Eni

Investor Presentation • May 10, 2023

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.

2022 AT A GLANCE	2
Main data	4
Eni share performance	7
NATURAL RESOURCES	9
Exploration & Production	10
Global Gas & LNG Portfolio	63
ENERGY EVOLUTION	71
Refining & Marketing and Chemicals	72
Refining & Marketing	73
Chemicals	84
Plenitude & Power	89
Environmental activities	96
ANNEX	99
Tables	100
Financial Data	100
Employees	115
Quarterly information	116

Disclaimer

Eni's Fact Book is a supplement to Eni's Annual Report and is designed to provide supplemental financial and operating information. It contains certain forward-looking statements regarding capital expenditures, dividends, buy-back programs, allocation of future cash flow from operations, financial structure evolution, future operating performance, targets of production and sale growth and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including: possible evolution in respect of the conflict between Russia and Ukraine, the impact of the pandemic disease; 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.

2022 at a glance

ACHIEVEMENTS

Hydrocarbon production at 1.61 mln boe/d

Côte d'Ivoire Baleine FID

start-up

LNG Mozambique Coral start-up Congo LNG FID

50% Russian gas replacement mainly from North Africa

UPSTREAM/GGP EXPLORATION DOWNSTREAM AGRIHUB

~750 mboe discovered resources mainly in Côte d'Ivoire, Cyprus, UAE and Algeria

<2 \$/boe Algeria Unit Exploration Cost Berkine South

Refining plant reliability and process optimization

Achieved the target of "palm oil free"

SAF production started

Porto Marghera transformation ongoing

Increased share in Novamont

Agribusiness vs. biorefineries vertical integration

First biofeedstock cargoes from Kenya

Sustainable crops and local development

OUTSTANDING FINANCIAL PERFORMANCE

€20.4 bln EBIT strong contributions from E&P, GGP and R&M business line

€2.6 bln PROFIT FROM ASSOCIATES about 50% distributed to Eni through dividends

€20.4 bln CFFO covering capex, acquisitions and shareholders remuneration. Surplus allocated to debt reduction

€13.3 bln NET PROFIT ~3X FY 2021

€8.2 bln CAPEX in line with guidance, at constant FX

13% LEVERAGE net debt at €7 bln; leverage at historical low

DIVIDEND & BUYBACK

€0.88 €/share €2.4 bln of stock repurchases 27% of CFFO

Norway Vår Energi IPO

Algeria aquisition of bp assets

Congo Tango FLNG acquisition

Angola start-up of Azule JV

SPAC NEOA IPO

€8.2 bln CAPEX

13% LEVERAGE

€0.88 €/share

27% of CFFO

DIVIDEND & BUYBACK

€2.4 bln of stock repurchases

in line with guidance, at constant FX

net debt at €7 bln; leverage at historical low

Renewable 2x installed capacity

Retail Resilient in a challenging environment

E-mobility Fast growing network

PORTFOLIO PLENITUDE CARBON CAPTURE AND STORAGE

CCS HyNet Project in UK to decarbonize the Bacton and Thames Estuary area

Ravenna CCS Project

Eni and Snam JV formed to perform the pilot stage of the Ravenna hub

DECARBONIZATION TARGETS

Methane emissions

intensity was 0.08% in line with the commitment to keep below 0.2%

-35% by 2030 -80%by 2040 in Eni Net GHG Lifecycle Emissions (Scope 1+2 +3) vs. 2018

-33% 2022 vs. 2018 in Net Carbon Footprint Upstream Scope 1+2

CASHFLOW ALLOCATION (€ BLN)

Main data

KEY FINANCIAL DATA

(€ million)	2022	2021	2020	2019	2018
Sales from operations	132,512	76,575	43,987	69,881	75,822
of which: Exploration & Production	31,200	21,742	13,590	23,572	25,744
Global Gas & LNG Portfolio	48,586	20,843	7,051	11,779	14,807
Refining & Marketing and Chemicals	59,178	40,374	25,340	42,360	46,483
Plenitude & Power	20,883	11,187	7,536	8,448	8,218
Corporate and other activities	1,879	1,698	1,559	1,676	1,588
Consolidation adjustments	(29,214)	(19,269)	(11,089)	(17,954)	(21,018)
Operating profit (loss)	17,510	12,341	(3,275)	6,432	9,983
of which: Exploration & Production	15,908	10,066	(610)	7,417	10,214
Global Gas & LNG Portfolio	3,730	899	(332)	431	387
Refining & Marketing and Chemicals	460	45	(2,463)	(682)	(501)
Plenitude & Power	(825)	2,355	660	74	340
Corporate and other activities	(1,901)	(816)	(563)	(688)	(668)
Impact of unrealized intragroup profit elimination	138	(208)	33	(120)	211
Operating profit (loss)	17,510	12,341	(3,275)	6,432	9,983
Exclusion of special items	3,440	(1,186)	3,855	2,388	1,161
Exclusion of inventory holding (gains) losses	(564)	(1,491)	1,318	(223)	96
Adjusted operating profit (loss)(a)	20,386	9,664	1,898	8,597	11,240
of which: Exploration & Production	16,411	9,293	1,547	8,640	10,850
Global Gas & LNG Portfolio	2,063	580	326	193	278
Refining & Marketing and Chemicals	1,929	152	6	21	360
Plenitude & Power	615	476	465	370	262
Corporate and other activities	(622)	(593)	(507)	(602)	(583)
Impact of unrealized intragroup profit elimination and consolidation adjustments	(10)	(244)	61	(25)	73
Net profit (loss)(b)	13,887	5,821	(8,635)	148	4,126
Adjusted net profit (loss)(a)(b)	13,301	4,330	(758)	2,876	4,583
Net cash flow from operating activities	17,460	12,861	4,822	12,392	13,647
Capital expenditure	8,056	5,234	4,644	8,376	9,119
Shareholders' equity including non-controlling interests at year end	55,230	44,519	37,493	47,900	51,073
Net borrowings at year end before IFRS 16	7,026	8,987	11,568	11,477	8,289
Net borrowings at year end after IFRS 16	11,977	14,324	16,586	17,125	n.a.
Leverage before lease liability ex IFRS 16	0.13	0.20	0.31	0.24	0.16
Leverage after lease liability ex IFRS 16	0.22	0.32	0.44	0.36	n.a.
Net capital employed at year end	67,207	58,843	54,079	65,025	59,362
of which: Exploration & Production	50,910	48,014	45,252	53,358	50,358
Global Gas & LNG Portfolio	672	(823)	796	1,327	1,742
Refining & Marketing and Chemicals	9,302	9,815	8,786	10,215	6,960
Plenitude & Power	7,486	5,474	2,284	1,787	1,869

(a) Non-GAAP measures.

(b) Attributable to Eni's shareholders.

KEY MARKET INDICATORS

		2022	2021	2020	2019	2018
Average price of Brent dated crude oil in U.S. dollars(a)	(\$/barrel)	101.19	70.73	41.67	64.30	71.04
Average EUR/USD exchange rate(b)		1.053	1.183	1.142	1.119	1.181
Average price of Brent dated crude oil	(€/barrel)	96.09	59.80	36.49	57.44	60.15
Standard Eni Refining Margin (SERM)(c)	(\$/barrel)	8.5	(0.9)	1.7	4.3	3.7
TTF	(€/kcm)	1,279	486	100	142	243
PSV		1,294	487	112	171	260

(a) Source: Platt's Oilgram. (b) Source: ECB.

(c) Source: Eni calculations. Approximates the margin of Eni's refining system in consideration of material balances and refineries' product yields.

SELECTED OPERATING DATA(a)

		2022	2021	2020	2019	2018
Employees at year end	(number)	32,188	32,689	31,495	32,053	31,701
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.41	0.34	0.36	0.34	0.35
of which: employees		0.29	0.40	0.37	0.21	0.37
contractors		0.47	0.32	0.35	0.39	0.34
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	39.39	40.08	37.76	41.20	43.35
Indirect GHG emissions (Scope 2)		0.79	0.81	0.73	0.69	0.67
Indirect GHG emissions (Scope 3) from use of sold products(b)		164	176	185	204	203
Net Carbon footprint Eni (Scope 1+2)		29.9	33.6	33.0	37.6	37.2
Net GHG Lifecycle Emissions (Scope 1+2+3)(c)		419	456	439	501	505
Net Carbon Intensity (Scope 1+2+3)	(gCO2 eq./MJ)	66	67	68	68	68
Carbon efficiency index (Scope 1+2)	(tonnes CO2 eq./kboe)	32.67	31.95	31.64	31.41	33.90
Direct methane emissions (Scope 1)	(ktonnes CH4 )	49.6	54.5	55.9	65.3	104.1
Total volume of oil spills (> 1 barrel)	(barrels)	6,139	4,408	6,824	7,265	6,687
of which: due to sabotage		5,253	3,053	5,866	6,245	4,022
operational		886	1,355	958	1,033	2,665
Freshwater withdrawals	(mmcm)	131	125	113	128	117
Reinjected production water	(%)	59	58	53	58	60
R&D expenditure	(€ million)	164	177	157	194	197
Patent application first filings	(number)	23	30	25	34	43

Exploration & Production		2022	2021	2020	2019	2018
Employees at year end	(number)	8.689	9,409	9,815	10,272	10,448
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.35	0.25	0.28	0.33	0.30
Net proved reserves of hydrocarbons	(mmboe)	6,614	6,628	6,905	7,268	7,153
Average reserve life index	(years)	11.3	10.8	10.9	10.6	10.6
Hydrocarbon production	(kboe/d)	1,610	1,682	1,733	1,871	1,851
Organic reserve replacement ratio	(%)	47	55	43	92	100
Profit per boe(d)(f)	(\$/boe)	9.8	4.8	3.8	7.7	6.7
Opex per boe(e)		8.4	7.5	6.5	6.4	6.8
Finding & Development cost per boe(e)(f)		24.3	20.4	17.6	15.5	10.4
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	21.5	22.3	21.1	22.8	24.1
Direct GHG emissions (Scope 1)/operated hydrocarbon gross production(g)	(tonnes CO2 eq./kboe)	20.6	20.2	20.0	19.6	21.4
Net Carbon Footprint upstream (Scope 1+2)(c)	(mmtonnes CO2 eq.)	9.9	11.0	11.4	14.8	14.8
Volumes of hydrocarbon sent to routine flaring	(billion Sm³)	1.1	1.2	1.0	1.2	1.4
Methane Intensity (upstream)	(%)	0.08	0.09	0.09	0.10	0.16
Operational oil spills (> 1 barrel)	(barrels)	845	436	882	985	1,595

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

(b) Category 11 of GHG Protocol Corporate Value Chain (Scope 3) Standard. Based on upstream production, Eni's share, consistently with IPIECA methodologies.

(c) Calculated on equity bases.

(d) Related to consolidated subsidiaries.

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

(g) Hydrocarbon gross production from fields fully operated by Eni (Eni's interest 100%) amounting to xx mmboe; 1,041 mmboe and 1,009 mmboe in 2022, 2021 and 2020, respectively.

Global Gas & LNG Portfolio		2022	2021	2020	2019	2018
Employees at year end	(number)	870	847	700	711	734
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.00	0.00	1.15	0.56	0.51
Natural gas sales	(bcm)	60.52	70.45	64.99	72.85	76.60
of which: Italy		30.67	36.88	37.30	37.98	39.17
outside Italy		29.85	33.57	27.69	34.87	37.43
LNG sales		9.4	10.9	9.5	10.1	10.3
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	2.09	1.01	0.36	0.25	0.62

Refining & Marketing and Chemicals		2022	2021	2020	2019	2018
Employees at year end	(number)	13,132	13,072	11,471	11,626	11,457
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.81	0.80	0.80	0.27	0.56
Biorefinery capacity	(mmtonnes/year)	1.1	1.1	1.1	1.1	0.4
Sold production of biofuels	(ktonnes)	428	585	622	256	219
Retail market share in Italy	(%)	21.7	22.2	23.2	23.6	24.0
Retail sales of petroleum products in Europe	(mmtonnes)	7.50	7.23	6.61	8.25	8.39
Service stations in Europe at year end	(number)	5,243	5,314	5,369	5,411	5,448
Average throughput of service stations in Europe	(kliters)	1,587	1,521	1,390	1,766	1,776
Balanced capacity of refineries (Eni's share)	(kbbl/d)	528	548	548	548	548
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	6.00	6.72	6.65	7.97	8.19
SOx emissions (sulphur oxide)	(ktonnes SO2 eq.)	2.34	2.67	2.78	4.16	4.80
Direc GHG emissions (Scope 1)/Refinery throughputs (raw and semi-finished materials)	(tonnes CO2 eq./ktonnes)	233	228	248	248	253
Production of petrochemical products	(ktonnes)	6,775	8,476	8,073	8,068	9,483
Sales of petrochemical products		3,676	4,451	4,339	4,295	4,946
Average petrochemical plant utilization rate	(%)	59	66	65	67	76

Plenitude & Power		2022	2021	2020	2019	2018
Employees at year end	(number)	2,794	2,464	2,092	2,056	2,056
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.31	0.29	0.32	0.62	0.60
Retail and business gas sales	(bcm)	6.84	7.85	7.68	8.62	9.13
Retail and business power sales to end customers	(TWh)	18.77	16.49	12.49	10.92	8.39
Thermoelectric production		21.37	22.31	20.95	21.66	21.62
Power sales in the open market		22.37	28.54	25.34	28.28	28.54
EV charging points(a)	(thousand)	13.1	6.2	3.4	n.a.	n.a.
Installed capacity from renewables at period end	(MW)	2,198	1,137	335	174	40
Energy production from renewable sources	(GWh)	2,553	986	340	61	12

(a) 2020 proforma figure is disclosed for comparative purpose.

SHARE DATA

		2022	2021	2020	2019	2018
Net profit (loss)(a)(b)	(€)	3.95	1.60	(2.42)	0.04	1.15
Dividend pertaining to the year		0.88	0.86	0.36	0.86	0.83
Dividend to Eni's shareholders pertaining to the year(c)	(€ million)	3,077	3,055	1,286	3,078	2,989
Cash dividend to Eni's shareholders		3,009	2,358	1,965	3,018	2,954
Cash flow(a)	(€)	5.01	3.61	1.35	3.45	3.79
Dividend yield(d)	(%)	6.5	7.1	4.2	6.3	5.9
Net profit (loss) per ADR(a)(b)(e)	(\$)	8.32	3.78	(5.53)	0.09	2.72
Dividend per ADR(e)		1.84	1.92	0.86	1.89	1.89
Cash flow per ADR(a)(e)	(%)	10.55	8.54	3.08	7.72	8.95
Dividend yield per ADR(d)(e)		6.5	7.1	4.2	6.3	5.9
Number of shares outstanding at period-end(f)	(million)	3,345.4	3,539.8	3,572.5	3,572.5	3,601.1
Weighted average number of shares outstanding(f)		3,483.6	3,566.0	3,572.5	3,592.2	3,601.1
Total Shareholders Return (TSR)	(%)	16.2	52.4	(34.1)	6.7	4.8

(a) Fully diluted. Calculated on the average number of Eni shares outstanding during the year.Dollars 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.

(c) The amount of dividend for the year 2022 is based on the Board's proposal.

(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

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

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

(b) Excluding treasury shares. (c) Number of outstanding shares by reference price at period end.

DATA ON ENI SHARE PLACEMENT

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

(a) Refers to share capital at December 31, 2021.

CLASS OF SHAREHOLDERS(a)

Dividend (€/share) (*) Refer to: BP, Chevron, Repsol, ExxonMobil, Shell and TotalEnergies. Eni's Dividend yield (%) Dividend yield - average of Oil & Gas petroleum companies(*) (%) 0.80 0.83 0.86 0.86 0.36 2017 2018 2019 2020 2021 0.88 2022 3.8 5.7 6.5 5.9 6.3 7.1 5.4 5.6 5.1 4.2 7.7 5.0 DIVIDEND PER SHARE

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

• TSR average stock market indices (%)
• TSR Ftse Mib (%)
• TSR Eni (%)
• TSR average Peer Group (%)

NATURAL RESOURCES

Exploration & Production Global Gas & LNG Portfolio

Exploration & Production

KEY PERFORMANCE INDICATORS		2022	2021	2020	2019	2018
Total recordable injury rate (TRIR)	(total recordable injuries/worked hours) x 1,000,000	0.35	0.25	0.28	0.33	0.30
of which: employees		0.12	0.09	0.18	0.18	0.29
contractors		0.42	0.30	0.31	0.37	0.30
Sales from operations(a)	(€ million)	31,200	21,742	13,590	23,572	25,744
Operating profit (loss)		15,908	10,066	(610)	7,417	10,214
Adjusted operating profit (loss)		16,411	9,293	1,547	8,640	10,850
Adjusted net profit (loss)		10,776	5,543	124	3,436	4,955
Capital expenditure		6,362	3,861	3,472	6,996	7,901
Profit per boe(b)(c)	(\$/boe)	9.8	4.8	3.8	7.7	6.7
Opex per boe(d)		8.4	7.5	6.5	6.4	6.8
Cash Flow per boe		29.6	20.6	9.8	18.6	22.5
Finding & Development cost per boe(c)(d)		24.3	20.4	17.6	15.5	10.4
Average hydrocarbons realizations		73.98	51.49	28.92	43.54	47.48
Hydrocarbons production(d)	(kboe/d)	1,610	1,682	1,733	1,871	1,851
Net proved hydrocarbon reserves	(mmboe)	6,614	6,628	6,905	7,268	7,153
Reserves life index	(years)	11.3	10.8	10.9	10.6	10.6
Organic reserves replacement ratio	(%)	47	55	43	92	100
Employees at year end	(number)	8,689	9,409	9,815	10,272	10,448
of which: outside Italy		5,497	6,045	6,123	6,781	6,971
Direct GHG emissions (Scope 1)(e)	(mmtonnes CO2 eq.)	21.5	22.3	21.1	22.8	24.1
GHG emissions (Scope 1)/operated hydrocarbon gross production(e)(f)	(tonnes CO2 eq./kboe)	20.6	20.2	20.0	19.6	21.4
Methane emission intensity(e) (m³CH4 /m³ gas sold)	(%)	0.08	0.09	0.09	0.10	0.16
Volumes of hydrocarbon sent to routine flaring(e)	(billion Sm³)	1.1	1.2	1.0	1.2	1.4
Net carbon footprint upstream (Scope 1+2)(g)	(mmtonnes CO2 eq.)	9.9	11.0	11.4	14.8	14.8
Operational oil spills (>1 barrel)(e)	(barrels)	845	436	882	988	1,595
Re-injected production water(e)	(%)	59	58	53	58	60

(a) Before elimination of intragroup sales.

(b) Related to consolidated subsidiaries. (c) Three-year average.

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

(e) Calculated on 100% operated assets. (f) Hydrocarbon gross production from fields fully operated by Eni (Eni's interest 100%) amounting to 980 mmboe, 1,041 mmboe, 1,009 mmboe and 1,114 mmboe in 2022, 2021, 2020 and 2019, respectively.

(g) Calculated on equity basis.

2022 marked a year of substantial progress. The Exploration & Production segment reported excellent performance and progressed to invest in the energy transition, founded on proprietary technologies, satellite model and stakeholders alliances.

In particular, gas reservoir and storage technologies are being used to develop, in synergy with depleted fields, effective solutions for CO2 underground storage. A first deployment is planned in UK to build the HyNet storage hub, which will leverage Eni's depleted Liverpool Bay fields, to start storing CO2 in 2025. In 2024, a CCS pilot project is expected to start-up off Ravenna, Italy, in joint venture with Snam, to evaluate the feasibility of a large high potential CCS hub, that will leverage Eni's depleted fields and infrastructures in the area. In the decarbonization path, Eni plans to offset its residual emissions by leveraging on the Natural Climate Solutions initiatives and the technological applications in different areas to progressively maximize the carbon removal. In July 2022, the first agri-hub was launched in Kenya. Africa will increasingly become part of a vertically integrated supply chain of biorefineries,

supplying bio-oil from raw materials grown in unproductive land, with important, positive effects on local employment and income. This development model will be applied to other African Countries as well as to Italy in cooperation with Bonifiche Ferraresi.

In 2022, significant progress was made in pursuing Eni's distinctive satellite model of creating independent entities focused on defined areas. In upstream business these entities will continue to bring new volumes to the market for energy security, while freeing additional capital and delivering dividends that allow the Group to optimize investments in its decarbonized energy portfolio. Following the success of the Vår Energi transaction through its listing at the Norway exchange and entry of new investors, in August Azule Energy, the JV combining Eni and bp asset in Angola, started operations to deliver real value to its shareholders through the development of organic projects and the maximization of operating synergies.

