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

☑

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017

☐

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

☐

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

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.

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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

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	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.

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	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.

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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.

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	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)

(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.

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Selected Operating Information

The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 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

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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.

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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

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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;

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•

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.

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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:

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

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the actual cost and timing of development and production expenditures;

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the timing and amount of actual production; and

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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:

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

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unfavourable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriation, 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;

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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;

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restrictions on exploration, production, imports and exports;

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tax or royalty increases (including retroactive claims);

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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;

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difficulties in finding qualified suppliers in critical operating environments; and

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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:

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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;

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

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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

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costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging at the end of oil&gas field production.

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:

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modifying operations;

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installing pollution control equipment;

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implementing additional safety measures; and

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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

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:

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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;

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

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

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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:

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

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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:

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

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

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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;

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Developing the green businesses;

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Pursuing margin and growth opportunities through enhanced business integration;

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Financial discipline;

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Increased digitalization to support operations efficiency;

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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:

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The first is to lower CO2 emissions in all our operations

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

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Third, we will keep on developing renewables, and

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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:

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

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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:

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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

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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.

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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.

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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).

See “Item 19 – Exhibits” in the Annual Report on Form 20-F 2009.

From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott.

See “Item 19 – Exhibits”.

Includes Eni’s share of proved reserves of equity-accounted entities.

See “Item 19 – Exhibits”.

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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.

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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

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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.

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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		(523)				(17)
Production for the year(a)		(631)		(616)		(629)		(32)		(28)		(13)

(a)

The difference compared to production sold of 622.3 mmBOE (642.4 mmBOE in 2015 and 608.6 mmBOE in 2016) reflected natural gas volumes of 35.2 mmBOE consumed in operations (26.4 mmBOE in 2015 and 32.1 mmBOE in 2016), changes in inventories and other factors.

	Subsidiaries and equity-accounted entities
(%)	2017		2016		2015
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources		25		193		145
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, organic		103		193		148

Eni’s proved reserves as of December 31, 2017 totaled 6,990 mmBOE (liquids 3,422 mmBBL; natural gas 19,472 BCF). Eni’s proved reserves reported a decrease of 500 mmBOE, or 6.7%, from December 31, 2016 due to production for the year, the disposal of a 40% interest in the Zohr gas field and of a 25% interest in the Coral discovery in Mozambique which obtained the FID in the year and the reclassification of 315 mmBOE of proved undeveloped reserves at the Perla gas project in Venezuela to the unproved category in accordance with the applicable US SEC regulation. These decreases were partly offset by the activity of the year. All sources additions to proved reserves booked in 2017 were 163 mmBOE; of which 448 mmBOE came from Eni’s subsidiaries, while Eni’s equity-accounted entities reported a negative revision due to the reserves reclassification in Venezuela described above.

Price effects were negligible, leading to a downward revision of 7 mmBOE, due to an increased Brent price used in the reserves estimation process up to 54.4 $/BBL in 2017 compared to 42.8 $/BBL in 2016. Further information about how to determine year-end amounts of proved reserves and the relevant net present value is provided in “Item 3 – Risk factors – Risks associated with the exploration and production of oil and natural gas”.

The methods (or technologies) used in the Eni’s proved reserves assessment in 2017 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modelling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that produce consistent and repeatable results including well or field measurements (i.e. logs, core samples, pressure information, fluid samples, production test data and performance data) and indirect measurements (i.e. seismic data). However for each reservoir assessment the most suitable combination of technologies and methods is applied providing a high degree of confidence in establishing reliable reserves estimates.

The all sources reserves replacement ratio achieved by Eni’s subsidiaries and equity-accounted entities was 25% in 2017 (193% in 2016 and 145% in 2015) due to the Zohr and Mozambique disposals as well as the reclassification of PUD in Venezuela. The organic reserves replacement ratio was 103% (193% in 2016 and 148% in 2015) when excluding sales and purchases of minerals-in-place. The ratio increased to 151% when excluding the reclassification of PUD in Venezuela.

The all sources reserves replacement ratio was calculated by dividing additions to proved reserves including sales and purchases of mineral-in-place by total production, each as derived from the tables of

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changes in proved reserves prepared in accordance with FASB Extractive Activities – Oil & Gas (Topic 932) (see the supplemental oil and gas information in “Item 18 – Consolidated Financial Statements”). The reserves replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by booked reserves total additions. Management considers the reserve replacement ratio to be an important indicator of the Company’s ability to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructures, reservoir performance, application of new technologies to improve the recovery factor as well as changes in oil&gas prices, political risks and geological and environmental risks. See “Item 3 – Risks associated with the exploration and production of oil and natural gas –Uncertainties in estimates of oil and natural gas reserves”.

The average reserves life index of Eni’s proved reserves was 10.5 years as of December 31, 2017, which included reserves of both subsidiaries and equity-accounted entities.

Eni’s subsidiaries

Eni’s subsidiaries added 448 mmBOE of proved oil&gas reserves in 2017 net of sales and purchase of minerals-in-place. This comprised 336 mmBBL of liquids and 611 BCF of natural gas. The breakdown of additions to proved reserves is the following: (i) extensions and discoveries were up by 483 mmBOE mainly due to the final investment decisions made for the Coral project offshore Mozambique and the Johan Castberg project offshore Norway; (ii) revisions of previous estimates were up by 466 mmBOE and mainly derived from progress in development activities at the number of projects including Zohr in Egypt, Jangkrik in Indonesia and Kashagan in Kazakhstan; (iii) improved recovery were 20 mmBOE mainly reported in Iraq and Egypt; (iv) purchases of mineral-in-place referred to certain assets in Nigeria; and (v) sales of minerals-in-place referred to the disposal of a 25% interest in natural gas-rich Area 4 offshore Mozambique and the divestment of a 40% stake in the Zohr gas field offshore in Egypt. Further information is provided in “Oil and gas properties, operations and acreage” in Eni’s principal oil and gas activities described in Mozambique and Egypt, respectively.

Eni’s share of equity-accounted entities

Additions in Eni’s share of equity-accounted entities’ proved oil&gas were negative in 2017 and derived mainly from the reclassification of 315 mmBOE of proved undeveloped reserves at the Perla gas project in Venezuela to the unproved category in accordance with the applicable US SEC regulation.

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2017 totaled 2,629 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,159 mmBBL, mainly concentrated in Africa and Asia. Proved undeveloped reserves of natural gas amounted to 8,021 BCF, mainly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,042 mmBBL of liquids and 7,755 BCF of natural gas. The table below provide a summary of changes in total proved undeveloped reserves for 2017.

(mmBOE)	Subsidiaries and equity-accounted entities
Proved undeveloped reserves as of December 31, 2016		3,215
Reclassification to proved developed reserves		(489)
Reclassification of the Perla Phase 2 project reserves		(315)
Extensions and discoveries		483
Revisions of previous estimates		240
Improved recovery		18
Sales of minerals-in-place		(523)
Proved undeveloped reserves as of December 31, 2017		2,629

In 2017, total proved undeveloped reserves decreased by 586 mmBOE mainly due to: (i) progress in maturing PUD to proved developed (489 mmBOE); (ii) extensions and discoveries (up by 483 mmBOE) due to the final investment decision made for the Coral project offshore Mozambique and the Johan Castberg project offshore Norway; (iii) reclassification of 315 mmBOE of proved undeveloped reserves at the Perla gas project in Venezuela to the unproved category in accordance with the applicable US SEC

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regulation; (iv) revisions of previous estimates (up by 240 mmBOE) mainly reported in Egypt due to the development activity of the Zohr project; (v) improved recovery (up 18 mmBOE) in particular in Iraq and Egypt; and (vi) divestments (down by 523 mmBOE) related to the disposals of interests in properties in Mozambique and Egypt, as above-mentioned.

During 2017, Eni converted 489 mmBOE of proved undeveloped reserves to proved developed reserves due to the progress of the development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves are related to the following fields/projects: Zohr (Egypt), Jangkrik (Indonesia); Cabaca South East (Angola), Sankofa (Ghana) and Nené (Congo).

In 2017, capital expenditures amounted to approximately €7.1 billion and was made to progress the development of proved undeveloped reserves.

Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The Company estimates that approximately 1 BBOE of proved undeveloped reserves have remained undeveloped for five years or more at the balance sheet date, mainly related to: (i) the Kashagan project in Kazakhstan (0.2 BBOE), related to forthcoming development phases (for further information see “Item 4 – Oil and gas properties, operations and acreage – Kashagan”); (ii) the Zubair field in Iraq (0.2 BBOE). Zubair is an infrastructure-driven large-scale project, where development of PUDs has been conditioned by the completion of such infrastructures. The large part of the planned expenditures for such project has already been made by Eni and the installation of the production facilities required to achieve and maintain the full field production plateau of 700 KBBL/d is almost complete. Eni’s planned activities contemplate the drilling of additional production and injection wells to be linked to the facilities currently in place; (iii) the Junin 5 field in Venezuela (0.1 BBOE) where the development scheme is planned through execution of several optimization activities with low technical complexity; and (iv) certain Libyan gas fields (0.5 BBOE) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force. In order to secure fulfillment of the contractual delivery quantities, Eni will implement phased production start-up from the relevant fields which are expected to be put in production over the next several years. (See also our discussion under the “Risk factors” section about risks associated with oil and gas development projects).

Eni remains strongly committed to put these projects into production over the next few years. The length of the development period depends on a range of external factors, such as for example the type of development, the location and physical operating environment of the field or the absence of infrastructure, considering that the majority of our projects are infrastructure-driven, and not a function of internal factors, such as an insufficient devotion of resources by Eni or a diminished commitment on the part of Eni to complete the project.

Delivery commitments

Eni, through consolidated subsidiaries and equity-accounted entities, sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Some of these contracts, mostly relating to natural gas, specify the delivery of fixed and determinable quantities.

Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 534 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Indonesia, Libya, Nigeria, Norway and Venezuela.

The sales contracts contain a mix of fixed and variable pricing formulas that are generally indexed to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available from production of the Company’s proved developed reserves and supplies from third parties based on existing contracts. Production is expected to account for approximately 88% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, 2017.

Oil and gas production, production prices and production costs

The matters regarding future production, additions to reserves and related production costs and estimated reserves discussed below and elsewhere herein are forward-looking statements that involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking

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statements. Such risks and uncertainties relating to future production and additions to reserves include political developments affecting the award of exploration or production interests or world supply and prices for oil and natural gas, or changes in the underlying economics of certain of Eni’s important hydrocarbons projects. Such risks and uncertainties relating to future production costs include delays or unexpected costs incurred in Eni’s production operations.

In 2017, oil and natural gas production available for sale averaged 1,719 KBOE/d (1,671 KBOE/d in 2016) and increased by 2.9% from 2016, mainly due to new project start-ups and the ramp-ups at fields started up in 2016, mainly in Angola, Egypt, Ghana, Indonesia and Kazakhstan as well as by the restart of certain Libyan fields due to better safety conditions. These positive results were partly offset by OPEC production cuts, negative price effects at PSAs contracts and lower production as a result of planned and unplanned shutdowns in Norway, the United Kingdom and the Gulf of Mexico, as well as mature field declines. New field start-ups and ramp-ups of production added an estimated 243 KBOE/d of new production.

Liquids production (852 KBBL/d) decreased by 26 KBBL/d, or 3% from the full year of 2016. Price effect, OPEC cuts and shutdowns in Norway, the United Kingdom and the Gulf of Mexico were partly offset by start-ups and ramp-ups of the year mainly in Angola, Ghana and Kazakhstan as well as higher production in Libya.

Natural gas production (4,734 mmCF/d) increased by 405 mmCF/d, or 9.4% compared to the full year of 2016. Start-ups and ramp-ups of producing assets in Indonesia and Egypt and the increasing production in Libya were partly offset by shutdowns, mature fields decline and price effect.

Oil and gas production sold amounted to 622.3 mmBOE. The 4.7 mmBOE difference over production on available-for-sale basis (627 mmBOE in 2017) reflected mainly changes in inventory and other factors. Approximately 70% of liquids production sold (308.3 mmBBL) was destined to Eni’s mid-downstream sectors. About 20% of natural gas production sold (1,713 BCF) was destined to Eni’s Gas & Power segment.

The tables below provide Eni subsidiaries and its equity-accounted entities’ production (annual volumes and daily averages), by final product marketed of liquids and natural gas by geographical area of each of the last three fiscal years.

2017 Production available for sale (a)		Italy	Rest of Europe	North Africa	Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania
Hydrocarbons production
Eni consolidated subsidiaries	(KBOE/d)	127	183	457	216	305	126	105	96	21	1,636
	(mmBOE)	46	67	167	79	111	46	38	35	8	597
Eni share of equity-accounted entities	(KBOE/d)			3		17		2	61		83
	(mmBOE)			1		6		1	22		30
Liquids production
Eni consolidated subsidiaries	(KBBL/d)	53	102	159	72	246	83	53	63	2	833
	(mmBBL)	19	37	58	26	90	30	20	23	1	304
Eni share of equity-accounted entities	(KBBL/d)			3		3		1	12		19
	(mmBBL)			1		2			4		7
Natural gas production
Eni consolidated subsidiaries	(mmCF/d)	402	443	1,632	784	328	231	282	181	101	4,384
	(BCF)	147	162	596	286	119	84	103	66	37	1,600
Eni share of equity-accounted entities	(mmCF/d)			2		72		9	267		350
	(BCF)			1		27		3	97		128

(a)

It excludes production volumes of natural gas consumed in operations. Said volumes were 527 mmCF/d or 35.2 mmBOE.

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2016 Production available for sale (a)		Italy	Rest of Europe	North Africa	Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania
Hydrocarbons production
Eni consolidated subsidiaries	(KBOE/d)	127	195	438	170	312	107	114	114	23	1,600
	(mmBOE)	47	71	160	62	114	39	42	42	8	585
Eni share of equity-accounted entities	(KBOE/d)			3		4		4	60		71
	(mmBOE)			1		2		2	22		27
Liquids production
Eni consolidated subsidiaries	(KBBL/d)	47	109	165	76	247	65	78	69	3	859
	(mmBBL)	17	40	60	28	91	24	28	25	1	314
Eni share of equity-accounted entities	(KBBL/d)			3		1		1	14		19
	(mmBBL)			1				1	5		7
Natural gas production
Eni consolidated subsidiaries	(mmCF/d)	436	468	1,486	514	353	234	199	243	110	4,043
	(BCF)	159	171	544	188	129	86	73	89	40	1,479
Eni share of equity-accounted entities	(mmCF/d)			3		16		15	252		286
	(BCF)			1		6		6	92		105

(a)

It excludes production volumes of natural gas consumed in operations. Said volumes were 478 mmCF/d or 32.1 mmBOE.

2015 Production available for sale (a)		Italy	Rest of Europe	North Africa	Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania
Hydrocarbons production
Eni consolidated subsidiaries	(KBOE/d)	161	179	631		324	92	123	120	25	1,655
	(mmBOE)	59	65	230		119	33	45	44	9	604
Eni share of equity-accounted entities	(KBOE/d)			4				5	24		33
	(mmBOE)			1				2	9		12
Liquids production
Eni consolidated subsidiaries	(KBBL/d)	69	85	268		256	56	77	75	5	891
	(mmBBL)	25	31	98		93	20	28	28	2	325
Eni share of equity-accounted entities	(KBBL/d)			4				1	12		17
	(mmBBL)			1				1	4		6
Natural gas production
Eni consolidated subsidiaries	(mmCF/d)	503	515	1,990		378	199	259	243	107	4,194
	(BCF)	183	188	727		138	73	94	89	39	1,531
Eni share of equity-accounted entities	(mmCF/d)			3				19	68		90
	(BCF)			1				7	25		33

(a)

It excludes production volumes of natural gas consumed in operations. Said volumes were 397 mmCF/d or 26.4 mmBOE.

Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 55 KBOE/d, 56 KBOE/d and 84 KBOE/d in 2017, 2016 and 2015, respectively.

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The tables below provide Eni subsidiaries and its equity-accounted entities’ average sales prices per unit of liquids and natural gas by geographical area for each of the last three fiscal years. Also Eni subsidiaries and its equity-accounted entities’ average production cost per unit of production are provided. The average production cost does not include any ad valorem or severance taxes.

AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTION

($)	Italy	Rest of Europe	North Africa	Egypt	Sub- Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2015
Consolidated subsidiaries
Oil and condensates, per BBL	43.46	45.88	46.66		49.91	48.26	40.10	43.36	45.84	46.46
Natural gas, per KCF	6.92	6.30	4.69		1.49	0.47	4.83	2.20	5.07	4.54
Average production cost, per BOE	11.08	10.93	5.72		14.08	7.93	6.48	11.61	14.49	9.18
Equity-accounted entities
Oil and condensates, per BBL			18.03				27.89	38.18		35.15
Natural gas, per KCF			3.78				9.27	4.24		5.30
Average production cost, per BOE			8.98				8.67	16.48		14.51
2016
Consolidated subsidiaries
Oil and condensates, per BBL	33.19	39.97	42.37	33.05	41.92	39.61	36.89	34.86	37.96	39.33
Natural gas, per KCF	4.93	4.49	3.10	3.82	1.41	0.34	3.50	1.94	3.60	3.20
Average production cost, per BOE	9.69	9.31	4.33	6.34	12.09	7.58	6.14	8.70	7.08	7.79
Equity-accounted entities
Oil and condensates, per BBL			17.93				34.95	32.39		30.85
Natural gas, per KCF			1.85				5.92	4.17		4.25
Average production cost, per BOE			9.74				8.19	8.81		8.34
2017
Consolidated subsidiaries
Oil and condensates, per BBL	46.51	47.81	52.68	46.06	53.66	50.62	48.94	44.24	49.36	50.33
Natural gas, per KCF	6.45	5.81	2.96	4.19	1.87	0.58	3.75	2.35	4.05	3.62
Average production cost, per BOE	11.43	11.62	4.76	4.51	13.34	9.78	6.39	10.10	7.77	8.45
Equity-accounted entities
Oil and condensates, per BBL			45.39		38.34		44.43	41.49		38.65
Natural gas, per KCF			2.63		7.34		6.06	4.19		4.64
Average production cost, per BOE			10.30		8.05		11.64	9.52		9.31

Development activities

In 2017, a total of 178 development wells were drilled (90.7 of which represented Eni’s share) as compared to 296 development wells drilled in 2016 (118.7 of which represented Eni’s share) and 335 development wells drilled in 2015 (132.4 of which represented Eni’s share).

The decrease in the number of development wells year-on-year reflects the finalization of certain large projects in 2016, which started production in 2017.

The drilling of 49 development wells (22.9 of which represented Eni’s share) is currently underway.

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The table below summarizes the number of the Company’s net interest in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 2017. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Development Well Activity

	Net wells completed						Wells in progress at 31 Dec.
	2017		2016		2015		2017
(units)	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy	2.6		4.0		6.0		1.0	1.0
Rest of Europe	2.7	0.2	5.6		10.2	0.1	5.0	0.8
North Africa	5.1		6.2	0.7	30.5	2.8	10.0	5.5
Egypt	49.7	2.3	32.4	0.5			10.0	5.4
Sub-Saharan Africa	8.6		21.2	0.2	22.0	2.5	21.0	9.6
Kazakhstan	1.2		4.6		4.7		2.0	0.6
Rest of Asia	15.0	0.2	31.6	0.5	29.7	5.9
Americas	3.1		9.9	1.3	17.4	0.1
Australia and Oceania					0.5
Total including equity-accounted entities	88.0	2.7	115.5	3.2	121.0	11.4	49.0	22.9

Exploration activities

In 2017, a total of 25 new exploratory wells were drilled (15.9 of which represented Eni’s share), as compared to 16 exploratory wells drilled in 2016 (10.2 of which represented Eni’s share) and 29 exploratory wells drilled in 2015 (19.1 of which represented Eni’s share).

