Eni Fact Book 202 1

Eni Fact Book

2021

We are an energy company.

We concretely support a just energy transition, with the objective of preserving our planet and promoting an efficient and sustainable access to energy for all. Our work is based on passion and innovation, on our unique strengths and skills, on the equal dignity of each person, recognizing diversity as a key value for human development, on the responsibility, integrity and transparency of our actions. We believe in the value of long-term partnerships with the Countries

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

Global goals for a sustainable development

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

Eni Fact Book 2021

ENI AT A GLANCE	2
Main data	4
Eni share performance	7
NATURAL RESOURCES	9
Exploration & Production	10
Global Gas & LNG Portfolio	55
ENERGY EVOLUTION	63
Refining & Marketing and Chemicals	64
Refining & Marketing	65
Chemicals	75
Plenitude & Power	80
Plenitude	85
Power	86
Environmental activities	88
ANNEX	91
Tables	92
Financial Data	92
Employees	105
Quarterly information	106

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.

Eni at a glance

THE ACCELERATION OF OUR TRANSFROMATION

In 2021 Eni achieved one of the best economic and financial performance of the last ten years, accelerating the transformation of its business model in order to become a leader in the energy transition and pursue the carbon neutrality strategy by 2050. Actions have been deployed by preserving capital and financial robustness through capital discipline and defining priorities in capital allocation.

Leveraging on selective capital allocation, cost reduction and portfolio optimizations, Eni has been able to seize the upside of the scenario, executing excellent operational and financial results. In particular, the main implemented actions are the following:

Portfolio enhancement

Implemented initiatives to enhance value from the portfolio restructuring, through the creation of independent and focused vehicles able to attract capital, create value and accelerate growth:

} launched the listing process of Plenitude, the subsidiary which integrates gas & power retail activities, renewables and e-mobility;
} listed at the Norwegian stock market a share of Vår Energi, representing the largest IPO in the European O&G sector for over a decade, enabling Eni to enhance the investments made so far and ensuring the growth of the company thanks to new possible capital contribution;
} launched with BP the combination of our respective significant portfolio in Angola through the establishment of Azule Energy, a new controlled business combination aimed at accelerate the development of assets in the country.

Business transformation

Accelerated the transformation of our business model. The target of "Net Zero Scope 1+2+3 to 2050" will allow Eni's customers to move towards an offer of decarbonised products:

} Group's installed capacity from renewables: approximately 1.2 GW, more than tripled in 2021, exceeding the target of more than 2 GW of installed capacity including assets under construction;
} reduced the incidence of palm oil in the production of biodiesel in biorefining and production of related bio feestocks;
} biofuel projects: made progress in the agreements with the governments of Kenya, Angola, Congo, Benin, Ivory Coast, Mozambique and Rwanda for the creation of an integrated agro-biofeedstock supply chains not in competition with the food chain to supply Eni's biorefineries and decarbonize the local energy mix.

EXCELLENT OPERATIONAL AND FINANCIAL RESULTS

-5% vs. 2020 Indirect GHG emissions (Scope 3) from use of sold products

eq.

Main data

KEY FINANCIAL DATA

(€ million)	2021	2020	2019	2018
Net sales from operations	76,575	43,987	69,881	75,822
of which: Exploration & Production	21,742	13,590	23,572	25,744
Global Gas & LNG Portfolio	20,843	7,051	11,779	14,807
Refining & Marketing and Chemicals	40,374	25,340	42,360	46,483
Plenitude & Power	11,187	7,536	8,448	8,218
Corporate and other activities	1,698	1,559	1,676	1,588
Impact of unrealized intragroup profit elimination and consolidation adjustments	(19,269)	(11,089)	(17,954)	(21,018)
Operating profit (loss)	12,341	(3,275)	6,432	9,983
of which: Exploration & Production	10,066	(610)	7,417	10,214
Global Gas & LNG Portfolio	899	(332)	431	387
Refining & Marketing and Chemicals	45	(2,463)	(682)	(501)
Plenitude & Power	2,355	660	74	340
Corporate and other activities	(816)	(563)	(688)	(668)
Impact of unrealized intragroup profit elimination	(208)	33	(120)	211
Operating profit (loss)	12,341	(3,275)	6,432	9,983
Exclusion of special items	(1,186)	3,855	2,388	1,161
Exclusion of inventory holding (gains) losses	(1,491)	1,318	(223)	96
Adjusted operating profit (loss)(a) ᵃ⁾	9,664	1,898	8,597	11,240
of which: Exploration & Production	9,293	1,547	8,640	10,850
Global Gas & LNG Portfolio	580	326	193	278
Refining & Marketing and Chemicals	152	6	21	360
Plenitude & Power	476	465	370	262
Corporate and other activities	(593)	(507)	(602)	(583)
Impact of unrealized intragroup profit elimination and consolidation adjustments	(244)	61	(25)	73
Net profit (loss)(b) ᵇ⁾	5,821	(8,635)	148	4,126
Adjusted net profit (loss)(a)(b) ⁽ᵇ⁾	4,330	(758)	2,876	4,583
Net cash flow from operating activities	12,861	4,822	12,392	13,647
Capital expenditure(c)	5,313	4,644	8,376	9,119
Shareholders' equity including non-controlling interests at year end	44,519	37,493	47,900	51,073
Net borrowings at year end before IFRS 16	8,987	11,568	11,477	8,289
Net borrowings at year end after IFRS 16	14,324	16,586	17,125	n.a.
Leverage before lease liability ex IFRS 16	0.20	0.31	0.24	0.16
Leverage after lease liability ex IFRS 16	0.32	0.44	0.36	n.a.
Net capital employed at year end	58,843	54,079	65,025	59,362
of which: Exploration & Production	48,014	45,252	53,358	50,358
Global Gas & LNG Portfolio	(823)	796	1,327	1,742
Refining & Marketing and Chemicals	9,815	8,786	10,215	6,960
Plenitude & Power	5,474	2,284	1,787	1,869

(a) Non-GAAP measures.

(b) Attributable to Eni's shareholders.

KEY MARKET INDICATORS

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

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

(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)

		2021	2020	2019	2018
Employees at year end	(number)	32,689	31,495	32,053	31,701
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.34	0.36	0.34	0.35
of which: employees		0.40	0.37	0.21	0.37
contractors		0.32	0.35	0.39	0.34
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	40.1	37.8	41.2	43.4
Indirect GHG emissions (Scope 2)		0.81	0.73	0.69	0.67
Indirect GHG emissions (Scope 3) from use of sold products(b)		176	185	204	203
Net GHG Lifecycle Emissions (Scope 1+2+3)(c)		456	439	501	505
Net Carbon Intensity (Scope 1+2+3)(c)	(gCO2 eq./MJ)	67	68	68	68
Carbon efficiency index Group	(tonnes CO2 eq./kboe)	32.0	31.6	31.4	33.9
Total volume of oil spills (> 1 barrel)	(barrels)	4,406	6,824	7,265	6,687
of which: due to sabotage and terrorism		3,051	5,866	6,232	4,022
operational		1,355	958	1,033	2,665
Freshwater withdrawals	(mmcm)	125	113	128	117
Reinjected production water	(%)	58	53	58	60
Group's renewable installed capacity	(MW)	1,188	351	190	n.s.
R&D expenditure	(€ million)	177	157	194	197
First patent filing application	(number)	30	25	34	43

Exploration & Production Employees at year end	(number)	2021 9,409	2020 9,815	2019 10,272	2018 10,448
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.25	0.28	0.33	0.30
Net proved reserves of hydrocarbons	(mmboe)	6,628	6,905	7,268	7,153
Reserves life index	(years)	10.8	10.9	10.6	10.6
Hydrocarbons production (e)	(kboe/d)	1,682	1,733	1,871	1,851
Organic reserve replacement ratio	(%)	55	43	92	100
Profit per boe(d)(f)	(\$/boe)	4.8	3.8	7.7	6.7
Opex per boe(e)		7.5	6.5	6.4	6.8
Finding & Development cost per boe(e)(f)		20.4	17.6	15.5	10.4
Direct GHG emissions (Scope 1)(h)	(mmtonnes CO2 eq.)	22.3	21.1	22.8	24.1
Direct GHG emissions (Scope 1)/operated hydrocarbon gross production(g)(h)	(tonnes CO2 eq./kboe)	20.2	20.0	19.6	21.4
Net Carbon Footprint upstream (Scope 1+2)(c)
	eq.)	11.0	11.4	14.8	14.8
Volumes of hydrocarbon sent to routine flaring(h)	(mmtonnes CO2 (billion Sm³)	1.2	1.0	1.2	1.4
Methane fugitive emissions	(ktonnes CH4 )	9.2	11.2	21.9	38.8
Oil spills due to operations (> 1 barrel)(h)	(barrels)	436	882	988	1,595

Global Gas & LNG Portfolio Employees at year end	(number)	2021 847	2020 700	2019 711	2018 734

Employees at year end	(number)	847	700	711	734
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.00	1.15	0.56	0.51
Natural gas sales	(bcm)	70.45	64.99	72.85	76.60
of which: Italy		36.88	37.30	37.98	39.17
outside Italy		33.57	27.69	34.87	37.43
LNG sales		10.9	9.5	10.1	10.3

(a) KPIs refer to 100% of the operated assets, where not indicated.

(g) Hydrocarbon gross production from fields fully operated by Eni (Eni's interest 100%) amounting to 1,041 mmboe, 1,009 mmboe and 1,114 mmboe in 2021, 2020 and 2019, respectively.

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

⁽c) Calculated on equity bases and included carbon sink.

⁽d) Related to consolidated subsidiaries. (e) Includes Eni's share in joint ventures and equity-accounted entities.

⁽f) Three-year average.

Refining & Marketing e Chimica 2021 2020 2019 2018 Employees at year end (number) 13,072 11,471 11,626 11,457 TRIR (Total Recordable Injury Rate) (total recordable injuries/worked hours) x 1,000,000 0.80 0.80 0.27 0.56 Capacity of biorefineries (mmtonnes/year) 1.1 1.1 1.1 0.4 Production sold of cetified biofuels (ktonnes) 585 622 256 219 Retail market share in Italy (%) 22.3 23.2 23.6 24.0 Retail sales of petroleum products in Europe (mmtonnes) 7.23 6.61 8.25 8.39 Service stations in Europe at year end (number) 5,314 5,369 5,411 5,448 Average throughput of service stations in Europe (kliters) 1,521 1,390 1,766 1,776 Balanced capacity of refineries (Eni's share) (kbbl/d) 548 548 548 548 Total volume of oil spills due to operations (> 1 barrel) (barrels) 919 75 48 1,069 Direct GHG emissions (Scope 1) (mmtonnes CO2 eq.) 6.72 6.65 7.97 8.19 SOx emissions (sulphur oxide) (ktonnes SO2 eq.) 2.67 2.78 4.16 4.80 GHG emissions/Refinery throughputs (raw and semi-finished materials) (tonnes CO2 eq./ktonnes) 228 248 248 253 Production of petrochemical products (ktonnes) 8,476 8,073 8,068 9,483 Sales of petrochemical products 4,451 4,339 4,295 4,946 Average chemical plant utilization rate (%) 66 65 67 76

Plenitude & Power		2021	2020	2019	2018
Employees at year end	(number)	2,464	2,092	2,056	2,056
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.29	0.32	0.62	0.60
Retail and business gas sales	(bcm)	7.85	7.68	8.62	9.13
Retail and business power sales to end customers	(TWh)	16.49	12.49	10.92	8.39
Thermoelectric production		22.36	20.95	21.66	21.62
Electricity sold to hub		28.54	25.33	28.28	28.54
Renewables installed capacity at period end	(MW)	1,137	335	174	40
Electricity sold to hub	(GWh)	986	340	61	12

ENI SHARE PERFORMANCE

SHARE DATA

		2021	2020	2019	2018
Net profit (loss)(a)(b)	(€)	1.60	(2.42)	0.04	1.15
Dividend pertaining to the year		0.86	0.36	0.86	0.83
Dividend to Eni's shareholders pertaining to the year(c)	(€ million)	3,022	1,286	3,078	2,989
Cash dividend to Eni's shareholders		2,358	1,965	3,018	2,954
Cash flow(a)	(€)	3.61	1.35	3.45	3.79
Dividend yield(d)	(%)	7.1	4.2	6.3	5.9
Net profit (loss) per ADR(a)(b)(e)	(\$)	3.78	(5.53)	0.09	2.72
Dividend per ADR(e)		2.10	0.82	1.93	1.96
Cash flow per ADR(a)(e)		8.54	3.08	7.72	8.95
Dividend yield per ADR(d)(e)		7.1	4.2	6.3	5.9
Number of shares at period-end	(million)	3,539.8	3,572.5	3,572.5	3,601.1
Weighted average number of shares outstanding(f)		3,566.0	3,572.5	3,592.2	3,601.1
Total Shareholders Return (TSR)	(%)	52.4	(34.1)	6.7	4.8

(a) Fully diluted. Ratio of net profit/cash flow and average number of shares outstanding in the period. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by Reuters (WMR) for the period presented.

(b) Pertaining to Eni's shareholders.

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

(e) One ADR represents 2 shares. Net profit and cash flow data in USD were converted using average exchange rates. Dividends data in USD were converted at the rate of the pay-out date. (f) Calculated by excluding own shares in portfolio.

SHARE INFORMATION

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

(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.

Natural Resources

Exploration & Production

The Natural Resources Business Group is committed to build up in a sustainable way, the value of Eni's Oil & Gas upstream portfolio, with the objective of reducing its carbon footprint by scaling up energy efficiency and expanding production in the natural gas business, and its position in the wholesale market. Furthermore, it is focused on the development of projects to capture and store CO2 emissions and of carbon sink, mainly through initiatives of Natural Climate Solutions. This business group includes the Exploration & Production and the Global Gas & LNG Portfolio segments.

KEY PERFORMANCE INDICATORS		2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)(a)	(recordable injuries/worked hours) x 1,000,000	0.25	0.28	0.33	0.30
of which: employees		0.09	0.18	0.18	0.29
contractors		0.30	0.31	0.37	0.30
Sales from operations(b)	(€ million)	21,742	13,590	23,572	25,744
Operating profit (loss)		10,066	(610)	7,417	10,214
Adjusted operating profit (loss)		9,293	1,547	8,640	10,850
Adjusted net profit (loss)		5,543	124	3,436	4,955
Capital expenditure		3,940	3,472	6,996	7,901
Profit per boe(c)(d)	(\$/boe)	4.8	3.8	7.7	6.7
Opex per boe(e)		7.5	6.5	6.4	6.8
Cash Flow per boe		20.6	9.8	18.6	22.5
Finding & Development cost per boe(d)(e)		20.4	17.6	15.5	10.4
Average hydrocarbons realizations		51.49	28.92	43.54	47.48
Hydrocarbons production(e)	(kboe/d)	1,682	1,733	1,871	1,851
Net proved hydrocarbon reserves	(mmboe)	6,628	6,905	7,268	7,153
Reserves life index	(years)	10.8	10.9	10.6	10.6
Organic reserves replacement ratio	(%)	55	43	92	100
Employees at year end	(number)	9,409	9,815	10,272	10,448
of which: outside Italy		6,045	6,123	6,781	6,971
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	22.3	21.1	22.8	24.1
Direct GHG emissions (Scope 1)/operated hydrocarbon gross production(a)(f)	(tonnes CO2 eq./kboe)	20.2	20.0	19.6	21.4
Methane fugitive emissions(a)	(ktonnes CH4 )	9.2	11.2	21.9	38.8
Volumes of hydrocarbon sent to routine flaring(a)	(billion Sm³)	1.2	1.0	1.2	1.4
Net carbon footprint upstream (Scope 1 + 2)(g)	(mmtonnes CO2 eq.)	11.0	11.4	14.8	14.8
Oil spills due to operations (>1 barrel)(a)	(barrels)	436	882	985	1,595
Re-injected production water(a)	(%)	58	53	58	60

(a) Calculated on 100% operated assets.

(b) Before elimination of intragroup sales. (c) Related to consolidated subsidiaries.

(d) Three-year average.

(e) Includes Eni's share of equity-accounted entities.

(f) Hydrocarbon gross production from fields fully operated by Eni (Eni's interest 100%) amounting to 1,041 mmboe, 1,009 mmboe, 1,114 mmboe and 1,067 mmboe in 2021, 2020, 2019 and 2018 respectively. (g) Calculated on equity bases and included carbon sink.

In 2021 with the mitigation of the health emergency followed by COVID-19 pandemic and the strong macroeconomic restart, the Exploration & Production segment reported a robust performance and progressed in the energy transition developing solutions for CCUS projects and Natural Climate Solutions initiatives to accelerate the achievement of the net zero target (Scope 1+2) of the business. In particular, in the United Kingdom, the Eni-led HyNet integrated project for the transport, capture and storage of CO2 , operated by a consortium of companies, has been granted access to priority public funding by the British Authorities, as part of the Country's decarbonization plans. The start of activities is expected by 2025, allowing the access to a tariff-regulated business model. Progressed Eni's initiatives within the Natural Climate Solutions, such as projects focusing on the forest's protection, conservation and sustainable management, mainly in developing Countries, by means of the REDD+ project scheme which was designed by the United Nations. In particular, in 2021, Eni launched other projects in the Republic of Zambia and Tanzania, in addition to Luangwa Community Forest project.

In addition, in partnership with several African countries we operate in Angola, Benin, Congo, Ivory Coast, Mozambique, Kenya and Rwanda, we are progressing projects based on biofuels to decarbonize the local energy mix, through the set-up of integrated agrobiofeedstock supply chains to supply renewable feedstock to Eni biorefineries, without impacting the local food chain and promoting circular economy through the recovery and valorization of non-strategic area. Furthermore, these agreements will allow to create new jobs and to foster local development. In addition, these projects will be supported by Eni research, also by leveraging on the agreement with the Bonifiche Ferraresi Group, aimed at establishing an equal joint venture for the development of agricultural research and experimentation projects of oil plant seeds to be used as feedstock in Eni's biorefineries.

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. The main success of the year was the discovery of the giant Baleine in the deep offshore of the Ivory Coast, with a mineral potential of over 2 billion barrels of oil in place and about 2.4 trillion cubic feet (TCF) of associated gas. It is set to be developed with a phased fast-track approach and will be the first development in Africa at net zero emissions (Scope 1 and 2).

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 2021 production start-up was achieved in the operated Block 15/06 discoveries in Angola, Merakes in Indonesia, Berkine in Algeria and Mahani in UAE.

Also the upstream portfolio is confirmed to be an important lever of value creation for the energy transition, as demonstrated, on the one hand, by the success of Vår Energi listing on the Norwegian stock exchange and, on the other hand, the set up together with BP of a strategic vehicle in Angola, combining the operations of the two partners and will become the top player in the Country.

ACTIVITY AREAS

ITALY

Eni has been operating in Italy since 1926. In 2021, Eni's oil and gas production amounted to 83 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 14,897 square kilometers (12,118 square kilometers net to Eni). Eni's production activities in Italy are regulated by concession contracts (25 operated onshore and 52 operated offshore).

Italy is a mature mining area. Eni's medium-term plans are focused on production fields optimization, the recovery of residual mineral potential and plant rationalization.

Adriatic and Ionian Seas

Production Main fields are Barbara, Annamaria, Clara NW (Eni's interest 51%), Luna, Angela, Hera Lacinia and Bonaccia and related satellites. Those fields accounted for 36% of Eni's domestic production in 2021, mainly gas. Production is operated by means of 53 fixed platforms (4 of these are manned) and is carried by sealine to the mainland where it is input in the national gas network. The system is subject continuously to rigorous safety control, maintenance activities and production optimization.

Development In the gas assets of the Adriatic Sea, development activities concerned: (i) maintenance and production optimization at offshore gas fields Annalisa (Eni's interest 100%) and Calipso (Eni's interest 51%); and (ii) decommissioning plan to plug-in depleted wells and to remove idle platforms progressed in the year in compliance with Italian Ministerial Decree 15 February 2019 "Linee guida nazionali per la dismissione mineraria delle piattaforme per la coltivazione in mare e delle infrastrutture connesse". A total of six offshore platforms to be removed are currently under the ministerial authorization process. In the circular economy initiatives, a program in collaboration with national research institutions was launched to redevelop asset in the decommissioning phase. Activities started up to convert an offshore platform into a marine science park.

In 2021 the IX Collaboration Agreement was signed with the Municipality of Ravenna. The agreement includes: (i) environmental projects by means of studies, monitoring program and environmental protection activities at the coastline areas; (ii) energy efficiency measures; (iii) professional training initiatives, programs to support local market and activities; and (iv) social projects and environmental education and sustainable development projects in collaboration with several local stakeholders.