The exploration is still a distinctive competence of Eni and is a strategic pillar of decarbonization path. It plays a dual role: replacing produced reserves and granting energy supplies that Eni will need in the transition phase and aligning our portfolio of resources to the production mix target and to medium/long-term emission profiles consistent with net zero target. Exploration confirmed its streak of excellent performances with the discovery of around 750 million boe of new resources, at a competitive unit cost of less than 2 \$/boe, thanks to the contribution of the Baleine appraisal and new discoveries in Cyprus, Algeria, Egypt, Angola, and the United Arab Emirates.

The reduction of reserves' time-to-market is the other great driver for the upstream value creation. The development phase creates value thanks to the integration with the exploration phase to maximize synergies with existing assets, the parallelization of activities and the fast-track approach including the start-up in early production and the subsequent ramp-up to reduce financial exposure. Leveraging this model, in 2022 production start-up was achieved in Algeria in the Berkine area, Coral in Mozambique, first production start-up in the Country, and in Mexico.

Activity areas

Italy

Eni has been operating in Italy since 1926. In 2022, Eni's oil and gas production amounted to 82 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 12,959 square kilometers (10,884 square kilometers net to Eni). Eni's production activities in Italy are regulated by concession contracts (24 operated onshore and 49 operated offshore).

Adriatic and Ionian Seas

Adriatic and Ionian Seas Main fields are Angela, Annamaria, Barbara, Bonaccia, Clara NW (Eni's interest 51%), Luna and Hera Lacinia and related satellites. Those fields accounted for 23% of Eni's domestic production in 2022, mainly gas. 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 Bonaccia, Arianna and Basil offshore fields; and (ii) decommissioning plan to plug-in depleted wells and to remove idle platforms progressed in the year in compliance with Italian Ministerial Decree February 15, 2019 "Linee guida nazionali per la dismissione mineraria delle piattaforme per la coltivazione in mare e delle infrastrutture connesse". The decommissioning process is ongoing as required by the Ministerial Decree for the first 10 platforms.

Within Eni's strategy to minimize carbon footprint, a program was launched to build a hub for the capture and storage of CO2 (Carbon Capture and Storage - CCS) in depleted fields off the coast of Ravenna with a potential CO2 store capacity of 500 million tonnes/year. The development program includes a Phase 1 of project to build a CCS plant to storage 25 ktonnes/year of CO2 from 2024. In December 2022 Phase 1 was sanctioned. By 2026, Phase 2 will start the industrial scale up with a storage injection of 4 million tonnes/year.

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 2022 the Val d'Agri concession accounted for approximately 49% of Eni's domestic production.

Development Activities concerned sidetrack activities based on the approved "Work Program". Optimization activities progressed to counteract the natural fields production decline.

In 2022 the Energy Valley project activities progressed and concerned certain initiatives with the support of local stakeholders, in the area nearby at the Val d'Agri Oil Center, relating to environmental sustainability, innovation, rehabilitation and enhancement of the area. In particular: (i) the agricultural rehabilitation programs through the "Agricultural Center for Experimentation and Training" project with sustainable agricultural initiatives and experimental crops; and (ii) training activities also by means of the partnership agreement with the CNH industrial company in the farm mechanization; and (iii) biomonitoring programs with innovative techniques.

In June 2022 Eni, Shell and the Basilicata Region, signed a Memorandum of Intent for a sustainable development of the ten-year program at the Val d'Agri concession. The agreement provides for: (i) energy transition and circular economy projects; (ii) development initiatives to enhance the area and socio-economic, cultural and environmental programs; and (iii) partnerships and networks developments with local and national stakeholders as well as local resources.

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 2022 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 gas treatment plant progressed at the Argo and Cassiopeia development project (Eni's interest 60%). The project will be developed in about 3 years with an investment of over €800 million. The onshore and offshore project facilities will speed up the development of any additional production resulting from the exploratory programs following the regulatory update to relaunch domestic natural gas production. 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 were launched to create a food storage and distribution center for disadvantaged communities.

REST OF EUROPE

Norway

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

During 2022, Eni and the private equity fund HitecVision, shareholders of Vår Energi, have finalized the process of listing the investee at the local stock exchange, the largest O&G IPO in Europe in 15 years, placing about a 16.2% interest. Following the closing Eni's interest is 63.1%.

Activities are performed in the Norwegian Sea, in the North Sea and in the Barents Sea, on a total developed and undeveloped acreage of 27,512 square kilometers (6,686 square kilometers net to Eni). Eni's production in Norway amounted to 145 kboe/d in 2022.

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 12.62%) in the Norwegian Sea, as well as Balder & Ringhorne (Eni's interest 56.77%) and Ringhorne East (Eni's interest 44.14%) in the North Sea. These fields amounted to approximately 18% of Eni's production in the Country.

In total, Vår Energi holds interests in 36 producing licenses across the Norwegian Continental Shelf, including: Åsgard (Eni's interest 15.41%), Mikkel (Eni's interest 30.51%), 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 9.17%), Statfjord Satellites North (Eni's interest 15.77%), Statfjord Satellites Sygna (Eni's interest 13.25%) and Grane (Eni's interest 17.86%).

In 2022, Vår Energi acquired: (i) 30% and operatorship of the PL820S and PL820 SB production licenses, north of the Balder field in the North Sea. The transaction is pending government approval; and (ii) the 40% stake and operatorship of the PL 917 and PL 917B production licenses, west of the Balder field, through an equity swap with Aker BP in PL 956 and PL 985 licenses. The transaction has been approved by the authorities. These transactions are part of the long-term growth strategy focused on the North Sea hubs and will be included in the further development of the Balder area.

Development Development activities mainly concerned: (i) the Johan Castberg (Eni's interest 18.92%) sanctioned project with start-up expected in 2024; (ii) the Balder X sanctioned project (Eni operator with a 56.77% interest) 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; and (iii) the Breidablikk sanctioned project with start-up in 2024. The project scheme provides for drilling production wells to be linked to existing treatment facilities in the area. Leveraging on high energy and operational efficiency technologies, the project development will minimize direct GHG emissions.

Exploration Exploration activity yielded positive results with the Lupa (Eni's interest 31.54%), Snofonn (Eni's interest 18.92%) and Skavl Sto (Eni's interest 18.92%) discoveries in the Barents Sea, and the Calypso discovery (Eni's interest 12.61%) in the Norwegian Sea.

The mineral interest portfolio increased with twelve exploration licenses (five of which are operated) following the "Awards in Predefined Areas 2022" (APA) by the Ministry of Petroleum and Energy of Norway. The licenses are distributed over the three main sections of the Norwegian continental shelf. The new acquired licenses are located in both nearfields already in production or development areas with high exploration mineral potential.

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 2,199 square kilometers (1,487 square kilometers net to Eni) of which 577 square kilometers related to the CCUS activities in the Country. In 2022, Eni's oil and gas production averaged 44 kboe/d.

Exploration and production activities in the UK are regulated by concession contracts. Activities are underway with the relevant Authorities of the country, in particular with BEIS (Department for Business, Energy & Industrial Strategy) and NSTA (North Sea Transition Authority; former OGA - Oil & Gas Authority) to define the regulatory framework and business model for CCUS projects.

Production Eni holds interests in 3 production areas of which the Liverpool Bay (Eni's interest 100%) is operated. In the two non-operated 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%).

In the year production start-up was achieved at the J-Area with three new development wells as well as at the Jade South recent discovery by means of the linkage to the existing facilities.

Development Development activities mainly concerned: (i) Talbot development project was sanctioned in 2022. Drilling activities start-up are planned during 2023 with first oil in 2024; (ii) work-over program at the Douglas field; and (iii) decommissioning planned activity of the Hewett Area.

Activities progressed at the HyNet North West integrated project where Eni is engaged with a consortium of local industries for the capture, transportation and storage of CO2 emitted by them and for the realization of a low carbon hydrogen production plant in the future. Eni will develop and operate both the onshore and offshore transportation and storage of CO2 in its Liverpool Bay assets. The project has been selected by the UK authorities between the two priority CCS projects of the Track 1 clusters. The HyNet North West project start-up is expected in 2025 with an initial CO2 storage capacity of 4.5 mmtonnes/year, at a later stage from 2030 will be increased to reach 10 mmtonnes/year. The HyNet North West project will support to achieve the decarbonization goals define by the UK Government at 2032. In particular the project will contribute to more than 80% of the CO2 capture and storage target by 2030, as well as with a production of 4 GW will support to achieve the 80% production of low carbon hydrogen target by 2030.

In March 2023, the UK Department for Energy Security and Net Zero (DESNZ) announced the first carbon capture projects that will access the £20 bn in funding provided by the government for Track 1 initiatives, to accelerate the UK's industrial decarbonization: five projects of the HyNet North West consortium have been confirmed in the eight selected projects.

In September 2022, Eni applied to the country's authorities for carbon storage license at the Hewett depleted field in the UK Southern North Sea, for the development of a CCS project aimed at decarbonising the Bacton and Thames Estuary area. To support this application, Eni announces the set-up of the Bacton Thames Net Zero initiative, including more than 10 companies, to decarbonize the energy-intensive and hardto-abate sectors in the area.

Exploration As of December 31, 2022, Eni holds interest in 9 exploration licenses, 6 of these are operated, with interest ranging from 16% to 100%.

NORTH AFRICA

Algeria

Eni has been present in Algeria since 1981. In 2022, Eni's oil and gas production averaged 95 kboe/d. Developed and undeveloped acreage was 18,476 square kilometers (8,720 square kilometers net to Eni). Activities are located in the Bir Rebaa desert, in the Central-Eastern area of the Country in the following operated exploration and production assets: (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 55%); (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 concessions in the Berkine Nord basin (Eni's interest 49%); and (vii) Berkine South block (Eni's interest 75%). In addition, Eni holds interest in the non-operated Block 404 and Block 208 with a 12.25% interest.

In September 2022, signed an agreement to purchase bp's assets in Algeria including the two gas-producing concessions In Amenas and In Salah, located in the southern Sahara Desert. Eni finalized this agreement in February 2023 and acquired a stake of 45.89% and 33.15% in the mentioned concessions, respectively.

During 2022, signed several agreements leveraging Eni's strong relationship with the country to increase and diversified natural gas export flows to Europe as well as other decarbonization initiatives. In particular: (i) in March 2022 awarded a new PSA agreement for the Berkine South Area. The project includes a fast-track development hub for oil and gas production through a synergy with existing assets in block 405b; (ii) in April 2022 signed a Memoradum of Understading to evaluate gas mineral potential and fasttrack development of recent discoveries. Additional natural gas production expected from the agreed areas will increase export capacity of the Transmed pipeline. In addition, the agreement launched a study to assess technical and economic feasibility of a green hydrogen pilot project nearby the BRN gas plant; (iii) in July 2022 a new PSA agreement was signed with the partner of the Blocks 404 and 208. The agreement will support additional investments to develop mineral potential in the area and possible initiative for the development of associated gas volumes; and (iv) in November 2022 the Solar Lab research center was launched to identify the most efficient technologies for the exploitation of solar energy in the country; as well as the activities for the construction of a 10 MW photovoltaic plant in the BRN production area started. The photovoltaic plant will be the second one linked to the BRN facility, to further contribute to decarbonize the facility's hydrocarbon production. In addition, in January 2023, signed a Memorandum of Understanding to study additional opportunities for Algerian gas export capacity increase to Italy and Europe and a second Memorandum of Understanding to identify decarbonization opportunities in the country by means of the greenhouse gas and methane gas emissions reductions as well as CCUS projects, renewable energy developments, energy efficiency initiatives also to monetize associated gas. These activities, in line with Eni's net zero strategy, are part of a wider-ranging decarbonization plan that also includes venting monitoring and zero routine flaring and energy efficiency projects.

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

BLOCKS 403A/D AND ROM NORTH

Production In 2022 production comes mainly from the HBN, ROMN and ROM and satellites fields and represented approximately 12% of Eni's production in Algeria. Production from ROMN, ROM and satellites (ZEA, ZEK and REC) is treated at the ROM Central Production Facilities (CPF) and sent to the BRN treatment plant for final treatment, while production from the HBN field is treated at the HBNS oil center operated by the Groupment Berkine.

Development During 2022, production optimization by means of work-over and rigless activities were carried out in the area.

BLOCKS 401A/402A

Production In 2022 production comes mainly from the ROD/

SFNE and satellites fields and accounted for approximately 22% of Eni's production in Algeria.

Development During 2022, production optimization by means of work-over activities were carried out in the area.

BLOCK 405B

Production In 2022 production comes from the MLECAFC project and accounted for approximately 7% of Eni's production in the Country. Four export pipelines link it to the national grid system.

Development In the year, activities concerned ongoing development program of the CAFC project.

BLOCK 403

Production The main fields are BRN, BRW and BRSW, which accounted for approximately 12% of Eni's production in Algeria in 2022. Production is treated at the MLE plant in the Block 405b.

Development During 2022, production optimization by means of work-over and rigless activities were carried out in the area as well as wells conversion in water-alternate-gas (WAG) injections.

BLOCK 404

Production The main fields are HBN, HBNS and Ourhoud fields, which accounted for approximately 15% of Eni's production in Algeria in 2022.

Development During 2022, production optimization by means of work-over activities were carried out in the area.

BLOCK 208

Production The El Merk field is the main production project in the area and accounted for approximately 12% of Eni's production in Algeria in 2022. Production is treated by means of a gas treatment plant for approximately 600 mmcf/d and two oil trains for 65 kbbl/d each.

Development During 2022, production optimization by means of work-over activities were carried out in the area.

BLOCKS SIF FATIMA II, OURHOUD II AND ZEMLET EL ARBI

Production In 2022 production comes mainly from Berkine North area and accounted for approximately 19% of Eni's production in Algeria. Production is treated at the MLE plant in the Block 405b.

During the year production start-up was achieved with two gas and two oil fields.

Development Development activities concerned the drilling and completion of 4 additional production wells.

Exploration Exploration activities yielded positive results with: (i) the HDLE oil and gas discovery in the Zemlet el Arbi concession; and (ii) the HDLS e RODW oil and associated gas discoveries in the Sif Fatima II. These discoveries will be put into production through fast-track development activities leveraging on the existing production facilities.

Production Production comes from two gas and two oil fields were started up in 2022, just six months from the closing of the contract agreement with a fast-track development. The linkage to treatment plant and the installation of the transport facilities were completed. In 2022 Berkine South accounted approximately 1% of Eni's production in the country. Production is expected to grow in 2023 due to the linkage and drilling of new wells and new fields start-up.

Libya

Eni started operations in Libya in 1959. In 2022, Eni's production amounted to 165 kboe/d. Developed and undeveloped acreage were 80,048 square kilometers (24,644 square kilometers net to Eni).

Exploration and production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area and includes six contractual 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%).

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

Libya is currently exposed to significant geopolitical risks. The social and political instability of the Country date back to the revolution of 2011 that brought a change of regime and a civil war, triggering an uninterrupted period of lack of well-established institutions and recurrent events of internal conflict, clashes, disorders and other forms of civil turmoil and unrest between the two conflicting factions. Latest events of instability date back to the second half of 2021, the opposition between the Government of National Unity installed in Tripoli and the self-appointed National Stability Government installed in the east of the country resumed. This has resulted in hostility acts and disorder that determined the almost total shutdown of oil production in the eastern part of the country and the main export terminals and in April 2022 force majeure affected some assets owned by Eni, revoked in July 2022 thanks to an agreement between the parties. Offshore production (in particular the Bahr Essalam field) and onshore in the Tripoli area continuously were performed. For further information see Annual Report 2022.

In January 2023, Eni signed an agreement with the National Oil Corporation of Libya (NOC) for the development of the large gas reserves of A&E Structures, offshore Tripoli. Production is expected to start in 2026 with volumes destined both to the domestic market and to Europe. The project comprises construction of an onshore Carbon Capture and Storage (CCS) hub, in line with Eni's decarbonization strategy.

In November 2022 farm-out agreement with bp was ratified by relevant authority. The agreement provides for the acquisition of a 42.5% interest and operatorship by Eni in the Ghadames North, Ghadames South and Sirte offshore exploration permits.

During the year activities concerned: (i) initiatives related to reduction GHG emissions progressed, in particular, with the BGUP project to monetize associated gas of the Bouri field. Start-up is expected in 2025; and (ii) 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.

Tunisia

Eni has been present in Tunisia since 1961. In 2022, Eni's production amounted to 7 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 following fields: Maamoura and Baraka offshore operated fields (Eni's interest 49%); Adam (Eni's interest 25%) and Oued Zar (Eni's interest 50%) onshore operated fields; MLD (Eni's interest 50%) and El Borma (Eni's interest 50%) non operated fields.

Exploration Exploration activities yielded positive results with the Anbar-1 exploration commitment well in the Borj El Khadra permit.

EGYPT

Eni has been present in Egypt since 1954. In 2022, Eni's production amounted to 346 kboe/d and accounted for approximately 21% of Eni's total annual hydrocarbon production. Developed and undeveloped acreage was 20,201 square kilometers (7,103 square kilometers net to Eni).

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 and Abu Rudeis fields (Eni's interest 100%); (iii) the Western Desert in the Melehia (Eni's interest 76%) and South West Meleiha (Eni's interest 100%) concessions; and (iv) Baltim (Eni's interest 50%), Nile Delta (Eni's interest 75%), North Port Said (Eni's interest 100%), and Temsah (Eni's interest 50%) concessions. Furthermore, Eni participates in the Ras el Barr (Eni's interest 50%) and South Ghara (Eni's interest 25%) concessions.

In 2022, the portfolio of mineral interest was reloaded with: (i) following the successful participation in the Egypt International Bid Round for Petroleum Exploration and Exploitation 2021, Eni was awarded five exploration licenses, out of which four as operator, for a total acreage of about 8,400 square kilometers. The licenses are distributed in the mining area of greatest interest to Eni, which will allow rapid developments through nearby existing plants. The operation is subjected to be ratified by the relevant authorities; (ii) the award of the operatorship of three concessions in the eastern Mediterranean Sea following the agreement with Ministry of Petroleum and the Egyptian state-owned company EGAS; (iii) the farm-in agreement was finalized in the Nargis Offshore Area with the acquisition of a 45% stake in the license. In January 2023, exploration activities yielded positive results with the Nargis-1 gas discovery. The discovery will be developed by leveraging Eni's existing facilities.

In April 2022 Eni signed a framework agreement with the Egyptian state-owned company EGAS to enhance gas production and LNG exports to Europe, and in particular to Italy, through the Damietta liquefaction plant. In addition, in January 2023 Eni signed a Memorandum of Intent (MoI) with EGAS to launch joint studies on identifying opportunities for the reduction greenhouse gas emissions in the country's upstream sector, through initiatives that will lead to further valorization of natural gas. In addition, during the year a desalination programs were launched in production areas to reduce freshwater withdrawals in line with the principles of the United Nations "CEO Water Mandate" initiative.

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

BLOCK SHOROUK

Production Production comes from the Zohr field which in 2022 achieved the production of approximately 175 kboe/d net to Eni.

Development Development activities of the Zohr project concerned: (i) EPCI activities for the construction of new submarine facilities and two additional treatment unit with a capacity of 6,000 barrels/d to manage and recover production water. The construction of further three units with a capacity of 9,000 barrels/d is being studied; and (ii) development drilling activities with the completion of three additional production wells with start-up in 2022.

Eni progressed its activities to support a just energy transition, in line with Eni's strategy and the country's national development plan. The Zohr development activities includes also several local development initiatives. The defined programs with an overall expense expected in \$20 million until 2024, include three main areas: (i) technical education. In particular the Zohr Applied Technology School (ATS) launched training programs for 528 students. In addition, in October 2022 activities started at the Centre of Excellence for access to employment supporting access to work; (ii) economic diversification. The Youth Empowerment Program implemented training programs for about 400 people and about 4,000 people benefitted of the Youth Center services; (iii) local community's health. In particular, several initiatives implemented to support local healthcare system with equipment for the Port Said hospital, healthcare staff training and about 16,000 people benefitted from health awareness campaigns.

SINAI

Production Production amounted to approximately 61 kbbl/d (51 kbbl/d net to Eni) and mainly comes from the Belayim Marine, Belayim Land and Abu Rudeis fields.

Development Development activities concerned production optimization programs.

Exploration Exploration activities yielded positive results with the Semiramis 1X oil near-field exploration well, already started up.

NORTH PORT SAID

Production In 2022 production amounted to approximately 12 kboe/d (approximately 8 kboe/d net to Eni). Part of the production of this concession is supplied to the United Gas Derivatives Co (Eni's interest 33.33%) with a treatment capacity of 1.3 bcf/d of natural gas and a yearly production of approximately 161 ktonnes of propane, 86 ktonnes of LPG and approximately 1,01 mmbbl of condensates. After condensates extraction the residual gas is fed back into the GASCO national grid.

BALTIM-NEHO

Production In 2022, production amounted to approximately 116 kboe/d (approximately 36 kboe/d net to Eni). During the year unitization agreement was finalized for the Sand-1 field with the North El Hammad (NEHO) concession.

Development Development activities concerned drilling development activities.

