Eni

Annual Report • May 12, 2021

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Eni Fact Book 2020

ENI AT A GLANCE	2
Main data	4
Eni share performance	7
EXPLORATION & PRODUCTION	9
GLOBAL GAS & LNG PORTFOLIO	47
REFINING & MARKETING AND CHEMICALS	54
Refining & Marketing	55
Chemicals	65
ENI GAS E LUCE, POWER & RENEWABLES	69
Eni gas e luce	69
Power	71
Renewables	72
TABLES	75
Financial data	75
Employees	87
Quarterly information	88

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 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

Average Brent dated price (\$/BBL)	PSV SERM (€/kcm) (\$/BBL)			Average exchange rate EUR/USD
I quarter 2020	50.26	I quarter 2020	121	I quarter 2020		3.6	I quarter 2020	1.103
II quarter 2020	29.20	II quarter 2020	75	II quarter 2020		2.3	II quarter 2020	1.101
III quarter 2020	43.00	III quarter 2020	95	III quarter 2020		0.7	III quarter 2020	1.169
IV quarter 2020	44.23	IV quarter 2020	156	IV quarter 2020		0.2	IV quarter 2020	1.193

The average price of the Brent benchmark crude oil decreased by 35% compared to the previous year, with an annual average of approximately 42 \$/barrel; the price of natural gas at the Italian spot market "PSV" declined on average by 35% and the Standard Eni Refining Margin SERM recorded the worst performance (down by 60%).

The trading environment in 2020 saw the largest drop in oil demand in history (down by 9% y-o-y) driven by the lockdown measures implemented globally to contain the spread of the COVID-19 pandemic, Eni has promptly defined actions, leveraging on the energy, resources and flexibility of the operations.

Management took decisive actions according to three priorities: health and safety of our people and asset integrity, robustness of balance sheet, organizational structure. In particular, were implemented initiatives to safeguard each of the 60 thousand people that work in Eni and with Eni, in all the workplaces and operational sites, and to ensure continuity, without operational interruptions and asset integrity. During the peak of the downturn, clear priorities in the cash allocation were defined in order to strengthen financial resilience and capital resilience of the company.

The Company's strategy and plans for the short-to-medium term were revised, leveraging on a reduction of €8 billion in the outlays for expenses and capital expenditures in the twoyear period 2020-2021, more exposed to the downturn, with the subsequent reshaping of the growth profile of production. In addition, established a new dividend policy based on a fixed component and a variable component linked to the scenario.

Thanks to these actions, the adjusted cash flow of €6.7 billion was able to finance 100% of net organic capex lowered to €5 billion (down by 35% vs. the original budget at constant exchange rates) due to the implemented optimizations, with a surplus of €1.7 billion. Opex were reduced by €1.9 billion compared to the pre-COVID-19 level, of which about 30% is structural. As of December 31, 2020, leverage was confirmed at 0.3 and net borrowings were in line with the comparative period, also

due to the issuance of two hybrid bonds for €3 billion.

2020: FAST REACTION TO COVID-19 CRISIS PEOPLE HEALTH AND BUSINESS CONTINUITY COSTS PORTFOLIO FINANCIALS >35% capex reduction vs. original 2020 guidance FID rescheduling on large upstream projects Leverage* in the comfort zone at about 0.3 -€1,9 bln cost savings vs. pre‐COVID-19 level Increased capex on green project First issuance of hybrid bonds of €3 bln NEW COMPANY ORGANIZATION LONG-TERM DECARBONIZATION PLAN

(*) Before IFRS 16.

In June 2020, the Board redefined the organizational structure of the Company with the establishment of two Business Groups: Natural Resources, which will maximize the value of Eni's Oil & Gas upstream portfolio from a sustainable perspective and develop energy

2020 RESULTS BY BUSINESS GROUPS

NATURAL RESOURCES

Production: 1,733 kboe/d Discovered resources: 400 mmboe Gas & LNG: EBIT €330 mln (+70%) Forestry REDD+: offset 1.5 mmton CO2 eq.; CCUS UK license awarded

ENERGY EVOLUTION

Renewables: 1 GW capacity installed and sanctioned Entered world's largest offshore wind project in UK Retail G&P: EBIT €330 mln (+17%) Biorefining & Marketing: EBIT €550 mln (+27%)

The upstream business is strengthening its recovery, despite the capex reduction of approximately 50% from 2019. Added 400 mmboe of new resources at a competitive cost of 1.6 \$/barrel, while E&P development helped to ensure a solid production level of 1.73 mmboe/day. The Global Gas & LNG Portfolio business reported an adjusted operating profit of €0.33 billion, higher than expected, notwithstanding the significant decline in European gas demand and the collapse in Asian LNG consumption during the peak of the crisis.

Within the REDD+ and CCS projects, in October, Eni was awarded by the UK Oil and Gas Authority a license for building a carbon storage project in the United Kingdom, while in November 2020, was achieved the first allowance of carbon credits by the REDD+ Luangwa Community Forest Project (LCFP) in Zambia to offset GHG emissions equivalent to 1.5 million tonnes of CO2 .

The businesses in the production and sale of decarbonized products achieved excellent results, driven by a 17% increase in the adjusted operating profit from Eni gas e luce, and thanks to biorefining + marketing adjusted operating profit of €550 million. The solar and wind capacity already installed or under construction amounted to 1 GW. Eni has laid foundations for strong growth in renewables by entering two strategic markets such as the U.S. and the Dogger Bank project in the UK's North Sea offshore wind market, which will be the largest in the world in the sector.

efficiency activities, projects for CO2 capture and forestry conservation (REDD+), and the Energy Evolution, which will focus on growing the businesses of power generation, transformation and marketing of products from fossil to

bio, blue and green.

Decarbonization path towards carbon neutrality

Eni started a new phase in the evolution of its business model, strongly oriented towards the creation of long-term value, combining economic/financial and environmental sustainability. To this purpose, Eni will pursue a strategy that aims to achieve by 2050 the net zero target on GHG Lifecycle Scope 1, 2 and 3 emissions and the associated emission intensity (Net Carbon Intensity), referred to the entire life cycle of the energy products sold, strengthening the intermediate decarbonization targets.

This path, achieved through existing technologies, will allow Eni to totally reduce its carbon footprint, both in terms of net emissions and in terms of net carbon intensity.

ENI NET ZERO EMISSIONS BY 2050

LEVERS

Carbon free products and services Increased share of gas on total production Biomethane for domestic use and mobility Biorefineries and circular economy Blue and green hydrogen CCS and REDD+ projects

Main data

KEY FINANCIAL DATA

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

(a) Non-GAAP measures.

(b) Attributable to Eni's shareholders.

KEY MARKET INDICATORS

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

		2020	2019	2018
Employees at year end	(number)	31,495	32,053	31,701
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.36	0.34	0.35
of which: employees		0.37	0.21	0.37
contractors		0.35	0.39	0.34
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	37.8	41.2	43.4
Indirect GHG emissions (Scope 2)		0.73	0.69	0.67
Indirect GHG emissions (Scope 3) other than those due to purchases from other companies(b)		185	204	203
Net GHG Lifecycle Emissions(b)		439	501	505
Net Carbon Intensity(b)	(gCO2 eq./MJ)	68	68	68
Carbon efficiency index Group	(tonnes CO2 eq./kboe)	31.6	31.4	33.9
Total volume of oil spills (> 1 barrel)	(barrels)	6,789	7,265	6,687
of which: due to sabotage and terrorism		5,831	6,232	4,022
operational		958	1,033	2,665
Freshwater withdrawals	(mmcm)	113	128	117
Reinjected production water	(%)	53	58	60
R&D expenditure	(€ million)	157	194	197
First patent filing application	(number)	25	34	43

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

Global Gas & LNG Portfolio		2020	2019	2018
Employees at year end	(number)	700	711	734
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	1.15	0.56	0.51
Natural gas sales	(bcm)	64.99	72.85	76.60
of which: Italy		37.30	37.98	39.17
outside Italy		27.69	34.87	37.43
LNG sales		9.5	10.1	10.3

Refining & Marketing and Chemicals		2020	2019	2018
Employees at year end	(number)	11,471	11,626	11,457
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.80	0.27	0.56
Capacity of biorefineries	(mmtonnes/year)	1.1	1.1	0.4
Production of biofuels	(ktonnes)	622	256	219
Retail market share in Italy	(%)	23.3	23.6	24.0
Retail sales of petroleum products in Europe	(mmtonnes)	6.61	8.25	8.39
Service stations in Europe at year end	(number)	5,369	5,411	5,448
Average throughput of service stations in Europe	(kliters)	1,390	1,766	1,776
Balanced capacity of refineries (Eni's share)	(kbbl/d)	548	548	548
Total volume of oil spills due to operations (> 1 barrel)	(barrels)	75	48	1,069
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	6.65	7.97	8.19
SOx emissions (sulphur oxide)	(ktonnes SO2 eq.)	2.78	4.16	4.80
GHG emissions/Refinery throughputs (raw and semi-finished materials)	(tonnes CO2 eq./kt)	248	248	253
Production of petrochemical products	(ktonnes)	8,073	8,068	9,483
Sales of petrochemical products		4,339	4,295	4,946
Average chemical plant utilization rate	(%)	65	67	76

Eni gas e luce, Power & Renewables		2020	2019	2018
Employees at year end	(number)	2,092	2,056	2,056
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.32	0.62	0.60
Retail gas sales	(bcm)	7.68	8.62	9.13
Retail power sales to end customers	(TWh)	12.49	10.92	8.39
Thermoelectric production		20.95	21.66	21.62
Electricity sold to hub		25.33	28.28	28.54
Renewables installed capacity at period end	(MW)	307	174	40
Electricity sold to hub	(GWh)	339.6	60.6	11.6

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

(b) KPIs are calculated on an equity basis.

(c) Related to consolidated subsidiaries.

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

(f) Hydrocarbon gross production from fields fully operated by Eni (Eni's interest 100%) amounting to 1,009 mmboe, 1,114 mmboe and 1,067 mmboe in 2020, 2019 and 2018, respectively.

ENI SHARE PERFORMANCE

SHARE DATA

	2020	2019	2018
Net profit (loss)(a)(b) (€)	(2.42)	0.04	1.15
Dividend pertaining to the year	0.36	0.86	0.83
Dividend to Eni's shareholders pertaining to the year(c) (€ million)	1,290	3,078	2,989
Cash dividend to Eni's shareholders	1,965	3,018	2,954
Cash flow (€)	1.35	3.45	3.79
Dividend yield(d) (%)	4.2	6.3	5.9
Net profit (loss) per ADR(b)(e) (\$)	(5.53)	0.09	2.72
Dividend per ADR(e)	0.82	1.93	1.96
Cash flow per ADR(e) (%)	3.08	7.72	8.95
Dividend yield per ADR(d)(e)	4.2	6.3	5.9
Number of shares at period-end (million)	3,572.5	3,572.5	3,601.1
Weighted average number of shares outstanding(f)	3,572.5	3,592.2	3,601.1
Total Shareholders Return (TSR) (%)	(34.1)	6.7	4.8

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

(b) Pertaining to Eni's shareholders.

(c) The amount of dividend for the year 2020 is based on the Board's proposal.

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

(e) One ADR represents 2 shares. Net profit, dividends and cash flow data were converted using average exchange rates. Dividends data were converted at the Noon Buying Rate of the pay-out date.

(f) Calculated by excluding own shares in portfolio.

SHARE INFORMATION

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

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

(b) Excluding treasury shares.

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

DATA ON ENI SHARE PLACEMENT

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

(a) Refers to share capital at December 31, 2020.

‐30%

TechnipFMC

Transocean (S) ‐20%

‐10%

TSR S&P 500 index

0%

10%

20%

+18.0%

Exploration & Production

SELECTED OPERATING DATA

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

(b) Related to consolidated subsidiaries.

(c) Three-year average.

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

(e) Calculated on 100% operated assets.

(f) Hydrocarbon gross production from fields fully operated by Eni (Eni's interest 100%) amounting to 1,009 mmboe, 1,114 mmboe and 1,067 mmboe in 2020, 2019 and

2018, respectively.

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

In a year like no other in the history of the energy industry, the Exploration & Production business confirmed the resilience of its activities thanks to the the asset portfolio characterized by low break even and the flexibility of our development projects.

The new organizational setup implemented by Eni in order to overcome the extraordinary crisis context and in line with the decarbonization strategy, provides that the E&P business will incorporate the exploration, development and production of oil and gas also with forestry conservation (REDD+) and CO2 capture and storage projects.

The exploration is still a distinctive competence of Eni. In these years, exploration activity granted both the replacement of produced reserves with a competitive discovery cost per boe which is the first step to reduce the break even of upstream projects, and a robust contribution to the cash generation through the deployment of the Dual Exploration Model. This strategy foresees the fast monetization of the discovered resources through the dilution of working interest in certain mineral interests, while retaining operatorship, otherwise an asset swap. Despite the capex reduction of approximately 50% from 2019, exploration activity achieved excellent results in 2020 with 400 mmboe of new resources at a competitive cost of 1.6 \$/barrel.

In carrying out exploration activities, Eni has expertly combined initiatives in high-risk/high-reward plays, with near-field exploration, which targets the discovery of additional mineral potential in mature, proven areas, close to existing producing platforms, FPSO units and other infrastructures in order to ensure fast support to production and cash flows.

The reduction of reserves' time-to-market is the other great driver for the upstream value creation which together with efficient exploration helps to ensure a resilient asset portfolio to the scenario. Our success leverages on an original development model based on the parallelization of phases (appraisal, pre-development, engineering), a modular approach that provides for accelerated start-up in early production and subsequent ramp-up, minimization of financial exposure and insourcing of critical project phases (detailed engineering, production supervision, commissioning/hook-up) in order to apply our skills and know-how.

Our production platform is still solid. Overall, discounting the reduction in capital expenditure of around €2 billion, E&P development helped to ensure a solid production level of 1.73 mmboe/day with the crisis cutting about 200 kboe, net of which we would have exceeded our initial expectations.

Within the Eni's strategy to valorize the upstream portfolio in a sustainable way, the projects in the start-up phase for the CO2 geological capture and sequestration using depleted fields as well as reusing in other production cycle are the main decarbonization drivers. Furthermore, launched initiatives focusing on the forest's protection, conservation and sustainable management, mainly in developing Countries, by means of the REDD+ projects.

In particular, in November 2020, was achieved the first allowance of carbon credits by the REDD+ Luangwa Community Forest Project (LCFP) in Zambia to offset GHG emissions equivalent to 1.5 million tonnes of CO2 . Eni continues to evaluate further initiatives in different Countries by means of partnerships with governments and international players in Africa, Latin America and Asia.

ACTIVITY AREAS

ITALY

Eni has been operating in Italy since 1926. In 2020, Eni's oil and gas production amounted to 107 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 16,798 square kilometers (13,632 square kilometers net to Eni). Eni's production activities in Italy are regulated by concession contracts (30 operated onshore and 58 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.

In December 2020, Eni signed with Saipem a Memorandum of Understanding to identify and develop jointly decarbonization initiatives and projects in the Country. In particular, the agreement provides for: (i) a collaboration in decarbonization projects in Italy focused on capture, transport, reuse and storage of CO2 produced by the industrial activity; and (ii) initiatives related to Green Deal Strategy to tackle climate change and to achieve of CO2 reduction targets at national, European and world level.

