)	(6,564)	(7,501)	(12,477)	(2,258)	(1,508)		(491) (39,695)
Standardized measure of discounted future net cash flows	4,327	1,185	7,984	9,838	11,272	10,781	3,899	2,388	737	52,411
Equity-accounted entities
Future cash inflows		18,608	347		2,675			8,292		29,922
Future production costs		(4,686)	(138)		(873)			(2,192)		(7,889)
Future development and abandonment costs		(3,633)	(3)		(75)			(191)		(3,902)
Future net inflow before income tax		10,289	206		1,727			5,909		18,131
Future income tax		(6,822)	(43)		(204)			(1,839)		(8,908)
Future net cash flows		3,467	163		1,523			4,070		9,223
10% discount factor		(1,104)	(76)		(793)			(2,009)		(3,982)
Standardized measure of discounted future net cash flows		2,363	87		730			2,061		5,241
Total consolidated subsidiaries and equity-accounted entities	4,327	3,548	8,071	9,838	12,002	10,781	3,899	4,449	737	57,652

(a) Estimated future cash inflows represent the revenues that would be received from production and are determined by applying the year-end average prices during the years ended. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered. The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor. Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the countries in which Eni operates. The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - Oil and Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni's proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

Changes in standardized measure of discounted future net cash flows

(€ million)	Consolidated subsidiaries	Equity-accounted entities	Total
2023
Standardized measure of discounted future net cash flows at December 31, 2022	61,256	20,701	81,957
Increase (Decrease):
- sales, net of production costs	(19,397)	(5,426)	(24,823)
- net changes in sales and transfer prices, net of production costs	(33,769)	(19,785)	(53,554)
- extensions, discoveries and improved recovery, net of future production and development costs	1,659		1,659
- changes in estimated future development and abandonment costs	(4,684)	(1,353)	(6,037)
- development costs incurred during the period that reduced future development costs	6,691	2,517	9,208
- revisions of quantity estimates	6,531	155	6,686
- accretion of discount	10,627	3,033	13,660
- net change in income taxes	12,675	14,753	27,428
- purchase of reserves in-place	977	44	1,021
- sale of reserves in-place	(845)	(60)	(905)
- changes in production rates (timing) and other	(1,412)	(2,294)	(3,706)
Net increase (decrease)	(20,947)	(8,416)	(29,363)
Standardized measure of discounted future net cash flows at December 31, 2023	40,309	12,285	52,594

(€ million)	Consolidated subsidiaries	Equity-accounted entities	Total
2022
Standardized measure of discounted future net cash flows at December 31, 2021	44,615	7,281	51,896
Increase (Decrease):
- sales, net of production costs	(25,987)	(4,912)	(30,899)
- net changes in sales and transfer prices, net of production costs	56,002	24,343	80,345
- extensions, discoveries and improved recovery, net of future production and development costs	1,519	2,139	3,658
- changes in estimated future development and abandonment costs	(7,046)	(3,169)	(10,215)
- development costs incurred during the period that reduced future development costs	3,821	2,000	5,821
- revisions of quantity estimates	(1,295)	7,134	5,839
- accretion of discount	7,226	1,510	8,736
- net change in income taxes	(18,393)	(21,676)	(40,069)
- purchase of reserves in-place	765	10,200	10,965
- sale of reserves in-place	(6,436)		(6,436)
- changes in production rates (timing) and other	6,465	(4,149)	2,316
Net increase (decrease)	16,641	13,420	30,061
Standardized measure of discounted future net cash flows at December 31, 2022	61,256	20,701	81,957

(€ million)	Consolidated subsidiaries	Equity-accounted entities	Total
2021
Standardized measure of discounted future net cash flows at December 31, 2020	24,386	3,306	27,692
Increase (Decrease):
- sales, net of production costs	(16,402)	(3,381)	(19,783)
- net changes in sales and transfer prices, net of production costs	40,864	9,256	50,120
- extensions, discoveries and improved recovery, net of future production and development costs	1,304	142	1,446
- changes in estimated future development and abandonment costs	(2,737)	(734)	(3,471)
- development costs incurred during the period that reduced future development costs	2,877	1,385	4,262
- revisions of quantity estimates	1,963	1,665	3,628
- accretion of discount	3,810	514	4,324
- net change in income taxes	(14,022)	(5,216)	(19,238)
- purchase of reserves in-place	27		27
- sale of reserves in-place	(28)		(28)
- changes in production rates (timing) and other	2,573	344	2,917
Net increase (decrease)	20,229	3,975	24,204
Standardized measure of discounted future net cash flows at December 31, 2021	44,615	7,281	51,896

(€ million)	Consolidated subsidiaries	Equity-accounted entities	Total
2020
Standardized measure of discounted future net cash flows at December 31, 2019	45,487	5,410	50,897
Increase (Decrease):
- sales, net of production costs	(10,046)	(1,490)	(11,536)
- net changes in sales and transfer prices, net of production costs	(34,188)	(5,324)	(39,512)
- extensions, discoveries and improved recovery, net of future production and development costs		142	265
- changes in estimated future development and abandonment costs	792	(834)	(42)
- development costs incurred during the period that reduced future development costs	4,147	1,192	5,339
- revisions of quantity estimates	36	(285)	(249)
- accretion of discount	7,136	1,065	8,201
- net change in income taxes	13,336	3,814	17,150
- purchase of reserves in-place
- sale of reserves in-place
- changes in production rates (timing) and other	(2,437)	(384)	(2,821)
Net increase (decrease)	(21,101)	(2,104)	(23,205)
Standardized measure of discounted future net cash flows at December 31, 2020	24,386	3,306	27,692

(€ million)	Consolidated subsidiaries	Equity-accounted entities	Total
2019
Standardized measure of discounted future net cash flows at December 31, 2018	52,411	5,241	57,652
Increase (Decrease):
- sales, net of production costs	(18,236)	(1,675)	(19,911)
- net changes in sales and transfer prices, net of production costs	(14,972)	(2,247)	(17,219)
- extensions, discoveries and improved recovery, net of future production and development costs	1,240	86	1,326
- changes in estimated future development and abandonment costs	(1,157)	(916)	(2,073)
- development costs incurred during the period that reduced future development costs	5,128	687	5,815
- revisions of quantity estimates	5,573	1,377	6,950
- accretion of discount	8,666	1,050	9,716
- net change in income taxes	6,013	(761)	5,252
- purchase of reserves in-place	260	2,579	2,839
- sale of reserves in-place(a)	(429)	(88)	(517)
- changes in production rates (timing) and other	990	77	1,067
Net increase (decrease)	(6,924)	169	(6,755)
Standardized measure of discounted future net cash flows at December 31, 2019	45,487	5,410	50,897

(a) Includes volume as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.

(€ million)	Consolidated subsidiaries	Equity-accounted entities	Total
2018
Standardized measure of discounted future net cash flows at December 31, 2017	36,993	2,633	39,626
Increase (Decrease):
Sales, net of production costs	(19,793)	(445)	(20,238)
Net changes in sales and transfer prices, net of production costs	27,970	671	28,641
Extensions, discoveries and improved recovery, net of future production and development costs	1,649		1,649
Changes in estimated future development and abandonment costs	(2,525)	216	(2,309)
Development costs incurred during the period that reduced future development costs	6,468	14	6,482
Revisions of quantity estimates	10,487	(803)	9,684
Accretion of discount	5,670	384	6,054
Net change in income taxes	(16,566)	193	(16,373)
Purchase of reserves in-place	5,369	6,700	12,069
Sale of reserves in-place	(8,363)		(8,363)
Changes in production rates (timing) and other	5,052 (4,322)
Net increase (decrease)	15,418	2,608	18,026
Standardized measure of discounted future net cash flows at December 31, 2018	52,411	5,241	57,652

(€ million)	2023	2022	2021	2020	2019	2018
Acquisition of proved and unproved properties		260	17	57	400	869
Italy		7
North Africa		161	6	55	135
Egypt				2	1
Sub-Saharan Africa		11
Rest of Asia					23	869
Americas		81	11		241
Exploration	784	708	391	283	586	463
Italy						1
Rest of Europe	41	82	81	9	43	52
North Africa	67	36	11	42	71	20
Egypt	194	163	37	48	86	80
Sub-Saharan Africa	142	258	81	20	128	22
Kazakhstan	7	2	2	4	7
Rest of Asia	223	163	120	124	141	140
Americas	110	4	59	36	74	146
Australia and Oceania					36	2
Oil and gas development	6,293	5,238	3,364	3,077	5,931	6,506
Italy	636	301	282	229	289	380
Rest of Europe	104	127	91	107	110	600
North Africa	756	300	206	220	536	525
Egypt	709	712	442	393	1,481	2,205
Sub-Saharan Africa	2,271	1,492	771	624	1,406	1,635
Kazakhstan	288	351	189	178	371	193
Rest of Asia	919	851	824	916	1,028	550
Americas	471	1,016	532	402	695	381
Australia and Oceania	139	88	27	8	15	37
Other	56	46	52	55	79	63
	7,133	6,252	3,824	3,472	6,996	7,901

Global Gas & LNG Portfolio

KEY PERFORMANCE INDICATORS

		2023	2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)(a)	(total recordable injuries/worked hours) x 1,000,000	0.00	0.00	0.00	1.15	0.56	0.51
of which: employees		0.00	0.00	0.00	0.99	0.96	0.40
contractors		0.00	0.00	0.00	1.37	0.00	0.69
Sales from operations(b)	(€ million)	20,139	48,586	20,843	7,051	11,779	14,807
Operating profit (loss)		2,431	3,730	899	(332)	431	387
Adjusted operating profit (loss)		3,247	2,063	580	326	193	278
Adjusted net profit (loss)		2,373	982	169	211	100	118
Capital expenditure		16	23	19	11	15	26
Natural gas sales(b)	(bcm)	50.51	60.52	70.45	64.99	72.85	76.60
Italy		24.40	30.67	36.88	37.30	37.98	39.17
Rest of Europe		23.84	27.41	28.01	23.00	26.72	29.17
of which: Importers in Italy		2.29	2.43	2.89	3.67	4.37	3.42
European markets		21.55	24.98	25.12	19.33	22.35	25.75
Rest of world		2.27	2.44	5.56	4.69	8.15	8.26
LNG sales(c)		9.6	9.4	10.9	9.5	10.1	10.3
Employees at year end	(number)	669	870	847	700	711	734
of which: outside Italy		390	588	571	410	418	416
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	0.69	2.09	1.01	0.36	0.25	0.62

(a) Calculated on 100% operated assets.

(b) Data include intercomapny sales. (c) Refers to LNG sales of the GGP segment (included in worldwide gas sales). Eni's Global Gas & LNG Portfolio (GGP) segment engages in all phases of the natural gas value chain: supply, trading and marketing of natural gas and LNG. Eni's leading position in the European gas market is ensured by a set of competitive advantages, including our multi-Country approach, long-term gas availability, access to infrastructures, market knowledge, in addition to long-term relations with producing Countries. Furthermore, integration with our upstream operations provides valuable growth options whereby the Company targets to monetize its large gas reserves.

GLOBAL GAS & LNG PORTFOLIO VALUE CHAIN

(a) Includes own consumptions.

GAS SALES IN ITALY (bcm) WORLDWIDE GAS SALES (bcm)

1 MARKETING

1.1 Natural gas

Supply of natural gas

Eni's activity of natural gas supply leverages on the availability of equity production volumes, on the access to all phases of the LNG chain (liquefaction, shipping and regasification) and to other international gas infrastructures, on gas trading activity finalized to hedge and stabilize commercial margins, on optimization of gas portfolio, as well as on risk management activity.

The supply of natural gas is a free activity where prices are determined by free negotiations of demand and supply involving natural gas resellers and producers. In order to secure mid and long-term access to gas availability, to support gas sales programs and contribute to the security of supply of the European and domestic market, Eni has signed a number of long-term gas supply contracts with key producing Countries that supply the European gas markets.

In November 2023, with the aim of continuing the plan to consolidate gas supplies in response to the energy crisis caused by the difficult international situation, Eni signed an agreement with Open EP to guarantee the flow of gas to Switzerland and Italy in the event of interruptions or significant flow reductions from Germany. The agreement promotes the efficient use of the Swiss Transitgas transport infrastructure for gas flows from France to Italy through Switzerland to support Swiss supply security.

In order to ensure a higher flexibility and further diversify natural gas supplies, in 2023 Eni signed a number of important agreements. In particular:

in Congo a purchase contract for LNG volumes from the Congo LNG project;
in Southern Asia with Merakes LNG Sellers;
in Qatar a long-term contract with QatarEnergy LNG NFE.

These new LNG contracts contribute to the build-up of the overall LNG contracted portfolio by leveraging on Eni's integrated approach in the Countries where we operate and are in line with the company's energy transition strategy, which aims to progressively increase the share of gas in overall upstream production to 60% by 2030, while also increasing the contribution of equity LNG.

Eni's consolidated subsidiaries supplied 50.05 bcm of natural gas, decreased by 10.54 bcm or by 17% from the full year 2022. Gas volumes supplied outside Italy from consolidated subsidiaries (44.34 bcm), imported in Italy or sold outside Italy, represented approximately 89% of total supplies, decreased by 12.85 bcm or by 23% from the full year 2022. This mainly reflected lower volumes purchased in Russia (down by 11.04 bcm), in France (down by 1.28 bcm), in Egypt (down by 0.80 bcm), in the UK (down by 0.49 bcm), in Norway (down by 0.26 bcm) and in Libya (down by 0.10 bcm), partly offset by higher purchases in Qatar (up by 0.35 bcm), in Netherlands (up by 0.23 bcm), in Algeria (up by 0.20 bcm) and in Indonesia (up by 0.20 bcm). Supplies in Italy (5.71 bcm) reported an increase of 68% from the full year 2022.

ENI'S NATURAL GAS SUPPLY

Long-term contracts

(a) It includes gas volumes marketed to Eni Plenitude.

Marketing in Italy and Europe

European gas market was characterized by consumption reduction due to mild weather conditions which have negatively impacted civil sector consumption, due to weak electrical demand, as well as the recovery of the hydroelectric and nuclear sectors, resulting in a different consumption mix. In this scenario, demand decreased by approximately 10% and 8% in Italy and in the European Union, respectively, compared to 2022. Natural gas sales amounted to 50.51 bcm (including Eni's own consumption, Eni's share of sales made by equity-accounted entities) and decreased by 10.01 bcm or 16.5% from the previous year due to lower sales in Italy, in Europe and outside Europe.

GAS SALES BY MARKET

(bcm)	2023	2022	2021	2020	2019	2018
ITALY	24.40	30.67	36.88	37.30	37.98	39.17
Wholesalers	10.71	12.22	13.37	12.89	13.08	14.67
Italian gas exchange and spot markets	6.28	9.31	12.13	12.73	12.13	12.49
Industries	1.50	2.89	4.07	4.21	4.62	4.40
Power generation	0.52	0.83	0.94	1.34	1.90	1.50
Own consumption	5.39	5.42	6.37	6.13	6.25	6.11
INTERNATIONAL SALES	26.11	29.85	33.57	27.69	34.87	37.43
Rest of Europe	23.84	27.41	28.01	23.00	26.72	29.17
Importers in Italy	2.29	2.43	2.89	3.67	4.37	3.42
European markets	21.55	24.98	25.12	19.33	22.35	25.75
Iberian Peninsula	2.75	3.93	3.75	3.94	4.22	4.65
Germany/Austria	3.35	3.58	0.69	0.35	2.19	1.93
Benelux	3.75	4.24	3.47	3.58	3.78	5.29
United Kingdom	1.42	1.92	2.65	1.62	1.75	2.22
Turkey	6.90	7.62	8.50	4.59	5.56	6.53
France	3.31	3.62	5.80	5.01	4.47	4.95
Other	0.07	0.07	0.26	0.24	0.38	0.18
Extra European markets	2.27	2.44	5.56	4.69	8.15	8.26
NATURAL GAS SALES	50.51	60.52	70.45	64.99	72.85	76.60

Sales in Italy (24.40 bcm) decreased by 6.27 bcm from 2022 mainly due to lower volumes marketed in all business segments, mainly to hub and in the wholesale and industrial segments. Sales to importers in Italy (2.29 bcm) decreased by 0.14 bcm from 2022 due to the lower availability of Libyan gas. Sales in the European markets amounted to 21.55 bcm, down by 3.43 bcm from 2022. Sales in the extra European markets of 2.27 bcm decreased by 0.17 bcm or 7% from the previous year, due to lower LNG volumes marketed in the Asian markets. A review of Eni's presence in the main European markets is presented below:

Benelux

Eni operates in Benelux in the industrial, wholesalers and power generation segments. In 2023, sales amounted to 3.75 bcm, down 0.49 bcm, or 11.6% compared to 2022, mainly due to lower sales to the industrial segment.

France

In France, Eni operates in all business segments through its direct commercial activities and its subsidiary Eni Gas & Power France SA. In 2023, sales in the Country amounted to 3.31 bcm (including sales to Plenitude's subsidiaries), a decrease of 0.31 bcm, or 8.6%, from a year ago, mainly due to lower sales to the industrial segment and to local distribution companies.

Germany/Austria

In 2023 total sales in Germany and Austria amounted to 3.35 bcm down by 0.23 bcm from 2022, due to the portfolio optimizations.

Spain

Eni operates in the Spanish natural gas market through marketing of natural gas to industrial clients, wholesalers and power generation utilities. In 2023, total Eni's sales in Spain amounted to 2.75 bcm, a decrease of 1.18 bcm, or 30% compared to 2022, due to lower sales to wholesalers and industrial segments.

Turkey

Eni sells gas transported via Blue Stream pipeline. In 2023, sales amounted to 6.90 bcm, a decrease of 0.72 bcm, or 9.4% from a year ago mainly driven by lower sales to Botas.

United Kingdom

Eni, through its subsidiary EGEM (Eni Global Energy Market), is engaged in marketing activities in the United Kingdom. This subsidiary markets the equity gas produced at Eni's fields in the North Sea and operates in the main North European natural gas hubs (NBP, Zeebrugge, TTF). In 2023, sales amounted to 1.42 bcm, down by 0.50 bcm or 26% compared to 2022 due to lower volumes sold to hub.

1.2 LNG

Eni is engaged in all the activities of the LNG business: liquefaction, gas feeding, shipping, regasification and sale.

In order to consolidate the LNG portfolio, leveraging the strong relationships with the Countries where Eni operates and in line with the energy transition strategy, Eni, in October 2023, signed a 0.8 bcm/year LNG sales and purchase agreement with Merakes LNG Sellers starting from January 2024 for 3 years. This agreement, in addition to the contract with Jangkrik LNG Sellers for 1.4 bcm/ year, in place since 2017, expands the overall LNG available from Bontang facility.

