20-F 1 tm215953-3_20f.htm 20-F tm215953-3_20f - none - 177.7977221s
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 20-F
(Mark One)

REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                   to                  
OR

SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report
Commission file number: 1-14090
Eni SpA
(Exact name of Registrant as specified in its charter)
Republic of Italy
(Jurisdiction of incorporation or organization)
1, piazzale Enrico Mattei - 00144 Roma - Italy
(Address of principal executive offices)
Francesco Esposito
Eni SpA
1, piazza Ezio Vanoni
20097 San Donato Milanese (Milano) - Italy
Tel +39 02 52061632 - Fax +39 06 59822575
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Shares
American Depositary Shares
E
New York Stock Exchange*
New York Stock Exchange
(Which represent the right to receive two Shares)
* Not for trading, but only in connection with the registration of American Depositary
Shares, pursuant to the requirements of the Securities and Exchange Commission.      
Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
      Ordinary shares 3,605,594,848
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes      ☑                              No      ☐
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes      ☐                              No      ☑
Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes      ☑                              No      ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes      ☑                              No      ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer      ☑               Accelerated filer      ☐               Non-accelerated filer      ☐               Emerging growth company      ☐
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.   ☐
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment on the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issues its audit report.   ☑
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP      ☐            International Financial Reporting Standards as issued by the International Accounting Standards Board      ☑            Other      ☐
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
Item 17      ☐                        Item 18      ☐
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes      ☐                              No      ☑

TABLE OF CONTENTS
Page
ii
ii
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viii
PART I
1
1
1
1
3
5
29
29
40
40
66
69
76
79
79
81
81
89
96
96
96
97
97
105
106
115
120
120
129
129
139
139
151
152
153
153
153
153
153
155
155
155
156
157
157
164
164
164
169
169
172
172
172
172
172
PART II
174
174
174
175
175
175
175
176
177
177
177
179
PART III
180
180
180
i

Certain disclosures contained herein including, without limitation, certain information appearing in “Item 4 – Information on the Company”, and in particular “Item 4 – Exploration & Production”, “Item 5 – Operating and Financial Review and Prospects” and “Item 11 – Quantitative and Qualitative Disclosures about Market Risk” contain forward-looking statements regarding future events and the future results of Eni that are based on current expectations, estimates, forecasts, and projections about the industries in which Eni operates and the beliefs and assumptions of the management of Eni. Eni may also make forward-looking statements in other written materials, including other documents filed with or furnished to the U.S. Securities and Exchange Commission (the “SEC”). In addition, Eni’s senior management may make forward-looking statements orally to analysts, investors, representatives of the media and others. In particular, among other statements, certain statements with regard to management objectives, trends in results of operations, margins, costs, return on capital, risk management and competition are forward looking in nature. Words such as ‘expects’, ‘anticipates’, ‘targets’, ‘goals’, ‘projects’, ‘intends’, ‘plans’, ‘believes’, ‘seeks’, ‘estimates’, variations of such words, and similar expressions are intended to identify such forward-looking statements. These forward-looking statements are only predictions and are subject to risks, uncertainties, and assumptions that are difficult to predict because they relate to events and depend on circumstances that will occur in the future. Therefore, Eni’s actual results may differ materially and adversely from those expressed or implied in any forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 20-F under the section entitled “Risk factors” and elsewhere. Any forward-looking statements made by or on behalf of Eni speak only as of the date they are made. Eni does not undertake to update forward-looking statements to reflect any changes in Eni’s expectations with regard thereto or any changes in events, conditions or circumstances on which any such statement is based. The reader should, however, consult any further disclosures Eni may make in documents it files with the SEC.
CERTAIN DEFINED TERMS
In this Form 20-F, the terms “Eni”, the “Group”, or the “Company” refer to the parent company Eni SpA and its consolidated subsidiaries and, unless the context otherwise requires, their respective predecessor companies. All references to “Italy” or the “State” are references to the Republic of Italy, all references to the “Government” are references to the government of the Republic of Italy. For definitions of certain oil and gas terms used herein and certain conversions, see “Glossary” and “Conversion Table”.
PRESENTATION OF FINANCIAL AND OTHER INFORMATION
The Consolidated Financial Statements of Eni, included in this Annual Report, have been prepared in accordance with International Financial Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
Unless otherwise indicated, any reference herein to “Consolidated Financial Statements” is to the Consolidated Financial Statements of Eni (including the Notes thereto) included herein.
Unless otherwise specified or the context otherwise requires, references herein to “dollars”, “$”, “U.S. dollars”, “US$” and “USD” are to the currency of the United States, and references to “euro”, “EUR” and “€” are to the currency of the European Monetary Union.
Unless otherwise specified or the context otherwise requires, references herein to “Division” and “segment” are to any of the following Eni's business activities: “Exploration & Production” ​(or “E&P”), “Gas & Power” ​(or “G&P”), “Global Gas & LNG Portfolio” (or “GGP”), “Refining & Marketing and Chemicals” ​(or “R&M & C”), “Eni gas e luce, Power & Renewables” and “Corporate and Other activities”.References to Versalis or Chemical are to Eni's chemical activities which are managed through its fully-owned subsidiary Versalis and Versalis' controlled entities.
References to Eni gas e luce or retail gas and power are to Eni's retail gas and power activities which are managed through its fully-owned subsidiary Eni gas e luce SpA and Eni gas e luce's controlled entities. The results of the operations of Eni gas e luce are included in the segment information “Eni gas e luce, Power & Renewables” for financial reporting purposes.
STATEMENTS REGARDING COMPETITIVE POSITION
Statements made in “Item 4 – Information on the Company” referring to Eni’s competitive position are based on the Company’s belief, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and Eni’s internal assessment of market share based on publicly available information about the financial results and performance of market participants. Market share estimates contained in this document are based on management estimates unless otherwise indicated.
ii

GLOSSARY
Below is a selection of the most frequently used terms throughout this Annual Report on Form 20-F. Any reference herein to a non-GAAP measure and to its most directly comparable GAAP measure shall be intended as a reference to a non-IFRS measure and the comparable IFRS measure.
Financial terms
Leverage
A non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’ equity, including non-controlling interest. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure, “Ratio of total debt to total shareholders equity (including non-controlling interest)” see “Item 5 – Financial Condition”.
Net borrowings
Eni evaluates its financial condition by reference to “net borrowings”, which is a non-GAAP measure. Eni calculates net borrowings 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. Non-operating financing receivables consist of amounts due to Eni’s financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. Securities not related to operations consist primarily of government and corporate securities. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure, “Total debt” see “Item 5 – Financial condition”.
TSR
(Total Shareholder Return)
Management uses this measure to assess the total return on Eni’s shares. It is calculated on a yearly basis, keeping account of the change in market price of Eni’s shares (at the beginning and at end of year) and dividends distributed and reinvested at the ex-dividend date.
Business terms
2nd and 3rd generation feedstock
Are feedstocks not in competition with the food supply chain as opposed to first generation feedstocks (vegetable oils). Second generation feedstocks are mostly agricultural non-food and Agro/Urban waste (such as animal fats, used cooking oils and agricultural waste) and the third generation feedstocks are Non-agricultural High Innovation Feedstocks (deriving from algae or waste).
ARERA (Italian Regulatory Authority for Energy, Networks and Environment) formerly AEEGSI (Authority for Electricity Gas and Water)
The Italian Regulatory Authority for Energy, Networks and Environment is, the Italian independent body which regulates, controls and monitors the electricity, gas and water sectors and markets in Italy. The Authority’s role and purpose is to protect the interests of users and consumers, promote competition and ensure efficient, cost-effective and profitable nationwide services with satisfactory quality levels. Furthermore, since December 2017 the Authority also has regulatory and control functions over the waste cycle, including sorted, urban and related waste.
Associated gas
Associated gas is a natural gas found in contact with or dissolved in crude oil in the reservoir. It can be further categorized as Gas-Cap Gas or Solution Gas.
Average reserve life index
Ratio between the amount of reserves at the end of the year and total production for the year.
Barrel/BBL
Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons.
BOE
Barrel of Oil Equivalent. It is used as a standard unit measure for oil and natural gas. The latter is converted from standard cubic meters into barrels of oil equivalent using a certain coefficient (see “Conversion Table” on page viii).
Concession contracts
Contracts currently applied mainly in Western countries regulating relationships between states and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive right on exploration, development and production activities and for this reason it acquires a right to hydrocarbons extracted against the payment of royalties on production and taxes on oil revenues to the state.
iii

Condensates
Condensates is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Consob
The Italian National Commission for listed companies and the stock exchange (Commissione Nazionale per le Società e la Borsa).
Contingent resources
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.
Conversion capacity
Maximum amount of feedstock that can be processed in certain dedicated facilities of a refinery to obtain finished products. Conversion facilities include catalytic crackers, hydrocrackers, visbreaking units, and coking units.
Conversion index
Ratio of capacity of conversion facilities to primary distillation capacity. The higher the ratio, the higher is the capacity of a refinery to obtain high value products from the heavy residue of primary distillation.
Deep waters
Waters deeper than 200 meters.
Development
Drilling and other post-exploration activities aimed at the production of oil and gas.
Enhanced recovery
Techniques used to increase or stretch over time the production of wells.
Eni carbon efficiency index
Ratio between GHG emissions (Scope 1 and Scope 2 in tonnes CO2 eq.) of the main industrial activities operated by Eni divided by the productions (converted by homogeneity into barrels of oil equivalent using Eni’s average conversion factors) of the single businesses of reference.
EPC
Engineering, Procurement and Construction.
EPCI
Engineering, Procurement, Construction and Installation.
Exploration
Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling.
FPSO
Floating Production Storage and Offloading System.
FSO
Floating Storage and Offloading System.
Greenhouse Gases (GHG)
Gases in the atmosphere, transparent to solar radiation, that trap infrared radiation emitted by the earth’s surface. The greenhouse gases relevant within Eni’s activities are carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). GHG emissions are commonly reported in CO2 equivalent (CO2eq) according to Global Warming Potential values in line with IPCC AR4, 4th Assessment Report.
Infilling wells
Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels.
LNG
Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed back into its natural gaseous state and consumed. One tonne of LNG corresponds to 1,400 cubic meters of gas.
LPG
Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression.
Margin
The difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemical products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.
iv

Mineral Potential
(Potentially recoverable hydrocarbon volumes) Estimated recoverable volumes which cannot be defined as reserves due to a number of reasons, such as the temporary lack of viable markets, a possible commercial recovery dependent on the development of new technologies, or for their location in accumulations yet to be developed or where evaluation of known accumulations is still at an early stage.
Mineral Storage
According to Legislative Decree No. 164/2000, these are volumes required for allowing optimal operation of natural gas fields in Italy for technical and economic reasons. The purpose is to ensure production flexibility as required by long-term purchase contracts as well as to cover technical risks associated with production.
Modulation Storage
According to Legislative Decree No. 164/2000, these are volumes required for meeting hourly, daily and seasonal swings in demand.
Natural gas liquids (NGL)
Liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that were previously defined as natural gasoline, are natural gas liquids.
Net GHG Lifecycle Emissions
GHG Scope 1+2+3 emissions associated with the value chain of the energy products sold by Eni, including both those deriving from own productions and those purchased from third parties, accounted for on an equity basis, net of offset.
Net Carbon Footprint
Overall Scope 1 and Scope 2 GHG emissions associated with Eni’s operations, accounted for on an equity basis, net of carbon sinks.
Net Carbon Intensity
Ratio between the Net GHG lifecycle emissions and the energy products sold, accounted for on an equity basis.
Network Code
A code containing norms and regulations for access to, management and operation of natural gas pipelines.
Over/Under lifting
Agreements stipulated between partners which regulate the right of each to its share in the production for a set period of time. Amounts lifted by a partner different from the agreed amounts determine temporary Over/Under lifting situations.
Plasmix
Plasmix is the collective name for the different plastics that currently have no use in the market of recycling and can be used as a feedstock in the new circular economy businesses of Eni.
Possible reserves
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
Probable reserves
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
Primary balanced refining capacity
Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d.
Production Sharing
Agreement (PSA)
Contract regulates relationships between states and oil companies with regard to the exploration and production of hydrocarbons. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country.
v

Proved reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
REDD+
The REDD+ (Reducing Emissions from Deforestation and Forest Degradation) scheme was designed by the United Nations (United Nations Framework Convention on Climate Change – UNFCC). It involves conserving forests to reduce emissions and improve the natural storage capacity of CO2, as well as helping local communities develop through socio-economic projects in line with principles on sustainable management, forest protection and nature conservation.
Renewable Installed
Capacity
Renewable Installed Capacity is measured as the maximun generating capacity of Eni’s share of power plants that use renewable energy sources (wind, solar and wave, and any other non-fossil fuel source of generation deriving from natural resources, excluding, from the avoidance of doubt, nuclear energy) to produce electricity. The capacity is considered “installed” once the power plants are in operation or the mechanical completion phase has been reached. The mechanical completion represents the final construction stage excluding the grid connection.
Reserves
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Reserve life index
Ratio between the amount of proved reserves at the end of the year and total production for the year.
Reserve replacement ratio
Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the amount of reserves – in PSAs – due to changes in international oil prices.
Scope 1 GHG Emissions
Direct greenhouse gas emissions from company’s operations, produced from sources that are owned or controlled by the company.
vi

Scope 2 GHG Emissions
Indirect greenhouse gas emissions resulting from the generation of electricity, steam and heat purchased from third parties.
Scope 3 GHG Emissions
Indirect GHG emissions associated with the value chain of Eni’s products.
SERM (Standard Eni Refining Margin)
It approximates the margin of Eni’s refining system in consideration of material balances and refineries' product yields.
Ship-or-pay
Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported.
Take-or-pay
Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
Title Transfer Facility
The Title Transfer Facility, more commonly known as TTF, is a virtual trading point for natural gas in the Netherlands. TTF Price is quoted in euro per megawatt hour and, for business day, is quoted day-ahead, i.e. delivered next working day after assessment.
UN SDGs
The Sustainable Development Goals (SDGs) are the blueprint to achieve a better and more sustainable future for all by 2030. Adopted by all United Nations Member States in 2015, they address the global challenges the world is facing, including those related to poverty, inequality, climate change, environmental degradation, peace and justice. For further detail see the website https://unsdg.un.org
Upstream/Downstream
The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities.
Upstream GHG Emission intensity
Ratio between 100% Scope 1 GHG emissions from Upstream operated assets and 100% gross operated production (expressed in barrel of oil equivalent).
vii

ABBREVIATIONS
mmCF = million cubic feet
BCF = billion cubic feet
mmCM = million cubic meters
BCM = billion cubic meters
BOE = barrel of oil equivalent
KBOE = thousand barrel of oil equivalent
mmBOE = million barrel of oil equivalent
BBOE = billion barrel of oil equivalent
BBL = barrels
KBBL = thousand barrels
mmBBL = million barrels
BBBL = billion barrels
mmBTU = million British thermal unit
ktonnes = thousand tonnes
KW = kilowatt
GW = gigawatt
Gcal = giga calorie
REDD+ = Reducing Emissions from Deforestation and   Forest Degradation
mmtonnes = million tonnes
MW = megawatt
GWh = gigawatthour
TWh = terawatthour
/d = per day
/y = per year
E&P = the Exploration & Production segment
G&P = the Gas & Power business
R&M & C
= the Refining & Marketing and Chemicals segment
GGP = the Global Gas & LNG Portfolio segment
CONVERSION TABLE
1 acre = 0.405 hectares
1 barrel = 42 U.S. gallons
1 BOE = 1 barrel of crude oil = 5,310 cubic feet of natural gas
1 barrel of crude oil per day
= approximately 50 tonnes
of crude oil per year
1 cubic meter of natural gas
= 35.3147 cubic feet of natural gas
1 cubic meter of natural gas
= approximately 0.00665 barrels
of oil equivalent
1 kilometer = approximately 0.62 miles
1 short ton = 0.907 tonnes = 2,000 pounds
1 long ton = 1.016 tonnes = 2,240 pounds
1 tonne = 1 metric ton = 1,000 kilograms
= approximately 2,205 pounds
1 tonne of crude oil = 1 metric ton of crude oil
= approximately 7.3 barrels of crude oil
(assuming an API gravity of 34 degrees)
viii

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS
NOT APPLICABLE
Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE
NOT APPLICABLE
Item 3. KEY INFORMATION
Selected Financial Information
The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (IASB). The tables below present Eni’s selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2016, 2017, 2018, 2019 and 2020.
Following a reorganization of the Company to align with its strategy and long-term goals, management has changed the Group’s segment information for financial reporting purposes. See “Item 5 – Operating and Financial Review and Prospects”.
Year ended December 31,
2020
2019
2018
2017
2016
(€ million except data per share and per ADR)
CONSOLIDATED PROFIT STATEMENT DATA
Sales from continuing operations
43,987 69,881 75,822 66,919 55,762
Operating profit (loss) by segment from continuing operations
Exploration & Production
(610) 7,417 10,214 7,651 2,567
Gas & Power
75 (391)
Global Gas & LNG Portfolio
(332) 431 387
Refining & Marketing and Chemicals
(2,463) (682) (501) 981 723
Eni gas e luce, Power & Renewables
660 74 340
Corporate and Other activities
(563) (688) (668) (668) (681)
Unrealized intragroup profit elimination
33 (120) 211 (27) (61)
Operating profit (loss) from continuing operations
(3,275) 6,432 9,983 8,012 2,157
Net profit (loss) attributable to Eni from continuing operations
(8,635) 148 4,126 3,374 (1,051)
Net profit (loss) attributable to Eni from discontinued operations (413)
Net profit (loss) attributable to Eni
(8,635) 148 4,126 3,374 (1,464)
Data per ordinary share (euro)(1)
Net profit (loss) attributable to Eni basic and diluted from continuing operations (2.42) 0.04 1.15 0.94 (0.29)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations 0.00 0.00 0.00 0.00 (0.12)
Net profit (loss) attributable to Eni basic and diluted
(2.42) 0.04 1.15 0.94 (0.41)
Data per ADR ($)(1)(2)
Net profit (loss) attributable to Eni basic and diluted from continuing operations (5.53) 0.09 2.72 2.12 (0.65)
Net profit (loss) attributable to Eni basic and diluted from discontinued operations 0.00 0.00 0.00 0.00 (0.25)
Net profit (loss) attributable to Eni basic and diluted
(5.53) 0.09 2.72 2.12 (0.90)
(1)
Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2020 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 12, 2021.
(2)
Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S.$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented.
1