Within Eni's long-term 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 which will be designed to store 500 million tonnes of CO2 . The development program includes a pilot project with expected start-up in 2023, following all necessary authorizations. The development on an industrial scale is expected in the next phase. The planned activities will benefit on the expected synergies on development cost leveraging on the offshore infrastructure of depleted fields and in addition to be significant impacted on the technology and competence areas.

Central Southern Apennines

Production Eni is the operator of the Val d'Agri concession (Eni's interest 61%) in the Basilicata Region in Southern Italy. The concession expired in October 2019 and activities have continued since then in accordance with the prorogation regime. Applications have been timely filed with Italian administrative Authority to obtain a ten-year extension of the concession based on the same work program as in the original concession award. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields which accounts for approximately 47% of Eni's domestic production, is treated by the Viggiano Oil Center.

Development During 2021 the Val d'Agri production plant was shut down, being executed mandatory maintenance activities to be performed every ten years, with the support of local stakeholders and in compliance with relevant regulations and health, safety, and environmental protection issues. The activities were related to inspections and maintenance as well as to execute intervention of improvement and upgrading of the production facilities. 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) in the agricultural rehabilitation programs with the "Agricultural Center for Experimentation and Training" project launched sustainable agricultural initiatives and the construction of agritech infrastructures; and (ii) start-up of biomonitoring programs with innovative techniques.

Within the strategic partnership with stakeholder, Eni, Shell and the Basilicata Region, have signed Preliminary Agreement to the Memorandum of Understanding of the Val d'Agri concession. The preliminary agreement, currently under negotiation, defines the main terms of a clearing programs linked to the concession work schedule in support of regional development, also by means of the action plan for the non-oil activities based on the sustainability principles.

Sicily

Production Eni operates 11 production concessions onshore and 2 offshore in Sicily. The main fields are Gela, Tresauro (Eni's interest 45%), Giaurone, Fiumetto, Prezioso and Bronte, which in 2021 accounted for approximately 11% of Eni's production in Italy.

Development Following 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 started up at the Argo and Cassiopeia project development (Eni's interest 60%). The project will be developed in about 3 years with an investment of over €700 million. Natural gas production start-up is expected in the first half of 2024. The project, through a significant reduction of the environmental impact, expects to achieve the carbon neutrality target.

Within the local support communities' initiatives, the final framework agreement was ratified with Fondazione Banco Alimentare Onlus, Banco Alimentare della Sicilia Onlus and the Municipality of di Gela 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 JV.

In February 2022, Eni and the equity fund HitecVision, shareholders of Vår Energi, completed the listing of the investee on the Oslo stock exchange, the largest O&G IPO in Europe in 15 years, placing an interest of about 11.2% of the investee's share capital. Eni's interest was reduced to 64.3% following the closing of the deal.

Activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea, on a total developed and undeveloped acreage of 27,927 square kilometers (7,272 square kilometers net to Eni). Eni's production in Norway amounted to 172 kboe/d in 2021.

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 45.40%) in the Barents Sea, Marulk (Eni's interest 13.97%) in the Norwegian Sea, as well as Balder & Ringhorne (Eni's interest 62.87%) and Ringhorne East (Eni's interest 48.88%) in the Norwegian section of the North Sea. These fields amounted to approximately 18% of Eni's production in the Country.

Furthermore, Vår Energi holds interests in 32 production licences in the Norwegian section of the North Sea and in the Norwegian Sea, including: Ekofisk area, Snorre, Grane, Statfjord, Fram, Sleipner, Åsgard, Tyrihans, Ormen Lange, Mikkel, Kristin e Heidrun.

Development Development activities mainly concerned: (i) the Johan Castberg sanctioned project (Eni's interest 20.96%), with start-up expected in 2024; (ii) the Balder X sanctioned project (Eni operator with a 62.87% 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 FPSO unit that will be relocated in the area. Production start-up is expected in 2023; (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; and (iv) the final investment decision (FID) was sanctioned for the Tommeliten Alpha Development gas and condensates project in the PL 044 licenses (Eni's interest 6.38%), in the Norwegian section of the North Sea.

In September 2021, a Cooperation Agreement was signed with others Oil & Gas operators in the area to assess the feasibility of the Barents Blu-Ammonia Project. The project provides for the monetization of gas production at the Goliath field by means of the blue ammonia production and commercialization. The CO2 captured in the process will be transported and stored in a depleted offshore field.

Exploration Vår Energi partecipated in 137 exploration licenses, of which 35 are operated.

Exploration activities yielded positive results with the offshore oil

discovery of: (i) Isflak in the PL 532 license (Eni's interest, 21%) in Barents Sea. The discovery will be linked to the Johan Castberg production hub (Eni's interest, 20.96%) under development; (ii) Blasto in the PL 090/090I license (Eni's interest, 17%), located in the northern North Sea, near the facility production of the Fram project (Eni's interest, 17.46%); (iii) Garantiana West in the PL 554 license (Eni's interest 21%) in the North Sea. The activities provide the joint development with the Garantiana field by means of the linkage to nearby facilities of the Snorre field (Eni's interest 12.99%); (iv) King and Prince in the PL 027 license (Eni's interest 62.86%) near to the Balder field (Eni's interest 62.87%); (v) Tyrihans North Ile in the PL 073 license (Eni's interest 8.4%) in the North Sea; and (vi) the Rodhette oil and gas discovery in the PL 901 license (Eni's interest 34.9%) in the Barents Sea, located in the north of the Goliat field.

Recent discoveries confirm the successfully Infrastucture Led Exploration ("ILX") strategy focused on additional reserve with high value and shortly time-to-market.

The mineral interest portfolio increases were as follows: (i) in 2021 eight exploration licenses were acquired as operator and five licenses in partnership, mainly located in the North Sea and the Barents Sea; and (ii) in January 2022, five exploration licenses were acquired as operator and five licenses in partnership. The licenses are distributed over the three main sections of the Norwegian continental shelf.

The new acquired licenses are located in both near-fields already in production or development areas with high exploration mineral potential.

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 2021, Eni's oil and gas production averaged 41 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 OGA (Oil & Gas Authority - OGA), 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. The other main non-operated fields are Elgin/Franklin (Eni's interest 21.87%), Glenelg (Eni's interest 8%), Joanne and Jasmine (Eni's interest 33%) as well as Jade (Eni's interest 7%).

In July 2021, Eni finalized the acquisition of 100% interest in the Conwy production field located in the Liverpool Bay area, near existing production facilities. This acquisition currently increases the production in the Country by leveraging on the operational synergies while in the next years during the abandonment phase this asset could be included in possible transitions to CO2 storage projects.

Development Within 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: (i) in March 2021, the project received funding of £33 million by the UK Research and Innovation (UKRI), Country's authority for research and innovation through the Industrial Decarbonisation Challenge (IDC) fund, including £21 million to finance 50% of engineering studies for the transport and storage phase; (ii) in May 2021, Eni signed a framework agreement with the Progressive Energy Limited to accelerate the project. Based on the agreement, Eni will develop and operate both the onshore and offshore transportation and storage of CO2 in its Liverpool Bay assets, while Progressive Energy will lead and coordinate the CO2 capture and hydrogen production on behalf of the Hynet North West consortium, thereby linking the CO2 emissions to Eni's transportation and storage infrastructure; (iii) in October 2021, the project has been selected by the UK Authorities between the two priority CCS projects in the country and granted access to priority public funding; (iv) signed 19 Memorandum of Understanding with local industries ("Emitters") to ensure the CO2 storage capacity of the project.

The HyNet North West project start-up is expected at the end of 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 decarbonisation goals define by the UK Government at 2030; as well as also will contribute to the 80% production of the 5 GW low carbon hydrogen target at 2030, announced by the Country, for further decarbonization of transport, industry and household utilities in the area.

In addition, in November 2021, Eni submitted to the UK Authority of Oil & Gas (OGA) in the Country a request to award a new license for possible realization of a CO2 storage project in Eni's exhausted offshore fields in the Hewett license, where production ended in 2020, to future develop the Bacton area as an hydrogen production hub.

In 2021 Eni announced exiting the Net Zero Teesside (Eni's interest 20%) and the North Endurance Partnership (Eni's interest 16.7%) projects where development activities are ongoing with other oil and gas partners in the area, following Eni's rationalization strategy of CCS projects in the United Kingdom based on focusing on its operated upstream assets. Other development activities mainly concerned: (i) production optimization, maintenance and asset integrity programs at the Liverpool Bay operated field; (ii) drilling of infilling wells and maintenance activity at the Elgin/Franklin and J-Area fields; and (iii) decommissioning activity of the Hewett Area project.

Exploration Eni holds interest in 9 exploration licenses, 2 of these are operated, with interest ranging from 16% to 100%.

In January 2021, Eni was awarded a 100% interest and operatorship in the exploration license P2511 in the North Sea and later a 50% farm-out agreement was finalized.

Exploration activity yielded positive results with the Talbot Appraisal (Eni's interest 33%) and Jade South (Eni's interest 7%) wells. The development activities will leverage on the existing production facilities in the area.

NORTH AFRICA

ALGERIA

Eni has been present in Algeria since 1981. In 2021, Eni's oil and gas production averaged 85 kboe/d. Developed and undeveloped acreage was 10,791 square kilometers (4,765 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%); and (vi) the Sif Fatima II, Zemlet El Arbi and Ourhoud II concessions in the Berkine Nord area (Eni's interest 49%). In addition, Eni holds interest in the nonoperated Block 404 and Block 208 with a 12.25% interest.

During 2021 Eni and Sonatrach signed several agreements in the exploration and production, research and development as well as decarbonization initiatives. In particular: (i) upgrading exploration and development activities in the Berkine area, also planning for the construction of an oil and gas development hub in synergy with the existing MLE-CAFC facilities. In March 2022, Eni awarded a new PSC in the basin of Berkine South (Eni operator with a 49% interest); (ii) signed a Memorandum of Understanding to jointly develop initiatives in new technologies, renewable energies, hydrogen, CCUS project, biorefining, and other fields in line with Eni's commitment to achieve carbon neutrality in 2050.

In April 2022, leveraging its consolidated partnership with the country, Eni signed framework agreement with Algeria to boost joint upstream operations and increase natural gas exports towards Europe.

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

Blocks 403a/d and ROM North

Production In 2021 production comes mainly from the HBN, ROMN and ROM and satellites fields and represented approximately 17% 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 the year, production optimization and workover activities were carried out at the ZEA field.

Blocks 401a/402a

Production In 2021 production comes mainly from the ROD/ SFNE and satellites fields and accounted for approximately 16% of Eni's production in Algeria.

Development In the year activity concerned production optimization.

Block 403

Production The main fields are BRN, BRW and BRSW, which accounted for approximately 11% of Eni's production in Algeria in 2021. Production is treated at the MLE plant in the Block 495b.

Development In the year activities concerned production optimization at the BRN and BRW fields.

Block 405b

Production In 2021 production comes from the MLE-CAFC project and accounted for approximately 10% of Eni's production in the Country. Four export pipelines link it to the national grid system.

Development Development activities concerned production optimization.

Block 404

Production The main fields are HBN, HBNS and Ourhoud fields, which accounted for approximately 16% of Eni's production in Algeria in 2021.

Development Development activities concerned production optimization.

Block 208

Production The El Merk field is the main production project in the area and accounted for approximately 14% of Eni's production in Algeria in 2021. 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 Development activities concerned production optimization.

Blocks Sif Fatima II, Ourhoud II and Zemlet El Arbi

Production In 2021 production comes mainly from Berkine North area and accounted for approximately 16% of Eni's production in Algeria. Production is treated at the MLE plant in the Block 405b.

Exploration In March 2022 exploration activity yielded positive results with the HDLE oil and associated gas discovery in the Zemlet el Arbi concession (Eni's interest 49%). The discovery

LIBYA

Eni started operations in Libya in 1959. In 2021, Eni's production amounted to 168 kboe/d. Developed and undeveloped acreage were 26,636 square kilometers (13,294 square kilometers net to Eni). 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 dates back to the revolution of 2011 that brought a change of regime and a civil. In the year of the revolution, Eni's operations in Libya were materially affected by a full-scale war, which forced the Company to shut down its development and extractive activities. Since September 2020, the situation has improved thanks to a peace agreement in the country that has allowed the resumption of all operational activities except for exploratory commitments on which the Force Majeure persists. This new stabilization phase has characterized most of the 2021 also thanks to a new Government of National Unity aiming to bring the country to elections by the end of 2021. Unfortunately, the electoral process has been postponed to a date to be defined, bringing the country back today in a situation of political and social uncertainty. Management believes that Libya's geopolitical situation will continue to represent a source of risk and uncertainty to Eni's operations in the country. For further information see Annual Report 2021.

TUNISIA

Eni has been present in Tunisia since 1961. In 2021, Eni's production amounted to 9 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 operated fields: Maamoura and Baraka offshore fields (Eni's interest 49%); Adam (Eni's interest 25%), Oued Zar (Eni's interest 50%), Djebel Grouz (Eni's interest 50%), MLD (Eni's interest 50%) and El Borma (Eni's interest 50%) onshore fields

Development Development activities concerned the drilling and start-up of an additional production well in the MLD concession.

EGYPT

Eni has been present in Egypt since 1954. In 2021, Eni's production amounted to 360 kboe/d and accounted for approximately 21% of Eni's total annual hydrocarbon production. Developed and undeveloped acreage was 18,712 square kilometers (6,776 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%), South West Meleiha (Eni's interest 100%), Ras Qattara (Eni's interest 75%) and West Abu Gharadig (Eni's interest 45%) concessions; and (iv) Baltim (Eni's interest 50%), Nile Delta (Eni's interest 75%), North Port Said (Eni's interest 100%), North Razzak (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 July 2021 an agreement was signed with the State energy, electricity and natural gas companies to assess the technical and commercial feasibility of projects for the blue and green hydrogen production also through the storage of CO2 in depleted natural gas fields.

In January 2022, Eni was awarded five exploration licenses, of which four as operator in the Egyptian offshore and onshore, following the successful participation in the Egypt International Bid Round for Petroleum Exploration and Exploitation 2021. The licenses are in mining basins of great interest to Eni: offshore East Mediterranean, the Western Desert and the Gulf of Suez, for a total acreage of about 8,410 square kilometers.

In April 2022, Eni and the Egyptian state-owned company EGAS agreed to valorize local gas reserves by increasing activities in jointly operated concessions and by exploring near field areas, with the goal of boosting production and gas exports to Italy via the Damietta liquefaction plant at an expected initial rate of up to 3 billion cubic meters in 2022.

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

Block Shorouk

Production Production comes from the Zohr field which in 2021 achieved the production of 183 kboe/d net to Eni.

Development Development activities of the Zohr project concerned: (i) EPCI (engineering, procurement, construction & installation) activities for the construction of new submarine facilities and two additional treatment unit with a capacity of 6,000 barrels/d to manage and recovery 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 two additional production wells with start-up expected in 2022.

Within the social responsibility initiatives, the programs defined by the Memorandum of Understanding signed in 2017 are currently to be implemented. The agreement, which supports the development activities of the Zohr project, defines two intervention projects to be implemented by the 2024. The first, already completed, included the renovation of the El Garabaa hospital, located nearby the onshore Zohr production facilities, and the supply of necessary medical equipment. The second project, for an overall expense of \$20 million, includes socio-economic, health and training programs to support local communities. In particular: (i) launched the phase 2 of the program upon completion of the health care center in Port Said in 2021. Planned activities include hospital equipment, healthcare staff training and health awareness campaigns; (ii) with the completion of youth center in 2020, Eni's training programs has been implemented. In particular, the Zohr Applied Technology School has been launched in partnership with the El Sewedy Electric Foundation and in cooperation with the local Authority. Civil infrastructure renovation activities started and then completed during the first months of 2022; and (iii) at the end of 2021, a technical education program was identified. Training activities is expected to be launched in 2022.

Sinai

Production Production amounted to approximately 68 kbbl/d (52 kbbl/d net to Eni) and mainly comes from the Belayim Marine, Belayim Land and Abu Rudeis fields.

Development During 2021 development activities concerned: (i) the completion of drilling development activities and production start-up in the production areas as well as production optimization programs by means of work-over activities; (ii) asset integrity program with certain activities to improve plant safety and to retain environmental standards; and (iii) study activities start-up to develop a photovoltaic plant of 15 MW in the area of the Abu Rudeis operated field in order to reduce electricity expenses by the national grid and related CO2 emissions. Start-up is expected by the end of 2022.

Exploration Exploration activities yielded positive results with near-field discoveries with the BLSE 1 oil exploration well. The exploration well was started up by means of the linkage to the existing facilities.

North Port Said

Production Production for the year amounted to approximately 13 kboe/d (approximately 9 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 159 ktonnes of propane, 97 ktonnes of LPG and approximately 1,057 mmbbl of condensates.

Baltim

Production In 2021, production amounted to approximately 91 kboe/d (approximately 29 kboe/d net to Eni).

Development Ongoing activities concerned development drilling program.

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 2021 production amounted to approximately 90 kboe/d (approximately 44 kboe/d net to Eni).

Ras el Barr

Production In 2021, the production amounted to approximately 19 kboe/d (approximately 11 kboe/d net to Eni), mainly gas from Ha'py and Seth fields.

El Temsah

ProductionThis concession includes Tuna, Temsah and Denise fields. Production in 2021 amounted to approximately 14 kboe/d (approximately 5 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 2021 production amounted to approximately 42 kboe/d (approximately 21 kboe/d net to Eni). In June 2021, Eni signed with the Egyptian General Petroleum

Corporation (EGPC) and Lukoil a unitization agreement and extension of exploitation rights until 2036 of the Meleiha and the Meleiha Deep contractual areas. The agreement includes an option of additional extension term to 2041. The agreement will allow to enhance the significant resource in the area by means of improved contractual terms and adding new exploratory mineral potential. In addition, the construction of a new gas treatment plant, which will be linked to the existing production facilities, will ensure a further possible development of the reserves in the area.

Development Development activities concerned the completion of drilling development activities and production start-up in the production areas as well as production optimization programs by means of work-over activities.

Exploration Exploration activities yielded positive results: (i) in 2021, with eight oil and natural gas discovery wells and already in production; and (ii) in April 2022, with near-field oil and gas discoveries were made in the Meleiha concessions, which have already been tied into production. The new discoveries confirm the positive track-record of Eni's exploration in the Country leveraging on the continuous technology progress in exploration activities that allows to re-evaluate the residual mineral potential in mature production areas.

The LNG business in Egypt

Eni holds interest in the Damietta natural gas liquefaction plant with a producing capacity of 5.2 mmtonnes/y of LNG corresponding to approximately 280 bcf/y of feed gas.

SUB-SAHARAN AFRICA

ANGOLA

Eni has been present in Angola since 1980. In 2021, Eni's production averaged 120 kboe/d. Eni's activities are concentrated in the conventional and deep offshore, over a developed and undeveloped acreage of 33,429 square kilometers (10,810 square kilometers net to Eni).

Eni's main asset in Angola is the Block 15/06 (Eni operator with a 36.84% interest), located in deep offshore, with the West Hub and the East Hub projects, already in production from 2014 and 2017, repexticely. Eni participates in other producing blocks: (i) Block 0 (Eni's interest 9.8%) in the Cabinda area in the north of the Country; (ii) Block 3 and 3/05-A (Eni's interest 12%) offshore of the Country; (iii) Block 14 (Eni's interest 20%) in the deep offshore west of Block 0; (iv) Block 14 K/A IMI (Eni's interest 10%); and (v) Block 15 (Eni's interest 18%) in the deep offshore of the Country.

In March 2022, Eni and BP signed an agreement to combine the respective upstream portfolios in the country, aiming at establishing a new jointly controlled venture, Azule Energy. The agreement follows the Memorandum of Understanding between the companies agreed in May 2021. In particular, the new venture will ensure significant operational synergies, targeting an ambitious investment plan and increasing the growth rate in the area. The transaction highlights both companies' commitment to continue developing the country's upstream potential and to support the energy transition by means of natural gas and renewable energy developments projects. The closing of the deal is subject to certain conditions precedent, including approval from the local authorities in charge.

In October 2021, Eni signed a Memorandum of Understanding with ANPG and Sonangol for joint development of the circular economy and decarbonization projects, in particular by promoting agricultural initiatives for the cultivation of oil plants to be used as feedstock for Eni's biorefineries, without impacting the local food chain.