Furthermore, in October 2023, Eni signed a long-term contract with QatarEnergy LNG NFE, the JV between Eni and QatarEnergy for the development of the North Field East project in Qatar, for the delivery of up to 1.5 bcm/year of LNG. LNG will be delivered at the receiving terminal "FSRU Italia", currently located in Piombino, Italy, with expected deliveries starting from 2026 with a duration of 27 years. The LNG production in Qatar will increase by 45 bcm in addition to the current 108 bcm. This agreement expands the import portfolio from Qatar given that Eni is already importing in Europe 2.9 bcm/year since 2007.

Relating to the liquefaction activity, during 2023, ships "Tango" Floating Liquefied Natural Gas (FLNG) and "Excalibur" Floating Storage Unit (FSU)

2 International transport

Eni owns transport rights on a large European and North African networks for transporting natural gas in Italy and Europe, which link key consumption basins with the main producing areas (Russia, Algeria, the North Sea, including the Netherlands, Norway, and Libya).

Eni transferred the interests in the TTPC onshore pipeline and TMPC pipeline to SeaCorridor Srl of which Snam acquired 49.9% interest, while the 50.1% interest is still being held by Eni. Eni and Snam exercise joint control over SeaCorridor Srl, based on the principles of equal governance.

A description of the main international pipelines is provided below:

• the TTPC pipeline 740-kilometer long, is made up of two lines that are each 370-kilometer long with a transport capacity at the Oued Saf Saf entry point of 34.3 bcm/y and five compression stations. This pipeline transports natural gas from Algeria have been launched from Dubai towards Congolese waters. The Tango FLNG facility has a liquefaction capacity of about 1 bcm/year and is moored alongside the Excalibur Floating Storage Unit (FSU) and has been initiated the introduction of gas at the floating liquefaction plant.

Furthermore, relating to Tango FLNG, in September 2023, Eni signed a purchase contract for LNG volumes from the Congo LNG project of up to approximately 4.5 bcm/year starting from the first quarter of 2024. The project and the relative offtakes will have two phases: in the first phase the Tango FLNG facility will have a liquefaction capacity of around 1 bcm/year, then a second FLNG with a capacity of around 3.5 bcm/year will begin production in 2025.

In the perspective of an increasingly greater diversification of LNG supplies and the expansion of areas of cooperation and collaboration, in April, Eni and SPP, the Slovakia's largest energy supplier, signed a Memorandum of Understanding (MoU) for a commercial cooperation in the gas and LNG sector, aimed at evaluating initiatives in the areas of trading and management of regasification and transportation capacities to secure and strengthen supplies of natural gas to the Slovak Republic.

LNG sales (9.6 bcm, included in the worldwide gas sales) increased by 2.1% from 2022. In 2023 the main sources of LNG supply were Qatar, Nigeria, Indonesia and Egypt.

across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline;

the TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 bcm/y. It crosses the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system;
the GreenStream pipeline for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 516-kilometer long with an originally transport capacity of 11.5 bcm/y crossing the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system;
the Blue Stream underwater pipeline (with a record water depth of more than 2,150 meters) linking the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 bcm/y.

SUPPLY OF NATURAL GAS

(bcm)	2023	2022	2021	2020	2019	2018
Italy	5.71	3.40	3.59	7.47	5.57	5.46
Russia	6.16	17.20	30.21	22.49	24.36	26.10
Algeria (including LNG)	12.06	11.86	10.12	5.22	6.66	12.02
Libya	2.52	2.62	3.18	4.44	5.86	4.55
Netherlands	1.62	1.39	1.41	1.11	4.12	3.95
Norway	6.49	6.75	7.52	7.19	6.43	6.75
United Kingdom	1.42	1.91	2.65	1.62	1.75	2.21
Indonesia (LNG)	1.56	1.36	1.81	1.15	1.58	3.06
Qatar (LNG)	2.91	2.56	2.30	2.47	2.79	2.56
Other supplies of natural gas	5.89	8.11	2.39	5.24	7.90	5.50
Other supplies of LNG	3.71	3.43	5.80	3.76	3.40	1.97
Outside Italy	44.34	57.19	67.39	54.69	64.85	68.67
Total supplies of Eni's consolidated subsidiaries	50.05	60.59	70.98	62.16	70.42	74.13
Offtake from (input to) storage	0.54	0.00	(0.86)	0.52	0.08	0.08
Network losses, measurement differences and other changes	(0.08)	(0.07)	(0.04)	(0.03)	(0.22)	(0.18)
Available for sale by Eni's consolidated subsidiaries	50.51	60.52	70.08	62.65	70.28	74.03
Available for sale of Eni's affiliates	0.00	0.00	0.37	2.34	2.57	2.57
NATURAL GAS VOLUMES AVAILABLE FOR SALE	50.51	60.52	70.45	64.99	72.85	76.60

GAS SALES BY ENTITY

(bcm)	2023	2022	2021	2020	2019	2018
Total sales of subsidiaries	50.51	60.52	69.99	62.58	70.17	73.68
Italy (including own consumption)	24.40	30.67	36.88	37.30	37.98	39.17
Rest of Europe	23.84	27.41	27.69	21.54	25.21	27.42
Outside Europe	2.27	2.44	5.42	3.74	6.98	7.09
Total sales of Eni's affiliates (net to Eni)	0.00	0.00	0.46	2.41	2.68	2.92
Rest of Europe	0.00	0.00	0.32	1.46	1.51	1.75
Outside Europe	0.00	0.00	0.14	0.95	1.17	1.17
NATURAL GAS SALES	50.51	60.52	70.45	64.99	72.85	76.60

LNG SALES

(bcm)	2023	2022	2021	2020	2019	2018
Europe	7.3	7.0	5.4	4.8	5.5	4.7
Outside Europe	2.3	2.4	5.5	4.7	4.6	5.6
TOTAL SALES	9.6	9.4	10.9	9.5	10.1	10.3

Tratta	Lines (units)	Lenght (km)	Diameter (inch)	Transport capacity(a) (bcm/y)	Compression stations (No.)
TTPC (Oued Saf Saf-Cap Bon)	2 lines of 370 km	740	48	34.3	5
TMPC (Cap Bon-Mazara del Vallo)	5 lines of 155 km	775	20/26	33.5
GreenStream (Mellitah-Gela)	1 line of 516 km	516	32	11.5	1
Blue Stream (Beregovaya-Samsun)	2 lines of 387 km	774	24	16.0	1

(a) Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.

CAPITAL EXPENDITURE

(€ million)	2023	2022	2021	2020	2019	2018
Market	13	2		5	3	19
Italy						8
Outside Italy	13	2		5	3	11
International transport	3	21	19	6	12	7
TOTAL CAPITAL EXPENDITURE	16	23	19	11	15	26

ENERGY EVOLUTION

Enilive, Refining and Chemicals Plenitude & Power Environmental activities

Enilive, Refining and Chemicals

KEY PERFORMANCE INDICATORS

		2023	2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)(a)	(total recordable injuries/worked hours) x 1,000,000	0.75	0.81	0.80	0.80	0.27	0.56
of which: employees		0.96	0.95	1.13	1.17	0.24	0.49
contractors		0.50	0.69	0.49	0.48	0.29	0.62
Sales from operations(b)	(€ million)	52,558	59,178	40,374	25,340	42,360	46,483
Operating profit (loss)		(1,397)	460	45	(2,463)	(682)	(501)
Adjusted operating profit (loss)		555	1,929	152	6	21	360
- Enilive and Refining		1,169	2,183	(46)	235	289	370
- Chemicals		(614)	(254)	198	(229)	(268)	(10)
Adjusted net profit (loss)		670	1,914	62	(246)	(42)	224
Capital expenditure		982	878	728	771	933	877
Bio throughputs	(ktonnes)	866	543	665	710	311	253
Capacity of biorefineries	(mmtonnes/year)	1.65	1.10	1.10	1.10	1.10	0.36
Average biorefineries utilization rate(c)	(%)	72	58	65	63	44	63
Conversion index of oil refineries		47	42	49	54	54	54
Balanced capacity of refineries (Eni's share)	(kbbl/d)	528	528	548	548	548	548
Average oil refineries utilization rate		77	79	76	69	88	91
Retail sales of petroleum products in Europe	(mmtonnes)	7.51	7.50	7.23	6.61	8.25	8.39
Service stations in Europe at year end	(number)	5,267	5,243	5,314	5,369	5,411	5,448
Average throughput per service station in Europe	(kliters)	1,645	1,587	1,521	1,390	1,766	1,776
Retail efficiency index	(%)	1.19	1.20	1.19	1.22	1.23	1.20
Production of chemical products	(ktonnes)	5,663	6,856	8,496	8,073	8,068	9,483
Sale of chemical products		3,117	3,752	4,471	4,339	4,295	4,946
Average chemical plant utilization rate	(%)	51	59	66	65	67	76
Employees at year end	(number)	14,092	13,132	13,072	11,471	11,626	11,457
- of which outside Italy		4,257	4,146	4,044	2,556	2,591	2,594
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	5.69	6.00	6.72	6.65	7.97	8.19
GHG emissions (Scope 1)/refinery throughputs (raw and semi-finished materials)	(tonnes CO2 eq./ktonnes)	232	233	228	248	248	253

(a) Calculated on 100% operated assets.

(b) Before elimination of intragroup sales.

Enilive, Refining and Chemicals segment engages in the supply and refining of biofeedstock and crude oil, storage, production, distribution and marketing of refined products and biofuels, biomethane, smart mobility solutions, production and distribution of basic petrochemical products, plastics, elastomers and chemicals from renewable sources.

It includes the results of the activities of the Enilive, Refining and Chemical businesses which have been aggregated into a single segment because these two operating segments have similar economic returns.

In the Enilive and Refining business, Eni, through Enilive¹ , is engaged in biofeedstock supply, processing and production of biofuels, in Italy at the Venice and Gela biorefineries, in the United States with a 50% interest in the Chalmette biorefinery, capable of processing sustainable biofeedstock, biomethane, as well as Enilive is engaged in smart mobility activities, including Enjoy car sharing, and the marketing and distribution of all energy carriers for mobility, including more than 5,000 Enilive stations in Europe, where a wide range of products is marketed, including biogenic fuels such as HVO (Hydrogenated Vegetable Oil), bioLPG and biomethane, as well as hydrogen and electricity, and other products such as bitumen, lubricants and fuels.

Enilive is targeted to provide progressively decarbonised services and products for the energy transition, accelerating the path towards reducing emissions on their entire life cycle. The Enilive stations network also supports other mobility services including catering, also through the collaboration with the Niko Romito Academy and the opening of the first "ALT Stazione del Gusto" restaurant in Rome, proximity shops and a number of services to support people on the move, such as Telepass points, Enjoy cars, payment of postal bills and Amazon Lockers. The business is also engaged in the wholesaler marketing, consisting mainly in resellers, manufacturing industries, service companies, public and local authorities, housing facilities, operators in the agricultural and seafood sector; in other sales mainly to oil companies.

Through the oil refining business, Eni carries out crude oil processing, production, storage and handling of petroleum products in Italy, Germany and the Middle East (through a 20% interest in ADNOC Refining) such as gasoline, diesel fuel, biodiesel, LPG, lubricants made available to the Enilive system or resold on cargo markets.

The Chemical business, through its wholly-owned subsidiary Versalis, operates internationally in the production and marketing of basic and intermediate products, plastics, elastomers and chemicals from renewable sources. The operations are managed through six businesses: intermediates, polyethylene, styrenics, elastomers, biochem, moulding and compounding.

ENILIVE AND REFINING INTEGRATED SYSTEM

Eni is active in the refining and marketing of oil and non-oil products in Italy and abroad and operates through biorefineries and traditional refining plants owned and invested, a network of sale points and an integrated system of warehouses.

PRODUCTION CYCLE OF REFINED PRODUCTS(a)

(a) 2023 figures (million tonnes).

(1) As of January 1, 2023, Enilive SpA, a 100% subsidiary of Eni, has acquired from Eni SpA the assets relating to the biorefining, marketing and distribution of fuels and other petroleum and bio products and mobility services.

ENILIVE

Biorefining

In Italy, Eni has converted the sites of Venice and Gela into modern biorefineries, with a fully operational installed capacity of 1.10 million tonnes/year, able to produce diesel with a lower carbon content, adopting the EcofiningTM proprietary technology. Including the recent acquisition of the Chalmette biorefinery, the total installed capacity amounted to 1.65 million tonnes/year.

Venezia (Porto Marghera): biorefinery started-up in June 2014, at Porto Marghera, with a production capacity of 0.4 mmtonnes/ year. The refinery exploits the proprietary EcofiningTM technology to transform biofeedstock (vegetable oil, waste and residues) into biofuels. Capacity is expected to be increased to 0.6 million tonnes/ year with biojet production (SAF) starting by 2025.

Gela: reached full operation in 2020, thanks to the EcofiningTM technology, developed by Eni, to convert into Hydrotreated Vegetable Oil (HVO) vegetable oil and feedstock from waste and residues, such as used cooking oil and animal fat. The plant properties and a strong supply strategy allow the production of HVO in compliance with the last regulatory constraints in terms of reduction of GHG emissions throughout the whole production chain. In March 2021, started the Biomass Treatment Unit (BTU) to expand the range of charges to be processed by the plant, allowing the replacement of palm oil with more sustainable feedstock.

In addition, as part of the projects aimed at strengthening territorial aggregation, university training and youth entrepreneurship, in January 2024 was defined the contract between the Gela Biorefinery and the Municipality of Gela for the start-up of the Macchitella Lab multipurpose center. The agreement provides for the Gela Biorefinery to grant the Municipality a free concession for the use of the "former Casa Albergo Eni" building for a period of two years, with the possibility of extension. The Municipality will be engaged in the use of the property exclusively for the activities envisaged by the Macchitella Lab Project and to cover the ordinary expenses.

Chalmette: In June 2023, Enilive and PBF Energy Inc. (PBF) finalized the 50-50 joint venture in St. Bernard Renewables LLC (SBR), an operative biorefinery co-located with PBF's Chalmette Refinery in Louisiana (USA). The biorefinery went into operation with a processing capacity of approximately 1.1 million tonnes/year of feedstock, with full pre-treatment capabilities. The plant will mainly produce HVO-diesel using the Ecofining™ process developed by Eni in collaboration with Honeywell UOP.

In January 2024, Enilive signed with LG Chem a joint venture agreement, a further step towards the final investment decision for the project of a new biorefinery in South Korea. The agreement follows the assessment, carried out in September 2023, for the development and management of a new biorefinery at LG Chem's petrochemical site in Daesan, South Korea. The target is to complete the plant by 2026 and to process about 400 ktons of biogenic raw materials using Eni's Ecofiningtm technology to make several products available, including Sustainable Aviation Fuel, HVO-diesel biofuel and bionaphtha.

As part of the decarbonization strategy, in line with the transformation of traditional refineries and the development of new biorefineries, in November 2023, Eni signed an agreement with Saipem, aimed at the study and possible construction of plants for the production of biojet, a sustainable aviation fuel, and HVO-diesel, produced 100% from renewable raw materials.

The volumes of biofuels processed from vegetable oil were 866 mmtonnes up by 59.5% from the previous year (up by 323 ktonnes), benefitting from the Chalmette contribution and from higher volumes processed at the Gela biorefinery.

In 2023 productions of biofuels (HVO) amounted to approximately 635 ktonnes (up by 48% vs. 2022) according to certifications in use (European RED and related directives), thanks to Chalmette contribution.

PRODUCTION CYCLE OF BIOFUELS

Biodiesel produced throughout EcofiningTM has not a maximum threshold for blending such as FAME, therefore it is a component utilized for the formulation of top quality products. In addition, compared to traditional FAME (Fatty Acid Methyl Esters), Biodiesel has:

Higher calorific value
Low solvent characteristic and low water solubility
No low value liquid by-product
Compatibility with automotive materials
Relevant oxydation stability
Performance at low temperature
Sulphur and aromatics/poliaromatics absence

Retail sales in Italy

Eni is a leader in the Italian retail market of refined products with a 21.4% market share, slightly decreased from 2022 (21.7%).

In 2023, retail sales in Italy were 5.32 mmtonnes, substantially in line with the 2022. Average throughput per service station (1,479 kliters) increased by 34 kliters from 2022 (1,445 kliters). As of December 31, 2023, Eni's retail network in Italy consisted of 3,976 service stations, lower by 27 units from December 31, 2022 (4,003 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (-23 units), lower motorway concessions (-3 units) the negative balance of the company owned stations (-1 unit).

RETAIL AND WHOLESALE BUSINESSES IN EUROPE - 2023 ENI'S COMPETITIVE POSITION

Retail sales in the rest of Europe

Retail sales in the Rest of Europe were 2.19 mmtonnes, an increase from 2022 (up by 3.3%) as result of higher volumes sold mainly in Germany and Switzerland, offset by the decrease of the volumes in France.

At December 31, 2023, Eni's retail network in the Rest of Europe

consisted of 1.291 units, increasing by 51 units from December 31, 2022, mainly thanks to the openings in Germany, Spain and France, balanced by the reduction in Austria and Switzerland. Average throughput (2,166 kliters) increased by 138 kliters compared to 2022 (2,027 kliters).

Eni markets fuels on the wholesale market: LPG, naphtha, gasoline, gasoil, jet fuel, lubricants, fuel oil and bitumen. Major customers are resellers, manufacturing industries, service companies, public and local authorities and transporters, as well as final users (transporters, housing facilities, operators in the agricultural and seafood sector, etc.). Eni provides its customers a wide range of products covering all market requirements leveraging on its expertise on fuels' manufacturing. Customer care and product distribution are supported by a widespread commercial and logistical organization presence all over Italy and articulated in local marketing offices and a network of agents and dealers.

Wholesale sales in Italy amounted to 6.45 mmtonnes, increasing by 4.2% from 2022, due to higher sales of jet fuel for the recovery of the aviation sector which offset lower volumes marketed in all the other segments.

Wholesale sales in the Rest of Europe were 1.94 mmtonnes, down by 20.5% from 2022 particularly in Germany, Spain and Austria.

Supplies of feedstock to the petrochemical industry (0.44 mmtonnes) increased by 12.8%. Other sales in Italy and outside Italy (11.14 mmtonnes) increased by 0.39 mmtonnes or up by 3.6% mainly due to lower volumes sold to oil companies.

