20-F 1 tv485407-20f.htm FORM 20-F tv485407-20f - none - 69.4245408s
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, 2017
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)
Massimo Mondazzi
Eni SpA
1, piazza Ezio Vanoni
20097 San Donato Milanese (Milano) - Italy
Tel +39 02 52041730 - Fax +39 02 52041765
(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
Name of each exchange on which registered
Shares
New York Stock Exchange*
American Depositary Shares
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 shares3,634,185,330   
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 and posted on their corporate Web sites, if any, 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, or a non-accelerated filer. See definition of  “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
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 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
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vii
PART I
1
1
1
1
3
4
5
26
26
32
32
63
68
75
75
79
79
92
97
98
98
99
99
103
104
116
123
123
131
131
140
156
167
168
169
169
169
170
170
170
171
171
172
173
173
181
181
181
186
187
190
190
190
190
190
PART II
192
192
192
193
193
193
193
195
195
195
195
198
PART III
199
199
199
i

Certain disclosures contained herein including, without limitation, 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, Gas & Power, Refining & Marketing and Chemicals, Corporate and Other activities.
References to Versalis or Chemical are to Eni’s chemical activities engaged through its fully-owned subsidiary Versalis and Versalis’ controlled entities.
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
A glossary of oil and gas terms is available on Eni’s web page at the address eni.com. Below is a selection of the most frequently used terms. 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’s 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 asses 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
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 has also 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”).
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.
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.
iii

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.
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.
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.
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.
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.
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.
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.
iv

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 in use in African, Middle Eastern, Far Eastern and Latin American countries, among others, regulating 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.
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.
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.
v

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.
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.
vi

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
ktonnes = thousand tonnes
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 segment
R&M & C
= the Refining & Marketing and Chemicals segment
E&C = the Engineering & Construction segment
CONVERSION TABLE
1 acre = 0.405 hectares
1 barrel = 42 U.S. gallons
1 BOE = 1 barrel of crude oil = 5,458 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 0.00647 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)
vii

PART I
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 selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2013, 2014, 2015, 2016 and 2017. In 2015, the business segment Engineering & Construction, operated by Eni’s subsidiary Saipem, was classified as discontinued operations based on the guidelines of IFRS 5. Eni’s interest in Saipem was divested on January 26, 2016; financial data for 2014 and 2013 have been restated accordingly.
All such data should be read in connection with the Consolidated Financial Statements and the related notes thereto included in Item 18.
Year ended December 31,
2017
2016
2015
2014
2013
(€ million except data per share and per ADR)
CONSOLIDATED PROFIT STATEMENT DATA
Net sales from continuing operations
66,919 55,762 72,286 98,218 104,117
Operating profit (loss) by segment from continuing operations
Exploration & Production
7,651 2,567 (959) 10,727 15,349
Gas & Power
75 (391) (1,258) 64 (2,923)
Refining & Marketing and Chemicals
981 723 (1,567) (2,811) (2,261)
Corporate and Other activities
(668) (681) (497) (518) (736)
Impact of unrealized intragroup profit elimination and other consolidation adjustments(1)
(27) (61) 1,205 1,503 928
Operating profit (loss) from continuing operations
8,012 2,157 (3,076) 8,965 10,357
Net profit (loss) attributable to Eni from continuing
operations
3,374 (1,051) (7,952) 1,720 5,808
Net profit (loss) attributable to Eni from discontinued operations 0 (413) (826) (417) (488)
Net profit (loss) attributable to Eni
3,374 (1,464) (8,778) 1,303 5,320
Data per ordinary share (euro)(2)
Operating profit (loss):
– basic
2.22 0.60 (0.85) 2.48 2.86
– diluted
2.22 0.60 (0.85) 2.48 2.86
Net profit (loss) attributable to Eni basic and diluted from continuing operations 0.94 (0.29) (2.21) 0.48 1.60
Net profit (loss) attributable to Eni basic and diluted from discontinued operations 0.00 (0.12) (0.23) (0.12) (0.13)
Net profit (loss) attributable to Eni basic and diluted
0.94 (0.41) (2.44) 0.36 1.47
Data per ADR ($)(2)(3)
Operating profit (loss):
– basic
5.03 1.33 (1.90) 6.59 7.59
– diluted
5.03 1.33 (1.90) 6.59 7.59
Net profit (loss) attributable to Eni basic and diluted from continuing operations 2.12 (0.65) (4.90) 1.27 4.26
Net profit (loss) attributable to Eni basic and diluted from discontinued operations 0.00 (0.25) (0.51) (0.31) (0.36)
Net profit (loss) attributable to Eni basic and diluted
 2.12 (0.90) (5.41) 0.96 3.90
(1)
This item pertains to intragroup sales of commodities and capital goods recorded in the assets of the purchasing business segment as of the end of the reporting period.
(2)
Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2017 is based on the proposal of Eni’s management which is submitted for approval at the Annual General Shareholders’ Meeting scheduled on May 10, 2018.
(3)
Eni’s financial statements are reported in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S.$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2013 through 2016 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 2017 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 (€0.80 per ADR) at the Noon Buying Rate recorded on the payment date on September 20, 2017, while the balance of €0.80 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2017. The balance dividend for 2017 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 23, 2018 to holders of Eni shares, being the ex-dividend date May 21, 2018 while ADRs holders will be paid on June 7, 2018.
1

As of December 31,
2017
2016
2015
2014
2013
(€ million except data per share and per ADR)
CONSOLIDATED BALANCE SHEET DATA
Total assets
114,928 124,545 139,001 150,366 142,426
Short-term and long-term debt
24,707 27,239 27,793 25,891 25,560
Capital stock issued
4,005 4,005 4,005 4,005 4,005
Non-controlling interest
49 49 1,916 2,455 2,842
Shareholders’ equity – Eni share
48,030 53,037 55,493 63,186 61,211
Capital expenditures from continuing operations
8,681 9,180 10,741 11,178 11,221
Weighted average number of ordinary shares outstanding (fully
diluted – shares million)
3,601 3,601 3,601 3,610 3,623
Dividend per share (euro)(1)
0.80 0.80 0.80 1.12 1.10
Dividend per ADR ($)(1)(2)
 1.81 1.77 1.77 2.65 2.99
(1)
Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2017 is based on the proposal of Eni’s management which is submitted for approval at the Annual General Shareholders’ Meeting scheduled on May 10, 2018.
(2)
Eni’s financial statements are reported in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S.$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2013 through 2016 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 2017 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 (€0.80 per ADR) at the Noon Buying Rate recorded on the payment date on September 20, 2017, while the balance of €0.80 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2017. The balance dividend for 2017 once the full-year dividend has been approved by the Annual General Shareholders’ Meeting is payable on May 23, 2018 to holders of Eni shares, being the ex-dividend date May 21, 2018 while ADRs holders will be paid on June 7, 2018.
2

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, 2013, 2014, 2015, 2016 and 2017.
Year ended December 31,
2017
2016
2015
2014
2013
Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL) 3,262 3,230 3,372 3,077 3,079
of which developed
2,220 2,190 2,100 1,847 1,831
Proved reserves of liquids of equity-accounted entities at period end (mmBBL) 160 168 187 149 148
of which developed
43 43 48 46 35
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF) 17,290 18,462 14,302 14,808 14,442
of which developed
9,535 9,244 8,899 8,342 8,542
Proved reserves of natural gas of equity-accounted entities at period end (BCF) 2,182 3,871 3,993 3,737 3,726
of which developed
1,916 1,905 1,402 120 34
Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end 6,430 6,613 5,975 5,772 5,708
of which developed
3,967 3,884 3,720 3,366 3,387
Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end 560 877 915 830 827
of which developed
394 391 303 67 40
Average daily production of liquids (KBBL/d)(1)
852 878 908 828 833
Average daily production of natural gas available for sale (mmCF/d)(1) 4,734 4,329 4,284 3,782 3,868
Average daily production of hydrocarbons available for
sale (KBOE/d)(1)
1,719 1,671 1,688 1,517 1,537
Hydrocarbon production sold (mmBOE)
622.3 608.6 614.1 549.5 555.3
Oil and gas production costs per BOE(2)
8.45 7.79 9.18 12.00 12.19
Profit per barrel of oil equivalent(3)
 8.72 1.98 (3.83) 9.86 16.19
(1)
Referred to Eni’s subsidiaries and its equity-accounted entities. Natural gas production volumes exclude gas consumed in operations (451, 442, 397, 478 and 527 mmCF/d in 2013, 2014, 2015, 2016 and 2017 respectively).
(2)
Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment including also royalties) 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”.
(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,
2017
2016
2015
2014
2013
Sales of natural gas to third parties(1)
71.34 77.24 79.06 76.11 77.67
Natural gas consumed by Eni(1)
6.18 6.10 5.88 5.62 5.93
Sales of natural gas of affiliates (Eni’s share)(1)
3.31 2.97 2.78 4.38 6.96
Worldwide natural gas sales(1)
80.83 86.31 87.72 86.11 90.56
Electricity sold(2)
35.33 37.05 34.88 33.58 35.05
Refinery throughputs(3)
24.02 24.52 26.41 25.03 27.38
Balanced capacity of wholly-owned refineries(4)
388 388 388 404 574
Retail sales (in Italy and rest of Europe)(3)
8.54 8.59 8.89 9.21 9.69
Number of service stations at period end (in Italy and rest of Europe) 5,544 5,622 5,846 6,220 6,386
Chemical production(3)
5.82 5.65 5.70 5.28 5.82
Average throughput per service station (in Italy and rest of Europe)(5) 1,783 1,742 1,754 1,725 1,828
Employees at period end (number)
 32,934 33,536 34,196 34,846 36,678
(1)
Expressed in BCM.
(2)
Expressed in TWh.
(3)
Expressed in mmtonnes.
(4)
Expressed in KBBL/d.
(5)
Expressed in thousand liters per day.
Exchange Rates
The following tables set forth, for the periods indicated, certain information regarding the Noon Buying Rate in U.S. dollars per euro, rounded to the second decimal (Source: The Federal Reserve Board).
High
Low
Average(1)
At
period end
(U.S. dollars per €)
Year ended December 31,
2013
1.38 1.28 1.33 1.38
2014
1.39 1.21 1.33 1.21
2015
1.20 1.05 1.11 1.09
2016
1.15 1.04 1.10 1.06
2017
 1.20 1.04 1.13 1.20
(1)
Average of the Noon Buying Rates for the last business day of each month in the period.
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High
Low
At period
end
(U.S. dollars per €)
October 2017
1.18 1.16 1.16
November 2017
1.19 1.16 1.19
December 2017
1.20 1.17 1.20
January 2018
1.25 1.19 1.24
February 2018
1.25 1.22 1.22
March 2018
 1.24 1.22 1.23
Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the electronic stock exchange and the dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on March 30, 2018 was $1.232 per €1.00.
Risk factors
The risks described below may have a material effect on our operational and financial performance. We invite our investors to consider these risks carefully.
Eni’s operating results, cash flow and rates of growth are affected by volatile prices of crude oil, natural gas, oil products and chemicals
Prices of oil and natural gas have a history of volatility due to many factors that are beyond Eni’s control. These factors include among other things:

global and regional dynamics of oil and gas supply and demand and global level of inventories. In 2017 crude oil prices were volatile, with the first half of the year characterized by market uncertainties about a rebalancing between global demand and supplies and the overhang of high global inventories. From the second part of the year, the recovery in crude oil prices progressively gained steam with prices reaching levels unseen in recent years, at around 70 $/BBL in early 2018. This upward trend was driven by better market fundamentals and full effectiveness of production cuts agreed by OPEC Countries at the end of November 2016 to reduce the output of the cartel, joined also by certain non-OPEC countries (among which Russia). The average price for the Brent crude oil benchmark increased by 24% y-o-y at about 54 $/BBL;

global political developments, including sanctions imposed on certain producing countries and conflict situations;

global economic and financial market conditions;

the ability of the OPEC cartel to control world supply and therefore oil prices;

prices and availability of alternative sources of energy (e.g., nuclear, coal and renewables);

weather conditions;

operational issues;

governmental regulations and actions;

success in the development and deployment of new technologies for the recovery of crude oil and natural gas reserves and technological advances affecting energy consumption;

competition from alternative energy sources like solar energy, photovoltaic and other renewables; and

growing sensibility among the public and the commitment of the world nations to addressing the issue of global warming and climate change by reducing the release in the atmosphere of greenhouse gases (“GHG”) produced by the consumption of hydrocarbons in human activities.
All these factors can affect the global balance between demand and supply for oil and prices of crude oil, natural gas, and other energy commodities.
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Management believes that current market dynamics are supportive of the ongoing recovery in crude oil prices. Going forward, we foresee a better balance between demand and supply driven by an improving macroeconomic outlook and the effects of the reduced investments made by international oil companies during the downturn. The production cuts agreed by OPEC with the cooperation of other countries (principally Russia) will provide further support in the short term. However, management has also evaluated the continuing risks and uncertainties inherent in such forecasts, including actual implementation of the production cuts announced by the OPEC, structural changes that have been affecting the oil industry – e.g. the increase in oil supply following the U.S. tight oil revolution – the unpredictable impact of geopolitical crisis and the greater role played by renewable energy sources, as well as risks associated with internationally-agreed measures intended to reduce GHG. Based on this outlook, management basically confirmed its long-term assumption for the benchmark Brent price to 72 $/BBL in 2021 real terms (under the previous plan it was 71.4 $/BBL) in elaborating the Group’s financial projections of the 2018 – 2021 industrial plan and the estimations of recoverability of the carrying amounts of the Group’s oil and gas assets as of December 31, 2017.
Fluctuations in oil and natural gas prices have had and may in the future have a material effect on the Group’s results of operations and cash flow. Lower 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 recognized 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. Based on the current portfolio of oil and gas assets, Eni’s management estimates that the Company’s consolidated net profit would vary by approximately euro 200 million for each one dollar change in the price of the Brent crude oil benchmark with respect to the price case assumed in Eni’s financial projections for 2018 at 60 $/BBL. Net cash provided by operating activities is expected to vary by a similar amount.
In addition to the adverse effect on revenues, profitability and cash flow, lower oil and gas prices could result in debooking of proved reserves, if they become uneconomic in this type of environment, and asset impairments.
Depending on the significance and speed of a decrease in crude oil prices, Eni may also need to review investment decisions and the viability of development projects. The effect of lower oil and gas prices over prolonged periods on Eni’s results of operations and cash flow may adversely affect the funds available to finance expansion projects, further reducing the Company’s ability to grow future production and revenues. In addition, such lower price may reduce returns from development projects, either planned or in progress, forcing the Company to reschedule, postpone or cancel development projects.
In response to weakened oil and gas industry conditions and resulting revisions made to rating agency commodity price assumptions, lower commodity prices may also reduce the Group’s access to capital and lead to a downgrade or other negative rating action with respect to the Group’s credit rating by rating agencies, including Standard & Poor’s Ratings Services (“S&P”) and Moody’s Investor Services Inc (“Moody’s”). 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 movements in oil prices impact pricing for approximately 50 per cent. of its current production. 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, due to the cost recovery mechanism, the Company is entitled to a larger number of barrels in the event of a fall in crude oil prices. (See the specific risks of the Exploration & Production segment in “Risks associated with the exploration and production of oil and natural gas” below).
The Group’s results from its Refining & Marketing and Chemicals businesses are primarily dependent upon the supply and demand for refined and chemical products and the associated margins on refined product and chemical products sales, with the impact of changes in oil prices on results of these segments being dependent upon the speed at which the prices of products adjust to reflect movements in oil prices.
Because of the above mentioned risks, a prolonged decline in commodity prices would materially and adversely affect the Group’s business prospects, financial condition, results of operations, cash flows, ability to finance planned capital expenditures and commitments and may impact shareholder returns, including dividends and the share price.
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Competition
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
Eni faces strong competition in each of its business segments.
The current competitive environment in which Eni operates is characterized 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 cost and efficient management of capital resources. It also depends on Eni’s ability to gain access to new investment opportunities, both in Europe and worldwide.

In the Exploration & Production segment, Eni faces competition from both international and state-owned oil companies for obtaining exploration and development rights, and developing and applying new technologies to maximize hydrocarbon recovery. Furthermore, Eni may face a competitive disadvantage because of its smaller size relative to other international oil companies, particularly 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. If, because of those competitive pressures, Eni fails to obtain new exploration and development acreage, to apply and develop new technologies, and to control costs, its growth prospects and future results of operations and cash flow may be adversely affected.

Throughout 2016, the Gas & Power segment experienced a history of operating losses due to a difficult market environment in the European gas sector. Eni is facing strong competition from gas and energy players to sell gas to the industrial segment, the thermoelectric sector and the retail customers both in the Italian market and in markets across Europe. Competition has been driven by ongoing weak demand, oversupplies and use of alternative energy sources for the production of electricity (renewables or coal). The production of gas-fired electricity is one of the major outlet for gas. In recent years the use of gas in gas-fired power plants has been negatively affected by an increased use of coal in firing power plants due to cost advantages and a dramatic growth in the adoption of renewable sources of energy (photovoltaic, wind and solar). The large-scale development of shale gas in the United States has been another fundamental trend that aggravated the oversupply situation in Europe because many LNG projects worldwide that originally targeted the U.S. market, were redirected to an already saturated European market. Furthermore, many LNG terminals in the US are undergoing upgrading projects designed to convert them into gas liquefaction facilities with the aim of exporting the large gas surplus out of the US. This development will further increase global gas supplies. In recent years, large gas availability in Europe led to the development of liquid spot markets where gas is traded daily. Prices at these hubs have become the benchmark to selling prices and have been on a downtrend in recent years. These trends have negatively affected the profitability of our Gas & Power business, because the Company is part of long-term gas supply contracts with take-or-pay clauses, which exposed us to a volume risk, as we are contractually required to purchase minimum annual amounts of gas or, if we fail to do so, to pay the corresponding price. Additionally, we have booked the transportation rights along the main gas backbones across Europe to deliver our contracted gas volumes to end-markets. In a weak market, the need to dispose of the minimum off-take of gas have negatively affected our margins. Looking forward, we believe that the competitive landscape in our Gas & Power business will remain challenging due to expected weak growth in demand, also reflecting political uncertainty in the EU about the role of gas in the energy mix, the continuing build of oversupplies and inter-fuel competition. Eni believes that these ongoing negative trends may adversely affect the Company’s future results of operations and cash flows.

In its Gas & Power segment, Eni is vertically integrated in the production of electricity via its gas-fired power plants, which are currently utilizing the combined-cycle technology. In the electricity business, Eni competes with other producers and traders from Italy or outside Italy who sell electricity in the Italian market. The Company expects continuing competition due to the projections of moderate economic growth in Italy and Europe over the foreseeable future, also causing outside players to place excess production on the Italian market. The economics of the gas-fired electricity business have dramatically changed over the latest few years due to ongoing
7

competitive trends. Spot prices of electricity in the wholesale market throughout Europe decreased due to excess supplies driven by the growing production of electricity from renewable sources, that also benefit from governmental subsidies, and a recovery in the production of coal-fired electricity which was helped by a substantial reduction in the price of this fuel on the back of a massive oversupply of coal occurring on a global scale. As a result of falling electricity prices, margins on the production of gas-fired electricity have been negatively affected. Eni believes that the competitive scenario in this business will remain challenging in the foreseeable future, negatively affecting results of operations and cash flow.

In the Refining & Marketing segment, Eni faces strong competition in both industrial and commercial activities. European refining margins remain lower than other areas due to higher energy costs, weak trends in demand for fuels and competitive pressure from cheaper productions mainly coming from Middle East and Asia and tighter compliance constraints. We believe that the competitive environment will remain challenging in the foreseeable future, also considering refining overcapacity in the European area. In marketing, Eni faces competition from other oil companies and new participants such as un-branded operators and large retailers, that leverage on the price awareness of final consumers to increase their market share. All these operators compete with each other primarily in terms of pricing and, to a lesser extent, service quality.

In the Chemical business, Eni faces strong competition from well-established international players and state-owned petrochemical companies, particularly in the most commoditized segments such as the production of basic petrochemical products and plastics. Many of those competitors based in the Far East and the Middle East are able to benefit from cost advantages due to scale, favourable environmental regulations, availability of cheap feedstock and proximity to end-markets. Excess capacity across Europe is also fuelling 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. Competition exacerbates the impact of any macroeconomic downturn on the business’ results of operations and cash flow; additionally, the business results are exposed to fluctuation in the relative prices of oil-based feedstock and final prices of petrochemicals products. The Company expects continuing margin pressures in its petrochemical segment in the foreseeable future as a result of those trends.
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. 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 mitigate 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 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. Accidents at a single well can lead to loss of life, damage or destruction to properties, environmental damage, GHG emissions and consequently potential economic losses that could have a material and adverse effect on the business, results of operations, liquidity, reputation and prospects of the Group, including its share price and dividends.
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 petrochemicals products. These risks can arise from the intrinsic characteristics and the overall life cycle 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.
8