As of December 31,
2020
2019
2018
2017
2016
(€ million except data per share and per ADR)
CONSOLIDATED BALANCE SHEET DATA
Total assets
109,648 123,440 118,373 114,928 124,545
Finance debt (short-term and long-term debt) and lease liabilities 31,704 30,166 25,865 24,707 27,239
Capital stock issued
4,005 4,005 4,005 4,005 4,005
Non-controlling interest
78 61 57 49 49
Shareholders’ equity – Eni share
37,415 47,839 51,016 48,030 53,037
Capital expenditures from continuing operations
4,644 8,376 9,119 8,681 9,180
Weighted average number of ordinary shares outstanding (fully
diluted – shares million)
3,573 3,592 3,601 3,601 3,601
Dividend per share (euro)(1)
0.36 0.86 0.83 0.80 0.80
Dividend per ADR ($)(1)(2)
0.82 1.93 1.96 1.81 1.77
(1)
Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2020 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 12, 2021.
(2)
Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S.$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented. Dividends per ADR for the years 2016 through 2019 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively. The dividend for 2020 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (€0.24 per ADR) at the Noon Buying Rate recorded on the payment date on September 23, 2020, while the balance of €0.48 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2020. The balance dividend for 2020 once the full-year dividend is approved by the Annual General Shareholders’Meeting is payable on May 26, 2021 to holders of Eni shares, being the ex-dividend date May 24, 2021.
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Selected Operating Information
The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2016, 2017, 2018, 2019 and 2020. In presenting data on production volumes and reserves for total hydrocarbons, natural gas volumes have been converted to oil-equivalent barrels on the basis of a certain equivalency. Effective January 1, 2020, Eni has updated the conversion rate of gas produced to 5,310 cubic feet of gas equals 1 barrel of oil (it was 5,408 cubic feet of gas per barrel in previous reporting periods). The effect of this update on production expressed in BOE was 14 kBOE/d for the full year 2020 and the change in the initial reserves balance as of January 1, 2020 amounted to 67 mmBOE. Prior-year converted amounts were left unchanged. Other per-BOE indicators were only marginally affected by the update (e.g. realization prices, costs per BOE) and also negligible was the impact on depreciation and depletion charges. Other oil companies may use different conversion rates.
Year ended December 31,
2020
2019
2018
2017
2016
Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL) 3,055 3,124 3,183 3,262 3,230
of which developed
2,218 2,219 2,208 2,220 2,190
Proved reserves of liquids of equity-accounted entities at period end (mmBBL) 460 477 357 160 168
of which developed
233 269 205 43 43
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF) 15,554 17,111 17,324 17,290 18,462
of which developed
10,851 12,070 11,203 9,535 9,244
Proved reserves of natural gas of equity-accounted entities at period end (BCF) 2,447 2,721 2,400 2,182 3,871
of which developed
2,158 2,347 2,063 1,916 1,905
Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end 5,984 6,287 6,356 6,430 6,613
of which developed
4,261 4,450 4,261 3,967 3,884
Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end 921 981 797 560 877
of which developed
639 704 583 394 391
Average daily production of liquids (KBBL/d)(1)
841 890 884 852 878
Average daily production of natural gas available for sale (mmCF/d)(1) 4,077 4,576 4,630 4,734 4,329
Average daily production of hydrocarbons available for
sale (KBOE/d)(1)
1,609 1,736 1,732 1,719 1,671
Hydrocarbon production sold (mmBOE)
575.2 630.6 625.0 622.3 608.6
Oil and gas production costs per BOE(2)
6.31 6.05 6.50 6.33 5.90
Profit per barrel of oil equivalent(3)
 (4.33) 5.06 9.27 8.72 1.98
(1)
Referred to Eni’s subsidiaries and its equity-accounted entities. It excludes production volumes of hydrocarbon consumed in operation (124, 124, 119, 97, and 88 KBOE/d in 2020, 2019, 2018, 2017, and 2016 respectively).
(2)
Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment) prepared in accordance with IFRS divided by production on an available-for-sale basis, expressed in barrels of oil equivalent. See the unaudited supplemental oil and gas information in “Item 18 – Notes to the Consolidated Financial Statements”. Oil and gas production costs per BOE exclude transportation costs relating to the export of the saleable volumes of oil and gas produced, other than the costs incurred to deliver hydrocarbons to a main pipeline, a common carrier, a refinery or a maritime terminal, when unusual physical or operational circumstances exist.
(3)
Expressed in U.S. dollars. Results of operations from oil and gas producing activities of consolidated subsidiaries, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations under Topic 932. See the unaudited supplemental oil and gas information in “Item 18 – Notes to the Consolidated Financial Statements” for a calculation of results of operations from oil and gas producing activities.
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Selected Operating Information continued
Year ended December 31,
2020
2019
2018
2017
2016
Worldwide natural gas sales(*)(1)
80.83 86.31
Natural gas sales (Global Gas & LNG Portfolio)(1)
64.99 72.85 76.60
Retail gas sales(1)
7.68 8.62 9.13
Electricity sold(2)
37.82 39.20 36.93 35.33 37.05
of which: Retail power sales to end customers
12.49 10.92 8.39
Power sales in the open market
25.33 28.28 28.54
Refinery throughputs on own account(3)
17.00 22.74 23.23 24.02 24.52
Balanced capacity of wholly-owned refineries(4)
388 388 388 388 388
Retail sales (in Italy and rest of Europe)(3)
6.61 8.25 8.39 8.54 8.59
Number of service stations at period end (in Italy and rest of Europe) 5,369 5,411 5,448 5,544 5,622
Chemical production(3)
8.07 8.07 9.48 8.96 8.81
Average throughput per service station (in Italy and rest of Europe)(5) 1,390 1,766 1,776 1,783 1,742
Employees at period end (number)
 31,495 32,053 31,701 32,934 33,536
(*)
Include Global Gas & LNG Portfolio and Eni gas e luce gas sales managed by the previous business segment G&P.
(1)
Expressed in BCM.
(2)
Expressed in TWh.
(3)
Expressed in mmtonnes.
(4)
Expressed in KBBL/d.
(5)
Expressed in thousand liters per day.
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RISK FACTORS
Strategic risks and risks related to the business activities and industries of Eni and its consolidated subsidiaries (together, the “Group”)
The Company’s performance is affected by volatile prices of crude oil and produced natural gas and by fluctuating margins on the marketing of natural gas and on the integrated production and marketing of refined products and chemical products
The price of crude oil is the single, largest variable that affects the Company’s operating performance and cash flow. The price of crude oil has a history of volatility because, like other commodities, it is cyclical and is influenced by several macro-factors that are beyond management’s control. Crude oil prices are mainly driven by the balance between global oil supplies and demand and hence the global levels of inventories and spare capacity. In the short-term, worldwide demand for crude oil is highly correlated to the macroeconomic cycle. A downturn in economic activity normally triggers lower global demand for crude oil and possibly a supply build-up. Whenever global supplies of crude oil outstrip demand, crude oil prices weaken. Factors that can influence the global economic activity in the short-term and demand for crude oil include several, unpredictable events, like trends in the economic growth in China, India, the United States and other large oil-consuming countries, financial crisis, geo-political crisis, local conflicts and wars, social instability, pandemic diseases, the flows of international commerce, trade disputes and governments’ fiscal policies, among others. All these events could influence demands for crude oil. In the long-term, factors which can influence demands for crude oil include on the positive side demographic growth, improving living standards and GDP expansion. Negative factors that may affect demand in the long-term comprise availability of alternative sources of energy (e.g., nuclear and renewables), technological advances affecting energy efficiency, measures which have been adopted or planned by governments all around the world to tackle climate change and to curb carbon-dioxide emissions (CO2 emissions), including stricter regulations and control on production and consumption of crude oil, or a shift in consumer preferences. The civil society and several governments all over the world, with the EU leading the way, have announced plans to transition towards a low-carbon model through various means and strategies, particularly by supporting development of renewable energies and the replacement of internal combustion vehicles with electric vehicles, including the possible adoption of tougher regulations on the use of hydrocarbons such as the taxation of CO2 emissions as a mitigation action of the climate change risk. The push to reduce worldwide greenhouse gas emissions and an ongoing energy transition towards a low carbon economy, which are widely considered to be irreversible trends, will represent in our view major trends in shaping global demand for crude oil over the long-term and may lead to structural lower crude oil demands and consumption. We also believe that the dramatic events of 2020 in relation to the spread of the COVID-19 pandemic could have possibly accelerated those trends. See the section dedicated to the discussion of climate-related risks below.
Global production of crude oil is controlled to a large degree by the OPEC cartel, which has recently extended to include other important oil producers like Russia and Kazakhstan (so-called OPEC+). Saudi Arabia plays a crucial role within the cartel, because it is estimated to hold huge amounts of reserves and a vast majority of worldwide spare production capacity. This explains why geopolitical developments in the Middle East and particularly in the Gulf area, like regional conflicts, acts of war, strikes, attacks, sabotages and social and political tensions can have a big influence on crude oil prices. Also, sanctions imposed by the United States and the EU against certain producing countries may influence trends in crude oil prices. However, we believe that the continued rise of crude oil production in the United States due to the technology-driven shale oil revolution has somewhat reduced the ability of the OPEC+ to control the global supply of oil. To a lesser extent, factors like adverse weather conditions such as, hurricanes in sensitive areas like the Gulf of Mexico, and operational issues at key petroleum infrastructure can influence crude oil prices.
The year 2020 was one of the worst on record for the oil&gas industry due to the far-reaching consequences of the COVID-19 pandemic, the long-term impacts of which have yet to be understood and estimated. Almost all of the companies in the sector suffered material economic losses and cash flow shortfalls and saw their business fundamentals along with share prices significantly deteriorate due to a massive hit to global demand for crude oil and other energy products and to collapsing commodity prices as direct consequences of the lockdown measures imposed in the first months of the year by governments throughout the world to contain the spread of the pandemic, leading to the suppression of industrial activity, international commerce and travel as well as souring the moods of consumers. To make things worse, while demand was falling precipitously, in March 2020 the OPEC+ failed to reach a deal for
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production cuts claimed by some members to counteract the effects of the COVID-19 pandemic and Saudi Arabia decided to increase its output and reduce prices to gain market share. The concurrence of a material reduction in global crude oil demand and rising production on the part of the OPEC+ members triggered a collapse in crude oil prices. At the peak of the COVID-19 crisis and the price war, the value of the Brent crude benchmark had fallen to below 15 $/BBL, marking the lowest point over several decades on an inflation-adjusted basis. The situation of extreme oversupply in the month of April 2020 was signalled by ballooning global inventories, depletion of storage capacity and a strong contango structure in the prices of contracts for future deliveries. Subsequently, with the gradual easing of lockdown measures and the implementation from May 2020 of major output cuts by the members of the OPEC+ as well as major capex curtailments implemented by international oil&gas companies, Brent prices staged a significant comeback, recovering to a level of almost 45 $/BBL in July. However, this recovery weakened at the end of the summer and in the autumn months due to a continuing rise in COVID-19 cases in western countries, particularly in the United States, continental Europe and the UK forcing national or local governments to re-impose new restrictive measures or full lockdowns to curb the spread of the virus, which negatively affected the pace of economic recovery and the consumption of fuels like gasoline and gasoil. On the other hand, an acceleration in the economic recovery in mainland China and other Asian countries where the virus was more effectively contained helped sustain the price of crude oil and a reduction in global inventories. Finally, the recovery of crude oil prices gained strength in the final months of 2020 and in the first months of 2021 due to a favourable combination of market and macro developments, most notably: a break-through in the development and approval of effective vaccines against COVID-19, further acceleration in the pace of economic activity in Asia, the outcome of the presidential election in the United States which fuelled expectations of large stimulus measures in favour of the U.S. economy, the continuing commitments on the part of OPEC+ to support the rebalancing of the oil market by slowing down the planned curtailments of the extra production quotas enacted in May 2020 and finally the surprising announcement by Saudi Arabia that it would implement a voluntary cut of its production quota of 1 million barrels/day in the months of February and March 2021 to compensate for any possible impact on demand due to recrudescence of the pandemic in western countries. Unexpectedly, while oil companies’ executives, traders and fund managers were weighing all these macro and market developments, a massive, unprecedented cold snap hit the Northern-Eastern hemisphere, particularly Japan, South Korea and China, causing a spike in demand for oil-based heating fuels and LNG, which significantly boosted the market prices of all hydrocarbons. Due to such recent developments, Brent crude oil prices strengthened to 50 $/bbl at the end of 2020 and then rallied further in the first quarter of 2021 averaging about 60 $/bbl. Despite this improvement, we expect the trading environment for crude oil price to remain volatile and uncertain in 2021 due to the virus overhang, a weak macroeconomic backdrop in the United States and Europe and high inventory levels in OECD countries, which remain above historical averages.
The COVID-19 pandemic negatively and materially affected a weak global natural gas market. As a result of the gas demand collapse recorded in the first half of 2020 due to the economic crisis resulting from COVID-19, gas prices fell to unprecedented lows in all the main geographies. Likewise, crude oil and natural gas prices recovered in the second half of the year supported by an improving economy and falling production levels due to capex constraints on global oil&gas companies. Overall, natural gas prices fell remarkably in 2020 (the prices at the Italian spot market were 35% lower than in 2019). However, at the end of 2020 and in January 2021 natural gas prices staged a material comeback supported by record seasonal demand in the Northern-Eastern hemisphere driven by record low temperatures.
Lower hydrocarbon prices from one year to another negatively affect the Group’s consolidated results of operations and cash flow. This is because lower prices translate into lower revenues recognised in the Company’s Exploration & Production segment at the time of the price change, whereas expenses in this segment are either fixed or less sensitive to changes in crude oil prices than revenues. In 2020, the Brent price averaged about 42 $/bbl, a decrease of 35% compared to 2019, which significantly and adversely affected Eni’s results of operations and cash flow for the year. We estimated that lower equity crude oil realizations and other scenario effects (lower equity gas prices, lower refining margins and other declines as described below) reduced the Company’s underlying operating profit and the net cash provided by operating activities by about €7 billion.
Considering the risks and uncertainties to the outlook for 2021, we are retaining a prudent financial framework and capital discipline in our investment decisions, while we are assuming a Brent price forecast of 50 $/bbl for the full year. Based on the current oil&gas assets portfolio of Eni, management estimates that the Company’s cash flow from operations will vary by approximately €150 million for each one-dollar change in the price of the Brent crude oil benchmark compared to the 50 $/bbl scenario adopted by management for the current year and for proportional changes in gas prices.
6

In addition to the short-term impacts on the Group’s profitability, a market crisis like the one experienced in 2020 may also alter the fundamentals of the oil and natural gas markets. Lower oil and gas prices over prolonged periods of time may have material adverse effects on Eni’s performance and business outlook, because such a scenario may limit the Group’s ability to finance expansion projects, further reducing the Company’s ability to grow future production and revenues, and to meet contractual obligations. The Company may also need to review investment decisions and the viability of development projects and capex plans and, as a result of this review, the Company could reschedule, postpone or curtail development projects. A structural decline in hydrocarbon prices could trigger a review of the carrying amounts of oil and gas properties and this could result in recording material asset impairments and in the de-booking of proved reserves, if they become uneconomic in this type of environment.
In the course of 2020 Eni’s management revised its view of the oil market fundamentals to factor in certain emerging trends. Management considered that the lockdown measures in response to COVID-19 could result in a prolonged period of weak oil demand. Furthermore, the massive actions in support of the economic recovery planned by governments in several countries may have a strong environmental footprint and be supportive of the green economy, leading to a potential acceleration in the pace of energy transition and in the replacement of hydrocarbons in the energy mix in the long-term. Based on these considerations, in 2020 the Company revised its long-term forecast for hydrocarbon prices, which are the main driver of capital allocations decisions and of the recoverability assessment of the book values of our non-current assets. The revised scenario adopted by Eni foresees a long-term price of the marker Brent of 60 $/bbl in 2023 real terms compared to the previous assumption of 70 $/bbl. The price of natural gas at the Italian spot market “PSV” is estimated at 5.5 $/mmBTU in real terms in 2023 as compared to the previous assumption of 7.8 $/mmBTU. This changed outlook for hydrocarbons prices drove the recognition of significant impairment losses relating to oil&gas assets (€1.9 billion, pre-tax). For further details, see the notes to the consolidated financial statements. Furthermore, given the decline in crude oil prices used in the estimation of proved reserves according to the SEC rules compared to 2019 (average of the first-of-the-day price of each month at 41 $/bbl in 2020 vs. 63 $/bbl in 2019), we were forced to debook 124 mmBOE of reserves that have become uneconomic in this environment.
Finally, during a downturn like the one experienced in 2020, the Group’s access to capital may be reduced and lead to a downgrade or other negative rating action with respect to the Group’s credit rating by rating agencies. These downgrades may negatively affect the Group’s cost of capital, increase the Group’s financial expenses, and may limit the Group’s ability to access capital markets and execute aspects of the Group’s business plans.
Eni estimates that approximately 50% of its current production is exposed to fluctuations in hydrocarbons prices. Exposure to this strategic risk is not subject to economic hedging, except for some specific market conditions or transactions. The remaining portion of Eni’s current production is largely unaffected by crude oil price movements considering that the Company’s property portfolio is characterized by a sizeable presence of production sharing contracts, whereby the Company is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditure and hence production, and vice versa.
All these risks may adversely and materially impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
Margins on the manufacturing and sale of fuels and other refined products, chemical commodities, and other energy commodities are driven by economic growth, global and regional dynamics in supplies and demand and other competitive factors. Generally speaking, the prices of products mirror that of oil-based feedstock, but they can also move independently. Margins for refined and chemical products depend upon the speed at which products’ prices adjust to reflect movements in oil prices. Margins at our business of wholesale marketing of natural gas are driven by the spreads between spot prices at continental hubs to which our procurement costs are indexed and the spot prices at the Italian hub where a large part of our gas sales occur. These spreads can be very volatile.
In 2020, demand and margins for fuels and petrochemical products were materially hit by the economic downturn triggered by the COVID-19 pandemic, resulting in lower demand for fuels and petrochemical commodities. The trading environment was particularly unfavourable in the refining business due to an unprecedented combination of negative market trends. During the peak of the pandemic crisis in
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the second quarter of 2020, the lockdown measures imposed by governments throughout the world to curb the spread of the pandemic resulted in the suppression of air travel and people’s commuting by car leading to a massive decline in worldwide consumption of gasoline, kerosene and other fuels. Furthermore, while those restrictive measures were eased in Asia and other parts of the world, they have continued or have been re-imposed in Italy and other European countries, which are the main reference markets of our refining and marketing business. Although since the implementation of the production cuts by OPEC+ producers, crude oil prices have been moderately recovering throughout 2020, the increases in the cost of the feedstock did not translate into higher prices of fuels due to a depressed demand environment. Finally, the profitability of our business was also negatively affected by the appreciation of sour crude oils towards medium/light qualities such as the Brent, due to market dislocations and the effects of the production cuts implemented by the OPEC+, which reduced availability of sour crudes in the marketplace. This latter trend negatively affected the profitability of conversion plants, which are normally supported by the fact that heavy and sour crudes trade at a discount vs. the light qualities as the Brent. Due to all those market trends, the Company’s own internal performance measure to gauge the profitability of its refineries, the SERM (see glossary), fell to historic lows over the second half of 2020, plunging into negative territory at the end of 2020 and the beginning of 2021 in concomitance with the rally in crude oil prices, which has yet to be supported by a recovery of fuel demand in Europe. This trend will negatively affect the profitability of our refining business in 2021. The sales volumes at our network of service stations were significantly impacted by lower consumption due to the lockdown and anti-pandemic measures. The deteriorated outlook for refining margins and fuels consumption triggered a revision of the book value of the Company’s oil-based refining assets leading to the recognition of €1.2 billion of impairment losses.
The chemical business of Eni was negatively affected by a significant reduction in demand in the segments most exposed to the COVID-19 crisis such as elastomers following the contraction in the automotive sector, while the polyethylene margins were supported both by the reduction in the cost of oil feedstock and by strong demand for single-use plastics and packaging as consequence of higher demand for goods related to “stay-at-home economy”.
There is strong competition worldwide, both within the oil industry and with other industries, to supply energy and petroleum products to the industrial, commercial and residential energy markets
The current competitive environment in which Eni operates is characterised by volatile prices and margins of energy commodities, limited product differentiation and complex relationships with state-owned companies and national agencies of the countries where hydrocarbons reserves are located to obtain mineral rights. As commodity prices are beyond the Company’s control, Eni’s ability to remain competitive and profitable in this environment requires continuous focus on technological innovation, the achievement of efficiencies in operating costs, effective management of capital resources and the ability to provide valuable services to energy buyers. It also depends on Eni’s ability to gain access to new investment opportunities. The economic crisis caused by the suppression of industrial activity and travel in response to the COVID-19 pandemic materially and negatively impacted demand for the Company’s products, driving a strong increase in the level of competition across all sectors where we are operating. We believe that the pandemic will have enduring effects on the competition within the oil&gas sectors, including the refining and marketing of fuels and other energy commodities and the supply of energy products to the retail segment.
Exploration & Production