The marketing of LPG in Italy is supported by the Eni's refining production logistic network made of two bottling plants, a secondary owned depot and coastal storage sites located in Livorno, Naples and Ravenna, to storage imported products.

LPG is used as heating and automotive fuel. In 2023, Eni share of LPG market in Italy was 15%.

Outside Italy, the main market of Eni is Ecuador, with a market share of 36.5%.

Eni operates five (owned and co-owned) blending and filling plants, in Italy, Spain, Germany, Africa and in the Far East.

With a wide range of products composed of over 650 different blends Eni masters international state of the art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, grease, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases, manufactured at Eni's refinery in Livorno.

Eni also owns one facility for the production of additives in Robassomero (Turin). In 2023, Eni's share of lubricants market in Italy was 15.3%, in Europe approximately 2% and on a worldwide base 1%. Eni operates in more than 80 Countries by subsidiaries, licensees and distributors.

Smart mobility

Since 2013, Eni is engaged in the vehicle sharing service with the brand Enjoy, spread out in several Italian cities, developed in partnership with Fiat. The service is based on the "free floating" model, with the pick up and return of the vehicle at any point within the covered service area. The service, including the detection, the booking and the opening of the vehicle and until the end of the rental, is completely managed online through mobile app or the Enjoy website.

Since 2018, the enjoy fleets includes opportunity of renting cargo vehicles (Enjoy Cargo), for the shared transport of "goods". Enjoy is already active through free floating modality in the following cities: Milan, Rome, Turin, Bologna and Florence; starting from November 2023 Enjoy is also active in Padua with Enjoy Point modality, which provides for the activation and the end of the rental at dedicated sale points.

As of December 31, 2023, the Enjoy fleet consisted of 3,213 cars, of which 2,272 hybrid, 580 electric and 34 Cargo vehicles, distributed over the major Italian cities: Milan (1,400 cars and 15 Cargo); Rome (1,085 cars and 11 Cargo); Turin (347 cars); Bologna (193 cars and 8 Cargo); Florence (139 cars), Padova (15 cars). The average number of rentals per month in 2023 including YOYOs amounted to 176,783 rentals/month.

In September, the first ALT Stazione del Gusto service station was inaugurated in Rome, it is the first Enilive restaurant in collaboration with the Niko Romito Academy. Enilive confirms its commitment to continue the process of renewing and expanding the range of services offered in its network of more than 5,000 points of sale in Europe, transforming Eni stations into "mobility points" capable of meeting an increasing number of people's needs on the move. The partnership includes a development plan also through franchising with the aim of reaching 100 openings in the next four years.

Sustainable mobility initiatives

In order to develop and widespread the use of HVOlution diesel, the first Enilive biodiesel produced from 100% renewable raw materials (waste raw materials, vegetable residues and oils generated from crops not competing with the food chain), important agreements with several partners were finalized. In particular:

• in March, as part of the path to decarbonize transport and mobility, Enilive and the Spinelli Group, leader in the integrated logistics sector, signed a two-year contract to supply the fleet of the Spinelli Group with HVOlution. The supply of biofuel to the Spinelli Group is realized leveraging on the network of Enilive stores;

in May, Eni signed an important agreement with RINA, a multinational inspection, certification and engineering consultancy company, in the field of energy transition and decarbonisation of maritime transport: the agreement provides for the involvement of the two companies to develop the use in the naval sector of HVO (Hydrogenated Vegetable Oil) biofuel produced by Eni in the Venice and Gela biorefineries and other energy carriers. In addition, the agreement includes the development of initiatives involving the entire logistics chain of the new energy carriers and the adoption of certified methodologies for the "taxonometric" calculation of the benefits in terms of lower CO² emissions made possible by the new carriers along the entire value chain;
in June, Enilive signed an agreement for the supply and use of HVOlution towards the Azimut-Benetti Group. This is the first agreement relating to the yachting industry aimed at decarbonization of the nautical sector. The Azimut-Benetti Group will introduce HVOlution to replace the fossil-based fuel currently used by the Azimut and Benetti brands for the technical testing of new yachts, for sea trials and for the handling of prototype models.
in line with the development of the decarbonization projects addressed to the aviation segment, Kenya Airways made its first flight with the SAF (Sustainable Aviation Fuel) by Enilive. JetA1 conventional fuel is blended with Eni Biojet produced by the Livorno refinery through the distillation of biocomponents produced in the biorefinery of Gela;
Enilive, through the company Enimoov (formerly Eni Fuel) and the Lannutti Group, a leading operator in the logistics and road transport sector, have signed an agreement for the use of HVOlution. With the 300 trucks of the Italian fleet already powered exclusively by HVO, out of a total fleet of 1,500 vehicles in Europe, the Lannutti Group is present in 8 European countries and actively contributes to the decarbonisation process;
in November 2023, Enilive signed an agreement with Saipem for the study and possible construction of plants for the production of biofuels for aviation and road transport;
Enilive signed a Letter of Intent with Ryanair for a long-term supply of sustainable aviation fuel in some airports in Italy where the airline operates. This agreement will allow Ryanair to access up to 100 ktons of Sustainable Aviation Fuel (SAF) between 2025 and 2030 (equal to 20,000 flights from Milan Malpensa Airport to Dublin).

OIL REFINING

In 2023, Eni refinery capacity (balanced refining capacity) was approximately 26.4 mmtonnes (equal to 528 kbbl/d), with a conversion index of 47%. Eni's 100% owned refineries have a balanced capacity of 18.4 mmtonnes (equal to 368 kbbl/d), with a 45% conversion index. In 2023, Eni's refineries throughputs in Europe were 18.88 mmtonnes, substantially in line compared to 2022.

	Ownership	Balanced refining capacity (Eni's share)(a)	Utilization rate (Eni's share)(a)	Conversion index(b)	Fluid catalytic cracking (FCC)(c)	Residue conversion(c)	Hydrocracking(c)	Visbreaking/ Thermal Cracking(c)
Wholly-owned refineries	(%)	(kbbl/d) 368	(%) 73	(%) 45	(kbbl/d) 38	(kbbl/d) 33	(kbbl/d) 76	(kbbl/d) 0
Italy
Sannazzaro	100	180	87	54	38	8	59	0
Taranto	100	104	66	56		25	17
Livorno	100	84	52	11
Partially-owned refineries		160	86	51	152	28	94	49
Italy
Milazzo	50	100	98	60	50	28	36
Germany
Vohburg/Neustadt (Bayernoil)	20	41	63	36	45		38	14
Schwedt	8	19	75	34	57		20	35
TOTAL		528	77	47	190	61	170	49

REFINING SYSTEM IN 2023

(a) Including 20% share in ADNOC Refining (167 kbl/d), balanced refining capacity amounted to 691 kbl/d. (b) Conversion index: catalytic cracking equivalent capacity/topping capacity (% wt).

Italy

Eni's refining system in Italy is composed by three wholly-owned refineries (Sannazzaro, Livorno and Taranto) and a 50% interest in the Milazzo refinery. Each of Eni's refineries in Italy has operating and strategic features that aim at maximizing the value associated to the asset structure, the geographic location with respect to end markets and the integration with Eni's other activities.

Sannazzaro refinery has a balanced refining capacity of 180 kbbl/d and a conversion index of 54%. Located in the Po Valley, in the center of the North Italy, Sannazzaro is one of the most efficient refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipments in the refinery are: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocracking unit for the conversion of middle distillates (HDC), two reforming units, a visbreaking thermal conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation.

Taranto refinery has a balanced refining capacity of 104 kbbl/d and a conversion index of 56%. Taranto is refinery upstream integrated with the Val d'Agri fields (Eni 61%) and Temparossa in Basilicata through a pipeline. The main equipments are a topping-vacuum unit, a residue hydrocracking and a gasoil hydrocracking unit, a platforming and two desulphurization units.

Livorno refinery, with a balanced refining capacity of 84 kbbl/d and a conversion index of 11%, is dedicated to the production of lubricants and specialties. The refinery is connected by pipeline to a depot in Calenzano (Florence). The refinery has a topping vacuum unit, a platforming unit, two desulphurization units and a de-aromatization unit (DEA) for the production of fuels; a propane de-asphalting (PDA), aromatics extraction and de-waxing units, for the production of base oils; a blending and filling plant for the production of finished lubricants.

In January 2024, confirmed the decision for the construction of a third biorefinery in Italy at the Livorno site, with a capacity of 500 ktons/year. The project, pending the completion of the authorization process, involves the construction of a biogenic pre-treatment unit, an Ecofining™ plant and a plant for the production of hydrogen from methane gas. Completion and start-up are expected by 2026.

Milazzo jointly-owned by Eni and Kuwait Petroleum Italy, has balanced refining capacity of 100 kbbl/d (net to Eni) and a conversion index of 60%. The refinery's activity mainly concerns the export and supply of Italian coastal depots. Located on the Northern coast of Sicily, it is provided with two primary distillation columns and a vacuum unit, two desulphurization units, a fluid catalytic cracker (FCC), one hydrocracking unit for the conversion of middle distillates (HDC), one reforming unit and one unit devoted to the residue treatment process (LCFiner).

Outside Italy

In Germany, Eni owns an interest of 8.33% in the Schwedt refinery (PCK) and 20% in the Vohburg and Neustadt refineries (Bayernoil). Eni's refining capacity in Germany is 60 kbbl/d to supply Eni's distribution network in Bavaria and in the Eastern Germany.

LOGISTICS

Eni is a leading operator in the Italian oil and refined products storage and transportation business. It owns an integrated infrastructure consisting of a network of oil and refined products pipelines and a system of 15 directly managed depots distributed throughout the national territory, and one managed through the subsidiary Petroven, 100% owned since December 2019.

Eni logistic model is organized in four hubs (northern depots, central depots, southern depots and LPG and pipeline). They manage the product flows in order to guarantee high safety, asset integrity and technical standards, as well as cost effectiveness and constant products availability along the Country.

Eni is also part of 7 different logistic joint ventures (Sigemi, Seram, Disma, Seapad, Toscopetrol, Genova Porto Petroli and Costiero Gas Livorno), together with other Italian operators, that operate other localized depots and pipelines.

Furthermore, Eni transports oil and refined products: (i) by sea through spot and long-term contracts of tanker ships; and (ii) through a proprietary pipeline network extending 1,200 kilometers in operation.

Secondary distribution of products is outsourced to independent tanker carriers, selected as market leaders in their own field.

(a) Data on capacity relate to Eni's share of balanced capacity in 2023.

OXYGENATES

Eni's, through its subsidiary Ecofuel (100% Eni's share), sells approximately 0.98 mmtonnes/y of oxygenates, mainly ethers (MTBE/ETBE used as a gasoline octane booster) and alcohols (methanol/ethanol mainly for chemical and fuel use).

About 79% of oxygenates are produced in Eni's plants in Italy (Ravenna), Saudi Arabia (in joint venture with Sabic) and Venezuela (in joint venture with Pequiven) and the remaining 21% is purchased.

PURCHASES

(mmtonnes)	2023	2022	2021	2020	2019	2018
Equity crude oil	4.57	5.02	3.85	3.55	4.24	4.14
Other crude oil	14.51	14.13	15.00	13.82	19.19	18.48
Total crude oil purchases	19.08	19.15	18.85	17.37	23.43	22.62
Purchases of intermediate products	0.21	0.07	0.26	0.11	0.26	0.65
Purchases of products	10.79	10.66	10.66	10.31	11.45	11.55
TOTAL PURCHASES	30.08	29.88	29.77	27.79	35.14	34.82
Consumption for power generation	(0.32)	(0.31)	(0.31)	(0.35)	(0.35)	(0.35)
Other changes(a)	(1.48)	(1.57)	(0.89)	(0.69)	(2.08)	(1.27)
TOTAL AVAILABILITY	28.28	28.00	28.57	26.75	32.71	33.20

(a) Include changes in inventories, transport declines, consumption and losses.

AVAILABILITY OF REFINED PRODUCTS

2023	2022	2021	2020	2019	2018

13.31	13.25	14.01	12.72	17.26	16.78
(1.32)	(1.70)	(1.71)	(1.75)	(1.25)	(1.03)
4.89	4.57	4.21	3.85	4.69	4.93
16.88	16.12	16.51	14.82	20.70	20.68
(1.17)	(1.11)	(1.11)	(0.97)	(1.38)	(1.38)
15.71	15.01	15.40	13.85	19.32	19.30
7.03	7.02	7.38	7.18	7.27	7.50
(0.43)	(0.40)	(0.67)	(0.66)	(0.68)	(0.54)
(0.31)	(0.31)	(0.31)	(0.35)	(0.35)	(0.35)
22.00	21.32	21.80	20.02	25.56	25.91
0.87	0.54	0.67	0.71	0.31	0.25

2.00	2.72	2.27	2.18	2.04	2.55
(0.17)	(0.19)	(0.18)	(0.17)	(0.18)	(0.20)
1.83	2.53	2.09	2.01	1.86	2.35
3.75	3.54	3.41	3.39	4.17	4.12
0.43	0.40	0.67	0.66	0.68	0.54
6.01	6.47	6.17	6.06	6.71	7.01
18.88	18.84	18.78	17.00	22.74	23.23
4.57	5.02	3.86	3.55	4.24	4.14
28.01	27.79	27.97	26.08	32.27	32.92
0.27	0.21	0.60	0.67	0.44	0.28
28.28	28.00	28.57	26.75	32.71	33.20

PRODUCTION AND SALES

(mmtonnes)	2023	2022	2021	2020	2019	2018
PRODUCTS:
Gasoline	5.39	5.36	5.01	3.99	5.80	5.97
Gasoil	7.23	7.29	7.43	6.94	8.81	8.81
Jet fuel/kerosene	1.32	1.25	0.95	0.63	1.53	1.60
Fuel oil	1.23	0.83	1.26	1.61	2.07	2.25
LPG	0.25	0.23	0.30	0.42	0.40	0.42
Lubricants	0.24	0.09	0.38	0.29	0.49	0.59
Petrochemical feedstock	0.75	0.85	0.78	0.67	0.76	0.72
Other	1.13	1.65	1.38	1.32	1.32	1.28
TOTAL PRODUCTS	17.54	17.54	17.49	15.87	21.18	21.64

SALES:

Italy	22.00	21.32	21.80	20.02	25.56	25.91
Gasoline	1.98	1.92	1.72	1.46	1.91	1.90
Gasoil	6.43	6.58	6.49	6.21	7.36	7.28
Jet fuel/kerosene	1.79	1.50	0.92	0.70	1.92	1.98
Fuel oil	0.03	0.04	0.03	0.02	0.06	0.07
LPG	0.47	0.48	0.48	0.45	0.56	0.58
Lubricants	0.06	0.05	0.08	0.08	0.08	0.08
Petrochemical feedstock	0.44	0.39	0.52	0.61	0.83	0.96
Other	10.80	10.36	11.56	10.49	12.84	13.06
Rest of Europe	5.45	5.99	5.68	5.60	6.26	6.56
Gasoline	1.13	1.11	1.06	1.13	1.31	1.30
Gasoil	2.48	2.92	2.78	2.73	3.02	3.16
Jet fuel/kerosene	0.18	0.11	0.07	0.09	0.29	0.33
Fuel oil	0.10	0.13	0.08	0.13	0.09	0.13
LPG	0.05	0.06	0.06	0.05	0.06	0.07
Lubricants	0.02	0.07	0.09	0.08	0.08	0.09
Other	1.49	1.59	1.54	1.39	1.41	1.48
Extra Europe	0.56	0.48	0.49	0.46	0.45	0.45
LPG	0.49	0.47	0.47	0.45	0.44	0.44
Lubricants	0.07	0.01	0.02	0.01	0.01	0.01
WORLDWIDE
GASOLINE	3.11	3.03	2.78	2.59	3.22	3.20
GASOIL	8.91	9.50	9.27	8.94	10.38	10.44
JET FUEL/KEROSENE	1.97	1.61	0.99	0.79	2.21	2.31
FUEL OIL	0.13	0.17	0.11	0.15	0.15	0.20
LPG	1.01	1.01	1.01	0.95	1.06	1.09
LUBRIFICANTS	0.15	0.13	0.19	0.17	0.17	0.18
PETROCHEMICAL FEEDSTOCK	0.44	0.39	0.52	0.61	0.83	0.96
OTHER	12.29	11.95	13.10	11.88	14.25	14.54
TOTAL WORLDWIDE SALES	28.01	27.79	27.97	26.08	32.27	32.92

(mmtonnes)	2023	2022	2021	2020	2019	2018
Retail	5.32	5.38	5.12	4.56	5.81	5.91
Wholesale	6.45	6.19	6.02	5.75	7.68	7.54
	11.77	11.57	11.14	10.31	13.49	13.45
Petrochemicals	0.44	0.39	0.52	0.61	0.83	0.96
Other markets	9.79	9.36	10.14	9.10	11.24	11.50
Sales in Italy	22.00	21.32	21.80	20.02	25.56	25.91
Retail rest of Europe	2.19	2.12	2.11	2.05	2.44	2.48
Wholesale rest of Europe	1.94	2.44	2.19	2.40	2.63	2.82
Wholesale outside Europe	0.53	0.52	0.52	0.48	0.48	0.47
Retail and wholesale outside Italy	4.66	5.08	4.82	4.93	5.55	5.77
Other markets	1.35	1.39	1.35	1.13	1.16	1.24
Sales outside Italy	6.01	6.47	6.17	6.06	6.71	7.01
TOTAL SALES	28.01	27.79	27.97	26.08	32.27	32.92

SALES BY PRODUCT/MARKET

(mmtonnes)	2023	2022	2021	2020	2019	2018
ITALY	11.77	11.57	11.14	10.31	13.49	13.45
Retail sales	5.32	5.38	5.12	4.56	5.81	5.91
Gasoline	1.55	1.49	1.38	1.16	1.44	1.46
Gasoil	3.41	3.54	3.38	3.10	3.95	4.03
LPG	0.31	0.32	0.31	0.27	0.38	0.38
Other products	0.05	0.03	0.05	0.03	0.04	0.04
Wholesale sales	6.45	6.19	6.02	5.75	7.68	7.54
Gasoil	3.02	3.04	3.11	3.11	3.41	3.25
Fuel oil	0.03	0.04	0.03	0.02	0.06	0.07
LPG	0.15	0.16	0.17	0.18	0.18	0.20
Gasoline	0.43	0.43	0.34	0.30	0.47	0.44
Lubricants	0.05	0.05	0.08	0.08	0.08	0.08
Bunker	0.45	0.48	0.59	0.63	0.77	0.80
Jet fuel	1.79	1.50	0.92	0.70	1.92	1.98
Other products	0.53	0.49	0.78	0.73	0.79	0.72
OUTSIDE ITALY (RETAIL + WHOLESALE)	4.66	5.08	4.82	4.93	5.55	5.77
Gasoline	1.13	1.11	1.06	1.13	1.31	1.30
Gasoil	2.48	2.92	2.78	2.73	3.02	3.16
Jet fuel	0.18	0.11	0.07	0.09	0.29	0.33
Fuel oil	0.10	0.13	0.08	0.13	0.09	0.14
Lubricants	0.09	0.08	0.11	0.09	0.09	0.09
LPG	0.54	0.53	0.53	0.50	0.50	0.50
Other products	0.14	0.20	0.19	0.26	0.25	0.25
TOTAL RETAIL AND WHOLESALE SALES	16.43	16.65	15.96	15.24	19.04	19.22