In December 2021, the FID of Quiluma & Maboqueiro fields within the first development project of the New Gas Consortium (Eni's interest 25.6%) was sanctioned. The project includes two offshore platforms, an onshore gas processing plant and connection to A-LNG for the marketing of gas via LNG cargo, and condensates.

In 2021 reached the Final Investment Decision (FID) and signed the EPC contract for the first phase start-up of Caraculo's photovoltaic project, located in Namibe. The project follows the Memorandum of Understanding signed with Sonangol in 2019 with establishing a new jointly controlled venture, Solenova for the development of renewable energy projects. Start-up is expected in the fourth quarter of 2022. The plant will have a total capacity of 50 MW and will be implemented by stages, the first set to reach a capacity of 25 MW. The project will ensure to reduce diesel consumption for electricity generation and so the GHG emissions as well as supporting the Country's energy transition. Planned activities also include certain initiatives in the field of access to water, access to energy, health and education.

Local development programs and initiatives progressed during the year, in particular with: (i) the South West integrated project in Huila and Namibe area, to support local communities affected by drought; (ii) access to energy, with health centers electrification by means of solar panels installation; (iii) an agricultural development program in the Cabinda area in partnership with local institutions; (iv) ongoing support of the Halo Trust initiative for the land demining in the Benguela province; and (v) several health initiatives in the Luanda, Cabinda and Zaire areas with healthcare staff training programs as well as medical equipment supplies.

Exploration and production activities in Angola are regulated by concessions and PSAs.

Block 15/06

Production Production comes from the West Hub and the East Hub projects that in 2021 produced 113 kboe/d (51 kboe/d net to Eni). The development program plans to hook up the blocks discoveries to the two FPSO in order to support production plateau. Production start-up was achieved: (i) in 2021, the Cuica field, just four months after the discovery, and the Cabaça North field through the linkage to the Armada Olombendo FPSO targeting to increase and to support production plateau of the area; (ii) in February 2022, the Ndung Early Production project by means of linkage 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 also through upgrading plant implemented in 2021, in line with Eni's decarbonisation strategy to achieve net zero.

Production start-up confirms the success of the Infrastructure Led Exploration (ILX) campaign progressed in the Country also by means of a modular and simplified development approach ensuring a shortly time-to-market of the discoveries.

Development Development activities concerned the Agogo Early Production Phase 2 development project with startup of construction activities relating to the planned offshore facilities. The full field development of the Agogo project provides for the construction of an additional FPSO. Concept definition studies and FEED activity were completed and started up the activities for the assigning main contracts.

Exploration Exploration activities yielded positive: (i) in 2021 through the Cuica-1 oil discovery in the Cabaça development area, so to extend the residual useful life of the FPSO which operates the block; and (ii) in March 2022 with the Ndungu-2 delineation well which allows to boost to 800-1,000 million boe in place the field resources.

Block 0

Production In 2021 production amounted to 205 kboe/d (20 kboe/d net to Eni) and comes mainly from the Takula, Malongo and Mafumeira fields in the Area A (13 kboe/d net to Eni) and from the Bomboco, Kokongo, Lomba, N'Dola, Nemba and Sanha fields in the Area B (7 kboe/d net to Eni). Associated gas of the area was delivered via Congo River Crossing to the A-LNG liquefaction plant (see below) and partially supplied to the domestic market, for the power generation in Cabinda.

In December 2021, Eni finalized a twenty-year extension of the Block 0, with expiring date in 2050.

Development Development activities concerned: (i) the Sanha Lean Gas Connection and Booster Gas Compressor project increasing associated gas production to feed the A-LNG liquefaction plant; (ii) the Lifua-A development project. The offshore facilities were completed, and start-up is expected in 2022; (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.

Block 3 and 3/05-A

Production Block is divided into three production offshore areas. Oil production is delivered at the Palanca FSO and then exported. In 2021, production from this area amounted to 21 kboe/d (2 kboe/d net to Eni).

Development Development activities concerned the FEED activity of the Punja project.

Blocks 14 and 14K/A IMI

Production In 2021 production amounted to approximately 59 kboe/d (9 kboe/d net to Eni). Main production fields are Landana and Tombua as well as Benguela-Belize/Lobito-Tomboco and Lianzi. Associated gas of the area was delivered via Congo River Crossing to the A-LNG liquefaction plant (see below).

Block 15

Production The block produced approximately 163 kboe/d (18 kboe/d net to Eni) in 2021. Main fields are: (i) the Hungo/ Chocalho, started up in 2004, and Marimba, started up in 2007, by means of the FPSO of the Kizomba A; (ii) the Kissanje/ Dikanza, started up in 2005 with the FPSO Kizomba B; (iii) Saxi/Batuque and Mondo, started up in 2008 and operated by two added FPSO units; (iv) Clochas and Mavacola, started up in 2012 as part of Kizomba Satellites Phase 1 project; and (v) Bavuca, Kakocha and Mondo South, started up in 2015 as part of Kizomba Satellites Phase 2 project.

The LNG business in Angola

Eni holds a 13.6% interest of the Angola LNG (A-LNG) which runs the plant, located in Soyo, with treatment capacity of approximately 353 bcf/year of feed gas and a liquefaction capacity of 5.2 mmtonnes/y of LNG. In 2021 production net to Eni averaged approximately 20 kboe/d.

CONGO

Eni has been present in Congo since 1968. In 2021, production averaged 70 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 2,484 square kilometers (1,306 square kilometers net to Eni).

In October 2021, Eni signed a Memorandum of Understanding with the Country's authorities for joint development of the circular economy and decarbonization projects, in particular by promoting agricultural initiatives for the cultivation of oil plants to be used as feedstock for Eni's biorefineries, without impacting the local food chain.

In April 2022, leveraging its consolidated partnership with the country, Eni signed framework agreement with the Republic of Congo to boost joint upstream operations and increase natural gas exports towards Europe. In particular the increase of natural gas production in the country will leverage also on the development of a LNG project with start-up expected in 2023 and a capacity of 4.5 billion cubic meters/year once fully operational (see below).

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

Production Eni's main operated producing interests are the Nené Marine and Litchendjili (Eni's interest 65%), Zatchi (Eni's interest 55.25%), Loango (Eni's interest 42.5%), Ikalou (Eni's interest 100%), Djambala (Eni's interest 50%), Foukanda and Mwafi (Eni's interest 58%), Kitina (Eni's interest 52%), Awa Paloukou (Eni's interest 90%), M'Boundi (Eni's interest 83%) and Kouakouala (Eni's interest 74.25%) fields with an overall production of approximately 81 kboe/d (60 kboe/d net to Eni) in 2021. 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 29 kboe/d (approximately 10 kboe/d).

During 2021 Eni relinquished the Loango II (Enis' interest 42.5%) and Zatchi II (Eni's interest 55.25%) production assets, effective from January 1st, 2022, in line with Eni's strategy of production portfolio rationalization.

Development Activities in the year concerned: (i) the PSA contract of the Marine XII production block was amended to include a new tax regime dedicated to LNG projects. Ongoing studies provides for a fast-track development project to monetize the associated and non-associated gas in the area both for the domestic power generation and LNG export, also targeting to support zero routine flaring. The export project consists of two modular and in phases LNG liquefaction plants. Start-up is expected in 2023 and a capacity of 4.5 billion cubic meters/year once fully operational; (ii) the additional development phase of the Nené-Banga production field in the Marine XII block with a construction of a new production platform. Start-up is expected in the second half of 2022; (iii) in the cultural initiatives to support local community, the construction activities progressed at the Oyo research center which is expected to be opened and in operation in 2022; (iv) the second phase of the Project Integrated Hinda (PIH) progressed with initiatives to support the economic and agricultural development, access to water, education programs and sanitary service program development; and (v) the CATREP program to support domestic agricultural economy with initiatives in the innovative agronomic techniques application aiming to integrate local producers into supply chain of agri-biofeedstock within Memorandum of Understanding signed in 2021.

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 the offshore exploration license Cape Three Points Block 4 (Eni's interest 42.47%).

Production In 2021, production averaged 36 kboe/d net to Eni and comes from the OCTP project. The OCTP project is the only non-associated gas development project in deep water entirely dedicated to the domestic market in Sub-Saharan Africa. This project will ensure at least 15 years of reliable gas supply 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.

Development In the year activities concerned production optimization program to support production of the OCTP field. Exploration Exploration activities yielded positive results with the Eban discovery in the Cape Three Points Block 4 offshore exploration licnese, close to the Sankofa production hub.

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 February 2022, Eni signed with the Ministry of Agriculture and Rural Development of the Republic of Mozambique an agreement for cooperation and development of agricultural projects in the Country, promoting agricultural initiatives for the cultivation of oil plants to be used as feedstock for biofuels production.

Development The development activities of Area 4 offshore (Eni's interest 25%) concerned the Coral South gas project and the gas discoveries of Mamba Complex where Eni is expected to coordinate the upstream phase and ExxonMobil midstream phase (natural gas liquefaction).

The sanctioned Coral South project includes the construction, installation and commissioning and of an FLNG vessel that will be linked to six subsea gas producing wells, where the gas will undergo treatment, liquefaction, storage and export, with a capacity of approximately 3.4 mmtonnes/y of LNG. The development activities are nearing completion. Production start-up is expected within 2022. The LNG produced will be sold by the Area 4 Concessionaires to BP under a long-term contract for a period of twenty years, with an option for an additional ten-year term.

Within the Mamba Complex discoveries, the Rovuma LNG project provides for the development of the straddled reserves of Area 1 according to its independent industrial plan, coordinated with the operator of Area 1 (TotalEnergies). The development project will include also a part of non-straddled reserves. The project provides the construction of two onshore LNG trains with capacity of approximately 7.6 mmtonnes/y each, fed by 24 subsea wells and facilities for storing and exporting LNG. In 2019, the plan of development (POD) was approved by the relevant Authorities. The Area 4 operators progressed with reassessment of the project, including maximizing synergies with Area 1, in order to optimize costs. In 2021, Eni's programs to support the local communities of the Country progressed with: (i) programs to support primary and infant scholarship. In particular, in city of Pemba, the infrastructural planned activities are completed and launched training initiatives also with study grants; (ii) launched the second phase of access to energy program also by means of clean cooking projects; (iii) support to disadvantaged populations in particular in the Cabo Delgado area and in the Maputo area, also with food assistance; and (iv) within the Coral South project development, certain activities were launched also through suppliers engagement aiming to increase workforce of local small e medium-size companies.

NIGERIA

Eni has been present in Nigeria since 1962. In 2021, Eni's oil and gas production averaged 84 kboe/d, over a developed and undeveloped acreage of 27,964 square kilometers (6,374 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 17 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 January 2021, Eni and the partners divested the onshore production and development block OML 17 (Eni's interest 5%). In 2021 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. In particular, during the year, maintenance activities were completed to ensure sustainable use of infrastructures implemented. 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. In March 2022, Eni and FAO, in partnership with NNPC, completed and delivered 11 water plants powered by photovoltaic systems in Borno and Yobo States in northeastern Nigeria. In addition, initiatives progressed with: (i) infrastructures projects with the realization of roads, schools, health centers, electrification and water work; (ii) training programs, also with study grants; (iii) access to energy programs; and (iv) the Green River Project to support local producers.

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

Blocks OMLs 60, 61, 62 and 63

Production Onshore four licenses produced approximately 32 kboe/d net to Eni in 2021. 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 3,5 mmbbl. A large portion of the gas reserves of these four OMLs is destined to supply the Bonny Island liquefaction plant (see below). Another portion of gas production is employed in firing the combined cycle power plant at Okpai.

Development Development activities concerned production optimization programs also with workover activity.

Exploration Exploration activities yielded positive results with the Obiafu 42 gas and condensates exploration well.

Block OML 118

Production The Bonga oil field produced 12 kboe/d net to Eni in 2021. Production is supported by an FPSO unit with a 225 kboe/d treatment capacity and a 2 mmboe storage capacity. Associated gas is carried to a collection platform on the EA field and, from there, is delivered to the Bonny liquefaction plant.

Development Development activities concerned production optimization programs also with workover activity.

Block OML 125

Production Production derived mainly from the Abo field which yielded approximately 17 kboe/d net to Eni in 2021. Production is supported by an FPSO unit with a 40 kboe/d treatment capacity and an 800 kboe storage capacity.

SPDC Joint Venture (NASE)

Production In 2021, production from the SPDC JV amounted to approximately 22 kboe/d net to Eni.

Development Development activities concerned: (i) production optimization programs also with work-over activities at the Kolo Creek gas field in the OML 28 block (Eni's interest 5%) and the Forkados Yokri oil field in the OML 43 Block (Eni's interest 5%); and (ii) drilling of four oil wells in the OML 79, 35 and 36 blocks (Eni's interest 5%) and of six gas wells in the OML 21 and 22 blocks (Eni's interest 5%) in the Assa North and Enhwe fields.

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 to approximately 1,250 bcf/y of feed gas. Natural gas supplies to the plant are currently provided under a gas supply agreement from the SPDC JV (Eni's interest 5%), TEPNG JV and the NAOC JV (Eni's interest 20%). In 2021, the Bonny liquefaction plant processed approximately 970 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%), the latter following agreements signed in July 2019. The Blocks are 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 4,600 square kilometers. The NCSPSA expires at the end of 2041.

Production In 2021, production averaged 374 kbbl/d of liquids (approximately 62 kbbl/d net to Eni) and 421 mmcf/d of natural gas (approximately 70 mmcf/d net to Eni). Gas volumes undergo a treatment process and then are delivered to the national gas marketing and transportation company (KazTransGas); a part of the gas volumes is utilized as fuel gas. A part of the raw gas volumes (approximately 43%) is re-injected in the reservoir. The liquid production is stabilized at the Bolashak facilities and exported to Western markets through the Caspian Pipeline Consortium (Eni's interest 2%) and the Atyrau-Samara pipeline.

Development The development activities of the Kashagan field concerned the phased expansion program of production capacity. The first development phase envisages increasing the production capacity up to 450 kbbl/d by upgrading the existing associated gas compression handling. The ongoing activities, sanctioned in 2020, mainly concerned: (i) increasing gas reinjection capacity by means of upgrading the existing facilities; and (ii) delivering a part of gas volumes to a new onshore treatment unit operated by a third party, currently under construction.

In addition, during the year the redevelopment activity was completed with energy efficiency of a school in the Turkestan region, built in partnership with UNDP (United Nations Development Programme).

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 2021, production of the Karachaganak field averaged 226 kbbl/d of liquids (40 kbbl/d net to Eni) and 866 mmcf/d of natural gas (approximately 160 mmCF/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 (Eni's interest 2%) and the Atyrau-Samara pipeline.

Development Within the gas treatment expansion projects of the Karachaganak field, activities concerned: (i) the Karachaganak Debottlenecking project was completed. The construction of a fourth gas reinjection unit is currently being finalized; and (ii) the Karachaganak Expansion Project (KEP) to increase gas re-injection capacity progressed. The project is scheduled to be achieved in several phases. The development program of the first phase, sanctioned at the end of 2020, provides the construction of a sixth injection line, the drilling of three additional injection wells and of a new gas compression unit. Start-up is expected in 2024. The project includes an additional phase with the installation of a new treatment and compression units.

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 medicines distribution, following the health emergency resulting from the COVID-19 pandemic.

REST OF ASIA

INDONESIA

Eni has been present in Indonesia since 2001. In 2021, Eni's production mainly composed of gas, amounted to 61 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 21,277 square kilometers (14,184 square kilometers net to Eni); in total, Eni holds interests in 13 blocks.

In June 2021, Eni signed a Memorandum of Understanding with the government entity SKK Migas for a partnership in hydrocarbons exploration in the Country. The agreement provides for the use of Eni's proprietary technologies, including the calculation and processing techniques of the Green Data Center, for an exploration prospects interpretation data.

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 long-term contracts, partly to state company Pertamina and to Eni, which will sell over the Asiatic market; (ii) the operated East Sepinggan block (Eni's interest 65%) with the Merakes gas project started up in April 2021. 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 in the year comprised: (i) development program of the Merakes East and Maha projects with the completion of the concept selection activity and the start-up of the concept definition activity; and (ii) 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.

Exploration Exploration activities yielded positive results in the operated West Ganal block (Eni's interest 40%) with the Maha 2 delineation well, near the Jangkrik production field.

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 37 kbbl/d net to Eni in 2021.

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 plateau of 700 kbbl/d. The production capacity and main facilities to treat the production plateau target have already been installed; the field reserves will be progressively put into production by drilling additional productive wells over the next few years.

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) launched an integrated training program in the Zubair district, including specific training initiatives for school staff and establishing online educational platform following the COVID-19 pandemic impact; (ii) progressed construction activities of a new school in the Zubair area with completion expected in 2023, as well as renovation and material supply initiatives; (iii) pediatric training project, renovation and expansion of the Basra Cancer Children Hospital as well as the supply of specific medical oncology equipment; and (iv) upgrading activity at the Al Barjazia drinking water plant in the Zubair area as well as the construction of new plant in the Bassora area.

PAKISTAN

Eni has been present in Pakistan since 2000. In 2021, Eni's production mainly composed of gas amounted to 11 kboe/d, over a developed and undeveloped acreage of 4,009 square kilometers (1,072 square kilometers net to Eni).

In March 2021, Eni signed an agreement to divest the entire upstream activity in the Country including interests in ten development and production licenses to Prime International Oil & Gas local company. The agreement is subject to approval from the relevant Authorities.

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 (1,620 square kilometers net to Eni).

Eni participates in the production Block PSC-TL-SO-T 19-13 with a 10.99% interest, following the agreement signed between Australia and Timor Leste in 2019. Eni participates in another production license and holds interests in 2 exploration licenses. Production Production comes mainly from the Bayu Undan gas and liquid field with a production of 113 kboe/day (9 kboe/ day net to Eni) in 2021. 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 four areas. In 2021, Eni's production averaged 7 kboe/d.

Exploration and production activities in Turkmenistan are regulated by PSAs.

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

UNITED ARAB EMIRATES

Eni has been present in United Arab Emirates since 2018 over a developed and undeveloped acreage of 32,620 square kilometers (18,771 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; (iii) Block offshore A and Block onshore 7 with a 90% interest in the Emirate of Ras al Khaimah. In addition Eni holds 50% interest in the Area B concession in the Emirate of Sharjah.

In the development phase Eni holds a 25% interest in the Ghasha offshore concession with duration of 40 years. The concession includes Hail, Ghasha, Dalma gas fields and certain 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 located in the offshore Abu Dhabi with oil, condensates and gas production.

Production In 2021 production averaged 51 kboe/d net to Eni and comes from Lower Zaku and Umm Shaif/Nasr fields as well as Mahani field with start-up achieved in January 2021.

The Mahani field is located in the onshore Concession Area B in the Emirate of Sharjah. Start-up was achieved just one year after Mahani 1 exploration well discovery and two years after signing the concession agreement. Development activities, sanctioned with the final investment decision, provide the progressive rampup with the tie-back of two additional productive wells.

Development During the year two development projects were sanctioned: the Dalma Gas Development in the offshore Gasha concession and the Umm Shaif Long-Term Development Phase 1 in the Umm Shaif concession.

Exploration In 2022 exploration activities yielded positive results in the operated Block 2 with the XF-002 well, in offshore Abu Dhabi. Drilling activities are ongoing, and upon completion expected in the second quarter of 2022 the size of the discovery will be evaluated.

AMERICAS

MEXICO

Eni has been present in Mexico since 2015 and is performing exploration and development activities over a developed and undeveloped acreage of 5,469 square kilometers (3,106 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 the Amoca, Miztón and Tecoalli discoveries. In the exploration phase, Eni is operator of: (i) the Area 10 (Eni's interest 65%), the Area 14 (Eni's interest 60%) and the Area 7 (Eni's interest 45%) located in the Sureste basin; and (i) the Area 24 (Eni's interest 65%) and Area 28 (Eni's interest 75%) located in Cuenca Salina basin. 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 2021 production comes from the operated Area 1 license and amounted to 14 kboe/d.

Development The development activities in the year mainly concerned the full field development program of the operated license Area 1. In particular: (i) the conversion and upgrading of an FPSO unit was completed including all linking facilities; (ii) the first production platform was installed in the Amoca field; and (iii) the development drilling activities progressed at the Miztón production field while the drilling activities started up in the Amoca field. The FPSO Miamte started operations at the Miztón field on February 23, 2022 allowing the production ramp-up. Other development phase includes the construction and installation of two additional production platform at the Amoca and Teocalli field.

Within the cooperation agreement with the local Authorities to identify initiatives relating to health, education and environment, as well as economic diversification initiatives to support employment, during the year the activities concerned: (i) restructuring of school buildings and construction of roads; (ii) training and learning activities to support school programs; (iii) initiatives to improve socio-economic conditions of communities with development programs of fishing activity; (iv) completed the Human Rights Action Plan identifying activities plan; and (v) awareness campaigns in the field of access to energy.