Adriatic and Ionian Seas

Production Fields in the Adriatic and Ionian Seas accounted for 36% of Eni's domestic production in 2020, mainly gas. Main operated fields are Barbara, Annamaria, Clara NW (Eni's interest 51%), Luna, Angela, Hera Lacinia and Bonaccia and related satellites. Production is operated by means of 59 fixed platforms (4 of these are manned) installed on the main fields, to which satellite fields are linked by underwater infrastructures. Production 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 Adriatic Sea, development activities in 2020 mainly concerned maintenance and production optimization at offshore gas fields to recover the residual mineral potential. The decommissioning plan to plug & abandon non-productive wells and remove non-productive platforms progressed in the year in compliance with applicable Italian laws; a total of five offshore platforms are currently in the authorization process to be removed. In the circular economy initiatives, a program in collaboration with national research institutions was launched to redevelop asset in the decomissioning phase. In particular activities started up to convert an offshore platform into a marine science park.

Within the VIII Agreement with the Municipality of Ravenna, activities progressed with: (i) environmental protection projects at the coastline areas; (ii) energy efficiency measures; (iii) programs to support employment, including mentoring and training initiatives; and (iv) completion of environmental monitoring studies.

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: (i) a pilot project with expected start-up in 2022, following all necessary authorizations; (ii) a full development phase expected to commence in 2026. The planned activities will benefit on the expected synergies on development cost due to the infrastructure in place 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 48% of Eni's domestic production, is treated by the Viggiano Oil Center.

Development During the year, maintenance and production optimization activities project were completed in the Val d'Agri concession.

In 2020 the Energy Valley project activities progressed and includes a number of initiatives relating to environmental sustainability, innovation and enhancement of the area: (i) Mini Blue Water project on circular economy, for treatment, recover and reuse of water production at the Viggiano Oil Center as well as installation of photovoltaic plants supporting oil production facilities; (ii) environmental and biodiversity monitoring plan. In particular, the opening of the Center of Environmental Monitoring to manage and spread data collected; and (iii) the CASF project to support the technological development and competence in the agrofood sector in the area. In 2020, upgrading of certain areas was completed and other initiatives was launched to support the agricultural, biomonitoring and teaching with a positive impact on local employment.

In addition, within the memorandum agreement with the Basilicata Region including environmental, social and sustainable development programs, initiatives progressed with defined activities of the Gas Agreement. Activities include a grant to support the gas consumption in 11 Municipalities of Val d'Agri and for energy efficiency programs.

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 2020 accounted for approximately 10% 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, initiatives progressed with: (i) development activities of the Cassiopea offshore gas fields (Eni's interest 60%). The project, through a significant reduction of the environmental impact, expects to achieve the carbon neutrality target. The activities provide the transportation of natural gas produced by offshore wells through a subsea pipeline to a new onshore treatment and compression plant, that will be realized in certain reclaimed area of the Gela Refinery; (ii) the sustainable development initiatives supported by local institutions. In particular, the Macchitella Lab project was launched to support youth employment and small and medium-sized local enterprises with the start-up of the redevelopment programs.

In addition, progressed the initiatives of the Memorandum of Understanding signed at the end of 2019 with the Ministry of Environment. Activities, which will be implemented in the next years, include the redevelopment programs of certain productive areas, environmental remediation projects as well as innovative projects developed by Eni's proprietary technologies to capture and reuse of CO2 .

REST OF EUROPE

NORWAY

Eni has been present in Norway since 1965 and the activities are conducted through Eni's equity accounted 69.85% interest in Vår Energi, the result of a business combination completed in 2018 between Point Resources AS and Eni Norge AS, fullyowned by HitecVision and Eni respectively. Eni's 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 25,667 square kilometers (6,253 square kilometers net to Eni). Eni's production in Norway amounted to 185 kboe/d in 2020.

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 prospecting 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 concerned: (i) the Johan Castberg sanctioned project (Eni's interest 20.96%) with start-up expected in 2023; and (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 2022.

In 2020, the Breidablikk project was sanctioned and start-up is expected in 2024. The development activities include the drilling of 23 productive wells that will be linked to existing facilities. Leveraging on high energy and operational efficiency technologies, the project development will minimize direct emissions.

Exploration Vår Energi partecipated in 136 exploration licenses, of which 32 are operated. The mineral interest portfolio increases were as follows: (i) in 2020 seven exploration licenses were acquired as operator and ten licenses in partnership. The licenses are distributed over the three main sections of the Norwegian continental shelf; and (ii) in 2021 ten exploration licenses were awarded, of which two as operator in the North Sea and three as operator in the Barents Sea. The licenses are located near-fields already in production or development.

Exploration activity yielded positive results with: (i) the Tordis NE and Lomre oil discoveries in the PL 089 block (Eni's interest 11.24%); (ii) the Enniberg oil and and gas discovery in the 971 license (Eni's interest 13.97%) in the North Sea, located near the Balder production field (Eni's interest 62.87%); and (iii) in March 2021, new oil discovery in the PL 532 license (Eni's interest 21%) and in the PL 090/090I license (Eni's interest 17%), located in the Barents Sea and in the northern North Sea, respectively.

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 1,680 square kilometers (975 square kilometers net to Eni). In 2020, Eni's oil and gas production averaged 52 kboe/d.

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

Production Eni holds interests in 4 production areas of which the Liverpool Bay (Eni's interest 100%) and Hewett Area (Eni's interest 89.3%) are 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%).

Development In October 2020 Eni was awarded by the UK Oil & Gas Authority a license, lasting six years, for building a carbon storage project in the Liverpool Bay area. The project includes the reutilization and refurbishment of Eni's depleted fields with a target of storing 3 million tonnes per year of CO2 . Activity start-up is expected in 2025.

Eni is expected to coordinate the storage and transportation phase from existing industries and future hydrogen production sites in the area, within the HyNet North West integrated project. The project will contribute to the UK's carbon neutrality targets by 2050. In the year concept selection activities started up and signed CO2 capture agreement with existing industries in the area. In addition, Eni signed a cooperation agreement with other upstream partners for the Net Zero Teeside (Eni's interest 20%) and North Endurance Partnership (Eni's interest 16.7%) projects. These integrated projects will allow to achieve the decarbonization target of the Teeside industrial area, in the north east UK, by means of the capture, transportation and storage of CO2 . Start-up is expected in 2026 with a carbon capture and storage of 4 million tonnes per year.

In March 2021, the UK Research and Innovation (UKRI), Country's authority for research and innovation, will fund the CCS projects developed by Eni and other partners: (i) the HyNet North West integrated project with approximately £33 million (£21 million net to Eni); and (ii) the Net Zero Teeside and North Endurance Partnership projects with approximately overall £52 million (£9 million net to Eni). The grants will finance 50% of the ongoing design studies and accelerate the final investment decision for all projects, expected in 2023.

The other development activities concerned the decommissioning programs, in particular of the McCulloch field (Eni's interest 40%), as well as the Hewett field, where abandonment activities started up in 2019 with production shutdown at the end of 2020. Exploration Eni holds interest in 11 exploration licenses, 3 of these are operated, with interest ranging from 6% to 100%. In January 2021, Eni was awarded a 100% interest in the

exploration license P2511 in the North Sea.

NORTH AFRICA

ALGERIA

Eni has been present in Algeria since 1981. In 2020, Eni's oil and gas production averaged 81 kboe/d. Developed and undeveloped acreage was 10,724 square kilometers (4,732 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.

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

Blocks 403a/d and ROM North

Production In 2020 production comes mainly from the HBN, ROMN and ROM and satellites fields and represented approximately 23% 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 Development activities concerned production optimization.

Blocks 401a/402a

Production In 2020 production comes mainly from the ROD/ SFNE and satellites fields and accounted for approximately 15% of Eni's production in Algeria.

Development Development activities concerned production optimization.

Block 403

Production The main fields in Block 403 are BRN, BRW and BRSW, which accounted for approximately 12% of Eni's production in Algeria in 2020.

During the year, was completed the fast-track development project for the export of associated gas production in the area. The development program included the construction of a pipeline and related facilities to link the BRN and BRW producing field to the MLE treatment plant in Block 405b.

Development Development activities concerned production optimization.

Block 405b

Production In 2020 production comes from the MLE-CAFC project and accounted for approximately 12% of Eni's production in the Country. Four export pipelines link it to the national grid system.

Development The upgrading of the MLE treatment plant was completed in the year and is expected to reach a gross peak production of 60 kboe/d leveraging also the production of the Block 403 and of the Berkine North area by the end of 2021.

Other development activities concerned production optimization.

Block 404

Production The main fields in Block 404 are HBN and HBNS fields, which accounted for approximately 17% of Eni's production in Algeria in 2020.

Development Development activities concerned production optimization.

Block 208

Production The El Merk field is the main production project in the Block 208 and accounted for approximately 14% of Eni's production in Algeria in 2020. 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 Activities concerned progress in the development program of the El Merk field with the drilling of one production well and workover activity.

Sif Fatima II, Ourhoud II and Zemlet El Arbi blocks

Production In 2020 production in the area accounted for approximately 8% of Eni's production in Algeria.

During the year, gas production was started at the Berkine North complex leveraging a fast-track development intended to valorize the existing gas reserves. The development program included the drilling of four producing wells that were linked to the existing facilities, as well as the laying of a pipeline connecting the producing field to the MLE treatment plant in Block 405b.

Exploration Exploration activities yielded positive results with the BKNES-1 near-field oil discovery well.

LIBYA

Eni started operations in Libya in 1959. In 2020, 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).

Eni's operations in Libya are currently exposed to significant geopolitical risks. At the beginning of 2020 oil export terminals in the eastern and southern parts of Libya were blocked, halting most of the Country's oil export terminals, and force majeure was declared at several Libyan production facilities. Production shutdowns also involved certain of the Company's profit centres (the El Feel oilfield and the Bu-Attifel offshore platform).

In September 2020, the situation began to improve thanks to a temporary agreement between the conflicting factions, the blockade was lifted at the main ports for exporting crude oil and production resumed at the main fields, revoking force majeure. Despite this, management believes that Libya's geopolitical situation will continue to represent a source of risk and uncertainty. For further information see Annual Report 2020.

TUNISIA

Eni has been present in Tunisia since 1961. In 2020, Eni's production amounted to 8 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 6,372 square kilometers (2,252 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 Baraka operated concession with the completion of drilling activities and production start-up of three productive wells.

Exploration Exploration activity yielded positive results with the Debech b-1 near-field oil and condensate discovery in the MLD concession and already achieved production start-up.

EGYPT

Eni has been present in Egypt since 1954. In 2020, Eni's production amounted to 291 kboe/d and accounted for approximately 17% of Eni's total annual hydrocarbon production. Developed and undeveloped acreage was 20,622 square kilometers (7,384 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 2020 the award of the exploration block West Sherbean (Eni's interest 50%) in the onshore Nile Delta was ratified.

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

Shorouk block

Production Production comes from the Zohr field which in 2020 achieved the production of 133 kboe/d net to Eni.

Development Development activities progressed at the Zohr project, targeting to ramp-up the field production capacity and concerned: (i) the drilling of two additional productive wells and linked to onshore production facility, reaching a gross production capacity of 3,200 mmscf/d; (ii) optimization and upgrading activities of the subsea facilities and of the onshore treatment plant.

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 in four years. 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 three socio-economic and health programs to support local communities in the Zohr and Port Said areas. In particular, two initiatives concerned the implementation of: (i) Health Care Center provides health services to approximately 60,000 people; and (iii) Youth Center provides programs to support youth, also with professional training services. The related activities have been completed and the two structures were handed to the local Authorities. The third project, which is part of education and technical training, is being defined. Expected activities start-up in 2021.

Sinai

Production Production for the year amounted to approximately 70 kbbl/d (37 kbbl/d net to Eni) and mainly comes from the Belayim Marine, Belayim Land and Abu Rudeis fields.

Development During the year, development activities mainly concerned: (i) the drilling of infilling wells in the production fields; and (ii) maintenance activities and extensive asset integrity programs at the onshore and offshore facilities.

North Port Said

Production Production for the year amounted to approximately 14 kboe/d (approximately 11 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 133 ktonnes of propane, 89 ktonnes of LPG and approximately 895 mmbbl of condensates.

Development During the year, development activities concerned maintenance activities and extensive asset integrity programs at the onshore and offshore facilities.

Baltim

Production In 2020, production amounted to approximately 70 kboe/d (approximately 23 kboe/d net to Eni).

Development Ongoing activities concerned the drilling development activity and production start-up of Baltim SW (Eni's interest 50%) operated fields. In particular, the Baltim SW project includes a full field development phase with the drilling of two additional productive wells.

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 2020 production amounted to approximately 87 kboe/d (approximately 42 kboe/d net to Eni).

Development During the year, development activities concerned maintenance activities and extensive asset integrity programs at the onshore and offshore facilities.

Exploration Exploration activities yielded positive results with the Nidoco NW-1 in the Abu Madi West concession and Bashrush gas discoveries (Eni's interest 37.5%) in the Great Nooros Area.

Ras el Barr

Production In 2020, the production amounted to approximately 25 kboe/d (approximately 8 kboe/d net to Eni), mainly gas from Ha'py and Seth fields.

Development During the year, development activities concerned maintenance activities and extensive asset integrity programs at the onshore and offshore facilities.

El Temsah

Production This concession includes Tuna, Temsah and Denise fields. Production in 2020 amounted to approximately 26 kboe/d (approximately 8 kboe/d net to Eni).

Development During the year, development activities concerned maintenance activities and extensive asset integrity programs at the onshore and offshore facilities.

Western Desert

Production This area includes Meleiha, Meleiha Deep, South West Meleiha, Ras Qattara and West Abu Gharadig, East Kanays and West Razzak concessions. In 2020 production amounted to approximately 48 kboe/d (approximately 22 kboe/d net to Eni).

Development During the year, development activities concerned: (i) the drilling of infilling wells in the production fields; and (ii) the drilling development activity and production start-up in the Arcadia South, Meleiha and South West Meleiha operated fields.

Exploration Exploration activities yielded positive results with near-field discoveries in the operated areas: (i) the SWM-A-6X oil discovery well in the South West Meleiha concession. The production start-up was achieved during the year; and (ii) the southern extension of the Arcadia field through the Arcadia 9 oil discovery well in the Meleiha concession and already in production.

SUB-SAHARAN AFRICA

ANGOLA

Eni has been present in Angola since 1980. In 2020, Eni's production averaged 123 kboe/d. Eni's activities are concentrated in the conventional and deep offshore, over a developed and undeveloped acreage of 21,304 square kilometers (5,639 square kilometers net to Eni).

Eni's main asset in Angola is the Block 15/06 (Eni operator with a 36.84% interest) with the West Hub and the East Hub projects. Eni participates in other producing blocks: (i) Block 0 in Cabinda offshore (Eni's interest 9.8%) north of the Angolan coast; (ii) Development Areas in the Block 3 and 3/05-A (Eni's interest 12%) offshore of the Country; (iii) Development Areas in the Block 14 (Eni's interest 20%) in the deep offshore west of Block 0; (iv) the Lianzi Development Area in the Block 14 K/A IMI (Eni's interest 10%); and (v) Development Areas in the former Block 15 (Eni's interest 18%) in the deep offshore of the Country.

In 2020 Eni was awarded the operatorship with a 60% interest in the offshore Block 28, in the Namibe basin, and a 42.5% interest in the onshore Cabinda Central block.

In 2020 the local development initiatives and projects concerned: (i) restructuring of the Beira Nova school in Cabinda; (ii) the installation of two power generation systems from renewable sources at two medical centers in Luanda area; (iii) support to the agricultural development of the area in collaboration with the relevant local Authorities; and (iv) the integrated development project in Huila and Namibe area through water and energy access initiatives, education programs, economic diversification and health protection projects.

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 2020 produced 123 kboe/d (42 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.