SERVICE STATIONS

(units)	2023	2022	2021	2020	2019	2018
Italy	3,976	4,003	4,078	4,134	4,184	4,223
Ordinary stations	3,868	3,892	3,967	4,019	4,068	4,108
Highway stations	108	111	111	115	116	115
Outside Italy	1,291	1,240	1,236	1,235	1,227	1,225
Germany	527	486	480	480	476	471
France	157	153	155	158	155	155
Austria/Switzerland	590	592	592	597	596	599
Spain	17	9	9
Service stations selling premium products	4,869	4,848	4,872	4,619	4,669	4,675
Service stations selling LNG	17	19	15	4	4	4
Service stations selling LPG and natural gas	1,468	1,348	1,111	1,091	1,086	1,043
Non-oil sales (€ million)	185	177	160	148	156	144

MARKET SHARES IN ITALY

(%)	2023	2022	2021	2020	2019	2018
Retail	21.4	21.7	22.2	23.2	23.6	24.0
Gasoline	19.0	19.0	19.6	20.2	19.8	20.2
Gasoil	22.7	23.2	23.5	24.9	25.4	25.7
LPG (automotive)	20.8	20.9	22.0	20.7	22.9	23.6
Wholesale	22.5	21.5	21.8	23.4	25.0	24.8
Gasoil	22.2	21.3	21.5	24.4	23.6	22.3
Fuel oil	7.7	7.9	7.2	4.9	10.9	12.8
Bunker	16.8	17.0	19.9	21.3	24.3	24.9
Lubricants	12.0	11.1	18.9	21.2	20.0	18.8

RETAIL MARKET SHARES OUTSIDE ITALY

(%)	2023	2022	2021	2020	2019	2018
Central Europe
Austria	12.2	12.0	11.4	12.4	12.3	12.3
Switzerland	6.5	6.2	6.7	6.7	7.7	7.8
Germany	3.2	2.9	3.0	3.1	3.2	3.2
France	0.7	0.7	0.7	0.7	0.6	0.8

(€ million)	2023	2022	2021	2020	2019	2018
Italy	695	538	470	535	743	661
Outside Italy	100	85	68	53	72	65
TOTAL	795	623	538	588	815	726
Refining, supply and logistic	621	491	390	462	683	587
Italy	597	469	375	449	662	578
Outside Italy	24	22	15	13	21	9
Marketing	174	132	148	126	132	139
Italy	98	69	95	86	81	83
Outside Italy	76	63	53	40	51	56
TOTAL	795	623	538	588	815	726

CHEMICALS

Eni through Versalis engages in the production and marketing of petrochemical products, basic petrochemicals, intermediates, polyethylene, styrenics and elastomers, leveraging on a wide range of patents (424), 26 production sites, 9 research centers (Brindisi, Ferrara, Mantua, Novara, Ravenna, Rivalta, Porto Torres, Terni and Piana di Monte Verna), as well as a large and efficient retail network located in 36 different Countries. In 2023, for the second consecutive year, Versalis, Eni's chemical company, obtained the "Platinum" rating from EcoVadis, placing it in the TOP 1% of the sector, at the highest level of the rating for corporate social responsibility.

THE PRODUCTIVE CYCLE

The materials produced by Versalis are obtained following a manufacturing cycle which involves several processing stages. Virgin naphtha, a raw material which is a distillation product from petroleum, undergoes thermal cracking also known as steam-cracking. The component molecules split into simpler molecules: monomers (ethylene, propylene, butadiene, etc.) and into blends of aromatic compounds. These are then reconstituted into more complex molecules: the polymers. The following are produced from polymers: polyethylene, styrenes and elastomers used by processing companies to produce a whole variety of products for everyday use.

In line with the transition path towards a circular economy, Versalis finalized a collaboration with Technip Energies to integrate the Versalis' Hoop® technology with the purification Pure.rOilTM and Pure.rGasTM technologies developed by T.EN, for the advanced chemical recycling of plastic waste, contributing significantly to the reduction of the total carbon footprint in the polymer value chain. This technological platform allow to realize an endless plastic recycling process, producing new virgin polymers suitable for all applications and identical to polymers from fossil raw materials.

In addition, in the Mantua plant, started the construction of the demo plant of Hoop®, the proprietary technology for the chemical recycling of mixed plastic waste. This technology is the result of a joint project with the Italian engineering company S.R.S. (Servizi di Ricerche e Sviluppo). The demonstration plant of the technology Hoop® in Mantua will have the ability to handle 6 ktons of second raw material, and is expected to be started at the end of 2024.

Finalized a partnership with the Flo Group that will allow to take advantage of a new recycling system: R-Hybrid, the first automatic distribution glass made with post-consumer recycled polystyrene. This is an important innovation in the field of food packaging. The project was developed with SCS (Styrenics Circular Solution), an European association that includes the entire styrene polymer supply chain, from raw material producers to post-consumer recyclers, and in collaboration with the Fraunhofer Institute, a leading applied research center in Europe.

As part of the projects aimed at developing products from renewable raw materials for boating, a collaboration with the Boero Group has been launched for the development of products for the marine market made with renewable raw materials.

In order to accelerate Versalis' strategy to develop chemistry from renewable sources, finalized the purchase of 64% interest in Novamont owned by the shareholder Mater-Bi, acquiring a whole control. Novamont, a company active abroad, based in Germany, France, Spain and the United States, owns a network of distributors in over 40 countries worldwide and is a world leader in the production of bioplastics and in the development of biochemical and bioproducts through the integration of chemistry, environment and agriculture.

(a) Versalis International manages the activities of the commercial branches (France, UK, Germany, Switzerland, Austria, Hungary, Romania, Poland, Czech Rep., Slovakia, Russia, Sweden, Spain, Greece, Angola and Mozambico), coordinates the companies in Turkey, America (United States and Mexico), Africa (Congo and Ghana), Asia (China and Singapore) and the joint venture in Abu Dhabi and delivers services to manufacturing companies in France, Germany, Hungary and UK.

Business areas

Sales of chemical products amounted to 3,117 ktonnes, decreased from 2022 (down by 635 ktonnes, or 16.9%), in particular, the main reductions were recorded in olefins (down by 26.3%), derivatives (down by 19.4%), aromatics (down by 17.9%) and styrenic (down by 12.0%). In the moulding & compounding business, sales amounted to 67 ktons, down by 11.8% from the comparative period.

Average sale prices of the intermediates business decreased by 17.4% from 2022, with olefins and aromatics down by 19.2% and 15.4%, respectively. The polymers reported a decrease of 25.9% from 2022. Chemical production of 5,663 ktonnes decreased from 2022 (down by 1,193 ktonnes vs. 2022) due to lower production of intermediates business (down by 1,020 ktonnes), in particular aromatics and derivatives. The main reductions were registered at Mantua site (down by 220 ktonnes), Dunkerque (down by 185 ktonnes) and Priolo (down by 162 ktonnes).

Plants nominal capacity decreased from the 2022. The average plant utilization rate, calculated on nominal capacity, was 51.4% (59.0% in 2022).

Intermediates

Intermediates revenues (€1,497 million) decreased by €871 million from 2022 (down by 36.8%), following also the decrease reported in sales volumes (1,651 ktonnes, down by 23.5% vs. 2022). The main reductions were registered in olefins (down by 26.3%) and in aromatics (down by 17.9%). Average prices decreased by 17.4%, in particular olefins (down by 19.2%), aromatics (down by 15.4%) and derivatives (down by 14.1%). Intermediates production (3,877 ktonnes) registered a decrease of 20.8% from 2022. Decreases were also registered in olefins (down by 20.1%), in the aromatics (down by 23.0%) and in derivatives (down by 21.6%).

Polymers

Polymers revenues (€2,152 million) decreased by €1,051 million or 32.8% from 2022 due to lower sales volumes (down by 144 ktonnes) and the decrease of the average unit prices (down 25.9%).

The sold volumes of polyethylene business reported a decrease (down by 6.7%) due to lower sales of EVA (down by 18.1%), LDPE (down by 10.6%), and HDPE (down by 1.3%), mainly in the elastomers (down by 13.9%) and styrenics (down by 12%). In addition, average sale prices decreased by 30.5%.

In the elastomers business, were registered lower sales of BR (down by 23.4%), NBR rubbers (down by 16.8%) and SBR (down by 6.1%). Average unit prices decreased by 18.9%. The decrease in sales volumes of styrenic was due to lower demand, which negatively affected GPPS sales (down by 15.7%) and HIPS sales (down by 15.1%). Polymers productions (1,658 ktonnes) decreased by 11.5% from the 2022 due to the lower productions of polyethylene (down by 4.6%), elastomers (down by 16.2%) and styrenics (down by 16.0%).

Oilfield chemicals, Biochem and Moulding & Compounding

Oilfiled chemicals revenues increased by 16.9% (up by €14 million compared to 2022) as a result of the increased unit price (up by 14.6%). Biochem business revenues (€83 million) increased significantly from 2022 (€25 million), thanks to the inclusion of Novamont Group in the consolidation area starting from October 1st, 2023. Moulding & Compounding business revenues decreased by €51 million from 2022 (down by 15.6%) due to lower sales volumes (down by 11.8%).

PRODUCT AVAILABILITY

(ktonnes)	2023	2022	2021	2020	2019	2018
Intermediates	3,877	4,897	6,284	5,861	5,818	7,130
Polymers	1,658	1,873	2,184	2,211	2,250	2,353
Biochem	57	5	8	1
Moulding & Compounding	71	81	20
PRODUCTIONS	5,663	6,856	8,496	8,073	8,068	9,483
Consumption and losses	(3,247)	(3,923)	(4,590)	(4,366)	(4,307)	(5,085)
Purchases and change in inventories	701	819	565	632	534	548
TOTAL AVAILABILITY	3,117	3,752	4,471	4,339	4,295	4,946
Intermediates	1,651	2,158	2,648	2,539	2,519	3,095
Polymers	1,350	1,494	1,771	1,790	1,766	1,851
Oilfield chemicals	21	21	24	9	10
Biochem	28	3	8	1
Moulding & Compounding	67	76	20
TOTAL SALES	3,117	3,752	4,471	4,339	4,295	4,946

	2023	2022	2021	2020	2019	2018
Italy	2,051	2,999	2,678	1,588	1,986	2,292
Rest of Europe	1,792	2,694	2,415	1,434	1,758	2,183
Asia	149	235	300	232	226	481
Americas	146	180	123	89	95	109
Africa	96	104	72	44	58	58
Other areas	2	3	2
	4,236	6,215	5,590	3,387	4,123	5,123

REVENUES BY PRODUCT

(€ million)	2023	2022	2021	2020	2019	2018
Olefins	879	1,478	1,445	879	1,168	1,667
Aromatics	307	442	355	191	293	340
Derivatives	311	448	366	259	279	365
Oilfield chemicals	97	83	65	56	51	29
Elastomers	570	816	736	452	567	665
Styrenics	630	919	831	534	611	749
Polyetilene	952	1,468	1,547	902	1,022	1,175
Biochem	83	25	60	6
Moulding & Compounding	276	327	70
Other	131	209	115	108	132	133
	4,236	6,215	5,590	3,387	4,123	5,123

CAPITAL EXPENDITURE

(€ million)	2023	2022	2021	2020	2019	2018
	187	255	190	182	118	151
of which:
- upkeeping	28	115	56	79	42	21
- plant upgrades and efficecny	46	22	23	35	34	84
- HSE and asset integrity	73	90	76	39	27	26
- decarbonization	4	4	21	13	4	8
- green & circular	30	20	4	7	4
- other	6	5	10	9	7	12

Plenitude & Power

KEY PERFORMANCE INDICATORS

		2023	2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)(a)	(total recordable injuries/worked hours) x 1,000,000	0.83	0.31	0.29	0.32	0.62	0.60
of which: employees		0.21	0.26	0.49	0.00	0.30	0.31
contractors		1.96	0.39	0.00	0.73	0.95	1.16
Sales from operations(b)	(€ million)	14,256	20,883	11,187	7,536	8,448	8,218
Operating profit (loss)		(464)	(825)	2,355	660	74	340
Adjusted operating profit (loss)		681	615	476	465	370	262
- Plenitude		515	345	363	304	256	178
- Power		166	270	113	161	114	84
Adjusted net profit (loss)		414	397	327	329	275	189
Capital expenditure		740	631	443	293	357	238
Plenitude
Retail gas sales	(bcm)	6.06	6.84	7.85	7.68	8.62	9.13
Retail power sales to end customers	(TWh)	17.98	18.77	16.49	12.49	10.92	8.39
Retail/business customers	(million of POD)	10.11	10.07	10.04	9.70	9.42	9.19
EV charging points(c)	(thousand)	19.0	13.1	6.2	3.4	n.d	n.d
Energy production from renewable sources	(TWh)	3.98	2. 55	0.99	0.34	0.06	0.01
Installed capacity from renewables at period end	(GW)	3.0	2.2	1.1	0.3	0.2	0.0
Power
Power sales in the open market	(TWh)	19.88	22.37	28.54	25.34	28.28	28.54
Thermoelectric production		20.66	21.37	22.31	20.95	21.66	21.62
Employees at year end		3,018	2,794	2,464	2,092	2,056	2,056
of which: outside Italy		788	698	600	413	358	337
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	9.36	9.76	10.03	9.63	10.22	10.47
Direct GHG emissions (Scope 1)/equivalent generated electricity (Enipower)(a)	(gCO2 eq./kWh eq.)	389	393	380	391	394	402

(a) Calculated on 100% operated assets.

(b) Before elimination of intragroup sales.

The Plenitude & Power segment engages in the activities of marketing of gas, power and services for end customers, in the production and marketing, including wholesale, of power produced by both thermoelectric plants and from renewable sources, as well as in the electric mobility business. It also includes trading activities of CO² emission certificates and forward sale of power with a view to hedging/optimizing the margins.

Country of presence	GW(a)	Retail + Business customers (mln)	EV charging points	Installed capacity of power stations (GW)(b)
Italy	~1.0	8.2	18,393	2.2
France	~0.1	1.0	171
Iberian peninsula	~1.4	0.3
USA	~1.5				Photovoltaic
UK	~0.5				Onshore Wind
Other	~0.2	0.6	426		Offshore Wind
TOTAL	~3	10.1	~19,000	2.2	Storage

(a) Data as of December 31, 2023 (installed or under construction assets).

(b) Power stations with CCGT technology and a heating district station.

PLENITUDE

Eni, through Plenitude, is active in the marketing of gas, power and services for retail and business customers, in the production and generation of electricity from renewables, as well as in the electric mobility business.

Retail Gas & Power

Plenitude operates, directly or through subsidiaries, in the marketing of gas, power and services in Italy, France, Greece, the Iberian Peninsula and Slovenia (where, through its subsidiary Adriaplin, it also operates in the natural gas distribution sector). Plenitude also offers to retail and business customers extra-commodity services in energy efficiency, expanding its commercial offer with integrated, innovative and high value added solutions, mainly focused on the segment of small and medium-sized enterprises and on the housing facilities.

Eni operates in a liberalized energy market, where customers are allowed to choose the gas supplier and, according to their specific needs, to evaluate the quality of services and select the most suitable offers.

Overall, Eni supplies 10.1 million of retail clients (gas and electricity) in Italy and Europe. In particular, clients located all over Italy are 8.2 million.

GAS SALES BY MARKET

(bcm)	2023	2022	2021	2020	2019	2018
ITALY	4.11	4.65	5.14	5.17	5.49	5.83
Retail	2.91	3.34	3.88	3.96	3.99	4.20
Business	1.20	1.31	1.26	1.21	1.50	1.63
INTERNATIONAL SALES	1.95	2.19	2.71	2.51	3.13	3.30
European markets
France	1.54	1.69	2.17	2.08	2.69	2.94
Greece	0.26	0.33	0.39	0.34	0.35	0.24
Other	0.15	0.17	0.15	0.09	0.09	0.12
RETAIL GAS SALES	6.06	6.84	7.85	7.68	8.62	9.13

(mln of POD) 2019 2020 ~9.6 9.7 2021 10.0 2022 10.1 2023 10.1

GAS AND POWER RETAIL AND BUSINESS CUSTOMERS

Retail gas sales

In 2023, retail gas sales in Italy and in the rest of Europe amounted to 6.06 bcm, down by 0.78 bcm or 11.4% from the previous year. Sales in Italy amounted to 4.11 bcm down by 11.6% from 2022, as a result of lower sales to the retail segment. Sales on the European markets of 1.95 bcm decreased by 11% (down by 0.24 bcm) compared to 2022. Lower sales were recorded in France and Greece.

Retail Power sales to end customers

In 2023, retail power sales to end customers amounted to 17.98 TWh, managed by Plenitude and the subsidiaries in France, Greece and Spain decreased by 4.2% from 2022, due to the negative impact of exceptionally mild weather conditions and lower consumption abroad, partly offset by increased sales in Italy (+4%).

Renewables

Eni is engaged in the renewable energy business (solar, wind and storage) aiming at developing, constructing and managing renewable energy producing plant. Eni's targets in this field will be reached by leveraging on an organic development of a diversified and balanced portfolio of assets, integrated with selective asset and projects acquisitions as well as national and international strategic partnerships.

Portfolio developments and significant agreements

In December 2023, Eni announced an agreement for an institutional investor to enter the capital of Plenitude, giving visibility to the value of this business estimated at around €10 billion with the aim of strengthening Eni's consolidated financial structure through access to incremental financial means to support growth plans.

The agreement finalized in March 2024 by Plenitude and Energy Infrastructure Partners (EIP) includes the entry of EIP into Plenitude's share capital through a capital increase of €0.6 billion or 7.6% of the Company's share capital.