In the Exploration & Production segment, Eni is facing competition from both international and state-owned oil companies for obtaining exploration and development rights and developing and applying new technologies to maximise hydrocarbon recovery. Because of its smaller size relative to other international oil companies, Eni may face a competitive disadvantage when bidding for large scale or capital intensive projects and it may be exposed to the risk of obtaining lower cost savings in a deflationary environment compared to its larger competitors given its potentially smaller market power with respect to suppliers. Due to those competitive pressures, Eni may fail to obtain new exploration and development acreage, to apply and develop new technologies and to control costs. The COVID-19 pandemic has caused exploration&production companies to significantly reduce their capital investment in response to lower cash flows from operations and to focus on the more profitable and scenario-resilient projects. We believe that this development will be long-lasting and likely drive increased competition among players to gain access to relatively cheaper reserves (onshore vs. offshore; proven areas vs. unexplored areas).
Global Gas & LNG Portfolio

In the Global Gas & LNG Portfolio business, Eni is facing strong competition in the European
8

wholesale markets to sell gas to industrial customers, the thermoelectric sector and retail companies from other gas wholesalers, upstream companies, traders and other players. The results of our wholesale gas business are subject to global and regional dynamics of gas demand and supplies. The results of the LNG business are mainly influenced by the global balance between demand and supplies, considering the higher level of flexibility of LNG with respect to gas delivered via pipeline. In 2020, the economic crisis triggered by the COVID-19 pandemic exacerbated the already weak fundamentals of the gas market. In fact, the lockdown of European economies resulted in sharply lower gas consumption leading to intensified competitive pressures. These developments caused lower sales volumes of gas marketed via pipeline and by our LNG business and significantly lower prices. In 2020 Eni’s gas and LNG sales declined by 11% due to the impact of the economic crisis triggered by the pandemic. Sales margins at our LNG business were put under pressure by collapsing demand due to the lockdown of Asian economies, which are the main outlet of global LNG production, as many buyers requested activation of the force majeure clauses for not lifting LNG contracted volumes. These developments led to increased competition in the global LNG market, dragging down sales margins. We expect continued competitive pressure in our wholesale gas and LNG businesses. However, in the first months of 2021 a colder-than normal winter in the Northern Hemisphere has supported the price of gas and LNG.
Refining & Marketing

In the Refining & Marketing segment, Eni is facing competition both in the refining business and in the retail marketing activity. Our Refining business has been negatively affected for years by structural headwinds due to muted trends in the European demand for fuels, refining overcapacity and continued competitive pressure from players in the Middle East, the United States and Far East Asia. Those competitors can leverage on larger plant scale and cost economies, availability of cheaper feedstock and lower energy expenses. This unfavourable competitive environment has been exacerbated by the effects of the 2020 economic crisis due to the COVID-19 pandemic, the consequent lockdown of entire economies and travel restrictions, which drove a collapse in the consumption of motor gasoline, jet fuels and other refined products. In the initial stages of the global energy downturn, refining margins were supported by a collapse in crude oil prices. Subsequently, as crude oil prices found support in the production curtailments implemented by the OPEC+, refining margins were severely hit by the weakness in global demand for fuels due to low propensity of people for travelling, which squeezed relative prices of fuels vs. the oil feedstock cost. This trend became particularly unfavourable starting from the summer months when refining margins were much less profitable, until the last months of the year when they even recorded negative value. On average, in 2020, the refining margin (SERM) dropped materially, down by 60% as compared to the prior year. Furthermore, Eni’s refining profitability was exposed to the volatility in the spreads between crudes with high sulphur content or sour crudes and the Brent crude benchmark, which is a low-content sulphur crude. Eni’s complex refineries are able to process sour crudes, which typically trade at a discount over Brent crude. Historically, this discount has supported the profitability of complex refineries, like our plant at Sannazzaro in Italy. However, in the course of 2020, a shortfall in supplies of sour crudes due to the production cuts implemented by OPEC+ in response to the COVID-19 pandemic, drove an appreciation of the relative prices of sour crudes as compared to Brent, which negatively affected the results of Eni’s refining business by reducing the advantage of processing sour crudes. Eni believes that the competitive environment of the refining sector will remain challenging in the foreseeable future, considering ongoing uncertainties and risks relating to the strength of the economic recovery in Europe and worldwide, and risks of another round of lockdown measures in case of failure by governments to effectively contain the spread of the pandemic, which would weigh heavily on demand for fuels. Other risks factors include refining overcapacity in the European area and expectations of a new investment cycle driven by capacity expansion plans announced in Asia and the Middle East, potentially leading to global oversupplies of refinery products. Due to a reduced profitability outlook in the refining business, management recognized impairment charges of €1.2 billion to align the book value of refineries to their realizable values.
The business of marketing refined products to drivers at our network of service stations and to large account customers (airlines, public administrations, transport and industrial customers, bulk buyers and resellers) is facing competition from other oil companies and newcomers such as low-scale and local operators, and un-branded networks with light cost structure. All of these operators compete with each other primarily in terms of pricing and, to a lesser extent, service
9

quality. Against this backdrop, in 2020 the lockdown measures adopted to contain the spread of the pandemic resulted in the suppression of travel and road transportation which weighed heavily on throughput volumes at our network of service stations in Italy and other European markets which were down by 19.9% as compared to the prior year.
Chemicals

Eni’s Chemical business is in a highly-cyclical, very competitive sector. We have been facing for years strong competition from well-established international players and state-owned petrochemical companies, particularly in the most commoditised market segments such as the production of basic petrochemical products (like ethylene and polyethylene), where demand is a function of macroeconomic growth. Many of these competitors based in the Far East and the Middle East have been able to benefit from cost economies due to larger plant scale, wide geographic moat, availability of cheap feedstock and proximity to end-markets. Excess worldwide capacity of petrochemical commodities has also fuelled competition in this business. Furthermore, petrochemical producers based in the United States have regained market share, as their cost structure has become competitive due to the availability of cheap feedstock deriving from the production of domestic shale gas from which ethane is derived, which is a cheaper raw material for the production of ethylene than the oil-based feedstock utilised by Eni’s petrochemical subsidiaries. Finally, rising public concern about climate change and the preservation of the environment has begun to negatively affect the consumption of single-use plastics. In 2020, these competitive dynamics were greatly amplified by the economic crisis triggered by the lockdown measures in response to the COVID-19 pandemic, which negatively affected plant utilization rates and sales volumes, particularly in those segments more exposed to the recession of their customer segments, like in the case of sales volumes of elastomers to the automotive industry. However, other chemicals segments performed relatively well, because the “stay-at-home economy” boosted demands for certain products like polyethylene, that is utilized in the packaging of food and other consumer goods as well as in materials for the sanitary emergency. These trends supported polyethylene margins. Looking forward, management believes that the competitive environment in the Chemicals businesses will remain challenging due to uncertainties and risks relating to the strength of the economic recovery or another round of lockdown measures in case of by governments to effectively contain the spread of the pandemic.
Retail gas and power

Eni’s retail gas and power business engages in the supply of gas and electricity to customers in the retail markets mainly in Italy, France and other countries in Europe. Customers include households, large residential accounts (hospitals, schools, public administration buildings, offices) and small and medium-sized businesses. The retail market is characterised by strong competition among selling companies which mainly compete in terms of pricing and the ability to bundle valuable services with the supply of the energy commodity. In this segment, competition has intensified in recent years due to the progressive liberalisation of the market and the ability of residential customers to switch smoothly from one supplier to another. In 2020, the performance of this business was negatively affected by the economic crisis caused by the lockdown measures imposed to contain the spread of COVID-19, which reduced energy demand particularly in the segments of medium and small businesses, increased credit risk and triggered increased credit losses. In 2020, sales volumes of natural gas to the retail market fell by 11%; however, this trend was partly offset by greater power requirements due to the “stay-at-home economy” with sales volumes up by 13% for the year. We anticipate that competition will remain strong in this business due to the likelihood of a slow economic recovery and weak trends in energy consumption, as well as the potential risk of yet another downturn in case of new lockdown measures to contain the pandemic and rising sensitivity among households and businesses to reduce the cost of the energy bill.
Eni also engages in the business of producing gas-fired electricity that is largely sold at wholesale energy market and balancing market (so called MSD) in Italy. Margins on the sale of electricity have declined in recent years due to oversupplies, weak economic growth and inter-fuel competition. The pandemic-driven economic crisis has exacerbated those trends, causing a material reduction in power consumption due to the lockdowns of entire industrial sectors and producing activities. In 2020, power sales in the wholesale market in Italy fell by 10% due to lower consumption by Italian businesses. Management believes that these factors will continue to negatively affect clean spark spread margins on electricity in the Italian wholesale markets.
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In case the Company is unable to effectively manage the above described competitive risks, which may increase in case of a weaker-than-anticipated recovery in the post-pandemic economy or in a worst case scenario of the imposition by governments of new lockdown measures and other restrictions in response to the pandemic, the Group’s future results of operations, cash flow, liquidity, business prospects, financial condition, shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares may be adversely and significantly affected.
Safety, security, environmental and other operational risks
The Group engages in the exploration and production of oil and natural gas, processing, transportation and refining of crude oil, transport of natural gas, storage and distribution of petroleum products and the production of base chemicals, plastics and elastomers. By their nature, the Group’s operations expose Eni to a wide range of significant health, safety, security and environmental risks. Technical faults, malfunctioning of plants, equipment and facilities, control systems failure, human errors, acts of sabotage, attacks, loss of containment and adverse weather events can trigger damaging consequences such as explosions, blow-outs, fires, oil and gas spills from wells, pipeline and tankers, release of contaminants and pollutants in the air, the ground and in the water, toxic emissions and other negative events. The magnitude of these risks is influenced by the geographic range, operational diversity and technical complexity of Eni’s activities. Eni’s future results of operations and liquidity depend on its ability to identify and address the risks and hazards inherent to operating in those industries.
In the Exploration & Production segment, Eni faces natural hazards and other operational risks including those relating to the physical and geological characteristics of oil and natural gas fields. These include the risks of eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and the security of Eni’s personnel and risks of blowout, fire or explosion.
Eni’s activities in the Refining & Marketing and Chemical segment entail health, safety and environmental risks related to the handling, transformation and distribution of oil, oil products and certain petrochemical products. These risks can arise from the intrinsic characteristics and the overall lifecycle of the products manufactured and the raw materials used in the manufacturing process, such as oil-based feedstock, catalysts, additives and monomer feedstock. These risks comprise flammability, toxicity, long-term environmental impact such as greenhouse gas emissions and risks of various forms of pollution and contamination of the soil and the groundwater, emissions and discharges resulting from their use and from recycling or disposing of materials and wastes at the end of their useful life.
All of Eni’s segments of operations involve, to varying degrees, the transportation of hydrocarbons. Risks in transportation activities depend on several factors and variables , including the hazardous nature of the products transported due to their flammability and toxicity, the transportation methods utilized (pipelines, shipping, river freight, rail, road and gas distribution networks), the volumes involved and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environmental considerations). All modes of transportation of hydrocarbons are particularly susceptible to risks of blowout, fire and loss of containment and, given that normally high volumes are involved, could present significant risks to people, the environment and the property.
Eni has material offshore operations relating to the exploration and production of hydrocarbons. In 2020, approximately 65% of Eni’s total oil and gas production for the year derived from offshore fields, mainly in Egypt, Libya, Angola, Norway, Congo, Indonesia, the United Arab Emirates, Italy, Ghana, Venezuela, the United Kingdom, Nigeria and the United States. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. Offshore accidents and spills could cause damage of catastrophic proportions to the ecosystem and to communities’ health and security due to the apparent difficulties in handling hydrocarbons containment, pollution, poisoning of water and organisms, length and complexity of cleaning operations and other factors. Furthermore, offshore operations are subject to marine risks, including storms and other adverse weather conditions and perils of vessel collisions, which may cause material adverse effects on the Group’s operations and the ecosystem.
The Company has invested and will continue to invest significant financial resources to continuously upgrade the methods and systems for safeguarding the reliability of its plants, production facilities, transport and storage infrastructures, the safety and the health of its employees, contractors, local communities and the environment, to prevent risks, to comply with applicable laws and policies and to respond to and learn from unforeseen incidents. Eni seeks to manage these operational risks by carefully designing and building facilities, including wells, industrial complexes, plants and equipment, pipelines,
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storage sites and other facilities, and managing its operations in a safe and reliable manner and in compliance with all applicable rules and regulations, as well as by applying the best available techniques in the marketplace. However, these measures may ultimately not be completely successful in preventing and/or altogether eliminating risks of adverse events. Failure to properly manage these risks as well as accidental events like human errors, unexpected system failure, sabotages or other unexpected drivers could cause oil spills, blowouts, fire, release of toxic gas and pollutants into the atmosphere or the environment or in underground water and other incidents, all of which could lead to loss of life, damage to properties, environmental pollution, legal liabilities and/or damage claims and consequently a disruption in operations and potential economic losses that could have a material and adverse effect on the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
Eni’s operations are often conducted in difficult and/or environmentally sensitive locations such as the Gulf of Mexico, the Caspian Sea and the Arctic. In such locations, the consequences of any incident could be greater than in other locations. Eni also faces risks once production is discontinued because Eni’s activities require the decommissioning of productive infrastructures and environmental sites remediation and clean-up. Furthermore, in certain situations where Eni is not the operator, the Company may have limited influence and control over third parties, which may limit its ability to manage and control such risks. Eni retains worldwide third-party liability insurance coverage, which is designed to hedge part of the liabilities associated with damage to third parties, loss of value to the Group’s assets related to unfavourable events and in connection with environmental clean-up and remediation. As of the date of this filing, maximum compensation allowed under such insurance coverage is equal to $1.2 billion in case of offshore incident and $1.4 billion in case of incident at onshore facilities (refineries). Additionally, the Company may also activate further insurance coverage in case of specific capital projects and other industrial initiatives. Management believes that its insurance coverage is in line with industry practice and is enough to cover normal risks in its operations. However, the Company is not insured against all potential risks. In the event of a major environmental disaster, such as the incident which occurred at the Macondo well in the Gulf of Mexico several years ago, for example, Eni’s third-party liability insurance would not provide any material coverage and thus the Company’s liability would far exceed the maximum coverage provided by its insurance. The loss Eni could suffer in case of a disaster of material proportions would depend on all the facts and circumstances of the event and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster. The Company cannot guarantee that it will not suffer any uninsured loss and there can be no guarantee, particularly in the case of a major environmental disaster or industrial accident, that such a loss would not have a material adverse effect on the Company.
The occurrence of any of the above mentioned risks could have a material and adverse impact on the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares and could also damage the Group’s reputation.
Risks deriving from Eni’s exposure to weather conditions
Significant changes in weather conditions in Italy and in the rest of Europe from year to year may affect demand for natural gas and some refined products. In colder years, demand for such products is higher. Accordingly, the results of operations of our businesses engaged in the marketing of natural gas and, to a lesser extent, the Refining & Marketing business, as well as the comparability of results over different periods may be affected by such changes in weather conditions. Over recent years, this pattern could have been possibly affected by the rising frequency of weather trends like milder winter or extreme weather events like heatwaves or unusually cold snaps, which are possible consequences of climate change. In 2020, our sales volumes of gas both at wholesale markets and at the retail sector particularly in Italy were negatively affected by lower seasonal sales in the first quarter.
Risks associated with the exploration and production of oil and natural gas
The exploration and production of oil and natural gas require high levels of capital expenditures and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of oil and gas fields. The exploration and production activities are subject to mining risk and the risks of cost overruns and delayed start-up at the projects to develop and produce hydrocarbons reserves. Those risks could have an adverse, significant impact on Eni’s future growth prospects, results of operations, cash flows, liquidity and shareholders’ returns.
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The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, higher-than-average rates of income taxes, additional royalties and taxes on production, environmental protection measures, control over the development and decommissioning of fields and installations, and restrictions on production. A description of the main risks facing the Company’s business in the exploration and production of oil and gas is provided below.
Exploratory drilling efforts may be unsuccessful
Exploration activities are mainly subject to mining risk, i.e. the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling and completing wells have margins of uncertainty, and drilling operations may be unsuccessful because of a large variety of factors, including geological failure, unexpected drilling conditions, pressure or heterogeneities in formations, equipment failures, well control (blowouts) and other forms of accidents. A large part of the Company exploratory drilling operations is located offshore, including in deep and ultra-deep waters, in remote areas and in environmentally-sensitive locations (such as the Barents Sea, the Gulf of Mexico, deep water prospect off West Africa, Indonesia, the Mediterranean Sea and the Caspian Sea). In these locations, the Company generally experiences higher operational risks and more challenging conditions and incurs higher exploration costs than onshore. Furthermore, deep and ultra-deep water operations require significant time before commercial production of discovered reserves can commence, increasing both the operational and the financial risks associated with these activities. Because Eni plans to make significant investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. Unsuccessful exploration activities and failure to discover additional commercial reserves could reduce future production of oil and natural gas, which is highly dependent on the rate of success of exploration projects and could have an adverse impact on Eni’s future performance and returns.
Development projects bear significant operational risks which may adversely affect actual returns
Eni is executing or is planning to execute several development projects to produce and market hydrocarbon reserves. Certain projects target the development of reserves in high-risk areas, particularly deep offshore and in remote and hostile environments or in environmentally sensitive locations. Eni’s future results of operations and business prospects depend heavily on its ability to implement, develop and operate major projects as planned. Key factors that may affect the economics of these projects include:

the outcome of negotiations with joint venture partners, governments and state-owned companies, suppliers and potential customers to define project terms and conditions, including, for example, Eni’s ability to negotiate favourable long-term contracts to market gas reserves;

commercial arrangements and granting of all necessary administrative authorizations to build pipelines and related equipment to transport and market hydrocarbons;

timely issuance of permits and licenses by government agencies;

the ability to carry out the front-end engineering design in order to prevent the occurrence of technical inconvenience during the execution phase; timely manufacturing and delivery of critical equipment by contractors, shortages in the availability of such equipment or lack of shipping yards where complex offshore units such as FPSO and platforms are built; delays in achievement of critical phases and project milestones;

risks associated with the use of new technologies and the inability to develop advanced technologies to maximise the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs;

performance in project execution on the part of contractors who are awarded project construction activities generally based on the EPC (Engineering, Procurement and Construction) contractual scheme;

changes in operating conditions and cost overruns;