In 2020, production ramp-up was achieved at the Agogo discovery well, connecting it to the Ngoma FPSO (West Hub project). Production started up just nine months after the discovery, confirming Eni's commitment in the fasttrack development of the discoveries, that maximizes the projects value leveraging on the synergies with the existing infrastructures.

Development Development activities concerned: (i) the completion of the subsea production and injection facilities at the Cabaça North & UM 4/5 project; (ii) studies for the full field development of the Agogo field; and (iii) activities related to the Ndungu discovery development.

Exploration Exploration activities yielded positive results with: (i) the successful appraisal well of the Agogo discovery, with estimated volumes of 1 billion boe in place; and (ii) the Cuica-1 oil well, second discovery in the development area of Cabaça. In 2020, the Block 15/06 exploration license was renewed for additional three years. The agreement will allow to assess the possible additional mineral potential of the area.

Block 0

Production In 2020 production amounted to 235 kboe/d (23 kboe/d net to Eni) and comes mainly from the Takula, Malongo and Mafumeira fields in the Area A (15 kboe/d net to Eni) and from the Bomboco, Kokongo, Lomba, N'Dola, Nemba and Sanha fields in the Area B (8 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.

Block 3 and 3/05-A

Production Block 3 is divided into three production offshore areas. Oil production is treated at the Palanca terminal and delivered to storage vessel unit and then exported. In 2020, production from this area amounted to 23 kboe/d (2 kboe/d net to Eni).

Block 14

Production In 2020, Development Areas in Block 14 produced approximately 60 kboe/d (9 kboe/d net to Eni). Main 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).

In October 2020, the unitization agreement of the three Development Areas of Block 14 was ratified with the related implementing decree. The agreements provide a new expiration date in 2028 and new development plan of the area as well as increasing entitlement volumes for the cost recovery.

Block 15

Production The block produced approximately 198 kboe/d (24 kboe/d net to Eni) in 2020. Main fields are: (i) the Hungo/ Chocalho, started up in 2004, and Marimba, started up in 2007, as part of phase A of the global development plan of the Kizomba reserves; (ii) the Kissanje/Dikanza, started up in 2005 as part of Phase 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 2020 production net to Eni averaged approximately 23 kboe/d.

CONGO

Eni has been present in Congo since 1968. In 2020, production averaged 73 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). Exploration and production activities in Congo are regulated by Production Sharing Agreements.

Production Eni's main operated producing interests in Congo 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 83 kboe/d (59 kboe/d net to Eni) in 2020. 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 41 kboe/d (approximately 14 kboe/d).

In 2020 production start-up was achieved at the Nené phase 2b project in the Marine XII block by means of the linkage to the existing production platform in the area. The full field development phase is expected in the second half of 2022.

Development Development activities concerned the expansion of the CEC power plant (Eni's interest 20%), increasing the electricity generation capacity to 484 MW, with the installation of a third turbine in 2020. Natural gas supply to the plant will be ensured by the Marine XII block production. The activities of 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. In particular, in the access to water initiatives, 5 additional wells were completed in 2020 achieving a total of 30 water wells for approximately 20,000 people. The activity progressed at the training center in Oyo area, in the north of the Country, with construction activity and equipment supply. Completion is expected 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 2020, production averaged 41 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 Development activity concerned: (i) production optimization activities; and (ii) development activities concerned the completion of the Takoradi-Tema Interconnection project. Project includes the construction of transportation facility of the OCTP associated gas production. The program increases the use of natural gas also in the eastern part of the Country.

The Africa Program targets to contribute the local socioeconomic development with initiatives to support economic diversification by means of training programs in the agricultural-food and agro-business areas and to facilitate access to the labor market in a path of economic growth, inclusive and sustainable at the same time, in line with the United Nations 2030 Agenda. In 2020, activities of the Pilot Project started up at the Okuafo Pa center, opened in 2019, in Ghana, in order to set-up the model to be replicated in other Countries. The project provides for defining to access microcredit facilities and the use of funds, in cooperation with Cassa Depositi e Prestiti, and for the development of agricultural activities with the support of Bonifiche Ferraresi. During the year, 800 people benefited from the training program

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.

Development The development activities of Area 4 offshore (Eni's interest 25%) concerned the Coral South project, operated by Eni, and the discoveries of Mamba Complex where Eni is expected to coordinate the upstream development and production phase and ExxonMobil the construction and operation phase of natural gas liquefaction facilities onshore. The sanctioned Coral South project includes the construction of FPSO for the gas treatment, liquefaction, storage and export of LNG, with a capacity of approximately 3.4 mmtonnes/y, fed by 6 subsea wells. 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 tenyear term. The project has reached a progress of more than 80% and the production start-up is expected in 2022.

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 (Total). 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 development activities towards a final investment decision (FID).

In 2020, Eni's programs to support the local communities of the Country progressed with: (i) the scholarship programs mainly in Pemba, also through the construction of a school and maintenance activities, as well as training initiatives; (ii) initiatives to promote more sustainable domestic behaviors through clean cooking projects; (iii) biodiversity protection programs and technical-professional training initiatives, also through agreements with institutions and Authorities of the Country; (iv) projects of forests protection and conservation (REDD+ program) with the Government of Mozambique; and (v) health care initiatives, coordinated with the Country's health Authorities, in the Maputo area, by means of specific initiatives on prevention.

NIGERIA

Eni has been present in Nigeria since 1962. In 2020, Eni's oil and gas production averaged 131 kboe/d, over a developed and undeveloped acreage of 29,265 square kilometers (6,439 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%). Eni continues the collaboration with the Food and Agriculture Organization (FAO) to foster access to safe and clean water in Nigeria, mainly in the north-east areas, by drilling boreholes powered with photovoltaic systems, both for domestic use and irrigation purposes. In 2020 Eni realized 6 wells to achieve a total of 22 wells, including the other wells completed in 2018-2019. Eni's programs to support local communities progressed with: (i) access to energy initiatives; (ii) economic programs for diversification purposes, in particular with the Green River Project; (iii) professional training and scholarship programs; and (iv) renovation and construction of health centers and supply of medical equipment.

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 72 kboe/d net to Eni in 2020. 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: (i) production optimization programs with workover and drilling activities; and (ii) increasing generation capacity of the combined cycle power plant at Okpai. Natural gas production of the area will support the plant capacity. The first phase of the expansion project was completed, reaching an installed capacity of 780 MW.

Block OML 118

Production The Bonga oil field produced over 12 kboe/d net to Eni in 2020. 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 the completion of an additional development well of the offshore Bonga field.

Block OML 125

Production Production derived mainly from the Abo field which yielded approximately 17 kboe/d net to Eni in 2020. 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 2020, production from the SPDC JV amounted to approximately 30 kboe/d net to Eni.

Development Development activities concerned: (i) the drilling of 8 oil wells in the EA offshore field in the Block 79 (Eni's interest 5%); (ii) production optimization programs with workover activity in the Gbaran field in the OML 28 block (Eni's interest 5%) and Forkados Yokri field in the OML 43 block (Eni's interest 5%); and (iii) the drilling of 4 oil wells in the western area of the Block 46 (Eni's interest 5%).

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 treatment capacity of approximately 1,236 bcf/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG. Natural gas supplies to the plant are currently provided under gas supply agreements from the SPDC JV, TEPNG JV and the NAOC JV (Eni's interest 20%). In 2020, the Bonny liquefaction plant processed approximately 1,135 bcf. LNG production is sold under longterm contracts and exported mainly to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG.

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 2020, production of the Kashagan field averaged 347 kbbl/d of liquids (approximately 57 kbbl/d net to Eni) and approximately 402 mmcf/d of natural gas (approximately 67 mmcf/d net to Eni).

Gas volumes undergo a treatment 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.

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 2020, production of the Karachaganak field averaged 239 kbbl/d of liquids (approximately 53 kbbl/d net to Eni) and 947 mmcf/d of natural gas (approximately 216 mmcf/d net to Eni). This field is producing liquids from the deeper layers of the reservoir. The gas is marketed (about 50%) at the Russian gas plant of Orenburg, the remaining 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 ongoing activities of the Karachaganak Debottlenecking project and the construction of a fourth gas reinjection unit; and (ii) completion of the Front End Engineering Design of the Karachaganak Expansion Project (KEP). This latter 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. Furthermore, the project includes the installation of one additional treatment and compression units.

Eni continues its commitment to support local communities in the nearby area of the Karachaganak field. In particular, activities focused on: (i) professional training; and (ii) realization of kindergartens and schools, maintenance of bridges and roads, construction of sport centers.

REST OF ASIA

INDONESIA

Eni has been present in Indonesia since 2001. In 2020, Eni's production mainly composed of gas, amounted to 48 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 2020, Eni was awarded the operatorship with 40% interest in the West Ganal exploration block.

The activities and initiatives in the fields of access to water and renewable energy progressed to support the local development areas of Samboja, Kutai Kartanegara and East Kalimantan.

Development and production activities are regulated by PSAs. Production Production derives mainly from 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.

Development Development activities are related to the offshore Merakes gas project in the operated East Sepinggan block (Eni's interest 65%). The project foresees the drilling and the completion of five subsea wells, which will be tie-back to the Floating Production Unit (FPU) of the Jangkrik field. Natural gas production will be 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 will be sold on a spot basis in the domestic market. Production start-up was achieved in April 2021.

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 45 kbbl/d net to Eni in 2020.

Development Development activities concerned the execution of an additional development phase of the ERP (Enhanced Redevelopment Plan) at the Zubair field, to achieve a production plateau of 700 kbbl/d. The production capacity and relevant facilities to treat the targeted production plateau have been already installed; the field reserves will be progressively put into production by drilling additional productive wells over the next few years.

Eni's commitment continues with projects in the fields of education, health, environment and access to water. In particular: (i) started up activities for the construction of a new school in Zubair City; (ii) progressed the revamping of two water plants to achieve the distribution of approximately 30 million liters of drinkable water per day; and (iii) progressed activities for the expansion of Basra Children Cancer and the supply of medical equipment.

PAKISTAN

Eni has been present in Pakistan since 2000. In 2019, Eni's production mainly composed of gas amounted to 15 kboe/d, over a developed and undeveloped acreage of 5,885 square kilometers (2,313 square kilometers net to Eni).

Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore).

In March 2021, Eni signed an agreement to divest the entire upstream activity in the Country including interests in eight development and production licenses to Prime International Oil & Gas local company. In particular, the agreement provides the disposal of the Bhit/Badhra (Eni's interest 40%) and Kadanwari (Eni's interest 18.42%) operated fields, as well as the partecipating interest in the Latif (Eni's interest 33.3%), Zamzama (Eni's interest 17.75%) and Sawan (Eni's interest 23.7%) fields

TIMOR LESTE

Eni has been present in Timor Leste since 2006 and is performing 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 108 kboe/day (10 kboe/day net to Eni) in 2020. 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.

UNITED ARAB EMIRATES

Eni has been present in United Arab Emirates since 2018 following the acquisition of 5% participating interest in the Lower Zakum oil concession and a 10% participating interest in the Umm Shaif/Nasr oil, condensates and natural gas concession, in the offshore of Abu Dhabi, with duration of 40 years.

In the exploration activity, Eni is operator of: (i) Block 1 and 2 with a 70% interest, located offshore Abu Dhabi. The exploration commitment for the first phase consists in exploration studies for the Block 1 and the drilling of two exploration wells and one appraisal well in the Block 2; (ii) three onshore exploration concessions in the Emirate of Sharjah with a 75% interest in the operated concession Area A and C and a 50% interest in the participated concession Area B; and (iii) Block A with a 90% interest, located offshore Emirate of Ras al Khaimah.

In addition Eni holds a 25% interest in the Ghasha concession with duration of 40 years and where the FID of the Dalma Gas Develompment project is sanctioned. The concession includes Hail, Ghasha, Dalma gas fields and certain offshore fields in the Al Dhafra area.

In 2020, Eni awarded the operatorship with a 70% interest in the Block 3, located offshore Abu Dhabi. The exploration commitment for the first phase includes exploration studies, the drilling of exploration and appraisal wells.

In April 2021, Eni awarded the Block 7 (Eni's interest 90%), located in the Ras Al Khaimah onshore.

Developed and undeveloped acreage was 32,190 square kilometers (18,680 square kilometers net to Eni).

Production In 2020 production amounted to 48 kboe/d net to Eni and comes from the Lower Zakum, Umm Shaif and Nasr fields.

In January 2021, production start-up was achieved at the Mahani field located in the onshore Area B concession located in the Emirate of Sharjah, just one year since discovery in January 2020 and two years after signing the concession agreement. Development activities, sanctioned with the final investment decision, provide the progressive ramp-up with the tie-back of two additional productive wells. Drilling activities were already planned.

AMERICAS

MEXICO

Eni has been present in Mexico since 2015, 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 Area 12 (Eni's interest 40%) and the Area 9 (Eni's interest 15%).

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

Production In 2020 production comes from the operated Area 1 license and amounted to 14 kboe/d.

Development The development activities concern the full field development program of the operated license Area 1. Development drilling activities are ongoing and during the year 2020 were completed producing wells which were linked to the Miztón production platform. A subsequent development phase of the project includes the production start-up of the Amoca discovery by means of the installation of a new leased production platform, currently under construction, as well as the conversion and upgrading of an FPSO unit that will be completed in 2021 including all linking and treatment facilities. Production start-up is expected in 2022. During the year, the FEED phase for these two production platforms started up.

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) food supply programs; (ii) restructuring of school buildings and construction of roads; (iii) child medical screening campaigns; (iv) initiatives to support youth employment; and (v) environmental monitoring program. The signed agreements target to define further projects improving the sustainable development in the areas close to Eni's activity in the Country. Exploration In February 2020, exploration activities yielded

positive results with the Saasken offshore oil discovery in the operated Block 10.

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 1,944 square kilometers (1,198 square kilometers net to Eni). In 2020, Eni's oil and gas production was 61 kboe/d.

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

Gulf of Mexico

Eni holds interests in 41 exploration and production blocks in the shallow and deep offshore of the Gulf of Mexico, of which 18 are operated by Eni.

Production The 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 2020, production amounted to 31 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 2020, Eni's production amounted to approximately 3 kboe/d.

Alaska

Eni holds interests in 151 exploration and development blocks in Alaska.

Production The main operated fields are Nikaitchuq (Eni's interest 100%) and Oooguruk (Eni's interest 100%) with a 2020 overall net production of approximately 27 kbbl/d.

VENEZUELA

Eni has been present in Venezuela since 1998. In 2020, Eni's production averaged 42 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 2020, Eni's production of oil and natural gas averaged 17 kboe/d. Activities are focused on offshore fields, over a developed and undeveloped acreage of 3,508 square kilometers (2,877 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 three exploration licenses.

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

FORESTRY PROJECTS

In the decarbonization path, one of the pillars and strategic guidelines of Eni include 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.

The projects including the REDD+ (Reducing Emissions from Deforestation and forest Degradation) scheme are a key lever in this context. The REDD+ scheme was designed by the United Nations (in particular within the UNFCCC - United Nations Framework Convention on Climate Change) and involves conservation forest activities to reduce emissions and improve the natural storage capacity of CO2 , as well as supporting, with a different development model, the local communities through socio-economic projects, in line with sustainable management, forest protection and biodiversity conservation. In this scheme, Eni's protection forest activities support national governments, local communities and UN agencies in the REDD+ strategies, in line with the NDCs (Nationally Determined Contributions) and National Development Plans and, mainly, the Sustainable Development Goals (SDGs) of UN.