Exploration Exploration activities yielded positive results with: (i) the Sayulita oil discovery in the offshore operated Block 10 (Eni's interest 65%) where the Saasken discovery was made in 2020. The new well identified 150-200 million barrels of oil in place that have boosted the commerciality prospects of the area; and (ii) the Yoti West oil discovery in the OBO AC12 block with estimated resources in approximately 170 million barrels of oil in place.

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 1,462 square kilometers (751 square kilometers net to Eni). In 2021, Eni's oil and gas production was 53 kboe/d.

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

Gulf of Mexico

Eni holds interests in 46 exploration and production blocks in the shallow and deep offshore of the Gulf of Mexico, of which 16 are operated by Eni.

ProductionThe main operated fields are Allegheny and Appaloosa (Eni's interest 100%), Pegasus (Eni's interest 85%), Longhorn, Devils Towers and Triton (Eni's interest 75%). Eni also holds interests in Europa (Eni's interest 32%), Medusa (Eni's interest 25%), Lucius (Eni's interest 8.5%), K2 (Eni's interest 13.4%), Frontrunner (Eni's interest 37.5%) and Heidelberg (Eni's interest 12.5%) fields. In 2021, production amounted to 30 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 2021, Eni's production amounted to approximately 2 kboe/d.

Alaska

Eni operates 41 exploration and development blocks and holds interest in 1 block.

ProductionThe main operated fields are Nikaitchuq (Eni's interest 100%) and Oooguruk (Eni's interest 100%) with a 2021 overall net production of approximately 21 kbbl/d.

VENEZUELA

Eni has been present in Venezuela since 1998. In 2021, Eni's production averaged 48 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 2021, Eni's production of oil and natural gas averaged 16 kboe/d. Activities are focused on offshore fields, over a developed and undeveloped acreage of 3,336 square kilometers (2,705 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.

In 2021 Eni signed a Memorandum of Understanding with the Australian company Santos to jointly seek cooperation opportunities within CO2 capture and storage or utilization project and to enhance partnership in the hydrocarbon developments in northern Australia.

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.

FORESTRY PROJECTS

In Eni's decarbonization path, Natural Climate Solutions (NCS) area one of the levers in the residual emission reduction. Among these, in 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 socioeconomic 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, like BioCarbon Partners, Terra Global, Peace Parks Foundation, First Climate, Carbonsink and Carbon Credits Consulting, which 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 the with highest standards for certification of the carbon emissions reduction and social and environmental effects (such as Verified Carbon Standard - VCS and Climate Community & Biodiversity Standards - CCB), internationally recognized and in line with the qualitative standards, target to be achieved by Eni. Eni launched the forestry projects in 2019 by means of the agreement with BioCarbon Partners to became active member in the governance of the Luangwa Community Forests Project (LCFP) in Zambia. The LCFP covers an area

of approximately 1 million hectares, involves approximately 200,000 beneficiaries, also with economic diversification initiatives, and is currently one of the largest REDD + projects in Africa. The LCFP achieved the CCB (Climate, Community and Biodiversity Standards) "triple gold" issued by international noprofit organization Verra, leader in the carbon credits certifying, for its outstanding social and environmental impact. Eni committed to purchase carbon credits generated by the LCFP project until 2038. During the year Eni finalized agreement to support the development of the Ntakata Mountains project in Tanzania and the Lower Zambezi project in Zambia, as well as launched the Amigos de Lakmul project in Mexico. In 2021 Eni achieved allowance of carbon credits by the projects to offset GHG emissions equivalent to over 2 million tonnes of CO2.

Eni is currently considering further different initiatives in several countries, by means of partnerships with governments and international developers in Africa, Latin America, and Asia. The medium/long-term target is a progressive growth of these initiatives and planned to reach a carbon credit portfolio on yearly basis to offset over 20 million tonnes of CO2 in 2030.

AGRO-FEEDSTOCK PROJECTS

During the year Eni finalized agreement with the Authorities of the Kenya, Congo, Angola, Rwanda and Ivory Coast as well as in Mozambique and Benin in 2022 aiming to decarbonize the local energy mix by means of biofuels value chain by promoting 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 socio-economic 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 the first step, industrial production start-up is

expected in: (i) Kenya, where development program includes the construction of 20 agri-hubs with start-up in 2022. In addition, the agreement provides also 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; (ii) Congo with activities start-up expected in 2023. The full capacity production is expected to achieve 350 ktonnes from 2026 with engagement of 300,000 farmers. The overall production is expected to subsequently reach an agro-feedstock volume of over 800 thousand tonnes by 2030 leveraging on additional initiatives in other countries.

Within these development initiatives, in November 2021 Eni finalized strategic partnership agreement with the Bonifiche Ferraresi Group aimed at establishing an equal joint venture. Based on the agreement, Eni purchased a minority stake in the subsidiary of BF Bonifiche Ferraresi. In addition, the agreement include: (i) research and experimentation projects of oil plant seeds to be used as feedstock in biorefineries; (ii) support in the countries where Eni will develop agro-feedstock projects by means of know-how transfer and agriculture seeds and products supplies.

MOVEMENTS IN NET PROVED HYDROCARBONS RESERVES

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

(mmboe)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest of	Asia Americas	Australia and Oceania	Total
2020(a)
Consolidated subsidiaries
Reserves at December 31, 2019	333	89	974	1,225	1,453	1,108	742	268	95	6,287
of which: developed	258	82	553	1,033	863	1,046	372	182	61	4,450
undeveloped	75	7	421	192	590	62	370	86	34	1,837
Purchase of minerals in place
Revisions of previous estimates	(51)	3	(84)	(9)	26	133	185	11	2	216
Improved recovery							5			5
Extensions and discoveries				1			11	5		17
Production	(39)	(19)	(92)	(107)	(127)	(59)	(64)	(28)	(6)	(541)
Sales of minerals in place(a)
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 1st, 2020, the conversion rate of natural gas from cubic feet to boe has been updated to 1barrel 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 67 mmboe.

(mmboe)		Rest of			Sub-Saharan		Rest of		Australia and
2019	Italy	Europe	North Africa	Egypt		Africa Kazakhstan		Asia Americas	Oceania	Total
Consolidated subsidiaries
Reserves at December 31, 2018	428	106	1,022	1,246	1,361	1,066	700	302	125	6,356
of which: developed	336	99	582	764	895	925	403	170	87	4,261
undeveloped	92	7	440	482	466	141	297	132	38	2,095
Purchase of minerals in place								30		30
Revisions of previous estimates	(50)	2	90	106	190	97	67	(20)	(23)	459
Improved recovery
Extensions and discoveries		1		2	35		53	10		101
Production	(45)	(20)	(138)	(129)	(129)	(55)	(69)	(25)	(7)	(617)
Sales of minerals in place(a)					(4)		(9)	(29)		(42)

Reserves at December 31, 2019	333	89	974	1,225	1,453	1,108	742	268	95	6,287
Equity-accounted entities
Reserves at December 31, 2018		363	14		68			352		797
of which: developed		205	14		17			347		583
undeveloped		158			51			5		214
Purchase of minerals in place		184								184
Revisions of previous estimates		59	3		3			(3)		62
Improved recovery
Extensions and discoveries		6								6
Production		(39)	(1)		(8)			(14)		(62)
Sales of minerals in place		(6)								(6)
Reserves at December 31, 2019		567	16		63			335		981
Reserves at December 31, 2019	333	656	990	1,225	1,516	1,108	742	603	95	7,268
Developed	258	412	569	1,033	886	1,046	372	517	61	5,154
consolidated subsidiaries	258	82	553	1,033	863	1,046	372	182	61	4,450
equity-accounted entities		330	16		23			335		704
Undeveloped	75	244	421	192	630	62	370	86	34	2,114
consolidated subsidiaries	75	7	421	192	590	62	370	86	34	1,837
equity-accounted entities		237			40					277

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

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

MOVEMENTS IN NET PROVED LIQUIDS RESERVES

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

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

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

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

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

MOVEMENTS IN NET PROVED NATURAL GAS RESERVES

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

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

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

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

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

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

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

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

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

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2018
Consolidated subsidiaries
Reserves at December 31, 2017	1,131	896	3,145	4,351	3,660	2,108	1,065	225	709	17,290
of which: developed	987	771	1,233	1,421	1,693	1,878	862	171	519	9,535
undeveloped	144	125	1,912	2,930	1,967	230	203	54	190	7,755
Purchase of minerals in place							69			69
Revisions of previous estimates	138	50	219	2,238	23	(22)	81	45	(16)	2,756
Improved recovery
Extensions and discoveries	86				7		205	76		374
Production(a)	(156)	(162)	(474)	(445)	(184)	(97)	(201)	(43)	(42)	(1,804)
Sales of minerals in place		(464)		(869)			(2)	(26)		(1,361)
Reserves at December 31, 2018	1,199	320	2,890	5,275	3,506	1,989	1,217	277	651	17,324
Equity-accounted entities
Reserves at December 31, 2017			14		349			1,819		2,182
of which: developed			14		83			1,819		1,916
undeveloped					266					266
Purchase of minerals in place		360								360
Revisions of previous estimates			2		(6)			(22)		(26)
Improved recovery
Extensions and discoveries
Production(b)			(2)		(33)			(81)		(116)
Sales of minerals in place
Reserves at December 31, 2018		360	14		310			1,716		2,400
Reserves at December 31, 2018	1,199	680	2,904	5,275	3,816	1,989	1,217	1,993	651	19,724
Developed	980	576	1,461	3,331	1,928	1,846	822	1,870	452	13,266
consolidated subsidiaries	980	300	1,447	3,331	1,871	1,846	822	154	452	11,203
equity-accounted entities		276	14		57			1,716		2,063
Undeveloped	219	104	1,443	1,944	1,888	143	395	123	199	6,458
consolidated subsidiaries	219	20	1,443	1,944	1,635	143	395	123	199	6,121
equity-accounted entities		84			253					337

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

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

HYDROCARBONS PRODUCTION(a)(b)(c)

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

Total 1,682 1,733 1,871 1,851

(a) Includes volumes of hydrocarbons consumed in operations (116, 124, 124 and 119 kboe/d in 2021, 2020, 2019, 2018, respectevely).

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

(c) 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 12.31.2019 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)	2021	2020	2019	2018
CONSOLIDATED SUBSIDIARIES
ITALY	36	47	53	60
Rest of Europe	19	23	23	113
Norway				89
United Kingdom	19	23	23	24
North Africa	124	112	166	154
Algeria	54	53	62	65
Libya	67	56	101	86
Tunisia	3	3	3	3
Egypt	82	64	75	77
Sub-Saharan Africa	198	218	249	244
Angola	91	89	102	111
Congo	44	49	59	65
Ghana	20	24	24	15
Nigeria	43	56	64	53
Kazakhstan	102	110	100	94
Rest of Asia	80	88	86	77
China	1	1	1	1
Indonesia	1	1	2	3
Iraq	24	31	27	28
Timor Leste	1	2
Turkmenistan	6	7	7	6
United Arab Emirates	47	46	49	39
Americas	53	57	55	52
Ecuador			6	12
Mexico	11	12	4
United States	42	45	45	40
Australia and Oceania			2	2
Australia			2	2
	694	719	809	873
EQUITY-ACCOUNTED ENTITIES
Angola	3	4	4	3
Norway	111	116	74
Tunisia	3	2	3	3
Venezuela	2	2	3	8
	119	124	84	14

Total	813	843	893	887

NATURAL GAS PRODUCTION

(mmcf/d)	2021	2020	2019	2018
CONSOLIDATED SUBSIDIARIES
Italy	251.0	316.6	376.4	426.2
Rest of Europe	119.3	159.1	174.6	444.9
Croatia				11.4
Norway				241.8
United Kingdom	119.3	159.1	174.6	191.7
North Africa	720.1	758.4	1,149.2	1,299.1
Algeria	165.1	152.5	111.8	105.5
Libya	541.7	594.4	1,025.8	1,180.3
Tunisia	13.3	11.5	11.6	13.3
Egypt	1,474.8	1,203.0	1,509.0	1,218.5
Sub-Saharan Africa	489.5	679.0	621.2	505.4
Angola	53.9	58.2	67.3	84.2
Congo	135.5	131.1	147.7	150.3
Ghana	83.8	87.6	97.9	19.3
Nigeria	216.3	402.1	308.3	251.6
Kazakhstan	233.0	282.2	272.4	265.2
Rest of Asia	516.5	465.0	502.7	550.7
Indonesia	321.2	248.5	308.1	376.5
Iraq	70.7	76.3	78.7	36.7
Pakistan	59.8	76.8	101.2	106.1
Timor Leste	42.5	46.8
Turkmenistan	6.3	6.2	6.0	27.2
United Arab Emirates	16.0	10.4	8.7	4.2
Americas	73.0	97.1	66.8	118.9
Mexico	14.8	10.9	2.8
Trinidad & Tobago				35.7
United States	58.2	86.2	64.0	83.2
Australia and Oceania	85.0	91.0	139.6	114.3
Australia	85.0	91.0	139.6	114.3
	3,962.2	4,051.4	4,811.9	4,943.2

EQUITY-ACCOUNTED ENTITIES
Angola	85.8	98.8	97.3	89.2
Indonesia				2.2
Norway	322.7	365.0	182.4
Tunisia	3.2	2.9	3.4	4.4
Venezuela	239.2	211.0	192.0	221.7
	650.9	677.7	475.1	317.5

Total	4,613.1	4,729.1	5,287.0	5,260.7

OIL AND NATURAL GAS PRODUCTION SOLD

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

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

MAIN OIL AND NATURAL GAS INTERESTS AT DECEMBER 31, 2021

	Commencement of operations	Number of interests	Gross developed acreage(a)(b)	Net acreage(a)(b) developed	Gross acreage(a) undeveloped	acreage(a) Net undeveloped	Types of fields/acreage	Number of producing fields	Number of other fields

EUROPE		308	14,224	8,246	65,679	31,612		106	84
Italy	1926	123	8,087	6,786	6,810	5,332	Onshore/Offshore	58	45
Rest of Europe		185	6,137	1,460	58,869	26,280		48	39
Albania	2020	1			587	587	Onshore
Cyprus	2013	7			25,474	13,988	Offshore		1
Greenland	2013	2			4,890	1,909	Offshore
Montenegro	2016	1			1,228	614	Offshore
Norway	1965	138	5,218	836	22,709	6,436	Offshore	38	34
United Kingdom	1964	34	919	624	1,280	863	Offshore	10	4
Other countries		2			2,701	1,883	Offshore
AFRICA		277	48,879	12,896	233,042	115,290		265	163
North Africa		75	12,068	5,292	48,201	22,483		73	61
Algeria	1981	51	6,809	2,851	3,982	1,914	Onshore	39	41
Libya	1959	11	1,963	958	24,673	12,336	Onshore/Offshore	11	15
Morocco	2016	1			16,730	7,529	Offshore
Tunisia	1961	12	3,296	1,483	2,816	704	Onshore/Offshore	23	5
Egypt	1954	56	4,983	1,782	13,729	4,994	Onshore/Offshore	37	26
Sub-Saharan Africa		146	31,828	5,822	171,112	87,813		155	76
Angola	1980	66	10,680	2,010	22,749	8,800	Onshore/Offshore	60	26
Congo	1968	21	1,164	678	1,320	628	Onshore/Offshore	16	5
Gabon	2008	3			2,931	2,931	Onshore/ Offshore		1
Ghana	2009	3	226	100	930	395	Offshore	1	1
Ivory Coast	2015	5			3,840	3,385	Offshore		1
Kenya	2012	6			50,677	41,892	Offshore
Mozambique	2007	10			24,782	4,171	Offshore		6
Nigeria	1962	31	19,758	3,034	8,206	3,340	Onshore/Offshore	78	36
South Africa	2014	1			55,677	22,271	Offshore
ASIA		70	15,943	4,964	267,694	150,518		28	23
Kazakhstan	1992	7	2,391	442	3,853	1,505	Onshore/Offshore	2	3
Rest of Asia		63	13,552	4,522	263,841	149,013		26	20
Bahrain	2019	1			2,858	2,858	Offshore
China	1984	3	62	10			Offshore	2
Indonesia	2001	13	4,778	2,441	16,499	11,743	Onshore/Offshore	3	8
Iraq	2009	1	1,074	446	16,499	11,743	Onshore	1
Lebanon	2018	2			3,653	1,461	Offshore
Myanmar	2014	2			7,192	4,113	Onshore/Offshore
Oman	2017	3			102,016	58,955	Offshore
Pakistan	2000	13	4,009	1,072			Onshore/Offshore	13
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			Onshore	2
United Arab Emirates	2018	12	3,017	251	29,603	18,520	Onshore/Offshore	4	9
Vietnam	2013	5			31,290	28,338	Offshore
Other countries		1			14,600	3,244	Offshore
AMERICAS		112	2,217	1,003	14,813	8,267		38	13
Mexico	2015	10	14	14	5,455	3,092	Offshore	1	3
United States	1968	90	942	492	520	259	Onshore/Offshore	34	8

Venezuela	1998	6	1,261	497	1,543	569	Onshore/Offshore	3	1
Other countries		6			7,295	4,347	Offshore		1
AUSTRALIA AND OCEANIA		4	728	588	2,608	2,117		1	1
Australia	2001	4	728	588	2,608	2,117	Offshore	1	1
Total		771	81,991	27,697	583,836	307,804		438	284

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

AVERAGE REALIZATIONS

	2021		2020		2019		2018
(\$/bbl) Liquids	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities
Italy	61.26		34.58		55.55		61.58
Rest of Europe	70.60	66.72	32.82	35.23	58.92	58.88	64.51
North Africa	68.03	17.89	38.33	18.16	57.91	18.06	65.95	17.92
Egypt	63.53		36.66		54.78		62.97
Sub-Saharan Africa	69.12	44.41	39.99	17.13	63.45	23.72	68.76	39.48
Kazakhstan	66.92		37.37		59.06		66.78
Rest of Asia	68.39		37.69		62.81		68.35	49.86
Americas	61.93	57.75	33.03	27.20	54.00	59.94	57.22	54.86
Australia and Oceania	58.76		17.45		52.93		68.72
	66.91	65.10	37.56	34.21	59.62	55.93	65.79	45.19
(\$/kcf) Natural gas
Italy	15.47		3.16		5.03		8.37
Rest of Europe	15.75	15.11	3.12	3.25	4.95	5.07	7.99
North Africa	6.42	5.83	4.33	6.29	6.21	7.23	4.97	3.58
Egypt	4.74		4.78		5.11		4.85
Sub-Saharan Africa	4.32	14.68	2.76	3.94	2.94	6.16	2.38	9.50
Kazakhstan	0.54		0.69		0.81		0.77
Rest of Asia	6.21		4.09		5.94		6.11	9.32
Americas	4.06	4.32	2.10	4.37	2.46	4.32	2.38	4.28
Australia and Oceania	4.25		3.84		4.41		4.80
	5.93	10.71	3.77	3.73	4.94	4.94	5.17	5.59
(\$/boe) Hydrocarbons
Italy	72.42		25.28		40.24		53.01
Rest of Europe	78.48	71.19	23.94	29.17	39.84	49.76	56.07
North Africa	51.51	18.69	30.28	19.36	44.86	19.39	43.34	18.14
Egypt	34.18		28.03		33.67		36.22
Sub-Saharan Africa	58.24	70.02	32.06	19.97	53.08	30.84	58.59	48.79
Kazakhstan	49.37		27.22		42.21		46.98
Rest of Asia	51.48		31.31		50.31		50.98	50.64
Americas	55.66	24.99	29.57	23.39	48.37	25.67	46.63	28.59
Australia and Oceania	23.03		20.35		26.32		28.99
	49.82	61.11	29.20	27.33	43.73	41.71	48.04	33.63
					2019		2018
Eni's Group Liquids (\$/bbl)	2021 66.62		2020 37.06		59.26		65.47
Natural gas (\$/kcf)	6.64		3.76		4.94		5.20
Hydrocarbons (\$/boe)	51.49		28.92		43.54		47.48

EXPLORATORY WELLS ACTIVITY

			Wells completed(a)						Wells in progress at Dec.31(b)
	2021		2020		2019		2018		2021
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy						0.5	1.8
Rest of Europe	0.1	0.3	0.8	0.4	0.3	1.4		0.5	23.0	5.7
North Africa			0.5	1.5	0.5			0.5	11.0	8.5
Egypt	5.0	5.0	0.7	1.5	1.5	1.5	1.7	1.5	14.0	10.5
Sub-Saharan Africa	1.1	0.4	0.1	0.9	0.9	0.9	0.4		33.0	19.0
Kazakhstan				1.1
Rest of Asia	0.7	1.0	0.8	0.9		1.7	2.2	2.6	15.0	6.5
Americas		0.7		0.6			4.0		3.0	1.9
Australia and Oceania						0.5			1.0	0.3

	7.0	7.4	2.9	6.9	5.8	6.5	10.1	5.1	100.0	52.4

DEVELOPMENT WELLS ACTIVITY

			Wells completed(a)						Wells in progress at Dec.31(b)
	2021		2020		2019		2018		2021
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy					3.0		3.0
Rest of Europe	4.8		2.8		3.3		2.8	0.3	28.0	5.5
North Africa	2.5		4.3		5.0	1.1	9.6	0.5	1.0	0.5
Egypt	17.0	0.8	23.2		33.5		30.7		9.0	3.8
Sub-Saharan Africa	3.8		1.2		7.0		7.3	0.1	6.0	1.2
Kazakhstan			0.3		0.9		0.9		1.0	0.3
Rest of Asia	14.9		23.2	0.4	27.3	2.2	21.9		31.0	10.0
Americas	3.9		2.0		2.1		2.3		4.0	4.0
Australia and Oceania							0.8
	46.9	0.8	57.0	0.4	82.1	3.3	79.3	0.9	80.0	25.3

PRODUCTIVE OIL AND GAS WELLS(d)

		2021
		Oil wells		Natural gas wells
	(units)	Gross	Net	Gross	Net
Italy		201.0	155.2	331.0	293.4
Rest of Europe		655.0	115.2	184.0	48.4
North Africa		620.0	262.2	132.0	71.2
Egypt		1,263.0	539.8	134.0	43.5
Sub-Saharan Africa		2,401.0	506.5	199.0	26.3
Kazakhstan		208.0	56.9	1.0	0.3
Rest of Asia		1,043.0	388.6	183.0	63.7
Americas		258.0	133.4	285.0	82.0
Australia and Oceania				2.0	2.0

		6,649.0	2,157.8	1,451.0	630.8

(a) Number of wells net to Eni.