The overall commercial success rate was 60% (52% net to Eni) as compared to 50% (50% net to Eni) and 16.7% (25.1% net to Eni) in 2016 and 2015, respectively.

The following table summarizes the Company’s net interests in productive and dry exploratory wells completed in each of the last three fiscal years and the number of exploratory wells in the process of being drilled and evaluated as of December 31, 2017. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

	Net wells completed						Wells in progress at Dec. 31(1)
	2017		2016		2015		2017
(units)	Productive	Dry	Productive	Dry	Productive	Dry	Gross	Net
Italy				1.0			4.0	2.3
Rest of Europe	1.2	1.3	0.1	0.4		2.2	9.0	2.5
North Africa	0.5		0.5	1.0	3.3	5.8	7.0	6.5
Egypt	2.5	5.4	5.5	0.8			7.0	4.9
Sub-Saharan Africa	2.9	0.3	0.1	1.1	0.6	2.9	28.0	14.1
Kazakhstan							6.0	1.1
Rest of Asia				0.9		3.4	11.0	5.0
Americas	0.5			1.0	1.0	0.3	5.0	4.5
Australia and Oceania							1.0	0.3
Total including equity-accounted entities	7.6	7.0	6.2	6.2	4.9	14.6	78.0	41.2

(1)

Includes temporary suspended wells pending further evaluation.

Oil and gas properties, operations and acreage

In 2017, Eni performed its operations in 46 countries located in five continents. As of December 31, 2017, Eni’s mineral right portfolio consisted of 756 exclusive or shared rights of exploration and development activities for a total acreage of 414,918 square kilometers net to Eni (323,896 square kilometers net to Eni as of December 31, 2016). Developed acreage was 31,038 square kilometers and undeveloped acreage was 383,880 square kilometers net to Eni.

In 2017, changes in total net acreage mainly derived from: (i) new leases mainly in Cyprus, Ivory Coast, Kazakhstan, Morocco, Mexico and Oman for a total acreage of approximately 97,200 square kilometers; (ii) the total relinquishment of licences mainly in Kenya, Pakistan, Ukraine, Norway, the

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United Kingdom, Egypt and the United States covering an acreage of approximately 6,700 square kilometers; (iii) interest increase mainly in Kenya and Australia for a total acreage of approximately 6,800 square kilometers; (iv) partial relinquishment in Indonesia, Gabon, Egypt and Pakistan or interest reduction mainly in Mozambique and Egypt for approximately 6,300 square kilometers.

The table below provides certain information about the Company’s oil&gas properties. It provides the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2017. A gross acreage is one in which Eni owns a working interest.

	December 31, 2016	December 31, 2017
	Total net acreage (a)	Number of interests	Gross developed acreage (a) (b)	Gross undeveloped acreage (a)	Total gross acreage (a)	Net developed acreage (a) (b)	Net undeveloped acreage (a)	Total net acreage (a)
EUROPE	45,380	280	15,232	59,373	74,605	10,414	40,792	51,206
Italy	16,767	144	10,011	10,321	20,332	8,351	8,029	16,380
Rest of Europe	28,613	136	5,221	49,052	54,273	2,063	32,763	34,826
Cyprus	10,018	6		23,858	23,858		17,967	17,967
Croatia	987	2	1,975		1,975	987		987
Greenland	1,909	2		4,890	4,890		1,909	1,909
Montenegro	614	1		1,228	1,228		614	614
Norway	2,608	54	2,337	4,403	6,740	462	1,655	2,117
Portugal	3,182	3		4,547	4,547		3,182	3,182
United Kingdom	6,328	60	909	5,298	6,207	614	5,191	5,805
Other Countries	2,967	8		4,828	4,828		2,245	2,245
AFRICA	152,676	264	46,319	260,611	306,930	11,723	150,258	161,981
North Africa	18,727	65	8,735	38,707	47,442	3,626	22,171	25,797
Algeria	1,179	42	3,172	187	3,359	1,110	31	1,141
Libya	13,294	11	1,963	24,673	26,636	958	12,336	13,294
Morocco	2,696	2		13,847	13,847		9,804	9,804
Tunisia	1,558	10	3,600		3,600	1,558		1,558
Egypt	10,665	54	5,692	19,683	25,375	2,131	7,061	9,192
Sub-Saharan Africa	123,284	145	31,892	202,221	234,113	5,966	121,026	126,992
Angola	4,367	58	8,098	12,953	21,051	1,027	3,340	4,367
Congo	1,168	25	1,430	1,320	2,750	843	628	1,471
Gabon	6,217	4		5,283	5,283		5,283	5,283
Ghana	579	3	226	1,127	1,353	100	479	579
Ivory Coast	286	3		4,010	4,010		2,905	2,905
Kenya	41,173	6		50,677	50,677		43,948	43,948
Liberia	585	1		2,341	2,341		585	585
Mozambique	1,956	6		3,911	3,911		978	978
Nigeria	7,370	34	22,138	8,631	30,769	3,996	3,374	7,370
South Africa	26,279	1		65,505	65,505		26,202	26,202
Other Countries	33,304	4		46,463	46,463		33,304	33,304
ASIA	109,761	60	14,560	286,866	301,426	5,058	178,971	184,029
Kazakhstan	869	7	2,391	3,890	6,281	442	1,101	1,543
Rest of Asia	108,892	53	12,169	282,976	295,145	4,616	177,870	182,486
China	7,069	8	77	7,141	7,218	13	7,141	7,154
India	5,244	1		13,110	13,110		5,244	5,244
Indonesia	25,181	14	4,949	26,892	31,841	1,990	20,899	22,889
Iraq	446	1	1,074		1,074	446		446
Myanmar	13,558	4		24,080	24,080		13,558	13,558
Oman		1		90,760	90,760		77,146	77,146
Pakistan	8,746	13	5,869	11,486	17,355	1,987	5,414	7,401
Russia	20,862	3		62,592	62,592		20,862	20,862
Timor Leste	1,230	1		1,538	1,538		1,230	1,230
Turkmenistan	180	1	200		200	180		180
Vietnam	23,132	5		30,777	30,777		23,132	23,132
Other Countries	3,244	1		14,600	14,600		3,244	3,244
AMERICAS	5,696	139	4,854	9,626	14,480	3,134	3,507	6,641
Ecuador	1,985	1	1,985		1,985	1,985		1,985
Mexico	67	6		1,657	1,657		1,146	1,146
Trinidad & Tobago	66	1	382		382	66		66
United States	1,186	117	1,226	879	2,105	586	466	1,052
Venezuela	1,066	6	1,261	1,543	2,804	497	569	1,066
Other Countries	1,326	8		5,547	5,547		1,326	1,326
AUSTRALIA AND OCEANIA	10,383	13	1,140	15,567	16,707	709	10,352	11,061
Australia	10,383	13	1,140	15,567	16,707	709	10,352	11,061
Total	323,896	756	82,105	632,043	714,148	31,038	383,880	414,918

(a)

Square kilometers.

(b)

Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves.

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The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had an interest as of December 31, 2017. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same borehole are counted as one well. Productive wells are producing wells and wells capable of production. The total number of oil and natural gas productive wells is 9,147 (3,725.5 of which represent Eni’s share).

Productive oil and gas wells at Dec. 31, 2017(a)

(units)	Oil Wells				Natural gas Wells
	Gross		Net		Gross		Net
Italy		231.0		184.7		573.0		495.7
Rest of Europe		378.0		65.0		177.0		92.2
North Africa		687.0		284.5		90.0		48.9
Egypt		1,186.0		729.4		139.0		46.8
Sub-Saharan Africa		2,786.0		585.7		330.0		29.1
Kazakhstan		205.0		55.6
Rest of Asia		739.0		477.5		1,032.0		402.0
Americas		273.0		134.1		296.0		86.7
Australia and Oceania		7.0		3.8		18.0		3.8
Total including equity-accounted entities		6,492.0		2,520.3		2,655.0		1,205.2

(a)

Multiple completion wells included above: approximately 1,960 (716.2 net to Eni).

Eni’s principal oil and gas properties are described below. In the discussion that follows, references to hydrocarbon production are intended to represent hydrocarbon production available for sale.

Italy

Eni has been operating in Italy since 1926. In 2017, Eni’s oil and gas production amounted to 127 KBOE/d. Eni’s activities in Italy are deployed in the Adriatic and Ionian Seas, the Central Southern Apennines, mainland and offshore Sicily and the Po Valley. Eni’s exploration and development activities in Italy are regulated by concession contracts (50 operated onshore and 62 operated offshore) and exploration licenses (13 onshore and 9 offshore).

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[MISSING IMAGE: tv485407_map-italysouth.jpg]

The Adriatic and Ionian Sea represents Eni’s main production area, accounting for 48% of Eni’s domestic production in 2017. Main operated fields are Barbara, Cervia/Arianna, Annamaria, Luna, Angela, Hera Lacinia and Bonaccia. Development activities in the Adriatic offshore concerned maintenance and production optimization, mainly at the Barbara and Porto Garibaldi-Agostino fields.

Eni is the operator of the Val d’Agri concession (Eni’s interest 60.77%) in the Basilicata Region in Southern Italy. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields, which accounts for 38% of Eni’s domestic production, is treated by the Val d’Agri oil center (“COVA”).

On April 18, 2017, Eni, before receiving a request by the Italian Authorities to halt operations, decided to shut-down the COVA due to the detection of an oil spill in the area adjoining the plant. Management promptly executed all requested remedial measures. On July 18 2017, Eni restarted operations at the COVA following approvals of the relevant Authorities that tested the functionality of the plant and the presence of all necessary environmental and safety conditions. Further information on this matter is provided Item 19 – consolidated financial statement – footnote 38-Legal proceedings”.

Eni operates 12 production concessions onshore and 3 offshore in Sicily. The main fields are Gela, Tresauro, Giaurone, Fiumetto, Prezioso and Bronte, which in 2017 accounted for approximately 8% of Eni’s production in Italy.

Rest of Europe

Eni’s operations in the Rest of Europe are mainly conducted in Croatia, Norway and the UK. In 2017, the Rest of Europe accounted for 11% of Eni’s total worldwide production of oil and natural gas.

Croatia. Eni has been present in Croatia since 1996. In 2017, Eni’s production of natural gas averaged approximately 16 mmCF/d. Activities are deployed in the Adriatic Sea near the city of Pula.

Exploration and production activities in Croatia are regulated by PSAs.

The main producing gas fields are Annamaria, Ivana, Ika & Ida, Ika JZ, Ana, Marica and Katarina and are operated by Eni through a 50/50 joint operating company with the Croatian oil company INA.

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Norway. Eni has been operating in Norway since 1965. Eni’s activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 126 KBOE/d in 2017.

Exploration and production activities in Norway are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a given number of years with possible extensions.

Eni currently holds interests in 10 production areas in the Norwegian Sea. The principal producing fields are Åsgard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.17%), Mikkel (Eni’s interest 14.9%), Tyrihans (Eni’s interest 6.2%), Marulk (Eni operator with a 20% interest) and Morvin (Eni’s interest 30%) which in 2017 accounted for 57% of Eni’s production in Norway.

Eni holds interests in 2 production licenses in the Norwegian section of the North Sea. The main producing properties is the Great Ekofisk Area (Eni’s interest 12.39%) in PL 018, which includes the Ekofisk field and the Eldfisk and Embla satellites fields. In 2017, the Great Ekofisk Area produced approximately 23 KBOE/d net to Eni and accounted for approximately 18% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension.

Eni holds interests in 13 exploration and development licences in the Barents Sea, of which Eni operates 8 licences. Operations have been focused on the Goliat production fields in PL 229 (Eni operator with a 65% interest). In 2017, Goliat produced 28 KBOE/d or 22% of Eni’s production in Norway. The license expires in 2042.

Development activities mainly concerned: (i) the drilling and production start-up of two new injection wells and an additional production well of the Goliat field; and (ii) infilling activities to support production of the Ekofisk, Eldfisk, Heidrun, Asgard and Norne (Eni’s interest 6.9%) fields.

The final investment decision of the Johan Castberg field (Eni’s interest 30%) was sanctioned. The project is located in the Barents Sea and start-up is expected in 2022.

Exploration activities yielded positive results with: (i) the Cape Vulture oil and gas discovery in the PL128/128D license (Eni’s interest 11.5%) in the Norwegian Sea, nearby to the production facilities of the Norne field; and (ii) the Kayak oil discovery in the PL532 license (Eni’s interest 30%) in the Barents Sea. The well is located nearby to the Johan Castberg developing project in the area.

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United Kingdom. Eni has been present in the UK since 1964. Eni’s activities are carried out in the British section of the North Sea and the Irish Sea. In 2017, Eni’s net production of oil and gas averaged 54 KBOE/d. Exploration and production activities in the UK are regulated by concession contracts.

Eni currently holds interests in 4 production areas of which the Liverpool Bay is operated by Eni with a 100% interest and Hewett Area is operated with an 89.3% interest. The other non-operated fields are Elgin/Franklin (Eni’s interest 21.87%), Glenelg (Eni’s interest 8%), J Block and Jasmine (Eni’s interest 33%) as well as Jade (Eni’s interest 7%).

Eni holds interest in 14 exploration licences of which Eni operates 10 licenses, with interest ranging from 9% to 100%.

North Africa

Eni’s operations in North Africa are conducted in Algeria, Libya, Morocco and Tunisia. In 2017, North Africa accounted for 27% of Eni’s total worldwide production of oil and natural gas.

Algeria. Eni has been present in Algeria since 1981. In 2017, Eni’s oil&gas production averaged 75 KBOE/d.

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Operated activities are located in the Bir Rebaa desert, in the Central-Eastern area of the country: (i) blocks 403a/d (Eni’s interest from 65% to 100%); (ii) block ROM North (Eni’s interest 35%); (iii) blocks 401a/402a (Eni’s interest 55%); (iv) block 403 (Eni’s interest 50%); (v) block 405b (Eni’s interest 75%); and (vi) block 212 (Eni’s interest 22.38%) with discoveries already made. In addition, Eni holds interest in the non-operated block 404 and block 208 with a 12.25% stake.

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

Production in blocks 403a/d and ROM North comes mainly from the HBN and ROM and satellites fields and represented approximately 21% of Eni’s production in Algeria in 2017.

Production in blocks 401a/402a comes mainly from the ROD/SFNE and satellites fields and accounted for approximately 17% of Eni’s production in Algeria in 2017.

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The main fields in block 403 are BRN, BRW and BRSW, which accounted for approximately 9% of Eni’s production in Algeria in 2017. In June 2017, Eni signed with the relevant Authorities a 15-year extension agreement of the Block 403 fields, with a possible further 10-year extension. The agreement received all the necessary authorizations required by the country.

The main fields in block 404 are HBN and HBNS and satellites, which accounted for approximately 22% of Eni’s production in Algeria in 2017.

Production in block 405b comes mainly from MLE and CAFC projects and accounted for approximately 15% of Eni’s production in the country.

The El-Merk field is the main production project in the Block 208 and accounted for approximately 16% of Eni’s production in Algeria in 2017.

Development activities concerned: (i) infilling activities and production optimization at the Zea field in the Block 403 a/d and at the ROD and SF/SFNE fields in the Blocks 401a/402a; (ii) workover activities at the BRN, BRW and RSW fields in the Block 403 and HBNS, HBNN and Ourhoud fields in the Block 404; (iii) in the Block 405b the completion of the treatment plant with a capacity of 32 KBBL/d of the CAFC oil project, the ongoing drilling planned activities in the area as well as infilling activities at the MLE project; and (iv) the ongoing development activities of the El Merk field in the Block 208 with the drilling of production and water injection wells.

In December 2017, Eni and Sonatrach the state oil company signed a Memorandum of Understanding for the development project in the renewables sector. The agreement includes the feasibility studies to build solar power production units in the selected production areas operated by the state company.

Libya. Eni started operations in Libya in 1959.

In recent years, Eni’s production levels in Libya were negatively impacted by the country’s political instability. More recently, Eni’s oil activities in the country have improved, 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. Despite this and other positive developments, Libya’s geopolitical situation continues to represent a source of risk and uncertainty for the foreseeable future. For further information on this matter, see “Item 3 – Risk factors-Political considerations”

Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area and includes six contract areas. Onshore contract areas are: (i) Area A consisting in the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 Block (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); (iv) Area F with Block 118 (Eni’s interest 50%) and (v) Area D with Block NC 169 that feeds the Western Libyan Gas Project (Eni’s interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Eni’s interest 50%); and (ii) Area D with Block NC 41 that feeds the Western Libyan Gas Project.

In the exploration phase, Eni is operator in the onshore contract Areas A, B and offshore Area D.

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Exploration and production activities in Libya are regulated by six Exploration and Production Sharing Agreement contracts (EPSA). The licenses of Eni’s assets in Libya expire in 2042 and 2047 for oil&gas properties, respectively.

Development activities concerned: (i) the installation, commissioning and production start-up of a new FSO at the Bouri field; (ii) the second development phase of the Bahr Essalam field (Eni’s interest 50%) with the installation of the offshore facilities and the completion of wells. The development plan foresees drilling and completion of ten production wells. Start-up is expected in 2018; and (iii) the drilling and linkage of two additional production wells at the Wafa field (Eni’s interest 50%). The upgrading activities of the compression capacity of Wafa plant progressed to support natural gas production. Start-up is expected in 2018.

Exploration activity yielded positive results with a new gas and condensates discovery in the contractual area D. The discovery is located nearby to the Bouri and Bahr Essalam production fields. In April 2017, the Country’s authorities extended the exploration license period until 2019, without additional commitment activities.

Management expect to reduce the Company’s exposure to Libya over the plan period as a result of the slowdown in exploration and development activities in recent years due to an uncertain political outlook.

Morocco. In December 2017, Eni signed a Petroleum Agreement with the Moroccan State Company ONHYM that includes the operatorship to Eni and a 75% stake enter into Tarfaya Offshore Shallow exploration permits I-XII, located in the Atlantic Ocean offshore. The agreement is subject to approval by the relevant Authorities of the country.

In June 2017, Eni signed an agreement with the ONHYM Company for exploration activities in the El Jadida Offshore area.

Eni also operates with a 40% interest the Rabat Deep Offshore exploration permits I-VI offshore, following a Farm-Out Agreement (FOA) with Chariot Oil & Gas defined in 2016.

Tunisia. Eni has been present in Tunisia since 1961. In 2017, Eni’s production amounted to 8 KBOE/d.

Eni’s activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet.

Exploration and production in this country are regulated by concessions.

Production mainly comes from operated Maamoura and Baraka offshore blocks (Eni’s interest 49%) and the Adam (Eni operator with a 25% interest), Oued Zar (Eni operator with a 50% interest), Djebel Grouz (Eni operator with a 50% interest), MLD (Eni’s interest 50%) and El Borma (Eni’s interest 50%) onshore blocks.

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Egypt

Eni has been present in Egypt since 1954. Exploration and production activities in Egypt are regulated by Production Sharing Agreements.