Eni built solid partnerships over time with recognized international developers of REDD+ projects, like BioCarbon Partners, Terra Global, Peace Parks Foundation, First Climate and Carbonsink, 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 also to allow the alignment with the 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 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 over 170,000 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 no-profit organization Verra, leader in the carbon credits certifying, for its oustanding social and environmental impact.

Eni committed to purchase carbon credits generated by the LCFP project until 2038. In particular, in November 2020 Eni achieved the first allowance of carbon credits by the project to offset GHG emissions equivalent to 1.5 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 (Angola, Democratic Republic of Congo, Ghana, Malawi, Mozambique and Zambia), Latin America (Colombia and Mexico) and Asia (Vietnam and Malaysia). The mediumlong term target is a progressive growth of these initiatives and planned to reach a carbon credit portfolio on yearly basis to offset over 6 million tonnes of CO2 by 2024, over 20 million tonnes of CO2 in 2030, as well as over 40 million tonnes of CO2 by 2050.

MOVEMENTS IN NET PROVED HYDROCARBONS RESERVES(a)

(mmboe)		Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2020
Consolidated subsidiaries
Reserves at December 31, 2019		333	89	974	1,225	1,453	1,108	742	268	95	6,287
of which: developed		258	82	553	1,033	863	1,046	372	182	61	4,450
undeveloped		75	7	421	192	590	62	370	86	34	1,837
Purchase of minerals in place
Revisions of previous estimates		(51)	3	(84)	(9)	26	133	185	11	2	216
Improved recovery								5			5
Extensions and discoveries					1			11	5		17
Production		(39)	(19)	(92)	(107)	(127)	(59)	(64)	(28)	(6)	(541)
Sales of minerals in place
Reserves at December 31, 2020		243	73	798	1,110	1,352	1,182	879	256	91	5,984
Equity-accounted entities
Reserves at December 31, 2019			567	16		63			335		981
of which: developed			330	16		23			335		704
undeveloped			237			40					277
Purchase of minerals in place
Revisions of previous estimates			(33)			32			4		3
Improved recovery
Extensions and discoveries			30								30
Production			(68)	(2)		(8)			(15)		(93)
Sales of minerals in place
Reserves at December 31, 2020			496	14		87			324		921
Reserves at December 31, 2020		243	569	812	1,110	1,439	1,182	879	580	91	6,905
Developed		199	322	448	1,022	846	1,093	424	486	60	4,900
consolidated subsidiaries		199	68	434	1,022	799	1,093	424	162	60	4,261
equity-accounted entities			254	14		47			324		639
Undeveloped		44	247	364	88	593	89	455	94	31	2,005
consolidated subsidiaries		44	5	364	88	553	89	455	94	31	1,723
equity-accounted entities			242			40					282
Reserves life index	(year)	6.2	6.5	8.6	10.4	10.7	20.0	13.7	13.5	15.2	10.9
Reserves replacement ratio, organic	(%)	(131)		(89)	(7)	43	225	314	47	33	43
Reserves replacement ratio, all sources		(131)		(89)	(7)	43	225	314	47	33	43

(a) 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 of this update on the change in the initial reserves balance as of January 1, 2020 amounted to 67 mmboe.

(mmboe)		Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest	of Asia Americas	Australia and Oceania	Total
2019
Consolidated subsidiaries
Reserves at December 31, 2018		428	106	1,022	1,246	1,361	1,066	700	302	125	6,356
of which: developed		336	99	582	764	895	925	403	170	87	4,261
undeveloped		92	7	440	482	466	141	297	132	38	2,095
Purchase of minerals in place									30		30
Revisions of previous estimates		(50)	2	90	106	190	97	67	(20)	(23)	459
Improved recovery
Extensions and discoveries			1		2	35		53	10		101
Production		(45)	(20)	(138)	(129)	(129)	(55)	(69)	(25)	(7)	(617)
Sales of minerals in place(a)						(4)		(9)	(29)		(42)
Reserves at December 31, 2019		333	89	974	1,225	1,453	1,108	742	268	95	6,287
Equity-accounted entities
Reserves at December 31, 2018			363	14		68			352		797
of which: developed			205	14		17			347		583
undeveloped			158			51			5		214
Purchase of minerals in place			184								184
Revisions of previous estimates			59	3		3			(3)		62
Improved recovery
Extensions and discoveries			6								6
Production			(39)	(1)		(8)			(14)		(62)
Sales of minerals in place			(6)								(6)
Reserves at December 31, 2019			567	16		63			335		981
Reserves at December 31, 2019		333	656	990	1,225	1,516	1,108	742	603	95	7,268
Developed		258	412	569	1,033	886	1,046	372	517	61	5,154
consolidated subsidiaries		258	82	553	1,033	863	1,046	372	182	61	4,450
equity-accounted entities			330	16		23			335		704
Undeveloped		75	244	421	192	630	62	370	86	34	2,114
consolidated subsidiaries		75	7	421	192	590	62	370	86	34	1,837
equity-accounted entities			237			40					277
Reserves life index	(year)	7.4	11.1	7.1	9.5	11.1	20.1	10.8	15.5	13.6	10.6
Reserves replacement ratio, organic		(%) (111)	115	67	84	166	176	174	(33)	(329)	92
Reserves replacement ratio, all sources		(111)	417	67	84	164	176	161	(31)	(329)	117

(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
Reserves life index	(year)	8.6	6.6	7.1	11.3	11.0	20.5	10.8	14.5	15.6	10.6
Reserves replacement ratio, organic	(%)	112	21	79	398	37	(62)	9	69	(50)	100
Reserves replacement ratio, all sources		112	21	79	253	37	(62)	518	58	(50)	124

MOVEMENTS IN NET PROVED LIQUIDS RESERVES

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

27

(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
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.

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

31

(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)

	(kboe/d) 2020	2019	2018
CONSOLIDATED SUBSIDIARIES
Italy	107	123	138
Rest of Europe	52	55	194
Croatia			2
Norway			134
United Kingdom	52	55	58
North Africa	255	379	392
Algeria	81	83	85
Libya	168	291	302
Tunisia	6	5	5
Egypt	291	354	300
Sub-Saharan Africa	345	363	337
Angola	100	113	127
Congo	73	87	92
Ghana	41	42	18
Nigeria	131	121	100
Kazakhstan	163	150	143
Rest of Asia	176	179	177
China	1	1	1
Indonesia	48	59	71
Iraq	45	41	34
Pakistan	15	19	20
Timor Leste	10
Turkmenistan	9	8	11
United Arab Emirates	48	51	40
Americas	75	68	75
Ecuador		6	12
Mexico	14	4
Trinidad & Tobago			7
United States	61	58	56
Australia and Oceania	17	28	23
Australia	17	28	23
	1,481	1,699	1,779
EQUITY-ACCOUNTED ENTITIES
Angola	23	23	19
Indonesia			1
Norway	185	108
Tunisia	2	3	4
Venezuela	42	38	48
	252	172	72
Total	1,733	1,871	1,851

(a) Includes volumes of hydrocarbons consumed in operations (124, 124 and 119 kboe/d in 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).

indicators per boe and operating cost per boe is unaffected by this transaction.

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

LIQUIDS PRODUCTION

(kbbl/d)	2020	2019	2018
CONSOLIDATED SUBSIDIARIES
Italy	47	53	60
Rest of Europe	23	23	113
Norway			89
United Kingdom	23	23	24
North Africa	112	166	154
Algeria	53	62	65
Libya	56	101	86
Tunisia	3	3	3
Egypt	64	75	77
Sub-Saharan Africa	218	249	244
Angola	89	102	111
Congo	49	59	65
Ghana	24	24	15
Nigeria	56	64	53
Kazakhstan	110	100	94
Rest of Asia	88	86	77
China	1	1	1
Indonesia	1	2	3
Iraq	31	27	28
Timor Leste	2
Turkmenistan	7	7	6
United Arab Emirates	46	49	39
Americas	57	55	52
Ecuador		6	12
Mexico	12	4
United States	45	45	40
Australia and Oceania		2	2
Australia		2	2
	719	809	873
EQUITY-ACCOUNTED ENTITIES
Angola	4	4	3
Norway	116	74
Tunisia	2	3	3
Venezuela	2	3	8
	124	84	14
Total	843	893	887

NATURAL GAS PRODUCTION

(mmcf/d)	2020	2019	2018
CONSOLIDATED SUBSIDIARIES
Italy	316.6	376.4	426.2
Rest of Europe	159.1	174.6	444.9
Croatia			11.4
Norway			241.8
United Kingdom	159.1	174.6	191.7
North Africa	758.4	1,149.2	1,299.1
Algeria	152.5	111.8	105.5
Libya	594.4	1,025.8	1,180.3
Tunisia	11.5	11.6	13.3
Egypt	1,203.0	1,509.0	1,218.5
Sub-Saharan Africa	679.0	621.2	505.4
Angola	58.2	67.3	84.2
Congo	131.1	147.7	150.3
Ghana	87.6	97.9	19.3
Nigeria	402.1	308.3	251.6
Kazakhstan	282.2	272.4	265.2
Rest of Asia	465.0	502.7	550.7
Indonesia	248.5	308.1	376.5
Iraq	76.3	78.7	36.7
Pakistan	76.8	101.2	106.1
Timor Leste	46.8
Turkmenistan	6.2	6.0	27.2
United Arab Emirates	10.4	8.7	4.2
Americas	97.1	66.8	118.9
Mexico	10.9	2.8
Trinidad & Tobago			35.7
United States	86.2	64.0	83.2
Australia and Oceania	91.0	139.6	114.3
Australia	91.0	139.6	114.3
	4,051.4	4,811.9	4,943.2
EQUITY-ACCOUNTED ENTITIES
Angola	98.8	97.3	89.2
Indonesia			2.2
Norway	365.0	182.4
Tunisia	2.9	3.4	4.4
Venezuela	211.0	192.0	221.7
	677.7	475.1	317.5
Total	4,729.1	5,287.0	5,260.7

OIL AND NATURAL GAS PRODUCTION SOLD

		2020	2019	2018
Oil and natural gas production	(mmboe)	634.3	683.0	675.6
Change in inventories other		(13.7)	(7.0)	(7.1)
Own consumption of hydrocarbons		(45.4)	(45.4)	(43.5)
Oil and natural gas production sold(a)		575.2	630.6	625.0
Liquids	(mmbbl)	300.1	325.4	320.0
- of which to R&M segment		201.6	216.2	221.3
Natural gas	(bcf)	1,461	1,650	1,665
- of which to GGP segment		272	302	349

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

PRINCIPAL OIL AND NATURAL GAS INTERESTS AT DECEMBER 31, 2020

					Gross undeveloped
	Commencement of operations	Number of interests	acreage(a)(b) developed Gross	acreage(a)(b) developed Net	acreage(a)	Net undeveloped acreage(a)	fields/acreage Types of	Number of producing fields	Number of fields other
EUROPE		312	15,284	9,335	63,741	30,506		114	95
Italy	1926	129	9,578	7,951	7,220	5,681	Onshore/Offshore	64	49
Rest of Europe		183	5,706	1,384	56,521	24,825		50	46
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	136	4,799	772	20,868	5,481	Offshore	40	42
United Kingdom	1964	34	907	612	773	363	Offshore	10	3
Other Countries		2			2,701	1,883	Offshore
AFRICA		255	48,458	12,333	232,341	116,834		268	153
North Africa		71	12,213	5,312	55,419	25,721		73	56
Algeria	1981	49	6,742	2,818	3,982	1,914	Onshore	40	35
Libya	1959	11	1,963	958	24,673	12,336	Onshore/Offshore	11	15
Morocco	2016	1			23,900	10,755	Offshore
Tunisia	1961	10	3,508	1,536	2,864	716	Onshore/Offshore	22	6
Egypt	1954	57	5,638	2,109	14,984	5,275	Onshore/Offshore	41	23
Sub-Saharan Africa		127	30,607	4,912	161,938	85,838		154	74
Angola	1980	47	8,158	1,035	13,146	4,604	Onshore/Offshore	59	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	4			3,747	3,372	Offshore
Kenya	2012	6			50,677	43,948	Offshore
Mozambique	2007	10			25,304	4,349	Offshore		6
Nigeria	1962	32	21,059	3,099	8,206	3,340	Onshore/Offshore	78	35
South Africa	2014	1			55,677	22,271	Offshore
ASIA		69	12,994	3,343	271,271	151,502		24	24
Kazakhstan	1992	7	2,391	442	3,853	1,505	Onshore/Offshore	2	3
Rest of Asia		62	10,603	2,901	267,418	149,997		22	21
Bahrain	2019	1			2,858	2,858	Offshore
China	1984	4	68	11			Offshore	3
Indonesia	2001	13	3,214	349	28,976	18,331	Onshore/Offshore	2	7
Iraq	2009	1	2,605	1,029	18,672	13,155	Onshore/Offshore	1
Lebanon	2018	2	1,074	446			Onshore
Myanmar	2014	3			3,653	1,461	Offshore
Oman	2017	3			13,750	10,015	Onshore/Offshore
Pakistan	2000	13			102,016	58,955	Offshore	10	1
Russia	2007	2	3,442	886	2,443	1,427	Onshore/Offshore
Timor Leste	2006	4			53,930	17,975	Offshore	1	3
Turkmenistan	2008	1			2,612	1,620	Offshore	2
United Arab Emirates	2018	10	200	180			Offshore	3	10
Vietnam	2013	4			23,908	20,956	Offshore
Other Countries		1			14,600	3,244	Offshore
AMERICAS		157	2,267	1,020	15,274	8,699		37	22
Mexico	2015	10	14	14	5,455	3,092	Offshore	1	3
United States	1968	134	992	509	952	689	Onshore/Offshore	34	16
Venezuela	1998	6	1,261	497	1,543	569	Onshore/Offshore	2	2
Other Countries		7			7,324	4,349	Offshore		1
AUSTRALIA AND OCEANIA		5	328	328	3,180	2,549		1	1
Australia	2001	5	328	328	3,180	2,549	Offshore	1	1
Total		798	79,331	26,359	585,807	310,090		444	295

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

AVERAGE REALIZATIONS

			2020		2019	2018
Liquids	(\$/bbl)	Consolidated subsidiaries	Equity-accounted entities	Consolidated subsidiaries	Equity-accounted entities	Consolidated subsidiaries	Equity-accounted entities
Italy		34.58		55.55		61.58
Rest of Europe		32.82	35.23	58.92	58.88	64.51
North Africa		38.33	18.16	57.91	18.06	65.95	17.92
Egypt		36.66		54.78		62.97
Sub-Saharan Africa		39.99	17.13	63.45	23.72	68.76	39.48
Kazakhstan		37.37		59.06		66.78
Rest of Asia		37.69		62.81		68.35	49.86
Americas		33.03	27.20	54.00	59.94	57.22	54.86
Australia and Oceania		17.45		52.93		68.72
		37.56	34.21	59.62	55.93	65.79	45.19

Natural gas	(\$/kcf)
Italy		3.16		5.03		8.37
Rest of Europe		3.12	3.25	4.95	5.07	7.99
North Africa		4.33	6.29	6.21	7.23	4.97	3.58
Egypt		4.78		5.11		4.85
Sub-Saharan Africa		2.76	3.94	2.94	6.16	2.38	9.50
Kazakhstan		0.69		0.81		0.77
Rest of Asia		4.09		5.94		6.11	9.32
Americas		2.10	4.37	2.46	4.32	2.38	4.28
Australia and Oceania		3.84		4.41		4.80
		3.77	3.73	4.94	4.94	5.17	5.59