All of Eni’s segments of operations involve, to varying degrees, the transportation of hydrocarbons. Risks in transportation activities depend both on the hazardous nature of the products transported, and on the transportation methods used (mainly 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 a loss of containment of hydrocarbons and other hazardous materials, and, given the high volumes involved, could present a significant risk to people and the environment.
The Company invests significant resources in order to upgrade the methods and systems for safeguarding safety and health of employees, contractors and 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 minimize these operational risks by carefully designing and building facilities, including wells, industrial complexes, plants and equipment, pipelines, storage sites and other facilities, and managing its operations in a safe and reliable manner and in compliance with all applicable rules and regulations. These measures may not ultimately adequately manage these risks. Failure to manage these risks could cause unforeseen incidents, including releases or oil spills, blowouts, fire, mechanical failures and other incidents resulting in personal injury, loss of life, environmental damage, legal liabilities and/or damage claims, destruction of crude oil or natural gas wells, as well as damage to equipment and other property, all of which could lead to a disruption in operations.
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. Particularly, Eni’s entities are insured against liabilities for damage to third parties and environmental claims up 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 sufficient 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 the event of such a disaster 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 the above mentioned events could have a material adverse impact on the Group’s business, competitive position, cash flow, results of operations, liquidity, future growth prospects and shareholders’ returns and damage the Group’s reputation.
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 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
9

and production leases, the imposition of specific drilling and other work obligations, income taxes and taxes on production, environmental protection measures, control over the development and abandonment 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.
Eni’s oil and natural gas offshore operations are particularly exposed to health, safety, security and environmental risks
Eni has material offshore operations relating to the exploration and production of hydrocarbons. In 2017, approximately 53% of Eni’s total oil and gas production for the year derived from offshore fields, mainly in Libya, Norway, Angola, Egypt, the Gulf of Mexico, Italy, Congo, the United Kingdom and Nigeria. 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 health and security of people due to objective 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 vessel collisions, as well as interruptions or termination by governmental authorities based on safety, environmental and other considerations. Failure to manage these risks could result in injury or loss of life, damage to property or environmental damage, and could result in regulatory action, legal liability, loss of revenues and damage to Eni’s reputation and could have a material adverse effect on Eni’s operations, results, liquidity, reputation, business prospects and the share price.
Exploratory drilling efforts may be unsuccessful
Exploration drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling, completing and operating 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, and shortages or delays in the delivery of equipment. The Company also engages in exploration drilling activities offshore, including in deep and ultra-deep waters, in remote areas and in environmentally-sensitive locations (such as the Barents Sea). In these locations, the Company generally experiences more challenging conditions and incurs higher exploration costs than onshore or in shallow waters. Furthermore, deep and ultra-deep water operations require significant time before commercial production of discovered reserves can commence, increasing both the operational and financial risks associated with these activities. Because Eni plans to make 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 growth prospects, results of operations and liquidity.
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 environmentally-sensitive locations. Eni’s future results of operations and liquidity 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, customers or others, including, for example, Eni’s ability to negotiate favourable long-term contracts to market gas reserves;

commercial arrangements for pipelines and related equipment to transport and market hydrocarbons;

timely issuance of permits and licences by government agencies;

the Company’s relative size compared to its main competitors which may prevent it from participating in large-scale projects or affect its ability to reap benefits associated with economies of scale;
10


the ability to carefully carry out 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; these events may cause cost overruns and delays impacting the time-to-market of the reserves;

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

poor performance in project execution on the part of contractors who are awarded project construction activities generally based on the EPC (Engineering, Procurement and Construction) – turn key contractual scheme. Eni believes this kind of risk may be due to lack of contractual flexibility, poor quality of front-end engineering design and commissioning delays;

changes in operating conditions and cost overruns. In recent years, the industry has been adversely impacted by the growing complexity and scale of projects which drove cost increases and delays, including higher environmental and safety costs;

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.
As previously described, events such as poor project execution, inadequate front-end engineering design, delays in the achievement of critical phases and project milestones, delays in the delivery of production facilities and other equipment by third parties, differences between scheduled and actual timing of the first oil, as well as cost overruns may adversely affect the economic returns of Eni’s development projects. Failure to deliver major projects on time and on budget could negatively affect results of operations, cash flow and the achievement of short-term targets of production growth. Lastly, the development and marketing of hydrocarbon reserves typically require several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its technical and economic feasibility, sanctioning a development project and the building and commissioning of related facilities. As a consequence, rates of return for such long lead time 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 capitalized 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
Unless the Company is able to replace 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”). Pursuant to these contracts, Eni 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. For a discussion of the Group’s sensitivity of production volumes to movements in crude oil prices see “Item 5- management expectations of operations. The opposite occurs in case of lower oil prices.
Future oil and gas production is dependent on 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 entities 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 and this will negatively affect future results of operations, cash flow and business prospects.
11

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;

projections regarding future rates of production and costs and timing of development expenditures;

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 or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.
Reserve estimates are subject to revisions as prices fluctuate due to the cost recovery mechanism under the Company’s production sharing agreements and similar contractual schemes.
Many of the factors, assumptions and variables involved in estimating proved reserves are subject to change over time and therefore affect the estimates of oil and natural gas reserves.
Accordingly, the estimated reserves reported as of the end of 2017 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 results of operations and financial condition.
The development of the Group’s proved undeveloped reserves may take longer and may require higher levels of capital expenditures than it currently anticipates. The Group’s proved undeveloped reserves may not be ultimately developed or produced
At 31 December 2017, approximately 38% 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. The Group’s reserve report at 31 December 2017 includes estimates of total future development costs associated with the Group’s proved undeveloped reserves of approximately euro 33.2 billion (undiscounted). 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 of 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 Italian statutory tax rate for corporate profit, which currently stands at 24 per cent.
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.
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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 nationalizations and expropriations.
Eni’s results and cash flow depend on its ability to identify and mitigate the above mentioned risks and hazards which are inherent to its operations.
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 U.S. 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 U.S. 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 per cent. 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.
Political considerations
A substantial portion of Eni’s oil and gas reserves and gas supplies are located in countries outside the EU and North America, mainly in Africa, Central Asia and Central-Southern America, where the socio-political framework and macroeconomic outlook is less stable than in the OECD countries. In those less stable countries, Eni is exposed to a wide range of additional risks and uncertainties, which could materially impact the ability of the Company to conduct its operations in a safe, reliable and profitable manner.
As of 31 December 2017, approximately 80% of Eni’s proved hydrocarbon reserves were located in such countries and 60% of Eni’s supplies of natural gas came from outside OECD countries. Adverse political, social and economic developments, such as internal conflicts, revolutions, establishment of non-democratic regimes, protests, strikes and other forms of civil disorder, contraction of economic activity and financial difficulties of the local governments with repercussions on the solvency of state institutions, inflation levels, exchange rates and similar events in those non-OECD countries may negatively impair Eni’s ability to continue operating in an economically viable way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. In particular, Eni faces risks in connection with the following, possible issues:

lack of well-established and reliable legal systems and uncertainties surrounding the enforcement of contractual rights;

unfavourable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriation, nationalization or forced divestiture of assets and unilateral cancellation or modification of contractual terms. Eni is facing increasing competition from state-owned oil companies that are partnering Eni in a number of oil and gas projects and properties in the host countries where Eni conducts its upstream operations. These state-owned oil companies can unilaterally change contractual terms and other conditions of oil and gas projects in order to obtain a larger share of profit from a given project, thereby reducing Eni’s profit share. They can also enforce different interpretations of contractual clauses relating to the recovery of
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certain expenses incurred by the Company to produce hydrocarbons reserves in any given project. In Kazakhstan we recorded a risk provision to account for a dispute with the First Party (i.e. the national oil company) about the sharing of the profit oil in a petroleum contract with regard to past fiscal years;

sovereign default or serious financial crises of those countries due to the fact that they rely heavily on petroleum revenues to sustain public finance and petroleum revenues have dramatically contracted during the recent, three-year long oil downturn. Financial difficulties at country level often translate into failure on part of state-owned companies and agencies to fulfill their financial obligations towards Eni relating to funding capital commitments in projects operated by Eni or to timely paying supplies of equity oil and gas volumes;

restrictions on exploration, production, imports and exports;

tax or royalty increases (including retroactive claims);

political and social instability which could result in civil and social unrest, internal conflicts and other forms of protest and disorder such as strikes, riots, sabotage, acts of violence and similar incidents. These risks could result in disruptions to economic activity, loss of output, plant closures and shutdowns, project delays, the loss of assets and threat 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;

difficulties in finding qualified suppliers in critical operating environments; and