In 2017, Eni’s share of production in this country amounted to 216 KBOE/d and accounted for 13% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Gulf of Suez, primarily the Belayim field (Eni’s interest 100%), and in the Western Desert mainly the Melehia (Eni’s interest 76%), the Ras Qattara (Eni’s interest 75%), Raml (Eni’s interest 45%) and West Razzaq and Kanayis (Eni’s interest 100%) concessions. Gas production mainly comes from the operated or participated concession of North Port Said (Eni’s interest 100%), El Temsah (Eni’s interest 50%), Baltim (Eni’s interest 50%), Ras el Barr (Eni’s interest 50%, non-operated) and the Nile Delta (Eni’s interest 75%), located offshore the Nile Delta. In 2017, production from these large concessions accounted for approximately 95% of Eni’s production in Egypt.

Eni operates the Shoruk concession (Eni’s interest 60%) where the Zohr gas field is located. Management believes that this field contains a large amount of gas reserves. The concession expires in 2037. Production at the field started at the end of 2017.

In 2017, Eni closed two agreements with major international players in the oil&gas business for the disposal of a 40% interest in the Zohr field, as part of its dual exploration model that targets early monetization of the reserves discovered through organic exploration in areas with high working interest. The agreements concerned the sale of: (i) a 10% interest to BP for a cash consideration of $375 million; and (ii) a 30% interest to Rosneft for a cash consideration of $1,125 million. Due to the fact that both transactions had retroactive economic effect to the beginning of 2016, Eni was also reimbursed of the share of capital and operating expenditures incurred at the divested interests to develop the field reserves for a total amount of approximately $1,500 million.

In March 2018, Eni signed an agreement with Mubadala Petroleum for the divestment of an additional 10% interest in Zohr for a cash consideration of $934 million. The transaction is subject to the fulfillment of certain conditions and all necessary authorizations from Egypt’s authorities.

In December 2017, production start-up at Zohr was achieved by means of offshore wells and subsea facilities. The natural gas production is carried by sea-line to the first treatment train of onshore plant with a capacity of approximately 350 mmCF/d. The development plan includes the construction of additional seven treatment trains that will support production ramp-up to achieve a production plateau of approximately 2.7 BCF/d. Development activities progressed with drilling activities to start-up 20 planned production wells, of which 6 wells already drilled, and the construction of treatment facilities.

As of December 31, 2017, the aggregate development costs incurred by Eni for the Zohr project capitalized in the financial statements amounted to $3.0 billion (€2.5 billion at the EUR/USD exchange rate of December 31, 2017). The capital expenditures of the four-year plan for the production ramp-up at the Zohr field will be financed with net cash flow from operating activities at the Eni pricing assumptions for the Brent marker.

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As of December 31, 2017, Eni’s proved reserves booked at the Zohr field amounted to 695 mmBOE.

The Baltim South West offshore project was sanctioned. The project provides to put into production six wells through the installation of a production platform and linkage facilities to the existing gas treatment plant in the Nooros area (Eni’s interest 75%).

Other development activities concerned: (i) infilling activities and production optimization at the Gulf of Suez, North Port Said and Meleiha concessions; and (ii) start-up of three additional wells and the completion of the second and third treatment unit of the Nooros field to achieve a production of approximately 1 BCF/d.

In the medium term, management expects to increase Eni’s production reflecting additions from the ramp-up of the Zohr fields and ongoing development projects.

Sub-Saharan Africa

Eni’s operations in Sub-Saharan Africa are conducted mainly in Angola, Congo, Ghana, Mozambique and Nigeria. In 2017, Sub-Saharan Africa accounted for 19% of Eni’s total worldwide production of oil and natural gas.

Angola. Eni has been present in Angola since 1980. In 2017, Eni’s production averaged 135 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore.

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The main Eni’s asset in Angola is the Block 15/06 (Eni operator with a 36.84% interest) with the West Hub project, where production started up in 2014 and the East Hub project with production start-up achieved in February 2017. Eni participates in other producing blocks: (i) Block 0 in Cabinda offshore (Eni’s interest 9.8%); (ii) Development Areas in the Block 3 and 3/05-A (Eni’s interest 12%) offshore the Congo Basin; (iii) Development Areas in the Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; ±(iv) the Lianzi Development Area in the Block 14 K/A IMI (Eni’s interest 10%), where a unitization was implemented with the Congo-Brazaville area; and (v) Development Areas in the Block 15 (Eni’s interest 20%) in the deep offshore of the Congo Basin.

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

In November 2017, Eni signed with Sonangol an agreement to acquire a 48% interest and the operatorship of the onshore Cabinda North block, which was previously participated by Eni with a 15% interest. In addition, Eni and Sonangol signed a Memorandum of Understanding to define joint projects in the downstream sector, exploration activities, development of associated and non-associated gas and renewable energy sector.

In February 2017, the East Hub project started-up production of Cabaça South East field through FPSO Armada Olombendo. In November 2017, Eni signed extension exploration rights of the Block 15/06 until 2020.

Development activities carried out in 2017 are: (i) the completion of project activities of the Ochigufu oil field, with production start-up achieved in March 2018, within the West Hub development project in the Block 15/06; (ii) the Vandumbu project in the Block 15/06 with the production start-up expected in 2019;

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(iii) the drilling of development wells of the Mafumeira Sul project in the Block 0; and (iv) the development activities of the Kizomba Satellites phase 2 project and infilling activities in the Block 15.

Eni owns a 13.6% interest of Angola LNG, which runs the plant, located in Soyo, with a treatment capacity of approximately 350 BCF/y of feed gas and a liquefaction capacity of 5.2 mmtonnes/y of LNG. In 2017 production net to Eni averaged approximately 20 KBOE/d.

Congo. Eni has been present in Congo since 1968. In 2017, production averaged 75 KBOE/d net to Eni.

Eni’s activities are concentrated in the conventional offshore in front of Pointe Noire and onshore Koilou region. Eni’s main operated oil producing fields in Congo are the Zatchi (Eni’s interest 55.25%), Loango (Eni’s interest 42.5%), Ikalou (Eni’s interest 100%), Djambala (Eni’s interest 50%), Foukanda and Mwafi (Eni’s interest 58%), Kitina (Eni’s interest 52%), Awa Paloukou (Eni’s interest 90%), M’Boundi (Eni’s interest 83%), Kouakouala (Eni’s interest 75%), Nené Marine and Litchendjili (Eni’s interest 65%), Zingali and Loufika (Eni’s interest 100%) fields.

Other non-operated producing areas, in which Eni owns a 35% interest are the Pointe Noire Grand Fond and Likouala permits.

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

Development activity carried out in 2017 was relate to the Nené Marine phase 2A project in the Marine XII block (Eni operator with a 65% interest), in detail: (i) installation and start-up of a new production platform; (ii) the construction of a sealine to export production to the Kitina hub; and (iii) start-up of seven additional production wells. Planned development activities include the drilling of additional production wells with start-up expected in 2018 and the construction of a sealine for the linkage to Litchendjili hub.

In the medium term, management expects to maintain production at the present level.

Ghana. Eni has been present in Ghana since 2009. In 2017, Eni’s production averaged 8 KBOE/d.

Eni’s main operated asset is the Offshore Cape Three Points (Eni’s interest 44.44%) permits which is regulated by a concession agreement. The license expires in 2036.

In May 2017, the Offshore Cape Three Points development project production started up and the oil production ramped up to the planned peak production of 45 KBBL/d. The production is processed by a floating production, storage and offloading unit (FPSO), which will produce up to 85 KBOE/d through 18 underwater wells. By mid-2018 the non-associated gas will start up and sent to an Onshore Receiving Facilities located in Sanzule, to be sold to the local market.

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

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Mozambique. Eni has been present in Mozambique since 2006, following the award of the exploration license relating to Area 4 offshore the Rovuma Basin block, located in the north of the country.

In 2011, Eni made the important gas discovery of Mamba. The Mamba reservoir extends through Area 4 and the adjacent Area 1 operated by Anadarko. In 2012, Eni made the Coral gas discovery which falls entirely in Area 4.

During the exploration period, which has expired in 2015, six Discovery Areas (DA) were identified. Pursuant to the Decree Law 02/2014 multiple plans of development can be submitted in respect of each DA. Under the Area 4 EPCC (Exploration and Production Concession Contract), each Plan of Development once approved by Government of Mozambique will give right to a Development and Production Period of the duration of 30 years, further extendable pursuant to the terms of the Area 4 EPCC and the applicable Petroleum Law.

Eni also operates the exploration offshore Block A-5A (Eni’s interest 70%), in the deep offshore of Zambesi.

In 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 Eni East Africa (EEA) that is the operator of Area 4. The agreed terms included a cash price of approximately $2.8 billion plus the contractual adjustments up to the closing date, including the reimbursement to Eni of share of capex incurred from the beginning of 2016 up to the completion date. Following completion of the transaction, Mozambique Rovuma Venture, former EEA, is now jointly owned by Eni and ExxonMobil each with a 35.7% stake and the remaining interest of 28.6% by CNPC.

Past transaction, Eni retains a 25% indirect interest in the Area 4 concession through a 35.7% stake in Mozambique Rovuma Venture, which is operator of the Area 4 concession with a 70% interest. The other partners in Area 4 are Galp, Kogas, ENH with a participating interest of 10% each and CNPC that holds a 20% indirect participation.

The other major event of 2017 was the final investment decision for the development of the gas reserves of the Coral discovery, exclusively located in Area 4.

The development activities of the Coral South project provides for the installation of a floating unit for the treatment, liquefaction and storage of natural gas (FLNG) with a capacity of approximately 3.4 mmtonnes/y fed by 6 subsea wells. Start-up is expected by mid-2022.

During 2017, project activities started and the following agreements were signed: (i) contracts for drilling, construction, installation and commissioning of production facilities; and (ii) project financing for the construction, installation and commissioning of the floating liquefaction unit (FLNG) to cover 60% of the investment. In December 2017, the financing agreement was closed and signed by 15 major international banks and guaranteed by 5 Export Credit Agencies. Further information is provided in “Item 19 – consolidated financial statement – footnote 38”.

Other development activities concerned the Mamba project according to its independent industrial plan, coordinated with the operator of Area 1 (Anadarko).

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Nigeria. Eni has been present in Nigeria since 1962. In 2017, Eni’s oil&gas production averaged 104 KBOE/d located mainly onshore and offshore the Niger Delta.

In the development/production phase Eni operates onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%), offshore OML 125 (Eni’s interest 100%) and OPL 245 (Eni’s interest 50%), holding interests in OML 118 (Eni’s interest 12.5%) and in OML 119 and 116 Service Contracts. As partners of SPDC JV, the largest joint venture in the country, Eni also holds a 5% interest in 17 onshore blocks and in 1 conventional offshore block and with a 12.86% in 2 conventional offshore blocks.

In the exploration phase Eni operates offshore OML 134 (Eni’s interest 85%), OPL 2009 (Eni’s interest 49%), and onshore OPL 282 (Eni’s interest 90%) and OPL 135 (Eni’s interest 48%). Eni also holds a 12.5% interest in non-operated OML 135.

Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and concession contracts as well as service contracts, in two blocks, where Eni acts as contractor for the State-owned Company.

Development activities carried out in 2017 are: (i) rigless programs to support production as well as maintenance and rehabilitation of the facilities damaged due to bunkering and sabotage in the OMLs 60, 61, 62 and 63 blocks; (ii) the completion of the Forcados-Yokri project in the OML 43 block (Eni’s interest 5%) and the Gbaran 2A/2b and Associated gas project in the OML 28 block (Eni’s interest 5%) to supply natural gas to the Bonny liquefaction plant. In particular, in the year, the tie-in of production wells and the upgrading of existing treatment plants were completed.

Eni holds a 10.4% interest in the Nigeria LNG Ltd joint venture, which runs the Bonny liquefaction plant located in the Eastern Niger Delta. The plant has treatment capacity of approximately 1,236 BCF/y of feed gas and a production capacity of 22 mmtonnes/y of LNG by six trains. Natural gas supplies to the plant are currently provided under a gas supply agreements from the SPDC JV, TEPNG JV and the NAOC JV. In 2017, the Bonny liquefaction plant processed approximately 1,130 BCF. LNG production is sold under long-term contracts and exported to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG.

The acquisition of the OPL 245 property made by Eni in 2011 is the subject of certain judicial proceedings describe in “Item 19 – consolidated financial statement – footnote 38”.

In January 2017, Eni signed with the Minister of State for Petroleum Resources and Chairman of the Board of the Nigerian National Petroleum Corporation (NNPC) a Memorandum of Understanding, which strengthens cooperation in the energy sector.

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Kazakhstan

Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA). In 2017, Eni’s operations in Kazakhstan accounted for 7% of its total worldwide production of oil and natural gas.

In 2017, Eni and KazMunayGas (KMG) signed an agreement, closed in December 2017, for the transfer to Eni of the 50% stake for exploration and production activities in the Isatay block located in the Kazakh sector of the Caspian Sea. The Isatay block will be operated by a joint operating company established by KMG and Eni on a 50/50 basis.

Eni, KMG and the other partners 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

Kashagan. Eni holds a 16.81% working interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the Kashagan field, which was discovered in the Northern section of the contractual area in the year 2000 over an area extending for 4,600 square kilometers. Management believes this field contains a large amount of hydrocarbon resources, which will eventually be developed in phases. The NCSPSA expires at the end of 2041.

In addition to Eni, the partners of the Consortium are the Kazakh national oil company, KazMunayGas, with a participating interest of 16.88%, the international oil companies Total, Shell and ExxonMobil, each with a participating interest of 16.81%, CNPC with 8.33%, and Inpex with 7.56%.

Ramp-up and stabilization of the production level at the Kashagan field progressed in 2017. Although gas re-injection started later than initially planned, it has been stepped-up in the course of the year and will allow to achieve the target production capacity of 370 KBBL/d when fully operational.

Further activities are in progress to increase production capacity up to 450 KBBL/d by installing additional gas compression capacity through the conversion of production wells into injection wells and the upgrading of the existing facilities. Studies are underway to evaluate a possible optimization of the CC01 gas re-injection project. The concept design envisions the installation of a new compressor unit intended to furnish an additional gas re-injection capacity to support production ramp-up.

Management believes that significant capital expenditures will be required in case the partners of the venture would sanction a second development phase and possibly other additional phases. Eni will fund those investments in proportion to its participating interest of 16.81%. However, taking into account that future development expenditures will be incurred over a long time horizon and subsequent to the production start-up, management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures.

As of December 31, 2017, Eni’s proved reserves booked for the Kashagan field amounted to 620 mmBOE, slightly increased from 608 mmBOE in 2016.

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As of December 31, 2017, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $9.8 billion (€8.2 billion at the EUR/USD exchange rate of December 31, 2017). This capitalized amount included: (i) $7.3 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.5 billion relating primarily to accrued finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years.

Karachaganak. Located onshore in West Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA lasting 40 years, until 2037. Eni and Shell are co-operators of the venture. Eni’s interest in the Karachaganak project is 29.25%.

In 2017, production of the Karachaganak field averaged 247 KBBL/d of liquids (54 KBBL/d net to Eni) and 859 mmCF/d of natural gas (188 mmCF/d net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir. The gas is marketed (about 51%) at the Russian gas plant in Orenburg and the remaining volumes is utilized for re-injecting in the higher layers and the production of fuel gas. Approximately 91% of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of approximately 250 KBBL/d and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline. The remaining volumes of non-stabilized liquid production (approximately 16 KBBL/d) are marketed at the Russian terminal in Orenburg.

Within the gas treatment expansion projects of the Karachaganak field, the detailed engineering design of the Karachaganak Debottlenecking project is expected to be completed shortly and a Final Investment Decision (FID) is expected to be made in the second quarter of 2018. Additional re-injection capacity will be ensured by installing a new re-injection facility in addition to the existing ones.

As of December 31, 2017, Eni’s proved reserves booked for the Karachaganak field amounted to 530 mmBOE, reporting a decrease of 83 mmBOE from 2016 due to an increased marker Brent price used in the reserves estimation process.

Rest of Asia

In 2017, Eni’s operations in the Rest of Asia accounted for 6% of its total worldwide production of oil and natural gas.

China. Eni has been present in China since 1984 with activities located in the South China Sea. In 2017, Eni’s production amounted to 2 KBOE/d.

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

In 2017, hydrocarbons were produced from the offshore Blocks 16/19 through 3 platforms connected to an FPSO.

Indonesia. Eni has been present in Indonesia since 2001. In 2017, Eni’s production mainly composed of gas, amounted to 35 KBOE/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds interests in 14 blocks.

Exploration and production activities in Indonesia are regulated by PSAs.

Production started up in the Jangkrik gas project in the Muara Bakau block (Eni operator with a 55% interest) by means of ten offshore wells linked to the Floating Production Unit (FPU) with a production of approximately 650 mmCF/d (equal to 120 KBOE/d). Natural gas production is processed by the FPU and then delivered by pipeline to the onshore plant, which is linked to the East Kalimantan transport system to feed Bontang liquefaction plant. The LNG is sold under long-term contracts, partly to PT Pertamina and partly to Eni, which will sell up to 11 million tonnes for 15 years as part of the supply agreement signed with the Pakistan LNG state company.

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Exploration activities yielded positive results with the Merakes 2 appraisal well confirming the mineral potential of the Merakes gas discovery in the western area of the East Sepinggan block (Eni operator with an 85% interest). The discovery is located nearby the operated Jangkrik project.

Iraq. Eni has been present in Iraq since 2009. Eni is leading a consortium of partners including international companies and the national oil company Missan Oil, with a 41.6% working interests in charge of executing a rehabilitation and a development plan at the Zubair oil field.

Development and production activities at the Zubair field are regulated by a technical service contract. This contractual scheme establishes an oil entitlement mechanism and an associated risk profile similar to those applicable to Production Sharing contracts.

In 2017, production of the Zubair field averaged 40 KBBL/d net to Eni.

The first stage of development activities (Rehabilitation Plan) of the Zubair field has been completed.

The consortium commitment includes the execution of an additional development phase (Enhanced Redevelopment Plan) of the Zubair field, to achieve a production plateau of 700 KBBL/d. This phase also contemplates utilization of the associated gas to power generation. The large part of production capacity and relevant facilities to treat the targeted production plateau have been already installed; the field reserves will be progressively put into production by drilling additional productive wells over the next few years.

Myanmar. Eni has been present in Myanmar since 2014. Eni is operator of four Production Sharing Contracts; two onshore blocks RSF-5 and PSC-K (Eni’s interest 90% in both leases) and two offshore blocks MD-02 and MD-04 (Eni’s interest 40% in both leases). The contracts foresee, for the onshore blocks, an exploration period of six years subdivided into three phases and for the offshore blocks a study period of two years, followed by an exploration period of six years, subdivided in 3 phases.

Oman. In 2017, Eni signed with the Government of the Sultanate and the state oil company OOCEP an Exploration and Production Sharing Agreement for the Block 52, located offshore Oman. In addition, at the same time, Eni signed an agreement to assign interest in the block to the 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.

In May 2017, Eni signed with the Oman Oil Company (OOC) state company a Memorandum of Understanding for cooperation in oil&gas sector.

Pakistan. Eni has been present in Pakistan since 2000. In 2017, Eni’s production mainly composed of gas amounted to 22 KBOE/d.

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

Eni’s main permits in the country relate to the fields of Bhit/Bhadra (Eni operator with a 40% interest), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.75%), which in 2017 accounted for approximately 80% of Eni’s production in Pakistan.

Production optimization through drilling activities of new development wells represents the main activity currently performed in the above listed fields to mitigate the natural field production decline.

Russia. Eni is present in Russia through three joint ventures with Rosneft for the exploration and development of the Fedynsky and the Central Barents licenses (Eni’s interest 33.33%) located in the Russian Barents Sea and Western Chernomorsky license (Eni’s interest 33.33%) in the Black Sea since 2013.