As a part of the development of the wind and photovoltaic sector, representing a pillar of Eni's growth strategy, in 2023 continued the expansion in the national and international renewable energy market through the signing of a series of significant agreements. In particular, regarding the wind sector:

GreenIT, the joint venture between Plenitude and CDP Equity signed, in March 2023, an agreement with Copenhagen Infrastructure Partners (CIP) to develop three floating offshore wind farms in Italy (Lazio and Sardinia). The plants will be located about 30 km off the coast, with a total capacity of nearly 2 GW. The agreement includes the development of a wind park off Civitavecchia, with an overall capacity up to 540 MW, and other two plants off Olbia (Sardinia) with a capacity of around 500 MW and 100 MW. The three projects are expected to generate about 5 TWh/year and will be operational between 2028 and 2031, once the permitting process and subsequent construction phase are completed;
Vårgrønn, a joint venture between Plenitude and HitecVision, finalized in July 2023 an agreement with the Irish integrated energy services company Energia Group for the joint development of two offshore wind projects in Ireland, with a total capacity of up to 1.8 GW by 2030. The development of these two plants, located in the Northern Celtic Sea and Southern Irish Sea, respectively, with an installed capacity of up to 900 MW each, allows Plenitude to extend its activities to the Irish offshore wind market through Vårgrønn;
Plenitude has signed an agreement to develop offshore wind projects in Spain through joining the strategic partnership with BlueFloat Energy and Sener Renewable Investments, among the industry leaders in the country with a portfolio of approximately 1.25 GW of floating offshore wind projects in Galicia (Parque Nordés), Catalonia (Parc Tramuntana) and the Canary Islands (Parque Tarahal).

In the photovoltaic sector, the main developments included:

the finalization of the acquisition from Helios UK (Spain) Ltd of a portfolio of two operational photovoltaic plants with a total capacity of 96.4 MW in the Albacete region of Spain in June 2023;
the acquisition from Plenium Partners S.L. of seven photovoltaic projects portfolio in Spain, that have reached the ready-to-build stage;
in July 2023, the GreenIT agreement with Hive Energy Limited and Sun Leonard Energy Limited to develop four photovoltaic projects

GAS SALES IN ITALY (bmc)

the GreenIT agreement with Galileo, a pan-European platform for development and investment in the renewable energy sector, to build eight photovoltaic projects in three regions of Southern, Central and Northern Italy, with a total capacity of about 140 MW;
the Energy Performance Contract (EPC) agreement with Dellorto, for the construction of a 1.35 MW photovoltaic plant in Cabiate (CO). The solar energy will help to supply the Dellorto plant and improve energy efficiency, avoiding CO² emissions of an expected amount of about 603 ton/year;
the agreement with Volvo Trucks Italia for the installation of 5 new photovoltaic systems that will contribute to power the Volvo Truck Center dealers in Northern Italy with renewable energy. The project will have a production capacity of 550,000 kWh/ year and will allow Volvo Trucks Italia to improve the energy efficiency of its sites;
the agreement with Saipem for the installation at Saipem's Fano site of a photovoltaic plant of about 1 MW. It is estimated that the solar power generation for the plant will be more than 1,000 MWh annually, which will help to meet almost the entire energy needs of the Saipem headquarters by improving its energy efficiency in a view of greater sustainability.

Furthermore, Plenitude, as part of the development of innovative technology solutions, during 2023, in order to support the energy transition process, invested in the joint project with KazMunayGas (KMG) for a 250 MW renewable-gas hybrid power plant in Zhanaozen, Mangystau region. The project, the first of its kind in the Country, includes a solar power plant, a wind power plant, and a gas power plant to generate and supply stable low carbon electricity to KMG's branches in the area.

Finally, on December 30, 2023, Plenitude, through its subsidiary Eni New Energy US Inc. signed an agreement with the leading global energy company EDP Renováveis, S.A. (EDPR) to acquire 80% of three already operational photovoltaic plants located in the United States. In particular, the parks Cattlemen (Texas) and Timber Roade and Blue Harvest (Ohio), which have a total installed capacity of approximately 0,48 GW, including 0,38 GW in Plenitude share. The plants are located over an area of 1,500 hectares and will generate energy over 800 MWh/year from renewable sources.

Developments in the renewable business

In line with the strategy of energy transition and decarbonization of products and processes, during 2023 Plenitude inaugurated:

in June, the first utility-scale battery plant, built in Assemini (Cagliari, Italy), with an installed capacity of 14 MW and an energy storage capacity of 9 MWh, built with battery modules based on lithium iron phosphate (LFP) technology. The plant represents one of the first large-scale storage systems connected to Italy's National Transmission Grid, enabling an increasing penetration of renewable energy into the Italian energy mix. In the industrial area of Assemini, Plenitude owns a 23 MW photovoltaic plant in operation, with which the storage system will share some connection infrastructure, and is evaluating other renewable generation projects;
in September, the first photovoltaic plant built in the Republic of Kazakhstan, at the Shaulder site, with a capacity of 50 MW. The photovoltaic plant, which will be able to produce up to about 90 GWh of energy per year, covers an area of 100 hectares and is equipped with more than 93,000 solar panels and a power substation connected to the local grid through a new 7.5-kilometer overhead electric transmission line;
in October, Dogger Bank, the world's largest offshore wind farm participated by Vårgrønn with a 20% share, has started power generation, transmitted to the UK national grid.

In February 2024, the plant at the Ravenna Ponticelle hub, with a capacity of installed capacity of 6 MW spread over an industrial area of 11 hectares and consists of over 10,000 photovoltaic panels. The new photovoltaic park is part of the recovery initiative of an abandoned industrial area of 26 hectares, completely reclaimed and owned by Eni Rewind.

Technology development

In May 2023, Plenitude signed a strategic partnership with Kraken Technologies (Octopus Energy Group) to support the growth of retail business outside Italy, abroad, which will progressively adopt Kraken's technology platform in France, Greece, Slovenia, Spain and Portugal (in these countries customers amounted to approximately 2 million). Plenitude will replace the current set of solutions for management and invoicing of retail customers with a single, technologically advanced cloud platform, simplifying processes and making the management of their retail activities more efficient. In addition, the adoption of Kraken will help the business scalability and enhance the development of innovative solutions.

In December 2023, Plenitude launched "Zurich Sole Protetto", the first parametric insurance policy for domestic photovoltaic systems in Italy offered free of charge to Plenitude customers who choose to purchase a photovoltaic system for domestic use by March 31, 2024. The policy, active for 3 years, will indemnify customers in the event that the system should benefit from lower than expected solar radiation and is based on an algorithm that considers both the data of the photovoltaic system and the historical weather data (starting from January 2005) of the specific location.

SOLAR AND WIND POWER INSTALLED CAPACITY AS OF DECEMBER 31, 2023

ENERGY PRODUCTION FROM RENEWABLE SOURCES

(TWh)	2023	2022	2021	2020	2019	2018
Energy production from renewable sources	3.98	2.55	0.99	0.34	0.06	0.01
of which: photovoltaic(a)	1.74	1.13	0.40	0.22	0.06	0.01
wind	2.24	1.42	0.59	0.12	0.00	0.00
of which: Italy	1.53	0.82	0.40	0.11	0.05	0.01
outside Italy	2.45	1.73	0.59	0.23	0.01	0.00

(a) It includes biogas generation.

Energy production from renewable sources amounted to 3.98 TWH (of which 1.74 TWh photovoltaic and 2.24 TWh wind) up by 1.43 TWh compared to 2022. The increase in production, compared to the previous year, benefitted from the entry in operations of new capacity, mainly for the contribution of assets already operating in Italy, Spain and United States, as well as from the organic development of projects in Italy, in the United States and in Kazakhstan.

Follows breakdown of the installed capacity by Country and technology:

INSTALLED CAPACITY FROM RENEWABLES AT PERIOD END (ENI'S SHARE)

	2023	2022	2021	2020	2019	2018
Installed capacity from renewables at period end	3.0	2.2	1.1	0.3	0.2	0.0
of which: photovoltaic (including installed storage capacity)	64%	54%	49%	80%	80%	100%
wind	36%	46%	51%	20%	20%

(gigawatt)	2023	2022	2021	2020	2019	2018
Italy	1.0	0.8	0.5	0.1	0.1	0
Outside Italy	2.0	1.4	0.7	0.2	0.1	0
United States	1.3	0.8	0.3	0.1
Spain	0.4	0.3	0.1
Others (Australia, Francia, Pakistan, Kazakhstan, UK)	0.3	0.3	0.3	0.1	0.1
TOTAL INSTALLED CAPACITY AT PERIOD END (INCLUDING INSTALLED STORAGE POWER)(a)	3.0	2.2	1.1	0.3	0.2	0

(a) Installed storage capacity amounted to a 21 MW, 7 MW, 7 MW, 8MW, 7 MW, in 2023, 2022, 2021, 2020 and 2019 respectively.

As of December 31, 2023, the total installed capacity from renewables amounted to 3 GW, an increase of 0.8 GW from 2022, mainly thanks to the acquisition of assets in Spain (Bonete) and United States (Kellam), to the organic development of projects in Italy, Spain and Kazakhstan, as well as from the acquisition of 3 photovoltaic plants in the United States with a total capacity of about 0.4 GW, defined at the end of 2023.

Italy

As of December 31, 2023, the total installed capacity amounted to approximately 1 GW in Italy. Eni's commitment in the country progressed during the year with the organic development of photovoltaic and wind projects and the storage system at the Assemini site in Sardinia.

Outside Italy

United States

As of December 31, 2023, the total installed capacity in the United States amounted to 1.3 GW, an increase of 0.5 GW compared to 2022, mainly due to the acquisition of the Kellam Plant and three additional photovoltaic plants located in Texas and Ohio.

Spain and France

As of December 31, 2023, the installed capacity in Spain and France amounted to 0.6 GW, an increase of approximately 0.2 GW compared to the end of 2022, thanks in particular to the acquisition of the Bonete assets and the organic development of the Villanueva photovoltaic plant and the Numancia wind power plant in Spain.

United Kingdom

In the United Kingdom, Eni is engaged in the development of significant offshore wind projects through the joint venture Vårgrønn (65% Plenitude, 35% HitecVision) which holds a 20% stake in the Dogger Bank projects. The three phases of the project (Dogger Bank A, B and C) include the construction of a total installed capacity of 3.6 GW (approximately 0.5 GW net of Plenitude) with turbines installed off the British coast. In October 2023, Dogger Bank started the power production transmitted to the UK's national grid.

Kazakhstan

With the construction of two 48 MW wind farms in the Badamsha area, and a 50 MW photovoltaic plant at the Shaulder site in the southern region of the country, Eni owns a total capacity in Kazakhstan of 146 MW.

Australia

In the Australian Northern Territory, Eni owns 3 photovoltaic plants (Katherine 34 MW, Bachelor and Manton Dam 25 MW each), and a storage system (6 MW) for a total capacity of 64 MW in the country.

Electric Mobility

In a context of the mobility market that includes a constant increase in the number of electric vehicles in circulation in Italy and in Europe, Plenitude, thanks to the acquisition of Be Charge, disposes of a widespread networks of public charging infrastructure for electric vehicles, and represents the first operator in Italy for public access sites at high power >100 kW.

As of December 31, 2023, there are about 19,000 charging points distributed throughout the country. These stations are smart and user-friendly, monitored 24 hours a day by a help desk and accessible via the mobile app. Within the sector chain, Be Charge plays both the role of owner and manager of the charging infrastructure network (CSO - Charge Station Owner and CPO - Charge Point Operator), and the role of charging and electric mobility service provider working directly with electric vehicle users (EMSP - Electric Mobility Service Provider). Be Charge charging stations are Quick (up to 22 kW) alternating current, Fast (up to 150 kW) or HyperCharge (above 150 kW) direct current type.

In 2023, Plenitude, through its subsidiary Be Charge, continued to expand its collaborations with the main players in the mobility sector, in order to develop electric charging infrastructures and solutions, in particular agreements were signed with:

BMW Italia, Porsche Italia and LeasePlan to develop new offers for electric charging, also in fast and ultrafast mode and for the identification of areas in which to install new charging hubs;
Energica Inside, a business unit of Energica Motor Company, to extend electric mobility to nautical segment through an innovative joint project, including the installation of charging stations in Italian ports and the offering of new possibilities of travel even on the water;
IKEA, for the installation of the innovative 250 charging stations in the parking areas of IKEA stores and shopping malls in Italy;
ACEA Energia and ACEA Innovation, subsidiaries of ACEA, which provides interoperable access to charging services for electric vehicles offered by the network of both companies throughout the national territory.

In addition, in May 2023, with the aim of fostering the development of infrastructure dedicated to electric mobility and accelerating the energy transition, the European Commission and Cassa Depositi e Prestiti, in recognition of its commitment to the electric mobility sector, allocated more than €100 million to Be Charge to build one of the largest high-speed charging networks in Europe by 2025.

In detail, CDP, as a national promotional institution, has granted a loan of €50 million in addition to another €50.4 million in nonrepayable grants allocated by the European Commission for the construction of a network of over 2,000 "ultra-fast" charging points, with a minimum power of 150 kW along the main European transport corridors of eight countries: Italy, Spain, France, Austria, Germany, Portugal, Slovenia and Greece.

renewable energy and electric vehicle charging stations. Red Bull will benefit from certified energy, through guarantees of European origin, produced by plants powered by 100% renewable sources.

POWER

Availability of electricity

Eni's power generation sites are located in Brindisi, Ferrera Erbognone, Ravenna, Mantova, Ferrara and Bolgiano. As of December 31, 2023, installed operational capacity of Enipower's power plants was 2.2 GW.

In 2023, thermoelectric power generation was 20.66 TWh, decreasing by 0.71 TWh from the previous year. Electricity trading (6.64 TWh) reported a decrease of 30% from 2022, in order to optimize inflows and outflows of power.

POWER GENERATION

	2023	2022	2021	2020	2019	2018
Purchases
Natural gas (mmcm)	4,144	4,218	4,670	4,346	4,410	4,300
Other fuels (ktep)	156	175	93	160	276	356
of which: steam cracking	85	86	68	88	91	94
Production
Power generation (TWh)	20.66	21.37	22.31	20.95	21.66	21.62
Steam (ktonnes)	6,981	6,900	7,362	7,591	7,646	7,919

Installed generation capacity (GW)	2.2	2.3	4.5	4.5	4.5	4.5

Power sales in the open market

In 2023, power sales in the open market were 19.88 TWh, representing a decrease of 11.1% compared to 2022, due to lower volumes marketed at Power Exchange.

POWER SALES

(TWh)	2023	2022	2021	2020	2019	2018
Power generation	20.66	21.37	22.31	20.95	21.66	21.62
Trading of electricity(a)	6.64	9.49	11.62	13.04	15.55	14.49
Availability	27.30	30.86	33.93	33.99	37.21	36.11
Power sales in the open market	19.88	22.37	28.54	25.34	28.28	28.54
Power sales to Plenitude	7.42	8.49	5.39	8.65	8.93	7.57

(a) Includes positive and negative imbalances (difference between the electricity effectively fed-in and as scheduled).

ENIPOWER PLANTS AND SITES IN ITALY

Installed capacity as of December 31, 2023: 2.2 GW (Eni's share).

The combined cycle gas fired technology (CCGT) ensures an high level of efficiency and low environmental impact.

District heating station

Combined cycle - CCGT

Power stations	Installed capacity as of December 31, 2023(a) (MW)	Effective/planned start-up	Technology	Fuel
Brindisi	647	2006	CCGT	Gas
Ferrera Erbognone	536	2004	CCGT	Gas/syngas
Mantova	375	2005	CCGT	Gas
Ravenna	433	2004-2023	CCGT/Peaker	Gas
Ferrara(b)	204	2008	CCGT	Gas
Bolgiano	33	2012	Power Station	Gas
Photovoltaic plants(c)	0.1	2011-2014	Photovoltaic	Photovoltaic
	2,228

(a) Installed operational capacity.

(b) Eni's share of capacity.

CAPITAL EXPENDITURE

(€ million)	2023	2022	2021	2020	2019	2018
- Plenitude	637	481	366	241	315	192
- Power	103	150	77	52	42	46
TOTAL CAPITAL EXPENDITURE	740	631	443	293	357	238

Environmental activities

The Group's environmental activities are managed by Eni Rewind, Eni's subsidiary engaged in the valorization of land, water and waste resources, industrial or deriving from reclamation activities, to give them new life leveraging on the circular economy principles, through sustainable reclamation and revaluation projects, both in Italy and abroad.

Eni Rewind, through its integrated end-to-end model, guarantees the supervision of every phase of the process reclamation and waste management, planning projects from the early stages to enhance and reuse resources (soils, water, waste), making them available for new development opportunities.

The main business areas are shown in the table below:

STRATEGICALLY RELEVANT INITIATIVES

On June 30, 2023, Eni Rewind acquired 30% of the share capital of Labanalysis Environmental Science, a leading company in the field of environmental analysis, with the aim of strengthening the integrated offering of environmental services to be proposed in the foreign market and consolidating its presence in a fundamental sector for the correct direction of environmental remediation solutions and waste management.

In July 2023, Eni and Edison signed an agreement establishing collaboration between the two companies for the management of environmental remediation projects at all industrial sites transferred in 1989 from Montedison to Enimont. The agreement will regulate the equal economic contribution for remediation interventions, already initiated by Eni Rewind and Versalis, in execution of the projects decreed by the Ministry of the Environment. The implementation of the agreement on a site-by-site basis, along with the related planning activities, cost sharing, and relations with institutions, will be coordinated by a joint technical-legal committee between the two Companies.

RECLAMATION ACTIVITIES

Based on the expertise gained and in agreement with the Authorities and stakeholders, Eni Rewind identifies projects for the enhancement and reuse of remediated areas, allowing for the environmental recovery of former industrial sites and the revitalization of the local economy.

Eni Rewind operates in 17 sites of national priority and over 100 sites of regional priority, consolidating in recent years its role as a global contractor for all Eni businesses. Among the main remediation projects at owned sites, interventions particularly stand out at: Assemini, Avenza, Brindisi, Cengio, Crotone, Gela, Porto Marghera, Porto Torres, Priolo, and Ravenna.

The Ponticelle Project in Ravenna, where Eni Rewind is committed to enhance the abandoned industrial area through Permanent Safety Measures of the site and the design of targeted improvements for the industrial requalification, is particularly relevant. Planned activities relate to the construction of a multifunctional platform for the preprocessing of waste in partnership with Herambiente and a biorecovery platform (biopile) for land to be reused in service stations after remediation, reducing landfilling disposal and consumption of vergin resources.