the actual performance of the reservoir and natural field decline; and

the ability and time necessary to build suitable transport infrastructures to export production to final markets.
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The occurrence of any of such risks may negatively affect the time-to-market of the reserves and cause cost overruns and a delayed pay-back period, therefore adversely affecting the economic returns of Eni’s development projects and the achievement of production growth targets.
Development projects normally have long lead times due to the complexity of the activities and tasks that need to be performed before a project final investment decision is made and commercial production can be achieved. Those activities include the appraisal of a discovery to evaluate the technical and economic feasibility of the development project, obtaining the necessary authorizations from governments, state agencies or national oil companies, signing agreements with the first party regulating a project’s contractual terms such as the production sharing, obtaining partners’ approval, environmental permits and other conditions, signing long-term gas contracts, carrying out the concept design and the front-end engineering and building and commissioning the related plants and facilities. All these activities normally can take years to perform. As a consequence, rates of return for such projects are exposed to the volatility of oil and gas prices and costs which may be substantially different from those estimated when the investment decision was made, thereby leading to lower return rates. Moreover, projects executed with partners and joint venture partners reduce the ability of the Company to manage risks and costs, and Eni could have limited influence over and control of the operations and performance of its partners. Furthermore, Eni may not have full operational control of the joint ventures in which it participates and may have exposure to counterparty credit risk and disruption of operations and strategic objectives due to the nature of its relationships.
Finally, if the Company is unable to develop and operate major projects as planned, particularly if the Company fails to accomplish budgeted costs and time schedules, it could incur significant impairment losses of capitalised costs associated with reduced future cash flows of those projects.
Inability to replace oil and natural gas reserves could adversely impact results of operations and financial condition
In case the Company’s exploration efforts are unsuccessful at replacing produced oil and natural gas, its reserves will decline. In addition to being a function of production, revisions and new discoveries, the Company’s reserve replacement is also affected by the entitlement mechanism in its production sharing agreements (“PSAs”), whereby the Company is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditure, and vice versa. Based on the current portfolio of oil and gas assets, Eni’s management estimates that production entitlements vary on average by approximately 330 barrels/d for each $1 change in oil prices based on current Eni’s assumptions for oil prices. In 2020, production and year-end proved reserves benefitted from lower oil prices which translated into higher entitlements (approximately 12 kBOE/d of incremental production and 118 MBOE of reserves volumes). In case oil prices differ significantly from Eni’s own forecasts, the result of the above-mentioned sensitivity of production to oil price changes may be significantly different.
Future oil and gas production is a function of the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiations with national oil companies and other owners of known reserves and acquisitions.
An inability to replace produced reserves by discovering, acquiring and developing additional reserves could adversely impact future production levels and growth prospects. If Eni is unsuccessful in meeting its long-term targets of production growth and reserve replacement, Eni’s future total proved reserves and production will decline.
Uncertainties in estimates of oil and natural gas reserves
The accuracy of proved reserve estimates and of projections of future rates of production and timing of development expenditures depends on a number of factors, assumptions and variables, including:

the quality of available geological, technical and economic data and their interpretation and judgement;

management’s assumptions regarding future rates of production and costs and timing of operating and development expenditures. The projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions;
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changes in the prevailing tax rules, other government regulations and contractual conditions;

results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and

changes in oil and natural gas prices which could affect the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.
Many of the factors, assumptions and variables underlying the estimation of proved reserves involve management’s judgement or are outside management’s control (prices, governmental regulations) and may change over time, therefore affecting the estimates of oil and natural gas reserves from year-to-year.
The prices used in calculating Eni’s estimated proved reserves are, in accordance with the SEC requirements, calculated by determining the unweighted arithmetic average of the first day-of-the-month commodity prices for the preceding twelve months. For the 12-months ending at December 31, 2020, average prices were based on 41 $/BBL for the Brent crude oil, which was materially lower than the reference price of 63 $/BBL utilized in 2019 due to the effects of the pandemic-induced economic crisis on demand and prices of hydrocarbons. Also, the reference price of natural gas was markedly lower than in 2019. Those reductions resulted in Eni having to remove 124 MBOE of proved reserves because they have become uneconomical in this price environment.
Accordingly, the estimated reserves reported as of the end of 2020 could be significantly different from the quantities of oil and natural gas that will be ultimately recovered. Any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s business prospects, results of operations, cash flows and liquidity.
At the end of 2020 due to a combination of a slowdown in development expenditures because of the need to preserve the Group liquidity during the downturn and the removal of a significant amount of reserves that have become uneconomical in this environment, the Group reserves additions for the year of 271 MBOE fell significantly short of the volume produced of 634 MBOE, negatively affecting the replacement ratio of produced volumes and the total quantity of proved reserves at year-end compared to 2019 (down by 5%) which could negatively affect the Group’s growth prospects going forward.
The development of the Group’s proved undeveloped reserves may take longer and may require higher levels of capital expenditures than it currently anticipates or the Group’s proved undeveloped reserves may not ultimately be developed or produced
At December 31, 2020, approximately 30% of the Group’s total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The Group’s reserve estimates assume it can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate and are subject to the risk of a structural decline in the prices of hydrocarbons due to possible long-lasting effects associated with the COVID-19 pandemic, including acceleration towards a low-carbon economy and a shift in consumers’ behaviour and preferences. In case of a continued decline in the prices of hydrocarbon the Group may not have enough financial resources to make the necessary expenditures to recover undeveloped reserves. The Group’s reserve report at December 31, 2020 includes estimates of total future development and decommissioning costs associated with the Group’s proved total reserves of approximately €27.7 billion (undiscounted, including consolidated subsidiaries and equity-accounted entities). It cannot be certain that estimated costs of the development of these reserves will prove correct, development will occur as scheduled, or the results of such development will be as estimated. In case of change in the Company’s plans to develop those reserves, or if it is not otherwise able to successfully develop these reserves as a result of the Group’s inability to fund necessary capital expenditures or otherwise, it will be required to remove the associated volumes from the Group’s reported proved reserves.
Oil and gas activity may be subject to increasingly high levels of income taxes and royalties
Oil and gas operations are subject to the payment of royalties and income taxes, which tend to be higher than those payable in many other commercial activities. Furthermore, in recent years, Eni has experienced adverse changes in the tax regimes applicable to oil and gas operations in a number of countries where the Company conducts its upstream operations. As a result of these trends, management estimates that the tax rate applicable to the Company’s oil and gas operations is materially higher than the
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Italian statutory tax rate for corporate profit, which currently stands at 24%. Management believes that the marginal tax rate in the oil and gas industry tends to increase in correlation with higher oil prices, which could make it more difficult for Eni to translate higher oil prices into increased net profit. However, the Company does not expect that the marginal tax rate will decrease in response to falling oil prices. Adverse changes in the tax rate applicable to the Group’s profit before income taxes in its oil and gas operations would have a negative impact on Eni’s future results of operations and cash flows.
In the current uncertain financial and economic environment, governments are facing greater pressure on public finances, which may induce them to intervene in the fiscal framework for the oil and gas industry, including the risk of increased taxation, windfall taxes, and even nationalisations and expropriations.
The present value of future net revenues from Eni’s proved reserves will not necessarily be the same as the current market value of Eni’s estimated crude oil and natural gas reserves
The present value of future net revenues from Eni’s proved reserves may differ from the current market value of Eni’s estimated crude oil and natural gas reserves. In accordance with the SEC rules, Eni bases the estimated discounted future net revenues from proved reserves on the 12-month un-weighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the SEC pricing used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:

the actual prices Eni receives for sales of crude oil and natural gas;

the actual cost and timing of development and production expenditures;

the timing and amount of actual production; and

changes in governmental regulations or taxation.
The timing of both Eni’s production and its incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. Additionally, the 10% discount factor Eni uses when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Eni’s reserves or the crude oil and natural gas industry in general. At December 31, 2020 the net present value of Eni’s proved reserves totalled approximately €27.7 billion and was materially lower than at the end of 2019 because the average prices used to estimate Eni’s proved reserves and the net present value at December 31, 2020, as calculated in accordance with the SEC rules, were 41 $/barrel for the Brent crude oil compared to 63 $/barrel utilized in 2019 due to the big fall recorded in hydrocarbons prices during the course of 2020 as a result of the demand contraction caused by the COVID-19 pandemic. Actual future prices may materially differ from those used in our year-end estimates.
Oil and gas activity may be subject to increasingly high levels of regulations throughout the world, which may impact our extraction activities and the recoverability of reserves
The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. These risks can limit the Group’s access to hydrocarbons reserves or may cause the Group to redesign, curtail or cease its oil&gas operations with significant effects on the Group’s business prospects, results of operations and cash flow.
In Italy, the activities of hydrocarbon development and production are performed by oil companies in accordance to concessions granted by the Ministry of Economic Development in agreement with the relevant Region territorially involved in the case of onshore concessions. Concessions are granted for an initial twenty-year term; the concessionaire is entitled to a ten-year extension and then to one or more five-year extensions to fully recover a field’s reserves and investments on the condition that the concessionaire has fulfilled all obligations related to the work program agreed in the initial concession award. In case of delay in the award of an extension, the original concession remains fully effective until the administrative procedure to grant an extension is finalized. These general rules are to be coordinated with a new law that was enacted in February 2019. This law requires certain Italian administrative bodies to adopt by the end of 2021 a plan intended to identify areas that are suitable for carrying out exploration, development and production of hydrocarbons in the national territory, including the territorial seawaters. Until approval of such a plan, a moratorium on exploration activities, including the award of new
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exploration leases, is in effect. Following the plan approval, exploration permits will resume in areas that have been identified as suitable and new exploration permits can be awarded. However, in unsuitable areas, exploration permits will be repealed, applications for obtaining new exploration permits ongoing at the time of the law enactment will be rejected and no new permit applications can be filed. As far as development and production concessions are concerned, pending the national plan approval, ongoing concessions remain in effect and administrative procedures underway to grant extensions to expired concessions remain unaffected; however, no applications to obtain new concessions can be filed. Once the above mentioned national plan is adopted, development and production concessions that fall in suitable areas can be granted further extensions and applications for new concessions can be filed; however, development and production concessions in place as at the approval of the national plan that fall in unsuitable areas will be repealed at their expiration, no further extensions will be granted, and no new concession applications can be filed or awarded. According to the statute, areas that are suitable to the activities of exploring and developing hydrocarbons must conform to a number of criteria including morphological characteristics and social, urbanistic and industrial constraints, with particular bias for the hydrogeological balance, current territorial planning and with regard to marine areas for externalities on the ecosystem, reviews of marine routes, fishing and any possible impacts on the coastline.
The Group’s largest operated development concession in Italy is Val d’Agri, which term expired on October 26, 2019. Development activities at the concession have continued since then in accordance with the “prorogation regime” described above, within the limits of the work plan approved when the concession was first granted. The Company filed an application to obtain a ten-year extension of the concession in accordance to the terms set by the law and before the enactment of the new law on the national plan for hydrocarbons activity. In this application the Company confirmed the same work program as in the original concession award. Similarly, Company operations are underway in accordance to the ongoing prorogation regime at another 41 expired Italian concessions for hydrocarbons development and production. The Company has also filed requests for extensions within the terms of the law for those concessions.
As far as proven reserves estimates are concerned, management believes the criteria laid out in the new law to be high-level principles, which make it difficult to identify in a reliable and objective manner areas that might be suitable or unsuitable to hydrocarbons activities before the plan is adopted by Italian authorities. However, based on the review of all facts and circumstances and on the current knowledge of the matter, management does not expect any material impact on the Group’s future performance.
Eni’s future performance depends on its ability to identify and mitigate the above-mentioned risks and hazards which are inherent to its oil&gas business. Failure to properly manage those risks, the Company’s underperformance at exploration, development and reserve replacement activities or the occurrence of unforeseen regulatory risks may adversely and materially impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
Risks related to political considerations
As of December 31, 2020, approximately 83% of Eni’s proved hydrocarbon reserves were located in non-OECD countries, mainly in Africa and central-south East Asia, where the socio-political framework, the financial system and the macroeconomic outlook are less stable than in the OECD countries. In those non-OECD countries, Eni is exposed to a wide range of political risks and uncertainties, which may impair Eni’s ability to continue operating economically on a temporary or permanent basis, and Eni’s ability to access oil and gas reserves. Particularly, Eni faces risks in connection with the following potential issues and risks:

socio-political instability leading to internal conflicts, revolutions, establishment of non-democratic regimes, protests, attacks, strikes and other forms of civil disorder and unrest, such as strikes, riots, sabotage, acts of violence and similar events. These risks could result in disruptions to economic activity, loss of output, plant closures and shutdowns, project delays, loss of assets and threats to the security of personnel. They may disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographical areas in which Eni operates. Additionally, any possible reprisals because of military or other action, such as acts of terrorism in Europe, the United States or elsewhere, could have a material adverse effect on the world economy and hence on the global demand for hydrocarbons;

lack of well-established and reliable legal systems and uncertainties surrounding the enforcement of contractual rights;
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unfavourable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriation, nationalisation or forced divestiture of assets and unilateral cancellation or modification of contractual terms;

sovereign default or financial instability due to the fact that those countries rely heavily on petroleum revenues to sustain public finance and petroleum revenues have dramatically contracted in 2020 due plunging hydrocarbons prices as a consequence of the global economic crisis caused by the COVID-19 pandemic. Financial difficulties at country level often translate into failure by state-owned companies and agencies to fulfil their financial obligations towards Eni relating to funding capital commitments in projects operated by Eni or to timely paying for supplies of equity oil and gas volumes;

restrictions on exploration, production, imports and exports;

tax or royalty increases (including retroactive claims);

difficulties in finding qualified international or local suppliers in critical operating environments; and