The Russia upstream sector is the target of certain international sanctions that are described in “Item 3 – Risk factors”.

Turkmenistan. Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused on the onshore Nebit Dag Area in the Western part of the country. The license expires in 2032.

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In 2017, Eni’s production averaged 8 KBOE/d.

Exploration and production activities in Turkmenistan are regulated by PSAs.

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

Production optimization represents the main activity currently performed in the area to mitigate the natural field production decline.

United Arab Emirates. In March 2018, Eni signed with the Supreme Petroleum Council (SPC) and the Abu Dhabi National Oil Company (ADNOC) two Concession Agreements related to the acquisition of a 5% participating interest in the Lower Zakum oil field and a 10% participating interest in the Umm Shaif and Nasr oil, condensates and natural gas fields, in the offshore of Abu Dhabi, for a consideration of $875 million with duration of 40 years.

Vietnam. Eni has been present in Vietnam since 2012 and is operator of five offshore Production Sharing Contracts, two of which are held with 100% interest (Block 116 and Block 122) and three are in Joint Venture (Block 114 Eni’s interest 50%, Block 120 – Eni’s interest 66.67%, Block 124 – Eni’s interest 60%).

Americas

In 2017, Eni’s operations in the Americas area accounted for 9% of its total worldwide production of oil and natural gas.

Ecuador. Eni has been present in Ecuador since 1988. Operations are performed in Block 10 (Eni’s interest 100%) located in the Oriente Basin, in the Amazon forest. In 2017, Eni’s production averaged 12 KBBL/d.

Exploration and production activities in Ecuador are regulated by a service contract that expires in 2033.

Block 10 production is processed by a Central Production Facility and transported to the Pacific Coast through a pipeline network.

In 2017, development activities of the Villano Phase VI project were completed with the drilling and production start-up of three infilling wells.

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Mexico. Eni has been present in Mexico since 2015. Eni is operator of the offshore Block 1 (Eni’s interest 100%) and is planning to develop the Amoca, Miztón and Tecoalli discoveries, located in the shallow waters of the Gulf of Mexico, regulated by PSA.

In June 2017, Eni was awarded the operatorship of Block 10 (Eni’s interest 100%), Block 14 (Eni’s interest 60%) and Block 7 (Eni’s interest 45%) located in the Sureste basin. Furthermore, in February 2018, Eni was awarded a 65% interest and the operatorship of Block 24. The new blocks are close to Area 1 block.

In March 2018, Eni was awarded the operatorship of the Block 28 (Eni’s interest 75%), located in Cuenca Salina basin, in offshore Mexico. The contract award is subject to approval from the authorities.

Exploration activities yielded positive results in the Area 1 block with: (i) the Amoca-2 and Amoca-3 appraisal oil wells; (ii) the first delineation well of the Miztón oil discovery; and (iii) the Teocalli2 appraisal oil well. Eni submitted an integrated development plan of all the three discoveries to the relevant Authorities. Production start-up is expected in 2019.

Trinidad and Tobago. Eni has been present in Trinidad and Tobago since 1970. In 2017, Eni’s production averaged 55 mmCF/d. Eni owns a 17.3% interest in the North Coast Marine Area 1 Block, located offshore North of Trinidad.

Exploration and production activities in Trinidad and Tobago are regulated by a PSA.

Production is provided by the Chaconia, Ixora, Hibiscus, Ponsettia, Bougainvillea and Heliconia gas fields. Production is supported by two fixed platforms linked to the Hibiscus processing facility. Natural gas is used to feed trains 2, 3 and 4 of the Atlantic LNG liquefaction plant on Trinidad’s coast and it is sold under long-term contracts with prices linked to the United States, as well as alternative destinations markets.

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United States. Eni has been present in the United States since 1968. Activities are performed in the shallow and deep offshore of the Gulf of Mexico, onshore and offshore in Alaska, and in Texas onshore.

In 2017, Eni’s oil&gas production was 74 KBOE/d mainly from the Gulf of Mexico and Alaska fields.

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

Eni holds interests in 75 exploration and production blocks in the Gulf of Mexico, of which 35 are operated by Eni.

The main operated fields are Allegheny and Appaloosa (Eni’s interest 100%), Pegasus (Eni’s interest 85%), Longhorn, Devils Towers and Triton (Eni’s interest 75%). Eni also holds interests in Europa (Eni’s interest 32%), Hadrian South (Eni’s interest 30%), Medusa (Eni’s interest 25%), Lucius (Eni’s interest 8.5%), K2 (Eni’s interst 13.4%), Frontrunner (Eni’s interest 37.5%) and Heidelberg (Eni’s interest 12.5%) fields.

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In 2017, the FID of the Lucius Subsequent Development project (Eni’s interest 8.5%) was sanctioned. The development activities provide for the drilling and completion of three subsea production wells and linkage to the existing facilities in the area. Start-up is expected in 2019 with a production plateau of 2 KBOE/d net to Eni.

To achieve the highest safety standards of its operations, Eni became a member of the HWCG Consortium of Gulf of Mexico operators. The HWCG provides resources, coordination and performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline. For further information on this matter, see “Item 3 – Risk factors”.

Eni holds interests in 42 exploration and development blocks in Alaska, with interests ranging from 30 to 100%; Eni is the operator in 26 of these blocks.

Eni’s production is provided by Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) fields with a 2017 overall net production of approximately 20 KBBL/d.

In Texas onshore, Eni’s production comes from the Alliance Area (Eni’s interest 27.5%).

Venezuela. Eni has been present in Venezuela since 1998. In 2017, Eni’s production averaged 61 KBOE/d.

Activity is concentrated both offshore (Gulf of Venezuela and Gulf of Paria) and onshore in the Orinoco Oil Belt.

Eni’s production comes from the Perla gas field (Eni’s interest 50%), in the Gulf of Venezuela, the Corocoro field (Eni’s interest 26%), in the Gulfo de Paria, and the Junin 5 oil field (Eni’s interest 40%), located in the Orinoco Oil Belt.

Eni is also participating with a 19.5% interest in Petrolera Güiria for oil exploration and with a 40% interest in Punta Pescador and Gulfo de Paria Ovest for gas exploration, both located offshore in the eastern Venezuela.

Australia and Oceania

Eni’s operations in Australia and Oceania area are conducted mainly in Australia. In 2017, the area of Australia and Oceania accounted for 1% of Eni’s total worldwide production of oil and natural gas.

Australia. Eni has been present in Australia since 2001. In 2017, Eni’s production of oil and natural gas averaged 21 KBOE/d. Activities are focused on conventional and deep offshore fields.

Exploration and production activities in Australia are regulated by concession agreements, whereas in the cooperation zone between Timor Leste and Australia (Joint Petroleum Development Area – JPDA) they are regulated by PSAs.

The main production blocks in which Eni holds interests are WA-33-L (Eni’s interest 100%) and JPDA 03-13 (Eni’s interest 10.99%). In the appraisal and development phase Eni holds interests in NT/RL8 (Eni’s interest 100%) and NT/RL7 (Eni’s interest 65%). In addition Eni holds interest in 6 exploration licenses, of which 1 in the JPDA.

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

Capital expenditures

See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”

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Disclosure pursuant to Section 13(r) of the Exchange Act

The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes. The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate.

In 2017, Eni fully recovered the overdue trade receivable owed by Iranian state-owned companies relating to the cost recovery of past projects due to enactment of the agreements signed in 2016. Further information is provided in “Item 19-consolidated financial statements under footnote 11”. Eni had no payables towards NIOC as of December 31, 2017. Eni made payments in the region of $0.8 million to the Iranian Social Security Organization in connection to health and social security insurance for which Eni retains at the balance sheet date a residual payable amounting to approximately $8 million date, which will be settled upon termination of our presence in the country.

Finally, in 2017 our Refining & Marketing business sold a limited amount of refined products (16,735 liters for a consideration of approximately €17,000), mainly jet fuels, to an Italian third-party service provider, which in turn re-fuelled an aircraft of the Iranian company Meraj Air.

Gas & Power

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international transport, and LNG supply/marketing and trading. This segment also includes electricity generation activities. In 2017, Eni’s worldwide sales of natural gas amounted to 80.83 BCM. Sales in Italy amounted to 37.43 BCM, while sales in European markets were 38.23 BCM that included 3.89 BCM of gas sold to certain importers to Italy.

The business results of operations in 2017 and its strategy are described in Item 5 – 2015-2017 Group results of operations and Item 5 – Management’s expectations of operations.

Supply of natural gas

In 2017, Eni’s total supply of natural gas was 78.28 BCM of natural gas, down by 4.36 BCM, or 5.3% from 2016. Gas volumes supplied outside Italy (73.23 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 94% of total supplies, down by 3.41 BCM, or 4.4% compared to the previous year, due to lower volumes purchased in the Netherlands (down by 4.40 BCM) following a contract termination, in Qatar (down by 0.92 BCM) and in Norway (down by 0.70 BCM) partially offset by higher purchases in the United Kingdom (up by 0.28 BCM) and in Algeria (up by 0.28 BCM).

Supplies in Italy (5.05 BCM) decreased by 15.8% from 2016 due to lower equity production.

In 2017, main gas volumes from equity production derived from: (i) Italian gas fields (4.1 BCM); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (1 BCM); Libyan fields (1.5 BCM); (iv) Indonesia (0.4 BCM); (v) other European areas, mainly in Croatia (2.6 BCM).

Considering also direct sales of the Exploration & Production segment and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 13.84 BCM representing 15% of total volumes available for sale.

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The table below sets forth Eni’s purchases of natural gas by source for the periods indicated.


Natural gas supply	2017		2016		2015
	(BCM)
Italy		5.05		6.00		6.73
Outside Italy		73.23		76.64		78.66
Russia		28.09		27.99		30.33
Algeria (including LNG)		13.18		12.90		6.05
Libya		4.76		4.87		7.25
the Netherlands		5.20		9.60		11.73
Norway		7.48		8.18		8.40
the United Kingdom		2.36		2.08		2.35
Hungary		0.04		0.02		0.21
Qatar (LNG)		2.36		3.28		3.11
Other supplies of natural gas		6.71		5.81		7.21
Other supplies of LNG		3.05		1.91		2.02
Total supplies of subsidiaries		78.28		82.64		85.39
Withdrawals from (input to) storage		0.31		1.40
Network losses, measurement differences and other changes		(0.45)		(0.21)		(0.34)
Volumes available for sale of Eni’s subsidiaries		78.14		83.83		85.05
Volumes available for sale of Eni’s affiliates		2.69		2.48		2.67
Total volumes available for sale		80.83		86.31		87.72

Sales of natural gas

In 2017, natural gas sales amounted to 80.83 BCM (including Eni’s own consumption, Eni’s share of sales made by equity-accounted entities), representing a decrease of 5.48 BCM, or 6.3% from the previous year. Sales in Italy (37.43 BCM) decreased by 2.6% from 2016. Lower sales to spot market, volumes sold to small and medium-sized enterprises segment and to services sector were offset by the higher sales to thermoelectrical segment. Sales in the European markets amounted to 34.34 BCM, a decrease of 9.8% or 3.72 BCM from 2016.

Sales to long-term buyers were down by 11% compared to the previous year due to the shorter availability of Libyan output. Sales in the Extra European markets (5.17 BCM) decreased by 0.28 BCM or 5.1% due to lower LNG sales in Japan, Argentina, United Arab Emirates, partly offset by higher volumes sold in South Korea and China.

The tables below set forth Eni’s sales of natural gas by principal market for the periods indicated.


Natural gas sales by entities	2017		2016		2015
	(BCM)
Total sales of subsidiaries		77.52		83.34		84.94
Italy (including own consumption)		37.43		38.43		38.44
Rest of Europe		36.10		40.52		41.14
Outside Europe		3.99		4.39		5.36
Total sales of Eni’s affiliates (Eni’s share)		3.31		2.97		2.78
Italy
Rest of Europe		2.13		1.91		1.75
Outside Europe		1.18		1.06		1.03
Worldwide gas sales		80.83		86.31		87.72

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Natural gas sales by market	2017		2016		2015
	(BCM)
ITALY		37.43		38.43		38.44
Wholesalers		8.36		7.93		4.19
Italian gas exchange and spot markets		10.81		12.98		16.35
Industries		4.42		4.54		4.66
Medium-sized enterprises and services		0.93		1.72		1.58
Power generation		2.22		0.77		0.88
Residential		4.51		4.39		4.90
Own consumption		6.18		6.10		5.88
INTERNATIONAL SALES		43.40		47.88		49.28
Rest of Europe		38.23		42.43		42.89
Importers in Italy		3.89		4.37		4.61
European markets		34.34		38.06		38.28
Iberian Peninsula		5.06		5.28		5.40
Germany/Austria		6.95		7.81		5.82
Benelux		5.06		7.03		7.94
Hungary				0.93		1.58
United Kingdom/Northern Europe		2.21		2.01		1.96
Turkey		8.03		6.55		7.76
France		6.38		7.42		7.11
Other		0.65		1.03		0.71
Extra European markets		5.17		5.45		6.39
WORLDWIDE GAS SALES		80.83		86.31		87.72

The LNG business

Eni LNG business can count currently on a portfolio of contracted long-term supplies mainly from Qatar, Nigeria, Oman and Algeria. Starting from 2017, the G&P LNG business marketed volumes of gas produced at the E&P large Jangkrik gas complex, off Indonesia. In the plan period, Eni intends to develop its LNG business by leveraging on the integration with the E&P segment and the valorization of the equity gas. Final markets of that gas include the Chinese market and other areas. The business’s profitability will be also driven by enhancing the commercial presence in premium markets and continuing integration with trading activities.


LNG sales	2017		2016		2015
	(BCM)
G&P sales		8.3		8.1		9.0
Rest of Europe		5.2		5.2		4.8
Extra European markets		3.1		2.9		4.2
E&P sales		5.9		4.3		4.5
Liquefaction plants:
- Soyo (Angola)		0.7		0.1
- Bontang (Indonesia)		1.3		0.4		0.5
- Point Fortin (Trinidad & Tobago)		0.6		0.7		0.7
- Bonny (Nigeria)		2.9		2.6		2.8
- Darwin (Australia)		0.4		0.5		0.5
		14.2		12.4		13.5

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Electricity sales and power generation

Electricity sales

As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market, on the Italian Stock Exchange for electricity and at industrial sites. Supplies of electricity include both own production volumes through gas-fired, combined-cycle facilities and purchases on the open market. This activity has been developed in order to capture further value along the gas value chain by leveraging on the Company’s large gas availability. In addition, with the aim of developing and retaining valuable customers in the residential segment and middle to large industrial users, the Company has been developing a commercial offer that provides the combined supply of gas, power and fuels.

In 2017, power sales (35.33 TWh) were directed to the free market (75%), the Italian Power Exchange (15%), industrial sites (8%) and others (2%). Compared to 2016, electricity sales were down by 0.96 TWh or by 3.5%, due to lower volumes sold to middle market, wholesalers, residential segment and small and medium-sized enterprises, partially offset by higher volumes sold to large customers.


Power availability	2017		2016		2015
	(TWh)
Power generation sold		22.42		21.78		20.69
Trading of electricity(a)		12.91		15.27		14.19
		35.33		37.05		34.88
Power sales by market
Free market(a)		26.53		27.49		25.90
Italian Exchange for electricity		5.21		5.64		5.09
Industrial plants		3.01		3.11		3.23
Other(a)		0.58		0.81		0.66
		35.33		37.05		34.88

(a)

Include positive and negative imbalances (differences between power introduced in the grid and the one planned).

Power generation

Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Mantova, Brindisi, Ferrara and Bolgiano. In 2017, power generation was 22.42 TWh, up by 0.64 TWh or by 2.9% from 2016 mainly due to higher production at Ferrera Erbognone, Ravenna, Brindisi, following increasing demand. As of December 31, 2017, installed operational capacity was 4.7 GW, unchanged compared to December 31, 2016. Electricity trading (12.91 TWh) reported a decrease of 15.5% thanks to the optimization of inflows and outflows of power.

Site

Total installed
capacity
in 2017
(GW)

Technology

Fuel

Brindisi

1.3

CCGT

gas

Ferrera Erbognone

1.0

CCGT

gas/syngas

Mantova

0.8

CCGT

gas

Ravenna

1.0

CCGT

gas

Ferrara(a)

0.4

CCGT

gas

Bolgiano

0.1

Power station

gas

4.7

(a)

Eni’s share of capacity.

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Power generation		2017		2016		2015
Purchases
Natural gas	(mmCM)		4,359		4,334		4,270
Other fuels	(ktoe)		392		360		313
- of which steam cracking			104		105		87
Production
Electricity	(TWh)		22.42		21.78		20.69
Steam	(ktonnes)		7,551		7,974		9,318
Installed generation capacity	(GW)		4.7		4.7		4.9

International transport

Eni has transport rights on a large European network of integrated infrastructures for transporting natural gas, which links key consumption markets with the main producing areas (Russia, Algeria, Libya and the North Sea). Eni has contracted the transport capacity under ship-or-pay contracts which are similar to take-or-pay contracts.

Likewise, Eni has contracted long-term access and transport capacity at the main entry points of the Italian national grid. Management believes that from 2019 the Company’s ship-or-pay obligations towards the Italian TSO might be softened at the entry points of the Italian gas transport network via a regulatory change. As a matter of fact, from thermal year October 2017 – October 2018 Eni is already allowed to defer utilization of entry capacities booked with a multi-year term over a period of three years thus reducing the incidence on the profit and loss of the sunk costs of the transport capacity.

Eni also retains ownership interests in certain pipeline companies which run and operate the facility by selling transportation capacity under long-term ship-or-pay contracts to both shareholders and third-party shippers. The main assets of Eni’s transport activities are provided in the table below.

International Transport infrastructure Route

	Lines	Total length		Diameter		Transport capacity(1)		Transit capacity(2)		Compression stations
	(units)	(km)		(inch)		(BCM/y)		(BCM/y)		(No.)
TTPC (Oued Saf Saf-Cap Bon)	2 lines of km 370		740		48		34.3		33.2		5
TMPC (Cap Bon-Mazara del Vallo)	5 lines of 155		775		20/26		33.5		33.5
GreenStream (Mellitah-Gela)	1 line of km 520		520		32		8.0		8.0		1
Blue Stream (Beregovaya-Samsun)	2 lines of km 387		774		24		16.0		16.0		1

(1)

Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.

(2)

The maximum volume of natural gas which is input at various entry points along the pipeline and transported to the next pipeline.

International transport activities

The TTPC pipeline, 740-kilometer long, is made up of two lines that are each 370-kilometers long with a transport capacity of 34.3 BCM/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline.

The TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometers long with a transport capacity of 33.5 BCM/y. It crosses the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system.

The GreenStream pipeline, jointly-owned with the Libyan National Oil Co, started operations in October 2004 for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 520-kilometers long with a transport capacity of 8 BCM/y crossing the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system.

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Eni holds a 50% interest in the Blue Stream underwater pipeline (water depth greater than 2,150 meters) linking the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometers long on two lines and has transport capacity of 16 BCM/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market.

Capital expenditures

See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”.

Refining & Marketing & Chemicals

Refining & Marketing

Eni’s Refining & Marketing business engages in the supply and refining of crude oil, as well as in the marketing of refined products primarily in Europe. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share. Company operations are fully integrated through refining, supply, logistics and marketing in order to maximize cost efficiencies and operational effectiveness.

In 2017 refining margins in the Mediterranean area increased by approximately 19% y-o-y due to better prices of refined products relative to the cost of the petroleum feedstock.