(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 1,198 gross (315.1 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.

⁽b) Includes temporary suspended wells pending further evaluation.

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	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(b)	(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) 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 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.

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

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

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

CAPITALIZED COST(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2021
Consolidated subsidiaries
Proved mineral interests	18,644	6,953	16,218	21,125	43,947	12,606	12,947	16,407	1,413	150,260
Unproved mineral interests	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 mineral interests		11,483	128		1,517			1,987		15,115
Unproved mineral interests		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 consolidated subsidiaries(b)		9,546	82		2,530		12	897		13,067
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(b)	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(b)		8,990	26		1,058		11	972		11,057

(a) Capitalized costs represent the total expenditures for proved and unproved mineral interests 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 €767 million in 2021 and €843 million in 2020 for the consolidates subsidiaries and €360 million in 2021 and €170 million in

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest of	Asia Americas	Australia and Oceania	Total
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)(c)		9,160	25		1,203		12	1,099		11,499
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 €878 million in 2019 and €831 million in 2018 for the consolidates subsidiaries and €166 million in 2019 and €180 million in 2018 for equity-accounted entities.

(b) Includes Vår Energi AS asset fair value.

COST INCURRED(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2021
Consolidated subsidiaries
Proved property 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
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(b)	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(c)		1,574	4		5			37		1,620
Total costs incurred equity-accounted entities(d)		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(b)	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(c)			3					(16)		(13)
Total costs incurred equity-accounted entities			5				103	(16)		92

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

(b) Includes the abandonment costs of the assets for €62 million in 2021, €516 million in 2020, €2,069 million in 2019 and negative for €517 million in 2018.

(c) Includes the abandonment decrease of the assets for €464 million in 2021, costs for €424 million in 2020, costs for €838 million in 2019 and decrease for €22 million in 2018.

(d) 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	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	3,751	4,249	5,300	8,635	11,051	10,333	3,544	4,486	547	51,896

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


6,120	1,737	19,780	26,003	26,901	21,519	22,528	6,638	1,599	132,825
(3,587)	(753)	(5,431)	(7,515)	(10,909)	(6,224)	(7,241)	(3,382)	(265)	(45,307)
(1,925)	(756)	(4,378)	(1,638)	(4,257)	(1,743)	(4,511)	(1,786)	(246)	(21,240)
608	228	9,971	16,850	11,735	13,552	10,776	1,470	1,088	66,278
(170)	(61)	(4,946)	(5,320)	(2,988)	(2,313)	(6,774)	(441)	(140)	(23,153)
438	167	5,025	11,530	8,747	11,239	4,002	1,029	948	43,125
(33)	108	(2,413)	(4,101)	(3,714)	(6,040)	(1,681)	(482)	(383)	(18,739)
405	275	2,612	7,429	5,033	5,199	2,321	547	565	24,386

	15,306	251		1,253			6,291		23,101
	(5,942)	(98)		(982)			(1,641)		(8,663)
	(6,244)	(29)		(46)			(137)		(6,456)
	3,120	124		225			4,513		7,982
	(576)	(54)		(3)			(1,375)		(2,008)
	2,544	70		222			3,138		5,974
	(1,055)	(43)		(110)			(1,460)		(2,668)
	1,489	27		112			1,678		3,306
405	1,764	2,639	7,429	5,145	5,199	2,321	2,225	565	27,692
						Africa Kazakhstan

		Rest of			Sub-Saharan		Rest of		Australia and
(€ million)	Italy	Europe	North Africa	Egypt		Africa Kazakhstan	Asia	Americas	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	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	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
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) 2021	2020	2019	2018
Acquisition of proved and unproved properties	17	57	400	869
North Africa	6	55	135
Egypt		2	1
Rest of Asia			23	869
Americas	11		241
Exploration	391	283	586	463
Italy				1
Rest of Europe	81	9	43	52
North Africa	11	42	71	20
Egypt	37	48	86	80
Sub-Saharan Africa	81	20	128	22
Kazakhstan	2	4	7
Rest of Asia	120	124	141	140
Americas	59	36	74	146
Australia and Oceania			36	2
Oil and gas development	3,443	3,077	5,931	6,506
Italy	282	229	289	380
Rest of Europe	91	107	110	600
North Africa	206	220	536	525
Egypt	442	393	1,481	2,205
Sub-Saharan Africa	771	624	1,406	1,635
Kazakhstan	189	178	371	193
Rest of Asia	824	916	1,028	550
Americas	611	402	695	381
Australia and Oceania	27	8	15	37
CCUS and agro-biofeedstock projects	37
Other	52	55	79	63
	3,940	3,472	6,996	7,901

(a) Includes reverse factoring operations in 2021.

Global Gas & LNG Portfolio

KEY PERFORMANCE INDICATORS

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

(a) Calculated on 100% operated assets.

(b) 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 2021, Eni's consolidated subsidiaries supplied 70.98 bcm of natural gas, up by 8.82 bcm or 14.2% from 2020.

Gas volumes supplied outside Italy from consolidated subsidiaries (67.39 bcm), imported in Italy or sold outside Italy, represented approximately 95% of total supplies, an increase of 12.70 bcm or 23% from 2020. This mainly reflected higher volumes purchased in Russia (up by 7.72 bcm), Algeria (up by 4.90 bcm), the UK (up by 1.03 bcm) and Indonesia (up by 0.66 bcm), partly offset by lower purchases in Libya (down by 1.26 bcm). Supplies in Italy (3.59 bcm) decreased by 51.9% from 2020.

ENI'S NATURAL GAS SUPPLY

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

Marketing in Italy and Europe

European gas market was characterised by extreme conditions due to tight supplies and uncertainties relating to gas flows from Russia. Against this backdrop, the recovery in demand marked increasing consumptions of about 7% and 6% in Italy and in the European Union, respectively, compared to 2020. Natural gas sales amounted to 70.45 bcm (including Eni's own consumption and the Eni's share of sales made by equity-accounted entities), increasing by 5.46 bcm or 8.4% from the previous year mainly due to higher sales in Turkey and higher volumes of LNG.

GAS SALES BY MARKET

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

Sales in Italy (36.88 bcm) decreased by 1.1% from 2020 mainly due to lower sales to hub and to power generation and industrial segments, partly offset by higher sales to wholesalers segment. Sales to importers in Italy (2.89 bcm) decreased by 21.3% from 2020 due to the lower availability of Libyan gas. Sales in the European markets amounted to 25.12 bcm, an increase of 30% or 5.79 bcm from 2020.

Sales in the extra European markets of 5.56 bcm increased by 0.87 bcm (18.6% from the previous year), due to higher volumes marketed in the Asian markets.

A review of Eni's presence in the main European markets is presented below:

GLOBAL GAS & LNG PORTFOLIO PRESENCE IN EUROPE

Benelux

Eni operates in Benelux in the industrial, wholesalers and power generation segments. In 2021, sales amounted to 3.47 bcm, down by 0.11 bcm, or 3.1% compared to 2020, mainly due to optimization actions partly offset by higher sales to hub.

France

In France, Eni operates in all business segments through its direct commercial activities and its subsidiary Eni Gas & Power France SA. In 2021, sales in the Country amounted to 5.80 bcm, an increase of 0.79 bcm, or 15.8%, from a year ago, mainly due to portfolio optimizations, partially offset by lower sales to hub.

Germany/Austria

In 2021 total sales in Germany and Austria amounted to 0.69 bcm, an increase of 0.34 bcm, or 97.1% from 2020, due to the portfolio optimizations and higher sales to hub.

Spain

Eni operates in the Spanish natural gas market through marketing of natural gas to industrial clients, wholesalers and power generation utilities. In 2021, total Eni's sales in Spain amounted to 3.75 bcm, a decrease of 0.19 bcm, or 4.8% compared to 2020.

In March 2021, as a part of portfolio optimization actions was completed the restructuring of Uniòn Fenosa Gas (UFG) through the finalization of the agreements with the authorities of the Arab Republic of Egypt (ARE) and the Spanish partner Naturgy for the settlement of the Uniòn Fenosa Gas disputes with the Egyptian partners. The agreement foresees the ownership by Eni of a 50% share of Damietta's plant and the related liquefaction capacity, as well as the gas marketing activities in Spain held by UFG and the restart of Damietta liquefaction plant.

Turkey

Eni sells gas supplied from Russia and transported via Blue Stream pipeline. In 2021, sales amounted to 8.50 bcm, a decrease of 3.91 bcm, or 85.2% from a year ago mainly driven by higher 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 2021, sales amounted to 2.65 bcm, up by 1.03 bcm or 63.6% compared to 2020 due to higher volumes sold to hub.

1.2 LNG

Eni is engaged in all the activities of the LNG business: liquefaction, gas feeding, shipping, regasification and sale. As a part of Eni's decarbonization strategy enhancing LNG portfolio, in 2021 Eni signed an agreement with CPC Corporation, a taiwanese utility, for the supply at the Yung An receiving terminal (Taiwan) of a LNG cargo certified carbon neutral, according to the internationally recognized PAS2060 standard, sourced from the Bontang liquefaction terminal in Indonesia and supplied by the Jangkrik Eni's gas field. The GHG emissions related to the entire value chain of the LNG cargo, including gas production, transmission, liquefaction, shipping, regasification, distribution and end use, were offset through the retirement of high quality nature based credits. In particular, the credits have been sourced from two projects REDD+: Luangwa Community Forest in Zambia and Kulera Landscape in Malawi.

In April 2022, Eni and the Egyptian state-owned company "EGAS" agreed to valorize local gas reserves by increasing activities in jointly operated concessions and by exploring near field areas, with the goal of boosting production and gas exports to Italy via the Damietta liquefaction plant at an expected initial rate of up to 3 billion cubic meters in 2022.

In 2021, LNG sales (10.9 bcm, included in the worldwide gas sales) increased by 14.7% from 2020 and mainly concerned LNG from Egypt, Qatar, Indonesia and Nigeria, and marketed in Europe and Asia.

2. INTERNATIONAL TRANSPORT

MAIN GAS TRANSPORT INFRASTRUCTURE IN EUROPE(*)

Eni, as shipper, 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). The Company owns shares in both entities operating the pipelines and entities managing transport rights.

As a part of the Eni's portfolio optimization strategy, aimed at growing in the areas related to the energy transition, was signed a sale agreement with Snam for the sale of the 49.9% Eni's stake (directly or indirectly) in the companies that manage the onshore gas pipelines running from the Algerian and Tunisian borders to Tunisia's coast (TTPC) and the offshore gas pipelines connecting the Tunisian coast to Italy (TMPC). The transaction includes the transfer of these investments to a JV of which a 49.9% share will be sold to Snam for approximately €385 million (Eni will continue to hold the remaining 50.1% stake). This operation allows to exploit synergies among the parties' expertise in gas transport on a strategic route for the security of the natural gas supply in Italy, enabling potential development initiatives within the hydrogen value chain from North Africa.

In April 2022, signed an agreement with Algeria, in order to gradually increase the volumes of gas exported to Italy through the Transmed pipeline as part of the existing longterm supply contracts with Sonatrach, with additional gas deliveries starting in the next heating season and rising up to 9 billion cubic meters per year in 2023-24.

A description of the main international pipelines currently participated or operated by Eni 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, for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 bcm/y. It crosses the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system;
} the GreenStream pipeline, for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and

Wafa. It is 520-kilometer long with an originally transport capacity of 8 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;

} Eni holds a 50% interest in 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. Announced by the management, the sale of 50% stake of this gas pipeline.

SUPPLY OF NATURAL GAS

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

GAS SALES BY ENTITY

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

LNG SALES

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

62 TRANSPORT INFRASTRUCTURES

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 520 km	520	32	8.0	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

	2021	2020	2019	2018
Market		5	3	19
Italy				8
Outside Italy		5	3	11
International transport	19	6	12	7
TOTAL CAPITAL EXPENDITURE	19	11	15	26

Energy Evolution

Refining & Marketing and Chemicals

The Energy Evolution Business Group is engaged in the evolution of the businesses of power generation, transformation and marketing of products from fossil to bio, blue and green. In particular, it is focused on growing power generation from renewable energy and biomethane, it coordinates the bio and circular evolution of the Company's refining system and chemical business, and it further develops Eni's retail portfolio, providing increasingly more decarbonized products for mobility, household consumption and small enterprises. The Business Group includes results of the Refining & Marketing business, the chemical business managed by Versalis SpA and its subsidiaries, the newly-formed Plenitude SpA which combines renewables generation, gas and power retail and business customers, electric vehicle charging and energy services in a unique business model. In addition to these activities, this business Group include the results of power generation from thermoelectric plants and the activities of environmental reclamation and requalification implemented by the subsidiary company Eni Rewind.

Refining & Marketing and Chemicals

KEY PERFORMANCE INDICATORS

		2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)(a)	(total recordable injuries/worked hours) x 1,000,000	0.80	0.80	0.27	0.56
of which: employees		1.13	1.17	0.24	0.49
contractors		0.49	0.48	0.29	0.62
Sales from operations(b)	(€ million)	40,374	25,340	42,360	46,483
Operating profit (loss)		45	(2,463)	(682)	(501)
Adjusted operating profit (loss)		152	6	21	360
- Refining & Marketing		(46)	235	289	370
- Chemicals		198	(229)	(268)	(10)
Adjusted net profit (loss)		62	(246)	(42)	224
Capital expenditure		728	771	933	877
Bio throughputs	(ktonnes)	665	710	311	253
Capacity of biorefineries	(mmtonnes/year)	1.1	1.1	1.1	0.4
Average biorefineries utilization rate	(%)	65	63	44	63
Conversion index of oil refineries		49	54	54	54
Balanced capacity of refineries (Eni's share)	(kbbl/d)	548	548	548	548
Average oil refineries utilization rate	(%)	76	69	88	91
Retail sales of petroleum products in Europe	(mmtonnes)	7.23	6.61	8.25	8.39
Service stations in Europe at year end	(number)	5,314	5,369	5,411	5,448
Average throughput per service station in Europe	(kliters)	1,521	1,390	1,766	1,776
Retail efficiency index	(%)	1.19	1.22	1.23	1.20
Production of petrochemical products	(ktonnes)	8,476	8,073	8,068	9,483
Sale of petrochemical products		4,451	4,339	4,295	4,946
Average petrochemical plant utilization rate	(%)	66	65	67	76
Employees at year end	(number)	13,072	11,471	11,626	11,457
- of which outside Italy		4,044	2,556	2,591	2,594
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	6.72	6.65	7.97	8.19
GHG emissions (Scope 1)/refinery throughputs (raw and semi-finished materials)	(tonnes CO2 eq./ktonnes)	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; 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.

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 five 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.

Among Eni's traditional refinery transformation strategy, in 2021 Eni signed a joint cooperation and licensing agreement with Chevron Lummes Global for a complete conversion of hydrocracking residues in order to market globally a wide range of hydrocracking processes, including complete conversion of heavy residues into lighter and valuable distillate products.

PRODUCTION CYCLE OF REFINED PRODUCTS

1. REFINING

In 2021, Eni refinery capacity (balanced refining capacity) was approximately 27.4 mmtonnes (equal to 548 kbbl/d), with a conversion index of 49%.

Eni's 100% owned refineries have a balanced capacity of 19.4

mmtonnes (equal to 388 kbbl/d), with a 47% conversion index. In 2021, Eni's refineries throughputs in Italy and outside Italy were 18.78 mmtonnes, increased from 2020 (up by 1.78 mmtonnes, or 10.5%).

REFINING SYSTEM IN 2021

	Ownership	Balanced refining capacity (Eni's share)(a)	Utilization rate (Eni's share)	Conversion index(b)	Fluid catalytic cracking (FCC)(c)	Residue	Conversion(c) Hydrocracking(c)	Visbreaking/ Thermal Cracking(c)
	(%)	(kbbl/d)	(%)	(%)	(kbbl/d)	(kbbl/d)	(kbbl/d)	(kbbl/d)
Wholly-owned refineries		388	74	47	34	26	71	29
Italy
Sannazzaro	100	200	75	58	34		51	29
Taranto	100	104	72	56		26	20
Livorno	100	84	73	11
Partially-owned refineries		160	81	52	143	182	239	27
Italy
Milazzo	50	100	84	60	45	25	32
Germany
Vohburg/Neustadt (Bayernoil)	20	41	69	36	49		43
Schwedt	8.33	19	90	42	49			27
TOTAL		548	76	49	177	208	310	56

(a) Including 20% share in ADNOC Refining, balanced refining capacity amounted to 732 kbbl/d.

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

Italy

Eni's refining system in Italy is composed by three whollyowned 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 200 kbbl/d and a conversion index of 58%. 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, and finally the Eni Slurry Technology (EST) plant, started up in 2013. The EST plant exploits a proprietary technology to convert extra heavy crude residues (vacuum and visbreaking tar) into naphtha and middle distillates (in particular gasoil), with a conversion factor of 95%.

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 in Basilicata (Eni 61%) 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 Florence (Calenzano). The refinery has a topping vacuum unit, a platforming unit,

BIO REFINERIES

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 vegetable oil in hydrogenated biofuels.

	Ownership share	Capacity (2021)	Throughput (2021)
Wholly owned	(%)	(mmtonnes/y)	(mmtonnes/y)
Venezia	100	0.4	0.2
Gela	100	0.7	0.5
Total		1.1	0.7

Gela: reached full operation at Gela biorefinery in 2020, thanks to the EcofiningTM technology, developed by Eni, to convert into biodiesel vegetable oil and second generation raw materials, such as used cooking oil and animal fat. The plant properties will allow the production of biodiesel in compliance with the last regulatory constraints in terms of reduction of GHG emissions throughout the whole production chain, deploying the full capacity in process second-generation feedstock. In March 2021, started the Biomass Treatment Unit (BTU) to expand the range of charges to be processed by the plant, allowing to use of up to 100% of biomass not in competition with the food chain in raplacement of palm oil.

The volumes of biofuels processed from vegetable oil were 665 mmtonnes down by 6% from the previous period (down by 40 ktonnes), as a result of standstill at Venezia biorefinery in a depressed scenario context.

In addition, the incidence rate of palm oil supplied for the production of biodiesel was reduced by approximately 34 percentage points compared to 2020, leveraging on the start-up of a new Biomass Treatment Unit (BTU) at the Gela biorefinery. Confirmed the zeroing palm oil by 2023 in the refining processes.

In 2021, production of biofuels (HVO) amounted to approximately 585 ktonnes (down by 6%) according to certifications in use (European RED and related directives).