Hydrocarbons (\$/boe) Italy 25.28 40.24 53.01 Rest of Europe 23.94 29.17 39.84 49.76 56.07 North Africa 30.28 19.36 44.86 19.39 43.34 18.14 Egypt 28.03 33.67 36.22 Sub-Saharan Africa 32.06 19.97 53.08 30.84 58.59 48.79 Kazakhstan 27.22 42.21 46.98 Rest of Asia 31.31 50.31 50.98 50.64 Americas 29.57 23.39 48.37 25.67 46.63 28.59 Australia and Oceania 20.35 26.32 28.99 29.20 27.33 43.73 41.71 48.04 33.63

ENI's GROUP	2020	2019	2018
Liquids (\$/bbl)	37.06	59.26	65.47
Natural gas (\$/kcf)	3.76	4.94	5.20
Hydrocarbons (\$/boe)	28.92	43.54	47.48

EXPLORATORY WELL ACTIVITY

		Net wells completed(a)						Wells in progress at Dec. 31(b)
		2020		2019		2018		2020
	(units)	productive	dry(c)	productive	dry(c)	productive	dry(c)	gross	net
Italy					0.5	1.8
Rest of Europe		0.8	0.4	0.3	1.4		0.5	16.0	3.3
North Africa		0.5	1.5	0.5			0.5	9.0	7.5
Egypt		0.7	1.5	4.5	1.5	1.7	1.5	15.0	11.8
Sub-Saharan Africa		0.1	0.9	0.5	0.9	0.4		33.0	17.8
Kazakhstan			1.1
Rest of Asia		0.8	0.9		1.7	2.2	2.6	11.0	4.5
Americas			0.6			4.0		1.0	0.8
Australia and Oceania					0.5			1.0	0.3
		2.9	6.9	5.8	6.5	10.1	5.1	86.0	46.0

DEVELOPMENT WELL ACTIVITY

	Net wells completed(a)					Wells in progress at Dec. 31
	2020		2019		2018		2020
(units)	productive	dry(c)	productive	dry(c)	productive	dry(c)	gross	net
Italy			3.0		3.0
Rest of Europe	2.8		3.3		2.8	0.3	24.0	5.0
North Africa	4.3		5.0	1.1	9.6	0.5	3.0	1.5
Egypt	23.2		33.5		30.7		3.0	1.4
Sub-Saharan Africa	1.2		7.0		7.3	0.1	5.0	0.9
Kazakhstan	0.3		0.9		0.9
Rest of Asia	23.2	0.4	27.3	2.2	21.9		17.0	3.4
Americas	2.0		2.1		2.3		6.0	2.0
Australia and Oceania					0.8
	57.0	0.4	82.1	3.3	79.3	0.9	58.0	14.2

PRODUCTIVE OIL AND GAS WELLS(d)

		2020
	(units)	Oil wells		Natural gas wells
		Gross	Net	Gross	Net
Italy		205.0	159.2	396.0	341.6
Rest of Europe		633.0	109.5	183.0	48.6
North Africa		612.0	258.1	127.0	67.9
Egypt		1,233.0	527.3	144.0	44.3
Sub-Saharan Africa		2,589.0	524.8	194.0	24.1
Kazakhstan		207.0	56.7	1.0	0.3
Rest of Asia		1,012.0	369.5	180.0	60.8
Americas		253.0	130.6	284.0	81.6
Australia and Oceania				2.0	2.0
		6,744.0	2,135.7	1,511.0	671.2

(a) Includes number of wells in Eni's share.

⁽b) Includes temporary suspended wells pending further evaluation.

⁽c) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well. (d) Includes 1,369 gross (349.0 net) multiple completion wells (more than one producing into the same well bore). Productive wells are producing wells and wells capable of production. One or more completions in the same bore hole are counted as one well.

RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2020
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	799	334	616		2,315	788	1,333	434	1	6,620
- sales to third parties		53	1,610	2,478	784	547	179	204	109	5,964
Total revenues	799	387	2,226	2,478	3,099	1,335	1,512	638	110	12,584
Production costs	(332)	(139)	(371)	(367)	(782)	(246)	(236)	(272)	(17)	(2,762)
Transportation costs	(4)	(30)	(39)	(11)	(21)	(164)	(4)	(12)		(285)
Production taxes	(111)		(135)		(295)		(133)	(13)		(687)
Exploration expenses	(19)	(14)	(124)	(56)	(77)	(3)	(104)	(112)	(1)	(510)
D.D. & A. and Provision for abandonment(b)	(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) Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni's share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to fulfil Eni's PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni's share of oil and gas production. (b) Includes asset net impairment amounting to €1,865 million.

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest	of Asia Americas	Australia and Oceania	Total
2019
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	1,493	618	1,081		4,576	1,195	2,367	825	5	12,160
- sales to third parties		30	4,084	3,715	944	766	149	180	227	10,095
Total revenues	1,493	648	5,165	3,715	5,520	1,961	2,516	1,005	232	22,255
Production costs	(391)	(181)	(520)	(330)	(847)	(255)	(256)	(273)	(43)	(3,096)
Transportation costs	(5)	(31)	(60)	(10)	(39)	(158)	(4)	(15)		(322)
Production taxes	(183)		(263)		(483)		(252)	(7)	(6)	(1,194)
Exploration expenses	(25)	(51)	(30)	(10)	(90)	(39)	(170)	(31)	(43)	(489)
D.D. & 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)
D.D. & 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)
D.D. & 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)
D.D. & 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 COSTS(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2020
Consolidated subsidiaries
Proved property	18,456	6,465	14,596	19,081	39,848	11,278	10,662	14,567	1,359	136,312
Unproved property	20	311	454	33	2,163	10	1,411	896	179	5,477
Support equipment and facilities	300	20	1,424	216	1,226	109	34	20	11	3,360
Incomplete wells and other	671	147	1,094	193	2,551	1,064	1,469	458	39	7,686
Gross Capitalized Costs	19,447	6,943	17,568	19,523	45,788	12,461	13,576	15,941	1,588	152,835
Accumulated depreciation, depletion and amortization	(15,565)	(5,597)	(12,793)	(12,161)	(32,248)	(2,839)	(9,003)	(12,612)	(805)	(103,623)
Net Capitalized Costs consolidated subsidiaries(b)	3,882	1,346	4,775	7,362	13,540	9,622	4,573	3,329	783	49,212
Equity-accounted entities
Proved property		11,466	68		1,384			1,833		14,751
Unproved property		2,131					11			2,142
Support equipment and facilities		23	8					6		37
Incomplete wells and other		1,566	9		17			209		1,801
Gross Capitalized Costs		15,186	85		1,401		11	2,048		18,731
Accumulated depreciation, depletion and amortization		(6,196)	(59)		(343)			(1,076)		(7,674)
Net Capitalized Costs equity accounted entities(b)		8,990	26		1,058		11	972		11,057
2019
Consolidated subsidiaries
Proved property	17,643	6,747	15,512	20,691	43,272	12,118	11,434	15,912	1,360	144,689
Unproved property	18	323	502	34	2,361	11	1,592	979	194	6,014
Support equipment and facilities	384	21	1,549	225	1,328	116	36	23	12	3,694
Incomplete wells and other	635	103	1,362	359	2,541	1,165	1,006	457	43	7,671
Gross Capitalized Costs	18,680	7,194	18,925	21,309	49,502	13,410	14,068	17,371	1,609	162,068
Accumulated depreciation, depletion 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(b)	4,076	1,416	6,123	8,430	16,265	10,758	4,968	3,906	855	56,797
Equity-accounted entities
Proved property		11,223	71		1,511		2	1,987		14,794
Unproved property		2,260					11			2,271
Support equipment and facilities		19	8					7		34
Incomplete wells and other		945	7		15		19	229		1,215
Gross Capitalized Costs		14,447	86		1,526		32	2,223		18,314
Accumulated depreciation, depletion and amortization		(5,287)	(61)		(323)		(20)	(1,124)		(6,815)
Net Capitalized Costs equity accounted entities(b)(c)		9,160	25		1,203		12	1,099		11,499

(a) Capitalized costs represent the total expenditures for proved and unproved mineral properties and related support equipment and facilities utilized in oil and gas exploration and production

activities, together with related accumulated depreciation, depletion and amortization.

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

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

COSTS INCURRED(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan	Africa Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
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 €516 million in 2020, €2,069 million in 2019, negative for €517 million in 2018.

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

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

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

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS1

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

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

(1) 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 2020, 2019 and 2018. 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.

45

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

(€ 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

	(€ million)	2020	2019	2018
Acquisition of proved and unproved properties		57	400	869
North Africa		55	135
Egypt		2	1
Rest of Asia			23	869
Americas			241
Exploration		283	586	463
Italy				1
Rest of Europe		9	43	52
North Africa		42	71	20
Egypt		48	86	80
Sub-Saharan Africa		20	128	22
Kazakhstan		4	7
Rest of Asia		124	141	140
Americas		36	74	146
Australia and Oceania			36	2
Development		3,077	5,931	6,506
Italy		229	289	380
Rest of Europe		107	110	600
North Africa		220	536	525
Egypt		393	1,481	2,205
Sub-Saharan Africa		624	1,406	1,635
Kazakhstan		178	371	193
Rest of Asia		916	1,028	550
Americas		402	695	381
Australia and Oceania		8	15	37
Other expenditure		55	79	63
		3,472	6,996	7,901

Global Gas & LNG Portfolio

KEY PERFORMANCE INDICATORS

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

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

The Global Gas & LNG Portfolio business (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. In recent years Eni renegotiated a number of the main longterm supply contracts, thus better aligning gas prices and related trends to market conditions.

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 2020, Eni's consolidated subsidiaries supplied 62.16 bcm of natural gas, down by 8.26 bcm or by 11.7% from the full year 2019.

Gas volumes supplied outside Italy from consolidated subsidiaries (54.69 bcm), imported in Italy or sold outside Italy, represented approximately 88% of total supplies, decreased by 10.16 bcm or by 15.7% from the full year 2019. This mainly reflected lower volumes purchased in the Netherlands (down by 3.01 bcm), in Russia (down by 1.87 bcm), Algeria (down by 1.44 bcm), in Libya (down by 1.42 bcm), partly offset by higher purchases in Norway (up by 0.76 bcm). Supplies in Italy (7.47 bcm) increased by 34.1% from the full year 2019.

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

In a 2020 scenario characterized by a raising competitive pressure and lower gas demand (about down by 5% and 3% in Italy and in the European Union, respectively, compared to 2019), natural gas sales amounted to 64.99 bcm (including Eni's own consumption, Eni's share of sales made by equityaccounted entities), down by 7.86 bcm or 10.8% from the previous year due to the economic downturn caused by the COVID-19 pandemic, with lower volumes marketed to thermoelectric and industrial segments.

GAS SALES BY MARKET

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

Sales in Italy (37.30 bcm) decreased by 1.8% from 2019 mainly driven by lower sales to thermoelectrical and industrial segments, partly offset by higher sales to hub. Sales to importers in Italy (3.67 bcm) decreased by 16% from 2019 due to the lower availability of Libyan gas.

decrease of 13.5% or 3.02 bcm from 2019. Sales in the Extra European markets of 4.69 bcm decreased by 3.46 bcm or 42.5% from the previous year, due to lower volumes in the United States and lower LNG sales in the Far East markets. A review of Eni's presence in key European markets is presented below:

Sales in the European markets amounted to 19.33 bcm, a

The percentage represents Eni's interest in each subsidiary as of December 31, 2020.

Benelux

Eni operates in Benelux in the industrial, wholesalers and thermoelectric segments, in 2020 sales amounted to 3.58 bcm, down by 0.20 bcm, or 5.3% compared to 2019, mainly due to lower volumes marketed to industrial and thermoelectric segments, partly offset by optimization actions.

France

Eni operates in all business segments through its direct commercial activities and through its subsidiary Eni Gas & Power France SA. In 2020 sales in the Country amounted to 5.01 bcm, an increase of 0.54 bcm, or 12.1%, from a year ago, mainly due to portfolio optimization.

Germany/Austria

Eni operates in the German natural gas market. Overall, in 2020, total sales in Germany and Austria amounted to 0.35 bcm, a decrease of 1.84 bcm, or 84% from 2019 due to the optimization of portfolio activities and lower volumes marketed to local distribution company.

Spain

In 2020, Eni operated in the Spanish gas market through the JV Unión Fenosa Gas (UFG) (Eni's interest 50%) engaged in supply and marketing of natural gas to industrial clients, wholesalers and power generation utilities. In 2020, total Eni's sales in the Iberian Peninsula amounted to 3.94 bcm, a decrease of 0.28 bcm, or down by 6.6% compared to 2019.

Turkey

Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2020, sales amounted to 4.59 bcm, a decrease of 0.97 bcm, or 17.4% from a year ago due to lower sales to Botas.

United Kingdom

Eni, through its subsidiary Eni Trading & Shipping SpA (ETS), markets in the United Kingdom the equity gas produced at Eni's fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF).

In 2020, sales amounted to 1.62 bcm, down by 0.13 bcm or down by 7.4% compared to 2019 due to lower volumes sold to industrial customers.

1.2 LNG

Eni is present in all phases of the LNG business: liquefaction, gas feeding, shipping, regasification and sale through a direct presence and interests in joint ventures and associates.

In order to expand the business, in February 2021, restarted LNG production at the Damietta liquefaction plant (Eni's interest 50%), coherently with a series of agreements finalized in March 2021 with the Arab Republic of Egypt (ARE) and the Spanish partner Naturgy for the resolution of all pending issues and restart the terminal, which was shut down in 2012. Furthermore, Eni will take over the contracts for the purchase of natural gas for the plant, receiving the corresponding liquefaction rights and will allow Eni to directly enter the Spanish gas market, strengthening its presence in the European gas. The restart of the plant, with a capacity of 7.56 billion cubic meters per year, enables Eni to strengthen its strategic objectives in terms of growth of its LNG portfolio and presence in the Eastern Mediterranean region.

In 2020, LNG sales (9.5 bcm, included in the worldwide gas sales) decreased by 5.9% from 2019 and mainly concerned LNG from Qatar, Nigeria, Indonesia and Oman and marketed in Europe, China, Pakistan and Taiwan.

2. INTERNATIONAL TRANSPORT

MAIN GAS TRANSPORT INFRASTRUCTURE IN EUROPE(*)

Eni, as shipper, has 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 participates to both entities which operate the pipelines and entities which manage transport rights. 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 an 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. It is part of a joint venture to sell gas produced in Russia on the Turkish market. These assets generate a steady operating profit thanks to the sale of transport rights on a long-term basis.

SUPPLY OF NATURAL GAS

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

GAS SALES BY ENTITY

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

LNG SALES

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

TRANSPORT INFRASTRUCTURE

Infrastructures	Lines (units)	Lenght (km)	Diameter (inch)	Transport capacity (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

CAPITAL EXPENDITURE

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

54

Refining & Marketing and Chemicals

KEY PERFORMANCE INDICATORS

		2020	2019	2018
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.80	0.27	0.56
of which: employees		1.17	0.24	0.49
contractors		0.48	0.29	0.62
Sales from operations(a)	(€ million)	25,340	42,360	46,483
Operating profit (loss)		(2,463)	(682)	(501)
Adjusted operating profit (loss)		6	21	360
- Refining & Marketing		235	289	370
- Chemicals		(229)	(268)	(10)
Adjusted net profit (loss)		(246)	(42)	224
Capital expenditure		771	933	877
Bio throughputs	(ktonnes)	710	311	253
Capacity of biorefineries	(mmtonnes/year)	1.1	1.1	0.4
Average biorefineries utilization rate	(%)	63	44	63
Conversion index of oil refineries		54	54	54
Balanced capacity of refineries (Eni's share)	(kbbl/d)	548	548	548
Average oil refineries utilization rate	(%)	69	88	91
Retail sales of petroleum products in Europe	(mmtonnes)	6.61	8.25	8.39
Service stations in Europe at year end	(number)	5,369	5,411	5,448
Average throughput per service station in Europe	(kliters)	1,390	1,766	1,776
Retail efficiency index	(%)	1.22	1.23	1.20
Production of petrochemical products	(ktonnes)	8,073	8,068	9,483
Sale of petrochemical products		4,339	4,295	4,946
Average petrochemical plant utilization rate	(%)	65	67	76
Employees at year end	(number)	11,471	11,626	11,457
- of which outside Italy		2,556	2,591	2,594
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	6.65	7.97	8.19
GHG emissions (Scope 1)/refinery throughputs (raw and semi-finished materials)	(tonnes CO2 eq./ktonnes)	248	248	253

(a) 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. The business is also active in marketing of 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 as well as 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 and biotech.