Management believes that refining margins in the short-term will remain stable at the 2017 level. In the medium-term, spreads between products and crude may widen as a consequence of the IMO 2020 regulations, which will lead, among other solutions, to the substitution of bunker fuel oil with cleaner fuels (gasoil, ULSFO and LNG) that could be short in the first period of law application, with benefit for high conversion refineries. In the longer term, refinery margins will normalize, as a result of supply-demand re-alignment thanks investments by both refining companies (fuel oil destruction units) as well as ship-owners (scrubbers, retrofitting, new ships/engines).

The business results of operations in 2017 and its strategy are described in Item 5 – 2015-2017 Group results of operations and Item 5 – Management’s expectations of operations.

Supply

In 2017, a total of 24.28 mmtonnes of crude were purchased (compared with 23.35 mmtonnes in 2016), of which 3.51 mmtonnes by equity crude oil. The breakdown by geographic area was the following: approximately 40% of purchased crude came from the Middle East, 19% from Central Asia, 15% from Russia, 12% from Italy, 10% from North Africa, 2% from North Sea, 1% from West Africa, and 1% from other areas.

Refining

In 2017, Eni refinery capacity (balanced with conversion capacity) was approximately 27.4 mmtonnes (equal to 548 KBBL/d), with a conversion index of 54%. Conversion index is a measure of refinery complexity. The higher the index, the wider the range of crude qualities and feedstock that a refinery is able to process thus enabling refineries to benefit from the cost economies arising from the discount – versus the benchmark – at which certain qualities of crude (particularly the heavy ones) may be supplied. Eni’s 100% owned refineries have a balanced capacity of 19.4 mmtonnes (equal to 388 KBBL/d), with a 55% conversion index. In 2017, Eni’s refineries throughputs in Italy and outside Italy were 24.02 mmtonnes. The refinery utilization rate, ratio between throughputs and refinery capacity, is 82.6%.

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Refining system in 2017

	Ownership (%)		Balanced refining capacity (Eni’s share) (KBBL/d)		Utilization rate (Eni’s share) %		Conversion index(1) (%)		Fluid catalytic cracking (FCC)(2) (KBBL/d)		Residue conversion(2) (KBBL/d)		Hydro- cracking(2) (KBBL/d)		Visbreaking/ Thermal Cracking(2) (KBBL/d)
Wholly-owned refineries				388		83		55		34		40		71		29
Italy
Sannazzaro		100		200		83		73		34		14		51		29
Taranto		100		104		68		56				26		20
Livorno		100		84		99		11
Partially owned refineries				160		104		52		143		25		75		27
Italy
Milazzo		50		100		109		60		45		25		32
Germany
Vohburg/Neustadt (Bayernoil)		20		41		93		36		49
Schwedt		8.33		19		102		42		49				43		27
Total				548		89		54		177		65		146		56

(1)

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

(2)

Conversion unit capacities are 100%.

Italy

Eni’s refining system in Italy is composed of the wholly-owned refineries of Sannazzaro, Livorno and Taranto, as well as its 50% stake in the Milazzo refinery in Sicily. Eni’s refineries operate to maximize asset value according to market conditions and the integration with marketing activities.

The Sannazzaro refinery has a balanced capacity of 200 KBBL/d and a conversion index of 73%. Located in the Po Valley, in the center of the Northern Italy, Sannazzaro is one of the most efficient refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipments in the refinery are: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocrackers (HdC), two reforming units, a visbreaking thermal conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation, and finally the Eni Slurry Technology (EST) plant, started up at the end of 2013. The EST plant exploits a proprietary technology to convert extra heavy crude residues (vacuum and visbreaking tar) into naphtha and middle distillates, with a conversion factor of 95%.

In January 2018 Eni has sold the licence and basic engineering project to the Chinese company Sinopec the largest refining company in the world, for the use of the EST conversion proprietary technology.

The Taranto refinery has a balanced capacity of 104 KBBL/d and a conversion index of 56%. Taranto has a strong market position due to the fact that is the only refinery in Southern Continental Italy, and is upstream integrated with the Val d’Agri fields in Basilicata (Eni 60.77%) through a pipeline. The main equipments are a topping-vacuum unit, a hydrocracking, a platforming unit and two desulphurization units.

The Livorno refinery, with a balanced refining capacity of 84 KBBL/d and a conversion index of 11%, is dedicated to the production of lubricants and specialties. The refinery is connected by pipeline to a depot in Florence (Calenzano). The refinery has a topping-vacuum unit, a platforming unit, two desulphurization units and a de-aromatization unit (DEA) – for the production of fuels; a propane de-asphalting (PDA), aromatics extraction and de-waxing units, for the production of base oils; a blending and filling plant – for the production of finished lubricants.

The Milazzo refinery (Eni 50%) has a balanced capacity of 200 KBBL/d and a conversion index of 60%. Located in Sicily, Milazzo is mainly dedicated to export and to the supply of Italian coastal depots. The main equipments in the refinery are: two primary distillation columns and a vacuum unit, two desulphurization units, a fluid catalytic cracker (FCC), one hydrocracker (HdC), one reforming unit and one LC fining (ebullated bed residue conversion).

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Outside Italy

In Germany, Eni owns an interest of 8.33% stake in the Schwedt refinery (PCK) and an interest of 20% in the Vohburg and Neustadt refineries (Bayernoil). Eni’s refining capacity in Germany is 60 KBBL/d to supply Eni’s distribution network in the country.

Green refineries

	Ownership share (%)		Capacity (2017) (ktonnes/y)		Capacity (at regime) (ktonnes/y)		Throughput (2017) (ktonnes/y)
Wholly-owned
Venezia		100		360		560		242
Gela		100				750
Total green refineries				360		1,310		242

Green Refining

Eni fully owns the green refinery of Venice and the site of Gela, where another green refinery is under construction.

The Venice green refinery started production in June 2014, with a production capacity of 360 ktonnes/y. The refinery leverages on the proprietary EcofiningTM technology to transform vegetable oil in hydrogenated bio-fuels. A second phase of development is underway. At full capacity, the refinery production will satisfy approximately half of Eni bio-fuels needs required for being compliant with the EU environmental normative aimed at reducing CO2 emissions.

The Gela refinery is located on the Southern coast of Sicily. The refinery was shut-down in March 2014 and in November 2014, Eni signed a Memorandum of Understanding for the reconversion of the plant into a bio-refinery with the Italian Ministry for Economic Development and Local Authorities. In 2017 Eni’s activities continued in line with the commitments foreseen in the Memorandum of Understanding. In August 2017 the project obtained the environmental impact assessment and authorization (VIA/AIA) by the Italian Ministry of the Environment and the Ministry of Cultural Heritage. The project is expected to come on stream by the end of 2018. The refinery will have a capacity of 750 ktonnes/y. The conversion will leverage on the application of the Eco-fining proprietary technology, developed and licensed by Eni, to convert unconventional and second generation raw materials into green diesel, a highly sustainable biofuel. The plant properties will allow the production of green diesel in compliance with the last regulatory constraints in terms of reduction of GHG emissions throughout the whole production chain, deploying the full capacity in process second-generation feedstock.

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The table below sets forth Eni’s products availability figures for the periods indicated.


Availability of refined products	2017		2016		2015
	(mmtonnes)
ITALY
Refinery throughputs
At wholly-owned refineries		16.03		17.37		18.37
Less input on account of third parties		(0.34)		(0.27)		(0.38)
At affiliated refineries		5.46		4.51		4.73
Refinery throughputs on own account		21.15		21.61		22.72
Consumption and losses		(1.36)		(1.53)		(1.52)
Products available for sale		19.79		20.08		21.20
Purchases of refined products and change in inventories		6.74		6.28		6.22
Products transferred to operations outside Italy		(0.46)		(0.39)		(0.48)
Consumption for power generation		(0.34)		(0.37)		(0.41)
Sales of products		25.73		25.60		26.53
Green refinery throughputs		0.24		0.21		0.20
OUTSIDE ITALY
Refinery throughputs on own account		2.87		2.91		3.69
Consumption and losses		(0.22)		(0.22)		(0.23)
Products available for sale		2.65		2.69		3.46
Purchases of finished products and change in inventories		4.36		4.72		4.77
Products transferred from Italian operations		0.46		0.40		0.48
Sales of products		7.47		7.81		8.71
Refinery throughputs on own account		24.02		24.52		26.41
of which: refinery throughputs of equity crude on own account		3.51		3.43		5.04
Total sales of refined products		33.20		33.41		35.24
Crude oil sales		0.86		0.20		0.27
TOTAL SALES		34.06		33.61		35.51

In 2017, refining throughputs were 24.02 mmtonnes, down by 2% from 2016 due to to the downtime of some plants at Sannazzaro refinery and the shutdown at the Taranto refinery, partly offset by a better performance of Milazzo and Livorno refineries.

Outside Italy, Eni’s refining throughputs were 2.87 mmtonnes, down by 40 ktonnes or 1.4% due to the downtime of BayernOil refinery in 2017, more impacting compared to the downtime of PCK refinery in 2016.

Total throughputs in wholly-owned refineries were 16.03 mmtonnes, down by 1.34 mmtonnes or 7.7% compared with 2016.

Approximately 15.2% of processed crude was equity, increased approximately 0.4 percentage points from 2016 (14.8%).

Logistics

Eni is a leading operator in the Italian oil and refined products storage and transportation business.

It owns an integrated infrastructure consisting of 16 directly managed depots and a network of oil and refined products pipelines. Eni logistic model is organized in three hubs (North, Central and South Italy). These hubs manage the product flows in order to guarantee high safety and technical standards, as well as cost effectiveness. Eni is also in joint venture with other Italian operators to optimize its logistic footprint and increase efficiency. Other depots are operated by six different joint ventures (Sigemi, Petroven, Petra, Seram, Disma, Toscopetrol). Eni transports oil and refined products: (i) by sea through spot and long-term contracts of tanker ships; and (ii) through a proprietary pipeline network extending approximately 1,462 kilometers.

Secondary distribution to retail and wholesale markets is outsourced to independent tanker carriers, selected as market leaders in their own field.

Marketing

Eni markets a wide range of refined petroleum products, primarily in Italy, through a widespread operated network of service stations, franchises and other distribution systems.

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The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated.


Oil products sales in Italy and outside Italy	2017		2016		2015
	(mmtonnes)
Italy
Retail		6.01		5.93		5.96
Wholesale		7.64		8.16		7.84
		13.65		14.09		13.8
Petrochemicals		0.86		1.02		1.17
Other sales		11.22		10.49		11.56
Total		25.73		25.60		26.53
Outside Italy
Retail		2.53		2.66		2.93
Wholesale		3.48		3.61		4.26
		6.01		6.27		7.19
Other sales		1.46		1.54		1.52
Total		7.47		7.81		8.71
TOTAL SALES		33.20		33.41		35.24

In 2017, sales volumes of refined products (33.20 mmtonnes) were down by 0.21 mmtonnes or by 0.6% from 2016, mainly due mainly due to the decrease of wholesale sales in Italy and the assets disposal in Hungary and Slovenia in the second half of 2016.

Retail sales in Italy

In 2017, retail sales in Italy were 6.01 mmtonnes, with a slight increase compared to 2016 (about 80 ktonnes from 2016 or 1.3%). Average gasoline and gasoil throughput (1.588 kliters) increased by approximately 40 kliters from 2016. Eni’s retail market share in 2017 was 25%, up by 0.7 percentage points from 2016 (24.3%).

As of December 31, 2017, Eni’s retail network in Italy consisted of 4,310 service stations, lower by 86 units from December 31, 2016 (4,396 service stations), resulting from the release of low throughput stations (25 units) and negative balance of acquisitions/releases of lease concessions (56 units) and of motorway concessions (5 units).

Retail sales in the rest of Europe

Eni’s strategy in the rest of Europe is focused on selectively growing its presence, particularly in Germany and Austria leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistic facilities.

In 2017, retail sales of refined products in the rest of Europe (2.53 mmtonnes), recorded a reduction from 2016 (down by 4.9%). This result reflected mainly the assets disposal in Slovenia and Hungary in the second half of 2016. On a homogeneous basis, when excluding the impact of the above mentioned disposal, sales slightly increased by 1.1% due to higher volumes traded in Austria and Germany.

At December 31, 2017, Eni’s retail network in the Rest of Europe consisted of 1,234 units, increasing by 8 units from December 31, 2016, mainly in Germany. Average throughput (2,440 kliters) increased by 100 kliters compared to 2016 (2,340 kliters).

Other businesses

Wholesale

Eni is strongly present in wholesale market in Italy, including sales of diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and sales of fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users

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(transporters, condominiums, farmers, fishers, etc.). Eni provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Customer care and product distribution are supported by a widespread commercial and logistical organization presence throughout Italy and is articulated in local marketing offices and a network of agents and concessionaires.

In 2017, sales volumes on wholesale markets in Italy (7.64 mmtonnes) decreased by 0.52 mmtonnes or 6.4% from the previous year, mainly due to lower volumes marketed of gasoil, bunkering and fuel oil partly offset by higher sales of jet fuel and bitumens.

Wholesale sales in the Rest of Europe were 3.03 mmtonnes, down by 4.7% from 2016 due to lower sold volumes in Austria and France and the above-mentioned asset disposals in the East Europe, offset by higher volumes in Switzerland and Germany.

Supplies of feedstock to the petrochemical industry (0.86 mmtonnes) decreased by 15.7%. Other sales in Italy and outside Italy (12.68 mmtonnes) decreased by approximately 0.65 mmtonnes or 5.4%, mainly due to lower sales volumes to oil companies.

LPG

The marketing of LPG in Italy is supported by the refining production and a logistic network made up of five bottling plants, 1 owned storage site and coastal storage sites located in Livorno, Naples and Ravenna.

LPG is used as heating and automotive fuel. In 2017, Eni share of LPG market in Italy was 17.7%.

Outside Italy, the main market of Eni is Ecuador, with a market share of 37.9%.

Lubricants

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

In 2017, Eni’s share of lubricants market in Italy was 19.58%, in Europe 3% and on a worldwide base 0.6%. Eni operates in more than 80 countries by subsidiaries, licensees and distributors.

Oxygenates

Eni’s, through its subsidiary Ecofuel (100% Eni’s share), sells approximately 1 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About 85% of oxygenates are produced in Eni’s plants in Italy (Ravenna), Saudi Arabia (in joint venture with Sabic) and Venezuela (in joint venture with Pequiven) and the remaining 15% is purchased.

Chemicals

Eni operates in the businesses of olefins and aromatics, basic and intermediate products, polystyrene, elastomers and polyethylene. Its major production hubs are located in Italy and Western Europe. At the end of 2017 Eni started operations for the production of elastomers in South Korea in joint venture with a local operator.

The business results of operations in 2017 and its strategy are described in Item 5 – 2015-2017 Group results of operations and Item 5 – Management’s expectations of operations.

In 2017 sales of chemical products amounted to 3,712 ktonnes, slightly decreased from 2016 (down by 47 ktonnes, or 1.3%). The steepest declines were registered in olefins (down by 7.1%) and derivatives (down by 14.1%), partly offset by higher sales volumes of polyethylene (+10.8%).

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Average unit sales prices increased by 16% from 2016. The intermediates business up by 27%, in particular butadiene (up by 88.3%) and the polymers business up by 13%, reflecting styrene and elastomers prices increased (up by 14.8% and 24.1%, respectively).

Petrochemical production of 5.818 ktonnes increased by 172 ktonnes (up by 3%) mainly due to higher production of polyethylene (up by 14.6%) and elastomers businesses (up by 5.9%); the intermediates productions were slightly increased (+1,2%).

The main increases in production were registered at the Ragusa site (up by 90%), due to a recovery of production capacity for a malfunctioning occurred at the plant in 2016, as well as Ravenna and Dunkerque (olefins), and Ferrara and Mantova sites (styrene) due to fewer production shutdowns of the plants. Decreasing productions at the Marghera, Mantova (derivatives) and Dunastyr sites due to planned shutdowns of the plants.

Nominal capacity of plants is in line from the previous year. The average plant utilization rate calculated on nominal capacity was 72.8% increased from 2016 (71.4%).

The table below sets forth Eni’s main chemical products availability for the periods indicated.

	Year ended December 31,
	2017		2016		2015
	(ktonnes)
Intermediates		3,458		3,417		3,334
Polymers		2,360		2,229		2,366
Total production		5,818		5,646		5,700
Consumption and losses		(2,584)		(2,166)		(1,908)
Purchases and change in inventories		478		279		9
		3,712		3,759		3,801

The table below sets forth Eni’s main petrochemical products revenues for the periods indicated.

	Year ended December 31,
	2017		2016		2015
	(€ million)
Intermediates		1,988		1,688		1,899
Polymers		2,730		2,380		2,690
Other revenues		133		128		127
Total revenues		4,851		4,196		4,716

Intermediates

Intermediates revenues (€1,988 million) increased by €300 million from 2016 (up by 17.8%) reflecting the higher commodity prices scenario that influences average intermediates prices of the main product of the business Unit. Sales decreased by 7.6%, in particular for ethylene business (down by 16%) and derivatives (down by 14.1%) driven by the planned shutdowns of Mantova plants.

Average unit prices increased by 27.1%, in particular olefins (up by 25.8%), aromatics (up by 29.2%) and derivatives (up by 26.7%).

Intermediates production (3,458 ktonnes) registered an increase of 1.2% from the last year. Increasing of olefins (up by 4.3%) and reduction of derivatives (down by 11.2%).

Polymers

Polymers revenues (€2,730 million) increased by €350 million or 14.7% from 2016 thanks to higher sales volumes (up by 6%), as well as to the increase of the average unit prices (up by 13%).

The styrenics business benefited from high commodities prices (styrene) with an increase of average sold prices (up by 14.8%); slightly decrease of sold volumes (down by 2%).

Polyethylene volumes increased (up by 8.3%) and average prices recorded a decrease (down by 2.2%).

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Polymers productions increased by 5.9% (2.360 ktonnes) from 2016 mainly driven by higher production of polyethylene (up by 14.6%). Elastomers business productions increased (up by 5.9%), especially in BR rubbers (up by 12.4%) and EPDM (up by 25.1%). The styrenics business reported higher production of expandable polystyrene (up by 6%) and ABS/SAN (up by 17.9%), decreasing production of styrene (down by 5.9%) due to planned shutdowns of the Mantova plant.

Capital expenditures

See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”.

Corporate and Other activities

These activities include the following businesses:

•

the “Other activities” segment comprises results of operations of Eni’s subsidiary Syndial which runs reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years, as well as Eni New Energy SpA which engages in developing the business of renewable energy; and

•

the “Corporate and financial companies” segment comprises results of operations of Eni’s headquarters and certain Eni subsidiaries engaged in treasury, finance and other general and business support services. Eni’s headquarters is a department of the parent company Eni SpA and performs Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions. Through Eni’s subsidiaries Eni Finance International SA, Banque Eni SA, Eni International BV, Eni Finance USA Inc and Eni Insurance DAC, Eni carries out cash management activities, administrative services to its foreign subsidiaries, lending, factoring, leasing, financing Eni’s projects around the world and insurance activities, principally on an intercompany basis. EniServizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group companies). Management does not consider Eni’s activities in these areas to be material to its overall operations.

Seasonality

Eni’s results of operations reflect the seasonality in demand for natural gas and certain refined products used in residential space heating, the demand for which is typically highest in the first quarter of the year, which includes the coldest months and lowest in the third quarter, which includes the warmest months. Moreover, year-to-year comparability of results of operations is affected by weather conditions affecting demand for gas and other refined products in residential space heating. In colder years, which are characterized by lower temperatures than historical average temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa.