NILE DELTA

Production Production comes mainly from the Nidoco NW and satellites fields as part of the Great Nooros Area project, in the Abu Madi West concession (Eni's interest 75%). In 2022 production amounted to approximately 78 kboe/d (approximately 38 kboe/d net to Eni).

Exploration Exploration activities yielded positive results with the El Qara South-1X near-field gas well, already in production.

RAS EL BARR

Production In 2022, the production amounted to approximately 17 kboe/d (approximately 7 kboe/d net to Eni), mainly gas from Ha'py and Seth fields.

EL TEMSAH

Production This concession includes Tuna, Temsah and Denise fields. Production in 2022 amounted to approximately 12 kboe/d (approximately 4 kboe/d net to Eni).

WESTERN DESERT

Production This area includes Meleiha, Meleiha Deep, South West Meleiha, Ras Qattara, West Abu Gharadig, East Kanays and West Razzak concessions. In 2022 production amounted to approximately 43 kboe/d (approximately 21 kboe/d net to Eni).

In 2022 has been completed the disposal of interests in the Ras Qattara (Eni's interest 75%), West Abu Gharadig (Eni's interest 45%), East Kanays (Eni's interest 100%) and West Razzak (Eni's interest 100%) production assets.

Development Development activities concerned: (i) the FID of the Meleiha Phase 2 project was sanctioned. The project was already started up in early production and the completion of the development program is expected in 2024; and (ii) upgrading of the facilities in the Emry Deep and Arcadia fields as well as of the water injection facilities.

Exploration Exploration activities yielded positive results with near-field three oil and natural gas discovery wells in the Meleiha concession. New discoveries were started up by means of the linkage to the existing facilities and already in production.

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 280 bcf/y of feed gas.

SUB-SAHARAN AFRICA

Angola

Eni has been present in Angola since 1980. In August 2022, started operations at Azule Energy, the equally owned joint venture by bp and Eni, with the derecognition of the Group's Angolan operating companies transferred to the JV Azule Energy combines both companies' Angolan upstream, LNG and solar businesses and is Angola's largest independent equity oil and gas producer. Azule is a further example of Eni's distinctive satellite model designed to unlock value. It holds stakes in 16 licences (of which 6 are exploration blocks) and a participation in Angola LNG JV and in Solenova, a solar company jointly held with Sonangol, and will continue the collaboration in the Luanda Refinery. Azule Energy boasts a strong pipeline of new projects that are scheduled to come on stream over the next few years, growing organically from exploration discoveries. The Azule JV also holds significant exploration acreage of over 30,000 square kilometres in Angola's most prolific basins, allowing it to leverage proximity with existing infrastructures. In addition, the new company will create more efficient operations and offer the potential for increased investment and growth in Angola. The business combination confirmed the commitment of both companies to progress in the development of the country's upstream sector and meanwhile to support the energy transition process through natural gas and renewable energy development projects.

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

Production In 2022 production amounted to 110 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 interst 10%) and Block 14K/A IMI (Eni's interest 5%).

In 2022 production start-up was achieved at: (i) the Ndungu Early Production by hooking it up to the Ngoma FPSO. The Ngoma FPSO is designed with treatment capacity of approximately 100 kbbl/d and with zero-water discharge and zero-process flaring to minimize emissions; (ii) the Agogo Early Production Phase 2 in the Block 15/06 with the completion of the development activities and the installation of the required submarine facilities; and (iii) one well started up from Cuica field in the Eastern area of Block 15/06.

Development In July 2022, reached the final investment decision (FID) by partners of the New Gas Consortium for the development of the Quiluma and Maboqueiro fields. The project, the first non-associated gas development in the country, is planned to start-up in 2026 with an expected production plateau at 330 mmcf/d.

Development activities concerned: (i) the definition phases of the Agogo Integrated West Hub for the full development of the western Block 15/06 area by means of the Ngoma and Agogo FPSOs; (ii) the Sanha Lean Gas Connection and Booster Gas Compressor project in Block 0 increasing associated gas production to feed the A-LNG liquefaction plant; and (iii) the FEED activity of the South Ndola e Sanha-Mafumeira connector projects for the construction of transportation facilities to put in production the residual reserves in the area; (iv) programs in the health services in the Luanda area also by means of the electrification of health centers 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 (v) 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 Ndungu-2 delineation well, increasing the resources estimated of the homonymous production field and enhancing its full development.

Congo

Eni has been present in Congo since 1968. In 2022, production averaged 78 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).

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

Production Eni's main operated producing interests are the Néné-Banga Marine and Litchendjili (Block Marine XII, 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 92 kboe/d (69 kboe/d net to Eni) in 2022. 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 27 kboe/d (approximately 9 kboe/d).

Development In April 2022 Eni signed a letter of intent with the Republic of Congo to strength joint operations in the upstream sector targeting to increase natural gas export flows to Europe. Development plans provide for an increase in natural gas production through fast-track projects to monetize the associated and non-associated volumes in the Marine XII block both for the domestic power generation and LNG export, also targeting to support zero routine flaring. The export project consists of modular and phased LNG liquefaction plants with reduced time-to-market. Start-up is expected in 2023 with capacity of approximately 35 BCF/year and approximately 160 BCF/y in 2025.

During 2022 additional development phase of the Néné-Banga field on the Marine XII block was completed with the installation of a new platform resulting production start-up.

During the year activities progressed with: (i) the construction of the Centre of Excellence for Renewable Energy and Energy Efficiency in Oyo; (ii) the Project Integrated Hinda (PIH) to support the socio-economic development of the local communities with education, sanitary service an access to water initiatives; (iii) in the agricultural sector with the CATREP program. In addition, the Agri-feedstock project progressed in the agricultural sector to integrate producers into the biofuels supply chain (see below).

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 2022, production averaged 32 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 reliable gas supply, equal to 65% 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 Activity of the year mainly concerned production optimization and maintenance initiatives.

Exploration Exploration activity yielded positive results with the Aprokuma-1X well in the CTP-4 block.

Ivory Coast

Eni has been present in Ivory Coast since 2015 and activities are concentrated in the offshore of the Country. Eni operates the Exclusive Area Development in the block CI-101 AEE (Eni's interest 83%) and holds operatorship with a 90% interest in other five exploration areas: CI-802, CI-205, CI-501, CI-401 and CI-801 blocks.

Activities mainly focused on the development project of the Baleine field, located in the CI-101 and CI-802 blocks.

In particular, during the year, exploration activities yielded positive results with the Baleine East 1X well in the CI-802 operated block, second discovery on the Baleine structure in the offshore Ivory Coast and allowed an increase in estimated hydrocarbons in place to 2.5 billion barrels of oil and 3.3 Tcf of associated gas.

During 2022 FID of both Phase 1 and 2 development projects was sanctioned. The development of Baleine field is phased and fast-tracked with start-up of Phase 1 in 2023 and Phase 2 at the end of 2024. The phased development approach is defined and agreed with the authorities. The project will be a Scope 1 and 2 net zero developments, the first of this kind in Africa. Carbon neutrality will leverage on certain emission reduction drivers by means of forest conservation (REDD+) and improved cookstoves initiatives. In particular, improved cookstoves project for vulnerable households was launched in June 2022 (see below). In addition a program to support primary education was launched in the Abidjan area.

In April 2023 the FPSO that will allow the production start-up of the the Baleine field sailed away from Dubai to the Ivory Coast.

The Baleine project confirms Eni's commitment to generate value while reducing the carbon footprint and focus to improve the time-to-market of exploration discoveries.

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. In the exploration phase Eni operates with a 49.5% interest the A5-A block and participates with an 10% interest in the A5-B block. In December 2022, Eni was awarded a 60% interest and operatorship of the A6-C exploration block following the participation in the 6th Bid Round. The completion of the relevant oil contract is expected in 2023.

Developed and undeveloped acreage was 14,602 square kilometers (3,868 square kilometers net to Eni).

Production In 2022 production amounted to 6 kboe/d net to Eni following the Coral South project start-up located in the Area 4 block, in the second half of 2022, first production startup in the country to develop gas discovery in the Rovuma offshore area. Start-up was achieved with 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, feed by six subsea wells. The Coral-Sul FLNG was designed to high standards in terms of safety and sustainability. The vessel was implemented with an energy efficiency approach and CO2 emissions reduction. In particular, the Coral Sul FLNG achieves zero flaring during normal operations and uses gas efficient turbines also to power generation. In November 2022, the first loading of liquefied natural gas was shipped from the Coral Sul Floating Liquefied Natural Gas (FLNG) vessel. The Coral South development plan is expected to produce total about 500 bcm of natural gas.

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.

In 2022, Eni's programs to support the local communities of the Country progressed with: (i) programs to support primary and infant education, public healthcare as well as youth employment in the Pemba area; (ii) programs in access to energy also by means of production and distribution of improved cookstoves; and (iii) initiatives in access to fresh water, health and social care programs, biodiversity projects in the Mecufi area.

Nigeria

Eni has been present in Nigeria since 1962. In 2022, 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%), OPL 245 (Eni's interest 50%) and holding interests in OML 118 (Eni's interest 12.5%). 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 2022 the collaboration with the Food and Agriculture Organization (FAO) progressed to foster access to safe and clean water in Nigeria for local communities affected by humanitarian crisis in the north-east areas of Nigeria: (i) in March 2022, Eni and FAO, in partnership with NNPC, completed and delivered 11 water plants powered by photovoltaic systems in Borno and Yobe states in northeastern Nigeria; and (ii) certain maintenance activities have been performed to provide infrastructures reliability and sustainability. Since 2018, start year of program, realized 22 wells powered with photovoltaic systems, both for domestic use and irrigation purposes, to benefit approximately 67,000 people.

During the year the activities in support of the Niger Delta populations, in addition to the Green River Project, concerned several extraordinary intervention programs, such as distribution of essential goods in about 260 communities, following the worst floods in recent years decades that have affected the area. In addition, Eni continues to support reconstruction interventions also by means of the restoration of main access and transport routes to reconnect all the different areas remained isolated.

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 24 kboe/d net to Eni in 2022. 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%). 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 workover and rigless activities to mitigate mature fields decline as well as asset integrity program of the facilities and the installation of new compressor units to monetize additional natural gas volumes and to improve environmental performance by reducing CO2 emissions related to flaring. During the year, additional production well was started up by means of the completion of drilling activity.

BLOCK OML 118

Production The Bonga oil field produced 9 kboe/d net to Eni in 2022. 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 plante.

Development Development activities focused on the drilling of five development wells, of which three wells were completed. Start-up was achieved with one production and one injection wells.

BLOCK OML 125

Production Production derived mainly from the Abo field which yielded approximately 14 kboe/d net to Eni in 2022. Production is supported by an FPSO unit with a 40 kboe/d treatment capacity and over 900 kboe storage capacity.

In August 2022 Eni finalized a twenty-year extension of the PSC agreement for the OML 125 block. In addition, Eni signed an agreement with the State company NNPC to recover past receivables related to the OML 125 development and production activities, starting in 2023.

SPDC JOINT VENTURE (NASE)

Production In 2022, production from the SPDC JV amounted to approximately 16 kboe/d net to Eni.

Development Development activities concerned: (i) restore the Trans Niger Pipeline (TNP) integrity that had been compromised by external interference from third parties. The TNP is the main trunk oil line to the Bonny export terminal. The TNP line was shut down for almost 2022 to address illegal tapping resulting from bunkering activities and the operation of illegal refineries; (ii) five new production gas wells in the Kolo Creek and Gbaran production areas have been linked, and five oil wells have been drilled in the Forcados area to increase oil production; (iii) workover and rigless programs to mitigate mature natural fields decline; and (iv) asset integrity activities.

THE LNG BUSINESS IN NIGERIA

Eni holds 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 2022, the Bonny liquefaction plant processed approximately 830 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 cooperator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA) for the development of the Kashagan field. In addition, Eni cooperates with State company Kaz-MunayGas (KMG) the Isatay block (Eni's interest 50%) and the Abay block (Eni's interest 50%), 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 2022, production averaged 57 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 Current development plans of the Kashagan field envisage a phased increase in the production capacity up to 450 kbbl/d by upgrading the existing associated gas compression facilities. The ongoing activities, sanctioned in 2020, mainly concerned: (i) increasing gas reinjection capacity by means of upgrading the existing facilities. Activities were completed during 2022; and (ii) delivering a part of gas volumes to a new onshore treatment unit operated by a third party, currently under construction.

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 2022, production of the Karachaganak field

averaged 69 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. 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 and the Atyrau-Samara pipeline.

Development During 2022 within the development plan of the Karachaganak field to increase gas re-injection treatment expansion in several phases, the installation and start-up of a fourth gas compression unit was completed. Ongoing development phases, sanctioned in 2020, include: (i) the drilling of three additional injection wells; (ii) a new injection line; and (iii) the installation of a fifth compression gas unit. Start-up is expected in 2024. In addition, in 2022 the last phase for the installation of a sixth compression unit was sanctioned. 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 medicine's distribution.

REST OF ASIA

Indonesia

Eni has been present in Indonesia since 2001. In 2022, Eni's production mainly composed of gas, amounted to 62 kboe/d. 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 18,235 square kilometers (12,106 square kilometers net to Eni); in total, Eni holds interests in 13 blocks.

Exploration and production activities are regulated by 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 longterm 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. The project was approved with the completion of the plan program definition; (ii) the Maha project in the operated West Ganal offshore block (Eni's interest 40%). Plan program definition is ongoing; (iii) upgrading activities of the gas compression facilities in the operated Muara Bakau block; and (iv) the activities and initiatives in the fields of access to water and renewable energy to support the local development areas of Samoja, Kutai Kartanegara and East Kalimantan.

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 31 kbbl/d net to Eni in 2022.

Development Development activities comprised the execution of an additional development phase of the ERP (Enhanced Redevelopment Plan) at the Zubair field, which will allow to achieve a production contractual plateau of 700 kbbl/d. The production capacity and main facilities to treat the production plateau target have already been installed. Activities to increase treatment capacity are ongoing. The field reserves will be progressively put into production by drilling additional productive wells over the next few years by means of the collection facilities expansion and the completion of the water reinjection wells. In particular, projects ensuring water availability to maintain reservoir pressurization are being implemented.

In February 2022, consistently with the sustainable development goals, Eni in collaboration with the European Union and UNICEF, has launched a project in partnership with the Governorate of Basra, aimed at improving quality of water for 850,000 people in the city of Basra, including over 160,000 children as direct beneficiaries.

Eni's commitment continues with projects in the fields of education, health, environment and access to water. In particular: (i) construction activities of a new school in the Zubair area with completion expected in 2024, as well as renovation and material supply initiatives; (ii) construction of a nuclear medicine department and a new pediatric oncology department, nearing completion, at the Basra Cancer Children Hospital; (iii) in 2022 start-up of the Al-Bardjazia drinking water supply plant in the Zubair area while the construction of the new Al-Buradeiah plant in Basra is ongoing.

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 2,612 square kilometers (1,928 square kilometers net to Eni).

Eni participates in the production Block PSC-TL-SO-T 19-13 with a 10.99% interest. In addition, Eni holds interests in 2 exploration licenses.

Production Production comes mainly from the Bayu Undan gas and liquid field with a production of 54 kboe/day (4 kboe/ day net to Eni) in 2022. Liquid production is supported by two treatment platforms and an FSO unit. Production of natural gas is carried by a 500-kilometer-long pipeline and 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). LNG is sold to Japanese power generation companies under long-term contracts.

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 2022, Eni's production averaged 5 kboe/d.

Exploration and production activities in Turkmenistan are regulated by PSAs.

Production Production derives mainly from the Burun oil field

(Eni operator with a 90% interest). 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.

United Arab Emirates

Eni has been present in United Arab Emirates since 2018 over a developed and undeveloped acreage of 32,620 square kilometers (18,662 square kilometers net to Eni). 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 75% 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 the development phase Eni holds a 25% interest in the Ghasha offshore concession with duration of 40 years. The concession includes Hail, Ghasha, Hair Dalma-Bu Hasser-Satah gas fields and other offshore fields in the Al Dhafra area.

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.

In March 2023 Eni signed a strategic agreement with ADNOC to explore potential opportunities in the areas 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 Global Methane Pledge, to support global energy security and a sustainable energy transition.

Production In 2022 production averaged 60 kboe/d net to Eni and comes from Lower Zaku and Umm Shaif/Nasr fields as well as Mahani field.

Development In 2022 development activities concerned: (i) the Dalma Gas Development sanctioned project in the offshore Ghasha concession (Eni's interest 25%) and the Umm Shaif Long-Term Development Phase 1 sanctioned project in the Umm Shaif concession; and (ii) ramp-up production program of the Mahani field in the onshore Area B concession.

Exploration Exploration activities yielded positive results in the operated Block 2 with the XF-002 well and DM-002 appraisal well, in offshore Abu Dhabi, with estimated resources in 170 million barrels of oil and between 2.5 and 3.5 TCF of natural gas in place.

AMERICAS

Mexico

Eni has been present in Mexico since 2015 and is performing exploration and development activities over a developed and undeveloped acreage of 5,470 square kilometers (3,107 square kilometers net to Eni). Eni's activities are concentrated in the Gulf of Mexico.

Eni is operator of the offshore Area 1 production license (Eni's interest 100%) with the Amoca, Miztón and Tecoalli discoveries. In the exploration phase, Eni is operator of the Area 10 (Eni's interest 65%), Area 14 (Eni's interest 60%), Area 7 (Eni's interest 45%), 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%) and the Area 9 (Eni's interest 15%).

In January 2022, was signed a four-year Memorandum of Understanding with the United Nations Educational, Scientific, and Cultural Organization (UNESCO) to identify potential jointly initiatives supporting local economy sustainable development by means of economic diversification, environmental and cultural heritage protection, access to primary services, 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 2022 production comes from the operated Area 1 license and amounted to 17 kboe/d.

Development The development activities mainly concerned the full field development program of the operated license Area 1 (Eni's interest 100%), already in production, with the completion of the first development phase. In particular: (i) in February 2022 start-up of the Miamte FPSO in the Miztón field with production ramp-up in the area. During the year drilling production wells and water injection wells were completed; and (ii) in March 2022 start-up of the Amoca WHP-1 platform. Drilling activities are ongoing. The development plan includes a second phase with the construction and installation of additional two platform in the Amoca and Tecoalli fields.

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) training and inclusion school programs; (iii) initiatives to improve socio-economic 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 In March 2023 exploration activities yielded positive results with the Yatzil discovery in the Area 7 operated license.

United States

Eni has been present in the United States since 1968. Activities are performed in the Gulf of Mexico, Alaska, and in Texas onshore, over a developed and undeveloped acreage of 1,215 square kilometers (654 square kilometers net to Eni). In 2022, Eni's oil and gas production was 57 kboe/d.

GULF OF MEXICO

Eni holds interests in 46 exploration and production blocks in the conventional and deep offshore of the Gulf of Mexico, of which 16 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 2022, production amounted to 34 kboe/d net to Eni.

TEXAS

Production Production comes from the Alliance area (Eni's interest 27.5%), in the Fort Worth Basin. This asset includes unconventional gas reserves (shale gas). In 2022, Eni's production amounted to approximately 2 kboe/d.

ALASKA

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

Production Production The main operated fields are Nikaitchuq (Eni's interest 100%) and Oooguruk (Eni's interest 100%) with a 2022 overall net production of approximately 21 kbbl/d.

Venezuela

Eni has been present in Venezuela since 1998. In 2022, Eni's production averaged 53 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 2022, Eni's production of natural gas averaged 52 mmcf/d (equal to 10 Kboe/d). Activities are focused on offshore fields, 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 started-up 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.

CARBON OFFSET INITIATIVES

Eni recognizes and supports economy transition towards a low carbon model and on this basis, Eni developed a decarbonization strategy of the Group's products and industrial processes to target net zero Scope 1+2+3 emissions by 2050. Eni plans to offset its residual emissions by leveraging on the Natural Climate Solutions initiatives and the technological applications in different areas to progressively maximize the carbon removal. These initiatives are expected to achieve a carbon credits portfolio on yearly basis to offset less than 25 million tons of CO2 in 2050.

Natural Climate Solutions

Within the Natural Climate Solutions (NCS) area, starting from 2019 Eni launched the forest protection, conservation and sustainable management projects, in particular in developing Countries. The forest projects are considered the most significant at internationally level within climate change mitigation strategies. These projects are framed in the REDD+ (Reducing Emissions from Deforestation and forest Degradation) scheme. The REDD+ scheme was designed by the United Nations (in particular within the UNFCCC - United Nations Framework Convention on Climate Change) and involves conservation forest activities to reduce emissions and improve the natural storage capacity of CO2 , as well as supporting, with a different development model, the local communities through socio-economic projects, in line with sustainable management, forest protection and biodiversity conservation. In this scheme, Eni's protection forest activities support national governments, local communities and UN agencies in the REDD+ strategies, in line with the NDCs (Nationally Determined Contributions) and National Development Plans and, mainly, the Sustainable Development Goals (SDGs) of UN.