complex processes of granting authorisations or licences affecting time-to-market of certain development projects.
Areas where Eni operates and where the Company is particularly exposed to political risk include, but are not limited to: Libya, Egypt, Algeria, Nigeria, Angola, Kazakhstan, Venezuela, Iraq and Russia. 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 Eni’s business, results of operations and financial condition.
In recent years, Eni’s operations in Libya were materially affected by the revolution of 2011 and the regime change, which caused a prolonged period of political and social instability. In 2011 Eni’s operations in the Country were shut down almost the entire year due to security issues with a material impact on results of operation and cash flow; in subsequent years we have experienced frequent disruptions at our operations albeit of a smaller scale than in 2011 due to security threats to our installations. Over the last couple of years, Eni’s oil activities in the country have come in line with management expectations, reflecting a certain degree of normalization in the Country internal situation and improving security conditions. In 2017, Eni’s production in Libya was 377 KBOE/d, which represents the highest level of Eni’s production in the Country on record. Despite this and other positive developments, Libya’s geopolitical situation continues to represent a source of risk and uncertainty for the foreseeable future. Currently, Libya represents approximately 20% of the Group’s total production; this incidence is forecasted to decrease in the medium term. In the event of major adverse events such as the resumption of internal conflict, acts of war, sabotage, social unrest, clashes and other forms of civil disorder, Eni could be forced to temporarily interrupt or reduce its producing activities at the Libyan plants, negatively affecting Eni’s results of operations, cash flow and business prospects.
Venezuela is currently experiencing a situation of financial stress amidst an economic downturn due to lack of resources to support the development of the country’s hydrocarbons reserves. The situation has been made worse by certain international sanctions targeting the country’s financial system, described below. We expect that the financial outlook of Venezuela will negatively impact our ability to recover our investments in the country. See Item 5 for a discussion of the impairment losses incurred by Eni at its assets in Venezuela in 2017.
Also Nigeria is undergoing a situation of financial stress, which has translated into continuing delays in collecting overdue trade receivables and operational credits and the incurrence of credit losses. Further, Eni’s activities in Nigeria have been impacted in recent years by continuing incidences of theft, acts of sabotage and other similar disruptions, which have jeopardized the Company’s ability to conduct operations in full security, particularly in the onshore area of the Niger Delta. Eni expects that those risks will continue to affect Eni’s operations in Nigeria and other countries.
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It is possible that the Group may incur further impairment or credit losses in future reporting periods depending on the evolution of the financial crises of the Countries where the Group is conducting oil&gas operations.
In Egypt, Eni plans to invest significantly in the next four-year plan, in particular to complete the development plan at the Zohr offshore gas field. We will continue monitoring the counterparty risk considering the expected increase in volumes of gas supplied to national oil companies due to the production ramp up at the Zohr project in the next years.
Eni closely monitors political, social and economic risks of 71 countries in which it has invested or intends to invest, in order to evaluate the economic and financial return of certain projects and to selectively evaluate projects. While the occurrence of those events is unpredictable, the occurrence of any such events could adversely affect Eni’s results from operations, cash flow and business prospects, also including the counterparty risk arising from the financing exposure of Eni in case state-owned entities, which are party to Eni’s upstream projects for developing hydrocarbons, fail to reimburse due amounts.
An escalation of the political crisis in Russia and Ukraine could affect Eni’s business in particular and the global energy supply generally. Sanctions against Venezuela could negatively affect the Country’s financial outlook, which could in turn negatively affect the Company.
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’s activities potentially targeted by the sanction regime comprise the upstream projects executed in Russia or with Russian partners that have been targeted by sectorial restrictive measures.
Eni has adapted its activities to the applicable sanctions and will adapt its business to any further restrictive measures that could be adopted by the relevant authorities. Recently, the US government has tightened the sanction regime against Russia by enacting the “Countering America’s Adversaries Through Sanctions Act”. In response to these new measures, the Company could possibly refrain from pursuing business opportunities in Russia or could slow down, postpone or put on hold certain exploration projects under execution in Russia.
It is possible 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.
In 2017, the US Administration enacted certain financing sanctions against Venezuela, which restrict the Country’s or its affiliates’ ability to access capital markets by prohibiting new transactions relating to equity or debt instruments with a longer maturity than a pre-set threshold. These sanctions have a limited, direct effect on Eni’s activities, which however are affected by the worsening financial outlook of the Country.
Risks in the Company’s Gas & Power business
Risks associated with the trading environment and competition in the gas market
The outlook of the European gas market remains muted due to continued oversupplies, exacerbated by increased availability of liquefied natural gas (“LNG”) on global scale, and weak demand dynamics. Growth in gas demand has been dampened by sluggish macroeconomic activity in the Eurozone, the increasing use of renewable sources in the production of electricity and competition from cheaper fossil fuels (like coal) in firing thermoelectric production. Management does not expect any meaningful acceleration in gas demand growth in Italy and in Europe and is forecasting flat growth in Europe and Italy until 2021.
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Against the backdrop of a challenging competitive environment, Eni anticipates a number of risk factors to the profitability outlook of the Company’s gas marketing business over the four-year planning period, considering the Company’s operational constraints dictated by its long-term supply contracts with take-or-pay clauses and its structure of fixed costs linked to the transportation rights at the main European backbones booked for multi-year periods. Such risk factors include continuing oversupplies, pricing pressures, volatile margins and the risk of deteriorating spreads of Italian spot prices versus continental benchmarks. The results of Eni’s wholesale business are particularly exposed to the volatility of the spreads between spot prices at European hubs and Italian spot prices because the Group’s supply costs are mainly linked to prices at European hubs, whereas a large part of the Group’s selling volumes are linked to Italian spot prices which, historically, have been higher. This price differential enables the Company to recover its fixed operating expenses in the gas wholesale business. In the next few years we expect that spot prices in Italy could align with prices at continental hubs due to a number of trends. These include possible developments in the regulatory environment aiming at increasing the liquidity at Italian hubs by granting access at international pipelines connecting Italy to Northern Europe and at Italian regasification terminal to new market operators; as well as the entry into operations of a project to import gas from the Caspian region to Italy by means of a new pipeline.
Eni’s management will continue to execute its strategy of renegotiating the Company’s long-term gas supply contracts in order to align pricing and volume terms to current market conditions as they evolve. The revision clauses provided by 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, the claiming party has the ability to open an arbitration procedure to obtain revised contractual conditions. However, the suppliers might also file counterclaims with the arbitration panel seeking to dismiss Eni’s request for a price review. All these possible developments within the renegotiation process could increase the level of risks and uncertainties relating the outcome of those renegotiations.
Current, negative trends in gas demands and supplies 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
In order to secure long-term access to gas availability, particularly with a view to supplying the Italian gas market and anticipating certain trends in gas demand, which thus far have failed to materialize, Eni has signed a number of long-term gas supply contracts with national operators of certain key producing countries. Most European gas supplies are sourced from those countries (Russia, Algeria, Libya, the Netherlands and Norway).
These contracts include take-or-pay clauses whereby the Company is required to off-take 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 the minimum contractual quantity. Similar considerations apply to ship-or-pay contractual obligations. Long-term gas supply contracts with take-or-pay clauses expose the Company to a volume risk, as the Company is contractually required to purchase minimum annual amounts of gas or, in case of failure, to pay the underlying price.
Management believes that the current market outlook which will be negatively affected by continued oversupplies, weak demand growth, strong competitive pressures as well as any possible change in sector-specific regulation represents a risk to the Company’s ability to fulfil its minimum take obligations associated with its long-term supply contracts.
Risks associated with sector-specific regulations in Italy
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 Gas & Power segment is subject to regulatory risks mainly in its domestic market in Italy. Developments in the regulatory framework may negatively affect future sales margins of gas and electricity,
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operating results and cash flow. The following describes the most important aspects of the ongoing regulatory framework of the gas&power sector in Italy.
The Italian Regulatory Authority for Energy, Networks and Environment (the “Authority”) is entrusted with certain powers in the matter of natural gas pricing. Specifically, 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. Accordingly, decisions of the Authority on these matters may limit the ability of Eni to pass an increase in the cost of the raw material onto final consumers of natural gas.
The Authority has established a benchmark gas price formula in favour of residential customers which are consuming 200,000 cubic meters of gas or less per year destined to civil utilizations (heating, cooking, air conditioning). In 2013, the Authority changed this pricing formula by introducing a full indexation of the raw material cost component of the tariff to spot prices, by this way replacing the former oil-linked indexation. The new regulatory regime was introduced in a market scenario where gas spot prices were significantly lower than gas prices under long-term, oil-linked contracts, as the Brent price at the time was about 100 $/BBL. Subsequently, the Authority introduced a compensation mechanism to promote the renegotiation of long-term gas supply contracts. This compensation mechanism was intended to mitigate the impact of the new tariff regime to operators with long-term supply contracts (typically oil-linked) by reimbursing them part of the higher long term gas supply costs which would be no longer recoverable through the tariffs. This compensation mechanism applied to the three thermal years from October 2013 through September 2016 and helped Eni mitigate the negative impact of the changed pricing regime to its final customers in the retail segment.
The indexation of the cost of the raw material to the spot prices of gas is expected to remain effective until September 2018. Subsequently, management forecasts a possible increase in competition in the retail segment due to the effects of Italian Law 124/2017 designed to further de-regulate the retail gas sector by eliminating the legal requirement of a gas price benchmark established pursuant to the administrative powers of the Authority. Italian Law 124/2017 has established measures intended to make retail customers knowledgeable about the possibility to choose among competing gas supply offers as well as to enable customers to evaluate competing offers against a benchmark. From March 2018, gas selling companies are required to provide customers in addition to their basic offer two additional pricing formulas, one at fixed price, the other at variable price, with contractual conditions in each case aligned with certain requirements established by the Authority.
Environmental, health and safety regulations
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 EU, international, national, regional and local laws and regulations regarding the impact of its operations on the environment and health and safety of employees, contractors, communities and properties. 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 health 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 resulting from the Group’s operations.
These laws and regulations also regulate the emission of substances and pollutants, the handling of hazardous materials and discharges to surface and subsurface of water 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 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 materials.
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Breaches of environmental, health and safety laws as well as negligent or willful release of pollutants into the atmosphere, the soil or groundwater would expose the Company’s employees to criminal and civil liability and the Company to the incurrence of liabilities associated with compensation for environmental, health or safety damage, expenses for environmental remediation and clean-up as well as damage to its reputation. Additionally, in the case of violation of certain rules regarding the safeguard of the environment and safety in the workplace, the Company may be liable for negligent or willful conduct on part of 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, safety in the workplace, health 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;

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 above permitted levels or of any other hazardous gases or other environmental liabilities as a result of its operations or if the Company is found guilty of violating environmental laws and regulations; and

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.
Furthermore, in those countries where Eni is currently operating new laws and regulations, the imposition of tougher licence requirements, increasingly strict enforcement or new interpretations of existing laws and regulations or the discovery of previously unknown contamination may also cause Eni to incur material costs resulting from actions taken to comply with such laws and regulations, including:

modifying operations;

installing pollution control equipment;