PRODUCTION CYCLE OF BIOFUELS

DEVELOPMENT OF THE CIRCULAR ECONOMY IN BIOFUELS

In 2021 Eni finalized the full share acquisition of FRI-EL Biogas Holding, Italian leader in biogas's production. The company, renamed EniBioCh4in, owns plants generating electricity from biogas and a plant for processing OFMSW, the organic fraction of municipal solid waste, which Eni intends to convert to produce biomethane, that will supply in Eni service stations which will deliver Compressed Natural Gas (CNG) and Liquefied Natural Gas (LNG), in line with the Eni's decarbonization strategy.

Furthermore, in order to promote initiatives to decarbonize

the aviation sector and accelerate the process of energy transition of airports, signed an agreement with SEA, the Milan Malpensa and Milan Linate airports operator, for the supply of sustainable fuels for aviation (SAF – Sustainable Aviation Fuel) and for ground handling (HVO – Hydrotreated Vegetable Oil). This initiative is in line with the agreement finalized in January 2022 with Aeroporti di Roma which launched the first supplies of pure HVO hydrogenated biofuel, produced in Eni's biorefinery in Porto Marghera, to fuel the road vehicles for handling passengers with reduced mobility at the airport.

The SAF production started in October through the esclusive use of waste and residues in line with the strategic decision of zeroing the use of palm oil by 2023.

As a step towards the transport decarbonization was signed a letter of intent with Air Liquide for development of hydrogen mobility in Italy, relating mainly to the feasibility and sustainability study for the development of the low carbon and renewable hydrogen supply chain to support the market of fuel cell vehicles for heavy and light mobility.

Finally, Eni signed a strategic agreement with BASF, for the development of a new technology to produce advanced bio-propanol from glycerin, obtained from the production of industrial biodiesel FAME (Fatty Acid Methil Esters), addressed to the use as a bio component in fuel formulation.

ENI'S REFINING AND LOGISTIC SYSTEM(*)

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, Porto Petroli di Genova e 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 to retail and wholesale markets 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 1.03 mmtonnes/y of oxygenates, mainly ethers (approximately 2% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use).

About 87% 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 13% is purchased.

MARKETING

1. RETAIL SALES IN ITALY

Eni is a leader in the Italian retail market of refined products with a 22.3% market share, slightly decreased from 2020 (23.2%). In 2021, retail sales in Italy were 5.12 mmtonnes, with an increase compared to 2020 (0.56 mmtonnes or up by 12.3%) as a result of the progressive economy reopening and greater mobility of people. Average gasoline and gasoil throughput (1,362 kliters) up by 156 kliters from 2020.

As of December 31, 2021, Eni's retail network in Italy consisted of 4.078 service stations, lower by 56 units from December 31, 2020 (4.134 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (65 units), a decrease of 4 motorway concession/acquisitions, partly offset by the positive balance of acquisitions/releases of network owned stations (13 units).

In order to enrich the range of services offered at Eni service stations, in 2021, more than 800 Amazon lockers have been installed, to allow customers to conveniently pick up purchases and about 200 Telepass points, to request, withdraw or replace the Telepass device. Other services include the Emporium retail chain, which at the end of 2021 counts in 80 stores located at the Eni cafè stores (in over 600 service stations).

2. RETAIL SALES IN THE REST OF EUROPE

Retail sales in the rest of Europe were 2.11 mmtonnes, reported an increase from 2020 (up by 2.9%) as a result of higher volumes sold in Austria, France and Spain benefitting from the economic recovery and greater mobility of people.

As of December 31, 2021, Eni's retail network in the rest of Europe consisted of 1,236 units, increasing by 1 units from December 31, 2020, in Spain, balanced by the retail network closer in Switzerland and France. Average throughput (2,025 kliters) increased by 45 kliters compared to 2020 (1,980 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.

RETAIL AND WHOLESALE BUSINESSES IN EUROPE - 2021 ENI'S COMPETITIVE POSITION

Wholesale sales in Italy amounted to 6.02 mmtonnes, increasing by 4.7% from the full year of 2020, due to lower impact of the restrictive measures and the resumption of air transport.

Supplies of feedstock to the petrochemical industry (0.52 mmtonnes) decreased by 14.8%.

Wholesale sales in the Rest of Europe were 2.19 mmtonnes, down by 8.8% from 2020 particularly in Germany, Switzerland and Austria.

Other sales in Italy and outside Italy (11.49 mmtonnes) increased (up by 1.26 mmtonnes or up by 12.3%) mainly due to higher 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 2021, Eni share of LPG market in Italy was 15.5%.

Outside Italy, the main market of Eni is Ecuador, with a market share of 36.6%.

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 knowhow 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 2021, Eni's share of lubricants market in Italy was 21.9%, 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, 2021, the Enjoy fleet consisted of 2,274 FIAT 500 cars and 98 FIAT Cargo vehicles distributed over the major Italian cities: Milan (910 FIAT 500 and 40 Cargo); Rome (860 FIAT 500 and 38 Cargo); Turin (270 FIAT 500 and 10 Cargo); Bologna (136 FIAT 500 e 10 Cargo); Florence (98 FIAT 500). The average number of rentals in the year was 175,000/monthly.

In line with the sustainable mobility growth strategy, in 2021 started the process of replacing the car fleet with hybrid/ electric cars. In particular, Eni signed an agreement in order to introduce, from 2022, the XEV YOYO zero emission city car as part of the Enjoy fleet, as well as to offer the battery swapping service for XEV's city car at Eni service stations.

In addition, the same sustainable development program includes Eni parking: in 2021, 30 car parks have been opened, throughout the national territory, for a total of about 500 stalls.

The Eni Parking are paid through, smart, paperless, cashless ways or through Eni Live App. These parking areas allow to recover and make profitable services in those discharged areas or not used at the Eni Stations; furthermore, in synergy with the car sharing service Enjoy and with the Eni charging service, Eni Parking will allow the creation of intermodal exchange hubs and alternative mobility.

PURCHASES

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

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

AVAILABILITY OF REFINED PRODUCTS

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

72 PRODUCTION AND SALES

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

SALES OF REFINED PRODUCTS BY MARKET

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

SALES BY PRODUCT/MARKET

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

SERVICE STATIONS

	2021	2020	2019	2018
Italy (units)	4,078	4,134	4,184	4,223
Ordinary stations	3,967	4,019	4,068	4,108
Highway stations	111	115	116	115
Outside Italy	1,236	1,235	1,227	1,225
Germany	480	480	476	471
France	155	158	155	155
Austria/Switzerland	592	597	596	599
Spain	9
Service stations selling premium products	4,872	4,619	4,669	4,675
of which service stations selling Diesel +	3,712	3,663	3,683	3,537
Service stations selling LNG	15	4	4	4
Service stations selling LPG and natural gas	1,111	1,091	1,086	1,043
NON-OIL SALES (€ million)	160	148	156	144

AVERAGE THROUGHPUT

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

74 MARKET SHARES IN ITALY

	2021	2020	2019	2018
Retail	22.3	23.2	23.6	24.0
Gasoline	19.7	20.2	19.8	20.2
Gasoil	23.6	24.9	25.4	25.7
LPG (automotive)	21.9	20.7	22.9	23.6
Wholesale	21.8	23.4	25.0	24.8
Gasoil	21.5	24.4	23.6	22.3
Fuel oil	7.2	4.9	10.9	12.8
Bunker	19.9	21.3	24.3	24.9
Lubricants	18.9	21.2	20.0	18.8

RETAIL MARKET SHARES OUTSIDE ITALY

	2021	2020	2019	2018
Central Europe
Austria	11.4	12.4	12.3	12.3
Switzerland	6.7	6.7	7.7	7.8
Germany	3.0	3.1	3.2	3.2
France	0.7	0.7	0.6	0.8

CAPITAL EXPENDITURE

(€ million)	2021	2020	2019	2018
Italy	470	535	743	661
Outside Italy	68	53	72	65
	538	588	815	726
Refining, supply and logistic	390	462	683	587
Italy	375	449	662	578
Outside Italy	15	13	21	9
Marketing	148	126	132	139
Italy	95	86	81	83
Outside Italy	53	40	51	56
TOTAL	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), 22 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.

Proprietary technologies will play a key role in accelerating the "green" conversion of Versalis by reducing dependence on oil feedstock; among these, we focus on the chemical recycling of non-reusable plastics (HOOP technology), on the enhancement of forest biomass for the production of bioethanol and biogas (PROESA technology) in collaboration with qualified partners such as Saipem and BTS Biogas.

As part of the valorization of proprietary technologies and the strengthening of Eni presence in Asia, Versalis has licensed the mass continuous technology to Supreme Petrochem Ltd, an Indian market-leader in compact and expandable polystyrene, to create a plant in Maharashtra (India). This is a technology that allows the production of styrene polymers with reduced environmental impact, thanks to low emission and low energy consumption.

In April 2022, Versalis signed an agreement with the Chinese Shandong Eco Chemical Co. Ltd. to license the proprietary continuous mass technology to manufacture styrenic polymers with a low-carbon footprint.

In order to expand the recycled polymers portfolio of Versalis Revive® and to consolidate the European leadership in styrenic polymers, Versalis acquired the technology and plants of Ecoplastic, company specialized in the recovery, recycling and transformation chain of styrenic polymers. This is the first step of the transformation project of Porto Marghera plant, which includes the installation in the next year of the plants acquired for the production of styrene polymers entirely obtained from recycle raw material. The overall capacity of the first phase will be approximately 20 ktonnes/year.

In addition, Versalis will build the first plant in Italy in Porto Marghera for the production of isopropyl alcohol, which is currently fully imported from abroad and used in various market sectors. The new plant capacity of 30,000 tonnes/year, is in line with domestic market demand and is considered a strategic step in specialising the Versalis' portfolio with higher value products. A hydrogen production plant will also be built to serve the isopropyl alcohol plant.

THE PRODUCTION CYCLE

product from petroleum, undergoes thermal cracking also known as steam-cracking. The component molecules split into simpler molecules: monomers (ethylene, propylene, butadiene, etc.) and into blends of aromatic compounds. These are then reconstituted into more complex molecules: the polymers. The following are produced from polymers: polyethylene, styrenes and elastomers used by processing companies to produce a whole variety of products for everyday use.

In September, Versalis finalized the acquisition of the control in Finproject, exercising the call option to buy the remaining 60% of share capital, following the initial acquisition of a 40% participating interest in 2020. The acquisition is complementary to specialties portfolio and will create an all-Italian leading platform with high-performance formulated polymer applications and compounding, less influenced by commodity fluctuations. In January 2022 Finproject has taken the ISCC Plus certification for compound productions and products from renewable raw materials.

The main objective of basic petrochemicals is granting the adequate availability of monomers (ethylene, butadiene and benzene) which represent the feedstock for further production processes: in particular olefins production is strictly linked with the polyethylene and elastomers business, aromatics grant the benzene availability necessary to produce intermediate products used in the production of resins, artificial fibres and polystyrene. In polymers business Versalis is one of the most relevant European producers of elastomers, where it is present in almost all the relevant sectors (in particular, in the automotive industry), polystyrene and polyethylene, whose most relevant use is in flexible packaging.

Versalis, coherently with the Eni's decarbonization strategy, has launched a transformation plan which aims to make its activities and products diversified and sustainable, in accordance with the principles of the circular economy.

In 2021, Versalis expanded the "circular" products offering, manufactured with recycled raw materials. A new product called Versalis Revive® PS Air F – Series Forever was added to Versalis Revive® product line.

It was addressed for food packaging and 75% made by recycled polystyrene from domestic waste sorting.

The new product developed by Versalis and Forever Plast SpA, is the result of collaboration with various operators in the polystyrene industry such as Corepla, Pro Food e Unionplast.

Confirmed the commitment aimed at the development of sustainable innovative technologies, through the agreement signed with BTS Biogas, an Italian company engaged in the design and realization of biogas plants, to develop and market an innovative technology to produce biogas and biomethane from residual lignocellulosic biomass. The technology will focus on Versalis' technology integration for biomass thermomechanical pretreatment, with the BTS Biogas technology for biogas and biomethane production via fermentative ways.

Finally, signed an agreement between Matrìca, a JV Versalis/Novamont company, and Lanxess, a leader in specialty chemicals for the production of biocides from renewable raw materials. In January 2022 started the supply of renewable-source raw materials obtained from vegetable oils to the Porto Torres plant. Lanxess will use these materials to produce biocidal industrial additives for the consumer goods sector.

INTEGRATED PLATFORM FOR PLASTIC WASTE RECYCLING

VERSALIS' INTERNATIONAL PRESENCE

Business areas

Petrochemical sales of 4,451 ktonnes slightly increased from 2020 (up by 112 ktonnes, or 2.6%) thanks to the macroeconomic growth and the rebound in demand in leading sectors, such as packaging, durable goods sector and the recovery of the automotive sector.

Singapore) and the joint venture in Abu Dhabi and delivers services to manufacturing companies in France, Germany, Hungary and UK.

This performance also reflects the ability to capture additional sales volumes thanks to the greater availability of the plants obtained by reprogramming the multi-year standstill, to reap the benefits from the recovery in demand e and the reduction in imports from producer countries (USA and Middle East), also as result of temporary product shortages.

Average unit sales prices of the intermediates business increased by 56.3% from 2020, with aromatics and olefins up by 84.7% and 52.9%, respectively. The polymers reported an increase of 66.6% from 2020.

Petrochemical production of 8,476 ktonnes up by 403 ktonnes from 2020 due to higher production of intermediates business (up by 423 ktonnes), in particular olefins; these higher volumes were partially offset by lower productions of styrenics down by 78 ktonnes from 2020.

The main increases in production were registered at the Priolo site (up by 527 ktonnes) and in Dunkerque (up by 221 ktonnes), offset by lower volumes processed at Brindisi (down by 201 ktonnes) and Porto Marghera (down by 140 ktonnes).

Nominal capacity of plants were substantially unchanged from 2020. The average plant utilization rate calculated on nominal capacity was 66% (65% in 2020).

INTERMEDIATES

Intermediates revenues (€2,166 million) increased by €837 million from 2020 (up by 63%) reflecting both the increase of commodity prices scenario and the higher product availability. Sales increased, in particular for olefins (up by 7.6%). Average unit prices increased by 56.3%, in particular aromatics (up by 84.7%), olefins (up by 52.9%) and derivatives (up by 50.1%). Intermediates production (6,284 ktonnes) registered an increase of 7.2% from 2020. Significant increases were recorded in aromatics (up by 14.2%) and in olefines (up by7.2%). In reduction derivatives (down by 7.3%).

POLYMERS

Polymers revenues (€3,114 million) increased by €1,226 million or 64.9% from 2020 due to the increase of the average unit prices (up by 66.6%). The styrenics business benefitted of the increase of prices sale (up by 68.9%) despite the decrease of sold volumes (down by 7.9%) due to the lower product availability as a result of the maintenance standstills in Mantova.

The decrease of volumes were mainly attributable to GPPS (down by 23%), ABS (down by 16.6%) and compact polystyrene (down by 3.3%), these lower volumes were partly offset by higher sales of styrene (up by 13.4%).

In the elastomers business, an increase of sold volumes (up by 11.4%) was attributable to higher volumes of EPR (up by 40.5%), lattices (up by 23.6%) and NBR rubbers (up by 14.8%). Overall, the sold volumes of polyethylene business reported a slight reduction (down by 1.4%) with lower sales of HDPE and LDPE (down by 10.3% and 3.4%, respectively), partly offset by higher sales of EVA (up by 6.4%); in addition, average sales prices increased (up by 73.9%). Polymers productions (2,184 ktonnes) decreased from the 2020 due to the lower productions of styrenics (down by 7.9%), partly offset by higher production of elastomers (up by 13.4%).

OILFIELD CHEMICALS, BIOCHEM AND MOULDING & COMPOUNDING

Oilfiled chemicals revenues (€65 million) increased by 16.1% (up by €9 million compared to 2020) as a result of the higher sales volumes (15 ktonnes) following the effect of the new contracts signed.

Biochem business revenues (€60 million) increased by €54 million from 2020 and mainly refer to sales of disinfectant produced at the Crescentino plant. The amount also includes the share of revenue from sales of energy produced at the biomass power plant at the Crescentino hub.

Moulding & Compounding business revenues of €70 million refer to 20 ktonnes of products sold, following the consolidation of the Finproject group on October 1st, 2021. The amount includes compounding activities for €21 million, moulding for €24 million and the Padanaplast activities for €25 million.

PRODUCT AVAILABILITY

2021	2020	2019	2018
6,284	5,861	5,818	7,130
2,184	2,211	2,250	2,353
8	1
8,476	8,073	8,068	9,483
20
8,496	8,073	8,068	9,483
(4,590)	(4,366)	(4,307)	(5,085)
565	632	534	548
4,471	4,339	4,295	4,946
2,648	2,539	2,519	3,095
1,771	1,790	1,766	1,851
24	9	10
8	1
4,451	4,339	4,295	4,946
20
4,471	4,339	4,295	4,946

REVENUES BY GEOGRAPHIC AREA

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

REVENUES BY PRODUCT

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

CAPITAL EXPENDITURE

(€ million)	2021	2020	2019	2018
	190	183	118	151
of which:
- upkeeping	56	79	42	21
- plant upgrades and efficecny	23	35	34	84
- HSE and asset integrity	76	39	27	26
- decarbonization	21	13	4	8
- green & circular	4	7	4
- other	10	9	7	12

Plenitude & Power

KEY PERFORMANCE INDICATORS

		2021	2020	2019	2018
TRIR (Total Recordable Injury Rate)(a)	(total recordable injuries/worked hours) x 1,000,000	0.29	0.32	0.62	0.60
of which: employees		0.49	0.00	0.30	0.31
contractors		0.00	0.73	0.95	1.16
Sales from operations(b)	(€ million)	11,187	7,536	8,448	8,218
Operating profit (loss)		2,355	660	74	340
Adjusted operating profit (loss)		476	465	370	262
- Plenitude		363	304	256	178
- Power		113	161	114	84
Adjusted net profit (loss)		327	329	275	189
Capital expenditure		443	293	357	238
Plenitude
Retail and business gas sales	(bcm)	7.85	7.68	8.62	9.13
Retail and business power sales to end customers	(TWh)	16.49	12.49	10.92	8.39
Retail/business customers	(million of POD)	10.04	9.70	9.55	9.33
Energy production sold from renewable sources	(GWh)	986	340	61	12
Renewables installed capacity at period end	(MW)	1,137	335	174	40
Power
Power sales in the open market	(TWh)	28.54	25.33	28.28	28.54
Thermoelectric production		22.36	20.95	21.66	21.62
Employees at year end		2,464	2,092	2,056	2,056
of which outside Italy		600	413	358	337
Direct GHG emissions (Scope 1)(a)	(mmtonnes CO2 eq.)	10.03	9.63	10.22	10.47
Direct GHG emissions (Scope 1)/equivalent produced electricity (Eni Power)	(gCO2 eq./kWh eq.)	380	391	394	402

(a) Calculated on 100% operated assets. (b) Before elimination of intragroup sales.

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

In particular, 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.

Country of presence	GW1	Technology	Customers (mln)	Charging points		Installed capacity of power stations (GW)2
Italy	0.5		7.8	>6,200		4.5
France	0.1		1.4
Spain	0.2		0.3
USA	0.8
UK	0.5
Other	0.2		0.5
TOTAL	2.3		10.0	>6,200		4.5
Photovoltaic		Onshore wind		Offshore wind	Other	E-Mobility

1) Data as of December 31,2021 (installed or under construction assets). 2) Power stations with CCGT technology and a heating district station.

1. RETAIL

Plenitude operates, directly or through subsidiaries, in the marketing of gas, power and services in Italy, France, Greece, Slovenia and in the Iberian Peninsula. It also operates in the business of natural gas distribution in Greece through a jointly controlled entity and Slovenia with a subsidiary.

Plenitude, in addition to the commodity services, continued its development of a series of extracommodity services in energy efficiency, expanding its commercial offer with integrated and innovative solutions, mainly focused on the segment of small and medium-sized enterprises and on the housing facilities.

As part of initiatives finalized to extract value from portfolio restructuring by creating independent vehicles focused on attracting capital, creating value and accelerating growth, started the listing process for Plenitude, comprising Gas & Power retail activities, renewables and e-mobility, with the strategic goal of decarbonizing Eni's customer portfolio, contributing to achieve the reduction target on GHG Scope 3 emissions.

Eni established Plenitude as part of its strategy and the long-term commitment to become a decarbonization energy company focused on sustainability. The decision is in line with a favorable industrial scenario, with the growth of renewables demand and green energy products for retail customers.