Research and development

Technology research and development (R&D) and continuous innovation are key factors in successfully implementing Eni’s business strategies and in supporting mid and long-term performances. R &D continuously supports the core business through the development of technologies able to reduce risks and maximize operational efficiency.

Eni recognizes the need to limit the rise in global temperature, by the end of the century, below 2° C compared to pre-industrial levels and intends to play a leadership role in the process of energy transition towards a low-carbon future. In this context, R&D represents a key element for the transformation of Eni into an integrated energy company and is committed to develop new solutions in the renewable energy sector, to support the Green Refinery, and to promote a progressive decarbonization of the energy mix through the fostering of the use of natural gas also through new business opportunities.

In order to address the several challenges that energy industry will have to face, Eni will therefore pursue the following technological targets in the next future:

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•

reducing operational risk and maximizing operational efficiency by development of new tools for prevention and response to blow outs (mechanical barriers and equipment for the capture of subsea oil eruption) and development of tools for vessel maintenance and restoring clogged pipes;

•

strengthening technological leadership in exploration by continuously development of proprietary tools;

•

maximizing the recovery factor of reservoirs aiming at innovative enhanced oil recovery techniques sustainable also in low oil price scenarios;

•

further development of technologies for the production of energy from renewable sources, in particular solar thermal and organic photovoltaic and quickly transfer them to the Energy Solution business unit;

•

integrating renewable sources with upstream operations especially in off-grid locations;

•

focusing on solar systems that use less polluting materials, can produce at lower cost and are more easily integrated into buildings;

•

further development of Eni’s Green Refinery processes with innovative solution for feeding bio-refineries with other feedstock than palm oil;

•

formulating innovative fuels and lubricants that comply with European regulations and new motor specifications;

•

development of new technologies for the separation, conversion, transportation and utilization of natural gas;

•

further development of innovative environmental technologies for in situ monitoring and remediation.

In 2017, Eni filed 27 patent applications (40 in 2016).

In 2017, Eni’s overall expenditure in R&D amounted to €185 million which were almost entirely expensed as incurred (€161 million in 2016 and €176 million in 2015).

Exploration & Production

Digital rock physics. An innovative workflow for petrophysical characterization was developed in 2017, integrating a new powerful X-ray micro CT (Computed Tomography) with SEM (Scanning Electron Microscope) images and dynamic simulation at pore/core scale; it can be applied to the majority of reservoir rock types, allowing a much faster petrophysical characterization. The next development phase will include static and dynamic simulations at core scale in order to calculate petrophysical properties like porosity, absolute and relative permeability.

New fluid for cementing operations. Eni and Versalis developed and scaled up an advanced fluid to clean up casings and wellbores with the objective of substantially improving cementing operations. The main benefit is an improved cement adhesion on casing and subterranean formations, with higher well integrity.

Drilling automation. Two new tools addressing lost/non productive time and based on big data technology were developed in 2017 to support operations. The first tool is e.NPT (Eni Non Productive Time) which analyzes and integrates multiple data sources in real time in order to predict sticking events. The second tool is a new solution enabling a near real time performance analysis to identify Invisible Lost Times.

Drilling Safety Technologies. The project aims to reduce by two orders of magnitude the risk of blowout occurrence compared to the OGP reference. To achieve this goal, new technologies able to improve well integrity both during drilling and well productive life are being developed. In 2017 Eni has field-tested the functionality and the integrity of the Downhole Isolation Packer. The tool, composed by a packer and a bypass valve, provides a backup barrier to ensure the control of formation fluids at all times.

Subsea R&D Program: in 2017 Eni launched a program to develop, together with industry partners, technologies to significantly reduce subsea development CAPEX and OPEX by using full subsea architectures, very long step-outs and life-of-field robotics. The program starts from lessons learned from Eni’s most recent subsea development projects (started-up in the last 3 years). The objective is to increase the distance between new subsea production systems and existing floating production facilities, or connect

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those new subsea assets directly to shore. Cost effective and flexible extra-long subsea architectures prove to efficiently work on a wide range of applications and design basis parameters. Key enabling technologies under development are multicontrol communication, subsea power distribution, subsea boosting and thermal management.

Refining & Marketing

Biofeedstock database. In 2017 Eni created one of the first Ecofining biofeedstock database in the oil industry. The archive already includes more than 100 characterized bio-oils from all over the world, representing possible alternatives to palm oil for our biorefining. The database is utilized to optimize the supply chain to reduce costs.

Methanol based alternative fuels. A new gasoline formulation containing alternative fuels (15% methanol and 5% bioethanol comprising a proper additive package to protect the engine), labeled M15, has been developed and is currently undergoing extensive road tests on five Fiat 500 cars belonging to the car sharing Enjoy fleet in Milan. M15 can provide more than 3% CO2 tailpipe emissions reduction due to the lower H/C ration and higher octane number.

Eni Green Diesel+. On 18 October, Eni successfully presented the final result of an experimental activity agreed with the Mayor of Turin, showing the environmental advantages of Eni Diesel+ on old buses (Euro 3) of Turin’s Transport Company (GTT): lower particles number (-40%), fewer particulate matter (-16%), compared to commercial diesel fuel; also NOx and CO2 emissions are reduced.

i-Sigma Bio Tech lubricants. Eni R&D in collaboration with Versalis and Matrìca developed a new synthetic lubricant base stock of ester type, obtained from renewable sources. This synthetic product is featured with excellent properties in terms of oxidation stability, volatility and wear protection that are suitable for several applications in the industrial and automotive lubrication sectors. Bioester is a key component of a new SAE 10W-30 engine oil for heavy duty services (trucks, buses, and off-road vehicles) designed and tested by Eni to meet some important international technical specifications, and ready for the market under the brand name i-Sigma Bio Tech.

Energy Saving Lubricants: In collaboration with BHGE, Eni has developed an innovative low viscosity oil for turbomachinery sector, Eni OTE GT 15, that showed outstanding energy saving characteristics by reducing friction losses up to 15%, decreasing the consumption of natural gas and decreasing CO2 emissions. In 2017 Eni OTE GT 15 received the letter of approval by BHGE and is now commercially available.

Renewable Energy & Environment

Concentrated Solar Power. The Eni R&D effort towards the definition and application of improved Concentrated Solar Power (CSP) solutions has led to proprietary technology assemblies with advantageous capital investment and operation costs. A long-term partnership with Massachusetts Institute of Technology and the Politecnico of Milano (that has realized the first proprietary CSP prototype) has allowed the focusing of capabilities for this purpose. The deployment phase is ongoing in the South of Italy, and foreseen in North Africa, Middle East and other suitable areas around the globe.

Luminescent Solar Concentrators and Smart Windows. The possibility of producing partially transparent window devices allowing the transfer of some of the incoming solar radiation towards photovoltaic modules on their sides has allowed the design and commercialization of Smart Window solutions. These produce relevant energy savings for conditioning purposes and electric energy production for small applications. Eni’s Luminescent Solar Concentrator technology is at the core of these devices and other smart applications are currently being explored. To this purpose, in 2017, an agreement with one of the major European building systems company was established. An extensive commercialization phase will begin at the end of 2018.

Organic Photovoltaic. New solutions (active and buffer materials) for flexible solar cells have been developed and applied in an emerging field that relies on organic polymeric photovoltaic solutions. The developed technology solutions allow easy transportation and application wherever power is required and no grid infrastructure is available. Thanks to the light weight and the technical and operational simplicity some photovoltaic modules with inflatable support have been also developed and installed in demonstrative situations.

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Energy storage. The storage of the electric energy produced from renewable sources is indeed a key issue for allowing the further development of this field. Accordingly, Eni is testing solutions for Redox Flow Batteries and for integrating these devices “conventional” electrical energy production devices such as gas turbines and diesel generators in demonstrative plants for off-grid applications. Targeting in these cases a relevant CO2 (higher that 75%) emission reduction.

Phytoremediation. Field tests showed that selected Plant Growth-Promoting Rhizobacteria able to enhance the plants biomass, increasing the uptake of metallic soil contaminants. The usage of these bacteria has been experimented in field tests for promoting the biodegradation of hydrocarbons in polluted environments (Ravenna, Priolo and Mantova).

Hydrocarbon recovery. Eni developed and applied a proprietary technology (e-hyrec®) allowing the remediation of aquifer environments through the recovery and separation of hydrocarbon contaminants. The technology tested at the refinery site in Gela (Italy) is now under application in several fields. An agreement with a manufacturer operating in the water treatment sector has been established with the purpose of deploying the technology in 2017. The full commercialization phase will begin in the second quarter of 2018.

Soil and Groundwater Bioremediation: Eni R&D has developed through laboratory, pilot and field scale tests, technologies and site-specific protocols (e-lamina®) for treating contaminated soils and groundwater utilizing biological, environmental-friendly and cost-effective means. The protocols involve: (i) sampling and site characterization, (ii) evaluation of the bio-degradation potential by micro/meso-cosm test studies, (iii) in situ pilot plant activities, (iv) design and application of full-scale bio-remediation treatments.

Waste to Fuel. Eni is evaluating a Waste-to-Fuel process able to transform wet domestic waste into bio-oils suitable to feed Eni’s biorefineries to obtain second-generation biofuels. The pilot scale development phase of the technology has been completed.

Hybridization of Hydrogen production/utilization for the mobility/fuel sector. The Hydrogen molecule can be produced from several sources including, gaseous hydrocarbons and renewable sources such as bio-mass derived compounds, municipal solid wastes and electrolysis of water utilizing electric energy produced by renewable sources. The “renewable” and the hydrocarbon produced hydrogen can be utilized in the mobility sector directly as fuel in Fuel Cell vehicles or integrated in the refinery hydro-treating processes for producing advanced hydrocarbon fuels. In this sense the production/utilization of Hydrogen allows a full integration of renewable and hydrocarbon refinery pathways for improving the sustainability of the mobility and fuel production sectors.

Energy Transition

In 2016 Eni launched the “Energy Transition” R&D program with the aim of developing new technologies to promote the widespread use of natural gas, making easier its production and transport, widening its uses and favoring the decarbonization of the whole value chain. In particular, the research deals with three areas of interest:

Natural gas transportation, transformation and uses,

H2S management,

CO2 management.

On the forefront of Natural Gas transportation and conversion, important results have been obtained for the development of a process for the production of methanol from natural gas. The process is based on an Eni proprietary technology for the conversion of methane to syngas, which is cheaper and has a footprint and a weight much lower than the existing processes based on steam reformer.

In the area of H2S and CO2 capture, innovative highly effective solvents for the separation of H2S and CO2 from natural gas have been identified and tested at lab scale. Now the results is under scaling-up to a pilot unit with the cooperation of an external specialized company. New ways for sulphur utilization are under consideration. Innovative sulphur-based products which can be used in agriculture have been obtained and are under testing in a field parcel in Central Italy.

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Concerning CO2 management, the project about on-board CO2 capture from autovehicles, launched in 2016 with the close collaboration of MIT, has generated interesting results and new patents. Since 2017 Fiat-Chrysler-Automobiles has joined the project, whose goal has been extended to the construction of a demonstration vehicle equipped with on-board CO2 capture system by the spring 2019. The target for the first demonstration unit is for a 25% capture of the total CO2 emitted by the internal combustion engine that is stored in liquid phase in a dedicated on-board tank. Innovative uses for CO2 are also under investigation. Promising materials, which could be employed in the building and construction industry have been obtained by “CO2 mineralization”, as well as polymers with high CO2 content.

Petrochemicals

Guayule. Project aiming at the production of natural latex, dry rubber and resins from Guayule (ongoing experimental cultivation in Basilicata and Sicily) with exploitation of all components with proprietary technologies and their development in the market allowing the use of whole value of the Guayule plant.

An important agreement has been signed with one of the most important international player in the field of tire manufacturing for the joint development of a common technology platform for guayule production and applications.

Bio-butadiene. A joint venture between Versalis and Genomatica has developed a process to produce 1,3 bio-butadiene from renewable sources via sugars production from biomasses, fermentation and subsequent chemical processes.

Insurance

In order to control the insurance costs incurred by each of Eni’s business units, the Company constantly assesses its risk exposure in both Italian and foreign activities. The Company has established a captive subsidiary, Eni Insurance DAC, in order to efficiently manage transactions with mutual entities and third parties providing insurance policies. Internal insurance risk managers work in close contact with business units in order to assess potential underlying business and other types of risks and possible financial impacts on the Group results of operations and liquidity. This process allows Eni to accept risks in consideration of results of technical and risk mitigation standards and practices, to define the appropriate level of risk retention and, finally, the amount of risk to be transferred to the market. Eni enters into insurance arrangements through its shareholding in the Oil Insurance Ltd (OIL) and with other insurance partners in order to limit possible economic impacts associated with damages to both third parties and the environment occurring in case of both onshore and offshore accidents. The main part of this insurance portfolio is related to operating risks associated with oil&gas operations which are insured making use of insurance policies provided by the OIL, a mutual insurance and re-insurance company that provides its members with a broad coverage of insurance services tailored to the specific requirements of oil and energy companies. In addition, Eni uses insurance companies who it believes are established in the marketplace. Insured liabilities vary depending on the nature and type of circumstances; however, underlying amounts represent significant shares of the plafond granted by insuring companies. In particular, in the case of oil spills and other environmental damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to $1.2 billion for offshore events and $1.4 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: $1,250 million for the fleet owned by the subsidiary LNG Shipping in the Gas & Power segment and time charters; $1 billion for FPSOs used by the Exploration & Production segment for developing offshore fields.

Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses. However, considering the limited capacity of the insurance market, we believe that Eni could be exposed to material uninsured losses in case of catastrophic incidents, like the one occurred in the Gulf of Mexico in 2010 which could have a material impact on our results, liquidity prospects, share price and reputation. See “Item 3 – Risk factors – Risk associated with the exploration and production of oil and natural gas”.

Environmental matters

Environmental regulation

Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil&gas operations, products and other activities, including

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legislation that implements international conventions or protocols. In particular, exploration, drilling and production activities require acquisition of a special permit that restricts the types, quantities and concentration of various substances that can be released into the environment. The particular laws and regulations can also limit or prohibit drilling activities in the certain protected areas or provide special measures to be adopted to protect health and safety at workplace and health of communities that could have been affected by the Company’s activities. These laws and regulations may also restrict emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemical plants, refineries, pipeline systems and other facilities that Eni owns. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Environmental laws and regulations have a substantial impact on Eni’s operations. Some risk of environmental costs and liabilities is inherent in certain operations and products of Eni, and there can be no assurance that material costs and liabilities will not be incurred. See “Item 3 – Risk factors”.

We believe that the Company will continue to incur significant amounts of expenses in order to comply with pending environmental, health and safety protection and safeguard regulations, particularly in order to achieve any mandatory or voluntary reduction in the emission of GHG in the atmosphere and cope with climate change and water quality of discharges, as well as availability.

European Union Environmental Laws Framework

In 2017, the main environmental efforts of the European Union continued to focus on the air quality, energy transition, circular economy, clean mobility, energy efficiency and climate change.

On November 4, 2016, the Paris Agreement entered into force, exactly 30 days after the date on which the last of at least 55 Parties to the Convention accounting in total for at least an estimated 55% of the total global greenhouse gas emissions have deposited their instruments of ratification. To date, the 175 Parties have ratified the Convention. This important step in the common international Climate Change strategy sets out a global action plan to put the world on track to avoid dangerous climate change by limiting global warming to well below 2°C. By the ratification of the Convention, the governments agreed to limit the increase to 1.5°C, since this would significantly reduce risks and the impacts of climate change. In 2017, the UN Climate Change Conference (COP 23) had taken place in Bonn. The COP 23 was the next step for governments to implement the Paris Agreement and accelerate the transformation to sustainable, resilient and climate-safe development. This conference further clarified the enabling frameworks that will make the agreement fully operational and the support needed for all nations to achieve their climate change goals. The participated countries had continued to negotiate the finer details of how the agreement will work from 2020 onwards. In particular the “Talanoa Dialogue” was proposed and the a large group of participate states (among them also Italy, Denmark, Finland) have joined the “Powering Past Coal Alliance” declaring “analysis shows that coal phase-out is needed no later than by 2030 in the OECD and EU28, and no later than by 2050 in the rest of the world”.

On October 4, 2016, the European Parliament approved the ratification of the Paris Agreement by the European Union. The Paris Convention vindicates the EU strategy in climate change defined in October 2014, when the European Council agreed on the 2030 climate and energy policy framework. In this strategy the EU stated an ambitious economy-wide domestic target of at least 40% GHG reduction for the period up to 2030 (below 1990 levels) and to a 27% share of renewable energy in final energy consumption.

On November 30, 2016, the following step of this strategy was written down, when the EU Commission presented the Clean Energy for All Europeans (so called “Clean Energy Package”). By this proposal, the EU is consolidating the enabling environment for the transition to a low carbon economy through a wide range of interacting policies and instruments reflected under the Energy Union Strategy. The Package has three main goals: putting energy efficiency first, achieving global leadership in renewable energies and providing a fair deal for consumers. The Package includes a proposal to revise Directive 2012/27/EU on Energy Efficiency (EED) with the goal to adapt the existing Directive in order to meet EU climate and energy targets for 2030 and align it with other aspects of the Clean Energy package, including a revised Energy Performance of Buildings Directive (EPBD), a recast directive on the Promotion of Renewable Energy Sources – Directive 2009/28/CE (RED II) and a new regulation on Governance of Energy Union. The latest progresses were made during the plenary session of the European parliament on the 17th January 2018, the outcome was not exactly in line with the position expressed by the commission

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one month earlier. The agreement is to be found for the targets to be achieved by 2030: binding EU-level targets of 35% improvement in energy efficiency; a minimum 35% share of energy from renewable sources in gross final consumption of energy (vs. a previous proposal of just 27%); and a 12% – 14% share of energy from renewable sources in transport. To meet these overall targets, EU member states are asked to set their own national targets, to be monitored and achieved in line with a draft law on the governance of the Energy Union. The contribution of so-called “first generation” biofuels (made from food and feed crops) should be capped, according to the parliament proposal to 2017 levels, with a maximum of 7% in road and rail transport as well has been considered a complete phase out of palm oil in transport fuels by 2021 No bans of palm oil is foreseen according to the EU commission position. On the other hand, the development of second generation biofuels is expected with 1.5% target at 2021 and 10% at 2030.

EU Council, Commission and parliament are expected to find a common position the soonest, since the legislative process on the Clean Energy Package is expected to be completed by the end of 2018. For Eni’s strategies and policy on biofuels, a revision of RED has a particular importance.

Moreover, under the energy market reform, in February 2018 MEPs have decided to impose rules on mechanisms often used as coal power subsidies, voting in favor of strict conditions for so-called capacity mechanisms, which will no longer be eligible for subsidies as of 2020 for new infrastructure and as of 2025 for existing plants. The Commission’s proposal that suggested excluding any plants that emit more than 550g of CO2 per kwh from public money, emerged as one the main points of the EU climate legislation. The 550g criterion, uses in the European Investment Bank’s policy, is technology neutral and in practice preclude coal power plants and some inefficient gas plants. It faced heavy opposition from coal-dependent member states like Poland in a recent Energy Council and will be discussed during upcoming negotiations.