In this regard, it is noted that in June 2023, the Regional Single Authorizing Provision (PAUR) was obtained for the construction of treatment platforms (Eni Rewind Platform for the bio-recovery of soils at a capacity of 80,000 tons/year and a polyfunctional platform at a capacity of 60,000 tons/year developed by HEA, a joint venture with Herambiente), and subsequently, the relevant tender contracts were awarded. Primary urbanization works are underway, and the construction of the photovoltaic plant by Plenitude for green energy production has been initiated. The primary urbanization works are currently underway, and the construction of the photovoltaic plant by Plenitude for the production of green energy has been initiated. In addition, important progress has been made in the permitting process of the 'Viggiano Blue Water' project during 2023, which will allow the treatment of up to 1,700 cubic meters per day of produced water within the extraction activity in Val d'Agri. In Porto Marghera, Eni Rewind has submitted the PAUR application to build a drying plant aimed at the energy recovery of sludge from the purification of civil wastewater. In the context of circular economy, the facility will be located in a certified environmental intervention area owned by Eni, with the triple objective of enabling its reuse through industrial redevelopment, avoiding the consumption of new land, and benefiting from the existing infrastructure, services, and utilities on-site.

WATER & WASTE MANAGEMENT

Eni Rewind manages water treatment, aimed at reclamation activities, through an integrated aquifer interception system and the conveyance of water for purification to treatment plants. During 2023, the project of automation and digitalization of groundwater treatment plants progressed as a part of a larger optimization initiative, in order to increase business competitiveness and sustainability, quality of work and process security. The main drivers of the optimization project are represented by the implementation of optimized operational model for plant management, leveraging on the technological enhancement of San Donato Milanese Control Room and the digitalization of its related sites.

Another area of digitization is that of the maintenance process, which has seen the adoption of specific maintenance management software.

Currently, there are 44 treatment plants fully in operation and managed in Italy, with over 35 million cubic meters of treated water in 2023. The recovery and reuse of treated water for the production of demineralized water for industrial use and as part of the operational plans for the remediation of contaminated sites is undergoing. In 2023 about 9 million cubic meters of water have been reused after treatment.

At the end of 2023, completed the installation of 60 devices using the proprietary technology E-Hyrec® for the selective removal of hydrocarbons from groundwater to improve the effectiveness and efficiency of groundwater reclamation, with significant reductions in extraction times and avoiding the disposal of more than 3,000 tons of waste equivalent.

Eni Rewind also operates as Eni's competence center for management of waste deriving from Eni's environmental remediation activities and production activities in Italy, thanks to its model allowing to minimize costs and environmental impacts, by adopting the best technological solutions available on the market.

In 2023, Eni Rewind managed a total of approximately 1.5 million tonnes of waste by sending for recovery or disposal at external plants. In particular, the recovery index (ratio of recovered/recoverable waste) in 2023 was 75%: the slight increase compared to 2022 (74%) is due to the qualitative and particle size characteristics of the reclamation waste, detected during characterization, notwithstanding the consistency of used equipped plants with technologies available for recovery did not increase. Out of the total indicated volumes, the portion managed on behalf of Eni's clients amounts to approximately 79%.

CERTIFICATION

Eni Rewind holds SOA Certification, the mandatory certification for participation in tenders to execute public works contracts with a basic auction amount exceeding €150,000.00, for its core activities in the OG 12 - Reclamation and protection works and plants environmental and in the specialized categories OS 22 - Drinking water and purification plants and OS 14 - Waste disposal and recovery plants. During 2023, the company obtained the VIII Class – unlimited – for the SOA Category OS 22, which joins similar rankings already obtained for OG 12 and OS 14.

NON-CAPTIVE INITIATIVES

During 2023, Eni Rewind strengthened its commitment to progressively grow its non-captive portfolio of initiatives by acquiring new clients in the environmental services sector and entering agreements with leading market operators.

In particular, in January 2023, was signed a contract between Anas and the Temporary Business Grouping (RTI), where Eni Rewind is the lead company, to carry out investigation and characterization services in the Adriatic Lot. The activity has a four-year duration.

In March 2023, was signed a contract between Kuwait Petroleum International (KPI) and the Temporary Business Grouping (RTI), where Eni Rewind acts as the lead company for the remediation of the former plant in Naples (Areas Ex Refinery, Ex Chemical and Via Del Pezzo), which is part of the National Interest Site of Eastern Naples. Eni Rewind is responsible for the design activities, environmental analysis, and the supply, installation, and management of the thermal desorption plant used for the remediation of the land.

In May 2023, the renewal contract with Acciaierie d'Italia was acquired, which will further enhance Eni Rewind's distinctive expertise in hydrogeological modeling and environmental engineering ongoing at the National Interest Site of Taranto.

In July 2023, Eni Rewind entered a contract with Edison for the remediation of soil and groundwater at the former Montedison sites in Crotone. This contract adds to a similar agreement already made for the Mantova areas in 2020.

Also, in the month of July, a contract was finalized between Eni Rewind and Roma Capitale regarding the feasibility study for the remediation of the Tor Fiscale quarry area.

In September 2023, the RTI, in which Eni Rewind participates as the lead company, was awarded the tenders issued by Invitalia for the Remediation of the Bagnoli Site, Lot I and Lot II. Eni Rewind's activities include detailed design, environmental analysis, and on-site thermal desorption operations for the remediation of the land.

In October 2023, Eni Rewind participated as lead company in the RTI, along with other leading companies in the sector, in the tender for the Permanent Safety Measures of the Malagrotta Landfill in Rome, the largest waste disposal site in Europe.

ENI REWIND OUTSIDE ITALY

Since 2018, Eni Rewind has been making its expertise available to Eni's subsidiaries, located outside Italy, to manage environmental issues, in particular for management and enhancement activities of the water resource, soil, as well as training and knowledge sharing. In 2023, in support of the subsidiary Eni Kenya BV, Eni Rewind conducted a feasibility study aimed at assessing the potential for biogas production in five urban waste landfills located in Kenya. The feasibility study concluded in October, and discussions with local Authorities are ongoing to define the next steps of the project. As part of the new mandate for the remediation of service stations entered with Eni Live effective from January 1st, 2023, the support of Eni Rewind has been envisaged in the design phase of environmental interventions, including the remediation of service stations within the European network.

KEY PERFORMANCE INDICATORS

	2023	2022	2021	2020	2019	2018
Treated water (mmcm)	35.4	35.4	36.4	36.4	30.7	29.7
of which reused	9.0	9.9	9.1	6.1	5.1	4.8
Waste manage (mmtonnes)	1.5	2.0	1.9	1.7	2.0	1.9
Recovered/recoverable waste	(%) 75	74	73	78	59	58

Tables

FINANCIAL DATA

PROFIT AND LOSS ACCOUNT

(€ million)	2023	2022	2021	2020	2019	2018
Sales from operations	93,717	132,512	76,575	43,987	69,881	75,822
Other income and revenues	1,099	1,175	1,196	960	1,160	1,116
Operating expenses	(77,221)	(105,497)	(58,716)	(36,640)	(54,302)	(59,130)
Other operating income (expense)	478	(1,736)	903	(766)	287	129
Depreciation, depletion, amortization	(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	(1,802)	(1,140)	(167)	(3,183)	(2,188)	(866)
Write-off of tangible and intangible assets	(535)	(599)	(387)	(329)	(300)	(100)
Operating profit (loss)	8,257	17,510	12,341	(3,275)	6,432	9,983
Finance income (expense)	(473)	(925)	(788)	(1,045)	(879)	(971)
Income (expense) from investments	2,444	5,464	(868)	(1,658)	193	1,095
Profit (loss) before income taxes	10,228	22,049	10,685	(5,978)	5,746	10,107
Income taxes	(5,368)	(8,088)	(4,845)	(2,650)	(5,591)	(5,970)
Tax rate (%)	52.5	36.7	45.3		97.3	59.1
Net profit (loss)	4,860	13,961	5,840	(8,628)	155	4,137
Attributable to:
- Eni's shareholders	4,771	13,887	5,821	(8,635)	148	4,126
- Non-controlling interest	89	74	19	7	7	11

SUMMARIZED GROUP BALANCE SHEET

	(€ million) Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Fixed assets
Property, plant and equipment	56,299	56,332	56,299	53,943	62,192	60,302
Right of use	4,834	4,446	4,821	4,643	5,349
Intangible assets	6,379	5,525	4,799	2,936	3,059	3,170
Inventories - Compulsory stock	1,576	1,786	1,053	995	1,371	1,217
Equity-accounted investments and other investments	13,886	13,294	7,181	7,706	9,964	7,963
Receivables and securities held for operating purposes	2,335	1,978	1,902	1,037	1,234	1,314
Net payables related to capital expenditure	(2,031)	(2,320)	(1,804)	(1,361)	(2,235)	(2,399)
	83,278	81,041	74,251	69,899	80,934	71,567
Net working capital
Inventories	6,186	7,709	6,072	3,893	4,734	4,651
Trade receivables	13,184	16,556	15,524	7,087	8,519	9,520
Trade payables	(14,231)	(19,527)	(16,795)	(8,679)	(10,480)	(11,645)
Net tax assets (liabilities)	(2,112)	(2,991)	(3,678)	(2,198)	(1,594)	(1,364)
Provisions	(15,533)	(15,267)	(13,593)	(13,438)	(14,106)	(11,626)
Other current assets and liabilities	(892)	316	(2,258)	(1,328)	(1,864)	(860)
	(13,398)	(13,204)	(14,728)	(14,663)	(14,791)	(11,324)
Provisions for employee benefits	(748)	(786)	(819)	(1,201)	(1,136)	(1,117)
Assets held for sale including related liabilities	747	156	139	44	18	236
CAPITAL EMPLOYED, NET	69,879	67,207	58,843	54,079	65,025	59,362
Shareholders' equity
attributable to: - Eni's shareholders	53,184	54,759	44,437	37,415	47,839	51,016
- Non-controlling interest	460	471	82	78	61	57
Shareholders' equity including non-controlling interest	53,644	55,230	44,519	37,493	47,900	51,073
Net borrowings before lease liabilities ex IFRS 16	10,899	7,026	8,987	11,568	11,477	8,289
Lease liabilities:	5,336	4,951	5,337	5,018	5,648
- of which Eni working interest	4,856	4,457	3,653	3,366	3,672
- of which Joint operators' working interest	480	494	1,684	1,652	1,976
Net borrowings after lease liabilities ex IFRS 16	16,235	11,977	14,324	16,586	17,125	8,289
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	69,879	67,207	58,843	54,079	65,025	59,362
Leverage before lease liability ex IFRS 16	0.20	0.13	0.20	0.31	0.24	0.16
Leverage after lease liability ex IFRS 16	0.30	0.22	0.32	0.44	0.36	n.a.
Gearing	0.23	0.18	0.24	0.31	0.26	0.14

SUMMARIZED GROUP CASH FLOW STATEMENT

(€ million)	2023	2022	2021	2020	2019	2018
Net profit (loss)	4,860	13,961	5,840	(8,628)	155	4,137
Adjustments to reconcile net profit (loss) to net cash provided by operating activities:
- depreciation, depletion and amortization and other non monetary items	7,781	4,369	8,568	12,641	10,480	7,657
- net gains on disposal of assets	(441)	(524)	(102)	(9)	(170)	(474)
- dividends, interest, taxes and other changes	5,596	8,611	5,334	3,251	6,224	6,168
Changes in working capital related to operations	1,811	(1,279)	(3,146)	(18)	366	1,632
Dividends received by equity investments	2,255	1,545	857	509	1,346	275
Taxes paid	(6,283)	(8,488)	(3,726)	(2,049)	(5,068)	(5,226)
Interests (paid) received	(460)	(735)	(764)	(875)	(941)	(522)
Net cash provided by operating activities - continuing operations	15,119	17,460	12,861	4,822	12,392	13,647
Capital expenditure	(9,215)	(8,056)	(5,234)	(4,644)	(8,376)	(9,119)
Investments and purchase of consolidated subsidiaries and businesses	(2,592)	(3,311)	(2,738)	(392)	(3,008)	(244)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments	596	1,202	404	28	504	1,242
Other cash flow related to investing activities	(348)	2,361	289	(735)	(254)	942
Free cash flow	3,560	9,656	5,582	(921)	1,258	6,468
Net cash inflow (outflow) related to financial activities	2,194	786	(4,743)	1,156	(279)	(357)
Changes in short and long-term financial debt	315	(2,569)	(244)	3,115	(1,540)	320
Repayment of lease liabilities	(963)	(994)	(939)	(869)	(877)
Dividends paid and changes in non-controlling interests and reserves	(4,882)	(4,841)	(2,780)	(1,968)	(3,424)	(2,957)
Net issue (repayment) of perpetual hybrid bond	(138)	(138)	1,924	2,975
Effect of changes in consolidation and exchange differences of cash and cash equivalent	(62)	16	52	(69)	1	18
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENT	24	1,916	(1,148)	3,419	(4,861)	3,492
Adjusted net cash before changes in working capital at replacement cost	16,498	20,380	12,711	6,726	11,700	12,529

CHANGES IN NET BORROWINGS

(€ million)	2023	2022	2021	2020	2019	2018
Free cash flow	3,560	9,656	5,582	(921)	1,258	6,468
Repayment of lease liabilities	(963)	(994)	(939)	(869)	(877)
Net borrowings of acquired companies	(234)	(512)	(777)	(67)		(18)
Net borrowings of divested companies	(155)	142			13	(499)
Exchange differences on net borrowings and other changes	(1,061)	(1,352)	(429)	759	(158)	(367)
Dividends paid and changes in non-controlling interest and reserves	(4,882)	(4,841)	(2,780)	(1,968)	(3,424)	(2,957)
Net issue (repayment) of perpetual hybrid bond	(138)	(138)	1,924	2,975
CHANGE IN NET BORROWINGS BEFORE LEASE LIABILITIES	(3,873)	1,961	2,581	(91)	(3,188)	2,627
IFRS 16 first application effect					(5,759)
Repayment of lease liabilities	963	994	939	869	877
Inception of new leases and other changes	(1,348)	(608)	(1,258)	(239)	(766)
Change in lease liabilities	(385)	386	(319)	630	(5,648)
CHANGE IN NET BORROWINGS AFTER LEASE LIABILITIES	(4,258)	2,347	2,262	539	(8,836)	2,627

SALES FROM OPERATIONS

(€ million)	2023	2022	2021	2020	2019	2018
Exploration & Production	23,903	31,194	21,742	13,590	23,572	25,744
Global Gas & LNG Portfolio	20,139	48,586	20,843	7,051	11,779	14,807
Enilive, Refining and Chemicals	52,558	59,178	40,374	25,340	42,360	46,483
Plenitude & Power	14,256	20,883	11,187	7,536	8,448	8,218
Corporate and other activities	1,972	1,886	1,698	1,559	1,676	1,588
Impact of unrealized intragroup profit elimination and consolidation adjustments	(19,111)	(29,215)	(19,269)	(11,089)	(17,954)	(21,018)
	93,717	132,512	76,575	43,987	69,881	75,822

SALES TO CUSTOMERS

(€ million)	2023	2022	2021	2020	2019	2018
Exploration & Production	10,843	12,889	8,846	6,359	10,499	9,943
Global Gas & LNG Portfolio	16,910	41,230	16,973	5,362	9,230	11,931
Enilive, Refining and Chemicals	52,165	58,470	40,051	24,937	41,976	46,088
Plenitude & Power	13,598	19,726	10,517	7,135	7,972	7,684
Corporate and other activities	201	197	188	194	204	176
	93,717	132,512	76,575	43,987	69,881	75,822

SALES BY GEOGRAPHIC AREA OF DESTINATION

(€ million)	2023	2022	2021	2020	2019	2018
Italy	33,450	60,090	29,968	14,717	23,312	25,279
Other EU Countries	18,271	25,413	14,671	9,508	18,567	20,408
Rest of Europe	18,476	21,748	12,470	8,191	6,931	7,052
Americas	7,004	6,929	4,420	2,426	3,842	5,051
Asia	7,404	9,062	7,891	4,182	8,102	9,585
Africa	9,057	9,191	7,040	4,842	8,998	8,246
Other areas	55	79	115	121	129	201
Total outside Italy	60,267	72,422	46,607	29,270	46,569	50,543
	93,717	132,512	76,575	43,987	69,881	75,822

SALES BY GEOGRAPHIC AREA OF ORIGIN

(€ million)	2023	2022	2021	2020	2019	2018
Italy	62,145	90,479	52,815	29,116	46,763	51,733
Other EU Countries	11,405	16,171	9,022	5,508	7,029	8,004
Rest of Europe	3,102	7,157	1,946	1,226	1,909	2,496
Americas	5,546	5,329	3,577	1,838	3,290	3,627
Africa	1,671	1,931	1,170	846	1,068	1,165
Asia	9,776	11,224	7,777	5,271	9,587	8,599
Other areas	72	221	268	182	235	198
Total outside Italy	31,572	42,033	23,760	14,871	23,118	24,089
	93,717	132,512	76,575	43,987	69,881	75,822

PURCHASES, SERVICES AND OTHER

(€ million)	2023	2022	2021	2020	2019	2018
Production costs - raw, ancillary and consumable materials and goods	58,170	85,139	41,174	21,432	36,272	41,125
Production costs - services	11,512	10,303	10,646	9,710	11,589	10,625
Operating leases and other	1,432	2,301	1,233	876	1,478	1,820
Net provisions	1,369	2,985	707	349	858	1,120
Other expenses	1,746	2,069	1,983	1,317	879	1,130
less:
capitalized direct costs associated with self-constructed tangible and intangible assets	(393)	(268)	(194)	(133)	(202)	(198)
	73,836	102,529	55,549	33,551	50,874	55,622

ACCOUNTANT FEES AND SERVICES

(€ thousand)	2023	2022	2021	2020	2019	2018
Audit fees	25,982	23,637	18,858	19,605	15,748	25,445
Audit-related fees	3,580	3,563	4,511	1,412	1,045	1,628
	29,562	27,200	23,369	21,017	16,793	27,073

PAYROLL AND RELATED COSTS

(€ million)	2023	2022	2021	2020	2019	2018
Wages and salaries	2,427	2,311	2,182	2,193	2,417	2,409
Social security contributions	497	465	455	458	449	448
Cost related to defined benefit plans and defined contribution plans	156	174	165	102	85	220
Other costs	196	194	204	239	213	170
less:
capitalized direct costs associated with self-constructed tangible and intangible assets	(140)	(129)	(118)	(129)	(168)	(154)
	3,136	3,015	2,888	2,863	2,996	3,093

DEPRECIATION, DEPLETION, AMORTIZATION, IMPAIRMENT LOSSES (IMPAIRMENT REVERSALS) NET AND WRITE-OFF

(€ million)	2023	2022	2021	2020	2019	2018
Exploration & Production	6,148	6,017	5,976	6,273	7,060	6,152
Global Gas & LNG Portfolio	233	217	174	125	124	226
Enilive, Refining and Chemicals	524	506	512	575	620	399
Plenitude & Power	466	358	286	217	190	182
Corporate and other activities	142	140	148	146	144	59
Impact of unrealized intragroup profit elimination	(34)	(33)	(33)	(32)	(32)	(30)
Total depreciation, depletion and amortization	7,479	7,205	7,063	7,304	8,106	6,988
Exploration & Production	1,037	432	(1,244)	1,888	1,217	726
Global Gas & LNG Portfolio	(1)	(12)	26	2	(5)	(73)
Enilive, Refining and Chemicals	764	717	1,342	1,271	922	193
Plenitude & Power	(30)	(37)	20	1	42	2
Corporate and other activities	32	40	23	21	12	18
Impairment losses (impairment reversals) of tangible and intangible and right of use assets, net	1,802	1,140	167	3,183	2,188	866
Depreciation, depletion, amortization, impairments and reversals, net	9,281	8,345	7,230	10,487	10,294	7,854
Write-off of tangible and intangible assets	535	599	387	329	300	100
	9,816	8,944	7,617	10,816	10,594	7,954

OPERATING PROFIT BY SEGMENT

(€ million)	2023	2022	2021	2020	2019	2018
Exploration & Production	8,549	15,963	10,113	(610)	7,417	10,214
Global Gas & LNG Portfolio	2,431	3,730	899	(332)	431	387
Enilive, Refining and Chemicals	(1,397)	460	45	(2,463)	(682)	(501)
Plenitude & Power	(464)	(825)	2,355	660	74	340
Corporate and other activities	(943)	(1,956)	(863)	(563)	(688)	(668)
Impact of unrealized intragroup profit elimination	81	138	(208)	33	(120)	211
	8,257	17,510	12,341	(3,275)	6,432	9,983

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

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

Inventory holding gain or loss

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

Special items

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

Correspondently, special charges/gains also include the evaluation effects relating to assets/liabilities utilized in a natural hedge relation to offset a market risk, as in the case of accrued currency differences at finance debt denominated in a currency other than the reporting currency, where the cash outflows for the reimbursement are matched by highly probable cash inflows in the same currency.