implementing additional safety measures; and

performing site clean-ups and remediation.
As a further result of any new laws and regulations or other factors, Eni may also have to curtail, modify or cease certain operations or implement temporary shutdowns of facilities, which could diminish Eni’s productivity and materially and adversely impact Eni’s results of operations, including profits and cash flow.
Risks of environmental, health and safety incidents and liabilities are inherent in many of Eni’s operations and products. Management believes that Eni adopts high operational standards to ensure safety in running its operations and safeguard of the environment and the health of employees, contractors and communities. In spite of such measures, it is possible that incidents like blowouts, oil spills, contaminations, pollution, and release in the air, soil and ground water of pollutants and other dangerous materials, liquids or gases, and other similar events could occur that would result in damage, also of large proportion and reach, to the environment, employees, contractors, communities and property. The occurrence of any such events could have a material adverse impact on the Group’s business, competitive position, cash flow, results of operations, liquidity, future growth prospects, shareholders’ returns and damage to the Group’s reputation.
As an example of said potential risks, operations at the Val d’Agri Oil Center (COVA) were shut down for a full quarter (from April 18, 2017 to July 18, 2017) became necessary following the detection of a small quantities of oil in the external area bordering the COVA. Notwithstanding the prompt and effective remedial measures taken by Eni, the shutdown of COVA negatively affected the Group results and cash flow in 2017. A shutdown also occurred at the Goliat platform offshore the Barents Sea due to an order from the Petroleum Safety Authority of Norway, which detected a failure at the electric engine of the facility.
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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 requirements and 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, natural resource damages, 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 a number of 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 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 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, nor 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 obligation exists 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 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 and the Italian Ministry of the Environment act as plaintiffs; (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 those risks, environmental liabilities could be substantial and could have a material adverse effect on Eni’s, results of operations, financial condition, liquidity business prospects, reputation and shareholders’ value, including dividends and the share price.
Rising public concern related to climate change has led and could lead to the adoption of worldwide laws and regulations which could result in a decrease of demand for hydrocarbons and increased compliance costs for the Company. Eni is also exposed to risks of technological breakthrough in the energy field and risks of extreme meteorological events linked to the climate change. All these developments may adversely affect the Group’s profitability, businesses outlook and reputation
Growing worldwide public concern over greenhouse gas (GHG) emissions and climate change, as well as increasingly regulations in this area, could adversely affect the Group’s businesses and reputation, increase its operating costs and reduce its profitability and shareholders returns. Those risks may emerge in the short and medium-term, as well as over the long-term.
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The scientific community has established a link between climate change and increasing GHG emissions. The worldwide goal to limit global warming has led, and we expect it to continue to lead, to new laws and regulations designed to reduce GHG emissions that could bring about a gradual reduction in the use of fossil fuel over the long-term, notably through the diversification of the energy mix.
Some governments have introduced carbon pricing mechanisms, which can be an effective measure to reduce GHG emissions at the lowest overall cost to society. Eni expects that more governments will adopt similar schemes and that a growing share of the Group GHG emissions will be subject to regulation in the short to medium term. We also expect that governments require companies to apply technical measures to reduce their GHG emissions. We are already incurring operating costs related to our participation in the European Emission Trading Scheme, whereby we need to purchase on the open markets emission allowances in case our GHG emissions exceed a pre-set limit established at European level by regulations in force (see Note No. 38 to the Financial Statements). In 2017 to comply with this carbon scheme, we purchased on the open market allowances corresponding to 11 million tonnes. In certain jurisdictions, we are already subject to carbon pricing schemes (for example in Norway). Due to likelihood of new regulations in this area, we expect 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 and could have a material adverse effect on Eni’s liquidity, results of operations, and financial condition.
The adoption and implementation of regulations that require reporting of GHG or otherwise limit GHG emissions from the Group’s equipment and operations could require us to incur costs to monitor and report on GHG emissions or install new equipment to reduce GHG emissions associated with the Group’s operations.
In the long-term, we expect that changes in environmental requirements targeting the reduction of GHG emissions (including land use policies responsive to environmental concerns) may increasingly focus on suppressing the demand for fossil fuels, which could negatively impact demand for oil and natural gas. State, national, and international governments and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of GHG in areas in which Eni conducts business. Because Eni’s business depends on the global demand for oil and natural gas, in case existing or future laws, regulations, treaties, or international agreements related to GHG and climate change, including incentives to preserve energy or use alternative energy sources, technological breakthrough in the field of renewable energies or mass-adoption of electric vehicles reduce the worldwide demand for oil and natural gas, this could significantly and negatively affect Eni’s results of operations, liquidity, business prospects and shareholders’ returns.
Natural gas, the least GHG-emitting fossil energy source, represented approximately 50% of Eni’s production in 2017 on an available-for-sale basis; as of December 31, 2017, gas reserves represented approximately 51% of Eni’s total proved reserves of its subsidiary undertakings and joint ventures. Eni’s portfolio exposure is reviewed annually against changing GHG regulatory regimes and physical conditions to identify emerging risks. To test the resilience of new projects, Eni assesses potential costs associated with GHG emissions when evaluating all new capital projects. New projects’ internal rates of return are stress-tested against two sets of assumptions: i) a uniform cost estimated by Eni’s management per ton of carbon dioxide (CO2) equivalent to the total GHG emissions of each capital project; ii) the hydrocarbon prices and cost of CO2 emissions adopted in the International Energy Agency (IEA) Sustainable Development Scenario “IEA SDS”. This stress test is performed both when the final investment decision is made and, on a regular basis, to monitor the progress of each project. The review performed at the end of 2017 concluded that the internal rates of return of Eni’s ongoing projects in aggregate would be only marginally affected by a carbon pricing mechanism. The project development process features a number of checks that may require the development of detailed GHG and energy management plans. High-emitting projects undergo additional sensitivity testing, including the potential for future CCS (Carbon Capture and Storage) projects. Projects in the most GHG-exposed asset classes have GHG intensity targets that reflect standards sufficient to allow them to compete and prosper in a more CO2 regulated future. These processes can lead to projects being stopped, designs being changed, and potential GHG mitigation investments being identified, in preparation for when regulation would make these investments commercially compelling.
Furthermore, management performed a review of the recoverability of the book values of the Company’s oil & gas assets under the assumptions of the IEA SDS. This review covered all of the oil & gas cash generating unit (CGUs) that are regularly tested for impairment in accordance to IAS 36. The IEA
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SDS sets out an energy pathway consistent with the goal of achieving universal energy access by 2030 and of reducing by a half energy-related CO2 emissions and premature deaths from air pollution by 2040, compared to projections with no further policy action. The IEA SDS forecasts that demand for oil is going to peak in 2020. The pricing assumptions are consistent with Eni’s scenario in the case of crude oil, while the gas prices projected by the IEA SDS are higher by an approximately 15% than Eni’s forecast. CO2 emissions will be priced at 140 $ per ton in real terms in 2040 higher than Eni’s CO2 pricing assumptions for the medium-long term. The sensitivity test performed at Eni’s oil&gas CGUs under the IEA SDS confirmed the resiliency of Eni’s asset portfolio with a 4% reduction in the aggregate fair value of Eni’s properties due to the CO2 pricing assumptions.
Some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have 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. Furthermore, Eni’s operations, particularly offshore production of oil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to Eni’s operations and consequent loss or damage of properties and facilities, as well as a loss of output, loss of revenues, increasing maintenance and repair expenses and cash flow shortfall. If any such effects were to occur because of climate change or otherwise, they could have an adverse effect on the Group’s assets and operations.
Finally, there is a reputational risk linked to the possibility that oil companies may be perceived by institutions and the general public as the entities mainly responsible of the climate change. This could possibly make Eni’s shares less attractive to investment funds and individual investors who assess the risk profile of companies against their environmental and social footprint when making investment decisions.
Risks related to legal proceedings and compliance with anti-corruption legislation
Eni is the defendant in a number of civil actions and administrative proceedings. In addition to existing provisions accrued, as of December 31, 2017 to account for ongoing proceedings, in future years Eni may incur significant losses in addition to the amounts already accrued in connection with pending or future legal proceedings 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; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to the circumstance that they are often inherently difficult to estimate. Certain legal proceedings and investigations to which Eni or its subsidiaries or its officers and employees are parties involve the alleged breach of anti-bribery and anti-corruption laws and regulations and other ethical misconduct. Such proceedings are described in Note 38 to the Consolidated Financial Statements, under heading “Legal Proceedings”. Ethical misconduct and noncompliance with applicable laws and regulations, including noncompliance with anti-bribery and 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.
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 materialize, Eni’s financial performance and shareholders’ returns may be adversely affected.
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
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higher. Accordingly, the results of operations of the Gas & Power segment 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.
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, its business and operations could be severely disrupted with negative consequences on results of operations and cash flow.
Exposure to financial risk
Eni’s business activities are exposed to financial risk. This includes exposure to market risk, including commodity price risk, interest rate risk and foreign currency risk, as well as liquidity risk, and credit risk.
Eni’s primary source of exposure to financial risk is the volatility in commodity prices. Generally, the Group does not hedge its strategic exposure to the commodity risk associated with its plans to find and develop oil and gas reserves, volume of gas purchased under its long-term gas purchase contracts, which are not covered by contracted sales, its refining margins and other activities. The Group’s risk management objectives in addressing commodity risk are to optimise the risk profile of its commercial activities by effectively managing economic margins and safeguarding the value of Eni assets. To achieve this, Eni engages in risk management activities seeking both to hedge Group’s exposures and to profit from short-term market opportunities and trading.
Eni is engaged in substantial trading and commercial activities in the physical markets. Eni also uses financial instruments such as futures, options, Over-the-Counter forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity in order to manage the commodity risk exposure. Eni also uses financial instruments to manage foreign exchange and interest rate risk.
The Group’s approach to risk management includes identifying, evaluating and managing the financial risk using a top-down approach whereby the Board of Directors is responsible for establishing the Group risk management strategy and setting the maximum tolerable amounts of risk exposure. The Group’s Chief Executive Officer is responsible for implementing the Group risk management strategy, while the Group’s Chief Financial Officer is in charge of defining policies and tools to manage the Group’s exposure to financial risk, as well as monitoring and reporting activities.
Various Group committees are in charge of defining internal criteria, guidelines and targets of risk management activities consistent with the strategy and limits defined at Eni’s top level, to be used by the Group’s business units, including monitoring and controlling activities. Although Eni believes it has established sound risk management procedures, trading activities involve elements of forecasting and Eni is exposed to the risks of market movements, of incurring significant losses if prices develop contrary to management expectations and of default of counterparties.
Exchange rate risk
Movements in the exchange rate of the euro against the U.S. dollar can have a material impact on Eni’s results of operations. Prices of oil, natural gas and refined products generally are denominated in, or linked to, U.S. dollars, while a significant portion of Eni’s expenses are incurred in euros. Accordingly, 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 U.S. dollar-denominated expenses and may also result in significant translation adjustments that impact Eni’s
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shareholders’ equity. The Exploration & Production segment is particularly affected by movements in the U.S. dollar versus the euro exchange rates as the U.S. dollar is the functional currency of a large part of its foreign subsidiaries and therefore movements in the U.S. dollar versus the euro exchange rate affect year-on-year comparability of results of operations.
Susceptibility to variations in sovereign rating risk
Eni’s credit ratings are potentially exposed to risk in 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 debt instruments issued by the Company could be downgraded.
Interest rate risk
Interest on Eni’s debt is primarily indexed at a spread to benchmark rates such as the Europe Interbank Offered Rate, “Euribor”, and the London Interbank Offered Rate, “Libor”. As a consequence, movements in interest rates can have a material impact on Eni’s finance expense in respect to its debt. Additionally, spreads offered to the Company may rise in connection with variations in sovereign rating risks or company rating risks, as well as the general conditions of capital markets.
Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or 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 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 a number of macroeconomic risk factors, including the financial situation of certain hydrocarbons-exporting countries whose financial conditions have sharply deteriorated following the protracted downturn in crude oil prices. 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, Eni’s ability to maintain Eni’s long-term investment program may be impacted with a consequent effect on Eni’s growth rate, and may impact shareholder returns, including 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, exploitation and production of oil and natural gas reserves. The Company’s capital budget for the four-year plan 2018 – 2021 amounts to approximately euro 32 billion. The Company has budgeted approximately euro 7.7 billion for capital expenditures in 2018. The Company is managing to contain capital expenditures without necessarily sacrificing growth leveraging on capital discipline, phased approach to major projects and the reduction of idle capital through the optimization of the time-to-market of the reserves.
Historically, Eni’s capital expenditures have been financed with cash generated by 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;
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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 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.
Credit risk
Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay due amounts. Credit risks arise from both commercial partners and financial ones. In the last few years, the Group has experienced a level of counterparty default higher than in previous years due to the severity of the economic and financial downturn that has negatively affected several Group counterparties, customers and partners. Consequently, the amount of trade and other receivables overdue at the balance sheet date has become an area of issue. Our E&P business is significantly exposed to the credit risk because of the deteriorated financial outlook of many oil-producing countries, particularly Venezuela and Nigeria, due to a three-year long downturn in oil prices, which has negatively impacted petroleum revenues and cash reserves. The financial difficulties of those countries have extended to state-owned oil companies and other national agencies who are partnering Eni in the execution of development projects of hydrocarbons reserves or who are the buyers of 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 receivable or its investments towards those entities. For further information, see the paragraph “Political Considerations” above. The Gas & Power business has also experienced a higher-than-average level of counterparty default in its segment of supplying gas and electricity to the retail market due to the severity of the economic downturn in Italy. In the 2017 Consolidated Financial Statements, Eni accrued an allowance against doubtful trade accounts amounting to euro 539 million, mainly relating to the Gas & Power business segment in relation to Italian retail customers. Management believes that this business 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 have been particularly hit by the financial and economic downturn. Eni believes that the management of doubtful accounts represents an issue to the Company, which will require management focus and commitment going forward. Eni cannot exclude the recognition of significant provisions for doubtful accounts in the future. In particular, management is closely monitoring exposure to the counterpart risk in its Exploration & Production due to the magnitude of the exposure at risk and to the long-lasting effects of the oil price downturn on its industrial partners.
Digital infrastructure is an important part of maintaining Eni’s operations. A breach of Eni’s digital security could result in serious damage to business operations, personal injury, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs
The reliability and security of Eni’s digital infrastructure is critical to maintaining the availability of Eni’s business applications, including the reliable operation of technology in Eni’s various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. Disruption to or breaches of Eni’s critical IT services or information security systems could adversely affect the Group’s operations. The Group’s activities depend heavily on the
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reliability and security of its information technology (IT) systems. Integrity of IT systems could be compromised due to, for example, technical failure, cyber-attack (viruses, computer intrusions), power or network outages or natural disasters. The cyber threat is constantly evolving. Attacks are becoming more sophisticated with regularly renewed techniques as 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. 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, litigation and legal liabilities could occur, potentially having a material adverse effect on the Group’s financial condition, including its operating profit and cash flow.
Claim of the Italian market regulator against Eni’s jv Saipem
Eni retains a 31% interest in Saipem which is jointly controlled with another shareholder. On March 5, 2018, the Italian securities and exchange regulator – Consob – asserted a claim against Saipem stating that the entity consolidated and separate financial statements for the year 2016 did not comply with applicable accounting rules. In the 2016 financial statement Saipem recorded impairment losses at its property, plants and equipment of  €2,118 million and an allowance for doubtful accounts of  €171 million. Consob is asserting that part of those impairment losses amounting to €1.3 billion and €0.1 billion of charges related to inventories and deferred tax assets should have been accrued in the financial year ended December 31, 2015. Consob is also asserting that the methodology used by Saipem to assess the discount rate of the future cash flows associated with the tangible assets is not fully compliant with generally accepted accounting principles. Saipem has expressed in a press release that it disagrees with the conclusions of Consob; however, it has committed to disclosing pro-forma statements of the financial position and of the profit and loss as at Dicember 31, 2016 including comparative data to account for the comments of Consob. On March 6, 2018, Saipem publicly disclosed that its Board of Directors resolved to file an appeal against Consob decision before the relevant judicial authorities.
On October 27, 2015 Eni and an Italian state-owned venture agreed to the divestiture of a 12.503% stake previously held in Saipem by Eni and entered into a shareholders’ agreement whereby Eni and the venture agreed to jointly control Saipem. Therefore, when the transactions closed on January 22, 2016, Saipem and its subsidiaries were derecognized from Eni’s consolidated accounts and the retained investment was classified as an investment in a joint-venture accounted under the equity method. Effective November 1, 2015 Saipem was classified in Eni’s consolidated financial statements as a discontinued operations and accounted in accordance to IFRS 5 which establishes the interruption of the amortization process and the evaluation of the disposal group at the lower of its carrying amount and the fair value given by the market value, because the recoverability of the disposal group occurs through a sale instead of its continuative use. On that date, the fair value of the disposal group was higher than its carrying amount.
In the Annual Report 2015 the interest in Saipem was aligned to its fair value which was lower than the carrying amount due to a downtrend in the market price of Saipem, thus recognizing in Eni’s consolidated accounts an impairment loss of  €393 million (€173 million pertaining to Eni’s shareholders). On January 22, 2016, when Eni lost its exclusive control over the investee due to the efficacy of the shareholders’ agreement and the joint control over Saipem was established, Eni aligned again the retained interest in the entity to its fair value recording an impairment loss of  €441 million in accordance to the provisions of IFRS 10. This fair value became the inception value for the subsequent accounting of the retained investment under the equity method. As of June 30, 2016 the carrying amount of Saipem investment in Eni’s books was significantly lower than the corresponding fraction of the net assets of the investee. This difference was absorbed at the closing of the financial year 2016.
Conclusively, pending the evolution of the litigation between Saipem and Consob, management believes that the accounting of the Saipem investment in Eni’s consolidated financial statements in the target reporting periods was primarily based on measurements at fair value obtained by observing market prices.
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Item 4. INFORMATION ON THE COMPANY
History and development of the Company
Eni SpA with its consolidated subsidiaries engages in the exploration, development and production of hydrocarbons, in the supply and marketing of gas, LNG and power, in the refining and marketing of petroleum products, in the production and marketing of basic petrochemicals, plastics and elastomers and in commodity trading. Eni has operations in 71 countries and 32,934 employees as of December 31, 2017.
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 Giovan Battista Di Giovanni, Washington DC –  USA 601, 13th street, NW 20005.
Eni’s principal segments of operations are described below.
Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 46 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Indonesia, Ghana and Mozambique. In 2017, Eni’s average daily production amounted to 1,719 KBOE/d on an available-for-sale basis. As of December 31, 2017, Eni’s total proved reserves amounted to 6,990 mmBOE, which include subsidiary undertakings and Eni’s share of reserves of equity-accounted and proportionally consolidated entities.
Eni’s Gas & Power segment engages in the supply, trading and marketing of gas, LNG and electricity, international gas transport activities and commodity trading and derivatives. This segment also includes the activity of electricity generation, which is ancillary to the marketing of electricity. In 2017, Eni’s worldwide sales of natural gas amounted to 80.83 BCM, of which 37.43 BCM in Italy. Eni produces power at a number of operated gas-fired plants in Italy with a total installed capacity of 4.7 GW as of December 31, 2017. In 2017, electricity sold totalled 35.33 TWh. The Gas & Power segment comprises results of the Group activities intended to manage commodity risk and of asset-backed trading activities. Through the trading department of the parent company and its wholly-owned subsidiary Eni Trading & Shipping SpA, the Group engages in derivative activities targeting the full spectrum of energy commodities on both the physical and financial trading venues. This activity is designated to hedge part of the Group’s exposure to commodity risk and to optimize commercial margins by entering speculative derivative transactions. Furthermore, this activity includes the results of crude oil and products supply, trading and shipping.
Eni’s Refining & Marketing and Chemicals segment includes the results of the R&M business and of the chemicals business.
The R&M business engages in crude oil supply and refining and the marketing of petroleum products in retail and wholesale markets mainly in Italy and in the rest of Europe, as well as in the petrochemical business. In 2017, processed volumes of crude oil and other feedstock, including renewable feedstock, amounted to 24.26 mmtonnes (of which traditional refinery throughputs were 24.02 mmtonnes and green refinery throughputs were 0.24 mmtonnes) and sales of refined products were 33.20 mmtonnes, of which 25.73 mmtonnes in Italy. Retail sales of refined products at Eni’s service stations amounted to 8.54 mmtonnes in Italy and in the rest of Europe. In 2017, Eni’s retail market shares in Italy through its “Eni” branded network of service stations was 25%.
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Through its wholly-owned subsidiary Versalis, Eni engages in the production and marketing of basic petrochemical products, plastics and elastomers. Activities are concentrated in Italy and in Europe. At the end of 2017 a joint venture for the production of elastomers started operations in South Korea with a local operator. In 2017, production volumes of petrochemicals amounted to 5,818 ktonnes. The results of Versalis have been aggregated with those of R&M, in the reportable segment “R&M and Chemicals” because the two segments exhibit similar economic characteristics.
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 48 – Other information about investments – of the Notes on Consolidated Financial Statements”.
Strategy
During the downturn in oil prices which lasted from the second half of 2014 to the end of 2017, the Company has managed to reduce its cash neutrality – i.e. the level of Brent price at which cash flow from operating activities is able to fund capital expenditures and dividend payments – and to preserve a solid balance sheet. We exited the downturn with a leverage of 0.23 as of December 31, 2017 and a cash neutrality estimated at 57 $/BBL. These targets were achieved by leveraging on cost and capital discipline, growing profitably in E&P, restructuring our loss-making mid and downstream business that are currently generating structural positive results and cash generation, and finally process simplification and streamlining.
Our exploration activity was one of the major drivers of our value-creating strategy due to its strong contribution to reserve replacement and cash generation by means of our dual exploration model. This helped the Company anticipate the cash conversion of discovered resources by divesting part of the high interests retained by Eni in its core exploration assets. In particular, in 2017 the Company closed the divestment of a 25% interest in natural gas-rich Area 4 offshore Mozambique and in the large Zohr gas discovery offshore Egypt. From 2013 our dual exploration model generated $10.3 billion of cash proceeds, without affecting the Company’s growth plans. Looking forward our strategy will evolve to enhance value generation across all our businesses.
The main drivers will be:

Growing oil & gas production with improving returns leveraging on the organic developments of our discoveries;

Retaining a strong focus on exploration activities to ensure reserve replacement and further opportunities to deploy our dual exploration model;

Strengthening results and cash generation in our mid and downstream businesses through new contract renegotiations, selective growth initiatives, plant optimizations, innovation in products and services, and cost efficiencies;

Developing the green businesses;

Pursuing margin and growth opportunities through enhanced business integration;

Financial discipline;

Increased digitalization to support operations efficiency;

Reducing the carbon footprint of the Company.
Implementation of this strategy will be supported by a capital plan of  €31.6 billion, more than 80% of which will be destined to finding and developing hydrocarbons reserves.
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We believe that the action plan we have designed for the next four-year period 2018-2021 at the Company’s Brent scenario of  $60 in 2018 subsequently increasing to our long-term case of  $72 will improve the Company’s profitability and cash generation driving down our cash neutrality. See Item 5 – Management Expectations of Operation. We remain committed to our progressive dividend policy in line with the expected growth in underlying earnings and cash flow.
Strategy for a low-carbon scenario
Our path to decarbonization has four main drivers that concern both our core business activities and new energy perspectives:

The first is to lower CO2 emissions in all our operations

Secondly, we will continue to expand a low cost and low carbon portfolio of oil&gas projects

Third, we will keep on developing renewables, and

Finally, R&D will play a key role in our decarbonization strategy.
On carbon footprint, we have already reduced our direct upstream CO2 emissions by around 40% since 2007, improving all of our performances and efficiency ratios. By 2025 we are targeting:

A reduction of upstream GHG emissions by 43% and methane fugitive emissions by 80% vs 2014 and

Zero routine gas flaring
In the long-term, we will continue to rely on the strength of our resilient portfolio. We currently estimate that the average breakeven price of new projects under execution is less than 30 $/BBL, which means that our projects will stay competitive under all carbon price scenarios. Eni applies a carbon pricing sensitivity of 40 $/ton CO2 in real terms that implies a strong readiness in our projects for emissions optimization. Even under the IEA Sustainable Development Scenario, our portfolio confirms its resilience, with a marginal reduction in our internal rates of return and in the value of our assets.
In addition, we will continue to support a widespread use of natural gas in the future energy mix with gas resources playing an increasing role in our portfolio.
In our decarbonization strategy, we plan a strong development of our green businesses, and we are planning capital expenditures of more than €1.8 billion over the next four years in these initiatives, including R&D.
In the downstream business we are currently producing bio-products from our facilities. The Venice traditional refinery underwent a re-configuration program to transform the plant into a bio-refinery with a current production of 0.24 mmtonnes and a similar industrial solution is being implemented at the Gela refinery with expected start-up at the end of 2018. The two refineries are planned to produce 1 mmtonnes per year of green-diesel by 2021, making Eni one of the top producers in Europe.
We have also launched a series of green chemical projects such as the production of intermediates from vegetable oil and a pilot project to use Guayule crops to produce natural rubber.
Finally, we will grow our new energy business to 1GW by the end of the four-year plan.
With regards to reductions in emissions, the current asset portfolio will enable Eni to save around 28 mmtonnes of CO2 during the four-year plan 2018-2021, which includes direct and indirect emissions.
More information are provided in paragraph “Path to decarbonization” below.
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Significant business and portfolio developments
The significant business and portfolio developments that occurred in 2017 and to date in 2018 were the following:

March 2018 – Eni and Sonangol started oil production at the Ochigufu project, in Block 15/06 of Angola’s deep offshore. The field will add 25 KBBL to the current production levels. Achieved one and a half year from the presentation of the Plan of Development, this start-up is Eni’s first in 2018 as well as being the first start-up of the year in Angola.

March 2018 – Eni signed a license agreement with Zhejiang Petrochemicals for the license for the construction of two refining lines based on Eni Slurry Technology (EST). The two production lines will have a refining capacity of 3 mmtonnes per year and they will be built as part of a project for the construction of a new refinery with a capacity of 40 mmtonnes per year. Start-up is planned for 2020.

March 2018 – Eni agreed to sell to Mubadala Petroleum a 10% stake in the Shorouk concession, offshore Egypt, where the Zohr gas field is currently producing. The agreed consideration is $934 million. The completion of the transaction is subject to the fulfillment of certain standard conditions, including all necessary authorizations from Egypt’s Authorities. Following approval of this agreement, Eni will retain the operatorship of the block with a 50% interest.

March 2018 – Eni signed in Abu Dhabi two Concession Agreements for the acquisition of a 5% stake in the Lower Zakum offshore oil field and of a 10% stake in the oil, condensate and gas offshore fields of Umm Shaif and Nasr, for a total participation fee of about $875 million and a contractual term of 40 years. Lower Zakum, located about 65 kilometers off the coast of Abu Dhabi, has a target production of 450 KBBL/d. Umm Shaif and Nasr, located about 135 kilometers from the coast of Abu Dhabi, have a target production of 460 KBBL/d.