Eni built solid partnerships over time with recognized international developers of REDD+ projects that allows to oversee every phase of the projects, from the design to the implementation up to verify the reduction emissions, with an active role in the governance of the project. The Eni's role is essential to allow the alignment with the REDD+ scheme and also with highest standards for certification of the carbon emissions reduction (Verified Carbon Standard - VCS) and social and environmental effects (Climate Community & Biodiversity Standards - CCB), internationally recognized.

Main initiatives supported by Eni are Luangwa Community Forest Project (LCFP) and Lower Zambezi REDD+ Project (LZRP) in Zambia, Kulera in Malawi, Ntakata Mountains in Tanzania and Amigos de Calakmul, in Mexico. In 2022 Eni achieved allowance of carbon credits by the projects to offset GHG emissions equivalent to about 3.5 million tons of CO2.

During 202 Eni finalized agreements to support the future development projects in Ivory Coast, Kenya and Mozambique where feasibility studies are underway.

In November 2022 Eni signed an agreement with the Rwanda Development Board and the non-profit tech start-up Rainforest Connection in Rwanda to testing the application of artificial intelligence technologies in the forest protection and conservation.

Eni continues to evaluate further NCS initiatives in restoration and sustainable management ecosystems in Africa, Latin America, and Asia.

Technological projects

The technological application in different areas is one of the levers in the residual emission reduction. In particular, Eni launched projects to promote the Improved Cookstoves (ICS) distribution for cooking food in energy poverty areas and continued to assess initiatives in renewable energy, waste management, agricultural practices improvement that ensuring in addition to climate change mitigation also significant social and environmental benefits for local stakeholders.

These initiatives ensure to offset emissions by generating high credits quality, certified according to the highest international environmental standards (Verified Carbon Standard - VCS) and support the achievement of the SDGs (Sustainable Development Verified Impact Standard - SD VISta).

In June 2022 Eni launched the distribution of ICS to vulnerable households in Ivory Coast. It is expected that more than 300,000 people form the Region of Gbêkê Project will benefit from the projects which targeting to deliver 100,000 ICS over a period of 6 years, starting already this year. All the stoves are produced by a local manufacturer, contributing to the development of local content and in-country value creation.

This activity will enhance Eni's decarbonization strategy in the Baleine discovery development. The project is expected to generate high-quality carbon credits certified by the international standard VERRA amounting to approximately 1 million of VCU (Verified Carbon Units) over the next 10 years. Similar initiatives are planned in several countries, including Mozambique, Congo, Kenya and Rwanda.

AGRI-FEEDSTOCK PROJECTS

During the year Eni finalized agreement with the authorities of Mozambique, Benin and Rwanda as well as in 2021 in Kenya, Congo, Angola, Kazakhstan and Ivory Coast aiming to promote agricultural initiatives for the cultivation of oil plants to be used as feedstock (Low ILUC feedstock - Indirect Land Use Change) for Eni's biorefineries, enhancing marginal areas not destined to the food chain. The development activities plan is focused on vertical integration and includes agreements to produce oilseeds by local farmers and cooperatives and the construction of oil collection and extraction centers by Eni (Agri Hubs). The supply chain byproducts will be aimed for domestic market and also for export. These initiatives will also support rural development, land restoration through sustainable and regenerative agriculture, with positive impacts on socioeconomic development and employment, access to market opportunities as well as human rights protection, health and food security. Further programs are being evaluated in other countries with a model in analogy to the ones applied.

In particular, in October 2022, a first cargo of vegetable oil, produced at Eni's Makueni agri-hub in Kenya, was shipped to the Eni's biorefinery of Gela. Makueni agri-hub started operations in July 2022. Production of such sustainable oil is expected to scale up rapidly to 20,000 tons by 2023 from current production of 2,500 tones at the end of 2022. The supply chain in Kenya is certified according to the ISCC-EU (International Sustainability and Carbon Certification) sustainability scheme, one of the main voluntary standards recognised by the European Commission for the certification of biofuels (EU RED II). In addition, the agreement reached with Kenya also provides for the engineering activities to conversion the Mombasa traditional refinery to biorefinery for HVO and Biojet production; as well as the collection of UCO (Used Cooking Oil) to be used as feedstock.

Other ongoing activities concerned: (i) in Congo, started the cultivation with the first 2,000 hectares sown. Launched the engineering and construction phases of the first Agri Hub with a capacity of 30 ktons/year and start-up in 2023. Full capacity is expected to produce 250 ktons starting from 2027; (ii) in Mozambique, in November 2022, started the cultivation of pilot fields and engineering activities of the first Agri-Hub with a capacity of 30 thousand tons/year and startup in 2023. Full capacity is expected to produce 200 ktons in 2027; (iii) in Angola, in December 2022, started the cultivation of pilot fields in the Luanda area. The construction area of the Agri-Hub plant has been identified. Production capacity is expected to 30 ktons/year; (iv) in Ivory Coast, are ongoing preliminary activities for the production chain definition and the area selection to build the Agri-Hub plant with start-up in 2023; and (v) in Italy, launched a project in partnership with the Bonifiche Ferraresi company, to evaluate the crops development for energy use, recovering degraded or polluted land not destinated to the food chain.

Agricultural productions projects started or under development will respond to the ISCC-EU sustainability certification scheme. Overall target production is expected to subsequently reach an agri-feedstock volume of over 700 thousand tonnes by 2026 leveraging on planned initiatives.

In November 2022, in Rwanda, Eni signed an agreement with the National Industrial Research and Development Agency to maximize techniques and know-how of the seeds production

for agri-feedstock initiatives launched by Eni in other African countries.

Within these development model, Eni finalized strategic partnership agreement with the Bonifiche Ferraresi Group aimed at establishing in 2021 the Agri-Energy equal joint venture. In 2022 the Agri-Energy JV launched research projects of sustainable energy crops, in particular with a pilot project in Sardinia. In addition, Agri-Energy will support in the countries where Eni will develop agrifeedstock projects by means of know-how transfer and agriculture seeds and products supplies.

Finally, in addition to the seeds cultivation in degraded or marginal land, Eni has diversified its types of feedstock with agricultural waste and residues.

Movements in net proved hydrocarbons reserves(a)

(mmboe)	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	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.

Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
73	798	1,110	1,352	1,182	879	256	91	5,984
68	434	1,022	799	1,093	424	162	60	4,261
5	364	88	553	89	455	94	31	1,723
						2		2
22	109	11	(149)	(97)	(52)	45	(3)	42
			2			10		12
1	8	2	51					62
(15)	(95)	(131)	(106)	(53)	(65)	(25)	(6)	(526)
			(5)					(5)
81	820	992	1,145	1,032	762	288	82	5,571
496	14		87			324		921
254	14		47			324		639
242			40					282
61	(3)		183			(25)		216
8								8
(63)	(1)		(7)			(17)		(88)
502	10		263			282		1,057
583	830	992	1,408	1,032	762	570	82	6,628
341	383	852	805	963	445	485	51	4,608
80	373	852	766	963	445	203	51	4,016
261	10		39			282		592
242	447	140	603	69	317	85	31	2,020
1	447	140	379	69	317	85	31	1,555

equity-accounted entities 241 224 465

									Australia
(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of	Asia Americas	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.

									Australia
(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of	Asia Americas	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.

									Australia
(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of	Asia Americas	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 America	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

									Australia
(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	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

		Rest of			Sub-Saharan		Rest of		Australia and
(mmbbl)	Italy	Europe	North Africa	Egypt	Africa	Kazakhstan	Asia	Americas	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

									Australia
(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	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

Movements in net proved natural gas reserves

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub - Saharan Africa	Kazakhstan	Rest	of Asia America	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.

		Rest of			Sub-Saharan		Rest of		Australia and
(bcf)	Italy	Europe	North Africa	Egypt	Africa	Kazakhstan	Asia	Americas	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.

		Rest of			Sub-Saharan		Rest of		Australia and
(bcf)	Italy	Europe	North Africa	Egypt	Africa	Kazakhstan	Asia	Americas	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.

2019

(bcf) Italy

Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total

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.

(c) It includes production volumes consumed in operations equal to 11 bcf.

		Rest of			Sub-Saharan		Rest of		Australia and
(bcf)	Italy	Europe	North Africa	Egypt	Africa	Kazakhstan	Asia	Americas	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.

(kboe/d)	2022	2021	2020	2019	2018
CONSOLIDATED SUBSIDIARIES
Italy	82	83	107	123	138
Rest of Europe	44	41	52	55	194
Croatia					2
Norway					134
United Kingdom	44	41	52	55	58
North Africa	264	259	255	379	392
Algeria	95	85	81	83	85
Libya	165	168	168	291	302
Tunisia	4	6	6	5	5
Egypt	346	360	291	354	300
Sub-Saharan Africa	230	291	345	363	337
Angola	57	101	100	113	127
Congo	78	70	73	87	92
Ghana	32	36	41	42	18
Nigeria	63	84	131	121	100
Kazakhstan	126	146	163	150	143
Rest of Asia	174	177	176	179	177
China	1	1	1	1	1
Indonesia	62	61	48	59	71
Iraq	31	37	45	41	34
Pakistan	11	11	15	19	20
Timor Leste	4	9	10
Turkmenistan	5	7	9	8	11
United Arab Emirates	60	51	48	51	40
Americas	74	67	75	68	75
Ecuador				6	12
Mexico	17	14	14	4
Trinidad & Tobago					7
United States	57	53	61	58	56
Australia and Oceania	10	16	17	28	23
Australia	10	16	17	28	23
	1,350	1,440	1,481	1,699	1,779
Equity-accounted entities
Angola	53	19	23	23	19
Indonesia					1
Mozambique	6
Norway	145	172	185	108
Tunisia	3	3	2	3	4
Venezuela	53	48	42	38	48
	260	242	252	172	72

Total 1,610 1,682 1,733 1,871 1,851 (a) Includes volumes of hydrocarbons consumed in operations (124, 116, 124, 124 and 119 kboe/d in 2022, 2021, 2020, 2019 and 2018, respectively).

(b)Effective January 1st, 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.

(c) Effective January 1st, 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.

(d) 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)	2022	2021	2020	2019	2018
CONSOLIDATED SUBSIDIARIES
Italy	36	36	47	53	60
Rest of Europe	20	19	23	23	113
Norway					89
United Kingdom	20	19	23	23	24
North Africa	122	124	112	166	154
Algeria	62	54	53	62	65
Libya	58	67	56	101	86
Tunisia	2	3	3	3	3
Egypt	77	82	64	75	77
Sub-Saharan Africa	139	198	218	249	244
Angola	52	91	89	102	111
Congo	40	44	49	59	65
Ghana	16	20	24	24	15
Nigeria	31	43	56	64	53
Kazakhstan	88	102	110	100	94
Rest of Asia	78	80	88	86	77
China	1	1	1	1	1
Indonesia	1	1	1	2	3
Iraq	15	24	31	27	28
Timor Leste	1	1	2
Turkmenistan	4	6	7	7	6
United Arab Emirates	56	47	46	49	39
Americas	59	53	57	55	52
Ecuador				6	12
Mexico	14	11	12	4
United States	45	42	45	45	40
Australia and Oceania				2	2
Australia				2	2
	619	694	719	809	873
Equity-accounted entities
Angola	36	3	4	4	3
Norway	89	111	116	74
Tunisia	3	3	2	3	3
Venezuela	4	2	2	3	8
	132	119	124	84	14
Total	751	813	843	893	887

Natural gas production

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

Oil and natural gas production sold

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

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

Main oil and natural gas interests at December 31, 2022

	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		302	14,635	8,137	54,096	25,495		65	42
Italy	1926	113	7,993	6,698	4,966		4,186 Onshore/Offshore	55	35
Rest of Europe		189	6,642	1,439	49,130	21,309		10	7
Albania	2020	1			587	587	Onshore
Cyprus	2013	7			25,474	13,988	Offshore		2
Greenland	2013						Offshore
Montenegro	2016						Offshore
Norway	1965	147	5,723	815	21,789	5,871	Offshore
United Kingdom	1964	34	919	624	1,280	863	Offshore	10	5
AFRICA		293	51,139	14,207	232,739	103,189		192	145
North Africa		81	16,820	7,773	104,546	35,307		80	68
Algeria	1981	54	11,561	5,332	6,915	3,388	Onshore	48	46
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	21	7
Egypt	1954	55	5,022	1,789	15,179		5,314 Onshore/Offshore	35	22
Sub-Saharan Africa		157	29,297	4,645	113,014	62,568		77	55
Angola	1980	82	10,863	907	30,544	5,609	Onshore/Offshore
Congo	1968	19	971	586	1,320	713	Onshore/Offshore	14	5
Gabon	2008	3			2,931	2,931	Onshore/Offshore		1
Ghana	2009	3	226	100	930	395	Offshore	1	1
Ivory Coast	2015	6			4,523	4,000	Offshore		2
Kenya	2012	6			50,677	41,892	Offshore
Mozambique	2007	8	719	180	13,883	3,688	Offshore	1	5
Nigeria	1962	30	16,518	2,872	8,206	3,340	Onshore/Offshore	61	41
South Africa	2014						Offshore
ASIA		55	10,926	3,238	256,816	142,347		15	24
Kazakhstan	1992	7	2,391	442	3,853		1,505 Onshore/Offshore	2	3
Rest of Asia		48	8,535	2,796	252,963	140,842		13	21
China	1984	3	62	10			Offshore	2
Indonesia	2001	13	3,770	1,787	14,465	10,319	Onshore/Offshore	3	8
Iraq	2009	1	1,074	446			Onshore	1
Lebanon	2018	2			3,653	1,461	Offshore
Myanmar	2014						Onshore/Offshore
Oman	2017	3			102,016	58,955	Offshore
Qatar	2022	1			1,206	38			1
Russia	2007	2			53,930	17,975	Offshore
Timor Leste	2006	4	412	122	2,200	1,806	Offshore	1	3
Turkmenistan	2008	1	200	180			Offshore	2
United Arab Emirates	2018	12	3,017	251	29,603	18,411	Onshore/Offshore	4	9
Vietnam	2013	5			31,290	28,633	Offshore
Other countries		1			14,600	3,244	Offshore
AMERICAS		98	2,230	1,046	14,570	8,140		38	10
Mexico	2015	10	34	34	5,436	3,073	Offshore	2	4
United States	1968	76	935	515	280	139	Onshore/Offshore	33	4
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		752	79,658	27,262	560,829	281,288		311	222

(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.

Net developed and undeveloped acreage

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

Average realizations

		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
Italy		67.07		61.26		34.58		55.55		61.58
Rest of Europe		93.94	97.51	70.60	66.72	32.82	35.23	58.92	58.88	64.51
North Africa		92.11	17.82	68.03	17.89	38.33	18.16	57.91	18.06	65.95	17.92
Egypt		87.64		63.53		36.66		54.78		62.97
Sub-Saharan Africa		103.96	85.71	69.12	44.41	39.99	17.13	63.45	23.72	68.76	39.48
Kazakhstan		86.94		66.92		37.37		59.06		66.78
Rest of Asia		94.13		68.39	0.00	37.69		62.81		68.35	49.86
Americas		92.03	88.39	61.93	57.75	33.03	27.20	54.00	59.94	57.22	54.86
Australia and Oceania		60.89		58.76		17.45		52.93		68.72
		92.41	92.97	66.91	65.10	37.56	34.21	59.62	55.93	65.79	45.19
Natural gas	(\$/kcf)
Italy		20.32		15.47		3.16		5.03		8.37
Rest of Europe		30.22	31.02	15.75	15.11	3.12	3.25	4.95	5.07	7.99

North Africa	10.52	9.67	6.42	5.83	4.33	6.29	6.21	7.23	4.97	3.58
Egypt	5.50		4.74		4.78		5.11		4.85
Sub-Saharan Africa	4.99	33.79	4.32	14.68	2.76	3.94	2.94	6.16	2.38	9.50
Kazakhstan	0.69		0.54		0.69		0.81		0.77
Rest of Asia	10.57		6.21		4.09		5.94		6.11	9.32
Americas	6.48	4.76	4.06	4.32	2.10	4.37	2.46	4.32	2.38	4.28
Australia and Oceania	4.10		4.25		3.84		4.41		4.80
	8.61	19.87	5.93	10.71	3.77	3.73	4.94	4.94	5.17	5.59

Hydrocarbons (\$/boe)
Italy	87.98		72.42		25.28		40.24		53.01
Rest of Europe	128.03	121.12	78.48	71.19	23.94	29.17	39.84	49.76	56.07
North Africa	73.29	19.31	51.51	18.69	30.28	19.36	44.86	19.39	43.34	18.14
Egypt	42.64		34.18		28.03		33.67		36.22
Sub-Saharan Africa	83.12	108.43	58.24	70.02	32.06	19.97	53.08	30.84	58.59	48.79
Kazakhstan	64.59		49.37		27.22		42.21		46.98
Rest of Asia	76.85		51.48	0.00	31.31		50.31		50.98	50.64
Americas	83.45	29.27	55.66	24.99	29.57	23.39	48.37	25.67	46.63	28.59
Australia and Oceania	22.25		23.03		20.35		26.32		28.99
	69.07	98.29	49.82	61.11	29.20	27.33	43.73	41.71	48.04	33.63
Eni's Group	2022			2021		2020		2019		2018
Liquids (\$/bbl)		92.49			37.06		59.26		65.47
Natural gas (\$/kcf)	10.37		6.64		3.76		4.94		5.20
Hydrocarbons (\$/boe)	73.98		51.49		28.92		43.54		47.48

Exploratory wells activity

		Wells completed(a)				Wells in progress at of Dec.31(b)
	2022		2021		2020		2019		2018		2022
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy								0.5	1.8
Rest of Europe	0.4	1.2	0.1	0.3	0.8	0.4	0.3	1.4		0.5	26.0	6.7
North Africa	1.0	4.0			0.5	1.5	0.5			0.5	9.0	6.0
Egypt	4.4	4.3	5.0	5.0	0.7	1.5	4.5	1.5	1.7	1.5	12.0	10.3
Sub-Saharan Africa	3.7	2.4	1.1	0.4	0.1	0.9	0.5	0.9	0.4		39.0	19.7
Kazakhstan						1.1
Rest of Asia	0.7	1.0	0.7	1.0	0.8	0.9		1.7	2.2	2.6	13.0	5.7
Americas				0.7		0.6			4.0		3.0	1.9
Australia and Oceania								0.5			1.0	0.3
	10.2	12.9	7.0	7.4	2.9	6.9	5.8	6.5	10.1	5.1	103.0	50.6

Development wells activity

	Wells completed(a)											Wells in progress at of Dec.31
	2022		2021		2020		2019		2018		2022
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy	1.0						3.0		3.0
Rest of Europe	4.6		4.8		2.8		3.3		2.8	0.3	8.0	3.7
North Africa	5.7	0.5	2.5		4.3		5.0	1.1	9.6	0.5	1.0	0.5
Egypt	19.9		17.0	0.8	23.2		33.5		30.7		5.0	2.3
Sub-Saharan Africa	8.5		3.8		1.2		7.0		7.3	0.1	17.0	3.0
Kazakhstan	0.6				0.3		0.9		0.9
Rest of Asia	22.1		14.9		23.2	0.4	27.3	2.2	21.9		8.0	3.9
Americas	8.2		3.9		2.0		2.1		2.3		1.0	0.1
Australia and Oceania									0.8
	70.6	0.5	46.9	0.8	57.0	0.4	82.1	3.3	79.3	0.9	40.0	13.5

Productive oil and gas wells(d)

		2022
	Oil wells		Natural gas wells
(units) Italy Rest of Europe North Africa Egypt Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania	Gross	Net	Gross	Net
	156.0	130.0	331.0	292.4
	635.0	105.0	223.0	49.1
	627.0	263.8	138.0	74.9
	1253.0	533.5	145.0	44.7
	2639.0	480.1	175.0	26.1
	209.0	57.2	1.0	0.3
	1004.0	349.4	108.0	45.6
	269.0	144.4	285.0	81.8
			2.0	2.0
	6,792.0	2,063.4	1,408.0	616.9

(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 1,089 gross (306.4 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.

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

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub - Saharan Africa	Kazakhstan	Rest of Asia	America	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(b)	(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) 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 €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)
DD&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)
DD&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	America	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 accordance 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.

		Rest of			Sub-Saharan		Rest of		Australia and
(€ million)	Italy	Europe	North Africa	Egypt	Africa	Kazakhstan		Asia Americas	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	America	Australia and Oceania	Total
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)(c)		8,794	67		9,562		335	883		19,641
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(b)	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(b)		9,546	82		2,530		12	897		13,067

(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 €725 million in 2022 and €767 million in 2021 for the consolidates subsidiaries and €565 million in 2022 and €360 million in 2021 for equity-accounted entities.