The deferral of both the unrealized portion of fair-valued commodity and other derivatives and evaluation effects are reversed to future reporting periods when the underlying transaction occurs.

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

Leverage

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

Gearing

Gearing is calculated as the ratio between net borrowings and capital employed net and measures how much of capital employed net is financed recurring to third-party funding.

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

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

Free cash flow

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

Net borrowings

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

ROACE Adjusted

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.

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 cashequivalents, securities held for non-operating purposes and financing receivables for non-operating purposes.

Net Debt/EBITDA adjusted

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.

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.

2023	Exploration & Production	Global Gas & LNG Portfolio	Enilive, Refining and Chemicals	Plenitude & Power	Corporate and other activities	Impact of unrealized intragroup profit elimination	Group
Reported operating profit (loss)	8,549	2,431	(1,397)	(464)	(943)	81	8,257
Exclusion of inventory holding (gains) losses			604			(42)	562
Exclusion of special items:
- environmental charges	81		373	1	193		648
- impairment losses (impairments reversals), net	1,037	(1)	764	(30)	32		1,802
- net gains on disposal of assets	2		(9)		(4)		(11)
- risk provisions	7		19		13		39
- provision for redundancy incentives	40	4	46	9	59		158
- commodity derivatives		97	14	1,144			1,255
- exchange rate differences and derivatives	62	(105)	24		3		(16)
- other	156	821	117	21	(4)		1,111
Special items of operating profit (loss)	1,385	816	1,348	1,145	292		4,986
Adjusted operating profit (loss)	9,934	3,247	555	681	(651)	39	13,805
Net finance (expense) income(a)	(196)	1	(38)	(15)	(195)		(443)
Net income (expense) from investments(a)	1,321	49	412	(34)	(2)		1,746
Income taxes(a)	(5,543)	(924)	(259)	(218)	249	(13)	(6,708)
Tax rate (%)							44.4
Adjusted net profit (loss)	5,516	2,373	670	414	(599)	26	8,400
of which attributable to:
- non-controlling interest							78
- Eni's shareholders							8,322
Reported net profit (loss) attributable to Eni's shareholders							4,771
Exclusion of inventory holding (gains) losses							402
Exclusion of special items							3,149
Adjusted net profit (loss) attributable to Eni's shareholders							8,322

	Exploration	Global	Enilive, Refining		Corporate	Impact of unrealized intragroup
2022 (€ million)	& Production	Gas & LNG Portfolio	and Chemicals	Plenitude & Power	and other activities	profit elimination	Group
Reported operating profit (loss)	15,963	3,730	460	(825)	(1,956)	138	17,510
Exclusion of inventory holding (gains) losses			(416)			(148)	(564)
Exclusion of special items:
- environmental charges	30		962	2	1,062		2,056
- impairment losses (impairments reversals), net	432	(12)	717	(37)	40		1,140
- impairment of exploration projects	2						2
- net gains on disposal of assets	(27)		(10)	1	(5)		(41)
- risk provisions	34		52		1		87
- provision for redundancy incentives	34	4	46	65	53		202
- commodity derivatives		(1,805)	4	1,412			(389)
- exchange rate differences and derivatives	(54)	244	(33)	(5)	(3)		149
- other	55	(98)	147	2	128		234
Special items of operating profit (loss)	506	(1,667)	1,885	1,440	1,276		3,440
Adjusted operating profit (loss)	16,469	2,063	1,929	615	(680)	(10)	20,386
Net finance (expense) income(a)	(319)	(17)	(36)	(11)	(669)		(1,052)
Net income (expense) from investments(a)	2,086	4	637	(6)	(91)		2,630
Income taxes(a)	(7,402)	(1,068)	(616)	(201)	673	6	(8,608)
Tax rate (%)							39.2
Adjusted net profit (loss)	10,834	982	1,914	397	(767)	(4)	13,356
of which attributable to:
- non-controlling interest							55
- Eni's shareholders							13,301
Reported net profit (loss) attributable to Eni's shareholders							13,887
Exclusion of inventory holding (gains) losses							(401)
Exclusion of special items							(185)
Adjusted net profit (loss) attributable to Eni's shareholders							13,301

2021	Exploration & Production	Global Gas & LNG Portfolio	Enilive, Refining and Chemicals	Plenitude & Power	Corporate and other activities	Impact of unrealized intragroup profit elimination	Group
Reported operating profit (loss)	10,113	899	45	2,355	(863)	(208)	12,341
Exclusion of inventory holding (gains) losses			(1,455)			(36)	(1,491)
Exclusion of special items:
- environmental charges	60		150		61		271
- impairment losses (impairments reversals), net	(1,244)	26	1,342	20	23		167
- impairment of exploration projects	247						247
- net gains on disposal of assets	(77)		(22)	(2)	1		(100)
- risk provisions	113		(4)		33		142
- provision for redundancy incentives	60	5	42	(5)	91		193
- commodity derivatives		(207)	50	(1,982)			(2,139)
- exchange rate differences and derivatives	(3)	206	(14)	(6)			183
- other	71	(349)	18	96	14		(150)
Special items of operating profit (loss)	(773)	(319)	1,562	(1,879)	223		(1,186)
Adjusted operating profit (loss)	9,340	580	152	476	(640)	(244)	9,664
Net finance (expense) income(a)	(313)	(17)	(32)	(2)	(539)		(903)
Net income (expense) from investments(a)	681		(4)	(3)	(691)		(17)
Income taxes(a)	(4,118)	(394)	(54)	(144)	244	68	(4,395)
Tax rate (%)							50.3
Adjusted net profit (loss)	5,593	169	62	327	(1,626)	(176)	4,349
of which attributable to:
- non-controlling interest							19
- Eni's shareholders							4,330
Reported net profit (loss) attributable to Eni's shareholders							5,821
Exclusion of inventory holding (gains) losses							(1,060)
Exclusion of special items							(431)
Adjusted net profit (loss) attributable to Eni's shareholders							4,330

2020	Exploration & Production	Global Gas & LNG Portfolio	Enilive, Refining and Chemicals	Plenitude & Power	Corporate and other activities	Impact of unrealized intragroup profit elimination	Group
Reported operating profit (loss)	(610)	(332)	(2,463)	660	(563)	33	(3,275)
Exclusion of inventory holding (gains) losses			1,290			28	1,318
Exclusion of special items:
- environmental charges	19		85	1	(130)		(25)
- impairment losses (impairments reversals), net	1,888	2	1,271	1	21		3,183
- net gains on disposal of assets	1		(8)		(2)		(9)
- risk provisions	114		5	10	20		149
- provision for redundancy incentives	34	2	27	20	40		123
- commodity derivatives		858	(185)	(233)			440
- exchange rate differences and derivatives	13	(183)	10				(160)
- other	88	(21)	(26)	6	107		154
Special items of operating profit (loss)	2,157	658	1,179	(195)	56		3,855
Adjusted operating profit (loss)	1,547	326	6	465	(507)	61	1,898
Net finance (expense) income(a)	(316)		(7)	(1)	(569)		(893)
Net income (expense) from investments(a)	262	(15)	(161)	6	(95)		(3)
Income taxes(a)	(1,369)	(100)	(84)	(141)	(34)	(25)	(1,753)
Tax rate (%)							175.0
Adjusted net profit (loss)	124	211	(246)	329	(1,205)	36	(751)
of which attributable to:
- non-controlling interest							7
- Eni's shareholders							(758)
Reported net profit (loss) attributable to Eni's shareholders							(8,635)
Exclusion of inventory holding (gains) losses							937
Exclusion of special items							6,940
Adjusted net profit (loss) attributable to Eni's shareholders							(758)

2019	Exploration & Production	Global Gas & LNG Portfolio	Enilive, Refining and Chemicals	Plenitude & Power	Corporate and other activities	Impact of unrealized intragroup profit elimination	Group
Reported operating profit (loss)	7,417	431	(682)	74	(688)	(120)	6,432
Exclusion of inventory holding (gains) losses			(318)			95	(223)
Exclusion of special items:
- environmental charges	32		244		62		338
- impairment losses (impairments reversals), net	1,217	(5)	922	42	12		2,188
- net gains on disposal of assets	(145)		(5)		(1)		(151)
- risk provisions	(18)		(2)		23		3
- provision for redundancy incentives	23	1	8	3	10		45
- commodity derivatives		(576)	(118)	255			(439)
- exchange rate differences and derivatives	14	109	(5)	(10)			108
- other	100	233	(23)	6	(20)		296
Special items of operating profit (loss)	1,223	(238)	1,021	296	86		2,388
Adjusted operating profit (loss)	8,640	193	21	370	(602)	(25)	8,597
Net finance (expense) income(a)	(362)	3	(36)	(1)	(525)		(921)
Net income (expense) from investments(a)	312	(21)	37	10	43		381
Income taxes(a)	(5,154)	(75)	(64)	(104)	218	5	(5,174)
Tax rate (%)							64.2
Adjusted net profit (loss)	3,436	100	(42)	275	(866)	(20)	2,883
of which attributable to:
- non-controlling interest							7
- Eni's shareholders							2,876
Reported net profit (loss) attributable to Eni's shareholders							148
Exclusion of inventory holding (gains) losses							(157)
Exclusion of special items							2,885
Adjusted net profit (loss) attributable to Eni's shareholders							2,876

2018	Exploration & Production	Global Gas & LNG Portfolio	Enilive, Refining and Chemicals	Plenitude & Power	Corporate and other activities	Impact of unrealized intragroup profit elimination	Group
Reported operating profit (loss)	10,214	387	(501)	340	(668)	211	9,983
Exclusion of inventory holding (gains) losses			234			(138)	96
Exclusion of special items:
- environmental charges	110		193	(1)	23		325
- impairment losses (impairments reversals), net	726	(73)	193	2	18		866
- net gains on disposal of assets	(442)		(9)		(1)		(452)
- risk provisions	360		21		(1)		380
- provision for redundancy incentives	26	4	8	118	(1)		155
- commodity derivatives		(63)	120	(190)			(133)
- exchange rate differences and derivatives	(6)	111	5	(3)			107
- other	(138)	(88)	96	(4)	47		(87)
Special items of operating profit (loss)	636	(109)	627	(78)	85		1,161
Adjusted operating profit (loss)	10,850	278	360	262	(583)	73	11,240
Net finance (expense) income(a)	(366)	(3)	11	(1)	(697)		(1,056)
Net income (expense) from investments(a)	285	(1)	(2)	10	5		297
Income taxes(a)	(5,814)	(156)	(145)	(82)	327	(17)	(5,887)
Tax rate (%)							56.2
Adjusted net profit (loss)	4,955	118	224	189	(948)	56	4,594
of which attributable to:
- non-controlling interest							11
- Eni's shareholders							4,583
Reported net profit (loss) attributable to Eni's shareholders							4,126
Exclusion of inventory holding (gains) losses							69
Exclusion of special items							388
Adjusted net profit (loss) attributable to Eni's shareholders							4,583

(€ million)	2023	2022	2021	2020	2019	2018
Special items of operating profit (loss)	4,986	3,440	(1,186)	3,855	2,388	1,161
- environmental charges	648	2,056	271	(25)	338	325
- impairment losses (impairments reversals), net	1,802	1,140	167	3,183	2,188	866
- impairment of exploration projects		2	247
- net gains on disposal of assets	(11)	(41)	(100)	(9)	(151)	(452)
- risk provisions	39	87	142	149	3	380
- provision for redundancy incentives	158	202	193	123	45	155
- commodity derivatives	1,255	(389)	(2,139)	440	(439)	(133)
- exchange rate differences and derivatives	(16)	149	183	(160)	108	107
- reinstatement of Eni Norge amortization charges						(375)
- other	1,111	234	(150)	154	296	288
Net finance (income) expense	30	(127)	(115)	152	(42)	(85)
of which:
- exchange rate differences and derivatives reclassified to operating profit (loss)	16	(149)	(183)	160	(108)	(107)
Net income (expense) from investments	(698)	(2,834)	851	1,655	188	(798)
of which:
- gains on disposals of assets	(834)	(2,990)			(46)	(909)
- impairments/revaluation of equity investmentss			851	1,207	148	67
Income taxes	(1,180)	(683)	19	1,278	351	110
Total special items of net profit (loss)	3,138	(204)	(431)	6,940	2,885	388
attributable to:
- Eni's shareholders	3,149	(185)	(431)	6,940	2,885	388
- Non-controlling interest	(11)	(19)

ADJUSTED OPERATING PROFIT BY SEGMENT

(€ million)	2023	2022	2021	2020	2019	2018
Exploration & Production	9,934	16,469	9,340	1,547	8,640	10,850
Global Gas & LNG Portfolio	3,247	2,063	580	326	193	278
Enilive, Refining and Chemicals	555	1,929	152	6	21	360
Plenitude & Power	681	615	476	465	370	262
Corporate and other activities	(651)	(680)	(640)	(507)	(602)	(583)
Impact of unrealized intragroup profit elimination	39	(10)	(244)	61	(25)	73
	13,805	20,386	9,664	1,898	8,597	11,240

ADJUSTED NET PROFIT BY SEGMENT

(€ million)	2023	2022	2021	2020	2019	2018
Exploration & Production	5,516	10,834	5,593	124	3,436	4,955
Global Gas & LNG Portfolio	2,373	982	169	211	100	118
Enilive, Refining and Chemicals	670	1,914	62	(246)	(42)	224
Plenitude & Power	414	397	327	329	275	189
Corporate and other activities	(599)	(767)	(1,626)	(1,205)	(866)	(948)
Impact of unrealized intragroup profit elimination and other consolidation adjustments(a)	26	(4)	(176)	36	(20)	56
	8,400	13,356	4,349	(751)	2,883	4,594
of which attributable to:
- Eni's shareholders	8,322	13,301	4,330	(758)	2,876	4,583
- Non-controlling interest	78	55	19	7	7	11

(a) This item concerned mainly intragroup sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of end of the period.