March 2018 – Eni signed agreements with Commonwealth Fusion Systems LLC (CFS) and the Massachusetts Institute of Technology to acquire an equity stake in CFS for the industrial development of the fusion power generation technology. Eni will support CFS to develop the first commercial power plant producing energy by fusion, a safe, sustainable, virtually inexhaustible source without any emission of pollutants and greenhouse gases. Eni will acquire a significant share in the company with an initial investment of  $50 million.

February 2018 – Eni’s subsidiary Versalis and Bridgestone Americas (Bridgestone) signed a partnership agreement to develop a technology platform to commercialize guayule in the agricultural, sustainable-rubber and renewable-chemical sectors. The partnership combines Versalis’ core strengths in guayule research, commercial-scale process engineering and market development for renewables with Bridgestone’s leadership position in guayule agriculture and production technologies.

February 2018 – Eni signed two Exploration and Production Agreements (EPA) with the Republic of Lebanon covering Blocks 4 and 9, in the deep waters offshore. Eni will retain a 40% interest in both blocks.

February 2018 – Exploration activities yielded positive results with the Calypso 1 gas discovery in Block 6 (Eni operator with a 50% interest), offshore Cyprus.

February 2018 – Eni and its partner Qatar Petroleum have been awarded rights to Block 24 located in in the deep waters of the Cuenca Salina Basin in Mexico. Eni will operate the Block 24 with a 65% working interest.

January 2018 – A licensing agreement was signed with Sinopec, the largest refining company in the world, for the use of the Eni Slurry Technology (EST) conversion proprietary technology. Eni will provide Sinopec with the basic engineering project related to the construction of a refining plant based on the EST, that is able to convert refining residues entirely into high-quality light products, eliminating both liquid and solid refining residues with significant environmental benefits.

In 2017, Eni signed a number of strategic cooperation agreements in the upstream and renewable energy sectors in Kazakhstan. A first agreement provided for the acquisition by Eni of a 50% stake for exploration and production activities in the Isatay block located in the Kazakh sector of the Caspian Sea. The Isatay block is estimated to have significant oil resources and will be operated by a joint operating company established by KMG and Eni on a 50/50 basis. In addition, Eni and KMG signed an agreement to further expand upstream technology co-operation and evaluate potential joint developments in new projects. The agreement includes technical and managerial training programs for local staff. Eni, KMG and the other partners
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signed with the Ministry of Energy of the Republic of Kazakhstan, and the Kazakh Committee of geology and subsoil use, a Memorandum of Understanding to evaluate future cooperation terms in the Kazakh-Russian Pre-Caspian Basin recording certain significant oil discoveries. In addition, Eni and General Electric (GE) signed with the Minister of Energy of the Republic of Kazakhstan an agreement to promote the development of renewable energy projects in the Country. In particular, Eni and GE will co-operate to evaluate the construction of a wind power plant with approximately 50 MW capacity and further future initiatives.

December 2017 – Eni successfully tested the Tecoalli 2 well in Area-1, offshore Mexico. The result and the revision of the reservoir models of the Amoca and Miztón fields, prompted Eni to raise its estimates of the hydrocarbon resources of Area 1, mainly crude oil.

December 2017 – Acquired a 32.5% interest of the Evans Shoal gas field in the NT/RL7 offshore license in the northern of Australia, nearby the Darwin liquefaction gas plant, where Eni holds an interest. The agreement received all necessary approvals. Following this acquisition Eni retains the operatorship with a 65% interest.

December 2017 – Eni signed a Petroleum Agreement (PA) with the Moroccan State Company ONHYM to enter into the Tarfaya Offshore Shallow exploration permits I-XII. Once the agreement is closed Eni will be the operator of the license with a 75% stake, while ONHYM will retain a 25% stake.

December 2017 – Eni achieved production start-up of the Zohr gas field, in less than two years from the FID and two and a half years from discovery, located in the Shorouk offshore block in Egypt.

In 2017 – In line with portfolio rationalization plan of the Gas & Power retail activities, Eni completed the sale to Eneco of retail activities in Belgium related to approximately 850,000 electricity and gas delivery points, representing a market share of around 10% of the Belgian market, and agreed to the divestment of the Tigàz gas activities in Hungary with the signing of an agreement with MET. Tigàz is active in the gas distribution through a 33,700 kilometers-long network and 1.2 million delivery points. The transaction is subject to regulatory approval by the relevant Authorities.

December 2017 – Eni and Sonatrach signed a Memorandum of Understanding for the development of a partnership in the renewables sector.

December 2017 – Eni and ExxonMobil closed the sale of a 25% indirect interest in the Area 4 block, offshore Mozambique, through the sale of a 35.7% stake in Mozambique Rovuma Venture. The agreed terms, based on the agreements of March 2017, include a cash price of approximately $2.8 billion plus the contractual adjustments up to the closing date. Following completion of the transaction, Mozambique Rovuma Venture, is now jointly by Eni and ExxonMobil with a 35.7% stake and the remaining interest of 28.6% by CNPC.

December 2017 – Eni, together with its Area 4 Partners, closed the project financing of Coral South FLNG construction project. The financing agreement was subscribed by 15 major international banks and guaranteed by 5 Export Credit Agencies. Coral South FLNG is the first project sanctioned by the Area 4 Partners for the development of the significant gas resources discovered by Eni and its Partners in the Rovuma Basin offshore Mozambique.

November 2017 – Eni signed with Sonangol an agreement to increase to 48% Eni’s interest in the Cabinda North block onshore Angola, which was previously participated by Eni with a 15% interest, also acquiring operatorship. The block is located in a little-known oil basin, where Eni plans to leverage on the mining knowledge acquired in the exploration and development activities progressed in nearby areas of the Republic of Congo.

November 2017 – Started production of elastomers at the Lotte Versalis Elastomers (LVE) joint venture. The industrial complex consists of three plants with a capacity of 200 ktonnes per year for the production of elastomers for tyre and other components in the automotive industries.

November 2017 – signed with the Government of the Sultanate of Oman and the state oil company OOCEP an Exploration and Production Sharing Agreement for the Block 52, offshore Oman. Concurrently Eni signed an agreement to assign an interest in the Block to Qatar Petroleum oil company. The agreement is subject to approval by the relevant Authorities of the country. Following approval of these agreements, Eni will retain the operatorship of the block with a 55% interest.

October 2017 – Eni closed the sale of a 30% stake in the Shorouk concession, offshore Egypt where the Zohr gas field is located, to Rosneft.
30


September 2017 – Eni and China National Petroleum Corporation (CNPC) signed a cooperation agreement, covering activities in China and overseas, in order to cooperate in the oil&gas exploration and production, gas and LNG value chain, trading and logistics opportunities, refining and petrochemicals.

May 2017 – Production started up at the Integrated Oil & Gas Development project in the Offshore Cape Three Points (OCTP) in Ghana, operated by Eni with a 44.44% interest.

May 2017 – Eni started LNG production from the Jangkrik Project in the Muara Bakau block, deep offshore Indonesia, ahead of schedule by means of ten offshore wells linked to the Floating Production Unit (FPU) with a production of approximately 630 mmCF/d (equal to 120 KBOE/​d). The LNG is sold under long-term contracts, partly to PT Pertamina and partly to Eni, which will sell up to 11 mmtonnes for 15 years as part of the supply agreement signed with the Pakistan LNG state company.

April 2017 – Exploration activity in Libya yielded positive results with a new gas and condensates discovery in the contractual area D (Eni’s interest 50%). The discovery is located nearby to the Bouri (Eni’s interest 50%) and Bahr Essalam (Eni’s interest 50%) production fields. The Country’s authorities extended the exploration license period until 2019, without additional commitment activities. The exploration success is in line with Eni’s exploration strategy of focusing on near-field incremental activities.

March 2017 – Obtained majority stakes in two exploration blocks offshore Ivory Coast. The two deep offshore blocks cover a total area of about 2,850 square kilometers. Eni will operate and hold a 90% stake in both blocks, with the state-owned company Petroci retaining the remaining 10% interest.

March 2017: Eni and Gazprom signed a Memorandum of Understanding for evaluating the prospects for cooperation in developing the Southern corridor for gas supplies from Russia to European countries, including Italy, as well as the updating of the Russia-Italy gas supply agreements.

March 2017: finalized a farm-in agreement to acquire a 50% interest of Block 11, Offshore Cyprus, which will be operated by Total. The exploration area covers 2,215 square kilometers, nearby the Zohr discovery in the Egyptian offshore. Block 11 is expected to be drilled within 2017.

February 2017: started-up the Cabaça South East field of the East Hub Development Project, in Block 15/06 of the Angolan deep offshore, five months ahead of the schedule. Block 15/06 will reach a peak production of 150 KBBL/d this year.

January 2017: successfully drilled an appraisal well of the Merakes gas discovery regulated by the Production Sharing Contract (PSC) in East Sepinggan, in Indonesia. This discovery is located 35 kilometers from the Eni operated Jangkrik field, close to starting operations.

January 2017: made a discovery in the PL128/128D licenses in the Norwegian Sea nearby the FPSO (Floating Production, Storage and Offloading) operating the Norne field. This discovery is part of Eni’s near-field exploration strategy aimed at unlocking the presence of additional resources in proximity to existing infrastructures.

January 2017: Eni was awarded three new exploration licenses in Norway, as a part of the APA Round.
31

BUSINESS OVERVIEW
Exploration & Production
Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 46 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Indonesia, Ghana and Mozambique. In 2017, Eni average daily production amounted to 1,719 KBOE/d on an available-for-sale basis. As of December 31, 2017, Eni’s total proved reserves amounted to 6,990 mmBOE; proved reserves of subsidiaries totaled 6,430 mmBOE; Eni’s share of reserves of equity-accounted entities was 560 mmBOE.
Eni’s strategy in its Exploration & Production operations is to pursue profitable production growth by developing its portfolio of projects underway and by optimizing its current producing fields. We plan to achieve an average production growth rate of 3.5% in the next 2018-2021 four-year period. Our production plans are incorporating our Brent price scenario of 60$/BBL in 2018 and a gradual recovery in the subsequent years up to our long-term case of 72$/BBL in 2021 and going forwards (on constant monetary term compared to 2021, i.e. from 2022 onwards crude oil prices will grow in line with a projected inflationary rate); as well as certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices which are disclosed under “Item 5 – Management’s expectations of operations”.
Management plans to achieve the target production growth by continuing development activities and new project start-ups in the main areas of operations including, North Africa, Sub-Saharan Africa, Mexico, Middle and Far East, by leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. New field start-ups, production ramp-ups and continuing production optimization will add approximately 900 KBOE/d in 2021; over 75% of these new projects have already been sanctioned and Eni is operator in approximately 80%.
Management plans to maximize the production recovery rate at our current fields by counteracting natural field depletion and reducing facilities downtime. This will require intense development activities of work-over and infilling and careful planning of maintenance activities. We expect that continuing technological innovation and competence build-up will drive increasing rates of reserve recovery.
Management plans to invest €24 billion to develop reserves over the next four years, of which approximately €16 billion directed to new field start-ups and ramp-ups while the remaining to product optimization.
Planned expenditures in exploration are expected to be approximately €2.0 billion. Our projects will comprise near-field activities designed to provide fast production support and contribute to the cash flow, as well as new initiatives targeting conventional prospects with high working interest in order to support Eni’s dual exploration model in case of material discoveries. Finally, we forecast selective initiatives in high-risk, high-reward plays.
Management intends to implement a number of initiatives to support profitability in its upstream operations by exercising tight control over project time schedules and costs and reducing the time span, which is necessary to develop and market reserves. We plan to achieve efficient development of our reserves by: (i) in-sourcing critical engineering and project management activities and increasing direct control and governance on construction and commissioning activities; and (ii) signing framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants, increasing focus on supply chain programming to optimize order flows. Based on these initiatives, we believe that almost all of our projects, which we are currently developing over the next four years, will be completed on time and on budget.
32