(c) 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 America	Australia and Oceania	Total
2020
Consolidated subsidiaries
Proved mineral interests	18,456	6,465	14,596	19,081	39,848	11,278	10,662	14,567	1,359	136,312
Unproved mineral interests	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	13,540	9,622	4,573	3,329	783	49,212
Equity-accounted entities
Proved mineral interests		11,466	68		1,384			1,833		14,751
Unproved mineral interests		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 consolidated subsidiaries(a)		8,990	26		1,058		11	972		11,057
2019
Consolidated subsidiaries
Proved mineral interests	17,643	6,747	15,512	20,691	43,272	12,118	11,434	15,912	1,360	144,689
Unproved mineral interests	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 and amortization	(14,604)	(5,778)	(12,802) (12,879)		(33,237)	(2,652)	(9,100)	(13,465)		(754) (105,271)
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 mineral interests		11,223	71		1,511		2	1,987		14,794
Unproved mineral interests		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

(a) The amounts include net capitalized financial charges totalling €843 million in 2020 and €878 million in 2019 for the consolidates subsidiaries and €170 million in 2020 and €166 million in 2019 for equity-accounted entities.

(b) Includes allocation at fair value of the assets purchased by Vår Energi AS.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub - Saharan Africa	Kazakhstan	Rest	of Asia America	Australia and Oceania	Total
2018
Consolidated subsidiaries
Proved mineral interests	16,569	6,236	14,140	17,474	40,607	11,240	12,711	15,347	1,967	136,291
Unproved mineral interests	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 mineral interests		9,102	58		1,481		2	1,912		12,555
Unproved mineral interests		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 €831 million in 2018 for the consolidates subsidiaries and €180 million in 2018 for equity-accounted entities.

(b) Includes Vår Energi AS asset fair value.

									Australia
(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of	Asia Americas	and Oceania	Total
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
2020
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions			55	2						57
Exploration	19	20	69	67	61	7	176	63	1	483
Development(b)	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(c)		1,481	3		6			14		1.504
Total costs incurred equity-accounted entities		1,528	3		6			14		1.551

(a) Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities.

(b) Includes the abandonment decrease of the assets for €307 million in 2022, costs for €62 million in 2021 and costs for €516 million in 2020. (c) Includes the abandonment decrease of the assets for €111 million in 2022, decrease for €464 million in 2021 and costs for €424 million in 2020.

		Rest of	North		Sub - Saharan		Rest		Australia and
(€ million)	Italy	Europe	Africa	Egypt	Africa	Kazakhstan	of Asia	America	Oceania	Total
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(c)			5				103	(16)		92

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

(b) Includes the abandonment costs of the assets for €838 million in 2019 and negative €22 million in 2018.

(c) Includes allocation at fair value of the assets purchased by Vår Energi AS.

Standardized measure of discounted future net cash flows(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub - Saharan Africa	Kazakhstan	Rest	of Asia America	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

									Australia
(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	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

		Rest of			Sub-Saharan		Rest of		Australia and
(€ million)	Italy	Europe	North Africa	Egypt	Africa	Kazakhstan	Asia	Americas	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
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	123	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)	730
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

Capital expenditure(a)

(€ million)	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	708	391	283	586	463
Italy					1
Rest of Europe	82	81	9	43	52
North Africa	36	11	42	71	20
Egypt	163	37	48	86	80
Sub-Saharan Africa	258	81	20	128	22
Kazakhstan	2	2	4	7
Rest of Asia	163	120	124	141	140
Americas	4	59	36	74	146
Australia and Oceania				36	2
Oil and gas development	5,238	3,364	3,077	5,931	6,506
Italy	301	282	229	289	380
Rest of Europe	127	91	107	110	600
North Africa	300	206	220	536	525
Egypt	712	442	393	1,481	2,205
Sub-Saharan Africa	1,492	771	624	1,406	1,635
Kazakhstan	351	189	178	371	193
Rest of Asia	851	824	916	1,028	550
Americas	1,016	532	402	695	381
Australia and Oceania	88	27	8	15	37
CCUS and agri-biofeedstock projects	110	37
Other	46	52	55	79	63
	6,362	3,861	3,472	6,996	7,901

(a) Expenditures to purchase plant and equipment from suppliers whose payment terms matched classification as financing payables, have been recognized among other changes of the cash flow statement (€61 million and €79 million in 2022 and 2021, respectively).

Global Gas & LNG Portfolio

KEY PERFORMANCE INDICATORS		2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)(a)	(total recordable injuries/worked hours) x 1,000,000	0.00	0.00	1.15	0.56	0.51
of which: employees		0.00	0.00	0.99	0.96	0,40
contractors		0.00	0.00	1.37	0,00	0.69
Sales from operations(b)	(€ million)	48,586	20,843	7,051	11,779	14,807
Operating profit (loss)		3,730	899	(332)	431	387
Adjusted operating profit (loss)		2,063	580	326	193	278
Adjusted net profit (loss)		982	169	211	100	118
Capital expenditure		23	19	11	15	26
Natural gas sales(b)	(bcm)	60.52	70.45	64.99	72.85	76.60
Italy		30.67	36.88	37.30	37.98	39.17
Rest of Europe		27.41	28.01	23.00	26.72	29.17
of which: Importers in Italy		2.43	2.89	3.67	4.37	3.42
European markets		24.98	25.12	19.33	22.35	25.75
Rest of world		2.44	5.56	4.69	8.15	8.26
LNG sales(c)		9.40	10.9	9.5	10.1	10.3
Employees at year end	(number)	870	847	700	711	734
of which: outside Italy		588	571	410	418	416
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	2.09	1.01	0.36	0.25	0.62

(a) Calculated on 100% operated assets. (b) Data include intercompany sales.

(c) Refers to LNG sales of the GGP segment (included in worldwide gas sales).

The Global Gas & LNG Portfolio segment (GGP) engages in the wholesale activity of supplying and selling natural gas via pipeline and LNG, and the international transport activity. It also comprises gas trading activities targeting both hedging and stabilizing the Group's commercial margins and optimizing the gas asset portfolio.

1 Marketing

1.1 Natural gas

SUPPLY OF NATURAL GAS

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. Eni could also leverage on the availability of natural gas deriving from equity production, the access to all phases of the LNG chain (liquefaction, shipping and regasification) and to other gas infrastructures, and by trading and risk management activity. Eni's long-term gas requirements are met by natural gas from those Countries, where Eni signed long-term gas supply contracts or holds upstream activities and by access to continental Europe's spot markets.

In line with the strategic guideline to increase gas production and import in Italy, Eni signed agreements with a number of governments in the countries where it operates. In particular a letter of intent signed with the petroleum authorities of the Republic of Congo with the aim of developing a liquefied natural gas project with start-up expected in 2023 and capacity of over 4.5 bcm/y in 2025; in Algeria, Eni plans to gradually increase volumes of gas imported in Italy through the Transmed pipeline as part of the existing long-term supply contracts with Sonatrach, with additional gas deliveries starting from next heating season and a progressive rampup to 9 bcm/y in 2024; in Egypt, Eni has agreed with the state-owned company "EGAS" to valorize local gas reserves by increasing activities in jointly managed concessions and through near-field exploration, with the target to increase in the next years the production and the exports of gas towards Italy, through the Damietta liquefaction plant, up to approximately 3 bcm.

Finally, as evidence of Eni's commitment to ensuring security of supply while at the same time pursuing our decarbonisation targets, in January 2023 the partnership between Italy and Algeria has been further strengthened. Eni and Sonatrach signed strategic agreements to accelerate emissions reduction and strengthen energy security. In particular, opportunities for the reduction of greenhouse gas and methane gas emissions will be identified and will be defined energy efficiency initiatives, renewable energy developments, green hydrogen projects and carbon dioxide capture and storage projects. In addition, studies will be conducted to identify possible measures to improve Algerian energy export capacity to Europe.

Eni's consolidated subsidiaries supplied 60.59 bcm of natural gas, decreased by 10.39 bcm or by 14.6% from the full year 2021.

Gas volumes supplied outside Italy from consolidated subsidiaries (57.19 bcm), imported in Italy or sold outside Italy, represented approximately 94% of total supplies, decreased by 10.20 bcm or by 15.1% from the full year 2021. This mainly reflected lower volumes purchased in Russia (down by 13.01 bcm), in Norway (down by 0.77 bcm), in the UK (down by 0.74 bcm), in Libya (down by 0.56 bcm) and in Indonesia (down by 0.45 bcm) partly offset by higher purchases in Algeria (up by 1.74 bcm), in the other European markets, in particular France, Germany and Spain (overall increase of 5.72 bcm). Supplies in Italy (3.40 bcm) reported a decrease of 5.3% from the full year 2021.

ENI AT A GLANCE NATURAL RESOURCES ENERGY EVOLUTION ANNEX 65

GLOBAL GAS & LNG PORTFOLIO VALUE CHAIN

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.

ENI'S AVAILABILITY OF NATURAL GAS (bcm)

(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 as well as to lower demand in price sensitive sector such as the industrial due to higher prices. In this scenario, demand decreased by approximately 10% and 13% in Italy and in the European Union, respectively, compared to 2021. Natural gas sales amounted to 60.52 bcm (including Eni's own consumption, Eni's share of sales made by equity-accounted entities) and decreased by 9.93 bcm or 14.1% from the previous year due to lower sales in Italy and outside Europe.

GAS SALES BY MARKET

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

Sales in Italy (30.67 bcm) decreased by 16.8% from 2021 mainly due to lower sales to hub, to industrial and wholesalers segments. Sales to importers in Italy (2.43 bcm) decreased by 15.9% from 2021 due to the lower availability of Libyan gas.

Sales in the European markets amounted to 24.98 bcm, substantially in line compared to 2021.

Sales in the extra European markets of 2.44 bcm decreased by 3.12 bcm or 56.1% 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 2022, sales amounted to 4.24 bcm, up 0.77 bcm, or 22.2% compared to 2021, mainly due to optimization actions.

France

In France, Eni operates in all business segments through its direct commercial activities and its subsidiary Eni Gas & Power France SA. In 2022, sales in the Country amounted to 3.62 bcm (including sales to Plenitude's subsidiaries), a decrease of 2.18 bcm, or 37.6%, from a year ago, mainly due to fewer portfolio optimizations and lower sales to local distribution companies.

Germany/Austria

In 2022 total sales in Germany and Austria amounted to 3.58 bcm up by 2.89 bcm, representing a more than a five-fold increase, due to the portfolio optimizations and higher sales to local distribution companies.

Spain

Eni operates in the Spanish natural gas market through marketing of natural gas to industrial clients, wholesalers and power generation utilities. In 2022, total Eni's sales in Spain amounted to 3.93 bcm, an increase of 0.18 bcm, or 4.8% compared to 2021, thanks to higher sales to wholesalers and industrial segments.

Turkey

Eni sells gas transported via Blue Stream pipeline. In 2022, sales amounted to 7.62 bcm, a decrease of 0.88 bcm, or 10.4% 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 2022, sales amounted to 1.92 bcm, down by 0.73 bcm or 27.5% compared to 2021 due to lower volumes sold to the industrial customers and to hub.

1.2 GNL

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

In June 2022, in the LNG business, Eni entered in the North Field East LNG project in Qatar, the world's largest, expanding its presence in the Middle East and gaining access to a leading country in the LNG production. In August, Eni acquired the Tango FLNG floating liquefaction plant, that will be used in the Republic of Congo, as part of the activities of the natural gas development project Marine Block XII. The plant has an LNG production capacity of approximately 0.6 mmtons/y

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).

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-kilometers 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 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,fortheimportofAlgeriangasis775-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;

(about 1 bscm/y). Furthermore, in December among the same project, a turnkey contract for construction, installation and commissioning activities of a FLNG floating unit with a capacity of 2.4 mmtons/y was signed. This plant, together with the Tango FLNG ship, acquired earlier, will accelerate the Eni development plan in the area. LNG production is expected to reach plateau capacity of 3 mmtons/y in 2025.

In 2022, LNG sales (9.4 bcm, included in the worldwide gas sales) decreased by 13.8% from 2021. In 2022 the main sources of LNG supply were Qatar, Egypt, Nigeria and Indonesia.

• 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.

In January 2023, as part of Eni's portfolio optimization, Eni finalized the sale to Snam of the 49.9% interest (directly and indirectly held) in the companies operating two groups of international gas pipelines connecting Algeria to Italy, in particular the TTPC and TMPC pipelines. These interests were transferred by Eni to SeaCorridor Srl held by Snam (49.9% interest) and Eni (50.1% interest). Eni and Snam exercise joint control over SeaCorridor, based on the principles of equal governance.

SUPPLY OF NATURAL GAS

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

GAS SALES BY ENTITY

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

LNG SALES

(bcm)	2022	2021	2020	2019	2018
Europe	7.0	5.4	4.8	5.5	4.7
Extra European markets	2.4	5.5	4.7	4.6	5.6
TOTAL SALES	9.4	10.9	9.5	10.1	10.3

TRANSPORT INFRASTRUCTURE

INFRASTRUCTURES	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)	2022	2021	2020	2019	2018
Market		2		5	3	19
Italy						8
Outside Italy		2		5	3	11
International transport		21	19	6	12	7
TOTAL CAPITAL EXPENDITURE		23	19	11	15	26

ENERGY EVOLUTION

Refining & Marketing and Chemicals Plenitude & Power Environmental activities

Refining & Marketing and Chemicals

KEY PERFORMANCE INDICATORS		2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)(a)	(total recordable injuries/worked hours) x 1,000,000	0.81	0.80	0.80	0.27	0.56
of which: employees		0.95	1.13	1.17	0.24	0.49
contractors		0.69	0.49	0.48	0.29	0.62
Sales from operations(b)	(€ million)	59,178	40,374	25,340	42,360	46,483
Operating profit (loss)		460	45	(2,463)	(682)	(501)
Adjusted operating profit (loss)		1,929	152	6	21	360
- Refining & Marketing		2,183	(46)	235	289	370
- Chemicals		(254)	198	(229)	(268)	(10)
Adjusted net profit (loss)		1,914	62	(246)	(42)	224
Capital expenditure		878	728	771	933	877
Bio throughputs	(ktonnes)	543	665	710	311	253
Capacity of biorefineries	(mmtonnes/year)	1.1	1.1	1.1	1.1	0.4
Average biorefineries utilization rate	(%)	53	65	63	44	63
Conversion index of oil refineries		42	49	54	54	54
Balanced capacity of refineries (Eni's share)	(kbbl/d)	528	548	548	548	548
Average oil refineries utilization rate		79	76	69	88	91
Retail sales of petroleum products in Europe	(mmtonnes)	7.50	7.23	6.61	8.25	8.39
Service stations in Europe at year end	(number)	5,243	5,314	5,369	5,411	5,448
Average throughput per service station in Europe	(kliters)	1,587	1,521	1,390	1,766	1,776
Retail efficiency index	(%)	1.20	1.19	1.22	1.23	1.20
Production of petrochemical products	(ktonnes)	6,775	8,476	8,073	8,068	9,483
Sale of petrochemical products		3,676	4,451	4,339	4,295	4,946
Average petrochemical plant utilization rate	(%)	59	66	65	67	76
Employees at year end	(number)	13,132	13,072	11,471	11,626	11,457
- of which outside Italy		4,146	4,044	2,556	2,591	2,594
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	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)	233	228	248	248	253

(a) Calculated on 100% operated assets.

(b) Before elimination of intragroup sales.

Eni's Refining & Marketing and Chemicals segment engages in the supply and refining of crude oil, storage, production, distribution and marketing of refined products and biofuels, production and distribution of basic petrochemical products, plastics, elastomers and chemicals from renewable sources. It includes the results of the activities of the Refining & Marketing and Chemical businesses which have been aggregated into a single segment because these two operating segments have similar economic returns.

The Refining & Marketing business is focused on refining of crude oil, production and storage of refined products in Italy, Germany and the Middle East (through the 20% interest in ADNOC Refining) and production of biofuels in Italy at Venice and Gela biorefineries able to process sustainable biofeedstock, on distribution and marketing of oil (gasoline, gasoil, biodiesel, LPG, lubricants) and non-oil products through the service stations network in Italy and in the rest of Europe, refined products on the wholesale market, mainly 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 and finally in smart mobility services under the Enjoy brand.

In January 2023, as a part of the Group's satellite strategy to set-up new dedicated entities to accelerate the decarbonization of its customer portfolio (Scope 3 emission), Eni established the new entity Eni Sustainable Mobility. The company is vertically integrated and will support Eni's energy transition by combining the offer of increasingly sustainable fuel with advanced services for drivers in Italy and Europe, leveraging on a network of 5,000 service stations, that will be also enhanced to support electric and hydrogen-based mobility. Eni Sustainable Mobility will manage Eni's biorefining and biomethane assets and will continue the development of new projects, including the development of a biorefinery in Louisiana (USA) through a 50-50 Joint Venture with PBF and the projects at Livorno and Pengerang in Malaysia, which are currently under evaluation.

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.

Refining & Marketing

Eni is active in the refining business in Italy and abroad and operates traditional refinery plants (both fully and jointly owned), as well as plants converted into biorefineries.

PRODUCTION CYCLE OF REFINED PRODUCTS

1. Refining

In 2022, Eni refinery capacity (balanced refining capacity) was approximately 26.4 mmtonnes (equal to 528 kbbl/d), with a conversion index of 42%.

Eni's 100% owned refineries have a balanced capacity of

18.4 mmtonnes (equal to 368 kbbl/d), with a 38% conversion index. In 2022, Eni's refineries throughputs in Italy and outside Italy were 18.84 mmtonnes, substantially in line compared to 2021.

REFINING SYSTEM IN 2022

	Ownership	Balanced refining capacity (Eni's share)(a)	Utilization rate (Eni's share)	Conversion index (b)	Fluid catalytic cracking (FCC)(c)	Residue Conversion(c)	Hydro-cracking(c)	Visbreaking/ Thermal Cracking(c)
	(%)	(kbbl/d)	(%)	(%)	(kbbl/d)	(kbbl/d)	(kbbl/d)	(kbbl/d)
Wholly-owned refineries		368	72	38	38	51	76	0
Italy
Sannazzaro	100	180	81	40	38	26	59	0
Taranto	100	104	70	56		25	17
Livorno	100	84	55	11
Partially-owned refineries		160	91	51	136	28	97	40
Italy
Milazzo	50	100	92	60	50	28	36
Germany
Vohburg/Neustadt (Bayernoil)	20	41	86	36	45		38	14
Schwedt	8.33	19	101	31	41		23	26
TOTAL		528	79	42	173	79	172	40

(a) Including 20% share in ADNOC Refining, balanced refining capacity amounted to 691 kbl/d.

(b) Conversion index: catalytic cracking equivalent capacity/topping capacity (% wt).

(c) Conversion unit capacities are 100%.

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 40%. 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 has a strong market position due to the fact that is the only refinery in southern continental Italy, and is 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.

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 (LC-Finer).

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 approximately 60 kbbl/d to supply Eni's distribution network in Bavaria and in the Eastern Germany.

2. Biorefining

In Italy, Eni has converted the sites of Venice and Gela into modern biorefineries, with a fully operational installed capacity of 1.1 million tonnes/year, able to produce diesel with a lower carbon content, adopting the EcofiningTM proprietary technology.

Venezia (Porto Marghera): biorefinery started-up in June 2014, with a production capacity of 0.4 mmtonnes/y. The refinery exploits the proprietary EcofiningTM technology to transform biofeedstock (vegetable oil, waste and residues) into biofuels.

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 will 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 2022, the volumes of biofuels processed from vegetable oil were 543 ktonnes down by 18.3% from the previous period (down by 122 ktonnes), as a result of standstill at Gela biorefinery particularly in the first months of 2022, partially offset by higher throughputs at Venice biorefinery (up 33 ktonnes).

In addition, the incidence rate of palm oil supplied for the production of biodiesel was reduced by approximately 28 percentage points compared to 2021, leveraging on the startup of a new Biomass Treatment Unit (BTU).

In October, Eni has definitively ended the supply of palm oil at the Venice and Gela biorefineries for production of hydrogenated biofuels. In 2022, production of biofuels (HVO) amounted to approximately 428 ktonnes (down by 27%) according to certifications in use (European RED and related directives).

In October 2022, a first cargo of vegetable oil for biorefining, produced at Eni's Makueni agri-hub in Kenya, has been shipped to Gela's biorefinery. Vegetable oil is obtained processing castor, croton, and cotton seeds. In Kenya, the initial production of 2,500 tons in 2022, is planned to scale up rapidly to 20,000 tons in 2023. This project marks the start of Eni's innovative model of agri-business vertically integrated with its biorefineries, supplying sustainable feedstock not competing with the food chain and capable of significantly contribute to local development and to the circular economy. This model will be replicated in other African countries, longterm partners of Eni.

As a part of Eni's decarbonisation strategy and with the aim to increase the availability of decarbonized and sustainable products to our customers and to achieve the Scope 1+2+3 emission reduction targets, in October an economic feasibility study of the construction and management of a biorefinery in Livorno was launched. The project involves three new plants for the production of hydrogenated biofuels: a biogenic feedstock pre-treatment unit, a 500,000 ton/year Ecofining™ plant and a plant for the production of hydrogen from methane gas. The transformation plan for the Livorno refinery will be discussed with local institutions and trade unions, within the framework of a participatory and inclusive industrial relations model.