complex processes of granting authorisations or licences affecting time-to-market of certain development projects.
The financial outlook of several, non-OECD countries where Eni is operating was significantly affected by the material contraction recorded in hydrocarbons revenues following the COVID-19 pandemic, which also increased the counterparty risk of a few state-owned or privately-held local companies that are Eni’s partners in certain projects to develop oil&gas reserves.
Areas where Eni operates and where the Company is particularly exposed to political risk include, but are not limited to Libya, Venezuela and Nigeria.
Eni’s operations in Libya are currently exposed to significant geopolitical risks. The current situation of social and political instability dates back to the revolution of 2011 that brought a change of regime and a civil war, triggering an uninterrupted period of lack of well-established institutions and recurrent episodes of internal conflict, clashes, disorders and other forms of civil turmoil. In the year of the revolution, Eni’s operations in Libya were materially affected by a full-scale war, which forced the Company to shut down its development and extractive activities for almost all of 2011, with a significant negative impact on the Group’s results of operation and cash flow. In subsequent years Eni has experienced frequent disruptions to its operations, albeit on a smaller scale than in 2011, due to security threats to its installations and personnel. In April 2019, a resurgence of the socio-political instability and a failure by the opposed factions to establish a national government triggered the resumption of the civil war with armed clashes in the area of Tripoli and elsewhere in the country. The situation continued to escalate also because international negotiations aimed at restoring a state of peace and stability proved elusive. 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). The Company repatriated its personnel and strengthened security measures at its plants and facilities still in operation. However, despite this difficult framework, the Company’s largest assets in Libya – the Bahr Essalam offshore platform and the onshore Mellitah oil and gas production centre – have continued to produce regularly. Due to those developments, we estimated a loss of output in the range of 9 KBBL/d on average for the year 2020. In late September, 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 to Eni’s operations in the country and to the Group’s results of operations and cash flow.
As of December 31, 2020, Libya represented approximately 10% of the Group’s total production; this percentage is forecasted to decrease in the medium term in line with the expected implementation of the Group’s strategy intended to diversify the Group’s geographical presence to better balance the geopolitical risk of the portfolio. In the event of major adverse events, such as the escalation of the internal conflict into a full-blown civil war, attacks, sabotage, social unrest, clashes and other forms of civil disorder, Eni could be forced to reduce or to shut down completely its production activities at its Libyan fields, which would significantly hit results of operations and cash flow.
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Venezuela is currently experiencing a situation of financial stress, which has been exacerbated by the economic recession caused by the effects of the COVID-19 pandemic. Lack of financial resources to support the development of the country’s hydrocarbons reserves has negatively affected the country’s production levels and hence fiscal revenues. The situation has been made worse by certain international sanctions targeting the country’s financial system and its ability to export crude oil to U.S. markets, which is the main outlet of Venezuelan production (see also “Sanctions targets” below).
Presently, the Company retains only one valuable asset in Venezuela: the 50%-participated Cardón IV joint venture, which is operating a natural gas offshore project and is supplying its production to the national oil company, PDVSA, under a long-term supply agreement. We also hold an equity interest in other two oil projects: the PetroJunin oilfield and the Corocoro field, with respect to which in past years we have registered significant impairment losses and reserves de-bookings, with currently little value left to recover. The main risk to Eni’s ability to recover its investment is the continued difficulty on the part of PDVSA to pay the receivables for the gas supplies of Cardón IV, resulting in a significant amount of overdue receivables. The joint-venture is systematically booking a loss provision on the revenues accrued. The expected credit loss was based on management’s appreciation of the counterparty risk driven by the findings of a review of the past experience of sovereign defaults on which basis a deferral in the collection of the gas revenues was estimated. As of December 31, 2020, Eni’s invested capital in Venezuela was approximately $1 billion. Despite the negative financial outlook of the country and of PDVSA, during the course of 2020 the Company was able to collect a certain percentage of accrued revenues, in line with management’s estimates of the expected credit losses. Eni expects the financial and political outlook of the country to remain a risk factor to Eni’s operations there for the foreseeable future.
We have significant credit exposure in Nigeria to state-owned and privately-held local companies, where the overall financial and economic outlook of the country has been made worse by the contraction of petroleum revenues due to the crisis of the oil sector in 2020 caused by the COVID-19 pandemic. Our credit exposure is due to the fact that we are funding the share of capital expenditures pertaining to Nigerian joint operators at Eni-operated oil projects. We have incurred in the past and it is possible to continue incurring in the future significant credit losses because of the ongoing difficulties of our Nigerian counterparts to reimburse amounts past due.
Eni is closely monitoring political, social and economic risks of the countries in which it has invested or intends to invest, in order to evaluate the economic and financial return of capital projects and to selectively evaluate projects. While the occurrence of these events is unpredictable, the occurrence of any such risks may adversely and materially impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
Finally, the United Kingdom left the European Union at the end of January 2020. Due to this decision, it is possible that in the future we may experience delays in moving our products and employees between the UK and EU. Also, additional tariffs and taxes could impact the demand for some of our products and this, combined with the weak macroeconomic conditions in both the EU and UK due to the COVID-19 pandemic, could have a material adverse effect on energy demand.
Sanction targets
The most relevant sanction programs for Eni are those issued by the European Union and the United States of America and in particular, as of today, the restrictive measures adopted by such authorities in respect of Russia and Venezuela.
In response to the Russia-Ukraine crisis, the European Union and the United States have enacted sanctions targeting, inter alia, the financial and energy sectors in Russia by restricting the supply of certain oil and gas items and services to Russia and certain forms of financing. Eni has adapted its activities to the applicable sanctions and will further adapt its business to any subsequent restrictive measures that shall be adopted by the relevant authorities. In response to these restrictions, the Company has put on hold its projects in the upstream sectors in Russia and currently is not engaged in any oil & gas project in the country. It is not possible to rule out the possibility that wider sanctions targeting the Russian energy, banking and/or finance industries may be implemented. Further sanctions imposed on Russia, Russian citizens or Russian companies by the international community, such as restrictions on purchases of Russian gas by European companies or measures restricting dealings with Russian counterparties, could adversely impact Eni's business, results of operations and cash flow. Furthermore, an escalation of the international crisis, resulting in a tightening of sanctions, could entail a significant disruption of energy supply and trade flows globally, which could have a material adverse effect on the Group's business, financial conditions, results of operations and prospects.
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Starting from 2017, the United States enacted a regime of economic and financial sanctions against Venezuela. The scope of the restrictions, initially targeting certain financial instruments issued or sold by the Government of Venezuela, was gradually expanded over 2017 and 2018 and then significantly broadened during the course of 2019 when Petroleos de Venezuela SA (“PDVSA”), the main national state-owned enterprise, has been added to the “Specially Designated Nationals and Blocked Persons List” and the Venezuelan governments and its controlled entities became subject to assets freeze in the United States. Even if such U.S. sanctions are substantially “primary” and therefore dedicated in principle to U.S. persons only, retaliatory measures and other adverse consequences may also interest foreign entities which operate with Venezuelan listed entities and/or in the oil sector of the country. The U.S. sanction regime against Venezuela has been further tightened in the final part of 2020 by restricting any Venezuelan oil exports, including swap schemes utilized by foreign entities to recover trade and financing receivables from PDVSA and other Venezuelan counterparties. This latter tightening of the sanction regime could jeopardize our ability to collect the trade receivable owed to us for our activity in the country.
Eni is carefully evaluating on a case by case basis the adoption of measures adequate to minimize its exposure to any sanctions risk which may affect its business operation. In any case, the U.S. sanctions add stress to the already complex financial, political and operating outlook of the country, which could further limit the ability of Eni to recover its investments in Venezuela.
Risks specific to the Company’s gas business in Italy
Current, negative trends in gas demands and supplies in Europe may impair the Company’s ability to fulfil its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts
Eni is currently party to a few long-term gas supply contracts with state-owned companies of key producing countries, from where most of the gas supplies directed to Europe are sourced via pipeline (Russia, Algeria, Libya and Norway). These contracts which were intended to support Eni’s sales plan in Italy and in other European markets, provide take-or-pay clauses whereby the Company has an obligation to lift minimum, pre-set volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, up to a minimum contractual quantity. Similar considerations apply to ship-or-pay contractual obligations which arise from contracts with pipeline owners, which the Company has entered into to secure long-term transport capacity. Long-term gas supply contracts with take-or pay clauses expose the Company to a volume risk, as the Company is obligated to purchase an annual minimum volume of gas, or in case of failure, to pay the underlying price. The structure of the Company’s portfolio of gas supply contracts is a risk to the profitability outlook of Eni’s wholesale gas business due to the current competitive dynamics in the European gas markets. In past downturns of the gas sector, the Company incurred significant cash outflows in response to its take-or-pay obligations. Furthermore, the Company’s wholesale business is exposed to volatile spreads between the procurement costs of gas, which are linked to spot prices at European hubs or to the price of crude oil, and the selling prices of gas which are mainly indexed to spot prices at the Italian hub. A reduction of the spreads between Italian and European spot prices for gas could negatively affect the profitability of our business by reducing the total addressable market and by reducing the margin to cover the business’s logistics costs and other fixed expenses.
Eni’s management is planning to continue its strategy of renegotiating the Company’s long-term gas supply contracts in order to constantly align pricing terms to current market conditions as they evolve and to obtain greater operational flexibility to better manage the take-or-pay obligations (volumes and delivery points among others), considering the risk factors described above. The revision clauses included in these contracts state the right of each counterparty to renegotiate the economic terms and other contractual conditions periodically, in relation to ongoing changes in the gas scenario. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will be ultimately obtained and the timing of recognition of profit. Furthermore, in case Eni and the gas suppliers fail to agree on revised contractual terms, both parties can start an arbitration procedure to obtain revised contractual conditions. All these possible developments within the renegotiation process could increase the level of risks and uncertainties relating the outcome of those renegotiations.
Risks associated with the regulatory powers entrusted to the Italian Regulatory Authority for Energy, Networks and Environment in the matter of pricing to residential customers
Eni’s wholesale gas and retail gas&power businesses are subject to regulatory risks mainly in our domestic market in Italy. The Italian Regulatory Authority for Energy, Networks and Environment (the “Authority”) is entrusted with certain powers in the matter of natural gas and power pricing. Specifically,
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the Authority retains a surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users until the market is fully opened. Developments in the regulatory framework intended to increase the level of market liquidity or of de-regulation or intended to reduce operators’ ability to transfer to customers cost increases in raw materials may negatively affect future sales margins of gas and electricity, operating results and cash flow.
Risks related to environmental, health and safety regulations and legal risks
Eni has incurred in the past, and will continue incurring, material operating expenses and expenditures, and is exposed to business risk in relation to compliance with applicable environmental, health and safety regulations in future years, including compliance with any national or international regulation on GHG emissions
Eni is subject to numerous European Union, international, national, regional and local laws and regulations regarding the impact of its operations on the environment and on health and safety of employees, contractors, communities and on the value of properties. We believe that laws and regulations intended to preserve the environment and to safeguard health and safety of workers and communities are particularly severe in our businesses due to their inherent nature because of flammability and toxicity of hydrocarbons and of industrial processes to develop, extract, refine and transport oil, gas and products. Generally, these laws and regulations require acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, including refinery and petrochemical plant operations, limit or prohibit drilling activities in certain protected areas, require to remove and dismantle drilling platforms and other equipment and well plug-in once oil and gas operations have terminated, provide for measures to be taken to protect the safety of the workplace and of plants and infrastructures, the health of employees, contractors and other Company collaborators and of communities involved by the Company’s activities, and impose criminal or civil liabilities for polluting the environment or harming employees’ or communities’ health and safety as result from the Group’s operations. These laws and regulations control the emission of scrap substances and pollutants, discipline the handling of hazardous materials and set limits to or prohibit the discharge of soil, water or groundwater contaminants, emissions of toxic gases and other air pollutants or can impose taxes on polluting air emissions, as in the case of the European Trading Scheme that requires the payment of a tax for each tonne of carbon dioxide emitted in the environment above a pre-set allowance, resulting from the operation of oil and natural gas extraction and processing plants, petrochemical plants, refineries, service stations, vessels, oil carriers, pipeline systems and other facilities owned or operated by Eni. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste. Breaches of environmental, health and safety laws and regulations as in the case of negligent or wilful release of pollutants and contaminants into the atmosphere, the soil, water or groundwater or exceeding the concentration thresholds of contaminants set by the law expose the Company to the incurrence of liabilities associated with compensation for environmental, health or safety damage and expenses for environmental remediation and clean-up. Furthermore, in the case of violation of certain rules regarding the safeguard of the environment and the health of employees, contractors and other collaborators of the Company, and of communities, the Company may incur liabilities in connection with the negligent or wilful violation of laws by its employees as per Italian Law Decree No. 231/2001.
Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures in the foreseeable future to comply with laws and regulations and to safeguard the environment and the health and safety of employees, contractors and communities involved by the Company operations, including:

costs to prevent, control, eliminate or reduce certain types of air and water emissions and handle waste and other hazardous materials, including the costs incurred in connection with government action to address climate change (see the specific section below on climate-related risks);

remedial and clean-up measures related to environmental contamination or accidents at various sites, including those owned by third parties (see discussion below);

damage compensation claimed by individuals and entities, including local, regional or state administrations, should Eni cause any kind of accident, oil spill, well blowouts, pollution, contamination, emission of GHG and other air pollutants above permitted levels or of any other hazardous gases, water, ground or air contaminants or pollutants, as a result of its operations or if the Company is found guilty of violating environmental laws and regulations; and
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costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging at the end of oil&gas field production.
As a further consequence of any new laws and regulations or other factors, like the actual or alleged occurrence of environmental damage at Eni’s plants and facilities, the Company may be forced to curtail, modify or cease certain operations or implement temporary shutdowns of facilities. For example, in Italy Eni has experienced in recent years a number of temporary plant shutdowns at our Val d’Agri oil treatment centre due to environmental issues and oil spillovers, causing loss of output and of revenues. The Italian judicial authorities have started legal proceedings to verify alleged environmental crimes or crimes against the public safety and other criminal allegations as described in the notes to the Consolidated Financial Statements.
If any of the risks set out above materialise, they could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
Climate-related risks
The civil society and the national governments adhering to the 2015 COP 21 Paris Agreement are stepping up efforts to reduce the risks of climate change and to support an ongoing transition to a low-carbon economy, which will likely lead to the adoption of national and international laws and regulations intended to curb carbon emissions, as well as to the implementation of fiscal measures which could possibly drive technological breakthrough in the use of hydrogen, exponential growth in the development of renewables energies and fast-growing adoption of electric vehicles, thus reducing the world’s economy reliance on fossil fuels. These trends could materially affect demand for hydrocarbons in the long-term, while we expect increased compliance costs for the Company in the short-term. Eni is also exposed to risks of unpredictable extreme meteorological events linked to climate change. All these developments may adversely and materially affect the Group’s profitability, businesses outlook and reputation
The civil society and the national governments adhering to the 2015 COP 21 Paris Agreement, with the EU playing a leading role, are advancing plans and initiatives intended to transition the economy towards a low-carbon model in the long run, as the scientific community has been sounding alarms over the potential, catastrophic consequences for human life on the planet in connection with risks of climate change, based on the scientific relationship between global warming and increasing GHG concentration in the atmosphere, mainly as a result of burning fossil fuels. This push, as well as increasingly stricter regulations in this area, could adversely and materially affect the Group’s business.
Those risks may emerge in the short and medium-term, as well as over the long term.
Eni expects that the achievement of the Paris Agreement goal of limiting the rise in temperature to well below 2° C above pre-industrial levels, or the more stringent goal advocated by the Intergovernmental Panel on Climate Change (IPCC) of limiting global warming to 1.5° C, will strengthen the global response to the issue of climate change and spur governments to introduce measures and policies targeting the reduction of GHG emissions, which are expected to bring about a gradual reduction in the use of fossil fuels over the medium to long-term, notably through the diversification of the energy mix, likely reducing local demand for fossil fuels and negatively affecting global demand for oil and natural gas.
Recently, governmental institutions have responded to the issue of climate change on two fronts: on the one side, governments can both impose taxes on GHG emissions and incentivise a progressive shift in the energy mix away from fossil fuels, for example, by subsidising the power generation from renewable sources; on the other side they can promote worldwide agreements to reduce the consumption of hydrocarbons. This trend has been progressively gaining traction with an increasing number of governments adopting national agendas and strategies intended to reach the goals of the Paris Agreement and formally pledging to obtain net-zero emissions by 2050, like the EU’s Green Deal, which may lead to the enactment of various measure to constrain, limit or prohibit altogether the use of fossil fuels. This trend could increase both in breadth and severity if more governments follow suit.
The dramatic fallout of the COVID-19 pandemic on economic activity and people’s lifestyle could possibly result in a breakthrough in the evolution towards a low-carbon model of development. The unprecedented contraction in economic activity caused by the lockdown measures adopted throughout the world to contain the spread of the virus, which resulted in the suppression of demand for hydrocarbons, could have an enduring impact on the future role of hydrocarbons in satisfying global energy needs. This is because many governments and the EU have deployed massive amounts of resources to help rebuild entire
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economies and industrial sectors hit by the pandemic-induced crisis and a large part of this economic stimulus has been or is planned to be directed to help transitioning the economy and the energy mix towards a low-carbon model, as in the case of the EU’s recovery fund, which provides for huge investments in the sector of renewable energies and the green economy, including large-scale adoption of hydrogen as a new energy source. At the same time, the auto industry is ramping up production of electric vehicles (EVs) and boosting the EVs line-up, while large amounts of risk capital and financing is propelling the growth of an entire new industry of pure-EV players. The growing role of EVs in transportation is leveraging on state subsidies to incentivize the purchase of EVs and growing interest among consumers towards EVs. Other potentially disruptive technologies designated to produce energy without fossil fuels and to replace the combustion engine in the transport sector are emerging, driven by the development of hydrogen-based innovations. These trends could disrupt demand for hydrocarbons in the not so distant future, with many forecasters, both within the industry, or state agencies and independent observers predicting peak oil demand sometimes in the next ten years or earlier; some operators still consider 2019 as the peak year for oil demand. A large portion of Eni’s business depends on the global demand for oil and natural gas. If existing or future laws, regulations, treaties, or international agreements related to GHG and climate change, including state incentives to conserve energy or use alternative energy sources, technological breakthrough in the field of renewable energies or mass-adoption of electric vehicles trigger a structural decline in worldwide demand for oil and natural gas, our results of operations and business prospects may be materially and adversely affected.
We expect our operating and compliance expenses to increase in the short-term due to the likely growing adoption of carbon tax mechanisms. Some governments have already introduced carbon pricing schemes, which can be an effective measure to reduce GHG emissions at the lowest overall cost to society. Today, about half of the direct GHG emissions coming from Eni’s operated assets are included in national or supranational Carbon Pricing Mechanisms, such as the European Emission Trading Scheme (ETS), as a result of which the Company incurs operating expenses. For example, under the European ETS, Eni is obligated to purchase, on the open markets, emission allowances in case its GHG emissions exceed a pre-set amount of free emission allowances. In 2020 to comply with this carbon emissions scheme, Eni purchased on the open market allowances corresponding to 10.5 million tonnes of CO2 emissions. Due to the likelihood of new regulations in this area and expectations of a reduction in free allowances under the European ETS and of the adoption of similar schemes by a rising number of governments, Eni is aware of the risk that a growing share of the Group’s GHG emissions could be subject to carbon-pricing and other forms of climate regulation in the not so distant future, leading to additional compliance obligations with respect to the release, capture, and use of carbon dioxide that could result in increased investments and higher project costs for Eni. Eni also expects that governments will require companies to apply technical measures to reduce their GHG emissions.
The scientific community has concluded that increasing global average temperature produces significant physical effects, such as the increased frequency and severity of hurricanes, storms, droughts, floods or other extreme climatic events that could interfere with Eni’s operations and damage Eni’s facilities. Extreme and unpredictable weather phenomena can result in material disruption to Eni’s operations, and consequent loss of or damage to properties and facilities, as well as a loss of output, loss of revenues, increasing maintenance and repair expenses and cash flow shortfall.
Finally, there is a reputational risk linked to the fact that oil companies are increasingly perceived by institutions and the general public as entities primarily responsible for global warming due to GHG emissions across the hydrocarbons value-chain, particularly related with the use of energy products. This could possibly make Eni’s shares less attractive to investment funds and individual investors who have been more and more assessing the risk profile of companies against their carbon footprint when making investment decisions. Furthermore, a growing number of financing institutions, including insurance companies, appear to be considering limiting their exposure to fossil fuel projects, as witnessed by a pledge from the World Bank to stop financing upstream oil and gas projects and a proposal from the EU finance minister to reduce the financing granted to oil&gas projects via the European Investment Bank (EIB). This trend could have a material adverse effect on the price of our securities and our ability to access equity or other capital markets. Accordingly, our ability to obtain financing for future projects or to obtain it at competitive rates may be adversely impacted. Further, in some countries, governments and regulators have filed lawsuits seeking to hold fossil fuel companies, including Eni, liable for costs associated with climate change. Losing any of these lawsuits could have a material adverse effect on our business prospects.
As a result of these trends, climate-related risks could have a material and adverse effect the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
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Eni is exposed to the risk of material environmental liabilities in addition to the provisions already accrued in the consolidated financial statement.
Eni has incurred in the past and may incur in the future material environmental liabilities in connection with the environmental impact of its past and present industrial activities. Eni is also exposed to claims under environmental requirements and, from time to time, such claims have been made against us. Furthermore, environmental regulations in Italy and elsewhere typically impose strict liability. Strict liability means that in some situations Eni could be exposed to liability for clean-up and remediation costs, environmental damage, and other damages as a result of Eni’s conduct of operations that was lawful at the time it occurred or of the conduct of prior operators or other third parties. In addition, plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution or in case the Company is found liable of violations of any environmental laws or regulations. In Italy, Eni is exposed to the risk of expenses and environmental liabilities in connection with the impact of its past activities at certain industrial hubs where the Group’s products were produced, processed, stored, distributed or sold, such as chemical plants, mineral-metallurgic plants, refineries and other facilities, which were subsequently disposed of, liquidated, closed or shut down. At these industrial hubs, Eni has undertaken several initiatives to remediate and to clean-up proprietary or concession areas that were allegedly contaminated and polluted by the Group’s industrial activities. State or local public administrations have sued Eni for environmental and other damages and for clean-up and remediation measures in addition to those which were performed by the Company, or which the Company has committed to perform. In some cases, Eni has been sued for alleged breach of criminal laws (for example for alleged environmental crimes such as failure to perform soil or groundwater reclamation, environmental disaster and contamination, discharge of toxic materials, amongst others). Although Eni believes that it may not be held liable for having exceeded in the past pollution thresholds that are unlawful according to current regulations but were allowed by laws then effective, or because the Group took over operations from third parties, it cannot be excluded that Eni could potentially incur such environmental liabilities. Eni’s financial statements account for provisions relating to the costs to be incurred with respect to clean-ups and remediation of contaminated areas and groundwater for which a legal or constructive obligations exist and the associated costs can be reasonably estimated in a reliable manner, regardless of any previous liability attributable to other parties. The accrued amounts represent management’s best estimates of the Company’s existing liabilities. Management believes that it is possible that in the future Eni may incur significant or material environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the likelihood of as yet unknown contamination; (ii) the results of ongoing surveys or surveys to be carried out on the environmental status of certain Eni’s industrial sites as required by the applicable regulations on contaminated sites; (iii) unfavourable developments in ongoing litigation on the environmental status of certain of the Company’s sites where a number of public administrations, the Italian Ministry of the Environment or third parties are claiming compensation for environmental or other damages such as damages to people’s health and loss of property value; (iv) the possibility that new litigation might arise; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of environmental restoration and remediation programs are often inherently difficult to estimate leading to underestimation of the future costs of remediation and restoration, as well as unforeseen adverse developments both in the final remediation costs and with respect to the final liability allocation among the various parties involved at the sites. As a result of these risks, environmental liabilities could be substantial and could have a material adverse effect the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
Risks related to legal proceedings and compliance with anti-corruption legislation
Eni is the defendant in a number of civil and criminal actions and administrative proceedings. In future years Eni may incur significant losses due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements or to judge a negative outcome only as possible or to conclude that a contingency loss could not be estimated reliably; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to circumstances that are often inherently difficult to estimate. Certain legal proceedings and investigations in which Eni or its subsidiaries or its officers and employees are defendants involve the alleged breach of anti-bribery and anti-corruption laws and regulations and other ethical misconduct. Such proceedings are described in the notes to the condensed consolidated interim financial statements, under the heading “Legal Proceedings”. Ethical misconduct and noncompliance with applicable laws and regulations, including noncompliance with anti-bribery and
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anti-corruption laws, by Eni, its officers and employees, its partners, agents or others that act on the Group’s behalf, could expose Eni and its employees to criminal and civil penalties and could be damaging to Eni’s reputation and shareholder value.
Internal control risks
Risks from acquisitions
Eni is constantly monitoring the oil and gas market in search of opportunities to acquire individual assets or companies with a view of achieving its growth targets or complementing its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case a prolonged decline in the market prices of oil and natural gas occurs. Eni may also incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets it acquires. If the integration and financial risks related to acquisitions materialise, expected synergies from acquisition may fall short of management’s targets and Eni’s financial performance and shareholders’ returns may be adversely affected.
Eni’s crisis management systems may be ineffective
Eni has developed contingency plans to continue or recover operations following a disruption or incident. An inability to restore or replace critical capacity to an agreed level within an agreed period could prolong the impact of any disruption and could severely affect business, operations and financial results. Eni has crisis management plans and the capability to deal with emergencies at every level of its operations. If Eni does not respond or is not seen to respond in an appropriate manner to either an external or internal crisis, this could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
Disruption to or breaches of Eni’s critical IT services or digital infrastructure and security systems could adversely affect the Group’s business, increase costs and damage our reputation
The Group’s activities depend heavily on the reliability and security of its information technology (IT) systems and digital security. The Group’s IT systems, some of which are managed by third parties, are susceptible to being compromised, damaged, disrupted or shutdown due to failures during the process of upgrading or replacing software, databases or components, power or network outages, hardware failures, cyber-attacks (viruses, computer intrusions), user errors or natural disasters. The cyber threat is constantly evolving. The oil and gas industry is subject to fast-evolving risks from cyber threat actors, including nation states, criminals, terrorists, hacktivists and insiders. Attacks are becoming more sophisticated with regularly renewed techniques while the digital transformation amplifies exposure to these cyber threats. The adoption of new technologies, such as the Internet of Things (IoT) or the migration to the cloud, as well as the evolution of architectures for increasingly interconnected systems, are all areas where cyber security is a very important issue. The Group and its service providers may not be able to prevent third parties from breaking into the Group’s IT systems, disrupting business operations or communications infrastructure through denial-of-service attacks, or gaining access to confidential or sensitive information held in the system. The Group, like many companies, has been and expects to continue to be the target of attempted cybersecurity attacks. While the Group has not experienced any such attack that has had a material impact on its business, the Group cannot guarantee that its security measures will be sufficient to prevent a material disruption, breach or compromise in the future. As a result, the Group’s activities and assets could sustain serious damage, services to clients could be interrupted, material intellectual property could be divulged and, in some cases, personal injury, property damage, environmental harm and regulatory violations could occur.
If any of the risks set out above materialise, they could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
Violations of data protection laws carry fines and expose us and/or our employees to criminal sanctions and civil suits
Data protection laws and regulations apply to Eni and its joint ventures and associates in the vast majority of countries in which we do business. The EU General Data Protection Regulation (GDPR) came into effect in May 2018 and increased penalties up to a maximum of 4% of global annual turnover for
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breach of the regulation. The GDPR requires mandatory breach notification, a standard also followed outside of the EU (particularly in Asia). Non-compliance with data protection laws could expose us to regulatory investigations, which could result in fines and penalties as well as harm our reputation. In addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations. We could also be subject to litigation from persons or corporations allegedly affected by data protection violations. Violation of data protection laws is a criminal offence in some countries, and individuals can be imprisoned or fined.
If any of the risks set out above materialise, they could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
Risks related to financial matters
Exposure to financial risk – We are exposed to treasury and trading risks, including liquidity risk, interest rate risk, foreign exchange risk, commodity price risk and credit risk and we may incur substantial losses in connection with those risks
Our business is exposed to the risk that changes in interest rates, foreign exchange rates or the prices of crude oil, natural gas, LNG, refined products, chemical feedstocks, power and carbon emission rights will adversely affect the value of assets, liabilities or expected future cash flows.
The Group does not hedge its exposure to volatile hydrocarbons prices in its business of developing and extracting hydrocarbons reserves and other types of commodity exposures (e.g. exposure to the volatility of refining margins and of certain portions of the gas long-term supply portfolio) except for specific markets or business conditions. The Group has established risk management procedures and enters into derivatives commodity contracts to hedge exposure to the commodity risk relating to commercial activities, which derives from different indexation formulas between purchase and selling prices of commodities. However, hedging may not function as expected. In addition, we undertake commodity trading to optimize commercial margins or with a view of profiting from expected movements in market prices. Although Eni believes it has established sound risk management procedures to monitor and control commodity trading, this activity involves elements of forecasting and Eni is exposed to the risks of incurring significant losses if prices develop contrary to management expectations and of default of counterparties.
We are exposed to the risks of unfavourable movements in exchange rates primarily because our consolidated financial statements are prepared in Euros, whereas our main subsidiaries in the Exploration & Production sector are utilizing the U.S. dollar as their functional currency. This translation risk is normally unhedged. Furthermore, our euro-denominated subsidiaries incur revenues and expenses in currencies other than the euro or are otherwise exposed to currency fluctuations because prices of oil, natural gas and refined products generally are denominated in, or linked to, the U.S. dollar, while a significant portion of Eni’s expenses are incurred in euros and because movements in exchange rates may negatively affect the fair value of assets and liabilities denominated in currencies other than the euro. Therefore, movements in the U.S. dollar (or other foreign currencies) exchange rate versus the euro affect results of operations and cash flows and year-on-year comparability of the performance. These exposures are normally pooled at Group level and net exposures to exchange rate volatility are netted on the marketplace using derivative transactions. However, the effectiveness of such hedging activity is uncertain, and the Company may incur losses also of significant amounts. As a rule of thumb, a depreciation of the U.S. dollar against the euro generally has an adverse impact on Eni’s results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in the U.S. dollar denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity.
We are exposed to fluctuations in interest rates that may affect the fair value of our financial assets and liabilities as well as the amount of finance expense recorded through profit. We enter into derivative transactions with purpose of minimizing our exposure to the interest rate risk.
Eni’s credit ratings are potentially exposed to risk from possible reductions of sovereign credit rating of Italy. On the basis of the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the debt instruments issued by the Company could be downgraded.
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We are exposed to credit risk; our counterparties could default, could be unable to pay the amounts owed to us in a timely manner or meet their performance obligations under contractual arrangements. These events could cause us to recognize loss provisions with respect to amounts owed to us by our debtors or in the worst case to write off a credit altogether. In recent years, the Group has experienced a significant level of counterparty default due to the severity of the economic and financial downturn that has negatively affected several Group counterparties, customers and partners and to the fact that Italy, which is still the largest market to Eni’s gas wholesale and retail businesses, has underperformed other OECD countries in terms of GDP growth. Those trends have been aggravated by the 2020 economic crisis caused by the lockdown measures adopted worldwide to contain the COVID-19 pandemic, resulting in a significantly deteriorated credit and financial profile of many of our counterparties, including national oil companies who are joint operators in our upstream projects, retail customers in the gas retail business and other industrial accounts. Therefore, in 2020 we incurred significant credit loss provisions based on management’s expectations of an increased default rate going forward, as the economic crisis is poised to continue affecting the financial conditions of our counterparties, and on evidence of our performance at collecting billed invoices in the retail gas&power business.
We believe that the retail gas & power segment is particularly exposed to credit risk due to its large and diversified customer base, which includes a large number of medium and small-sized businesses and retail customers who are expected to be particularly hit by the Italian economic recession. Eni’s Exploration & Production business is significantly exposed to credit risk because of the deteriorated financial outlook of many oil-producing countries due to the collapse recorded in crude oil prices and uncertainties about a stable recovery, which has negatively impacted petroleum revenues of those countries triggering financial instability. The financial difficulties of those countries have extended to state-owned oil companies and other national agencies who are partnering with Eni in the execution of oil&gas projects or who are buying Eni’s equity production in a number of oil&gas projects. These trends have limited Eni’s ability to fully recover or to collect timely its trade or financing receivables or its investments towards those entities. Eni believes that the management of doubtful accounts in the post pandemic environment represents a risk to the Company, which will require management focus and commitment going forward. Eni cannot exclude the recognition of significant provisions for doubtful accounts in future reporting periods. Management is closely monitoring exposure to the counterparty risk in its Exploration & Production business due to the magnitude of the exposure at risk and to the long-lasting effects of the oil price downturn on its industrial partners.
If any of the risks set out above materialises, this could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or that the Group is unable to sell its assets on the marketplace in order to meet short-term financial requirements and to settle obligations. Such a situation would negatively affect the Group’s results of operations and cash flows as it would result in Eni incurring higher borrowing expenses to meet its obligations or, under the worst conditions, the inability of Eni to continue as a going concern. Global financial markets are volatile due to several macroeconomic risk factors, including the fiscal outlook of the hydrocarbons-producing countries. In 2020, due to a collapse in hydrocarbons consumption and prices caused by an almost standstill of the global economy and travel in response to the COVID-19 pandemic, we experienced a material contraction in our cash flows from operations, which reduced the Company’s cash reserves. We were forced to reduce a significant portion of our liquidity reserves and we tapped the financial markets, as we managed through the downturn. We did not incur worsened borrowings conditions with respect to standard market terms or past fiscal years, nor were our finance expenses unusually high. However, due to an increase in the Company’s net exposure towards the financial system and indebtedness ratio, our liquidity risk profile has deteriorated. In case of new restrictive measures in response to a resurgence of the pandemic leading to a double-dip in economic activity and energy demand, in the event of extended periods of constraints in the financial markets, or if Eni is unable to access the financial markets (including cases where this is due to Eni’s financial position or market sentiment as to Eni’s prospects) at a time when cash flows from Eni’s business operations may be under pressure, we may incur significantly higher borrowing costs than in the past or difficulties obtaining the necessary financial resources to fund our development plans, therefore jeopardizing Eni’s ability to maintain long-term investment programs. Low investments to develop our reserves may significantly and negatively affect Eni’s business prospects, results of operations and cash flows, and may impact shareholder returns, including
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dividends or share price. The oil and gas industry is capital intensive. Eni makes and expects to continue to make substantial capital expenditures in its business for the exploration, development and production of oil and natural gas reserves. Over the next four years, the Company plans to invest in the oil&gas business approximately an average of €4.5 billion per year. In 2021, Eni expects to make capital expenditures slightly below the level of €6 billion, of which about 70% in the Exploration & Production segment, at the planned exchange rate of 1.19 USD/EUR. Historically, Eni’s capital expenditures have been financed with cash generated from operations, proceeds from asset disposals, borrowings under its credit facilities and proceeds from the issuance of debt and bonds. The actual amount and timing of future capital expenditures may differ materially from Eni’s estimates as a result of, among other things, changes in commodity prices, available cash flows, lack of access to capital, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments. Eni’s cash flows from operations and access to capital markets are subject to a number of variables, including but not limited to:

the amount of Eni’s proved reserves;

the volume of crude oil and natural gas Eni is able to produce and sell from existing wells;

the prices at which crude oil and natural gas are sold;

Eni’s ability to acquire, find and produce new reserves; and

the ability and willingness of Eni’s lenders to extend credit or of participants in the capital markets to invest in Eni’s bonds.
If revenues or Eni’s ability to borrow decrease significantly due to factors such as a prolonged decline in crude oil and natural gas prices, Eni might have limited ability to obtain the capital necessary to sustain its planned capital expenditures. If cash generated by operations, cash from asset disposals, or cash available under Eni’s liquidity reserves or its credit facilities is not sufficient to meet capital requirements, the failure to obtain additional financing could result in a curtailment of operations relating to development of Eni’s reserves, which in turn could adversely affect its business, financial condition, results of operations, and cash flows and its ability to achieve its growth plans. These factors could also negatively affect shareholders’ returns, including the amount of cash available for dividend distribution and share repurchases, as well as the share price. In addition, funding Eni’s capital expenditures with additional debt will increase its leverage and the issuance of additional debt will require a portion of Eni’s cash flows from operations to be used for the payment of interest and principal on its debt, thereby reducing its ability to use cash flows to fund capital expenditures and dividends.
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Item 4. INFORMATION ON THE COMPANY
History and development of the Company
Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders.
The name of the agent of Eni in the United States is Marco Margheri, Washington DC – USA 601, 13th street, NW 20005.
The Company engages in producing and selling energy products and services to worldwide markets, with operations in the traditional businesses of exploring for, developing, extracting and marketing crude oil and natural gas, manufacturing and marketing oil-based fuels and chemicals products and gas-fired power as well as energy products from renewable sources. The company is implementing a strategy designed to reduce in the long term its dependence on hydrocarbons and to increase the weight of decarbonized products in its portfolio and with the aim of reaching the target of net zero emissions of carbon dioxide (“CO2”) by 2050 to comply with the climate target of the Paris Agreement. According to the management, this strategic shift away from traditional hydrocarbon will place the Company in a very competitive position in the market for the supply of de-carbonized products, combining value creation, business sustainability and economic and financial robustness, lessening the Company’s dependence on the volatility of the results of the hydrocarbons businesses.
In June 2020, Eni’s Board of Directors established a new organizational structure with two business groups to align with the Company’s decarbonization strategy. The “Natural Resources” business group is responsible for enhancing the oil & gas portfolio of the Exploration & Production (“E&P”) segment in a sustainable manner, focusing also on energy efficiency activities, projects for forests conservation (REDD+) and projects for the capture, storage and/or utilization of CO2 (“CCS” or “CCU”). In addition to E&P, this business group comprises the wholesale gas and LNG businesses as well as the activity of environmental protection and remediation managed by our subsidiary Eni Rewind. The other business group “Energy Evolution” is responsible for progressing and developing the renewable businesses of generating and selling renewable power and manufacturing and marketing sustainable products obtained from decarbonized industrial processes (blue products) and by biomass (bio-products). This business group comprises the Refining & Marketing business, the chemical business managed by Versalis SpA and its subsidiaries, the retail gas and power business managed by Eni gas e luce and the business of producing and selling power from thermoelectric plants and renewable sources.
In re-designing the Group’s segment information for financial reporting purposes, management evaluated that the components of the Company whose operating results are regularly reviewed by the CEO (Chief Operating Decision Maker as defined by IFRS 8) to make decisions about the allocation of resources and to assess performance would continue being the single business units which are comprised in the two newly-established business groups, rather than the two groups themselves. Therefore, in order to comply with the provisions of the international reporting standard that regulates the segment reporting (IFRS 8), the new reportable segments of Eni, substantially confirming the pre-existing setup, are identified as follows:

Exploration & Production, which also comprises the economics of the forestry projects (REDD+) and projects for CO2 capture and storage and/or utilization. Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as in LNG operations, in 42 countries, most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and United Arab Emirates. In 2020, Eni average daily production amounted to 1,609 KBOE/d on an available- for-sale basis. As of December 31, 2020, Eni’s total proved reserves amounted to 6,905 mmBOE, which include subsidiary undertakings and proportionally consolidated entities and Eni’s share of reserves of equity-accounted joint ventures and associates.

Global Gas & LNG Portfolio: engages in the wholesale activity of supplying and selling natural
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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. In 2020, Eni’s worldwide sales of natural gas amounted to 64.99 BCM, of which 37.30 BCM was in Italy. The LNG business includes the purchase and marketing of LNG worldwide, with a large proportion of equity LNG supplies.

Refining & Marketing and Chemicals: engages in the manufacturing, supply and distribution and marketing activities of oil products and chemical products and in trading activities. The results of operations of the R&M business and of the chemical business have been combined in a single reporting segment because the two businesses exhibit similar characteristics. Oil and products trading activities are designed to perform supply balancing transactions on the market and to stabilize or hedge commercial margins. The R&M business engages in crude oil supply and refining and marketing of petroleum products to the cargo market, to large business accounts (airlines companies, bunker, public administrations, operators of privately-held networks of service stations) and to retail customers through a network of proprietary or leased service stations in Italy and in the rest of Europe. Production of refined products derives from both oil-based refineries and from manufacturing processes based on renewable feedstock. As of December 31, 2020, the balanced refining capacity was 548 KBBL/d. In 2020, processed volumes of crude oil and other feedstock, including renewable feedstock, amounted to 17.71 mmtonnes (of which traditional refinery throughputs were 17 mmtonnes and bio refinery throughputs were 0.71 mmtonnes) and sales of refined products were 26.08 mmtonnes, of which 20.02 mmtonnes were in Italy. Retail sales of refined products at Eni’s service stations amounted to 6.61 mmtonnes in Italy and in the rest of Europe. In 2020, Eni’s retail market share in Italy through its “Eni” branded network of service stations was 23.3%. In the Chemical business Eni, through its wholly-owned subsidiary Versalis, engages in the production and marketing of basic petrochemical products, plastics and elastomers. Versalis is developing the business of green chemicals. Activities are concentrated in Italy and in Europe. In 2020, production volumes of petrochemicals amounted to 8,073 ktonnes.

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 comprises trading activities of CO2 emission allowances and of forward sales of power to help stabilize/hedge the clean crack spreads of power sales. As at December 31, 2020, Eni customer base was 9.6 million retail points of delivery (gas and electricity) in Italy and Europe (of which 7.7 million were in Italy). In 2020, retail power sales to end customers, managed by Eni gas e luce and subsidiaries companies in France and Greece, amounted to 12.49 TWh. Retail gas sales, in Italy and in European markets, amounted to 7.68 BCM. 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. Eni is engaged in the renewable energy business (solar photovoltaic and wind facilities both onshore and offshore) through the business unit Energy Solutions which engages in building, commissioning and managing renewable energy producing plants. At the end of 2020, the total installed and sanctioned capacity amounted to 1 GW, of which the total installed capacity for the generation of energy from renewable sources amounted to 307 MW (in Eni share and including the storage power).