A centerpiece of the EU’s 2030 energy and climate policy framework is the binding target to reduce overall GHG emissions by at least 40% below 1990 levels by 2030. To achieve this cost-effectively, the sectors covered by the EU Emission Trading System (ETS) will have to reduce their emissions by 43% compared with 2005, while non-ETS sectors will have to reduce theirs by 30%. The ETS is now in the last years of the III phase (2013-2020). In July 2015, the European Commission published its proposal to revise the directive on the EU ETS for the 2021-2030 period (Phase IV) and on February 2018, the European Council formally approved the reform of the EU ETS for phase IV to ensure the energy sector and energy intensive industries deliver the emissions reductions needed. To this end, the overall number of emission allowances will decline at an annual rate of 2.2% from 2021 onwards, compared to 1.74%. Currently around 48% of Eni’s direct GHG emissions are included within the Carbon Pricing Scheme by its participation in the EU ETS.

On 21 December, representatives of the Estonian Presidency and the European Parliament reached a provisional deal on the effort sharing regulation to ensure further emission reductions in sectors falling outside the scope of the EU emissions trading system (ETS) for the period 2021-2030. In January 2018, EU ambassadors gave their support to the provisional agreement. The text has now to be approved by the European Parliament. This agreement brings the EU closer to fulfilling its Paris climate commitment of an at least 40% cut in greenhouse gas emissions by 2030 compared to 1990 levels. The regulation aims to ensure that the non-ETS sectors emissions reduction target of 30% by 2030 compared to 2005 levels is reached in the effort sharing sectors, including buildings, agriculture (non-CO2 emissions), waste management and transport (excluding aviation and international shipping).

Air quality remains at the center of the European environmental policies and strategies. On December 18, 2013, the European Commission adopted a package of proposals to improve air quality in the EU, which updated the air policy objectives for 2020 and 2030. The package includes a long-awaited revision of the National Emission Ceilings (NEC) Directive, a proposal to address emissions from medium scale combustion plants (MCP) and a proposal for ratification of the recently amended Gothenburg Protocol.

In order to guarantee better quality standards and to shift toward a low carbon economy, in December 2017, the Commission has launched the Clean Mobility Package. This is a decisive step forward in implementing the EU’s commitments under the Paris Agreement for a binding domestic CO2 reduction of at least 40% till 2030. Its aim is to help accelerate the transition to low- and zero emissions vehicles, through a new target for the EU fleet wide average CO2 emissions of new passenger cars and vans of 30% by 2030 to provide stability and long-term direction. The Mobility Package has a 2025 intermediary target of 15% to ensure that investments kick-start already now. As the confirmation of Eni’s involvement in sustainable mobility in November Eni and FCA have signed a contract to carry out research and develop technological applications aimed at reducing CO2 emissions in road transport.

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On December 31, 2016, the new National Emissions Ceilings (NEC) Directive entered into force. The NEC directive based on a Commission proposal sets stricter limits on the five main pollutants in Europe: sulfur dioxide (SO2), nitrogen oxides (NOx), ammonia (NH3), volatile organic compounds (VOC) and primary particulate matter (PM). The NEC Directive must be transposed by the Member states by 30 June 2018. The new NEC directive repeals and replaces Directive 2001/81/EC. Each EU Member State is required to produce a National Air Pollution Control Program by 31 March 2019 setting out the measures it will take to ensure compliance with the 2020 and 2030 reduction commitments.

On December 18, 2015, the Directive No. 2015/2193/EU on the limitation of emissions of certain pollutants into the air from medium combustion plants entered into force. The Medium Combustion PlanT Directive (MCP Directive) regulates pollutant emissions from the combustion of fuels in plants with a rated thermal input equal to or greater than 1 MW and less than 50 MW. The MCP Directive is a part of the Clean Air Policy Package adopted on December 18, 2013 and it regulates emissions of SO2, NOX and dust into the air with the aim of reducing those emissions and the risks to human health and the environment they may cause. The MCP Directive will have to be transposed by Member States by December 19, 2017. The MCP Directive also ensures implementation of the obligations arising from the Gothenburg Protocol under the UNECE Convention on Long-Range Trans-boundary Air Pollution.

The Industrial Emission Directive (IED) 2010/75/EU is fundamental for European industries, it provides the framework for granting permits for about 50,000 industrial installations across the EU. It lays down rules on the integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are defined by the sector specific and cross-sector Best Available Technology (BAT) Conclusions.

In 2016, the Commission has published the Implementing Decision (EU) 2016/902 of 30 May 2016 establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU, for common wastewater and waste gas treatment/management systems in the chemical sector.

In August 2017 the Commission Implementing decision 2017/1442 of 31 July 2017 entered in force. The decision establishes the best available techniques (BAT) conclusions, under Directive 2010/75/EU of the European Parliament and of the Council, for large combustion plants (LCP – combustion installations with a rated thermal input exceeding 50 MW). Plants with a thermal input lower than 50 MW are, however, discussed in the LCP BAT where technically relevant because smaller units can potentially be added to a plant to build one larger installation exceeding 50 MW. In December 2017, the Large Combustion Plant Best Available Technique reference document (LCP BREF) was published. The update of both documents was expected under the Emission Directive and will have a significant implication on the Eni’s technologies applied in the power plants. A Technical Working Group has been formed to implement a new Best Available Techniques Guidance Document on the upstream hydrocarbon exploration and production sector. Moreover, in November, Commission has published its implementing decision establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU of the European Parliament and of the Council, for the production of large volume organic chemicals (LVOC BAT). New emissions and efficiency standards will help national authorities to lower the environmental impact of the 3,200 installations that produce Large Volume Organic Chemicals (LVOC) and represent 63% of the EU’s entire chemical industry.

In 2017 (at the latest on May 16) all Member States must apply the rules of the new Environmental Impact Assessment Directive 2014/52/EU (EIA). The EIA Directive should simplify the rules for assessing the potential effects of projects on the environment and boarders scope of the EIA covering new issues such as climate change, biodiversity, resource efficiency and risks prevention on both human and environmental aspects.

Fluorinated gases (‘F-gases’) play an important role in the accomplishment of the Paris Agreement and in the EU environmental policy. These ozone-depleting substances are regulated by F-gas Regulation (No. 517/2014) which applies from January 1, 2015. The new regulation strengthens the previous measures and should cut by 2030 the EU’s F-gas emissions by two-thirds compared with 2014 levels. This represents a fair and cost-efficient contribution by the F-gas sector to the EU’s objective of cutting its overall GHG emissions by 80-95% of 1990 levels by 2050. In 2017, the EU continued to shape the F-gases strategy. In October 2017, the Commission Implementing Decision (EU) 2017/1984 was published in the Official Journal. The decision sets a reference values for the period 1 January 2018 to 31 December 2020 for each producer or importer which has lawfully placed on the market hydrofluorocarbons from 1 January 2015 UE of 24 October 2017.

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Moreover, in October 2016 the Kigali amendment to the Montreal Protocol (on Substances that Deplete the Ozone Layer) was signed in Rwanda. In July 2017, the EU formally ratified the Kigali Amendment to the Montreal Protocol, which aims to gradually reduce global production and consumption of hydrofluorocarbons (HFCs). Implementation of the agreement is expected to prevent up to 80 billion tonnes CO2 equivalent of emissions by 2050, which will make a significant contribution to the Paris Agreement. The EU member states, like other developed countries, are required to start the first reductions in 2019.

During the reporting year, the EU focused on improving the environmental management principles and rule. In December, the Commission published the decision, amending the user’s guide setting out the steps needed to participate in EMAS (decision 2017/2285). The guidelines offer an additional information and guidance about the steps needed to participate in EMAS, which represents the voluntary participation by organizations in a Community eco-management, and audit scheme. In November, Commission Guidelines on Environmental Impact Assessment (EIA) were released (they include three parts: Guidance Document on Screening, Guidance Document on Scoping and Guidance Document on the preparation of the EIA Report). The Commission has updated and revised the 2001 EIA Guidance Documents to reflect both the legislative changes brought by 2014/52/EU and the current state of good practice. In February 2018, the working group of experts has started the revision of the ISO 14067 standard that specifies principles, requirements and guidelines for the quantification and communication of the carbon footprint of a product (CFP), based on International Standards on life cycle assessment.

In 2015 the European Commission adopted the Circular Economy Package, which includes revised legislative proposals on waste to stimulate Europe’s transition towards a circular economy which emphasizes the need to move towards a lifecycle-driven ‘circular’ economy, with a cascading use of resources and residual waste that is close to zero. As part of a shift in EU policy towards a circular economy, the European Commission made four legislative proposals introducing new waste-management targets regarding reuse, recycling and landfilling. The proposals also strengthen provisions on waste prevention and extended producer responsibility, and streamline definitions, reporting obligations and calculation methods for targets. In 2017, the consensus on the Circular Economy has grown significantly in EU. In December 2017, the negotiators from the European Parliament and EU member states reached an agreement and the circular economy package should be approved in the second quarter of 2018, by both the European parliament and Member States. In January 2018, the first Europe-wide strategy on plastics was adopted. By 2030, all plastics packaging should be recyclable. The strategy also highlights the need for specific measures, possibly a legislative instrument, to reduce the impact of single-use plastics, particularly in the seas and oceans. The O&G sector will have to put a significant effort to follow the “circular philosophy” by investing in innovative technological solutions, optimization of the water use, energy efficiency and the green procurement.

European Union Health and Safety Laws Framework

Legislative Decree No. 81/2008 concerned the protection of health and safety in the workplace and was designed to regulate the work environments, equipment and individual protection devices, physical agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances (chemical agents, carcinogenic substances, etc.), biological agents and explosive atmosphere, the system of signs, video terminals. Eni worked on the implementation of the general framework regulations on health and safety concerning prevention and protection of workers at national and European level to be applied to all kinds of workers and employees.

On June 1, 2007, the REACH Regulation of the European Union (EC No. 1907/2006 of December 18, 2006) entered into force. REACH stands for Registration, Evaluation, Authorization and Restriction of Chemicals and was adopted to improve the protection of human health, safety and the environment from the risks that can be posed and caused by chemicals, while enhancing the competitiveness of the EU chemical industry. It also promotes alternative methods for the assessment of hazardous substances in order to reduce the number of tests on animals. REACH places the burden of proof on companies. To comply with the regulation, companies must identify and manage the risks linked to the substances they manufacture and market in the EU. They have to demonstrate to the European Chemicals Agency (ECHA) how the substance can be safely used and communicate risk management measures to users. If the risks cannot be managed, Authorities can restrict the use of substances in different ways. Over time, hazardous substances should be substituted with less dangerous ones. The deadline of the REACH registration

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depends on the tonnage band of a substance and the classification of a substance; next and last deadline is 2018. Eni recognizes the importance of the Regulation EC No. 1907/2006 (REACH), the general principles of which are already an intrinsic part of the Company’s commitment to sustainability and are an integral part of the culture and history of the Company. The compliance with the REACH requirements and the involvement of all the interested parties in the Company are coordinated and supervised by the HSEQ function. In particular, Eni is involved in the registration of substances to ECHA which regards a complex series of information about the characteristics of such substances and their uses and in another fundamental aspect that concerns the exchange of information between producers and importers, as well as the users of chemical substances (“downstream users”).

The CLP Regulation (Classification, Labeling and Packaging) entered into force in January 2009 (Regulation EC No. 1272/2008 on the classification, labeling and packaging of substances and mixtures), and the method of classifying and labeling chemicals introduced is based on the United Nations’ Globally Harmonized System. The Regulation will replace two previous pieces of legislation, the Dangerous Substances Directive and the Dangerous Preparations Directive. The CLP Regulation ensures that the hazards presented by chemicals are clearly communicated to workers and consumers in the European Union through classification and labeling of chemicals. Before placing chemicals on the market, the industry must establish the potential risks to human health and the environment of such substances and mixtures, classifying them in line with the identified hazards. The hazardous chemicals also have to be labeled according to a standardized system so that workers and consumers know about their effects before they handle them.

European institutions have also increased their activities in the area of environmental protection in the field of hydrocarbon extraction.

On June 12, 2013, the Directive No. 2013/30/EU was issued with the aim of replacing the existing National Legislations and uniform the legislative approach at European level. The main elements of the EU Directive are the following:

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The Directive introduces licensing rules for the effective prevention of and response to a major accident. The licensing authority in Member States will have to make sure that only operators with proven technical and financial capacities are allowed to explore and produce oil&gas in EU waters. Public participation is expected before exploratory drilling starts in previously un-drilled areas.

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Independent national competent authorities, responsible for the safety of installations, are in charge of verifying the provisions for safety, environmental protection, and emergency preparedness of rigs and platforms and the operations conducted on them. Enforcement actions and penalties apply in case of non-compliance with the minimum set standards.

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Obligatory emergency planning calls for companies to prepare reports on major hazards, containing an individual risk assessment and risk-control measures, and an emergency response plan before exploration or production begins. These plans have to be submitted to National Authorities.

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Technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation.

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Companies are required publish on their websites information about standards of performance of the industry and the activities of the national competent authorities, as well as reports of offshore incidents.

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Companies are required prepare emergency response plans based on their rig or platform risk assessments and keep resources at hand to be able to put them into operation when necessary. These plans are periodically tested by the industry and National Authorities.

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Oil and gas companies are fully liable for environmental damage caused to the protected marine species and natural habitats. For damage to waters, the geographical zone is extended to cover all EU waters including the exclusive economic zone (about 370 km from the coast) and the continental shelf, where the coastal Member States exercise jurisdiction. For water damage, the present EU legal framework for environmental liability is restricted to territorial waters (about 22 km offshore).

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Operators working in the EU are required to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations.

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We believe that Eni operations are currently in compliance with all those regulations in each European country where they have been enacted.

Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices would trigger cost increases to comply with new HSE standards. Eni exploration and development plans to produce hydrocarbon reserves and drilling programs could also be affected by changing HSE regulations and industrial practices. Lastly, the Company expects that production royalties and income taxes in the oil&gas industry will probably increase in future years.

Moreover, in order to achieve the highest safety standards of our operations in the Gulf of Mexico, Eni entered into a consortium led by Helix that worked at the containment of the oil spill at the Macondo well. The Helix Fast Response System performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline.

Worldwide Eni approach was to join international consortiums for main equipment and to develop in-house technologies to improve the intervention capability. Eni Emergency Response Kit consists of:

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Outsourced equipment contracted by Eni Head Quarter;

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Access Agreement to Subsea Capping Equipment consortium;

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Access Agreement to Global Dispersant Stockpile consortium;

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Eni Head Quarter proprietary equipment;

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Rapid Cube;

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Killing System.

As regards major accidents, the Seveso III (Directive No. 2012/18/EU) was adopted on July 4, 2012 and entered into force on August 13, 2012. Italy has transposed it into national legislation through the Legislative Decree No. 105/2015 (June 26, 2015).

The main changes in comparison to the previous Seveso Directive are:

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technical updates to take into account the changes in EU chemical classification, mainly regarding the 2008 European CLP Regulation of substances and mixtures;

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expanded public information about risks resulting from Company activities;

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modified rules in participation by the public in land-use planning projects related to Seveso plants; and

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stricter standards for inspections of Seveso establishments.

Eni has carried out specific activities aimed at guaranteeing the compliance of its own industrial sites.

HSE activity for the year 2017

Eni is committed to continuously improving its model for managing health, safety and environment issues across all its businesses in order to minimize risks associated with its own industrial activities, ensure reliability of its industrial operations and comply with all applicable rules and regulations.

In 2017, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. The total number of certifications achieved was 305, of which:

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98 certifications according to the ISO 14001 standard;

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11 registrations according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union);

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21 certifications according to the ISO 50001 standard (certification for an energy management system);

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101 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems – requirements);

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38 according to the ISO 9001 standard (certification of the quality management system).

In 2017 the percentage of Eni industrial installations and operating units with a significant HSE risk covered by certification is 97% for the OHSAS 18001 and ISO 14001 standards.

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In 2017, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to €1,101 million, in line with 2016.

Environment. In 2017, Eni incurred total expenditures of €756.16 million for the protection of the environment (with an increase of 28.5% with respect to 2016). Environmental expenditures are mainly related to remediation and reclamation activities (€260.7 million), waste management (€225.8 million), water management (€99.7 million), air protection (€55.1 million) and spill prevention (€53.4 million).

Safety. Eni is committed to safeguarding the safety of its employees, contractors and all people living in the areas where its activities are conducted and its assets located. In 2017, the new legislation didn’t impact significantly procedures already in place for safety in the workplace.

The dissemination of safety culture is a primary target for Eni. In 2017, in order to increase safety’s culture in the workforce, awareness-raising initiatives continued. Road Shows and Safety Day were organized with the aim of sharing performance, target, new projects and safety vision between Eni’s top management and employees and contractors.

In order to keep developing new awareness raising actions regarding safety at work, in 2017 two initiatives, launched in 2016, continued:

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“Inside Lesson Learned Project” to share lessons learned using video clips made by internal resources and inspired by real events occurred in the company;

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“Eni in Safety 2” to increase safety culture with workshops finalized to discuss safe behaviors, responsibility and leadership in safety involving employees and contractors.

In 2013, Eni launched an initiative aimed at issuing work permits in electronic form for standardizing and improving the related risk assessment process. The initiative is progressively involving all the operating sites.

In 2015, Eni developed the Company Process Safety Management System for increasing the safety of its operations through still higher technical and management standards. Starting from 2016 and in following years these standards are applied progressively in all operating activities.

Results of efforts to achieve a better safety in all activities brought an improvement of Eni workforce total recordable injury rate (0.33), decreased by 6.8% compared to 2016.

Regarding emergency preparedness, Eni has joined the Oil Spill Response-Joint Industry Project (OSR-JIP I & II) which was launched in December 2011 by International Association of Oil&Gas Producers (IOGP) and International Petroleum Industry Environmental Conservation Association (IPIECA) and concluded in 2016. The JIP executed the outstanding recommendations from the report produced by the Global Industry Response Group (GIRG) set-up after the Macondo accident.

The JIP aimed at:

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providing a forum for industry to share knowledge on the science, tools and techniques;

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representing the industry on approaches for oil spill preparedness and response, working closely with other associations on communications with both national and global regulatory groups;

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engaging pro-actively in broader outreach and communication.

The OSR-JIP carried out specific projects dealing with exercise planning, in situ burning, dispersants advocacy-subsea, efficacy-post spill monitoring, upstream risk assessment and response capability, etc., publishing 11 Research Reports, 9 Technical Reports and 24 Good Practice Guidance during 2017 the translation into various languages (Italian for example) was completed..

Costs incurred in 2017 to support the safety levels of operations and to comply with applicable rules and regulations were €249.8 million.

Health. Eni’s activities for protecting health aim to continuously improve the psychophysical wellbeing of people in the workplace. Eni believes that it achieved a good performance in this area thanks to:

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plant and facility efficiency and reliability;

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promotion and dissemination of knowledge, adoption of best practices and operating management systems based on advanced criteria of protection of health and internal and external environment;

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certification programs of management systems for production sites and operating units;

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identified indicators in order to monitor exposure to chemical and physical agents;

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strong engagement in health protection for workers operating worldwide also with the support of international health providers capable of guaranteeing a prompt and adequate response to any emergency;

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identification of an effective and reliable health providers, in Italy and abroad;

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training programs for medics and paramedics.

In order to protect the health and safety of its employees, Eni relies on a network of health care facilities located in its main operating areas. A set of international agreements with the best local and international health providers ensures efficient services and timely responses to emergencies.

Eni is engaged to the elaboration of HIA and relative standards to be applied to all new projects of evaluation of working exposure to environment, in Italy and abroad. The main aim of HIA is to avoid any negative impacts and maximize any positive impacts of the project on the host community and it is usually carried out as part of/or in conjunction with the Health, Environmental and a Social Impact Assessment process. Its results are used to develop appropriate mitigation measures and an improvement plan with the host community.