In December, Eni, Euglena and Petronas started a collaboration in order to estimate the economic feasibility for the construction and management of a biorefinery in Malaysia in the Pengerang Integrated Complex (PIC). The three parties are currently carrying out technical and economic feasibility assessments for the proposed project. The investment decision is expected to be reached by 2023 and the plant is targeted to be operational by 2025. The expected capacity of the biorefinery is about 650,000 tonnes/y with an expected production capacity up to 12,500 barrels/d of biofuel (SAF, HVO and bionaphtha). The raw materials will not compete with those in the food chain. The biorefinery will use the Honeywell UOP's Ecofining™ process which was developed by Eni in cooperation with Honeywell UOP.

In February 2023, a collaboration agreement was announced with the refining company PBF relating to the St. Bernard Renewables LLC (SBR) biorefining project, under construction in Louisiana (USA) through a joint venture. The transaction, subject to the usual closing conditions, involves a capital injection of \$835 million by the subsidiary Eni Sustainable Mobility and the contribution of the biorefining technologies. The start-up of the plant is expected in the first half of 2023 with the target of a processing capacity of about 1.1 million tons/year, mainly for the production of HVO Diesel.

PRODUCTION CYCLE OF BIOFUELS

Sustainable mobility initiatives

As a part of the path of transport and mobility decarbonization, Eni signed a letter of intent with IVECO to develop a sustainable mobility platform for commercial fleets by offering innovative vehicles powered by biofuels and other sustainable energy vectors, such as HVO (Hydrotreated Vegetable Oil), biomethane, hydrogen and electricity and the related infrastructure. The areas of collaboration include Eni's offer of 100%-pure HVO for IVECO heavy trucks equipped with engines able to operate on it. HVO biofuels derived from materials of vegetable origin and waste, produced using the proprietary Ecofining™ technology at Eni's Venice and Gela biorefineries. 100%-pure HVO enables CO2 emission reductions of 60% to 90% (calculated throughout the lifecycle) compared to the standard fossil fuel mix.

Furthermore, Eni and IVECO intend to speed up the market availability of biomethane, a renewable fuel from agro-industrial waste, which can be both compressed (CNG) and liquified (LNG). This will be made possible through partnerships in Italy and abroad.

In order to develop projects for the air transport decarbonization, Eni in December signed an agreement with DHL Express Italy and SEA Group, which manages Milan Malpensa and Milan Linate airports to test Eni Biojet, a Sustainable Aviation Fuel (SAF) 20% blended with JetA1 and produced exclusively from waste raw materials, animal fat and used vegetable oils. In 2022, some flights departing from Malpensa were be also powered by SAF produced by Eni in its Livorno refinery in partnership with Eni's biorefinery in Gela.

In February 2023, Eni signed a Memorandum of Understanding (MoU) with Saipem finalized to boost biofuels on Saipem's drilling and construction naval vessels, with particular attention to operations in the Mediterranean Sea. This agreement represents an important milestone for Eni and Saipem, confirming the mutual commitment to diversifying energy sources and to reducing the carbon footprint across offshore operations.

As part of the development of hydrogen mobility, in June 2022 Eni inaugurated a new Eni-branded hydrogen refuelling station in Mestre (Venice). This is the first road mobility station to open to the public in an urban area in Italy where it is also possible to refuel using hydrogen.

The system is equipped with two dispensing points with a capacity of over 100 kg/day, which can refuel vehicles in about 5 minutes and buses.

Furthermore in October 2022, two projects by Eni and Enel Green Power, aimed at developing green hydrogen will receive public funding approved by the European Commission under IPCEI Hy2Us, the European project aimed at supporting the hydrogen value chain. The electrolyzers with a capacity of 20 MW and 10 MW will be implemented at the Gela biorefinery in Sicily, and at Taranto refinery, respectively. Both will use PEM (polymer electrolyte membrane) technology.

(a) Data on capacity relate to Eni's share of balanced capacity in 2022.

(b) After the first quarter of 2022, following the Russia's military aggression of Ukraine, Eni interrupted Russian crude oil purchase from cargo market. During 2022, the PCK refinery continued to supply Ural crude oil through Druzbha pipeline. Russian crude oil was replaced by volumes from Central Asia and North Africa.

3. 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 1,156 kilometers in operation.

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

4. Oxygenates

Eni's, through its subsidiary Ecofuel (100% Eni's share), sells approximately 1.08 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 81% 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 19% is purchased.

Marketing

1. Retail sales in Italy

Eni is a leader in the Italian retail market of refined products with

a 21.7% market share, slightly decreased from 2021 (22.2%). In 2022, retail sales in Italy were 5.38 mmtonnes, with an increase compared to 2021 (0.26 mmtonnes or up by 5.1%) as a result of higher volumes of gasoline and gasoil sold, thanks to the progressive economy reopening and greater mobility of people in the first part of 2022. Average gasoline and gasoil throughput (1,445 kliters) up by 83 kliters from 2021.

As of December 31, 2022, Eni's retail network in Italy consisted of 4,003 service stations, lower by 75 units from December 31, 2021 (4,078 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (-90 units), the negative balance of the company owned stations (-9 units), partly balanced by the increase of 24 lease stations.

2. Retail sales in the rest of Europe

Retail sales in theRest of Europe were 2.12 mmtonnes, substantially unchanged compared to 2021 as result of higher volumes sold in Germany, France, Spain and Austria partly balanced by the decrease of the volumes in Switzerland.

At December 31, 2022, Eni's retail network in the Rest of Europe consisted of 1,240 units, increasing by 4 unit from December 31, 2021, mainly thanks to the openings in Germany and Austria balanced by the reduction in Switzerland and France. Average throughput (2,027 kliters) increased by 2 kliters compared to 2021 (2,025 kliters).

3. Wholesale business

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 6.19 mmtonnes, increasing by 2.7% from 2021, due to higher sales of jet fuel for the recovery of the aviation sector which offset lower volumes marketed in all the other segments.

Supplies of feedstock to the petrochemical industry (0.39 mmtonnes) decreased by 25%.

Wholesale sales in the Rest of Europe were 2.44 mmtonnes, up by 11.4% from 2021 particularly in Germany, Austria and Spain.

Other sales in Italy and outside Italy (10.76 mmtonnes) decreased by 0.74 mmtonnes or down by 6.4% 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 2022, Eni share of LPG market in Italy was 15.4%.

Outside Italy, the main market of Eni is Ecuador, with a market share of 35.5%.

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 2022, Eni's share of lubricants market in Italy was 14.4%, in Europe approximately 2% and on a worldwide base 1%.

Eni operates in more than 80 Countries by subsidiaries, licensees and distributors.

4. 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". As of December 31, 2022, the Enjoy fleet consisted of 2,110 FIAT 500 cars and 69 FIAT Cargo vehicles distributed over the major Italian cities: Milan (883 FIAT 500 and 32 Cargo); Rome (743 FIAT 500 and 22 Cargo); Turin (243 FIAT 500 and 5 Cargo); Bologna (145 FIAT 500 e 10 Cargo); Florence (96 FIAT 500).

In line with the decarbonization strategy, in 2022 Eni strengthened the collaboration with XEV, through a cooperation agreement to explore areas of collaboration concerning research and development into sustainable mobility systems to reduce the environmental impact of vehicles, the development of battery swapping technology and the assembly of the car manufacturer's vehicles. The agreement is aimed at developing the electric city car sector jointly, in particular to implement XEV's battery swapping technology, but also for the possible assembly of XEV vehicles or parts of them in Italy and for the management of the car battery life cycle from production to installation, maintenance and end-of-life through recycling. During 2022, Eni's car sharing service has been expanded through the introduction of the XEV YOYO (248) in Turin, Bologna, Florence and Milan. XEV YOYO is an electric car always in operation thanks to battery swapping, alternative to plug-in columns.

In 2022, the average number of rentals, including FIAT and XEV YOYO vehicles, was 215,000 monthly.

PURCHASES

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

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

AVAILABILITY OF REFINED PRODUCTS

(mmtonnes)	2022	2021	2020	2019	2018
ITALY
At wholly-owned refineries	13.25	14.01	12.72	17.26	16.78
Less input on account of third parties	(1.70)	(1.71)	(1.75)	(1.25)	(1.03)
At affiliate refineries	4.57	4.21	3.85	4.69	4.93
Refinery throughputs on own account	16.12	16.51	14.82	20.70	20.68
Consumption and losses	(1.11)	(1.11)	(0.97)	(1.38)	(1.38)
Products available for sale	15.01	15.40	13.85	19.32	19.30
Purchases of refined products and change in inventories	7.02	7.38	7.18	7.27	7.50
Products transferred to operations outside Italy	(0.40)	(0.67)	(0.66)	(0.68)	(0.54)
Consumption for power generation	(0.31)	(0.31)	(0.35)	(0.35)	(0.35)
Sales of products	21.32	21.80	20.02	25.56	25.91
Bio throughputs	0.54	0.67	0.71	0.31	0.25
OUTSIDE ITALY
Refinery throughputs on own account	2.72	2.27	2.18	2.04	2.55
Consumption and losses	(0.19)	(0.18)	(0.17)	(0.18)	(0.20)
Products available for sale	2.53	2.09	2.01	1.86	2.35
Purchases of refined products and change in inventories	3.54	3.41	3.39	4.17	4.12
Products transferred from Italian operations	0.40	0.67	0.66	0.68	0.54
Sales of products	6.47	6.17	6.06	6.71	7.01
REFINERY THROUGHPUTS ON OWN ACCOUNT IN ITALY AND OUTSIDE ITALY	18.84	18.78	17.00	22.74	23.23
of which: refinery throughputs of equity crude on own account	5.02	3.86	3.55	4.24	4.14
TOTAL SALES OF REFINED PRODUCTS IN ITALY AND OUTSIDE ITALY	27.79	27.97	26.08	32.27	32.92
Crude oil sales	0.21	0.60	0.67	0.44	0.28
TOTAL SALES	28.00	28.57	26.75	32.71	33.20

PRODUCTION AND SALES

(mmtonnes)	2022	2021	2020	2019	2018
Products:
Gasoline	5.36	5.01	3.99	5.80	5.97
Gasoil	7.29	7.43	6.94	8.81	8.81
Jet fuel/kerosene	1.25	0.95	0.63	1.53	1.60
Fuel oil	0.83	1.26	1.61	2.07	2.25
LPG	0.23	0.30	0.42	0.40	0.42
Lubricants	0.09	0.38	0.29	0.49	0.59
Petrochemical feedstock	0.85	0.78	0.67	0.76	0.72
Other	1.65	1.38	1.32	1.32	1.28
Total products	17.54	17.49	15.87	21.18	21.64
Sales:
Italy	21.32	21.80	20.02	25.56	25.91
Gasoline	1.92	1.72	1.46	1.91	1.90
Gasoil	6.58	6.49	6.21	7.36	7.28
Jet fuel/kerosene	1.50	0.92	0.70	1.92	1.98
Fuel oil	0.04	0.03	0.02	0.06	0.07
LPG	0.48	0.48	0.45	0.56	0.58
Lubricants	0.05	0.08	0.08	0.08	0.08
Petrochemical feedstock	0.39	0.52	0.61	0.83	0.96
Other	10.36	11.56	10.49	12.84	13.06
Rest of Europe	5.99	5.68	5.60	6.26	6.56
Gasoline	1.11	1.06	1.13	1.31	1.30
Gasoil	2.92	2.78	2.73	3.02	3.16
Jet fuel/kerosene	0.11	0.07	0.09	0.29	0.33
Fuel oil	0.13	0.08	0.13	0.09	0.13
LPG	0.06	0.06	0.05	0.06	0.07
Lubricants	0.07	0.09	0.08	0.08	0.09
Other	1.59	1.54	1.39	1.41	1.48
Extra Europe	0.48	0.49	0.46	0.45	0.45
LPG	0.47	0.47	0.45	0.44	0.44
Lubricants	0.01	0.02	0.01	0.01	0.01
Worldwide
Gasoline	3.03	2.78	2.59	3.22	3.20
Gasoil	9.50	9.27	8.94	10.38	10.44
Jet fuel/kerosene	1.61	0.99	0.79	2.21	2.31
Fuel oil	0.17	0.11	0.15	0.15	0.20
LPG	1.01	1.01	0.95	1.06	1.09
Lubricants	0.13	0.19	0.17	0.17	0.18
Petrochemical feedstock	0.39	0.52	0.61	0.83	0.96
Other	11.95	13.10	11.88	14.25	14.54
TOTAL WORLDWIDE SALES	27.79	27.97	26.08	32.27	32.92

SALES OF REFINED PRODUCTS BY MARKET

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

SALES BY PRODUCT/MARKET

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

SERVICE STATIONS

(units)	2022	2021	2020	2019	2018
Italy	4,003	4,078	4,134	4,184	4,223
Ordinary stations	3,892	3,967	4,019	4,068	4,108
Highway stations	111	111	115	116	115
Outside Italy	1,240	1,236	1,235	1,227	1,225
Germany	486	480	480	476	471
France	153	155	158	155	155
Austria/Switzerland	592	592	597	596	599
Spain	9	9
Service stations selling premium products	4,848	4,872	4,619	4,669	4,675
of which service stations selling Diesel +	3,676	3,712	3,663	3,683	3,537
Service stations selling LNG	19	15	4	4	4
Service stations selling LPG and natural gas	1,348	1,111	1,091	1,086	1,043
Non-oil sales (€ million)	177	160	147.8	156	144

AVERAGE THROUGHPUT

	(kliters/no. of service stations)	2022	2021	2020	2019	2018
Italy		1,445	1,362	1,206	1,586	1,589
Germany		2,714	2,696	2,800	3,186	3,247
France		1,985	1,892	1,650	2,043	2,144
Austria/Switzerland		1,664	1,707	1,609	2,033	2,018
Average throughput		1,587	1,521	1,390	1,766	1,776

ENI IN AT A GLANCE

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

RETAIL MARKET SHARES OUTSIDE ITALY

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

CAPITAL EXPENDITURE

(€ million)	2022	2021	2020	2019	2018
Italy	538	470	535	743	661
Outside Italy	85	68	53	72	65
	623	538	588	815	726
Refining, supply and logistic	491	390	462	683	587
Italy	469	375	449	662	578
Outside Italy	22	15	13	21	9
Marketing	132	148	126	132	139
Italy	69	95	86	81	83
Outside Italy	63	53	40	51	56
TOTAL	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 (265), 23 production sites, 6 research centers (Brindisi, Ferrara, Mantova, Novara, Ravenna and Rivalta), as well as a large and efficient retail network located in 34 different Countries.

In line with the energy transition path, in 2022 the development of green chemistry business progressed through the strengthening of the partnership with Novamont. The commitment to Matrìca – the joint venture set up between Versalis and Novamont at Porto Torres specializing in manufacturing bioproducts from renewable sources – has been reaffirmed aiming at enhancing technologies and productive assets in order to fully develop its products, also within supply chains integrated with the two partners, by focusing on growth in the previously referenced markets. In this context, shareholder agreements have been also redefined: Versalis has increased its interest in Novamont from 25% to 35%.

As part of the initiatives aimed at developing circular economy, Versalis in June 2022 announced the start of the use of packaging made from recycled raw materials from post-consumer industrial packaging.Toachievethisgoal,twoprojectshavebeenimplemented, "Bag to Bag" and "Liner to Liner", in order to create a virtuous circle aimed at recovering and recycling industrial polyethylene packaging bags and putting them back into the system.

As far as the "Bag to Bag" project is concerned, sacks are made with 50% of recycled materials and are fully recyclable. The project has passed the testing phase at all Versalis operating sites. Currently, the sacks are used at the Ragusa and Ferrara plants and by the end of the year, the project will be operational at Brindisi and at the foreign subsidiaries located in Dunkerque and Oberhausen.

The "Liner to Liner" project, developed and applied mainly at the Brindisi site, relates to the interior coverings of containers used for transporting bulk polyethylene, called "Liners". They were sent for recycling and transformed into new Liners, containing 50% of recycled plastic. The two projects will help to reduce the consumption of virgin raw materials by 50% respectively with a consequent reduction in terms of CO2 .

As part of the transformation process of the Porto Marghera site, Versalis signed a new agreement with Forever Plast, an Italian company, leader in Europe in the recycling of postconsumer plastics. The agreement involves the acquisition of an exclusive licence to build an advanced mechanical recycling unit for selected post-consumer plastics from waste sorting, in particular polystyrene and high-density polyethylene. The plant, which is scheduled to go onstream in 2024 will have a transformation capacity of 50,000 tonnes/y and will produce recycled polymer compounds. The deal also includes an extension of the contract with Forever Plast, which will ensure the volumes required for the expansion of Versalis' portfolio of recycled products and consolidate its current competitive advantage. The company has already started a collaboration based on which new polystyrene compounds with up to 75% of recycled content, already available on the market under the Versalis Revive® brand, were developed for food packaging, thermal insulation and the electrical sector.

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.

As a further step in the decarbonization path, in December 2022, Versalis acquired from DSM a technology to produce enzymes for second-generation ethanol to be employed at the Crescentino plant

Enzymes are essential for the production of second-generation sugars as they allow the saccharification of biomass. Second

to integrate the proprietary Proesa® technology to deliver sustainable bioethanol and chemical products from lignocellulosic biomass.

generation sugars are then transformed, through fermentation processes, into cellulosic ethanol – "advanced bioethanol" – or into other chemical intermediates. Bioethanol, produced through Proesa® technology, is used for the formulation of petrol with a renewable component.

Furthermore, starting from the technology acquired, Versalis plans to proceed with research activities to ensure further development in this area.

INTEGRATED PLATFORM FOR PLASTIC WASTE RECYCLING

VERSALIS' INTERNATIONAL PRESENCE

(*) 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

Petrochemical sales of 3,676 ktonnes decreased from 2021 (down by 775 ktonnes, or 17.4%). In particular, the main changes were registered in olefine (down by 22.8%), elastomer (down by 18.7%), in the polyethylene (down by 16.4%) and in the styrenic (down by 12.1%). In Moulding & Compounding business sales were 76 ktonnes.

Average unit sales prices of the intermediates business increased by 34.2% from 2021, with aromatics and olefins up by 47.2% and 32.4%, respectively. The polymers reported an increase of 22.0% from 2021.

Petrochemical production of 6,775 ktonnes were down by 1,701 ktonnes from 2021 due to lower production of intermediates business (down by 1,387 ktonnes), particularly olefins and aromatics.

The main decreases in production were registered at the Porto Marghera site (down by 821 ktonnes), Dunkerque (down by 563 ktonnes) and Priolo (down by 164 ktonnes).

Nominal capacity of plants decreased from 2021. The average plant utilization rate calculated on nominal capacity was 59.0% lower compared to 2021 (66.0% in 2021).

INTERMEDIATES

Intermediates revenues (€2,368 million) increased by €202 million from 2021 (up by 9.3%) mainly reflecting the higher commodity prices scenario. Sales (2,158 ktonnes) decreased by 18.5% vs. 2021.

Reductions were registered in olefins (down by 22.8%), aromatics (down by 15.3%) and derivatives (down by 0.8%).

Average prices increased by 34.2%, in particular aromatics (up by 47.2%), olefins (up by 32.4%) and derivatives (up by 23.5%). Intermediates production (4,897 ktonnes) registered a decrease of 22.1% from 2021. Decreases were also registered in olefins (down by 24.3%), in the aromatics (down by 22.6%), while a slight increase was reported in derivatives (up by 0.6%).

ENI IN AT A GLANCE NATURAL RESOURCES ENERGY EVOLUTION ANNEX 87

POLYMERS

Polymers revenues (€3,203 million) increased by €89 million or 2.9% from 2021 due to the increase of the average unit prices. The styrenics business benefitted by the increase of sale prices (up by 25.8%), notwithstanding the reduction of volumes sold (down by 12.1%) for lower product availability and lower demand. The reduction in volumes is mainly attributable to SAN (down by 33.1%), EPS (down by 26.8%) and GPPS (down by 11.5%), partly offset by higher sales of ABS (up by 11.9%).

In the elastomers business, the decrease of sold volumes (down by 18.7%) was attributable to the decline in European and extra-European consumption and to the non-competitive prices, due to the higher energy costs. In particular were registered lower sales of BR (down by 23.7%), SBR (down by 17.9%) and NBR rubbers (down by 17.3%). Overall, the sold volumes of polyethylene business reported a decrease (down by 16.4%) with lower sales of LDPE (down by 27.7%), EVA (down by 12.5%) and HDPE (down by 10.6%). In addition, average sale prices increased by 13.4%.

Polymers productions (1,873 ktonnes) decreased by 14.2% from the 2021 due to the lower productions of polyethylene (down by 17.3%), elastomers (down by 17.2%) and styrenics (down by 10%).