REFINING & MARKETING

PRODUCTION CYCLE OF REFINED PRODUCTS

1. REFINING

Eni is active in the refining business in Italy and abroad. In 2020, Eni refinery capacity (balanced with conversion capacity) was approximately 27.4 mmtonnes (equal to 548 kbbl/d), with a conversion index of 54%.

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

19.4 mmtonnes (equal to 388 kbbl/d), with a 55% conversion index.

In 2020, Eni's refineries throughputs in Italy and outside Italy were 17 mmtonnes, slightly decreased from 2019 (down by 5.74 mmtonnes, or 25.2%).

REFINING SYSTEM IN 2020

	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	66	55	34	40	71	29
Italy
Sannazzaro	100	200	61	73	34	14	51	29
Taranto	100	104	73	56		26	20
Livorno	100	84	72	11
Partially-owned refineries		160	76	52	143	25	75	27
Italy
Milazzo	50	100	78	60	45	25	32
Germany
Vohburg/Neustadt (Bayernoil)	20	41	63	36	49		43
Schwedt	8.33	19	94	42	49			27
TOTAL		548	69	54	177	65	146	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).

(c) Conversion unit capacities are 100%.

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 73%. 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, 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% stake in the Schwedt refinery (PCK) and an interest of 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.

BIOREFINERIES

	Ownership share	Capacity (2020)	Throughput (2020)
Wholly owned	(%)	(mmtonnes/y)	(mmtonnes/y)
Venezia	100	0.4	0.2
Gela	100	0.7	0.5
Total		1.1	0.7

Venice (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. A second phase of development is underway to achieve a full capacity of 0.56 mmtonnes/y. At full capacity, the refinery production will satisfy approximately half of Eni biofuels needs required for being compliant with the EU environmental normative aimed at reducing CO2 emissions.

Gela: reached full operation at Gela biorefinery in 2020, with a five-fold increase in biofuel productions compared to 2019, 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. The ramp-up of the plant is a step forward along the path to decarbonization of Eni's activities. In March 2021, started the Biomass Treatment Unit (BTU) to expand the range of charges to be processed by the plant, allowing the replacement of palm oil with other sustainable sources.

PRODUCTION CYCLE OF BIOFUELS

DEVELOPMENT OF THE CIRCULAR ECONOMY IN BIOFUELS

In March 2021, Eni signed an agreement to acquire the FRI-EL Biogas Holding company, a leader in the Italian biogas production sector.

This acquisition sees Eni strengthening its growth in the circular economy, laying the foundations to become the first producer of biomethane in Italy.

The agreement is subject to the authorisation of the relevant Antitrust authorities. Furthermore, this accord is in line with Eni's decarbonization strategy and will allow an increase in Eni service stations that will supply CNG (Compressed Natural Gas) and LNG (Liquefied Natural Gas).

The start-up in March 2021 of the biomass treatment unit (BTU) at the Gela biorefinery will enable to produce biodiesel, bionaphtha, bioLPG and biojet from biomass from used cooking oil and fats from fish and meat processing produced in Sicily (therefore not in competition with the food chain) to create a zero-kilometre circular economy model.

The new plant contributes with other ongoing projects, such as the use of castor oil from crops on semi-desert land in Tunisia, to achieve the goal of zeroing palm oil as feedstock for biorefineries from 2023.

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 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 0.8 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About 75% 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 25% is purchased.

MARKETING

gasoline and gasoil throughput (1,206 kliters) down by 380 kliters. As of December 31, 2020, Eni's retail network in Italy consisted of 4,134 service stations, lower by 50 units from December 31, 2019 (4,184 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (46 units), closure of low throughput stations (3 units) and a decrease of 1 motorway concession.

2. RETAIL SALES IN THE REST OF EUROPE

1. RETAIL SALES IN ITALY

Eni is a leader in the Italian retail market of refined products with a 23.3% market share, slightly decreased from 2019 (23.6%). In 2020, retail sales in Italy were 4.56 mmtonnes, with a decrease compared to 2019 (1.25 mmtonnes or down by 21.5%) as consequence of the restrictive measures implemented mainly in the second quarter during the pandemic peak. Average Retail sales in the rest of Europe were 2.05 mmtonnes, recorded a reduction from 2019 (down by 16%) mainly due to the restrictive measures adopted against COVID-19 in the second quarter during the pandemic peak.

At December 31, 2020, Eni's retail network in the rest of Europe consisted of 1,235 units, increasing by 8 units from December 31, 2019, mainly in Germany and France. Average throughput (1,980 kliters) decreased by 376 kliters compared to 2019 (2,356 kliters).

RETAIL AND WHOLESALE BUSINESSES IN EUROPE - 2020 ENI'S COMPETITIVE POSITION

3. WHOLESALE BUSINESS

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

Wholesale sales in Italy amounted to 5.75 mmtonnes, decreasing by 25.1% from the full year of 2019, due to the contraction of industrial activity and in particular, for lower sales of jet fuel following a deep crisis of the airlines sector.

Supplies of feedstock to the petrochemical industry (0.61 mmtonnes) decreased by 26.5%.

Wholesale sales in the Rest of Europe were 2.40 mmtonnes, down by 8.7% from 2019 due to lower sold volumes mainly in Spain, partly offset by higher volumes marketed in Germany for higher product availability due to the restart of Vohburg plant. Other sales in Italy and outside Italy (10.23 mmtonnes) decreased by 2.17 mmtonnes or down by 17.5% mainly due to lower volumes sold to oil companies.

The marketing of LPG in Italy is supported by the Eni's refining production logistic network made of three 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 2020, Eni share of LPG market in Italy was 15.3%.

Outside Italy, the main market of Eni is Ecuador, with a market share of 37.4%.

Eni operates five (owned and co-owned) blending and filling plants, in Italy, Spain, Germany, Africa and in the Far East. With a wide range of products composed of over 650 different blends Eni masters international state of the art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, grease, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases, manufactured at Eni's refinery in Livorno. Eni also owns one facility for the production of additives in Robassomero (Turin).

In 2020, Eni's share of lubricants market in Italy was 21%, 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

Beginning in 2013, Eni provides the vehicle sharing service with the brand Enjoy 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 service also offers the opportunity of renting cargo vehicles (Enjoy Cargo), within the covered service area for the shared transport of "goods".

At December 31, 2020 the Enjoy fleet consisted of approximately 2,500 FIAT 500 cars and 100 FIAT Cargo vehicles distributed over the major Italian cities (Milan 1,037 FIAT 500 and 40 Cargo; Rome 905 FIAT 500 and 40 Cargo; Turin 312 FIAT 500 and 10 Cargo; Bologna 148 FIAT 500 e 10 Cargo; Florence 98 FIAT 500). The average number of rentals in the year was 200,000/monthly, recording a remarkable decline compared to 2019, due to COVID-19 pandemic.

In 2021, the process of replacing the car fleet with hybrid cars was started, in line with Eni's strategy on sustainable mobility.

PURCHASES

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

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

AVAILABILITY OF REFINED PRODUCTS

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

PRODUCTION AND SALES

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

SALES OF REFINED PRODUCTS BY MARKET

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

SALES BY PRODUCT/MARKET

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

SERVICE STATIONS

	2020	2019	2018
Italy (units)	4,134	4,184	4,223
Ordinary stations	4,019	4,068	4,108
Highway stations	115	116	115
Outside Italy	1,235	1,227	1,225
Germany	480	476	471
France	158	155	155
Austria/Switzerland	597	596	599
Service stations selling premium products	4,619	4,669	4,675
of which service stations selling Biodiesel	3,663	3,683	3,537
"Multi-Energy" service stations	4	4	4
Service stations selling LPG and natural gas	1,091	1,086	1,043
NON-OIL SALES (€ million)	148	156	144

AVERAGE THROUGHPUT

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

MARKET SHARES IN ITALY

	(%) 2020	2019	2018
Retail	23.3	23.6	24.0
Gasoline	20.3	19.8	20.2
Gasoil	24.9	25.4	25.7
LPG (automotive)	20.8	22.9	23.6
Wholesale	23.5	25.0	24.8
Gasoil	24.6	23.6	22.3
Fuel oil	4.6	10.9	12.8
Bunker	21.4	24.3	24.9
Lubricants	21.1	20.0	18.8

RETAIL MARKET SHARES OUTSIDE ITALY

	(%)	2020	2019	2018
Central Europe
Austria		12.4	12.3	12.3
Switzerland		6.7	7.7	7.8
Germany		3.1	3.2	3.2
France		0.7	0.6	0.8

CAPITAL EXPENDITURE

(€ million)	2020	2019	2018
Italy	535	743	661
Outside Italy	53	72	65
	588	815	726
Refining, supply and logistic	462	683	587
Italy	449	662	578
Outside Italy	13	21	9
Marketing	126	132	139
Italy	86	81	83
Outside Italy	40	51	56
TOTAL	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 (312), 14 production sites, 6 research centers (Ferrara, Mantova, Novara, Porto Torres, Ravenna, Rivalta), as well as a large and efficient retail network located in 30 different Countries.

In 2021, Versalis has licensed to Enter Engineering Pte Ltd a Low Density Polyethylene/Ethyl Vinyl Acetate (LDPE/ EVA are ethylene polymers and co-polymers possessing a suitable balance between processability and mechanical properties) swing unit to be built as part of a new Gas to Chemical Complex based on MTO-Methanol to Olefins technology to be located in the Karakul area in the Bukhara region of the Republic of Uzbekistan.

Another example of technological success was the application at the Crescentino site of an advanced proprietary technology aimed at the production of a bioethanol disinfectant from corn glucose syrup, based on the formulation provided by the WHO for medical applications.

Finally in July 2020, was finalized the acquisition of a 40% interest in Finproject, a company engaged in the production of high-performance polymers, increasing exposure to products more resilient to the volatility of the chemical. This initiative allows Eni to exploit value from the integration of Finproject's positioning in the market of high value added applications with the industrial and technological leadership of Versalis.

THE PRODUCTION CYCLE

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

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 is also committed to developing biotechnologies and circular economy processes to meet regulatory and environmental challenges.

In this regard during 2021 was implemented on an industrial scale the technologies of plastic waste recycling thanks to the alliance with Forever Plast in order to develop and market a new range of solid polystyrene products made from reused packaging.

An agreement was also signed with AGR, an Italian company owner of a proprietary technology to treat used elastomers, to develop and market new products and applications in recycled rubber, and with COREPLA (National Consortium for the Collection, Recycling and Recovery of Plastic Packaging) to develop effective solutions to reutilize plastics, applying Eni's expertise in the fields of gasification and chemical recycling by means of pyrolysis.

Furthermore, Versalis joined the Circular Plastics Alliance (CPA)

to contribute to the European target of using 10 million tonnes of recycled plastic in new products by 2025. The mission of this alliance, promoted by the European Commission, is to promote the recycling of plastic in Europe and at the same time to develop the market of second raw materials.

True to commitment in the development of green chemistry from renewable sources, in 2021 Versalis entered the market of agricultural protection, thanks to the alliance with AlphaBio Control, a research and development company engaged in the production of natural formulations for the protection of crops, aimed at the production of herbicides and biocides for the disinfection of plant-based and biodegradable surfaces, using the active ingredients produced from the chemistry from the renewable sources platform of Porto Torres.

INTEGRATED PLATFORM FOR PLASTIC WASTE RECYCLING

VERSALIS' INTERNATIONAL PRESENCE

Denmark, Sweden, Spain, Greece and Angola), coordinates the companies in Turkey, America (United States and Mexico), Africa (Congo and Ghana), Asia (China and Singapore) and the joint venture in Abu Dhabi and delivers services to manufacturing companies in France, Germany, Hungary and UK.

Business areas

In 2020 sales of chemical products amounted to 4,339 ktonnes, slightly increased from 2019 (up by 44 ktonnes, or 1%) thanks to the positive performance reported in the intermediate, styrenics and polyethylene segments, due to the accelerated economic recovery in the fourth quarter, mainly in Asia and lower competitive pressure, partly mitigated by the generalized reduction in volumes during the pandemic peak in the second quarter and by the global economic downturn which affected all the main end-markets, particularly the automotive sector, and the subsequent conservative position of operators which induced to decrease storage.

Average sale prices of the intermediates business decreased by 23.3% from 2019, with aromatics and olefins down by 36.4% and 25.4%, respectively. The polymers reported a decrease of 15% from 2019.

Petrochemical production of 8,073 ktonnes were substantially unchanged from 2019 (up by 5 ktonnes) mainly due to higher production of intermediates business (up by 43 ktonnes), in particular olefins, partly offset by the reduced elastomers and polyethylene productions (down by 23 ktonnes and down by 18 ktonnes, respectively).

The main decreases in production were registered at the Priolo site

(down by 207 ktonnes), due to the prolonged planned shutdown and at Brindisi (down by 33 ktonnes); these reductions were offset by higher volumes at Porto Marghera plant (up by 246 ktonnes). Plants nominal capacity slightly decreased from the 2019. The average plant utilization rate, calculated on nominal capacity was 65%, decreasing from 2019 (67%) following the aforementioned shutdowns.

INTERMEDIATES

Intermediates revenues (€1,385 million) decreased by €406 million from 2019 (down by 22.7%) reflecting both the lower commodity prices scenario and the lower product availability due to the standstills occurred in 2020.

Sales increased, in particular for aromatics (up by 2.4%), olefins (up by 0.8%) following the higher product availability. Average unit prices decreased by 23.3%, in particular aromatics (down by 36.4%), olefins (down by 25.4%) and derivatives (down by 5.9%). Intermediates production (5,861 ktonnes) registered an increase of 0.7% from 2019. Increases were recorded in olefins (up by 1.7%) and decreases in derivatives (down by 3.9%) and in aromatics (down by 0.8%).

POLYMERS

Polymers revenues (€1,888 million) decreased by €313 million or 14.2% from 2019 due to the decrease of the average unit prices (down by 15%). The styrenics business benefitted of the increase of volumes sold (up by 4.0%) for higher product availability; decrease of sale prices (down by 16.0%). Polyethylene volumes increased (up by 2.0%) for higher demand. Average prices decreased by 13.4%. In the elastomers business, a decrease of sold volumes (down by 4.6%) was attributable to lattices (down by 8.4%), EPR (down by 6.5%), TPR (down by 4.8%), SBR rubbers (down by 4.6%) and BR (down by 3.0%). Higher styrenics volumes sold (up by 4.0%) were mainly attributable to ABS (up by 7.8%), expandable polystyrene (up by 5.1%) and compact polystyrene (4.5%), these higher volumes were partly offset by lower sales of styrene (down by 12.7%). Overall, the sold volumes of polyethylene business reported an increase (up by 2.0%) with higher sales of LDPE and EVA (up by 4.6% and 7.3%, respectively), while volumes of LLDPE decreased (down by 2.3%). In addition, average sales prices decreased (down by 13.4%). Polymers productions (2,212 ktonnes) decreased from the 2019 due to the lower productions of elastomers (down by 6.7%), polyethylene (down by 1.9%).