GAS DEMAND

Eni operates in a liberalized market where energy customers are allowed to choose the gas supplier and, according to their specific needs, to evaluate the quality of services and offers. Overall Eni supplies 10 million retail and business customers (gas and electricity) in Italy and Europe. In particular, clients located all over Italy are 7.8 million.

GAS SALES BY MARKET

(bcm)	2021	2020	2019	2018
ITALY	5.14	5.17	5.49	5.83
Residential	3.88	3.96	3.99	4.20
Small and medium-sized enterprises and services	0.72	0.70	0.87	0.79
Industries	0.30	0.28	0.30	0.39
Resellers	0.24	0.23	0.33	0.45
INTERNATIONAL SALES	2.71	2.51	3.13	3.30
European markets
France	2.17	2.08	2.69	2.94
Greece	0.39	0.34	0.35	0.24
Other	0.15	0.09	0.09	0.12
WORLDWIDE GAS SALES	7.85	7.68	8.62	9.13

RETAIL AND BUSINESS GAS SALES

In 2021, retail and business gas sales in Italy and in the rest of Europe amounted to 7.85 bcm, up by 0.17 bcm or 2% from the previous year. Sales in Italy amounted to 5.14 bcm were substantially unchanged from 2020, the reduction reported in the residential segment was almost fully absorbed by the higher volumes marketed at the industries and the small and medium enterprises segments.

Sales in the European markets (2.71 bcm) are increasing of 8% or 0.20 bcm compared to 2020. Higher sales were recorded in France, Greece and Spain benefiting from the lower impact of the COVID-19 which strongly impacted 2020, as well as the acquisition of Aldro Energía.

RETAIL AND BUSINESS POWER SALES TO END CUSTOMERS

In 2021, retail and business power sales to end customers amounted to 16.49 TWh, managed by Plenitude and its subsidiaries in France, Greece and Spain. The increase of 32% from 2020 was due to the growth of retail customers portfolio (up by 4% vs. 2020) thanks to the acquisition of Aldro Energía and the development of activities in Italy and abroad.

2. RENEWABLES

Eni's targets in the renewable energy business will be reached by leveraging on an organic development of a diversified and balanced portfolio of assets, integrated through selective assets and projects acquisitions as well as international strategic partnership.

BUSINESS DEVELOPMENTS

Evolvere, Plenitude's subsidiary, finalized the acquisition of a 100% stake in PV Family, an innovative startup that manages My Solar Family, the largest digital community of prosumer (consumers/ energy producers), in Italy with over 80 thousand subscribers. This acquisition is aimed to combine the Evolvere's offer with digital community services, in a context that promotes a new energy model where the customer evolves from a consumer to an energy producer. With this acquisition Evolvere confirms the leadership in distributed generation from renewable sources in Italy and reaffirms the promotion of a new energy model, decentralized and sustainable, contributing to the ongoing energy transition.

Eni and CDP Equity established GreenIT, a new joint venture for the development, construction and management of plants for the production of electricity from renewable sources in Italy. The JV's aim is to reach a level of installed capacity of approximately 1 GW. In March 2022, GreenIT has acquired the entire portfolio of Fortore Energia Group, consisting of four onshore wind farms operating in Puglia with a total capacity of 110 MW.

RENEWABLE ENERGY BUSINESS DEVELOPMENTS

In 2021 continued the expansion in the national and international renewable energy market, with strong acceleration in the build-up of renewable generation capacity, leveraging targeted tuck-in acquisitions to be quickly integrated into Eni's portfolio:

} in Italy finalized the acquisition from Glennmont Partners ("Glennmont") and PGGM Infrastructure Fund("PGGM") of a portfolio of 13 onshore wind farms in Italy, for a total capacity of 315 MW;
} in Spain, finalized in October the acquisition from Azora

Capital of 9 renewable energy projects consisting of 3 wind facilities in operation and 1 under construction for a total of 234 MW and 5 photovoltaic projects at an advanced stage of development for about 0.9 GW;

} in France and Spain finalized in October the acquisition of Dhamma Energy Group, owner of a pipeline of photovoltaic projects with a target installed capacity of about 3 GW, and installations already in operation or under construction with a capacity of approximately 120 MW;
} in Greece, in January 2022, acquired the Greek company Solar Konzept Greece "SKGR", owner of a portfolio of photovoltaic plants in Greece with a pipeline of projects targeting about 800 MW, which will form the basis for further development of the renewable portfolio in the country;
} in the UK offshore wind market finalized the agreement with Equinor and SSE Renewables for the acquisition of the 20% interest in Dogger Bank C project (1.2 GW), the third phase of the largest offshore wind farm in the world (3.6 GW) currently under construction in the UK North Sea. Production will start in different stages in the 2023-2025 period.

In February 2022 was expanded portfolio of renewable capacity in the United States through the acquisition from BayWa r.e. with a total capacity of 466 MW in Texas, of which about 266 MW referred to Corazon I Solar plant.

The plant began operations in August 2021, it will produce about 500 GWh each year, equivalent to eliminating about 250 ktonnes of CO2 emissions annually into the atmosphere. In the same location, acquired Guajillo storage project, in advanced stage of development, with a capacity of around 200 MW/400 MWh.

In 2021, signed a number of collaboration agreements to develop renewable plants with: Equinor (through Vårgrønn) for the development of an offshore wind project in the Utsira Nord, with Red Rock Power in order to make a joint bid to ScotWind proposition, and with Copenhagen Infrastructure Partners (CIP), as part of the competition for allocation of marine concessions for the offshore wind farm development in Polonia and for the subsequent participation in incentive mechanisms (contract-for-difference), which will be auctioned between 2025 and 2027.

SOLAR AND WIND POWER INSTALLED CAPACITY AS OF DECEMBER 31, 2021

ENERGY PRODUCTION FROM RENEWABLE SOURCES

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

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

Energy production from renewable sources amounted to 986 GWh (of which 398 GWh photovoltaic and 588 GWh wind) up by 646 GWh compared to 2020. 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. Follows breakdown of the installed capacity by Country and technology.

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

	(MW)	2021	2020	2019	2018
Renewables installed capacity at period end		1,137	335	174	40
of which: photovoltaic		48%	77%	76%	100%
wind		51%	20%	20%
installed storage capacity		1%	3%	4%
	(technology)	2021	2020	2019	2018
Italy	fotovoltaic	116	112	82	35
Outside Italy		436	160	58	5
Algeria(a)	fotovoltaic		5	5	5
Australia	fotovoltaic	64	64	39
France	fotovoltaic	108
Pakistan	fotovoltaic	10	10	10
Tunisia(a)	fotovoltaic		9	4
The United States	fotovoltaic	254	72
TOTAL PHOTOVOLTAIC INSTALLED CAPACITY		552	272	140	40
Italy	wind	350
Outside Italy		235	63	34
Kazakhstan	wind	91	48	34
Spain	wind	129
The United States	wind	15	15
TOTAL WIND INSTALLED CAPACITY		585	63	34
TOTAL INSTALLED CAPACITY AT PERIOD END (INCLUDING INSTALLED STORAGE POWER)		1,137	335	174	40
of which installed storage power		7	8	7

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

At the end of 2021, the total installed and sanctioned capacity amounted to 1,137 MW +802 MW from 2020 mainly relating to acquisition in Italy (+315 MW, onshore wind), Spain (+129 MW, onshore wind) e France (+108 MW, photovoltaic), carried out during the second half of 2021, as well as the acquisition in United States (+182 MW, photovoltaic), and the completion of three plants in Puglia (+35 MW, onshore wind).

ITALY

As of 31 December 2021, Eni owns 15 utility-scale plants in operation in Italy and the total installed capacity of 0.47 GW.

Eni's commitment in Italy started with the industrial reconversion project, mainly but not exclusively, aimed at the construction of photovoltaic systems in industrial areas owned by the Group, reclaimed and available for use.

In 2021, this commitment is demonstrated by the the acquisition from Glennmont Partners ("Glennmont") and PGGM Infrastructure Fund ("PGGM") of a portfolio of 13 onshore wind farms in Italy, (with a total capacity of 315 MW) as well as thorough the completion of onshore wind projects in Puglia for a total of 35 MW.

In collaboration with Eni Rewind, new areas are being assessed to be made available for post-remediation use with the aim of supporting growth in the medium/long-term.

In addition, Plenitude (51%) and Cdp Equity (49%), in February 2021 established the JV GreenIT in order to support the country's energy transition in line with the objectives of the 2030 National Integrated Energy and Climate Plan. The joint venture intends to develop and build greenfield plants by developing the real estate assets belonging to the CDP Group and the Public Administration.

OUTSIDE ITALY

Kazakhstan

Eni strengthened its presence in the Country with the construction of the second Badamsha wind farm (48 MW). The initiative allows Eni to reach, during the first months of 2022, a total capacity of 96 MW. Currently, a new photovoltaic plant in the region of Shauldir (50 MW) is under construction. The completion is expected in 2022.

Australia

Katherine's photovoltaic park (34 MW),completed in 2019, is the largest farm in the Australian Northern Territory and is integrated with a storage system with a capacity of 6 MW. Leveraging on these technologies, the plant will be able to forecast and compensate possible variations in solar irradiation by taking energy from a storage system, in order to minimize the impact on the grid. In the Northern Territory, Eni has installed solar capacity for a total of 25 MW at the Bachelor and Manton Dam sites.

United States

Within the partnership agreement with Falck (Eni 49%, Falck 51%), in 2020 Eni acquired 57 MW of photovoltaic asset already operating managed by Falck Renewables in the Country. The JV, has increased its capacity up to 120 MW at the end of 2021, through both the acquisition of operations asset (62 MW of wind and photovoltaic in lowa and Maryland, 30 MW net to Eni) and with the development of 30 MW solar project in Virginia (15 MW net to Eni) and a 37 MW project in the State of New York (18 MW net to Eni), completed in 2021. In 2021, Eni acquired a 99% share of the photovoltaic project Bluebell Solar (149 MW). In February 2022 was also acquired by BayWar.e. the Corazon I photovoltaic system (266 MW), in operation from August 2021, as well as, Eni acquired the Guajillo storage project of around 200 MW/400 MWh, which is in advanced stage of development.

Currently in the Country is under construction the solar plant of Brazoria County in Texas (260 MW), which is expected to be completed by the end of 2022.

United Kingdom

At the end of February 2021, Eni finalized the acquisition of a 20% share of the offshore wind project Dogger Bank (A and B) which includes the installation of 190 turbines situated approximately 80 miles from the British coast. Each turbine has a capacity of 13 MW for a total capacity of 2.4 GW (480 MW net to Eni). This acquisition allows Eni to enter in the Northern Europe offshore wind market, one of the most promising and stable, with two partners Equinor and SSE characterized by wide experience in this business.

As of March 2022, Eni has strengthened its presence in the Dogger Bank project by entering into an agreement with Equinor and SSE Renewables acquiring a 20% stake of the 1.2 GW Dogger Bank C project, the third phase of the offshore wind farm.

Spain and France

In October 2021, Eni finalized the acquisition from Azora Capital of a portfolio of 9 renewable energy projects in Spain. The transaction involved three wind farms in service (129 MW), a wind farm under construction (105 MW), and other solar projects in advanced stage of development for around 0.9 GW. In the same month was also finalized the acquisition of Dhamma Energy Group, owner of a pipeline of photovoltaic projects with a target installed capacity of about 3 GW, and installations already in operation (108 MW) or under construction.

3. E-MOBILITY

In a mobility market facing a constant increase in the number of electric vehicles in use in Italy and Europe, Plenitude, thanks to the acquisition of Be Power SpA and its subsidiary Be Charge Srl owns one of the largest and most widespread networks of public charging infrastructure for electric vehicles.

As of December 31, 2021, there are more than 6,200 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 is in charge of managing the charging infrastructure network (CPO - Charge Point Operator), as well as 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.

Among the main initiatives for the development of the e-mobility sector in Italy, Plenitude signed an agreement with Hyundai to expand the range of products for recharging electric cars and to encourage energy efficiency. Thanks to this agreement, Hyundai dealers will be able to offer their customers the purchase and the installation of the Plenitude E-start charging stations. Hyundai can also install charging stations and photovoltaic plants at their own dealerships, and adopt Plenitude's energy efficiency solutions.

A LEADING ELECTRIC MOBILITY OPERATOR IN ITALY

Furthermore, in December Be Charge signed a number of agreements that permit to activate grid interoperability, allowing access to the widest national charging network of about 20,000 charging points. This synergy is part of Eni's broader strategy for the mobility of the future, which includes the evolution of the current service stations, mobility points at which we plan, among other things, to offer fast and ultra-fast charging for electric mobility.

4. POWER

As part of the strategy aimed to enhance assets and free up new resources for the energy transition, on March 14, 2022, Eni signed an agreement with the investment company Sixth Street for the sale of the 49% share in EniPower which owns six gas power plants. This agreement, subject to certain conditions precedent and authorizations of the competent Authorities, is part of Eni's strategy to enhance its assets and generate resources for the energy transition. Eni will mantain 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, 2021, installed operational capacity of Enipower's power plants was 4.5 GW. In 2021, thermoelectric power generation was 22.36 TWh, increasing by 1.41 TWh from the previous year. Electricity trading (22.79 TWh) reported an increase of 33% from 2020, thanks to the optimization of inflows and outflows of power.

POWER GENERATION

		2021	2020	2019	2018
Purchases
Natural gas	(mmcm)	4,670	4,346	4,410	4,300
Other fuels	(ktep)	93	160	276	356
of which: steam cracking		68	88	91	94
Production
Power generation	(TWh)	22.36	20.95	21.66	21.62
Steam	(ktonnes)	7,362	7,591	7,646	7,919

Installed generation capacity	(GW)	4.5	4.5	4.5	4.5

In 2021, power sales in the open market were 28.54 TWh, representing an increase of 13% compared to 2020, due to higher volumes marketed at Power Exchange.

POWER SALES

	2021	2020	2019	2018
Power generation	22.36	20.95	21.66	21.62
Trading of electricity(a)	22.79	17.09	17.83	15.45
Availability	45.15	38.04	39.49	37.07
POWER SALES IN THE OPEN MARKET	28.54	25.33	28.28	28.54

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

ENIPOWER PLANTS AND SITES IN ITALY

	Installed capacity as of	Effective/planned
Power stations	December 31, 2021(a) (MW)	start-up	Technology	Fuel
Brindisi	1,268	2006	CCGT	Gas
Ferrera Erbognone	1,052	2004	CCGT	Gas/syngas
Mantova(b)	736	2005	CCGT	Gas
Ravenna	984	2004	CCGT	Gas
Ferrara(b)	400	2008	CCGT	Gas
Bolgiano	64	2012	Power Station	Gas
Photovoltaic sites(c)	0.2	2011-2014	Photovoltaic	Photovoltaic
	4,504

(a) Installed operational capacity.

(b) Eni's share of capacity.

CAPITAL EXPENDITURE

	2021	2020	2019	2018
- Plenitude	366	241	315	192
- Power	77	52	42	46
TOTAL CAPITAL EXPENDITURE	443	293	357	238

The combined cycle gas fired technology (CCGT) ensures an high level of efficiency and low environmental impact. In particular, management estimates that for a given amount of energy (electricity and steam) produced, using the CCGT technology instead of conventional power generation technology, the emission of carbon dioxide is reduced by about 5 mmtonnes, on an energy production of 24 TWh.

Environmental activities

The Group's environmental activities are developed by Eni Rewind, the Eni's company that operates in line with the principles of the circular economy to give new life to land, water and waste resources, industrial or deriving from reclamation activities, through sustainable reclamation and revaluation projects, both in Italy and abroad.

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

In its activities, Eni Rewind integrates the principles of environmental sustainability and applies the best technologies available, with the aim of maximizing effectiveness and efficiency.

THE ENI REWIND INTEGRATED MODEL

Reclamation activities

Coherently with the expertise gained and in agreement with the institutions and stakeholders, Eni Rewind identifies the projects for enhancement and reuse of reclaimed areas, allowing the environmental recovery of former industrial area and the resumption of the local economy. In this context, during 2021, were identified suitable areas for the installation of photovoltaic and wind plants.

In 2021, Eni Rewind, owner of the Ponticelle area in Ravenna,

a disused industrial area outside the petrochemical plant of Ravenna, obtained the certification for the activities of Permanent Safety Measures (MISP), with the realization of a capping. In addition, was started a redevelopment plan production that includes the application of innovative, sustainable and recovery technologies, as well as to the urbanization works of the area. In the area object of MISP is planned the construction of a photovoltaic plant and a biorecovery platform for the subsequent reuse of land and management of industrial waste. In particular, the latter will be managed by HEA SpA, a joint venture between Eni Rewind and Herambiente Servizi Industriali established in March 2021.

The most relevant advances made in 2021 were located in:

} Ravenna: certification for the completion of permanent safety measures, preparatory to the development of Ponticelle project;
} Porto Torres: construction and launch of the sand platform for treatment of contaminated soils in the Minciaredda area;
} Crotone: construction of a cliff of over 1,000 meters, to protect those areas on which we will start the excavations included in the reclamation project for the removal of the former seafront landfills;
} Cirò Marina: completion of the demolition works of the Punta Alice pier, utilized to load ships with salt produced in the Belvedere Spinello mines;
} Gela: demolition of the D1 torch and the SNOX chimney, both with a significant impact on the site's skyline (heights of about 150 meters);
} Cengio: the safety activities of the A1 area have been completed. This is the last area in the site whose reclamation had to be completed after the planned interventions carried out in recent years in areas A2, A3, A4. The reclamation project of the site, defined by the State Commissioner for Reclamation at the beginning of the 2000s, is completed.

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.

Currently 42 treatment plants are fully in operation and in Italy, with over 36 million cubic meters of treated water in 2021. Continued the activities of automation and digitalization of groundwater treatment plants and implementation of the remote control. The activity of recovery and reuse of treated water for the production of demineralized water is ongoing for industrial use, as part of the operational plans for the remediation of contaminated sites. In 2021 about 9 million cubic meters of water have been reused after treatment, with an increase of over 3 million cubic meters compared to 2020. During 2021, completed the installation of 44 devices using the proprietary technology E-Hyrec® for the selective removal of hydrocarbons from groundwater, allowing the improvement of the effectiveness and efficiency of groundwater reclamation, with significant reductions in extraction times and avoiding the disposal of more than 1,000 tons of waste equivalent.

In addition, are ongoing the activities related to the application of Blue Water technology, aimed at treatment and the recovery of production water deriving from crude oil extraction activities. It's underway the preliminary inquiry for obtaining authorizations from Local Authorities to carry out the first plant on an industrial scale in the Val d'Agri Oil Center in Viggiano, in the Region of Basilicata.

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 that, by adopting the best technological solutions available on the market, allows to minimize costs and environmental impacts.

During 2021, Eni Rewind managed a total of approximately 1.9 million tonnes1 of waste by sending for recovery or disposal at external plants.

In particular, the recovery index (ratio of recovered/recoverable waste) in 2021 was 73%: the slight decrease compared to 2020 (78%) is due to the qualitative and particle size characteristics of the reclamation waste, detected during characterization, which prevented and/or limited its recovery compared to the previous year, as well as a reduction in availability from external plants, in order to recovery, in specific regions of Italy.

Relating to waste management in line with the principles of the circular economy, the valorization of resources and synergy with the territory, continues the company's commitment to the development of the Eni's proprietary "Waste to Fuel" technology that treats the organic fraction of municipal waste to produce bio-oil and biomethane, as well as recovering the water that constitutes the main component of the so-called "wet", for new industrial and irrigation uses.

Certification

In 2021 Eni Rewind obtained SOA Certification, the mandatory certification for participation in tenders to execute public works contracts with a basic auction amount exceeding €150,000, 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.

Non captive initiatives

Starting from 2020, Eni Rewind has expanded the scope of its activities outside the Group. In 2021, continued the activities related to the finalization of contracts with Edison, for the reclamation of the Mantova site, for waste management in Altomonte (Cosenza) and with Acciaierie d'Italia, for the design of reclamation interventions of the former Ilva area in Taranto. In addition completed the qualification processes as a supplier for important national and international operators (Arcadis, MOL Group, Edison, Tamoil, TOTAL, Q8, ADNOC).

Started the participation in several tenders with leading national operators, awarding the contract with ANAS, for survey and characterization services in the Adriatic area (Emilia Romagna, Marche, Abruzzo, Molise, Puglia), where Eni Rewind will provide chemical analysis service, through its environmental laboratories. Signed collaboration agreements with main Italian companies that manage collection and processing of urban waste and with key players in the supply chain (CONAI). These agreements are aimed at assessing the opportunity of setting up new waste treatment and recovery plants on reclaimed land or will become available following the progressive conversion of Eni's refining and chemical sites.