OILFIELD CHEMICALS, BIOCHEM AND MOULDING & COMPOUNDING

Oilfiled chemicals revenues (€83 million) increased by 26.6% (up by €17 million compared to 2021) as a result of the combined mix of increased unit price for formulations and for the associated services. Biochem business revenues (€25 million) decreased by €35 million from 2021, mainly due to lower production of disinfectant, following the end of the health emergency, partly offset by the sale of energy produced at the biomass power plant at the Crescentino hub, at full capacity.

Moulding & Compounding business revenues of €327 million include compounding activities for €78 million, moulding for €108 million and the Padanaplast activities for €141 million.

PRODUCT AVAILABILITY

(ktonnes)	2022	2021	2020	2019	2018
Intermediates	4,897	6,284	5,861	5,818	7,130
Polymers	1,873	2,184	2,211	2,250	2,353
Biochem	5	8	1
Petrochemical productions	6,775	8,476	8,073	8,068	9,483
Moulding & Compounding	81	20
PRODUCTIONS	6,856	8,496	8,073	8,068	9,483
Consumption and losses	(3,923)	(4,590)	(4,366)	(4,307)	(5,085)
Purchases and change in inventories	819	565	632	534	548
TOTAL AVAILABILITY	3,752	4,471	4,339	4,295	4,946
Intermediates	2,158	2,648	2,539	2,519	3,095
Polymers	1,494	1,771	1,790	1,766	1,851
Oilfield chemicals	21	24	9	10
Biochem	3	8	1
Petrochemical sales	3,676	4,451	4,339	4,295	4,946
Moulding & Compounding	76	20
TOTAL SALES	3,752	4,471	4,339	4,295	4,946

REVENUES BY GEOGRAPHIC AREA

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

REVENUES BY PRODUCT

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

CAPITAL EXPENDITURE

(€ million)	2022	2021	2020	2019	2018
	255	190	182	118	151
of which:
- upkeeping	115	56	79	42	21
- plant upgrades and efficecny	22	23	35	34	84
- HSE and Asset integrity	90	76	39	27	26
- decarbonization	3	21	13	4	8
- green & circular	20	4	7	4
- other	5	10	9	7	12

KEY PERFORMANCE INDICATORS		2022	2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)(a)	(total recordable injuries/worked hours) x 1,000,000	0.31	0.29	0.32	0.62	0.60
of which: employees		0.26	0.49	0.00	0.30	0.31
contractors		0.39	0.00	0.73	0.95	1.16
Sales from operations(b)	(€ million)	20,883	11,187	7,536	8,448	8,218
Operating profit (loss)		(825)	2,355	660	74	340
Adjusted operating profit (loss)		615	476	465	370	262
- Plenitude		345	363	304	256	178
- Power		270	113	161	114	84
Adjusted net profit (loss)		397	327	329	275	189
Capital expenditure		631	443	293	357	238
Plenitude
Retail gas sales	(bcm)	6.84	7.85	7.68	8.62	9.13
Retail power sales to end customers	(TWh)	18.77	16.49	12.49	10.92	8.39
Retail/business customers	(million of POD)	10.07	10.04	9.70	9.42	9.19
EV charging points(c)	(thousand)	13.1	6.2	3.4	n.d	n.d
Energy production sold from renewable sources	(GWh)	2,553	986	340	61	12
Renewables installed capacity at period end	(MW)	2,198	1,137	335	174	40
Power
Power sales in the open market	(TWh)	22.37	28.54	25.34	28.28	28.54
Thermoelectric production		21.37	22.31	20.95	21.66	21.62
Employees at year end		2,794	2,464	2,092	2,056	2,056
of which outside Italy		698	600	413	358	337
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	9.76	10.03	9.63	10.22	10.47
Direct GHG emissions (Scope 1)/equivalent produced electricity (Enipower)(a)	(gCO2 eq./kWh eq.)	393	380	391	394	402

(a) Calculated on 100% operated assets.

(b) Before elimination of intragroup sales. (c) 2020 proforma figure is disclosed for comparative purpose.

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)	Installed capacity Technology	Retail + Business customers (mln)	EV charging points	Installed capacity of power stations (GW)(b)
Italy	1.0		8.1	>13,000	2.3
France	0.1		1.1
Iberian Peninsula	0.3		0.3			Photovoltaic
USA	0.8					Onshore wind
UK	0.5					Offshore wind
Other	0.2		0.6			Storage
TOTAL	~3		10.1	>13,000	2.3

(a) Data as of December 31, 2022 (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

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 valueadded solutions, mainly focused on the segment of small and medium-sized enterprises and on the housing facilities. With the aim to optimize its portfolio, in December 2022, Plenitude sold to Depa Infrastructure, a Greek subsidiary of Italgas, a 49% stake of Eda Thess (Gas Distribution Company of Thessaloniki – Thessaly SA), one of the main operators of the gas infrastructure system in Greece.

GAS DEMAND

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 million of retail clients (gas and electricity) in Italy and Europe. In particular, clients located all over Italy are 8.1 million.

GAS SALES BY MARKET

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

RETAIL AND BUSINESS CUSTOMERS (mln of POD)

RETAIL GAS SALES

In 2022, retail gas sales in Italy and in the rest of Europe amounted to 6.84 bcm, down by 1.01 bcm or 12.9% from the previous year. Sales in Italy amounted to 4.65 bcm down by 9.5% from 2021, as a result of lower sales to the retail segment.

Sales on the European markets of 2,19 bcm decreased by 19.2% (down by 0.52 bcm) compared to 2021. Lower sales were recorded in France and Greece.

GAS SALES IN ITALY (bmc)

RETAIL POWER SALES TO END CUSTOMERS

In 2022, retail power sales to end customers amounted to 18.77 TWh, managed by Plenitude and the subsidiaries in France, Greece and Spain increased by 13.8% from 2021, due to the development of activities in Italy and abroad.

Renewables

Plenitude is engaged in the renewable energy business (solar and wind) 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

As a part of the development of the wind and photovoltaic sector, representing a pillar of our growth strategy, in 2022 continued the expansion in the national and international renewable energy market, with acquisitions able to be quickly integrated into Eni's portfolio, in particular:

• in Italy and Spain, started a new partnership with Infrastrutture SpA to develop solar and wind power projects, by acquiring a 65% stake in Hergo Renewables SpA, a company holding a portfolio of projects in the two countries, with a total capacity of approximately 1.5 GW; in addition Plenitude acquired 100% of PLT (PLT Energia Srl and SEF Srl and their respective subsidiaries and affiliates), an integrated Italian group engaged in producing renewable electricity and in supplying energy to the retail segment. The acquired company includes 90,000 retail customers in Italy and a portfolio capacity of 1.6 GW. The agreement allows Plenitude to strengthen its presence in the two countries, consolidating a vertically integrated platform;
• in the United States, Plenitude, through its US subsidiary Eni New Energy US Inc., acquired the 81 MW Kellam photovoltaic plant, located in North Texas (closing in January 2023). The plant, sold by Hanwha Qcells USA Corp., joins the other assets within Texas and the rest of the United States in Plenitude's portfolio, which reaches, with this transaction, an installed capacity of 878 MW in the US market. The operation was carried out with the support of Novis Renewables, LLC, a partnership between Eni New Energy US, Inc. and Renantis North America, Inc., which is exclusive for the US and dedicated to the development of solar, wind and storage projects. The plant stands on over 150 hectares of land and the produced energy will be sold to a local power company.

In order to strengthen the presence in the offshore wind sector and contribute to the expansion of the Norwegian joint venture Vårgrønn, Plenitude and HitecVision, in October 2022, have signed an agreement which involved the transfer to the JV of the 20% stake held by Plenitude in the Dogger Bank (UK) offshore wind projects. As a result of this transaction, HitecVision increased its stake in Vårgrønn from 30.4% to 35% through a capital injection.

This operation laid the foundations for the establishment of a financially independent entity focused on the development in the offshore wind sector, expanding the existing industrial collaboration with HitecVision and accelerating its growth path. Finally, to support the energy transition process, Plenitude in 2022 invested in innovative technological solutions, in particular in EnerOcean S.L., a Spanish developer of the W2Power technology for floating wind power. The agreement is structured as a long-term partnership focused on the deployment of the W2Power technology as a lead solution for floating wind power developments worldwide. Plenitude will contribute to the development program of EnerOcean S.L. with capital and expertise and will initially retain a 25% stake in the Company, which will continue to operate independently.

DEVELOPMENTS IN THE RENEWABLE BUSINESS

In linewith the strategy of energy transition and decarbonization of product and process, Plenitude inaugurated:

• the Badamsha 2 wind farm located in the Aktobe region, Kazakhstan, the second wind installation in the region, allowing to double the installed capacity of Badamsha 1 project (48 MW, for a total amount of 96 MW installed in the Country);
• • the 104.5 MW El Monte wind farm, located in the Spanish region of Castilla La Mancha, built in collaboration with the strategic partner Azora Capital. The plant will produce about 300 GWh/year, equivalent to the domestic consumption of 100,000 households;
• • the 263 MW "Golden Buckle Solar Project" solar farm in Brazoria County, Texas (USA), in January 2023. The plant was built in just over a year and will produce a yearly average of 400 to 500 GWh of solar energy. The plant development was carried out with the support of Novis Renewables, LLC.

GreenIT, a joint venture with the Italian agency CDP Equity, acquired the entire portfolio of Fortore Energia Group, consisting of four onshore wind farms operating in Italy with a total capacity of 110 MW (56 MW Eni's share); furthermore the JV signed an additional agreement with the equity fund Copenhagen Infrastructure Partners (CIP) to build and operate two floating offshore wind farms in Sicily and Sardinia, with an expected total capacity of approximately 750 MW.

In January 2023, Plenitude signed an agreement with Simply Blue Group for the joint development of floating offshore wind projects in Italy. The first two floating offshore wind projects, "Messapia" in Apulia and "Krimisa" in Calabria, have already been submitted to the relevant authorities. The Messapia project, located about 30 km off the Otranto coast, will have a total capacity of 1.3 GW and will be able to provide annual power generation of about 3.8 TWh. The Krimisa project, located about 45 km off the coast of Crotone, will have a total capacity of 1.1 GW and will be able to provide annual energy production of up to 3.5 TWh.

TECHNOLOGY DEVELOPMENTS

Eni signed an agreement with Ansaldo Energia to develop projects based on innovative technological solutions for electricity storage as an alternative to electrochemical batteries. Under the terms of the agreement, these technologies, which are being studied, are implemented in synergy in some industrial sites of Eni and its subsidiaries in Italy, exploiting the potential of existing power generation and consumption systems. Electricity storage is essential to overcome the structural limitations of renewables in terms of predictability and intermittency and is consequently necessary to promote their development.

SOLAR AND WIND POWER INSTALLED CAPACITY AS OF DECEMBER 31, 2022

ENERGY PRODUCTION FROM RENEWABLE SOURCES

(GWh)	2022	2021	2020	2019	2018
Energy production from renewable sources	2,553	986	340	61	12
of which: photovoltaic	1,135	398	223	61	12
wind	1,418	588	116
of which: Italy	818	400	112	54	12
outside Italy	1,735	586	227	7
of which: own consumption(a)	1%	8%	23%	60%	75%

(a) Electricity for Eni's production sites consumptions.

Energy production from renewable sources amounted to 2,553GWh (of which 1,135 GWh photovoltaic and 1,418 GWh wind) up by 1,567 GWh compared to 2021. 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, France, Spain and United States, as well as from the organic development of projects in the United States and Kazakhstan.

Follows breakdown of the installed capacity by Country and technology:

(megawatt)	2022	2021	2020	2019	2018
Renewables installed capacity at period end	2,198	1,137	335	174	40
of which: photovoltaic (including installed storage capacity)	54%	49%	80%	80%	100%
wind	46%	51%	20%	20%
	2022	2021	2020	2019	2018
Italy	844	466	112	82	35
Outside Italy	1,354	671	223	92	5
Algeria(a)			5	5	5
Australia	64	64	64
France	114	108
Pakistan		10	10	10
Tunisia(a)			9	4
United States	797	269	87
Spain	283	129
Kazakhstan	96	91	48	34
TOTAL INSTALLED CAPACITY AT PERIOD END (INCLUDING INSTALLED STORAGE POWER)	2,198	1,137	335	174	40
of which: installed storage power	7	7	8	7

(a) Asset trasferred to other segments in the fourth quarter of 2021.

As of December 31, 2022, the total installed capacity from renewables amounted to 2.2 MW, doubled from 2021, mainly thanks to the construction of the photovoltaic plant of Brazoria, in the United States and the onshore wind farm Badamsha 2 in Kazakhstan, as well as, the acquisition of assets of Fortore Energia and PLT in Italy, the Corazon photovoltaic plant, in the United States and the Cuevas assets in Spain.

ITALY

As of December 31, 2022, the total installed capacity amounted to 0.8 GW. In 2022, Eni's commitment in Italy progressed with the acquisition of 100% of PLT, an integrated Italian group with an installed capacity of over 0.3 GW already in operation, as well as 0.1 GW under construction and 1.2 GW of projects under development (mainly wind) in Italy and Spain. In addition, through GreenIT, a joint venture with CDP Equity, Plenitude acquired the whole portfolio of the Fortore Energia Group, consisting of four onshore wind farms operating in Italy with a total capacity of 110 MW (56 MW in Eni's share). To support growth in the mediumand long-term, the JV has signed a further agreement with the Copenhagen Infrastructure Partners (CIP) for the construction and operation of two floating offshore wind farms in Sicily and Sardinia, with a total expected capacity of about 750 MW.

OUTSIDE ITALY

United States

As of December 31, 2022, the total installed capacity amounted to 0.8 GW, almost tripled compared to the end of 2021, in particular, leveraging on: (i) the construction of the 263 MW "Golden Buckle Solar Project" photovoltaic plant in Brazoria County, Texas, built in just over a year, with an average production of solar energy between 400 and 500 GWh/year; (ii) the acquisition of the approximately 266 MW Corazon I photovoltaic plant in operation located in Texas. In addition, in Texas, were finalized the acquisitions of the Guajillo storage project, of about 200/400 MWh, with start-up expected by the end of 2023, and the 81 MW Kellam photovoltaic plant (closing in January 2023).

Spain and France

As of December 31, 2022, the installed capacity in Spain and France amounted to 0.4 GW, almost doubled compared to the end of 2021 thanks in particular to the acquisition of the Cuevas assets (105 MW) and the organic development of the Cerillares photovoltaic plant (50 MW), in Spain, as well as minor projects in France (6 MW).

United Kingdom

In the United Kingdom, Eni is engaged in the development of the offshore wind projects through the Vårgrønn joint venture (65% Plenitude, 35% HitecVision) to which in October 2022 was transferred the 100% stake of the consolidated company Eni North Sea Wind Ltd, holding 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 (468 MW Plenitude's share) with latest generation turbines installed off the British coasts.

Kazakhstan

Eni owns a total capacity in the Country amounting to 96 MW, thanks to the construction of the two 48 MW wind farms in the Badamsha area. Plenitude plans to increase the capacity by further 50 MW through the construction of a photovoltaic plant near Shaulder in the southern region of Kazakhstan.

Australia

TheKatherine photovoltaic park (34 MW), builtin 2019,represents the largest plant in the Northern Territory and is integrated with a 6 MW energy storage system. Thanks to these technologies, the plant is able to predict and compensate possible variations in solar radiation by drawing energy from the storage system, so as to minimize the impact on the electricity grid. In the Australian Northern Territory, Eni owns a solar capacity of 25 MW at the Bachelor and Manton Dam sites.

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 one of the largest and most 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, 2022, there are about 13,000 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.

As a recognition of Eni's commitment to sustainable infrastructure development, the European Climate, Infrastructure and Environment Executive Agency (CINEA) has selected a project of Be Charge, the Plenitude integrated operator for electric mobility, to build, by 2025, one of the largest high-speed charging networks in Europe for EVs along key European transport corridors (TEN-T) and at parking areas and in major cities in 8 Country: Italy, Spain, France, Austria, Germany, Portugal, Slovenia and Greece.

POWER

In 2022, Eni finalized the disposal to the investment company Sixth Street of the 49% share in Enipower which owns six gas power plants. Eni holds the remaining 51% share and maintains the operative control of Enipower as well as the consolidation of the company.

AVAILABILITY OF ELECTRICITY

Eni's power generation sites are located in Brindisi, Ferrera Erbognone, Ravenna, Mantova, Ferrara and Bolgiano. As of December 31, 2022, installed operational capacity of Enipower's power plants was 2.3 GW. In 2022, thermoelectric power generation was 21.37 TWh, decreasing by 0.94 TWh from the previous year. Electricity trading (9.49 TWh) reported a decrease of 18.3% from 2021, in order to optimize inflows and outflows of power.

POWER GENERATION

		2022	2021	2020	2019	2018
Purchases
Natural gas	(mmcm)	4,218	4,670	4,346	4,410	4,300
Other fuels	(ktep)	175	93	160	276	356
of which: steam cracking		86	68	88	91	94
Production
Power generation	(TWh)	21.37	22.31	20.95	21.66	21.62
Steam	(ktonnes)	6,900	7,362	7,591	7,646	7,919
Installed generation capacity	(GW)	2.3	4.5	4.5	4.5	4.5

POWER SALES IN THE OPEN MARKET

In 2022, power sales in the open market were 22.37 TWh, representing a decrease of 21.6% compared to 2021, due to lower volumes marketed at Power Exchange.

POWER SALES

(TWh)	2022	2021	2020	2019	2018
Power generation	21.37	22.31	20.95	21.66	21.62
Trading of electricity(a)	9.49	11.62	13.04	15.55	14.49
Availability	30.86	33.93	33.99	37.21	36.11
Power sales in the open market	22.37	28.54	25.34	28.28	28.54
Power sales to Plenitude	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 and operational generation capacity as of December 31, 2022: 2,297 MW.

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

Power stations	Installed capacity as of December 31, 2022(a)(b) (MW)	Effective start-up	Technology	Fuel
Brindisi	647	2006	CCGT	Gas
Ferrera Erbognone	536	2004	CCGT	Gas/syngas
Mantova	375	2005	CCGT	Gas
Ravenna	502	2004	CCGT	Gas
Ferrara	204	2008	CCGT	Gas
Bolgiano	33	2012	Power Station	Gas
Photovoltaic sites(c)	0.1	2011-2014	Photovoltaic	Photovoltaic
	2,297

(a) Installed operational capacity.

(b) Eni's share of capacity.

(c) Plants managed by Enipower Mantova.

CAPITAL EXPENDITURE

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

District heating station Combined cycle - CCGT

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:

Coherently with the expertise gained and in agreement with institutions and stakeholders, Eni Rewind assesses the projects for enhancement and reuse of reclaimed areas, allowing the environmental recovery of former industrial area and the resumption of the local economy.

Eni Rewind operates in 13 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. Main activities on remediation, water and waste management, valorization of restorated sites are progressing mainly in Ravenna, Porto Torres, Gela, Cengio and Porto Marghera.

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 pre-processing 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.

Ponticelle area will become a hub for sustainable reclamation, waste enhancement and green energy production also leveraging on the collaboration with Eni New Energy, Plenitude' subsidiary, engaged in the realization of a photovoltaic plant and a storage lab.

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 2022, 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.

Currently, there are 43 treatment plants fully in operation and managed in Italy, with over 35 million cubic meters of treated water in 2022. 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 2022 about 9.9 million cubic meters of water have been reused after treatment, with an increase of 10% compared to 2021.

At the end of 2022, completed the installation of 57 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 1,200 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 2022, Eni Rewind managed a total of approximately 2 million tonnes1 of waste by sending for recovery or disposal at external plants.

In particular, the recovery index (ratio of recovered/recoverable waste) in 2022 was 74%: the slight increase compared to 2021 (73%) 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.

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 2022, Eni Rewind achieved the highest certification, with unlimited amount, relative to the categories OS14 and OG12.

Non captive initiatives

In line with the path started in 2020, Eni Rewind expanded the scope of its activities, by offering services outside Eni group. In particular, in 2022, Eni Rewind progressed in the implementation of activities for the qualification process of leading national and international operators as suppliers.

Finalized also the registration to the MEPA portal (Electronic Market of the Public Administration).

In addition, Eni Rewind was awarded the Raggruppamento Temporaneo d'Impresa (RTI) of the reclamation of the former Q8 plant in Naples, and will carry out the design, environmental analysis, supply, installation and management of a thermal desorber.

Under the public regime, the post-assignment due diligence process by ANAS of requirements of the RTI in which Eni Rewind is principal, was completed, in order to start activities for investigation services and characterization in the Adriatic lot (Emilia-Romagna, Marche, Abruzzo, Molise, Puglia), where

⁽¹⁾ The volume includes waste deriving from the management of the environmental activities of the points of sale network (about 112 ktonnes), whose "producer" is the same environmental company in charge of the execution out the work.

Eni Rewind, through its environmental laboratories, will provide specific chemical analysis services.