PRODUCT AVAILABILITY

(ktonnes)	2020	2019	2018
Intermediates	5,861	5,818	7,130
Polymers	2,212	2,250	2,353
Production	8,073	8,068	9,483
Consumption and losses	(4,366)	(4,307)	(5,085)
Purchases and change in inventories	632	534	548
TOTAL AVAILABILITY	4,339	4,295	4,946
Intermediates	2,549	2,529	3,095
Polymers	1,790	1,766	1,851
TOTAL SALES	4,339	4,295	4,946

REVENUES BY GEOGRAPHIC AREA

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

REVENUES BY PRODUCT

	(€ million)	2020	2019	2018
Olefins		879	1,168	1,667
Aromatics		191	293	340
Derivatives		259	279	365
Oilfield chemicals		56	51	29
Elastomers		452	567	665
Styrenics		534	611	749
Polyetilene		902	1,022	1,175
Other		114	132	133
		3,387	4,123	5,123

CAPITAL EXPENDITURE

(€ million)	2020	2019	2018
	182	118	151
of which:
- upkeeping	79	42	21
- plant upgrades	35	34	84
- HSE	39	27	26
- green and circular	7	4
- energy recovery	2	1	2

Eni gas e luce, Power & Renewables

KEY PERFORMANCE INDICATORS

		2020	2019	2018
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.32	0.62	0.60
of which: employees		0.00	0.30	0.31
contractors		0.73	0.95	1.16
Sales from operations(a)	(€ million)	7,536	8,448	8,218
Operating profit (loss)		660	74	340
Adjusted operating profit (loss)		465	370	262
- Eni gas e luce		325	278	201
- Power & Renewables		140	92	61
Adjusted net profit (loss)		329	275	189
Capital expenditure		293	357	238
Eni gas e luce
Retail gas sales	(bcm)	7.68	8.62	9.13
Retail power sales to end customers	(TWh)	12.49	10.92	8.39
Retail customers	(million of POD)	9.57	9.42	9.19
Power & Renewables
Power sales in the open market	(TWh)	25.33	28.28	28.54
Thermoelectric production		20.95	21.66	21.62
Energy production sold from renewable sources	(GWh)	340	61	12
Renewables installed capacity at period end	(MW)	307	174	40
Employees at year end		2,092	2,056	2,056
of which outside Italy		413	358	337
Direct GHG emissions (Scope 1)	(mmtonnes CO2 eq.)	9.63	10.22	10.47
Direct GHG emissions (Scope 1)/equivalent produced electricity (Eni Power)	(gCO2 eq./kWh eq.)	391	394	402

(a) Before elimination of intragroup sales.

Eni gas e luce, Power & Renewables 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 electricity with a view to hedging/optimising the margins of the electricity.

ENI GAS E LUCE

Eni through its subsidiary Eni gas e luce SpA operates, directly or through subsidiaries, in the marketing of gas, power and services in Italy, France, Greece and Slovenia. It also operates in the business of natural gas distribution in Greece through a jointly controlled entity and Slovenia with a subsidiary.

In line with the target to increase the customer portfolio in Europe, in January 2021 was signed an agreement with Grupo Pitma for the 100% acquisition of Aldro Energía with a 250,000 customers portfolio mainly in Spain and Portugal and focused on small and medium-sized enterprises.

In addition, Eni gas e luce SpA continued its development of a series of extracommodity services in the 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.

In 2020, with the aim to support the digital evolution of the methods of interaction with the customer base (current and potential) and to prevent churn, Eni acquired a 20% interest in Tate Srl, a start-up operating in the activation and management of electricity and gas contracts through digital solutions. Furthermore, was launched a strategic partnership between Eni gas e luce and OVO targeting the residential market in France to raise customer awareness for a responsible use of energy and access to zero-emission technologies leveraging digitalization.

Finally, in line with the strategy of decarbonization and energy transition, in February 2020 was signed an agreement with Be Charge, a company of the Be Power Group SpA, aimed at the development of infrastructure for electric mobility, which provides for the nationwide installation of co-branded public charging stations for electric vehicles that will be powered by renewable energy supplied by Eni gas e luce.

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 9.6 million retail clients (gas and electricity) in Italy and Europe. In particular, clients located all over Italy are 7.7 million.

GAS SALES BY MARKET

(bcm)	2020	2019	2018
	5.17	5.49	5.83
	3.96	3.99	4.20
	0.70	0.87	0.79
	0.28	0.30	0.39
	0.23	0.33	0.45
	2.51	3.13	3.30
	2.08	2.69	2.94
	0.34	0.35	0.24
	0.09	0.09	0.12
	7.68	8.62	9.13

RETAIL GAS SALES

In 2020, natural gas sales in Italy and in the rest of Europe amounted to 7.68 bcm, down by 0.94 bcm or 10.9% from the previous year. Sales in Italy amounted to 5.17 bcm down by 5.8% compared to 2019, the reduction was mainly due to lower volumes marketed at small and medium enterprises and resellers segments; the reduction reported in the residential segment was mitigated by the positive weather effect mainly in the last quarter of the year.

Sales in the European markets (2.51 bcm) reported a reduction of 19.8% or 0.62 bcm compared to 2019. In France, sales decreased by 22.7% due to lower volumes marketed to industrial customers. In Greece and Slovenia sales were substantially in line with the comparative period.

RETAIL POWER SALES TO END CUSTOMERS

In 2020, retail power sales to end customers, managed by Eni gas e luce and the subsidiaries in France and Greece, amounted to 12.49 TWh, an increase by 14.4% from 2019, due to growth of retail customers portfolio (up by 270,000 customers vs. 2019) and higher volumes sold to the retail and industrial segments in Europe.

POWER

AVAILABILITY OF ELECTRICITY

Eni's power generation sites are located in Brindisi, Ferrera Erbognone, Ravenna, Mantova, Ferrara and Bolgiano. As of December 31, 2020, installed operational capacity of Enipower's power plants was 4.6 GW. In 2020, thermoelectric power generation was 20.95 TWh, substantially in line compared to 2019. Electricity trading (17.09 TWh) reported a decrease of 4.2% from 2019, thanks to the optimization of inflows and outflows of power.

POWER GENERATION

		2020	2019	2018
Purchases
Natural gas	(mmcm)	4,346	4,410	4,300
Other fuels	(ktep)	160	276	356
of which: steam cracking		88	91	94
Production
Power generation	(TWh)	20.95	21.66	21.62
Steam	(ktonnes)	7,591	7,646	7,919
Installed generation capacity	(GW)	4.6	4.7	4.7

POWER SALES IN THE OPEN MARKET

In 2020, power sales in the open market were 25.33 TWh, representing a reduction of 10.4% compared to 2019, due to economic downturn.

POWER SALES

	(TWh)	2020	2019	2018
Power generation		20.95	21.66	21.62
Trading of electricity(a)		17.09	17.83	15.45
Availability		38.04	39.49	37.07
POWER SALES IN THE OPEN MARKET		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 and operational generation capacity as of December 31, 2020: 4,619 MW.

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 22.6 TWh.

	Installed capacity as of	Effective/planned
Power stations	December 31, 2020(a) (MW)	start-up	Technology	Fuel
Brindisi	1,268	2006	CCGT	Gas
Ferrera Erbognone	1,052	2004	CCGT	Gas/syngas
Mantova	851	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
	4,619

(a) Installed operational capacity.

(b) Eni's share of capacity.

(c) Plants managed by Enipower Mantova.

RENEWABLES

Eni is engaged in the renewable energy business (solar and wind) through the business unit Energy Solutions aiming at developing, constructing and managing renewable energy producing plant.

Eni's targets in this field will be reached by leveraging on an organic development of a diversified and balanced portfolio of assets, integrated with selective asset acquisitions, as well as projects and international strategic partnership.

EXPANSION OF RENEWABLES BUSINESS

In 2020, the expansion in the international market was continued thanks to the strategic partnership with the Italian Group Falck; in particular, in the USA were developed the following initiatives: (i) in March was acquired a 49% share of Falck's photovoltaic plants in operation in the Country (57 MW net to Eni); (ii) in November was finalized the acquisition from Building Energy SpA of 62 MW of operating capacity (30.2 MW net to Eni) in wind and solar plants and a pipeline of wind projects up to 160 MW. Production in operation will avoid more than 93 ktonnes of CO2 emissions per year; and (iii) in the same month was acquired a 30 MW solar project "ready to build" in Virginia from Savion LLC (14.5 MW net to Eni). The plant will allow to avoid over 33 ktonnes of CO2 emissions per year. In July, Eni has started power production from the photovoltaic plant at Volpiano (total capacity of 18 MW), with an expected production of 27 GWh/y, avoiding 370 ktonnes of CO2 emissions over the service life of the plant.

In February 2021, signed an agreement with X-Elio, a Spanish leader company, for the acquisition of three photovoltaic projects located in the Southern region of Spain with a total capacity of 140 MW.

Relating to the wind segment, finalized the acquisition from Asja Ambiente of three wind projects for a total capacity of 35.2 MW expected to produce approximately 90 GWh/y, avoiding around 38 ktonnes of CO2 emissions per year. The plants, currently under construction, will be completed in 2021.

In 2020, signed a Sale and Purchase Agreement for the acquisition from Equinor and SSE Renewables of a 20% share of the offshore wind project Dogger Bank (A and B) in the United Kingdom, which will be the largest wind power facility in the world. This transaction was finalized at the end of February 2021.

SOLAR AND WIND POWER INSTALLED CAPACITY

ENERGY FROM RENEWABLE SOURCES

(GWh)	2020	2019	2018
Energy production from renewable sources	339.6	60.6	11.6
of which: photovoltaic	223.2	60.6	11.6
wind	116.4
of which: Italy	112.2	53.5	11.6
Outside Italy	227.5	7.3
of which: own consumption(a)	23%	60%	75%
Renewables installed capacity at period end	307	174	40
of which: photovoltaic	77%	76%	100%
wind	20%	20%
installed storage capacity	3%	4%

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

Energy production from renewable sources amounted to 339.6 GWh (of which 223.2 GWh photovoltaic and 116.4 GWh wind) up by 279 GWh compared to 2019.

The increase in production compared to the previous year benefitted from the entry in operations of new capacity, as well as the contribution of assets already operating in the United States, acquired in 2020.

At the end of 2020, the total installed and sanctioned capacity amounted to 1 GW: the total installed capacity for the generation of energy from renewable sources amounted to 307 MW (in Eni share and including the storage power), of which about 84 MW in Italy and 223 MW abroad, with 30 plants in operation; the capacity under construction/advanced stage of development amounted to about 0.7 GW and mainly relating to the Dogger Bank A and B offshore wind projects in the UK (480 MW in Eni share) and the new capacity in Kazakhstan (98 MW, of which 48 MW onshore wind and 50 MW solar photovoltaic).

Follows breakdown of the installed capacity by Country and technology:

INSTALLED CAPACITY AT PERIOD END (ENI'S SHARE)

	(megawatt) (% Eni's share)	(technology)	2020	2019	2018
ITALY			84	82	35
Assemini (CA)	100	fotovoltaic (fixed)	23	23	23
Porto Torres (SS)	100	fotovoltaic (fixed)	31	31
Volpiano (TO)	100	fotovoltaic (fixed)	18	16
Gela - ISAF (CL)	100	fotovoltaic (fixed)	5	5	5
Other plants (10 plants)	100	fotovoltaic (tracker/fixed)	7	7	7
OUTSIDE ITALY			223	92	5
Algeria - BRN	50	fotovoltaic (fixed)	5	5	5
Kazakhstan - Badamsha	100	onshore wind	48	34
Australia - Katherine	100	fotovoltaic (tracker + storage)	39	39
Australia - Batchelor & Manton	100	fotovoltaic (tracker)	25
Pakistan - Bhit	100	fotovoltaic (tracker)	10	10
Tunisia - Adam	50	fotovoltaic (tracker + storage)	4	4
Tunisia - Tataouine	50	fotovoltaic (tracker)	5
United States (11 plants)	49	fotovoltaic (tracker/fixed) and onshore wind	87
TOTAL INSTALLED CAPACITY AT PERIOD END (INCLUDING INSTALLED STORAGE POWER)			307	174	40
of which installed storage power			8	7
PLANTS IN OPERATION AT PERIOD END			30	15	12

ITALY

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 reclaimed and available for use, owned by the Group.

As of today, in Italy, Eni has 15 plants in operation and total installed capacity amount to 84 MW:

• Porto Torres (SS), 31 MW: the plant was completed at the end of 2019 and inaugurated at the beginning of 2020. Currently, this plant is the biggest photovoltaic site realized by Eni in Italy, on a site owned by Eni Rewind.
• Assemini (CA), 23 MW: the plant is located in the heritage site of Sulcis-Iglesiente and the Assemini site area in Sardinia. Land is owned by Eni Rewind and its subsidiary Luigi Conti Vecchi.
• Volpiano (TO), 18 MW: the plant is located in the industrial area of Eni R&M depot and storage in Piemonte.
• Other plants for a total of 12 MW, including Ferrera Erbognone and Gela-Isola 10 (1 MW each) built in 2018 on land owned by Group companies.

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, under the partnership with Cassa Depositi e Prestiti Equity (CDPE), in February 2021 was established GreenIT (Eni's interest 51% and CDPE's interest 49%). The JV leveraging on the CDPE's high institutional profile and Eni's technical capabilities and know-how will develop new renewable energy projects in Italy by exploiting unused areas, minimizing land consumption destined for other uses (including areas in the Public Property) with the target of reaching an installed capacity of approximately 1,000 MW by 2025, with cumulative investments amounting to over €800 million in the five-year period.

OUTSIDE ITALY

Kazakhstan

Eni entered the renewable energy production sector in the Country with the construction of the Badamsha wind farm (48 MW). The initiative represented Eni's first project development in the onshore wind energy sector. Currently, Eni is building a new wind farm (48 MW) in the region of Badamsha, and a 50 MW photovoltaic plant at Shauldir, in the Southern of Kazakhstan. The completion of the photovoltaic plant is expected in 2021.

Australia

Katherine's photovoltaic park (34 MW) 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. During 2020, in the Northern Territory, Eni has installed additional solar capacity for a total of 25 MW at the Bachelor and Manton Dam sites.

United States

In 2020, Eni acquired a 49% share of the assets already managed by Falck Renewables in the Country (57 MW net to Eni). The JV, established as part of the partnership agreements with Falck, already in operation has increased its capacity with the acquisition of the Building Energy US plants at the end of 2020 (62 MW in Iowa and Maryland, 30 MW net to Eni) and with the acquisition of a 30 MW solar project in Virginia (15 MW net to Eni), currently under construction and expected to be completed in 2021.

United Kingdom

At the end of 2020 Eni signed a Sale and Purchase Agreement for the acquisition of a 20% share of the offshore wind project Dogger Bank (A and B) which involves the installation of 190 state-of-the-art 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 sees Eni enter the Northern Europe offshore wind market, one of the most promising and stable in the world, with two partners (Equinor and SSE) that have extensive experience in the sector, and with whom it will be able to enhance its own expertise in the construction and operation of offshore wind farms for future projects in other areas as well.