Corporate and Other activities: include the costs of the main business support functions, as well as the results of the Group environmental clean-up and remediation activities performed by the subsidiary Eni Rewind.
Eni’s registered head office is located at Piazzale Enrico Mattei 1, Rome, Italy (telephone number: +39-0659821).
Eni branches are located in:

San Donato Milanese (Milan), Via Emilia, 1; and

San Donato Milanese (Milan), Piazza Ezio Vanoni, 1. Internet address: eni.com
A list of Eni’s subsidiaries is provided in “Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements”.
Strategy
The Company is executing a strategy designed to adapt its business model and to grow in a low-carbon economy. Our long-term goal is to reach the carbon-neutrality of our industrial processes and products by
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2050, covering GHG scope 1, 2 and 3 emissions, in line with the goals set by the Paris Agreement on climate, which we fully endorse. The evolution of our business model and the underlying action plan will be accomplished over a thirty-year timeframe and will significantly increase the weight of fully-decarbonized products in our portfolio, while progressively reducing the Company’s exposure to traditional hydrocarbons products, capitalizing on the opportunities arising from a rapidly-changing energy landscape. The strategic guidelines that will drive our evolution going forward are:

To actively contribute to the achievement of the 17 UN SDGs which are reflected in Eni’s mission, particularly the goals of improving air quality and securing universal access to energy;

To maximize the integration of the portfolio along the entire value chain;

To retain a financial framework which prioritizes capital discipline and a strong balance sheet;

To improve the Group’s resilience to the oil scenario, also by reducing the exposure to the traditional oil-based businesses and growing the weight of the green/retail/circular economy businesses;

To leverage the technology to speed up the business evolution; and

To achieve a competitive, progressive shareholders’ distribution policy.
In the short-term, while progressing the transformation of its business model, the Company’s priorities will be to shore up its cash flow and to improve its financial resilience which have been significantly and adversely affected by the consequences of the COVID-19 pandemic on worldwide economic activity and human life.
In 2020, the Company was confronted with a challenging trading environment because the pandemic crisis drove a collapse in hydrocarbons demand, which pressured prices and margins of hydrocarbons. To contain the spread of the virus, governments throughout the world imposed tough lockdown measures which caused an unprecedented contraction in economic activity, international commerce and travel particularly in the second quarter of 2020, leading to a massive decline in demand for fuels and other hydrocarbons-based commodities. Prices for crude oil and natural gas plunged to multi-year lows at the peak of the crisis, during the March-April period, with the price of the Brent crude oil benchmark down to an historic low at around 15 $/bbl. The subsequent recovery in crude oil prices was supported by a rebound in economic activity, mainly in China and other parts of Asia, and by the huge production cuts implemented by the OPEC+ producers starting in May 2020. However, the recovery was not enough to overcome the losses incurred in the second quarter, because gains in crude oil prices were capped by a continuing rise in new virus cases particularly in the United States, continental Europe and the UK, while many people stayed at home and worked remotely, thus depressing demand for gasoline and other fuels. This situation explained why refining margins fell to record lows in the third and fourth quarter of 2020, while crude oil prices hovered around 40 $/bbl. Finally, the recovery in crude oil prices gained strength in the final months of 2020 and at the beginning of 2021 due to a combination of market and macro developments, most notably: substantial progress in developing vaccines against the virus, continuing production discipline on part of OPEC+ producers with the surprising announcement of further production cuts by the Saudi Arabia in early January 2021 and finally the outcome of the U.S. presidential election which boosted expectation for massive stimulus measures of the economy. Crude oil prices closed the year at about 50 $/bbl vs. an average price of approximately 42 $/bbl for the FY 2020, then the recovery gained steam in January through March 2021, with the average Brent price for the first quarter of 2021 above 60 $/bbl. However, the recovery has yet to be felt in the refining sector, where margins have continued to be depressed because of millions of people still locked down.
The hydrocarbons crisis of 2020 materially and adversely hit the Company’s results of operations and cash flows with an estimated loss of approximately €7 billion due to lower hydrocarbons prices and other COVID-related effects, net of management’s initiatives to cope with the downturn. Confronted with such a shortfall and an uncertain path to a demand recovery due to elevated risks of new, virus-induced economic lockdowns and travel restrictions as well as economic downturn, the Company has taken a number of steps to strengthen its balance sheet and to improve the financial resiliency of its operations, while maintaining its focus on implementing its decarbonization strategy. We plan to retain strict capital discipline in investment decisions going forward and to allocate cash prioritizing the preservation of a healthy balance sheet, shareholder returns, and an ongoing expansion into the low-carbon businesses.
The steps taken so far to deal with the effects of the 2020 downturn in the hydrocarbon sector on the Company’s results and financial position and our forecast actions for 2021 and the medium term are described below:
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During the peak of the crisis, we revised our operating plans for the remainder of 2020 and for 2021, resolving to reduce the cash outlays for capital expenditures and operating expenses by approximately €8 billion in that period.

As part of the €8 billion amount, we delivered a reduction of €2.6 billion in capital expenditures, equaling a cut of 35% of the original amount budgeted for 2020, and €1.9 billion of lowered operating expenses, of which 30% of structural nature. The reduction of capital expenditures was concentrated almost entirely in the E&P segment, where we could leverage on project re-phasing and remodulation to achieve the expected savings, with the option of resuming the delayed or suspended project phases once the scenario normalizes.

We are planning to invest an average yearly amount of less than €7 billion of organic expenditures in the business over the next four-year planning period compared to a level of €8 billion per year in previous planning assumptions before the COVID-19 crisis, to factor in expected risks and uncertainties about the recovery, thus signaling a more prudent approach to investment decisions than in the past. For 2021, we forecast a level of expenditures slightly below €6 billion;

Approximately 20% of the capex plan will be allocated to growing our decarbonized businesses, particularly the generation capacity of renewable power, the manufacturing capacity of biofuels, the expansion of our customer portfolio in the retail marketing of gas and power and the development of circular economy projects.

We have established a new, flexible distribution policy based on a fixed dividend plus a variable component linked to trends in the oil scenario. This new policy was initially announced to the market in July 2020, when we established a floor dividend of €0.36 per share at an oil price environment of at least 45 $/bbl of Brent. The floor dividend is expected to be reassessed periodically to factor in the Company’s progress at delivering on its strategy and industrial targets. For fiscal year 2020, management resolved to distribute the base dividend of €0.36 per share notwithstanding the yearly average price of the Brent crude oil was 42 $/bbl, lower than the internally set threshold. This policy was updated in February 2021, when the Company set its strategies and targets for the four-year plan 2021-2024 and the long-term. Going forward, the floor dividend of €0.36 per share is planned to be paid at an average Brent scenario of 43 $/bbl for the reference year and a variable dividend is expected to be paid as a function of an expected growth in cash flow driven by rising oil prices above the threshold of 43 $/bbl up to 65 $/bbl. See Item 5 – Management Expectations of Operations.

In 2020, in order to preserve the Company’s cash flow we decided to suspend the buy-back program of Eni’s shares. In our strategic update of February 2021, we reaffirmed our commitment to resume the buy-back of Eni’s shares and we lowered the Brent price threshold where the buy-back is expected to resume. We are now forecasting to allocate €300 million per year to the repurchase of Eni’s shares provided that the Brent price is not lower than 56 $/bbl; that amount will ramp-up to €400 million provided that the Brent price is not lower than 61 $/bbl and to €800 million from 66 $/bbl, which were the triggering prices of our prior shareholder return policy.

Our oil&gas production plans have been revised to discount our changed cash allocation priorities and reduced expenditures to develop our reserves both in 2020 and in the following years. In 2020, our oil&gas production on an available-for-sale basis averaged 1,609 KBOE/d which was negatively affected by capex curtailments, OPEC+ production quotas, lower gas demand and other operating factors. For 2021, we expect flat oil&gas production as compared to the prior year, assuming OPEC+ cuts of about 40 kBOE/d in the year. We anticipate production growth to resume in the subsequent years of our plans, as we are targeting an average growth rate of 4% in the four-year period 2021-2024. Despite strict capital discipline, we expect our future growth rate to be supported by continuing exploration success in proven and mature areas where the discovered resources can be developed by means of existing facilities and infrastructure without incurring additional expenses, the ramp-up/start-up of certain large projects where the majority of development expenses have already been incurred, planned production growth at our equity-accounted investments and an easing of the production cuts enacted by OPEC.

We are assuming a long-term crude oil price of the Brent benchmark at 60 $/bbl in real terms 2023 (nominal growth rate of 2% from 2024 onwards) – revised down from our prior assumption of 70 $/bbl — for our planning assumptions, investment decision processes and evaluation of the recoverability of the carrying amounts of oil&gas assets.
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In E&P, we plan to maximize the cash generation by growing production profitably, by retaining strict capital discipline in selecting exploration and development projects and by strengthening the resiliency of our portfolio made up of conventional oil&gas assets. Our goal is to reduce the Brent price at which the business can fund its capital expenditures needs through internally generated funds, leveraging the quality of its asset portfolio consisting of assets with low breakeven prices and fast time-to-market. The business will also advance several projects designed to address the issue of the decarbonization of the Group products, most notably two large projects which are in the pre-feasibility stage designed to capture carbon dioxide and store it at depleted offshore natural gas field in the northern section of the Adriatic Sea (Italy) and in the Liverpool Bay (UK). We plan to build an underground capacity to store up to 7 million tons per year of CO2 by 2030 (Eni’s share, corresponding to a gross capacity of 15 MTPA). Furthermore, we plan to ramp up a set of actions designated to sink CO2 by means of participating in projects for preserving forests (the so called REDD+ projects), targeting obtaining allowances to offset carbon emissions for an amount of 6 million tonnes per year in 2024 and more than 20 million by 2030.

In the Global Gas & LNG Portfolio business, we plan to hold steady profitability and cash generation, leveraging on the continuing renegotiation of our long-term gas supply contracts to align pricing and other terms to changing market conditions, on the optimization of logistic costs and on an expected growth in the LNG business. We also plan to strengthen the integration with the E&P with the objective of extracting the full value from the equity production of natural gas by trading increasing volumes of LNG equity. Contractual LNG volumes are expected to exceed 14 million tons per year, up 45% from 2020.

In the R&M segment, we plan to restore the profitability of the traditional business of manufacturing oil-based fuels and other products via plant optimizations, capital discipline and cost savings and to fully realize the value of our investment in ADNOC R&T with the help of a new platform to trade oil and other commodities. We will expand the business of manufacturing biofuels targeting approximately 2 million tons of capacity by the end of 2024, at the same time advancing the process of feedstock diversification in running our bio-refineries by zeroing the use of palm oil in 2023, whose target is seven years ahead of the EU ban on palm oil, while growing the share of feedstock coming from waste and residues covering approximately 80% of the total processed volumes in 2024, up from the current 20% share.

In the petrochemicals business, we plan to restore the profitability of our operations by means of further plant integrations and optimizations by right-sizing the production capacity of basic commodities to align to the needs of downstream markets and cost-cutting measures. We will seek to reduce our exposure to the margin volatility of oil-based petrochemicals products by expanding our presence in the niche of high-quality and high-performance polymers and to develop and integrate the new businesses of producing chemicals products from renewables and from the re-use of wasted plastics through processes of mechanical recycling and via chemical treatment processes based on the pyrolysis of the non-recyclable fraction of utilized plastics.

In the gas&power retail marketing business, we plan to improve the profitability of our operations, which will be driven by an expected growth of our customer base, the offering of innovative products and services with a rising weight of decarbonized commodities, as well as by improving customers’ experience and effective marketing processes. Our goal is to increase the number of our clients from 9.6 million at the end of 2020 to 11 million units by 2024, also leveraging the integration with our business of renewable power which is expected to be merged with our subsidiary Eni gas e luce which is engaged in the retail gas&power business.

In the business of renewable power, we plan to aggressively expand the installed capacity of solar power and of both onshore and offshore wind power targeting an installed capacity of approximately 4 gigawatts by 2024, leveraging on our pipeline of projects already sanctioned or under construction as well as our participation in equity-accounted ventures and initiatives.
We believe the outlined actions will improve the Group financial resiliency and cash flow in the coming years. We expect the Group’s balance sheet to strengthen going forward under our assumption of a modest recovery in Brent crude oil prices that are projected to increase from 50 $/bbl in 2021 up to 60 $/bbl in 2023 and to progressively reduce the Group’s cash neutrality, i.e. the level of Brent crude oil price at which the Group is able to fund the planned organic capital expenditures (i.e. before acquisitions) and the floor dividend to below 40 $/bbl at the end of the four-year plan.
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Carbon footprint
Eni, is aware of the ongoing climate emergency and intends to play a key role in the commitment of the energy sector contributing to carbon neutrality by 2050, in order to keep global warming within the threshold of 1.5° C at the end of the century.
The strategy and the action plan designed by the Company for the medium and the long-term will drive a significant improvement in our carbon footprint with the objective to become carbon neutral by 2050. Eni pursues a strategy that aims to reach the net zero target on our GHG emissions covering scope 1, 2 and 3, both in absolute and relative terms, which will be supported by continued advances and progress that we expect to achieve in the short and medium-term.
To evaluate our emissions, we have adopted a fully comprehensive lifecycle approach that takes into account all the energy products sold and traded by our organization and the GHG emissions they generate along their value chains.
The implementation of our strategy and of our action plan over the next thirty years will drive:

an absolute reduction in net lifecycle GHG emissions (scope 1, 2 and 3) by 25% in 2030 and by 65% by 2040 vs the 2018 baseline, reaching net zero in 2050 in line with low carbon scenarios compatible with the aim of limiting global warming to 1.5 C°

a reduction of 15% and 40% in net carbon intensity per unit of energy product sold respectively by 2030 and 2040 vs the 2018 baseline. In 2050 we target net zero carbon intensity.
Other intermediate targets of de-carbonization include:

net zero carbon footprint by 2030 for scope 1 and 2 emissions in the E&P business, accounted on equity basis; and

net zero carbon footprint by 2040 for Eni’s scope 1 and 2 emissions.
The actions mostly yet to be put in place to drive our carbon footprint reduction are:

progressive reduction of the hydrocarbons production in the medium long term, with an increasing share of gas in our portfolio, reaching 90% in the energy mix in 2050. At the same time, we will seek to retain the ability to modulate future investments in exploration and development to enable the Company to capture market opportunities as they evolve. We expect to produce a large part of the value of our reserves by 2035 under the most conservative scenario assumptions;

progressively upgrade traditional refineries through new technologies, to value decarbonized products and waste material recycling, to hubs to produce hydrogen, methanol, bio-methane;

increase the focus on equity gas in Global Gas & LNG Portfolio, progressively reducing the marketing of gas purchased from third parties;

expand production capacity for manufacturing biofuels in the long-term to over 5 million tonnes per year in 2050, utilizing exclusively feedstock which are compatible with the environment (palm oil free starting from 2023);

evolve the product mix marketed to our retail customers, with the aim to reach 100% of de-carbonized products by 2050;

expand the business of circular economy, which comprises several business initiatives designed to make the best use of industrial and civil waste, both organic and inorganic, through re-use or recycling aiming at producing energy feedstock and reusable finished products;

scale up the business of power generation from renewable sources, targeting a progressive expansion of the installed global capacity with the aim to reach 60 GW by 2050;

increase the production of green and blue hydrogen coupled with projects to capture and store CO2;

expand retail activities to reach a customer base of over 20 million by 2050, leveraging the expected growth in consumption of renewables and bio-methane;

build and operate projects of carbon capture and storage (CCS) with the goal of capturing up to 50 million tons per year (MTPA) of CO2, once our projects reach full capacity in 2050, with intermediate target of 7 MTPA in 2030;
34


ramp up the participation in projects for forest conservation and preservation with the goal of obtaining allowances to offset up to 40 MTPA of CO2, in 2050, with an intermediate target more than 6 MTPA in 2024 and 20 MTPA in 2030.
One of the milestones of our decarbonization strategy is to achieve by 2030 a net zero carbon footprint in our E&P business relating to scope 1 and 2 emissions on equity basis, with an intermediate target of 50% reduction in 2024 vs. 2018. We are planning to reach this goal:

by increasing efficiency to minimize direct upstream CO2 emissions. As part of this target by 2025 we plan to eliminate routine gas flaring at our industrial processes to extract and treat hydrocarbons and reduce fugitive methane emissions by 80% in our operated assets; and

by offsetting residual upstream emissions through the ramp up of our projects designed to build carbon sinks like the projects for the conservation of primary and secondary forests, projects for the capture and storage of carbon dioxide leveraging our technologies and availability of depleted reservoirs, as well as for carbon capture and reuse which aim at recycling the carbon dioxide to manufacture valuable basic materials (see paragraph “Research&Development” below, for information about those technologies).
Our portfolio of oil and gas properties features a large weight of natural gas, the least GHG-emitting fossil energy source, which represented approximately 48% of Eni’s production in 2020 on an available-for-sale basis; as of December 31, 2020, gas reserves represented approximately 49% of Eni’s total proved reserves of its subsidiary undertakings and joint ventures. The other pillar of our resilient portfolio of oil&gas properties is the high incidence of conventional projects, developed through phases and with low CO2 intensity. We estimate that oil&gas projects under execution, which will drive the expected production increase in the next four-year period and attract a large part of the projected development expenditures in the same period, have a price breakeven of around 23 $/bbl. We believe that those characteristics of our portfolio coupled with a relatively low pay-back period will mitigate the risk of stranded reserves going forward, should risks of structurally declining hydrocarbons demands materialize because of stricter global environmental constraints and regulations and changing consumers’ preferences resulting in trends like the mass adoption of electric vehicles or a lower weight of hydrocarbons in the energy mix.
Eni’s portfolio exposure to those risks is reviewed annually against changing GHG regulatory regimes, evolving consumers’ habits, technological developments and physical conditions to identify emerging risks. To test the resilience of new capital projects, Eni assesses potential costs associated with GHG emissions and their impact on projects’ returns. New projects’ internal rates of return are stress-tested against two sets of assumptions: i) Eni’s management estimation of a cost per ton of carbon dioxide (CO2), which is applied to the total GHG emissions of each capital project along its life cycle, while retaining the management scenario for hydrocarbons prices; and ii) the hydrocarbon prices and cost of CO2 emissions adopted in the International Energy Agency (IEA) Sustainable Development Scenario “IEA SDS” WEO 2020. This stress test is performed on a regular basis to monitor progress and risks associated with each project. The review performed at the end of 2020 indicated that the internal rates of return of Eni’s ongoing projects in aggregate should not be substantially affected by a carbon pricing mechanism, also under the assumption that the costs for emission allowances are not recoverable in the cost oil or are not deductible from profit before taxes. This observation holds true also under the more severe CO2 pricing assumptions of the IEA SDS scenario. The development process and internal authorization procedures of each E&P capital project feature several checks that may require additional and well detailed GHG and energy management plans to address potential risks of underperformance in relation to possible scenarios of global or regional adoption of regulations introducing mechanisms of carbon cap and trade or carbon pricing. These processes and internal authorization hurdles can lead to projects being stopped, designs being changed, and potential GHG mitigation investments being identified, in preparation for when the economic conditions imposed by new regulations would make these investments commercially compelling.
Furthermore, management performed a sensitivity analysis of the recoverability of the book values of the Company’s oil & gas assets under the assumptions set forth in the IEA SDS WEO 2020 to evaluate the reasonableness of the outcome of impairment review of those assets under the base case management scenario as well as possible risks of stranded assets. This stress test covered all the oil & gas cash generating unit (CGUs) that are regularly tested for impairment in accordance to IAS 36. The IEA SDS sets out an energy pathway consistent with the goal of achieving universal energy access by 2030 and of reducing energy-related CO2 emissions and air pollution in line with the goals of the Paris Agreement which endorse effective action to combat climate change by holding the rise in global average temperature to well below 2°C with respect to the baseline before the Industrial Revolution and to pursuing efforts to limit it to 1.5°C.
35

The hydrocarbon pricing assumptions of the IEA SDS scenario are substantially aligned to the ones adopted by Eni in its base case impairment review made in accordance with IAS 36. CO2 emissions costs under the IEA SDS show a strong uptrend consistent with the goal of encouraging the adoption of low carbon technologies. The IEA SDS projects CO2 emissions costs in advanced economies to reach 140 $ per ton in real terms 2019 by 2040, which is higher than Eni’s CO2 pricing trends and assumptions for the medium-long term. The sensitivity test performed at Eni’s oil&gas CGUs under the IEA SDS assumptions and applying the CO2 cost estimated by the IEA for advanced economies to all of our oil and gas assets validated the resiliency of Eni’s asset portfolio, determining a reduction of 11% in the total value-in-use of all of Eni’s oil&gas CGUs compared to the result of the impairment review performed by the Company in the preparation of its 2020 financial statements using the management’s base case scenario. That reduction falls to a 5% decline assuming the recoverability of CO2 costs in the cost oil or the deductibility from the taxable income.
Finally, management considered the following trends in the sector: the increased volatility of crude oil prices which have been increasingly exposed to macro and global risks; the continued oversupply in the oil markets which has determined a reset in hydrocarbons realized prices and cash flows of oil companies; growing uncertainty about long-term evolution of global oil demand in light of the rising commitment on the part of the international community at addressing climate change and speeding up the pace of the energy transition, the increase in energy alternatives to fossil fuels and changing consumer preferences, management has evaluated the recoverability of the book values of Eni’s oil&gas properties under different stress-test scenarios, including the risk of stranded assets. Particularly, under the more conservative set of the assumptions which envisages a flat long-term Brent price of 50 $/bbl and at a flat Italian gas price of 5 $/mmBTU, management is estimating that approximately 81% of the volumes of the Company’s proven and unproven reserves (latter being properly risked) will be produced within 2035 and 93% of their net present value will be realized. The net present value of those production volumes, valued at the most conservative of the scenarios evaluated, is substantially aligned with the book values of the net fixed assets of Eni’s oil&gas properties, including Eni’s share of the fixed assets of our joint ventures like Vår Energi AS, and including in the calculation the expected cash outflows committed to the Company’s forestry projects.
In October 2018 the Intergovernmental Panel on Climate Change (IPCC) stated that to reduce risks of irreversible changes to the ecosystem the world economy needs to limit the increase in global temperatures to 1.5°C. To meet this challenge, the world economy would need to undertake in the next decades a deeper and more complex transformation, both in term of size and speed, than the one foreseen in the Paris Agreement. Recognizing the IPCC position, the IEA has elaborated in its WEO 2020 a new detailed modelling called the Net Zero Emissions 2050 case (NZE2050) to examine what more would be needed compared to the SDS in next decade to put global CO2 emissions on a pathway to net zero by 2050. The set of actions contemplated by the IEA NZE2050 case comprise a dramatic increase in investments in low-emission electricity, infrastructure and innovation as well as demanding behavioral changes on part of the consumers. Currently, this scenario like the one outlined by the IPCC have yet to be complemented by a full set of pricing and other operating assumptions, which once available will be analyzed by the Company for the purpose of updating stress-testing models and methodologies.
Significant business and portfolio developments

March 2021 - Signed a Memorandum of Understanding with Zhejiang Energy company across the gas and LNG value chain in China and internationally, establishing a cooperation framework aimed at facilitating joint initiatives and promoting a reduction in emissions by favoring a switch from coal to gas in the production of electricity.