In September 2022, Eni Rewind signed the relevant act setting up the RTI to subscribe the contract with Anas.

Relating to the private sector, Eni Rewind was awarded a threeyear framework agreement (renewable for a further 2 years) for the transport and disposal service of about 50 ktonnes of waste generated by the Refinery of Milazzo (RAM).

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 order to implement the Memorandum of Understanding (MoU) signed in 2021 with the National Authority for oil and gas of the Kingdom of Bahrain (NOGA), the Bahrain Petroleum Company refinery (BAPCO) requested in 2022 to Eni Rewind a large-scale implementation of the e-Hyrec treatment system, including services such as engineering, supply, installation and technical assistance.

Eni Rewind is progressing in the collaboration with Eni on "water management & valorization" projects.

In June 2022, completed the feasibility studies for the optimization of waste water management and process water through its reuse for plants located in Algeria and Libya.

In 2022, carried out the environmental engineering activities for the remediation of company service stations in France and Germany. In the new mandate for the reclamations of the service stations' areas signed with Eni Sustainable Mobility effective from January 1st, 2023, Eni Rewind will support the company in the feasibility of environmental activities also for the remediation of service stations of the European network.

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

Tables

FINANCIAL DATA

PROFIT AND LOSS ACOOUNT

(€ million)	2022	2021	2020	2019	2018
Sales from operations	132,512	76,575	43,987	69,881	75,822
Other income and revenues	1,175	1,196	960	1,160	1,116
Operating expenses	(105,497)	(58,716)	(36,640)	(54,302)	(59,130)
Other operating income (expense)	(1,736)	903	(766)	287	129
Depreciation, depletion, amortization	(7,205)	(7,063)	(7,304)	(8,106)	(6,988)
Net impairment reversals (losses) of tangible and intangible and right-of-use assets	(1,140)	(167)	(3,183)	(2,188)	(866)
Write-off of tangible and intangible assets	(599)	(387)	(329)	(300)	(100)
Operating profit (loss)	17,510	12,341	(3,275)	6,432	9,983
Finance income (expense)	(925)	(788)	(1,045)	(879)	(971)
Income (expense) from investments	5,464	(868)	(1,658)	193	1,095
Profit (loss) before income taxes	22,049	10,685	(5,978)	5,746	10,107
Income taxes	(8,088)	(4,845)	(2,650)	(5,591)	(5,970)
Tax rate (%)	36.7	45.3		97.3	59.1
Net profit (loss)	13,961	5,840	(8,628)	155	4,137
Attributable to:
- Eni's shareholders	13,887	5,821	(8,635)	148	4,126
- Non-controlling interest	74	19	7	7	11

SUMMARIZED GROUP BALANCE SHEET

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

SUMMARIZED GROUP CASH FLOW STATEMENT

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

CHANGES IN NET BORROWINGS

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

SALES FROM OPERATIONS

	(€ million)	2022	2021	2020	2019	2018
Exploration & Production		31,200	21,742	13,590	23,572	25,744
Global Gas & LNG Portfolio		48,586	20,843	7,051	11,779	14,807
Refining & Marketing and Chemicals		59,178	40,374	25,340	42,360	46,483
Plenitude & Power		20,883	11,187	7,536	8,448	8,218
Corporate and other activities		1,879	1,698	1,559	1,676	1,588
Consolidation adjustments		(29,214)	(19,269)	(11,089)	(17,954)	(21,018)
		132,512	76,575	43,987	69,881	75,822

SALES TO CUSTOMERS
	(€ million)	2022	2021	2020	2019	2018
Exploration & Production		12,896	8,846	6,359	10,499	9,943
Global Gas & LNG Portfolio		41,230	16,973	5,362	9,230	11,931
Refining & Marketing and Chemicals		58,470	40,051	24,937	41,976	46,088
Plenitude & Power		19,726	10,517	7,135	7,972	7,684
Corporate and other activities		190	188	194	204	176
		132,512	76,575	43,987	69,881	75,822

SALES BY GEOGRAPHIC AREA OF DESTINATION

2022	2021	2020	2019	2018
60,090	29,968	14,717	23,312	25,279
25,413	14,671	9,508	18,567	20,408
21,748	12,470	8,191	6,931	7,052
6,929	4,420	2,426	3,842	5,051
9,062	7,891	4,182	8,102	9,585
9,191	7,040	4,842	8,998	8,246
79	115	121	129	201
72,422	46,607	29,270	46,569	50,543
132,512	76,575	43,987	69,881	75,822

SALES BY GEOGRAPHIC AREA OF ORIGIN

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

PURCHASES, SERVICES AND OTHER

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

PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

PAYROLL AND RELATED COSTS

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

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

(€ million)	2022	2021	2020	2019	2018
Exploration & Production	6,018	5,976	6,273	7,060	6,152
Global Gas & LNG Portfolio	217	174	125	124	226
Refining & Marketing and Chemicals	506	512	575	620	399
Plenitude & Power	358	286	217	190	182
Corporate and other activities	139	148	146	144	59
Impact of unrealized intragroup profit elimination	(33)	(33)	(32)	(32)	(30)
Total depreciation, depletion and amortization	7,205	7,063	7,304	8,106	6,988
Exploration & Production	432	(1,244)	1,888	1,217	726
Global Gas & LNG Portfolio	(12)	26	2	(5)	(73)
Refining & Marketing and Chemicals	717	1,342	1,271	922	193
Plenitude & Power	(37)	20	1	42	2
Corporate and other activities	40	23	21	12	18
Impairment losses (impairment reversals) of tangible and intangible and right of use assets, net	1.140	167	3.183	2.188	866
Depreciation, depletion, amortization, impairments and reversals, net	8,345	7,230	10,487	10,294	7,854
Write-off of tangible and intangible assets	599	387	329	300	100
	8,944	7,617	10,816	10,594	7,954

OPERATING PROFIT BY SEGMENT

(€ million)	2022	2021	2020	2019	2018
Exploration & Production	15,908	10,066	(610)	7,417	10,214
Global Gas & LNG Portfolio	3,730	899	(332)	431	387
Refining & Marketing and Chemicals	460	45	(2,463)	(682)	(501)
Plenitude & Power	(825)	2,355	660	74	340
Corporate and other activities	(1,901)	(816)	(563)	(688)	(668)
Impact of unrealized intragroup profit elimination	138	(208)	33	(120)	211
	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 ofinventory accounting as required by IFRS, except in those business segments where inventories are utilized as a lever to optimize margins.

Finally, the same special charges/gains are excluded from the Eni's share of results at JVs and other equity accounted entities, including any profit/loss on inventory holding.

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

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

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

Adjusted operating and net profit

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

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

Inventory holding gain or loss

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

Special items

These include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones. Exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturallyoccurring 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 wheneveritis deemed thatthe 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 cash-equivalents, 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. Itis 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.

(€ million)	Exploration & Production	Global Gas & LNG Portfolio	Refining & Marketing and Chemicals	Plenitude & Power	Corporate and other activities	Impact of unrealized intragroup profit elimination	Group
	15,908	3,730	460	(825)	(1,901)	138	17,510
			(416)			(148)	(564)
	30		962	2	1,062		2,056
	432	(12)	717	(37)	40		1,140
	2						2
	(27)		(10)	1	(5)		(41)
	34		52		1		87
	34	4	46	65	53		202
		(1,805)	4	1,412			(389)
	(57)	244	(33)	(5)			149
	55	(98)	147	2	128		234
	503	(1,667)	1,885	1,440	1,279		3,440
	16,411	2,063	1,929	615	(622)	(10)	20,386
	(319)	(17)	(36)	(11)	(669)		(1,052)
	2,086	4	637	(6)	(91)		2,630
	(7,402)	(1,068)	(616)	(201)	673	6	(8,608)
							39.2
	10,776	982	1,914	397	(709)	(4)	13,356
							55
							13,301
							13,887
							(401)
							(185)
							13,301

2021	(€ million)	Exploration & Production	Global Gas & LNG Portfolio	Refining & Marketing and Chemicals	Plenitude & Power	Corporate and other activities	Impact of unrealized intragroup profit elimination	Group
Reported operating profit (loss)		10,066	899	45	2,355	(816)	(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
- 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)		9,293	580	152	476	(593)	(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)	247	68	(4,395)
Tax rate (%)								50.3
Adjusted net profit (loss)		5,543	169	62	327	(1,576)	(176)	4,349
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	(€ million)	Exploration & Production	Global Gas & LNG Portfolio	Refining & Marketing 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
- 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)
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	(€ million)	Exploration & Production	Global Gas & LNG Portfolio	Refining & Marketing 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
- 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
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

EX

2018	(€ million)	Exploration & Production	Global Gas & LNG Portfolio	Refining & Marketing 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
- 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
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

BREAKDOWN OF SPECIAL ITEMS

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

ADJUSTED OPERATING PROFIT BY SEGMENT

(€ million)	2022	2021	2020	2019	2018
Exploration & Production	16,411	9,293	1,547	8,640	10,850
Global Gas & LNG Portfolio	2,063	580	326	193	278
Refining & Marketing and Chemicals	1,929	152	6	21	360
Plenitude & Power	615	476	465	370	262
Corporate and other activities	(622)	(593)	(507)	(602)	(583)
Impact of unrealized intragroup profit elimination(a)	(10)	(244)	61	(25)	73
	20,386	9,664	1,898	8,597	11,240

ADJUSTED NET PROFIT BY SEGMENT

(€ million)	2022	2021	2020	2019	2018
Exploration & Production	10,776	5,543	124	3,436	4,955
Global Gas & LNG Portfolio	982	169	211	100	118
Refining & Marketing and Chemicals	1,914	62	(246)	(42)	224
Plenitude & Power	397	327	329	275	189
Corporate and other activities	(709)	(1,576)	(1,205)	(866)	(948)
Impact of unrealized intragroup profit elimination(a)	(4)	(176)	36	(20)	56
	13,356	4,349	(751)	2,883	4,594
of which attributable to:
Eni's shareholders	13,301	4,330	(758)	2,876	4,583
Non-controlling interest	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)	2022	2021	2020	2019	2018
Finance income (expense) related to net borrowings	(939)	(849)	(913)	(962)	(627)
- Interest and other finance expense on ordinary bonds	(507)	(475)	(517)	(618)	(565)
- Net finance income (expense) on financial assets held for trading	(53)	11	31	127	32
- Net expenses on other financial assets valued atfair value with effects on profit and loss	(2)
- Interest and other expense due to banks and other financial institutions	(128)	(94)	(102)	(122)	(120)
- Interest on lease liabilities	(315)	(304)	(347)	(378)
- Interest from banks	57	4	10	21	18
- Interest and other income on financial receivables and securities held for non operating purposes	9	9	12	8	8
Income (expense) from derivative financial instruments	13	(306)	351	(14)	(307)
- Derivatives on exchange rate	(70)	(322)	391	9	(329)
- Derivatives on interest rate	81	16	(40)	(23)	22
- Options	2
Exchange differences, net	238	476	(460)	250	341
Other finance income (expense)	(275)	(177)	(96)	(246)	(430)
- Interest and other income on financing receivables and securities held for operating purposes	128	67	97	112	132
- Finance expense due to the passage of time (accretion discount)	(199)	(144)	(190)	(255)	(249)
- Other finance income (expense)	(204)	(100)	(3)	(103)	(313)
	(963)	(856)	(1,118)	(972)	(1,023)
Finance expense capitalized	38	68	73	93	52
	(925)	(788)	(1,045)	(879)	(971)

INCOME (EXPENSE ON) FROM INVESTMENTS

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

PROPERTY, PLANT AND EQUIPMENT BY SEGMENT

(€ million)	2022	2021	2020	2019	2018
Property, plant and equipment by segment, gross
Exploration & Production	158,137	162,617	150,613	159,597	151,046
Global Gas & LNG Portfolio	2,653	2,665	2,164	2,332	2,286
Refining & Marketing & Chemicals	28,058	27,390	26,713	26,154	25,428
Plenitude & Power	5,442	4,497	3,641	3,402	3,249
Corporate and other activities	2,155	2,205	2,134	1,944	1,875
Impact of unrealized intragroup profit elimination	(633)	(628)	(624)	(614)	(600)
	195,812	198,746	184,641	192,815	183,284
Property, plant and equipment by segment, net
Exploration & Production	49,645	50,332	48,296	55,702	53,535
Global Gas & LNG Portfolio	735	849	579	738	826
Refining & Marketing & Chemicals	3,316	3,342	4,132	5,015	5,300
Plenitude & Power	2,534	1,653	860	708	624
Corporate and other activities	320	369	348	323	327
Impact of unrealized intragroup profit elimination	(218)	(246)	(272)	(294)	(310)
	56,332	56,299	53,943	62,192	60,302

CAPITAL EXPENDITURE BY SEGMENT

(€ million)	2022	2021	2020	2019	2018
Exploration & Production	6,362	3,861	3,472	6,996	7,901
Global Gas & LNG Portfolio	23	19	11	15	26
Refining & Marketing and Chemicals	878	728	771	933	877
Plenitude & Power	631	443	293	357	238
Corporate and other activities	166	187	107	89	94
Impact of unrealized intragroup profit elimination	(4)	(4)	(10)	(14)	(17)
Capital expenditure	8,056	5,234	4,644	8,376	9,119
Investments and purchase of consolidated subsidiaries and businesses	3,311	2,738	392	3,008	244
Total capex and investments and purchase of consolidated subsidiaries and businesses	11,367	7,972	5,036	11,384	9,363

CAPITAL EXPENDITURE BY GEOGRAPHIC AREA OF ORIGIN

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

NET BORROWINGS

			Cash and	Financial assets measured at fair value thorugh profit	Financing receivables held for non-operating	Leasing
	(€ million)	Debt and bonds	cash equivalents	or loss	purposes	Liabilities	Total
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)	2022	2021	2020	2019	2018
Exploration & Production	Italy	3,192	3,364	3,692	3,491	3,477
	Outside Italy	5,497	6,045	6,123	6,781	6,971
		8,689	9,409	9,815	10,272	10,448
Global Gas & LNG Portfolio	Italy	282	276	290	293	318
	Outside Italy	588	571	410	418	416
		870	847	700	711	734
Refining & Marketing and Chemicals	Italy	8,986	9,028	8,915	9,035	8,863
	Outside Italy	4,146	4,044	2,556	2,591	2,594
		13,132	13,072	11,471	11,626	11,457
Plenitude & Power	Italy	2,096	1,864	1,679	1,698	1,719
	Outside Italy	698	600	413	358	337
		2,794	2,464	2,092	2,056	2,056
Corporate and other activities	Italy	6,322	6,503	6,999	6,971	6,625
	Outside Italy	381	394	418	417	381
		6,703	6,897	7,417	7,388	7,006
Total employees at year end	Italy	20,878	21,035	21,575	21,488	21,002
	Outside Italy	11,310	11,654	9,920	10,565	10,699
		32,188	32,689	31,495	32,053	31,701

BREAKDOWN BY POSITION

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

QUARTERLY INFORMATION

MAIN FINANCIAL DATA(a)

2022	(€ million)	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
Exploration & Production		4,381	4,867	4,272	2,891	16,411
Global Gas & LNG Portfolio		931	(14)	1,083	63	2,063
Refining & Marketing and Chemicals		(91)	1,104	537	379	1,929
Plenitude & Power		185	140	172	118	615
Corporate and other activities		(174)	(120)	(185)	(143)	(622)
Unrealized profit intragroup elimination and consolidation adjustments		(41)	(136)	(107)	274	(10)
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

2021	(€ million)	I quarter	II quarter	III quarter	IV quarter
Net sales from operations		14,494	16,294	19,021	26,766	76,575
Operating profit (loss)		1,862	1,995	2,793	5,691	12,341
Adjusted operating profit (loss)		1,321	2,045	2,492	3,806	9,664
Exploration & Production		1,378	1,841	2,444	3,630	9,293
Global Gas & LNG Portfolio		(30)	24	50	536	580
Refining & Marketing and Chemicals		(120)	190	186	(104)	152
Plenitude & Power		202	108	64	102	476
Corporate and other activities		(146)	(111)	(109)	(227)	(593)
Unrealized profit intragroup elimination and consolidation adjustments		37	(7)	(143)	(131)	(244)
Net (loss) profit(b)		856	247	1,203	3,515	5,821
Capital expenditure		1,139	1,248	1,200	1,647	5,234
Investments		520	351	553	1,314	2,738
Net borrowings at period end		17,507	15,323	16,622	14,324	14,324

2020	(€ million)	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
Exploration & Production		1,037	(807)	515	802	1,547
Global Gas & LNG Portfolio		233	130	64	(101)	326
Refining & Marketing and Chemicals		16	73	21	(104)	6
Plenitude & Power		191	85	57	132	465
Corporate and other activities		(204)	(135)	(84)	(84)	(507)
Unrealized profit intragroup elimination and consolidation adjustments		34	220	(36)	(157)	61
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

2022	I quarter	II quarter	III quarter	IV quarter
Average price of Brent dated crude oil(a)	101.40	113.78	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)	1,043	1,032	2,082	1,009	1,294
TTF(d)	1,018	1,011	2,077	999	1,279

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)	198	264	491	987	487
TTF(d)	196	262	500	975	486

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)	121	74	91	156	112
TTF(d)	102	56	81	155	100

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

(b) Source: ECB. (c) 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 (d) €/kcm.

MAIN OPERATING DATA

2022		I quarter	II quarter	III quarter	IV quarter
Liquids production	(kbbl/d)	780	740	707	776	751
Natural gas production	(mmcf/d)	4,638	4,447	4,583	4,426	4,523
Hydrocarbons production	(kboe/d)	1,662	1,586	1,578	1,617	1,610
Italy		84	82	81	80	82
Rest of Europe		214	180	181	182	189
North Africa		240	270	268	291	267
Egypt		358	353	343	328	346
Sub-Saharian Africa		284	283	316	273	289
Kazakhstan		164	108	81	150	126
Rest of Asia		181	174	171	171	174
Americas		124	125	127	135	127
Australia and Oceania		13	11	10	7	10
Hydrocarbons production sold	(mmboe)	136.0	134.7	127.7	133.6	532.0
Sales of natural gas to third parties	(bcm)	16.71	12.11	12.02	14.26	55.10
Own consumption of natural gas		1.55	1.27	1.31	1.29	5.42
Sales to third parties and own concumption		18.26	13.38	13.33	15.55	60.52
Sales of natural gas of Eni's affiliates (net to Eni)		0.00	0.00	0.00	0.00	0.00
Total sales and own consumption of natural gas - GGP		18.26	13.38	13.33	15.55	60.52
Retail and business gas sales		3.42	0.95	0.61	1.86	6.84
Retail and business power sales to end customers	(TWh)	5.10	4.49	4.77	4.43	18.79
Power sales in the open market		5.73	5.61	5.96	5.07	22.37
Sales of refined products	(mmtonnes)	6.10	7.22	7.25	7.22	27.79
Retail sales in Italy		1.20	1.35	1.46	1.38	5.39
Wholesale sales in Italy		1.32	1.60	1.71	1.55	6.18
Retail sales Rest of Europe		0.48	0.52	0.58	0.53	2.11
Wholesale sales Rest of Europe		0.55	0.64	0.65	0.60	2.44
Wholesale sales outside Europe		0.13	0.11	0.14	0.13	0.51
Other markets		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

(bbl)	158.987 l oil(a)	0.159 m3 petrolio	162.602 m3 gas		5,263 ft3 gas
			5,800,000 btu
(bbl/d)	~50 t/y
(m3 )	1,000 l oil	6.71 bbl	1,033 m3 gas		36,481 ft3 gas
(toe)	1,160.49 l oil	7.299 bbl	1.161 m3 petrolio	1,187 m3 gas	41,911 ft3 gas
					(average reference density 32.35 f API, relative density 0.8636)

GAS

1 cubic meter	(m3 )	0.976 l oil	0.00671 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 tep
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	(tLNG)	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	94.448 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 m3oil	112.4 m3 gas	3,968.3 ft3 gas

(a) l oil:liters of oil

CONVERSION OF MASS

	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 feet (ft3 )	barrel (bbl)	liter (lt)	cubic meter (m3 )
ft3	1	0.1781	28.32	0.02832
bbl	5.263	1	159	0.158984
l	0.035315	0.0065	1	0.001
m3	35.31485	6.65	103	1

Eni SpA

Headquarters

Piazzale Enrico Mattei, 1 - Rome - Italy Capital Stock as of December 31, 2022: € 4,005,358,876.00 fully paid Tax identification number 00484960588

Branches

Via Emilia, 1 - San Donato Milanese (Milan) - Italy Piazza Ezio Vanoni, 1 - San Donato Milanese (Milan) - Italy

Contacts

eni.com +39-0659821 800940924 segreteriasocietaria.azionisti@eni.com

Investor Relations

Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com

Layout and supervision K-Change - Rome

Printing Tipografia Facciotti – Rome

Printed on Fedrigoni Arena Smooth