Eni Rewind outside Italy

Eni Rewind, starting from 2018, has made its expertise available to Eni's subsidiaries located in foreign countries for environmental issues, in particular for management and enhancement activities of the water resource, soil, as well as training and knowledge sharing.

In January 2021, Eni Rewind signed a Memorandum of Understanding (MoU) with the National Authority for oil and gas of the Kingdom of Bahrain (NOGA) with the target to identify and promote joint initiatives for the management, recovery and reuse of water and soil resources and waste in the country. In October, an assessment was carried out at the petrochemical plants and refining of the Kingdom of Bahrain which has identified three possible areas of activity for Eni Rewind related to groundwater modeling, waste management and field testing of the proprietary E-Hyrec® technology.

Eni Rewind obtained the qualification as a supplier to Abu Dhabi Oil Company (ADNOC) for the activities of demolition and reclamation.

Completed the feasibility studies on the optimization of waste water management and process water through its reuse for plants located in Algeria and Libya and extended the design services to foreign subsidiaries for environmental activities and decommissioning of the operative and disposed points sales.

KEY PERFORMANCE INDICATORS

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

Tables

FINANCIAL DATA

PROFIT AND LOSS ACOOUNT

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

SALES FROM OPERATIONS

	2021	2020	2019	2018
Exploration & Production	21,742	13,590	23,572	25,744
Global Gas & LNG Portfolio	20,843	7,051	11,779	14,807
Refining & Marketing and Chemicals	40,374	25,340	42,360	46,483
Plenitude & Power	11,187	7,536	8,448	8,218
Corporate and other activities	1,698	1,559	1,676	1,588
Impact of unrealized intragroup profit elimination and consolidation adjustments	(19,269)	(11,089)	(17,954)	(21,018)
	76,575	43,987	69,881	75,822

SALES TO CUSTOMERS

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

SALES BY GEOGRAPHIC AREA OF DESTINATION

	2021	2020	2019	2018
Italy	29,968	14,717	23,312	25,279
Other EU Countries	14,671	9,508	18,567	20,408
Rest of Europe	12,470	8,191	6,931	7,052
Americas	4,420	2,426	3,842	5,051
Asia	7,891	4,182	8,102	9,585
Africa	7,040	4,842	8,998	8,246
Other areas	115	121	129	201
Total outside Italy	46,607	29,270	46,569	50,543
	76,575	43,987	69,881	75,822

SALES BY GEOGRAPHIC AREA OF ORIGIN

	2021	2020	2019	2018
Italy	52,815	29,116	46,763	51,733
Other EU Countries	9,022	5,508	7,029	8,004
Rest of Europe	1,946	1,226	1,909	2,496
Americas	3,577	1,838	3,290	3,627
Africa	1,170	846	1,068	1,165
Asia	7,777	5,271	9,587	8,599
Other areas	268	182	235	198
Total outside Italy	23,760	14,871	23,118	24,089
	76,575	43,987	69,881	75,822

PURCHASES, SERVICES AND OTHER

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

PRINCIPAL ACCOUNTANT FEES AND SERVICES

	2021	2020	2019	2018
Audit fees	18,858	19,605	15,748	25,445
Audit-related fees	4,511	1,412	1,045	1,628
	23,369	21,017	16,793	27,073

PAYROLL AND RELATED COSTS

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

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

	2021	2020	2019	2018
Exploration & Production	5,976	6,273	7,060	6,152
Global Gas & LNG Portfolio	174	125	124	226
Refining & Marketing and Chemicals	512	575	620	399
Plenitude & Power	286	217	190	182
Corporate and other activities	148	146	144	59
Impact of unrealized intragroup profit elimination	(33)	(32)	(32)	(30)
Total depreciation, depletion and amortization	7,063	7,304	8,106	6,988
Exploration & Production	(1,244)	1,888	1,217	726
Global Gas & LNG Portfolio	26	2	(5)	(73)
Refining & Marketing and Chemicals	1,342	1,271	922	193
Plenitude & Power	20	1	42	2
Corporate and other activities	23	21	12	18
Impairment losses (impairment reversals) of tangible and intangible and right of use assets, net	167	3,183	2,188	866
Depreciation, depletion, amortization, impairments and reversals, net	7,230	10,487	10,294	7,854
Write-off of tangible and intangible assets	387	329	300	100
	7,617	10,816	10,594	7,954

OPERATING PROFIT BY SEGMENT

(€ million)	2021	2020	2019	2018
Exploration & Production	10,066	(610)	7,417	10,214
Global Gas & LNG Portfolio	899	(332)	431	387
Refining & Marketing and Chemicals	45	(2,463)	(682)	(501)
Plenitude & Power	2,355	660	74	340
Corporate and other activities	(816)	(563)	(688)	(668)
Impact of unrealized intragroup profit elimination	(208)	33	(120)	211
	12,341	(3,275)	6,432	9,983

FINANCE INCOME (EXPENSE)

2021	2020	2019	2018
(849)	(913)	(962)	(627)
(475)	(517)	(618)	(565)
11	31	127	32
(94)	(102)	(122)	(120)
(304)	(347)	(378)
4	10	21	18
9	12	8	8
(306)	351	(14)	(307)
(322)	391	9	(329)
16	(40)	(23)	22
476	(460)	250	341
(177)	(96)	(246)	(430)
67	97	112	132
(144)	(190)	(255)	(249)
(100)	(3)	(103)	(313)
(856)	(1,118)	(972)	(1,023)
68	73	93	52
(788)	(1,045)	(879)	(971)

INCOME (EXPENSE ON) FROM INVESTMENTS

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

SUMMARIZED GROUP BALANCE SHEET

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

PROPERTY, PLANT AND EQUIPMENT BY SEGMENT

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

CAPITAL EXPENDITURE BY SEGMENT

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

CAPITAL EXPENDITURE BY GEOGRAPHIC AREA OF ORIGIN

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

NET BORROWINGS

(€ million)	Debt and bonds	Cash and cash equivalents	Securities held for trading	Financing receivables hel for non operating purposes	Leasing Liabilities	Total
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

SUMMARIZED GROUP CASH FLOW STATEMENT

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

CHANGES IN NET BORROWINGS

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

Non-GAAP measures (Alternative performance measures)

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

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

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

Non-GAAP financial measures should be read together with information determined by applying IFRS and do not stand in for them. Other companies may adopt different methodologies to determine Non-GAAP measures. Follows the description of the main alternative performance measures adopted by Eni. The measures reported below refer to the performance of the reporting periods disclosed in this press report.

Adjusted operating and net profit

Adjusted operating profit and adjusted net profit are determined by excluding inventory holding gains or losses, special items and, in determining the business segments' adjusted results, finance charges on finance debt and interest income. The adjusted operating profit of each business segment reports gains and losses on derivative financial instruments entered into to manage exposure to movements in foreign currency exchange rates, which impact industrial margins and translation of commercial payables and receivables. Accordingly, also currency translation effects recorded through profit and loss are reported within business segments' adjusted operating profit. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents not related to operations. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production segment).

Inventory holding gain or loss

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

Special items

These include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones. Exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturally-occurring opposite positions and then dealing with any residual risk exposure in the derivative market. Finally, special items include the accounting effects of fair-valued commodity derivatives relating to commercial exposures, in addition to those which lack the criteria to be designed as hedges, also those which are not eligible for the own use exemption, including the ineffective portion of cash flow hedges, as well as the accounting effects of commodity and exchange rates derivatives whenever it is deemed that the underlying transaction is expected to occur in future reporting periods. As provided for in Decision No. 15519 of July 27, 2006 of the Italian market regulator (CONSOB), nonrecurring 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.

Net cash provided by operating activities before changes in working capital at replacement cost

Net cash provided from operating activities before changes in working capital and excluding inventory holding gain or loss.

Free cash flow

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

Net borrowings

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

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.

EBITDA

Earnings Before Interest, Taxes, Depreciation and Amortization, equal to operating profit plus amortization, depreciation and impairments.

Net Debt/EBITDA adjusted

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

Profit per boe

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

Opex per boe

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

Finding & Development cost per boe

Represents Finding & Development cost per boe of new proved or possible reserves. It is calculated as the overall amount of exploration and development expenditure, the consideration for the acquisition of possible and probable reserves as well as additions of proved reserves deriving from improved recovery, extensions, discoveries and revisions of previous estimates (as defined by FASB Extractive Activities - Oil and Gas Topic 932).

The following tables report the group operating profit and Group adjusted net profit and their breakdown by segment, as well as is represented the reconciliation with net profit attributable to Eni's shareholders of continuing operations.

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
of which attributable to:
- non-controlling interest							19
- Eni's shareholders							4,330
Reported net profit (loss) attributable to Eni's shareholders							5,821
Exclusion of inventory holding (gains) losses							(1,060)
Exclusion of special items							(431)
Adjusted net profit (loss) attributable to Eni's shareholders							4,330

2020 (€ 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)
of which attributable to:
- non-controlling interest							7
- Eni's shareholders							(758)
Reported net profit (loss) attributable to Eni's shareholders							(8,635)
Exclusion of inventory holding (gains) losses							937
Exclusion of special items							6,940
Adjusted net profit (loss) attributable to Eni's shareholders							(758)

2019 (€ million)	Exploration & Production	Global Gas & LNG Portfolio	Refining & Marketing and Chemicals	& Power Plenitude	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
of which attributable to:
- non-controlling interest							7
- Eni's shareholders							2,876
Reported net profit (loss) attributable to Eni's shareholders							148
Exclusion of inventory holding (gains) losses							(157)
Exclusion of special items							2,885
Adjusted net profit (loss) attributable to Eni's shareholders							2,876

2018 (€ million)	Exploration & Production	Global Gas & LNG Portfolio	Refining & Marketing and Chemicals	& Power Plenitude	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
of which attributable to:
- non-controlling interest							11
- Eni's shareholders							4,583
Reported net profit (loss) attributable to Eni's shareholders							4,126
Exclusion of inventory holding (gains) losses							69
Exclusion of special items							388
Adjusted net profit (loss) attributable to Eni's shareholders							4,583

BREAKDOWN OF SPECIAL ITEMS

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

ADJUSTED OPERATING PROFIT BY SEGMENT

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

ADJUSTED NET PROFIT BY SEGMENT

	2021	2020	2019	2018
Exploration & Production	5,543	124	3,436	4,955
Global Gas & LNG Portfolio	169	211	100	118
Refining & Marketing and Chemicals	62	(246)	(42)	224
Plenitude & Power	327	329	275	189
Corporate and other activities	(1,576)	(1,205)	(866)	(948)
Impact of unrealized intragroup profit elimination and other consolidation adjustments(a)	(176)	36	(20)	56
	4,349	(751)	2,883	4,594
of which attributable to:
Eni's shareholders	4,330	(758)	2,876	4,583
Non-controlling interest	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.

EMPLOYEES

EMPLOYEES AT YEAR END

	(units)	2021	2020	2019	2018
Exploration & Production	Italy	3,364	3,692	3,491	3,477
	Outside Italy	6,045	6,123	6,781	6,971
		9,409	9,815	10,272	10,448
Global Gas & LNG Portfolio	Italy	276	290	293	318
	Outside Italy	571	410	418	416
		847	700	711	734
Refining & Marketing and Chemicals	Italy	9,028	8,915	9,035	8,863
	Outside Italy	4,044	2,556	2,591	2,594
		13,072	11,471	11,626	11,457
Plenitude & Power	Italy	1,864	1,679	1,698	1,719
	Outside Italy	600	413	358	337
		2,464	2,092	2,056	2,056
Corporate and other activities	Italy	6,503	6,999	6,971	6,625
	Outside Italy	394	418	417	381
		6,897	7,417	7,388	7,006
Total employees at year end	Italy	21,035	21,575	21,488	21,002
	Outside Italy	11,654	9,920	10,565	10,699
		32,689	31,495	32,053	31,701

BREAKDOWN BY POSITION

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

QUARTERLY INFORMATION

MAIN FINANCIAL DATA(a)

(€ million)			2021
	I quarter	II quarter	III quarter	IV quarter		I quarter	II quarter	III quarter	IV quarter
Net sales from operations	14,494	16,294	19,021	26,766	76,575	13,873	8,157	10,326	11,631	43,987
Operating profit (loss)	1,862	1,995	2,793	5,691	12,341	(1,095)	(2,680)	220	280	(3,275)
Adjusted operating profit (loss)	1,321	2,045	2,492	3,806	9,664	1,307	(434)	537	488	1,898
Exploration & Production	1,378	1,841	2,444	3,630	9,293	1,037	(807)	515	802	1,547
Global Gas & LNG Portfolio	(30)	24	50	536	580	233	130	64	(101)	326
Refining & Marketing and Chemicals	(120)	190	186	(104)	152	16	73	21	(104)	6
Plenitude & Power	202	108	64	102	476	191	85	57	132	465
Corporate and other activities	(146)	(111)	(109)	(227)	(593)	(204)	(135)	(84)	(84)	(507)
Unrealized profit intragroup elimination and consolidation adjustments	37	(7)	(143)	(131)	(244)	34	220	(36)	(157)	61
Net (loss) profit(b)	856	247	1,203	3,515	5,821	(2,929)	(4,406)	(503)	(797)	(8,635)
Capital expenditure(c)	1,139	1,268	1,232	1,674	5,313	1,590	978	889	1,187	4,644
Investments	520	351	553	1,314	2,738	222	42	95	33	392
Net borrowings at period end	17,507	15,323	16,622	14,324	14,324	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

	2021					2020
	I quarter	II quarter	III quarter	IV quarter		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	50.26	29.20	43.00	44.23	41.67
Average EUR/USD exchange rate(b)	1.205	1.206	1.179	1.144	1.183	1.103	1.101	1.169	1.193	1.142
Average price in euro of Brent dated crude oil	50.54	57.07	62.33	69.73	59.80	45.56	26.51	36.78	37.08	36.49
Standard Eni Refining Margin (SERM)(c)	(0.6)	(0.4)	(0.4)	(2.2)	(0.9)	3.6	2.3	0.7	0.2	1.7

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

(b) Source: ECB.

(c) In USD per barrel. Source: Eni calculations. It gauges the profitability of Eni's refineries against the typical raw material slate and yields.

MAIN OPERATING DATA

		2021						2020
		I quarter	II quarter	III quarter	IV quarter		I quarter	II quarter	III quarter	IV quarter
Liquids production	(kbbl/d)	814	779	805	852	813	892	853	817	809	843
Natural gas production	(mmcf/d)	4,726	4,339	4,688	4,700	4,613	4,768	4,653	4,694	4,800	4,729
Hydrocarbons production	(kboe/d)	1,704	1,597	1,688	1,737	1,682	1,790	1,729	1,701	1,713	1,733
Italy		99	65	82	87	83	112	106	105	103	107
Rest of Europe		238	172	213	228	213	256	243	224	228	237
North Africa		272	247	266	264	262	252	258	253	264	257
Egypt		355	371	364	348	360	303	266	290	304	291
Sub-Saharian Africa		310	293	316	321	310	372	386	369	347	368
Kazakhstan		153	147	119	165	146	174	167	144	168	163
Rest of Asia		148	169	201	190	177	193	173	172	167	176
America		112	116	111	119	115	110	114	127	114	117
Australia and Oceania		17	17	16	15	16	18	16	17	18	17
Hydrocarbons production sold	(mmboe)	139.9	136.7	140.7	149.4	566.7	144.7	143.8	142.6	144.1	575.2
Sales of natural gas to third parties	(bcm)	15.51	15.48	15.49	17.14	63.62	14.37	11.95	13.96	16.17	56.45
Own consumption of natural gas		1.52	1.46	1.65	1.74	6.37	1.53	1.44	1.58	1.58	6.13
Sales to third parties and own concumption		17.03	16.94	17.14	18.88	69.99	15.90	13.39	15.54	17.75	62.58
Sales of natural gas of Eni's affiliates (net to Eni)		0.45	0.01	0.00	0.00	0.46	0.69	0.46	0.44	0.82	2.41
Total sales and own consumption of natural gas - GGP		17.48	16.95	17.14	18.88	70.45	16.59	13.85	15.98	18.57	64.99
Retail and business gas sales		3.52	1.08	0.63	2.62	7.85	3.63	0.88	0.66	2.51	7.68
Retail and business power sales to end customers	(TWh)	3.66	3.89	4.22	4.72	16.49	3.28	2.74	3.07	3.40	12.49
Power sales in the open market		6.42	6.55	7.82	7.75	28.54	6.50	5.60	6.65	6.58	25.33
Sales of refined products	(mmtonnes)	6.56	6.55	7.53	7.33	27.97	6.64	5.85	7.42	6.18	26.09
Retail sales in Italy		1.04	1.27	1.45	1.36	5.12	1.12	0.89	1.41	1.14	4.56
Wholesale sales in Italy		1.29	1.46	1.70	1.57	6.02	1.51	1.16	1.58	1.50	5.75
Retail sales Rest of Europe		0.43	0.52	0.62	0.54	2.11	0.52	0.43	0.61	0.49	2.05
Wholesale sales Rest of Europe		0.54	0.43	0.59	0.63	2.19	0.57	0.59	0.63	0.61	2.40
Wholesale sales outside Europe		0.12	0.13	0.13	0.14	0.52	0.12	0.11	0.12	0.13	0.48
Other markets		3.14	2.74	3.04	3.09	12.01	2.80	2.67	3.07	2.30	10.85

ENERGY CONVERSION TABLE

OIL

					(average reference density 32.35 f API, relative density 0.8636)
1 barrel	(bbl)	158.987		l oil(a) 0.159 m3 petrolio	162.602	m3 gas		5,310	ft3 gas
					5,800,000	btu
1 barile/d	(bbl/d)	~50	t/y
1 cubic meter	(m3 )	1,000	l oil	6.65 bbl	1,033	m3 gas		36,481	ft3 gas
1 tonne oil equivalent	(toe)	1,160.49		l oil 7.299 bbl	1.161	m3 petrolio	1,187 m3 gas	41,911	ft3 gas

GAS

1 cubic meter	(m3 )	0.976		l oil 0.00665 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	m3 oil	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 foot (ft3 )	barrel (bbl)	liter (lt)	cubic meter (m3 )
ft3	1	0	28.32	0.02832
bbl	5.310	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, 2021: € 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 [email protected]

Investor Relations

Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: [email protected]

Layout and supervision K-Change - Roma

Printing Tipografia Facciotti – Roma

Eni Fact Book

2021

AI Terminal

Eni

4348_rns_2022-05-11_83878a6d-42ee-46c4-a1d2-deda51a6d661.pdf

Eni Fact Book 202 1

Eni Fact Book 2021

Disclaimer

Eni at a glance

THE ACCELERATION OF OUR TRANSFROMATION

Portfolio enhancement

Business transformation

EXCELLENT OPERATIONAL AND FINANCIAL RESULTS

Main data

KEY FINANCIAL DATA

KEY MARKET INDICATORS

SELECTED OPERATING DATA(a)

ENI SHARE PERFORMANCE

SHARE DATA

SHARE INFORMATION

DATA ON ENI SHARE PLACEMENT

Natural Resources

ACTIVITY AREAS

ITALY

Adriatic and Ionian Seas

Central Southern Apennines

Sicily

REST OF EUROPE

NORWAY

UNITED KINGDOM

NORTH AFRICA

ALGERIA

Blocks 403a/d and ROM North

Blocks 401a/402a

Block 403

Block 405b

Block 404

Block 208

Blocks Sif Fatima II, Ourhoud II and Zemlet El Arbi

LIBYA

TUNISIA

EGYPT

Block Shorouk

Sinai

North Port Said

Baltim

Nile Delta

Ras el Barr

El Temsah

Western Desert

The LNG business in Egypt

SUB-SAHARAN AFRICA

ANGOLA

Block 15/06

Block 0

Block 3 and 3/05-A

Blocks 14 and 14K/A IMI

Block 15

The LNG business in Angola

CONGO

GHANA

MOZAMBIQUE

NIGERIA

Blocks OMLs 60, 61, 62 and 63

Block OML 118

Block OML 125

SPDC Joint Venture (NASE)

The LNG business in Nigeria

KAZAKHSTAN

KASHAGAN

KARACHAGANAK

REST OF ASIA

INDONESIA

IRAQ

PAKISTAN

TIMOR LESTE

TURKMENISTAN

UNITED ARAB EMIRATES

AMERICAS

MEXICO

UNITED STATES

Gulf of Mexico