FINANCE INCOME (EXPENSE)

(€ million)	2023	2022	2021	2020	2019	2018
Finance income (expense) related to net borrowings	(487)	(939)	(849)	(913)	(962)	(627)
- Interest expense on corporate bonds	(667)	(507)	(475)	(517)	(618)	(565)
- Net income from financial activities held for trading	250	(53)	11	31	127	32
- Net income from financial assets measured at fair value through profit or loss	34	(2)
- Interest expense for banks and other financing istitutions	(207)	(128)	(94)	(102)	(122)	(120)
- Interest expense for lease liabilities	(267)	(315)	(304)	(347)	(378)
- Interest from banks	356	57	4	10	21	18
- Interest and other income from receivables and securities for non-financing operating activities	14	9	9	12	8	8
Income (expense) from derivative financial instruments	(61)	13	(306)	351	(14)	(307)
- Derivatives on exchange rate	(63)	(70)	(322)	391	9	(329)
- Derivatives on interest rate	2	81	16	(40)	(23)	22
- Options		2
Exchange differences, net	255	238	476	(460)	250	341
Other finance income (expense)	(274)	(275)	(177)	(96)	(246)	(430)
- Interest and other income from receivables and securities for financing operating activities	153	128	67	97	112	132
- Finance expense due to the passage of time (accretion discount)	(341)	(199)	(144)	(190)	(255)	(249)
- Other finance income (expense)	(86)	(204)	(100)	(3)	(103)	(313)
	(567)	(963)	(856)	(1,118)	(972)	(1,023)
Finance expense capitalized	94	38	68	73	93	52
	(473)	(925)	(788)	(1,045)	(879)	(971)

INCOME (EXPENSE ON) FROM INVESTMENTS

(€ million)	2023	2022	2021	2020	2019	2018
Share of profit of equity-accounted investments	1,622	2,163	202	38	161	409
Share of loss of equity-accounted investments	(281)	(285)	(1,294)	(1,733)	(184)	(430)
Gains on disposals	430	483	1		19	22
Dividends	255	351	230	150	247	231
Decreases (increases) in the provision for losses on investments from equity accounted investments	(5)	(37)	1	(38)	(65)	(47)
Other income (expense), net	423	2,789	(8)	(75)	15	910
	2,444	5,464	(868)	(1,658)	193	1,095

PROPERTY, PLANT AND EQUIPMENT BY SEGMENT

(€ million)	2023	2022	2021	2020	2019	2018
Property, plant and equipment by segment, gross
Exploration & Production	156,342	158,003	162,569	150,613	159,597	151,046
Global Gas & LNG Portfolio	2,540	2,653	2,665	2,164	2,332	2,286
Enilive, Refining and Chemicals	29,192	28,058	27,390	26,713	26,154	25,428
Plenitude & Power	6,109	5,442	4,497	3,641	3,402	3,249
Corporate and other activities	2,355	2,289	2,253	2,134	1,944	1,875
Impact of unrealized intragroup profit elimination	(651)	(633)	(628)	(624)	(614)	(600)
	195,887	195,812	198,746	184,641	192,815	183,284
Property, plant and equipment by segment, net
Exploration & Production	48,837	49,512	50,284	48,296	55,702	53,535
Global Gas & LNG Portfolio	569	735	849	579	738	826
Enilive, Refining and Chemicals	3,599	3,316	3,342	4,132	5,015	5,300
Plenitude & Power	3,055	2,534	1,653	860	708	624
Corporate and other activities	443	453	417	348	323	327
Impact of unrealized intragroup profit elimination	(204)	(218)	(246)	(272)	(294)	(310)
	56,299	56,332	56,299	53,943	62,192	60,302

CAPITAL EXPENDITURE BY SEGMENT

(€ million)	2023	2022	2021	2020	2019	2018
Exploration & Production	7,133	6,252	3,824	3,472	6,996	7,901
Global Gas & LNG Portfolio	16	23	19	11	15	26
Enilive, Refining and Chemicals	982	878	728	771	933	877
Plenitude & Power	740	631	443	293	357	238
Corporate and other activities	363	276	224	107	89	94
Impact of unrealized intragroup profit elimination	(19)	(4)	(4)	(10)	(14)	(17)
Capital expenditure	9,215	8,056	5,234	4,644	8,376	9,119
Investments and purchase of consolidated subsidiaries and businesses	2,592	3,311	2,738	392	3,008	244
Total capex and investments and purchase of consolidated subsidiaries and businesses	11,807	11,367	7,972	5,036	11,384	9,363

CAPITAL EXPENDITURE BY GEOGRAPHIC AREA OF ORIGIN

(€ million)	2023	2022	2021	2020	2019	2018
Italy	2,006	1,475	1,333	1,198	1,402	1,424
Other European Union Countries	485	415	199	152	306	267
Rest of Europe	235	205	202	119	9	538
Africa	4,105	3,163	1,604	1,443	3,902	4,533
Americas	609	1,266	659	441	1,017	534
Asia	1,471	1,390	1,203	1,267	1,685	1,782
Other areas	304	142	34	24	55	41
Total outside Italy	7,209	6,581	3,901	3,446	6,974	7,695
Capital expenditure	9,215	8,056	5,234	4,644	8,376	9,119

NET BORROWINGS

				Financial assets measured at fair	Financing receivables held
	(€ million)	Debt and bonds	Cash and cash equivalents	value thorugh profit or loss	for non-operating purposes	Leasing Liabilities	Total
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

EMPLOYEES

EMPLOYEES AT YEAR END

	(units)	2023	2022	2021	2020	2019	2018
Exploration & Production	Italy	3,193	3,192	3,364	3,692	3,491	3,477
	Outside Italy	5,592	5,497	6,045	6,123	6,781	6,971
		8,785	8,689	9,409	9,815	10,272	10,448
Global Gas & LNG Portfolio	Italy	279	282	276	290	293	318
	Outside Italy	390	588	571	410	418	416
		669	870	847	700	711	734
Enilive, Refining and Chemicals	Italy	9,835	8,986	9,028	8,915	9,035	8,863
	Outside Italy	4,257	4,146	4,044	2,556	2,591	2,594
		14,092	13,132	13,072	11,471	11,626	11,457
Plenitude & Power	Italy	2,230	2,096	1,864	1,679	1,698	1,719
	Outside Italy	788	698	600	413	358	337
		3,018	2,794	2,464	2,092	2,056	2,056
Corporate and other activities	Italy	6,212	6,322	6,503	6,999	6,971	6,625
	Outside Italy	366	381	394	418	417	381
		6,578	6,703	6,897	7,417	7,388	7,006
Total employees at year end	Italy	21,749	20,878	21,035	21,575	21,488	21,002
	Outside Italy	11,393	11,310	11,654	9,920	10,565	10,699
		33,142	32,188	32,689	31,495	32,053	31,701

BREAKDOWN BY POSITION

	2023	2022	2021	2020	2019	2018
Senior Managers	960	966	986	982	1,037	1,025
Middle Managers and Senior Staff	9,349	9,133	9,196	9,245	9,461	9,227
White collar workers	16,557	15,903	15,970	16,285	16,403	16,208
Blue collar workers	6,276	6,186	6,537	4,983	5,152	5,241
Total	33,142	32,188	32,689	31,495	32,053	31,701
of which:
- fully consolidated entities	32,321	31,376	31,888	30,775	31,321	30,950
- joint operations	821	812	801	720	732	751

QUARTERLY INFORMATION

MAIN FINANCIAL DATA(a)

2023 (€ million)	I quarter	II quarter	III quarter	IV quarter
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 at period end	12,634	12,941	13,578	16,235	16,235

2022	I quarter	II quarter	III quarter	IV quarter
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 at period end	13,993	12,777	11,533	11,977	11,977

I quarter	II quarter	III quarter	IV quarter
14,494	16,294	19,021	26,766	76,575
1,862	1,995	2,793	5,691	12,341
1,321	2,045	2,492	3,806	9,664
856	247	1,203	3,515	5,821
1,139	1,248	1,200	1,647	5,234
520	351	553	1,314	2,738
17,507	15,323	16,622	14,324	14,324

2020	I quarter	II quarter	III quarter	IV quarter
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 at period end	18,681	19,971	19,853	16,586	16,586

(a) Quarterly data are unaudited.

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

KEY MARKET INDICATORS

2023	I quarter	II quarter	III quarter	IV quarter
Average price of Brent dated crude oil(a)	81.27	78.39	86.76	84.05	82.62
Average EUR/USD exchange rate(b)	1.073	1.089	1.088	1.08	1.08
Average price in euro of Brent dated crude oil	75.74	71.99	79.71	78.17	76.40
Standard Eni Refining Margin (SERM)(c)	11.0	5.5	11.7	4.3	8.1
PSV(d) (€/MWh)	57	37	34	41	42
TTF(d) (€/MWh)	54	35	33	41	41

2022	I quarter	II quarter	III quarter	IV quarter
Average price of Brent dated crude oil(a)	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	90.40	106.84	100.15	86.93	96.09
Standard Eni Refining Margin (SERM)(c)	(0.9)	17.2	4.1	13.6	8.5
PSV(d) (€/MWh)	99	97	197	95	122
TTF(d) (€/MWh)	96	96	196	94	121

2021	I quarter	II quarter	III quarter	IV quarter
Average price of Brent dated crude oil(a)	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	50.54	57.07	62.33	69.73	59.80
Standard Eni Refining Margin (SERM)(c)	(0.6)	(0.4)	(0.4)	(2.2)	(0.9)
PSV(d) (€/MWh)	19	25	46	93	46
TTF(d) (€/MWh)	19	25	47	92	46

2020	I quarter	II quarter	III quarter	IV quarter
Average price of Brent dated crude oil(a)	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	45.56	26.51	36.78	37.08	36.49
Standard Eni Refining Margin (SERM)(c)	3.6	2.3	0.7	0.2	1.7
PSV(d) (€/MWh)	11	7	9	14	10
TTF(d) (€/MWh)	10	5	8	15	9

(a) In USD per barrel. Source: Platt's Oilgram.

(b) Source: ECB.

(c) In USD per barrel. Source: Eni calculations. It gauges the profitability of Eni's refineries against the typical raw material slate and yields. From January 1,2024, the benchmark refining margin has been calculated based on a new methodology which considers a revised industrial set-up in connection with the planned restructuring of the Livorno plant and implemented optimizations of utilities consumption, as well as current trends in crude supplies building in a slate of both high-sulfur and low-sulfur crudes. The values of the SERM indicator of the comparative 2023 quarters have been restated.

(d) In €/MWh. Source: ICIS European Spot Gas Markets.

MAIN OPERATING DATA

2023		I quarter	II quarter	III quarter	IV quarter
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)	1,661	1,616	1,635	1,708	1,655
Italy		75	69	68	66	69
Rest of Europe		180	172	172	182	177
North Africa		295	271	286	352	301
Egypt		332	323	313	303	318
Sub-Saharian Africa		292	284	308	307	298
Kazakhstan		166	162	147	178	163
Rest of Asia		174	185	187	185	183
Americas		141	143	144	129	139
Australia and Oceania		6	7	10	6	7
Hydrocarbons production sold	(mmboe)	131.2	135.0	134.9	144.8	545.9
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
Retail and business gas sales		2.91	0.87	0.53	1.74	6.06
Retail and business power sales to end customers	(TWh)	4.62	4.19	4.57	4.60	17.98
Power sales in the open market		5.16	4.90	4.85	4.97	19.88
Sales of refined products	(mmtonnes)	6.32	6.22	7.74	7.71	28.01
Retail sales in Italy		1.25	1.32	1.42	1.32	5.32
Wholesale sales in Italy		1.42	1.65	1.79	1.58	6.45
Retail sales Rest of Europe		0.50	0.56	0.59	0.54	2.19
Wholesale sales Rest of Europe		0.41	0.48	0.57	0.48	1.94
Wholesale sales outside Europe		0.13	0.13	0.13	0.14	0.53
Other markets		2.61	2.08	3.24	3.65	11.58

	I quarter	II quarter	III quarter	IV quarter
(kbbl/d)	780	740	707	776	751
(mmcf/d)	4,638	4,447	4,583	4,426	4,523
(kboe/d)	1,662	1,586	1,578	1,617	1,610
	84	82	81	80	82
	214	180	181	182	189
	240	270	268	291	267
	358	353	343	328	346
	284	283	316	273	289
	164	108	81	150	126
	181	174	171	171	174
	124	125	127	135	127
	13	11	10	7	10
(mmboe)	136.0	134.7	127.7	133.6	532.0
(bcm)	16.71	12.11	12.02	14.26	55.10
	1.55	1.27	1.31	1.29	5.42
	18.26	13.38	13.33	15.55	60.52
	3.42	0.95	0.61	1.86	6.84
(TWh)	5.10	4.49	4.77	4.43	18.79
	5.73	5.61	5.96	5.07	22.37
(mmtonnes)	6.10	7.22	7.25	7.22	27.79
	1.20	1.35	1.46	1.38	5.39
	1.32	1.60	1.71	1.55	6.18
	0.48	0.52	0.58	0.53	2.11
	0.55	0.64	0.65	0.60	2.44
	0.13	0.11	0.14	0.13	0.51
	2.42	3.00	2.71	3.03	11.16

2021		I quarter	II quarter	III quarter	IV quarter
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
Italy		99	65	82	87	83
Rest of Europe		238	172	213	228	213
North Africa		272	247	266	264	262
Egypt		355	371	364	348	360
Sub-Saharian Africa		310	293	316	321	310
Kazakhstan		153	147	119	165	146
Rest of Asia		148	169	201	190	177
Americas		112	116	111	119	115
Australia and Oceania		17	17	16	15	16
Hydrocarbons production sold	(mmboe)	139.9	136.7	140.7	149.4	566.7
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 concumption		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
Retail and business gas sales		3.52	1.08	0.63	2.62	7.85
Retail and business power sales to end customers	(TWh)	3.66	3.89	4.22	4.72	16.49
Power sales in the open market		6.42	6.55	7.83	7.74	28.54
Sales of refined products	(mmtonnes)	6.56	6.55	7.53	7.33	27.97
Retail sales in Italy		1.04	1.27	1.45	1.36	5.12
Wholesale sales in Italy		1.29	1.46	1.70	1.57	6.02
Retail sales Rest of Europe		0.43	0.52	0.62	0.54	2.11
Wholesale sales Rest of Europe		0.54	0.43	0.59	0.63	2.19
Wholesale sales outside Europe		0.12	0.13	0.13	0.14	0.52
Other markets		3.14	2.74	3.04	3.09	12.01

2020		I quarter	II quarter	III quarter	IV quarter
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
Italy		112	106	105	103	107
Rest of Europe		256	243	224	228	237
North Africa		252	258	253	264	257
Egypt		303	266	290	304	291
Sub-Saharian Africa		372	386	369	347	368
Kazakhstan		174	167	144	168	163
Rest of Asia		193	173	172	167	176
Americas		110	114	127	114	117
Australia and Oceania		18	16	17	18	17
Hydrocarbons production sold	(mmboe)	144.7	143.8	142.6	144.1	575.2
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 concumption		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
Retail and business gas sales		3.63	0.88	0.66	2.51	7.68
Retail and business power sales to end customers	(TWh)	3.28	2.74	3.07	3.40	12.49
Power sales in the open market		6.50	5.60	6.65	6.58	25.33
Sales of refined products	(mmtonnes)	6.64	5.85	7.42	6.18	26.09
Retail sales in Italy		1.12	0.89	1.41	1.14	4.56
Wholesale sales in Italy		1.51	1.16	1.58	1.50	5.75
Retail sales Rest of Europe		0.52	0.43	0.61	0.49	2.05
Wholesale sales Rest of Europe		0.57	0.59	0.63	0.61	2.40
Wholesale sales outside Europe		0.12	0.11	0.12	0.13	0.48
Other markets		2.80	2.67	3.07	2.30	10.85

ENERGY CONVERSION TABLE

OIL				(average reference density 32.35 f API, relative density 0.8636)
1 barrel	(bbl)	158.987 l oil(a)	0.159 m3 petrolio	162.602 m3 gas		5,232 ft3 gas
				5,800,000 btu
1 barrel/d	(bbl/d)	~50 t/y
1 cubic meter	(m3 )	1,000 l oil	6.75 bbl	1,033 m3 gas		36,481 ft3 gas
1 tonne oil equivalent	(toe)	1,160.49 l oil	7.299 bbl	1.161 m3 petrolio	1,187 m3 gas	41,911 ft3 gas

GAS

1 cubic meter	(m3 )	0.976 l oil	0.00675 bbl	35,314.67 btu		35,315 ft3 gas
1.000 cubic feet	(ft3 )	27.637 l oil	0.1742 bbl	1,000,000 btu	27.317 m3 gas	0.02386 toe
1.000.000 British thermal unit	(btu)	27.4 l oil	0.17 bbl	0.027 m3 oil	28.3 m3 gas	1,000 ft3 gas
1 tonne LNG	(tGNL)	1.2 toe	8.9 bbl	52,000,000 btu		52,000 ft3 gas

ELECTRICITY

1 megawatthour=1.000 kWh	(MWh)	93.532 l oil	0.5883 bbl	0.0955 m3 oil	94.488 m3 gas	3,412.14 ft3 gas
1 terajoule	(TJ)	25,981.45 l oil	163.42 bbl	25.9814 m3 oil	26,939.46 m3 gas	947,826.7 ft3 gas
1.000.000 kilocalories	(kcal)	108.8 l oil	0.68 bbl	0.109 m3 oil	112.4 m3 gas	3,968.3 ft3 gas

(a) l oil: liters of oil

	kilogram (kg)	pound (lb)	metric ton (t)
kg	1	2.2046	0.001
lb	0.4536	1	0.0004536
t	1,000	22,046	1

CONVERSION OF LENGTH

	meter (m)	inch (in)	foot (ft)	yard (yd)
m	1	39.37	3.281	1.093
in	0.0254	1	0.0833	0.0278
ft	0.3048	12	1	0.3333
yd	0.9144	36	3	1

CONVERSION OF VOLUMES

	cubic foot (ft3 )	barrel (bbl)	liter (lt)	cubic meter (m3 )
ft3	1	0	28.32	0.02832
bbl	5.232	1	159	0.158984
l	0.035315	0.00675	1	0.001
m3	35.31485	6.75	103	1

Eni SpA

Headquarters

Piazzale Enrico Mattei, 1 - Rome - Italy Capital Stock as of December 31, 2023: € 4,005,358,876.00 fully paid Tax identification number 00484960588

Branches

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Contacts

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Investor Relations

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Layout and supervision K-Change - Rome

Tipografia Facciotti – Rome

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Eni

4348_rns_2024-05-15_c91ba722-97d1-493b-8bd1-c3d792618ed8.pdf

Global goals for a sustainable development

Eni Fact Book 2023

Disclaimer

2023 at a glance

2023 HIGHLIGHTS

STRATEGIC MILESTONES

GENG NORTH DISCOVERY

NEPTUNE ACQUISITION

PLENITUDE

ENILIVE LAUNCH

NOVAMONT ACQUISITION

CCS

STRONG EARNINGS

NATURAL RESOURCES

Main data

KEY FINANCIAL DATA

KEY MARKET INDICATORS

SELECTED OPERATING DATA

SHARE DATA

SHARE INFORMATION

DATA ON ENI SHARE PLACEMENT

ENI SHARE PRICE IN MILAN (December 31, 2020 - May 3, 2024)

ENI ADR PRICE IN NEW YORK (December 31, 2020 - May 3, 2024)

SHAREHOLDERS DISTRIBUTION BY GEOGRAPHIC AREA(a) (%)

TOTAL SHAREHOLDER RETURN (TSR)* (Eni vs. Peer Group and benchmark Stock Exchange indexes)

DIVIDEND PER SHARE

NATURAL RESOURCES

Exploration & Production Global Gas & LNG Portfolio

Exploration & Production

KEY PERFORMANCE INDICATORS

ACTIVITY AREAS

Italy

Adriatic and Ionian Seas

Central Southern Apennines

Sicily

Rest of Europe

Norway

United Kingdom

North Africa

Algeria

Libya

Tunisia

Egypt

The LNG business in Egypt

Sub-Saharan Africa

Angola

Congo

Côte d'Ivoire

Ghana

Mozambique

Nigeria

Blocks OMLs 60, 61, 62 and 63

Blocks OML 118

Blocks OML 125

SPDC joint venture (NASE)

The LNG business in Nigeria

Kazakhstan

Kashagan

Karachaganak

Rest of Asia

Indonesia

Iraq

Qatar

Timor Leste

Turkmenistan

United Arab Emirates

Americas

Mexico

United States

Gulf of Mexico

Alaska

Venezuela

Australia and Oceania

Australia

Movements in net proved hydrocarbons reserves

Movements in net proved liquids reserves

Hydrocarbons production(a)(b)