Finally, we plan to achieve further cost efficiencies by: (i) increasing the scale of our operations as we concentrate our resources on larger fields than in the past where we plan to achieve economies of scale; (ii) expanding the share of operated production. We believe operatorship will enable the Company to exercise better cost control, effectively manage reservoir and production operations, and deploy our safety standards and procedures to minimize risks; and (iii) applying our technologies which we believe can reduce drilling and completion costs.
We plan to mitigate the operational risk relating to drilling activities by applying Eni’s rigorous procedures throughout the engineering and execution stages, by leveraging on proprietary drilling technologies, excellent skills and know-how, increased control of operations and by deploying technologies which we believe to be able to reduce blow-out risks and to enable the Company to respond quickly and effectively in case of emergencies.
For the year 2018, management plans to spend over €6 billion in reserves development and exploration projects.
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 U.S. Securities and Exchange Commission (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 share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil). A similar scheme applies to buy-back and 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) continuously 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.
33

Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has 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.
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 “Università degli Studi di Milano” and received a Master of Science degree in Physics in 1988. He has more than 25 years of experience in the oil&gas industry and more than 15 years of experience in evaluating reserves.
Staff involved in the reserves evaluation process fulfils the professional qualifications requested by the role and complies 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
Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation2 of part of its proved reserves on a rotational basis. 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 2017, Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of approximately 29% of Eni’s total proved reserves at December 31, 20174, confirming, as in previous years, the reasonableness of Eni internal evaluation5.
In the 2015-2017 three-year period, 96% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2017, the main Eni property, which did not undergo an independent evaluation in the last three years, was Blacktip (Australia).
1
See “Item 19 – Exhibits” in the Annual Report on Form 20-F 2009.
2
From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott.
3
See “Item 19 – Exhibits”.
4
Includes Eni’s share of proved reserves of equity-accounted entities.
5
See “Item 19 – Exhibits”.
34

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, 2017, 2016 and 2015. Net proved reserves are set out in more detail under the heading “Supplemental oil and gas information” on page F-142.
HYDROCARBONS
(mmBOE)
Italy
Rest
of
Europe
North
Africa
Egypt
Sub-
Saharan
Africa
Kazakhstan
Rest
of
Asia
Americas
Australia
and
Oceania
Total
reserves
Consolidated subsidiaries1
Year ended Dec. 31, 2017
422​
525​
1,052​
1,078​
1,436​
1,150​
427​
203​
137​
6,430​
developed
350​
360​
532​
463​
856​
891​
238​
176​
101​
3,967​
undeveloped
72​
165​
520​
615​
580​
259​
189​
27​
36​
2,463​
Year ended Dec. 31, 2016
354​
426​
1,139​
1,293​
1,317​
1,221​
491​
227​
145​
6,613​
developed
287​
374​
605​
352​
809​
966​
175​
205​
111​
3,884​
undeveloped
67​
52​
534​
941​
508​
255​
316​
22​
34​
2,729​
Year ended Dec. 31, 2015
465​
495​
1,694​
1,282​
1,198​
422​
269​
150​
5,975​
developed
362​
404​
1,010​
764​
689​
159​
217​
115​
3,720​
undeveloped
103​
91​
684​
518​
509​
263​
52​
35​
2,255​
Equity-accounted entities
Year ended Dec. 31, 2017
14​
75​
1​
470​
560​
developed
14​
20​
1​
359​
394​
undeveloped
55​
111​
166​
Year ended Dec. 31, 2016
14​
82​
2​
779​
877​
developed
14​
26​
2​
349​
391​
undeveloped
56​
430​
486​
Year ended Dec. 31, 2015
14​
87​
4​
810​
915​
developed
14​
22​
2​
265​
303​
undeveloped
65​
2​
545​
612​
Consolidated subsidiaries and equity accounted entities
Year ended Dec. 31, 2017
422​
525​
1,066​
1,078​
1,511​
1,150​
428​
203​
607​
6,990​
developed
350​
360​
546​
463​
876​
891​
239​
176​
460​
4,361​
undeveloped
72​
165​
520​
615​
635​
259​
189​
27​
147​
2,629​
Year ended Dec. 31, 2016
354​
426​
1,153​
1,293​
1,399​
1,221​
493​
1,006​
145​
7,490​
developed
287​
374​
619​
352​
835​
966​
177​
554​
111​
4,275​
undeveloped
67​
52​
534​
941​
564​
255​
316​
452​
34​
3,215​
Year ended Dec. 31, 2015
465​
495​
1,708​
1,369​
1,198​
426​
1,079​
150​
6,890​
developed
362​
404​
1,024​
786​
689​
161​
482​
115​
4,023​
undeveloped
103​
91​
684​
583​
509​
265​
597​
35​
2,867​
(1)
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.
35

LIQUIDS
(mmBBL)
Italy
Rest
of
Europe
North
Africa
Egypt
Sub-
Saharan
Africa
Kazakhstan
Rest
of
Asia
Americas
Australia
and
Oceania
Total
reserves
Consolidated subsidiaries
Year ended Dec. 31, 2017
215​
360​
476​
280​
764​
766​
232​
162​
7​
3,262​
developed
169​
219​
306​
203​
546​
547​
81​
144​
5​
2,220​
undeveloped
46​
141​
170​
77​
218​
219​
151​
18​
2​
1,042​
Year ended Dec. 31, 2016
176​
264​
454​
281​
809​
767​
307​
163​
9​
3,230​
developed
132​
228​
287​
205​
507​
556​
124​
143​
8​
2,190​
undeveloped
44​
36​
167​
76​
302​
211​
183​
20​
1​
1,040​
Year ended Dec. 31, 2015
228​
305​
821​
787​
771​
262​
189​
9​
3,372​
developed
171​
237​
542​
511​
355​
126​
149​
9​
2,100​
undeveloped
57​
68​
279​
276​
416​
136​
40​
1,272​
Equity-accounted entities
Year ended Dec. 31, 2017
12​
12​
136​
160​
developed
12​
6​
25​
43​
undeveloped
6​
111​
117​
Year ended Dec. 31, 2016
13​
15​
140​
168​
developed
13​
8​
22​
43​
undeveloped
7​
118​
125​
Year ended Dec. 31, 2015
13​
16​
158​
187​
developed
13​
6​
29​
48​
undeveloped
10​
129​
139​
Consolidated subsidiaries and equity accounted entities
Year ended Dec. 31, 2017
215​
360​
488​
280​
776​
766​
232​
298​
7​
3,422​
developed
169​
219​
318​
203​
552​
547​
81​
169​
5​
2,263​
undeveloped
46​
141​
170​
77​
224​
219​
151​
129​
2​
1,159​
Year ended Dec. 31, 2016
176​
264​
467​
281​
824​
767​
307​
303​
9​
3,398​
developed
132​
228​
300​
205​
515​
556​
124​
165​
8​
2,233​
undeveloped
44​
36​
167​
76​
309​
211​
183​
138​
1​
1,165​
Year ended Dec. 31, 2015
228​
305​
834​
803​
771​
262​
347​
9​
3,559​
developed
171​
237​
555​
517​
355​
126​
178​
9​
2,148​
undeveloped
57​
68​
279​
286​
416​
136​
169​
1,411​
36

NATURAL GAS
(BCF)
Italy
Rest
of
Europe
North
Africa
Egypt
Sub-
Saharan
Africa
Kazakhstan
Rest
of
Asia
Americas
Australia
and
Oceania
Total
reserves
Consolidated subsidiaries1
Year ended Dec. 31, 2017
1,131​
896​
3,145​
4,351​
3,660​
2,108​
1,065​
225​
709​
17,290​
developed
987​
771​
1,233​
1,421​
1,693​
1,878​
862​
171​
519​
9,535​
undeveloped
144​
125​
1,912​
2,930​
1,967​
230​
203​
54​
190​
7,755​
Year ended Dec. 31, 2016
977​
878​
3,738​
5,520​
2,767​
2,485​
1,003​
353​
741​
18,462​
developed
845​
801​
1,732​
799​
1,651​
2,239​
280​
338​
559​
9,244​
undeveloped
132​
77​
2,006​
4,721​
1,116​
246​
723​
15​
182​
9,218​
Year ended Dec. 31, 2015
1,304​
1,044​
4,798​
2,714​
2,354​
878​
439​
771​
14,302​
developed
1,051​
919​
2,566​
1,390​
1,830​
185​
373​
585​
8,899​
undeveloped
253​
125​
2,232​
1,324​
524​
693​
66​
186​
5,403​
Equity-accounted entities
Year ended Dec. 31, 2017
14​
349​
1,819​
2,182​
developed
14​
83​
1,819​
1,916​
undeveloped
266​
266​
Year ended Dec. 31, 2016
15​
368​
4​
3,484​
3,871​
developed
15​
104​
4​
1,782​
1,905​
undeveloped
264​
1,702​
1,966​
Year ended Dec. 31, 2015
13​
387​
12​
3,581​
3,993​
developed
13​
85​
9​
1,295​
1,402​
undeveloped
302​
3​
2,286​
2,591​
Consolidated subsidiaries and equity accounted entities
Year ended Dec. 31, 2017
1,131​
896​
3,159​
4,351​
4,009​
2,108​
1,065​
2,044​
709​
19,472​
developed
987​
771​
1,247​
1,421​
1,776​
1,878​
862​
1,990​
519​
11,451​
undeveloped
144​
125​
1,912​
2,930​
2,233​
230​
203​
54​
190​
8,021​
Year ended Dec. 31, 2016
977​
878​
3,753​
5,520​
3,135​
2,485​
1,007​
3,837​
741​
22,333​
developed
845​
801​
1,747​
799​
1,755​
2,239​
284​
2,120​
559​
11,149​
undeveloped
132​
77​
2,006​
4,721​
1,380​
246​
723​
1,717​
182​
11,184​
Year ended Dec. 31, 2015
1,304​
1,044​
4,811​
3,101​
2,354​
890​
4,020​
771​
18,295​
developed
1,051​
919​
2,579​
1,475​
1,830​
194​
1,668​
585​
10,301​
undeveloped
253​
125​
2,232​
1,626​
524​
696​
2,352​
186​
7,994​
(1)
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.
37

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 178 mmBOE as of December 31, 2017 (212 and 139 mmBOE as of December 31, 2016 and 2015, respectively). Said volumes are not included in reserves volumes shown in the table herein.
Subsidiaries
Equity-accounted entities
(mmBOE)
2017
2016
2015
2017
2016
2015
Additions to proved reserves
969 1,254 849 (285) (10) 98
Purchases of minerals-in-place
2
Sales of minerals-in-place