CAPITAL EXPENDITURE

(€ million)	2020	2019	2018
- Eni gas e luce	175	173	143
- Power	52	42	46
- Renewables	66	142	49
TOTAL CAPITAL EXPENDITURE	293	357	238

Tables

FINANCIAL DATA

PROFIT AND LOSS ACCOUNT

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

SALES FROM OPERATIONS

	(€ million)	2020	2019	2018
Exploration & Production		13,590	23,572	25,744
Global Gas & LNG Portfolio		7,051	11,779	14,807
Refining & Marketing and Chemicals		25,340	42,360	46,483
EGL, Power & Renewables		7,536	8,448	8,218
Corporate and other activities		1,559	1,676	1,588
Consolidation adjustments		(11,089)	(17,954)	(21,018)
		43,987	69,881	75,822

SALES TO CUSTOMERS

	(€ million)	2020	2019	2018
Exploration & Production		6,359	10,499	9,943
Global Gas & LNG Portfolio		5,362	9,230	11,931
Refining & Marketing and Chemicals		24,937	41,976	46,088
EGL, Power & Renewables		7,135	7,972	7,684
Corporate and other activities		194	204	176
Impact of unrealized intragroup profit elimination
		43,987	69,881	75,822

SALES BY GEOGRAPHIC AREA OF DESTINATION

	(€ million)	2020	2019	2018
Italy		14,717	23,312	25,279
Other EU Countries		9,508	18,567	20,408
Rest of Europe		8,191	6,931	7,052
Americas		2,426	3,842	5,051
Asia		4,182	8,102	9,585
Africa		4,842	8,998	8,246
Other areas		121	129	201
Total outside Italy		29,270	46,569	50,543
		43,987	69,881	75,822

SALES BY GEOGRAPHIC AREA OF ORIGIN

(€ million)	2020	2019	2018
Italy	29,116	46,763	51,733
Other EU Countries	5,508	7,029	8,004
Rest of Europe	1,226	1,909	2,496
Americas	1,838	3,290	3,627
Africa	846	1,068	1,165
Asia	5,271	9,587	8,599
Other areas	182	235	198
Total outside Italy	14,871	23,118	24,089
	43,987	69,881	75,822

PURCHASES, SERVICES AND OTHER

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

PRINCIPAL ACCOUNTANT FEES AND SERVICES

	(€ thousand)	2020	2019	2018
Audit fees		19,605	15,748	25,445
Audit-related fees		1,412	1,045	1,628
		21,017	16,793	27,073

PAYROLL AND RELATED COSTS

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

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

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

OPERATING PROFIT BY SEGMENT

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

FINANCE INCOME (EXPENSE)

(€ million)	2020	2019	2018
Finance income (expense) related to net borrowings	(913)	(962)	(627)
- Interest expense on corporate bonds	(517)	(618)	(565)
- Net income from financial activities held for trading	31	127	32
- Interest expense for banks and other financing istitutions	(102)	(122)	(120)
- Interest expense for lease liabilities	(347)	(378)
- Interest from banks	10	21	18
- Interest and other income from receivables and securities for non-financing operating activities	12	8	8
Income (expense) from derivative financial instruments	351	(14)	(307)
- Derivatives on exchange rate	391	9	(329)
- Derivatives on interest rate	(40)	(23)	22
Exchange differences, net	(460)	250	341
Other finance income (expense)	(96)	(246)	(430)
- Interest and other income from receivables and securities for financing operating activities	97	112	132
- Finance expense due to the passage of time (accretion discount)	(190)	(255)	(249)
- Other finance income (expense)	(3)	(103)	(313)
	(1,118)	(972)	(1,023)
Finance expense capitalized	73	93	52
	(1,045)	(879)	(971)

INCOME (EXPENSE ON) FROM INVESTMENTS

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

SUMMARIZED GROUP BALANCE SHEET

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

PROPERTY, PLANT AND EQUIPMENT BY SEGMENT

(€ million)	2020	2019	2018
Property, plant and equipment by segment, gross
Exploration & Production	150,613	159,597	151,046
Global Gas & LNG Portfolio	2,164	2,332	2,286
Refining & Marketing and Chemicals	26,713	26,154	25,428
EGL, Power & Renewables	3,641	3,402	3,249
Corporate and other activities	2,134	1,944	1,875
Impact of unrealized intragroup profit elimination	(624)	(614)	(600)
	184,641	192,815	183,284
Property, plant and equipment by segment, net
Exploration & Production	48,296	55,702	53,535
Global Gas & LNG Portfolio	579	738	826
Refining & Marketing and Chemicals	4,132	5,015	5,300
EGL, Power & Renewables	860	708	624
Corporate and other activities	348	323	327
Impact of unrealized intragroup profit elimination	(272)	(294)	(310)
	53,943	62,192	60,302

CAPITAL EXPENDITURE BY SEGMENT

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

CAPITAL EXPENDITURE BY GEOGRAPHIC AREA OF ORIGIN

(€ million)	2020	2019	2018
Italy	1,198	1,402	1,424
Other European Union Countries	152	306	267
Rest of Europe	119	9	538
Africa	1,443	3,902	4,533
Americas	441	1,017	534
Asia	1,267	1,685	1,782
Other areas	24	55	41
Total outside Italy	3,446	6,974	7,695
Capital expenditure	4,644	8,376	9,119

NET BORROWINGS

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

CHANGES IN NET BORROWINGS

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

Alternative performance measures (Non-GAAP measures)

Management evaluates underlying business performance on the basis of Non-GAAP financial measures under IFRS ("Alternative performance measures"), such as adjusted operating profit and adjusted net profit, which are arrived at 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. From 2017, the recognition of the inventory holding (gains) losses has been revised in the Gas & Power segment considering a recently-enacted, less restrictive regulatory framework relating the legal obligation on part of gas wholesalers to retain gas volumes in storage to ensure an adequate level of modulation to the retail segment. On this basis, management has progressively reduced gas quantities held in storage and has commenced to leverage those quantities to improve margins by seeking to capture the seasonality in gas prices existing between the phase of gas injection (which typically occurs in summer months) vs. the phase of gas off-take (which typically occurs during the winter months). Therefore, from the closure of the statutory period of gas injection, i.e. from the fourth quarter of 2017, the determination of the stock profit or loss in the Gas & Power segment has changed and currently gas off-takes from storage are valued at the average cost incurred during the injection period net of the effects of hedging derivatives, ensuring when the purchased volumes are matched by the corresponding sales (net of the effects of hedging derivatives) the proper measurement and accountability of the economic performances. 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 affect 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. Management includes them in order to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Eni's trading performance on the basis of their forecasting models. Non-GAAP financial measures should be read together with information determined by applying IFRS and do not stand in for them. Other companies may adopt different methodologies to determine Non-GAAP measures. Follows the description of the main alternative performance measures adopted by Eni. The measures reported below refer to the performance of the reporting periods disclosed in this press release.

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

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

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

Leverage Leverage is a Non-GAAP measure of the Company's financial condition, calculated as the ratio between net borrowings and shareholders' equity, including noncontrolling 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 thirdparty 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 (Return On Average Capital Employed) 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 nonoperating purposes.

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

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

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

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

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

2020	(€ million)	& Production Exploration	& LNG Portfolio Global Gas	Marketing and Refining & Chemicals	& Renewables EGL, Power	Corporate and other activities	intragroup profit of unrealized elimination Impact	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)

(a) Excluding special items.

2019	(€ million)	& Production Exploration	& LNG Portfolio Global Gas	Marketing and Refining & Chemicals	& Renewables EGL, Power	Corporate and other activities	intragroup profit of unrealized elimination Impact	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

(a) Excluding special items.

2018	(€ million)	& Production Exploration	& LNG Portfolio Global Gas	Marketing and Refining & Chemicals	& Renewables EGL, Power	other activities Corporate and	intragroup profit of unrealized elimination Impact	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
(a) Excluding special items.

BREAKDOWN OF SPECIAL ITEMS

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

ADJUSTED OPERATING PROFIT BY SEGMENT

(€ million)	2020	2019	2018
Exploration & Production	1,547	8,640	10,850
Global Gas & LNG Portfolio	326	193	278
Refining & Marketing and Chemicals	6	21	360
EGL, Power & Renewables	465	370	262
Corporate and other activities	(507)	(602)	(583)
Impact of unrealized intragroup profit elimination	61	(25)	73
	1,898	8,597	11,240

ADJUSTED NET PROFIT BY SEGMENT

(€ million)	2020	2019	2018
Exploration & Production	124	3,436	4,955
Global Gas & LNG Portfolio	211	100	118
Refining & Marketing and Chemicals	(246)	(42)	224
EGL, Power & Renewables	329	275	189
Corporate and other activities	(1,205)	(866)	(948)
Impact of unrealized intragroup profit elimination and other consolidation adjustments	36	(20)	56
	(751)	2,883	4,594
attributable to:
Eni's shareholders	(758)	2,876	4,583
Non-controlling interest	7	7	11

EMPLOYEES

EMPLOYEES AT YEAR END

	(number)	2020	2019	2018
Exploration & Production	Italy	3,692	3,491	3,477
	Outside Italy	6,123	6,781	6,971
		9,815	10,272	10,448
Global Gas & LNG Portfolio	Italy	290	293	318
	Outside Italy	410	418	416
		700	711	734
Refining & Marketing and Chemicals	Italy	8,915	9,035	8,863
	Outside Italy	2,556	2,591	2,594
		11,471	11,626	11,457
EGL, Power & Renewables	Italy	1,679	1,698	1,719
	Outside Italy	413	358	337
		2,092	2,056	2,056
Corporate and other activities	Italy	6,999	6,971	6,625
	Outside Italy	418	417	381
		7,417	7,388	7,006
Total employees at year end	Italy	21,575	21,488	21,002
	Outside Italy	9,920	10,565	10,699
		31,495	32,053	31,701

BREAKDOWN BY POSITION

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

QUARTERLY INFORMATION

MAIN FINANCIAL DATA(a)

(€ million)			2020			2019
	I quarter	II quarter	III quarter	IV quarter		I quarter	II quarter	III quarter	IV quarter
Net sales from operations	13,873	8,157	10,326	11,631	43,987	18,540	18,440	16,686	16,215	69,881
Operating profit (loss)	(1,095)	(2,680)	220	280	(3,275)	2,518	2,231	1,861	(178)	6,432
Adjusted operating profit (loss)	1,307	(434)	537	488	1,898	2,354	2,279	2,159	1,805	8,597
Exploration & Production	1,037	(807)	515	802	1,547	2,308	2,140	2,141	2,051	8,640
Global Gas & LNG Portfolio	233	130	64	(101)	326	166	4	69	(46)	193
Refining & Marketing and Chemicals	16	73	21	(104)	6	(18)	51	149	(161)	21
EGL, Power & Renewables	191	85	57	132	465	164	35	15	156	370
Corporate and other activities	(204)	(135)	(84)	(84)	(507)	(132)	(123)	(144)	(203)	(602)
Unrealized profit intragroup elimination and consolidation adjustments	34	220	(36)	(157)	61	(134)	172	(71)	8	(25)
Net (loss) profit(b)	(2,929)	(4,406)	(503)	(797)	(8,635)	1,092	424	523	(1,891)	148
Capital expenditure	1,590	978	889	1,187	4,644	2,239	1,997	1,899	2,241	8,376
Investments	222	42	95	33	392	30	21	2,931	26	3,008
Net borrowings at period end	18,681	19,971	19,853	16,586	16,586	14,496	13,591	18,517	17,125	17,125

(a) Quarterly data are unaudited.

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

KEY MARKET INDICATORS

	2020					2019
	I quarter	II quarter	III quarter	IV quarter		I quarter	II quarter	III quarter	IV quarter
Average price of Brent dated crude oil(a)	50.26	29.20	43.00	44.23	41.67	63.20	68.82	61.94	63.25	64.30
Average EUR/USD exchange rate(b)	1.103	1.101	1.169	1.193	1.142	1.136	1.124	1.112	1.107	1.119
Average price in euro of Brent dated crude oil	45.56	26.51	36.78	37.08	36.49	55.65	61.25	55.70	57.13	57.44
Standard Eni Refining Margin (SERM)(c)	3.6	2.3	0.7	0.2	1.7	3.4	3.7	6.0	4.2	4.3

(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.

		2020 2019
	quarter	I II quarter	III quarter	IV quarter		I quarter	II quarter	III quarter	IV quarter
Liquids production	(kbbl/d) 892	853	817	809	843	887	867	893	926	893
Natural gas production	(mmcf/d) 4,768	4,653	4,694	4,800	4,729	5,157	5,230	5,379	5,379	5,287
Hydrocarbons production	(kboe/d) 1,790	1,729	1,701	1,713	1,733	1,841	1,834	1,888	1,921	1,871
Italy	112	106	105	103	107	132	123	120	117	123
Rest of Europe	256	243	224	228	237	170	146	146	191	163
North Africa	252	258	253	264	257	374	388	372	393	382
Egypt	303	266	290	304	291	336	346	369	363	354
Sub-Saharian Africa	372	386	369	347	368	363	399	395	385	386
Kazakhstan	174	167	144	168	163	148	120	169	163	150
Rest of Asia	193	173	172	167	176	181	179	183	174	179
America	110	114	127	114	117	107	106	106	106	106
Australia and Oceania		18 16	17	18	17	30	27	28	29	28
Hydrocarbons production sold	(mmboe) 144.7	143.8	142.6	144.1	575.2	152.3	150.0	162.0	166.3	630.6
Sales of natural gas to third parties-GGP	(bcm) 14.37	11.95	13.96	16.17	56.45	18.84	15.71	14.59	14.78	63.92
Own consumption of natural gas	1.53	1.44	1.58	1.58	6.13	1.62	1.43	1.65	1.55	6.25
Sales to third parties and own consumption	15.90	13.39	15.54	17.75	62.58	20.46	17.14	16.24	16.33	70.17
Sales of natural gas of Eni's affiliates (net to Eni)	0.69	0.46	0.44	0.82	2.41	0.75	0.62	0.59	0.72	2.68
Total sales and own consumption of natural gas - GGP	16.59	13.85	15.98	18.57	64.99	21.21	17.76	16.83	17.05	72.85
Retail gas sales	3.63	0.88	0.66	2.51	7.68	3.99	1.41	0.74	2.48	8.62
Retail power sales to end customers	(TWh) 3.28	2.74	3.07	3.40	12.49	2.75	2.47	2.75	2.95	10.92
Power sales in the open market	6.50	5.60	6.65	6.58	25.33	7.32	6.73	7.37	6.86	28.28
Sales of refined products (mmtonnes)	6.64	5.85	7.42	6.17	26.08	7.66	8.14	8.47	8.00	32.27
Retail sales in Italy	1.12	0.89	1.41	1.14	4.56	1.38	1.48	1.53	1.42	5.81
Wholesale sales in Italy	1.51	1.16	1.58	1.50	5.75	1.70	1.98	2.07	1.93	7.68
Retail sales Rest of Europe	0.52	0.43	0.61	0.49	2.05	0.56	0.62	0.66	0.60	2.44
Wholesale sales Rest of Europe	0.57	0.59	0.63	0.61	2.40	0.56	0.59	0.76	0.72	2.63
Wholesale sales outside Europe	0.12	0.11	0.12	0.13	0.48	0.11	0.12	0.12	0.13	0.48
Other markets	2.80	2.67	3.07	2.30	10.84	3.35	3.35	3.33	3.20	13.23

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 oil	162.602	m3 gas		5,310	ft3 gas
					5,800,000	btu
1 barrel/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 oil	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	toe
1,000,000 British thermal unit	(btu)	27.4	l oil	0.17 bbl	0.027	m3 oil	28.3 m3 gas	1,000	ft3 gas
1 tonne LNG	(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 feet (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