March 2021 - Versalis, Eni's chemical company, signed a development agreement with Bridgestone EMIA, a leader in advanced mobility solutions, for the research, production and supply of synthetic rubber with advanced properties.

March 2021 – Made one oil discovery in the production licence 532 (Eni’s interest 21%) in the Barents Sea and in the production licence 090/090I (Eni’s interest 17%) in the northern North Sea, offshore Norway.

March 2021 – Signed an agreement to acquire the FRI-EL Biogas Holding company, a leader in the Italian biogas production sector. With this agreement, Eni strengthening its growth in the circular economy, laying the foundations to become the first producer of biomethane in Italy.

March 2021 — 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
36

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.

March 2021 – Established GreenIT (Eni’s interest 51%), a joint venture with the Italian agency CDP Equity, for building, commissioning and managing plants for the production of power from renewable sources in Italy, with the aim of reaching an installed capacity of approximately 1,000 MW by 2025, with cumulative investments amounting to over 800 million euro in the five-year period.

March 2021 – Finalized a series of agreements with the Arab Republic of Egypt (ARE) and the Spanish partner Naturgy for the restart of the Damietta liquefaction plant and the resolution of all pending issues of the JV Uniòn Fenosa Gas with the Egyptian partners and the subsequent restructuring of the venture, which assets will be split between the two shareholders. The LNG production restarted in February 2021. The liquefaction plant in Egypt has produced and lifted its first LNG cargo since the terminal was shut down in 2012, representing a milestone in the process to complete the agreement reached on December 1, 2020 aimed at settling all pending disputes between the parties and at restarting the operations at the plant. The restart of the plant was a condition precedent to the effectiveness of a restructuring plan of the Union Fenosa Gas joint venture providing for a break-up of the venture. The deal will strengthen Eni’s portfolio of LNG by retaining a 50% stake in the ownership of the Damietta plan and other activities and allow Eni to directly enter the Spanish gas market. No significant impacts on the Group cash position are expected following the completion of the transaction.

March 2021 – Signed an agreement to divest the entire upstream activity in Pakistan, including interests in eight development and production licenses, to Prime International Oil&Gas, a local company. The agreement provides for the disposal of the Bhit/Badhra (Eni’s interest 40%) and Kadanwari (Eni’s interest 18.42%) operated fields and the participating interest in the Latif (Eni’s interest 33.3%), Zamzama (Eni’s interest 17.75%) and Sawan (Eni’s interest 23.7%) fields.

February 2021 – Restarted LNG production in Damietta. The liquefaction plant in Egypt has produced and lifted its first LNG cargo since the terminal was shut down in 2012. Such event represents a milestone in the process to complete the agreement reached on December 1, 2020 aimed at settling all pending disputes between the parties and at restarting the operations at the plant. The restart of the plant was a condition precedent the efficacy of a restructuring plan of the Union Fenosa Gas joint venture providing for a break-up of the venture. Following the completion of the plan, Eni is retaining a 50% stake in the ownership of the Damietta plan and other activities.

February 2021 – Signed an agreement with X – Elio for the acquisition of three photovoltaic projects in Spain for a total capacity of 140 MW.

February 2021 – Launch of a plan to build a hub for the capture and storage of CO2 in depleted fields off the coast of Ravenna (Italy, near the Po delta) which will be designed to store more than of 500 million tonnes per year of CO2. The project will benefit on the expected synergies on development cost due to the infrastructure in place. The program includes: (i) a pilot project with start-up expected in 2022 following all necessary authorizations; and (ii) a full development phase expected to commence in 2026.

February 2021 – 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 target the decarbonization of the Teeside industrial area, in the north east UK, by means of the transportation and storage of CO2. Start-up is expected in 2026 with a carbon capture and storage of 4 million tonnes per year.

February 2021 – Signed an agreement with Be Charge, to increase the national supply of charging infrastructures for electric mobility. The charging station will be powered by renewable energy to be supplied by Eni gas e luce.

January 2021 – Awarded the operatorship of the exploration license P2511 (Eni’s interest 100%) in the North Sea in the United Kingdom.

January 2021 – Signed an agreement to acquire 100% of Aldro Energía, with a portfolio of approximately 250,000 customers located in Spain and Portugal. The transaction will be completed upon receipt of the authorizations by the relevant authorities.

January 2021 – Awarded 10 new exploration licenses to Vår Energi in Norway, with 5 operatorships.
37


January 2021 – Signed a Memorandum of Understanding (MoU) between Eni Rewind and NOGA (National Oil and Gas Authority) of the Kingdom of Bahrain with the aim of promoting joint initiatives for the management, recovery and reuse of water, soil and waste in Bahrain.

January 2021 – Started up gas production in the Sharjah Emirate (UAE), at the Mahani exploration prospect (Eni’s interest 50%) in the onshore Concession B, just one year since discovery and two years after signing the concession agreement.

December 2020 – Made an oil discovery, in Meleiha Concession, in the Western Desert of Egypt. The discovery adds 10,000 barrels of oil per day to the current production of the Concession.

December 2020 – Started a strategic collaboration with the Italian agency CDP and Snam in the field of the energy transition, which includes the study of joint projects in key segments such as the hydrogen supply chain, circular economy (including the use of biomethane) and sustainable mobility.

December 2020 – Awarded the operatorship of the offshore Block 3 (Eni’s interest 70%) of approximately 12,000 square kilometers, in the United Arab Emirates with near-field targets.

December 2020 – Signed a Memorandum of Understanding (MoU) with Saipem for a collaboration in decarbonization projects in Italy focused on capture, transport, reuse, and storage of CO2 produced by the industrial activity.

December 2020 – Signed a Sale and Purchase agreement for the acquisition from Equinor and SSE Renewables of a 20% interest in the Dogger Bank (A and B) offshore wind projects in the UK, which will be the largest wind power facility in the world, with a planned installed capacity of 2.4 GW (100% share), with completion expected in 2023-2024. The operation will contribute 480 MW to the renewable generation capacity and to Eni’s growth targets.

December 2020 – Signed an agreement with Enel aimed at the study and development of green hydrogen projects, through facilities powered by renewable energy.

November 2020 – Versalis signed an agreement 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.

November 2020 – Agreement between Eni Rewind and Herambiente for the construction in Ravenna in the decommissioned industrial area “Ponticelle”, a platform for the treatment of non-recyclable industrial waste able to manage up to 60 ktonnes/year, coherently with circular economy principles.

November 2020 – Achieved the first allowance of carbon credits by the REDD+ Luangwa Community Forest Project (LCFP) to offset GHG emissions equivalent to 1.5 million tonnes of CO2.

November 2020 – Versalis signed an agreement with AGR, an Italian company that owns a proprietary technology to treat used elastomers, to develop and market new products and applications in recycled rubber, in collaboration with the EcoTyre Consortium, which manages a national network for the collection and processing of ELTs (End-of-Life Tyres).

November 2020 – Within the partnership with Falck Renewables, Eni acquired a 30 MW solar project “ready to build” in Virginia from Savion LLC (14.5 MW in Eni share). The plant will avoid over 33 ktonnes of CO2 emissions per year.

November 2020 – Eni Research Center for Renewable Energy and the Environment in Novara launched a pilot trial for a technology for the capture/reuse of CO2 (CCU) based on bio-fixation through micro-algae, with the production of an algal oil usable in bio-refineries.

October 2020 – Awarded by the UK Oil and Gas Authority a license for building a carbon storage project in depleted offshore fields located in the Liverpool Bay and the Irish Sea. 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.

September 2020 – Made a gas discovery in the Abu Madi West (Eni operator with a 75% interest) concession in the Great Nooros Area in the Nile Delta. The preliminary evaluation of the well results, considering the extension of the reservoir towards north and the dynamic behaviour of the field, together with the recent discoveries performed in the area, indicates that the Great Nooros Area gas in place can be estimated in excess of 4 Tcf.

August 2020 – Signed through the subsidiary Novis Renewables Holdings (Eni’s interest 49%), an
38

agreement with Building Energy SpA to acquire Building Energy Holdings US (BEHUS) managing 62 MW of wind and solar capacity fully in operation in the U.S.A. and a pipeline of wind projects of up to 160 MW. Production from already in operation BEHUS assets is expected to avoid over 93 ktons of CO2/y.

August 2020 – Versalis signed an agreement with Forever S.p.A., a leading Italian company in the recovery and recycling of post-consumer plastic to develop and market a new range of solid polystyrene products made from recycled packaging.

July 2020 – Eni have successfully drilled the first exploration well in the North El Hammad license, in the Bashrush prospect in the Nile Delta, located near Nooros and Baltim South West fields. The well has been opened to test potentiality of production, and it delivered up to 32 mmcf/d of gas. The test rate was limited by surface testing facilities. The well deliverability in production configuration is estimated at up to 100 mmcf of gas and 800 barrels of condensate per day.

July 2020 – Made an oil discovery in the SWM-A-6X exploration prospect, in South West Meleiha concession, in the Western Desert of Egypt. Production from South West Meleiha concession, started up in July 2019, in just one year ramped up to 12,000 BOE/d leveraging on the contribution of new discoveries.

July 2020 – Eni confirms and expands gas and condensate potential in the Ken Bau discovery in Block 114, offshore Vietnam. The estimate of gas and condensate potential was increased to 7-9 trillion cubic feet of gas in place and 400-500 million of barrels of condensate.

July 2020 – Versalis finalized the acquisition of a 40% interest in Finproject, a company engaged in the high-performance polymers segment, increasing exposure to products more resilient to the volatility of the chemical scenario.

July 2020 – Made a gas discovery in the license of North El Hammad, in the Bashrush prospect in the Nile Delta, located near Nooros and Baltim South West fields. The new discovery is located in 22 meters of water depth, 11 km from the coast and 12 km North-West from the Nooros field and about 1 km west of the Baltim South West field, both already in production.

July 2020 – 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.

July 2020 – Started a photovoltaic plant at the Volpiano site in Italy (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.

June 2020 – Versalis signed an agreement 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.

June 2020 – Acquired a 20% interest in Tate s.r.l., a start-up operating in the activation and management of electricity and gas contracts through digital solutions.

June 2020 – Acquired from Asja Ambiente three wind projects for a total capacity of 35.2 MW, which are expected to produce approximately 90 GWh/y, avoiding around 38,000 tonnes of CO2 emissions per year. The three plants, currently under construction, are the first wind project to be launched by Eni in Italy.

March 2020 – Completed the construction of a gas pipeline connecting Bir Rebaa Nord (BRN) and Menzel Ledjmet Est (MLE) fields in the Berkine Basin, in the south-eastern part of Algeria. When fully operational, the gas project of the Berkine Nord will bring production to a total of 6.5 million cubic meters and 10,000 barrels of associated liquids which, together with the oil development, will lead to an overall production of 65,000 barrels of oil equivalent per day (boed) by 2020.

March 2020 – Started up a wind farm in Kazakhstan with a capacity of 48 MW.
For significant business and portfolio developments occurred from January 2020 to the beginning of March 2020 see also the Annual Report on Form 20-F 2019 filed to SEC on April 2, 2020.
39

BUSINESS OVERVIEW
Exploration & Production
Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as in LNG operations, in forty-two countries, most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Iraq, Indonesia, Ghana, Mozambique, Bahrain, Oman and the United Arab Emirates. In 2020, Eni average daily production amounted to 1,609 KBOE/d on an available-for-sale basis. As of December 31, 2020, Eni’s total proved reserves amounted to 6,905 mmBOE; proved reserves of subsidiaries totaled 5,984 mmBOE; Eni’s share of reserves of equity-accounted entities was 921 mmBOE.
“Eni’s strategy and short-to-medium term targets in its Exploration & Production segment are disclosed in Item 5 – Business trends and Management’s expectations of operations.”
Disclosure of reserves
Overview
The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil&gas reserves in accordance with applicable SEC regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil&gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions. Prices are calculated as the unweighted arithmetic average of the first-day-of- the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements.
Engineering estimates of the Company’s oil&gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil&gas reserves can be designated as “proved”, the accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information.
Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni’s equity interest to total proved reserves of the contractual area, until expiration of the relevant mineral right. Eni’s proved reserves entitlements under PSAs are calculated so that the sale of production entitlements cover expenses incurred by the Group for field development (Cost Oil) and recognize a share of profit set contractually (Profit Oil). A similar scheme applies to service contracts.
Reserves governance
Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production segment is in charge of: (i) ensuring the periodic certification process of proved reserves; (ii) updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation.
Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which stated that those guidelines comply with the SEC rules1. D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by other entities, Eni estimates its share of proved reserves on the basis of the above guidelines.
1
See “Item 19 – Exhibits” in the Annual Report on Form 20-F 2009.
40

The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department and the operations unit at the head office verify the production profiles of such properties where significant changes have occurred and operating expenses, respectively; (iii) geographic area managers verify the commercial conditions and the progress of the projects; (iv) the Planning and Control Department provides the economic evaluation of reserves; and (v) the Reserves Department, through the Headquarter Reserves Evaluators (HRE), provides independent reviews of fairness and correctness of classifications carried out by the above-mentioned units and aggregates worldwide reserves data.
The head of the Reserves Department attended the “Politecnico di Torino” and received a Master of Science degree in Mining Engineering in 2000. He was appointed in 2020 and has more than 20 years of experience in evaluating reserves.
Staff involved in the reserves evaluation process fulfil the professional qualifications requested by the role and comply with the required level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers.
Reserves independent evaluation
Eni has its proved reserves audited on a rotational basis by independent oil engineering companies2. The description of qualifications of the persons primarily responsible for the reserves audit is included in the third-party audit report3. In the preparation of their reports, independent evaluators rely upon information furnished by Eni, without independent verification, with respect to property interests, production, current costs of operations and development, sales agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, development plans, future capital and operating costs.
In order to calculate the net present value of Eni’s equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided by Eni to third-party evaluators. In 2020, Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of approximately 36% of Eni’s total proved reserves at December 31, 20204, confirming, as in previous years, the reasonableness of Eni internal evaluation5.
In the 2018-2020 three-year period, 92% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2020, Balder in Norway and Merakes in Indonesia were the main Eni property, which did not undergo an independent evaluation in the last three years.
2
From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott. In 2018, the Societé Generale de Surveillance (SGS) company also provided an independent certification.
3
See “Item 19 – Exhibits”.
4
Includes Eni’s share of proved reserves of equity-accounted entities.
5
See “Item 19 – Exhibits”.
41

Summary of proved oil and gas reserves
The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2020, 2019 and 2018.
HYDROCARBONS(1)
(mmBOE)
Italy
Rest
of
Europe
North
Africa
Egypt
Sub-
Saharan
Africa
Kazakhstan
Rest of
Asia
Americas
Australia
and
Oceania
Total
reserves
Consolidated subsidiaries(2)
Dec. 31, 2020
243
73
798
1,110
1,352
1,182
879
256
91
5,984
developed
199
68
434
1,022
799
1,093
424
162
60
4,261
undeveloped
44
5
364
88
553
89
455
94
31
1,723
Dec. 31, 2019
333
89
974
1,225
1,453
1,108
742
268
95
6,287
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
Dec. 31, 2018
428
106
1,022
1,246
1,361
1,066
700
302
125
6,356
developed
336
99
582
764
895
925
403
170
87
4,261
undeveloped
92
7
440
482
466
141
297
132
38
2,095
Equity-accounted entities(3)
Dec. 31, 2020
496
14
87
324
921
developed
254
14
47
324
639
undeveloped
242
40
282
Dec. 31, 2019
567
16
63
335
981
developed
330
16
23
335
704
undeveloped
237
40
277
Dec. 31, 2018
363
14
68
352
797
developed
205
14
17
347
583
undeveloped
158
51
5
214
Consolidated subsidiaries and equity accounted entities
Dec. 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
undeveloped
44
247
364
88
593
89
455
94
31
2,005
Dec. 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
undeveloped
75
244
421
192
630
62
370
86
34
2,114
Dec. 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
undeveloped
92
165
440
482
517
141
297
137
38
2,309
(1)
Effective January 1, 2020, Eni has updated the conversion rate of gas produced to 5,310 cubic feet of gas equals 1 barrel of oil (it was 5,408 cubic feet of gas per barrel in previous reporting periods). The effect of this update on the change in the initial reserves balance as of January 1, 2020 amounted to 67 mmBOE. Prior-year converted amounts were left unchanged.
(2)
Include Eni’s share of reserves held by a joint-operation in Mozambique which is proportionally consolidated in the Group consolidated financial statements in accordance to IFRS.
(3)
Reserves volumes of the Rest of Europe area, in 2018, are affected by the merger agreement that provided for the sale of the reserves of the former subsidiary Eni Norge as part of the business combination with Point Resources and the acquisition of Eni’s share of the reserves held by the combined company Vår Energi, an equity-accounted entity participated by Eni with a 69.85% interest.
42

LIQUIDS
(mmBBL)
Italy
Rest
of
Europe
North
Africa
Egypt
Sub-
Saharan
Africa
Kazakhstan
Rest
of
Asia
Americas
Australia
and
Oceania
Total
reserves
Consolidated subsidiaries
Dec. 31, 2020
178
34
383
227
624
805
579
224
1
3,055
developed
146
31
243
172
469
716
297
143
1
2,218
undeveloped
32
3
140
55
155
89
282
81
837
Dec. 31, 2019
194
41
468
264
694
746
491
225
1
3,124
developed
137
37
301
149
519
682
245
148
1
2,219
undeveloped
57
4
167
115
175
64
246
77
905
Dec. 31, 2018
208
48
493
279
718
704
476
252
5
3,183
developed
156
44
317
153
551
587
252
143
5
2,208
undeveloped
52