In 2017 Eni had a big expansion towards the green economy with the transformation of some traditional refineries into green ones for the development of green products; this saw a big involvement in evaluation and registration of green products.

Path to decarbonization

Eni intends to play a leading role in the energy transition process, supporting the objectives of the Paris Agreement.

Eni has been committed for a long time to promoting full and effective disclosure on climate change and is the only company in the Oil & Gas industry to take part in the Task Force on Climate-related Financial Disclosures (TCFD) of the Financial Stability Board. In June 2017 the latter published its voluntary recommendations to encourage effective disclosure of the financial implications of climate change; Eni is committed to a gradual implementation of these recommendations.

Below is a Dashboard which shows the reports/documents containing climate information based on the four areas covered by the TCFD recommendations and the relevant level of detail.

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Recommendation	ANNUAL REPORT ON FORM 20-F (Management Discussion)	SUSTAINABILITY REPORT [Addendum Eni For]
GOVERNANCE
Disclose the organization’s governance around climate-related risks and opportunities.	√ Key elements	√

STRATEGY
Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s businesses, strategy, and financial planning where such information is material.	√ Key elements	√

RISK MANAGEMENT
Disclose how the organization identifies, assesses, and manages climate-related risks.	√ Key elements	√

METRICS & TARGETS
Disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities where such information is material.	√ Key elements	√

Governance

Eni’s decarbonization strategy is part of a structured system of Corporate Governance; within this, the Board of Directors (BOD) and the Chief Executive Officer (CEO) play a central role in managing the main aspects linked to climate change.

The BOD examines and approves, based on the CEO’s proposal, the strategic plan which defines strategies and includes objectives also on climate change and energy transition; every six months it is also informed on the progress of the main projects, where the operating, economic and financial key performance indicators (KPIs) are reported.

Since 2014, the BOD has been supported in conducting its duties by the Sustainability and Scenarios Committee (CSS), which examines, on a periodic basis, the integration between strategy, future scenarios and the medium to long-term sustainability of the business. During 2017, at all twelve CSS meetings, detailed discussions were held on aspects related to decarbonization strategy, energy scenarios, renewable energy, R&D to support energy transition and climate partnerships.

Since the second half of 2017, the BOD and the CEO are also supported by an Advisory Board, composed of international experts, focused on topics related to the decarbonization process.

The CEO also chairs the Steering Committee of the Climate Change Program, a cross-functional working group composed of members of Eni’s top management with the aim of developing and monitoring appropriate medium/long-term decarbonization strategies. The CEO’s short-term monetary plan has a weight of 12.5% to the objective of reducing the intensity of upstream GHG emissions in line with the long term target; the same objective has been given to all the managers who have a strategic role on this matter.

As evidence of the attention paid to climate change and the clear decarbonization strategy embarked upon, in 2015 a business unit dedicated to the development of renewable energy (Energy Solutions Department) was established, directly reporting to the CEO.

Among the many international climate initiatives that Eni participates in, Eni’s CEO has a leading role in the Oil and Gas Climate Initiative (OGCI); in 2014 Eni was one of the five founding companies of the initiative which now counts ten companies, representing more than 25% of the global hydrocarbon production. The OGCI is currently engaged in the joint investment of $1 billion over 10 years in the development of technologies to reduce GHG emissions along energy value chain.

Eni has also been actively involved, since the start of its work, in the Task Force on Climate Related Financial Disclosure (TCFD), set up by the Financial Stability Board with the aim of defining recommendations for company’s climate change disclosure, published during 2017.

In 2017, based on its strategies and actions, Eni was confirmed as a climate change leader by CDP (ex Carbon Disclosure Project), the main independent rating agency that assesses international companies with a high market capitalization.

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Risk Management

Eni has developed and adopted an Integrated Risk Management (IRM) Model to ensure that management takes risk-informed decisions, taking fully into consideration current and potential future risks, including medium and long-term ones, as part of an organic and comprehensive vision. The model also aims to raise awareness, at all company levels, that appropriate risk assessment and management has an important effect on the achievement of company objectives and values.

The process is implemented using a “top-down risk based” approach, starting from the contribution to the definition of Eni’s Strategic Plan, by means of analyses that support the understanding and evaluation of the likelihood of underlying risk (e.g. definition of specific de-risking objectives) and continue with the support for its implementation through periodic risk assessment & treatment cycles and monitoring. Risk prioritization is carried out on the basis of multi-dimensional matrices which measure the level of risk by combining clusters of probability of occurrence and impact.

The risk of Climate Change is identified as one of Eni’s top strategic risks and is analysed, assessed and monitored by the CEO as part of the IRM process. The analysis is carried out using an integrated and cross-cutting approach which involves specialist departments and business areas and considers both aspects correlated with energy transition (market scenario, regulatory and technological developments, reputation issues) and physical aspects (extreme/chronic weather and climate phenomena), as described in the Strategy section.

Strategy

Main risks and opportunities

The climate change risk is analysed taking into account five drivers for which the main results are shown below.

Market scenario. In a low carbon scenario, as in the IEA SDS6 (WEO 2017), the role of fossil fuels remains central to the energy mix. Natural gas, that increases also in the SDS scenario, represents an opportunity for strategic repositioning for oil&gas companies, due to its lower carbon intensity and the possibility of integration with renewable sources in electricity production. Although the IEA SDS scenario foresees the oil demand reaching a peak in around 2020 and going down to 75 Mb/d in 2040, the need for significant investments in the upstream sector to compensate for the drop in production from existing fields. There is residual uncertainty linked to the effect that regulatory developments and breakthrough technologies could have on the scenario, with a consequent impact on the company business model.

Regulatory developments. The adoption of policies (e.g. reduction of emissions, also from deforestation; carbon pricing; development of renewable sources; energy efficiency; diversification of electricity production; advanced biofuels; electric vehicles; etc.) designed to support energy transition to low carbon sources could have significant impacts on the business. The differentiated approach by country could provide an advantage for the development of new business opportunities.

Technological developments. Technologies to capture and reduce GHG emissions as well as leaks of natural gas along the oil&gas value chain will be fundamental for affirming the dominant role of natural gas in the global energy mix. On the other hand, technological development in the field of renewable energy production and storage and in the efficiency of electric vehicles could have impacts on the demand for hydrocarbons and therefore on the business. The capacity to rapidly intercept and integrate technological breakthroughs in the business will play a key role in business competitiveness.

Reputation. The increasing attention being given to climate change has a negative impact on the reputation of the entire oil&gas industry, seen as one of the main parties responsible for GHG emissions, with effects on the management of relations with the key stakeholders. The ability to develop and implement strategies to adapt the business model to a low-carbon scenario, as well as the capacity to communicate these in a transparent manner provides an opportunity to improve stakeholder perceptions.

Physical risks. The intensification of extreme/chronic weather and climate phenomena could result in an increase in costs (including insurance) for adaptation measures to protect assets and people. The IPCC (Intergovernmental Panel on Climate Change) scenarios predict that these physical effects will manifest themselves mainly over the medium to long term. The exposure to risk is mitigated by the design requirements adopted (defined to resist extreme environmental conditions) and the insurance covers taken out.

International Energy Agency- Sustainable Development Scenario from the World Energy Outlook 2017.

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Strategy and objectives

In relation to the risks and opportunities described above, Eni has defined a path to decarbonization and pursues a clear and well-defined climate strategy, integrated with its business model, which is based on the following drivers:

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reduction in direct GHG emissions; from 2014 to 2017 the actions taken have enabled the GHG emission intensity index of the upstream sector to be reduced by 15%; the goal is to reduce this rate by 43% by 2025 compared to 2014 through projects to eliminate process flaring, reduce fugitive emissions of methane (for the upstream segment by 80% in 2025 compared to 2014) and energy efficiency projects; in total the investments in support of these targets add up to an expenditure of about €0.6 billion in 2018-21, at 100% and with reference only to upstream operated activities;

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“low carbon” oil&gas portfolio characterized by conventional projects developed in stages and with low CO2 intensity. The new upstream projects being executed, which represent about 65% of the total development investments in the sector in the 2018-21 four-year period, have break-even points below 30 $/bl, and are therefore resilient even in low-cabon scenarios. In general, Eni’s portfolio has hydrocarbon resources with a high natural gas percentage, a bridge towards a reduced emissions future. The mid-downstream segment is less exposed to climate change risk, as the net book value of traditional refineries and petrochemical plants is negligible compared to the total assets of the group, while the green component of this business is being developed;

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green business development through i) a growing commitment to renewable energy (approximately 1,000 MW installed power in 2021); ii) development of the second phase of the Venice biorefinery (with a maximum capacity of 560 ktonnes/y from 2021) and the completion of the Gela biorefinery (with maximum capacity of 720 ktonnes/y) by 2018; iii) strengthening of Green Chemistry, with production of bio-intermediates from vegetable oil at Porto Torres (capacity of 70 ktonnes/year), studies, pilot projects and partnerships with other operators. In the 2018 – 2021 four-year period, total investments are expected at more than €1.8 billion, including the scientific and technological development (R&D) activities related to the path to decarbonization;

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commitment to scientific and technological research (R&D), essential for achieving maximum efficiency in the decarbonisation process.

The composition of the portfolio and Eni’s strategy minimize the risk of “stranded assets” in the upstream sector; in this regard, the management has subjected to a sensitivity analysis the book value of all CGUs (Cash Generating Units) in the upstream sector, adopting the IEA SDS scenario; this stress test highlighted the substantial retention of the asset book values, with a reduction of about 4% of the fair value.

Metrics and comments

Below are described the main performances, showing the results achieved by Eni to date in relation to the decarbonization strategy.

In 2017 all the production emission indexes recorded an improvement compared to 2016. In particular, in the E&P sector the GHG intensity index calculated per unit of gross hydrocarbon unit produced – on operatorship basis – fell by 2.7% compared to the previous year, amounting to 0.162 tonCO2eq/toe; the overall variation in the index compared to 2014 is -15%, in line with the target of 43% reduction by 2025. Also in the other sectors, the GHG emission intensity has decreased, in particular Enipower’s emission index has decreased by 0.8% and the refineries’ by 7%.

Since 2010, Eni’s direct emissions on operatorship basis have been reduced by 27%, although last year reported an increase of 2.5% compared to 2016 due to the rise in combustion and process emissions as a result of increased production in the E&P segment (in particular activities in Libya and start-ups in Ghana, Angola and Indonesia) and in G&P (where both electricity production and volumes of natural gas transported have increased). In line with its decarbonisation strategy, during 2017 Eni has purchased and cancelled in its favour 680,193 forestry credits in the international market, thus offsetting about half of the increase in direct emissions compared to 2016.

Compared to Eni’s main GHG emissions sources, since 2014 the volume of hydrocarbons sent to process flaring decreased by 7%. Emissions from flaring increased in the last year, despite the fact that Eni invested €29 million in flaring down projects in 2017 (in particular in Nigeria and Libya). This was due

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both to new start-ups and the restart of the Abu Attifel field in Libya, which was shut down in 2016 due to the difficult situation in the country. Fugitive emissions of methane (equal to about 80% of total methane emissions) have decreased in the E&P and G&P segments, both due to periodic maintenance activities (the so-called LDAR – Leak Detection and Repair campaigns) carried out on sites already subject to monitoring in previous years and the extension of the survey to new sites, with an improvement in the accuracy of emissions estimates based on actual plant configuration. The energy efficiency initiatives carried out in 2017 allow, in full operation, energy savings for around 300 ktoe/year, amounting to a reduction in emissions of approx 0.8 million tonnes of CO2eq. In 2017, Eni invested €9 million in energy efficiency projects.

In 2017, Eni’s investment in scientific research and technological development amounted to €185 million, of which €72 million relating to the Path to Decarbonization. This investment refers to: energy transition, biorefining, green chemistry, renewable sources, emissions’ reduction and energy efficiency.

In 2017, production of biofuels reached 206 thousand tonnes, an all-time record, with an increase of more than 14% over the previous year.

		2017		2016		2015
Key sustainability performance indicators		Operated companies	Fully consolidated entities	Operated companies	Fully consolidated entities	Operated companies	Fully consolidated entities
Direct GHG emissions (Scope 1)	(mln tonnes CO2eq)	42.52	27.04	41.46	26.48	42.32	27.12
of which: CO2eq from combustion and process		32.65	22.61	31.99	22.64	32.22	23.02
of which: CO2eq from flaring		6.83	3.37	5.4	2.49	5.51	2.47
of which: CO2eq from non-combusted methane and fugitive emissions		1.46	0.84	2.4	1.16	2.79	1.34
of which: CO2eq from venting		1.58	0.23	1.67	0.19	1.8	0.3
GHG emisions/100% operated hydrocarbon gross production (E&P)	(tonnes CO2eq/toe)	0.162	0.176	0.166	0.163	0.177	0.19
GHG emissions/kWheq (EniPower)	(gCO2eq/kWheq)	395	398	398	402	409	413
GHG emissions/products (crude oil and semifinished) processed in refineries	(tonCO2eq/kt)	258	258	278	278	253	253
Widespread emissions and methane fugitive emissions (upstream)	(tonCH4)	38,819	19,413	72,644	30,331	91,416	36,763
Volumes of hydrocarban sent to flaring	(MSm3)	2,283	1,262	1,950	1,112	1,989	1,154
of which: sent to process flaring		1,556	594	1,530	767	1,564	774
Net consumption of primary resources	(Mtoe)	13.15	9.06	12.52	8.75	12.76	9.02
Primary energy purchased from other companies	(Mtoe)	0.38	0.33	0.44	0.38	0.38	0.32
Electricity produced by solar panels (EniPower)	MWh	14,720	14,720	13,527	13,527	13,750	13,750
Energy comsuption of producing activities/Hydrocarbon production (100% E&P operated)	(GJ/toe)	1.487	na	1.711	na	1.595	na
Net consumption of primary resources/electricity produced (EniPower)	(toe/MWheq)	0.162	0.163	0.163	0.164	0.168	0.169
Energy Intensity Index (refineries)	(%)	109.2	109.2	101.7	101.7	100.3	100.3
R&D expenditures	(€ million)	185		161		176
of which: new energy		58		51		—
First patent filing applications	(number)	27		40		33
of which filed on renewable sources		11		12		16
Production of biofuels	(ktonnes)	206		181		179
Biorefineries capacity	(ktonnes/year)	360		360		360

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Regulation of Eni’s businesses

Overview

The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments.

Regulation of exploration and production activities

Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements. See “Regulation of the Italian hydrocarbons industry” and “Environmental matters” for a description of the specific aspects of the Italian regulation and of environmental regulation concerning Eni’s exploration and production activities. Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any royalties that are payable in-kind. A license holder is generally required to pay production taxes or royalties, which may be in cash or in-kind. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. In production sharing agreements, entitlements to production volumes are defined on the basis of contractual agreements drawn up with state oil companies holding the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (Cost Oil) and give entitlement to a portion of the production volumes exceeding volumes destined to cover costs incurred (Profit Oil). A similar scheme to PSA applies to Service and “buy-back” contracts. In general, Eni is required to pay income tax on income generated from production activities (whether under a license or PSA). The taxes imposed upon oil&gas production profits and activities may be substantially higher than those imposed on other businesses.

Regulation of the Italian hydrocarbons industry

Exploration & Production

The Italian hydrocarbons industry is regulated by a combination of constitutional provisions, statutes, governmental decrees and other regulations that have been enacted and modified from time to time, including legislation enacted to implement EU requirements (collectively, the “Hydrocarbons Laws”).

Exploration permits and production concessions. Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are the property of the State. Exploration activities require an exploration permit, while production activities require an exploiting concession, in each case granted by the Minister of Economic Development. The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. Upon each of the three-year extensions, 25% of the area under exploration must be relinquished to the State (only for initial acreages larger than 300 square kilometers). The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and additional five-year extensions until the field depletes.

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Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Legislative Decree No. 625 of November 25, 1996, subsequent modifications and integrations and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with fixed amount of exemption. Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties onshore for oil and gas are equal to 20,06%, with no exemptions).

Gas & Power

Natural gas market in Italy

New liberalization measures in Italy

Law Decree No. 1 enacted by the Italian Government on January 24, 2012, the so-called Liberalization Decree, was converted to Law No. 20 on March 24, 2012. This law aimed at:

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enhancing competitiveness in gas tariffs to residential customers and in the distribution of refined products. The ARERA, in charge with setting pricing mechanisms for supplies to final users, starting from the second quarter of 2012 updated the indexation mechanism by gradually increasing the weight of spot prices in the indexation of the supply costs of gas that previously used to be oil-linked; and

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reforming the storage system introducing market-based mechanisms for the allocation of storage capacity, moving away from the traditional “pro-rata”/tariff system, and with the aim to reduce the cost of natural gas for industrial customers. In particular:

for an amount determined by the Ministry itself, storage capacity started to be primarily reserved for the offer to industrial sector of an integrated service (international transport of liquefied natural gas, regasification and storage), thus allowing industrial clients to supply natural gas directly from abroad in the form of liquefied natural gas; and

the remaining amount of storage capacity started to be assigned via auction procedures devoted to the modulation needs.

Based on the principles described above, the Minister of Economic Development and the ARERA establish every year the detailed criteria for the allocation of gas storage capacities.

In 2017, 1,5 BCM of integrated storage and regasification capacity was offered to the industrial sector.

Such integrated service is no longer offered since 2018, due to a new market-based mechanism for allocating regasification capacities in Italy introduced by the Italian regulator.

With three operating LNG regasification terminals, Italy has a lot of regasification capacity, about half of which was not used in 2017. The Adriatic LNG terminal has a capacity of 8 billion cubic metres (BCM)/year, while capacity at OLT and Panigaglia is 3.75 BCM/y and 3.5 BCM/y, respectively. The low interest in accessing to and using regasification capacity on a spot or monthly basis is mainly due to the high level of regasification tariffs in Italy compared to the rest of Europe. The new market-based system for allocating regasification capacity in Italy is working on principles similar to the ones already set for the mechanisms for allocating storage capacity and it is therefore based on auctions that will express the market-value of the regasification capacity.

Such new mechanism is likely to attract more LNG deliveries to the country in the future.

Management believes that these new regulation will increase competition in the wholesale natural gas market in Italy, leading to possible margin pressures.

Negotiation platform for gas trading and gas balancing market and other measures to increase gas market liquidity

In compliance with the provisions of Law No. 99 of July 23, 2009, on March 18, 2010, the Ministry of Economic Development published a decree that implements a trading platform for natural gas starting from May 10, 2010, aimed at increasing competition and flexibility on wholesale markets. Management and organization of this platform (MGAS) are entrusted to an independent operator, the Gestore dei Mercati Energetici (GME), an Italian agency. In the MGAS, parties authorized to carry out transactions at the “Punto di Scambio Virtuale” (PSV – Virtual Trading Point) may make forward and spot purchases and sales of volumes of natural gas. In the MGAS, GME plays the role of central counterparty to the transactions concluded by Market Participants.

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In October 2016 the new gas balancing regime – an evolution of the one already in place – has entered into force in the Italian system in compliance with the EU regulatory framework. This system is based on the principle that network users have to balance their daily position, also in accordance with the timely information provided by Snam Rete Gas about the daily gas consumption. The new gas balancing regime provides for:

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the possibility for shippers to modify intra-day the gas nominations;

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the possibility for shippers to trade on the market with other shippers and/or with the TSO itself (that can access the market under some constraints, in order to address overall system balancing needs that may arise on top of shippers’ activities)

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the incentive for shippers to balance their position via penalizing imbalance prices.

To foster market liquidity, starting from April 2017 all of the above-mentioned gas trading activities were concentrated on the MGAS, managed by GME, as one single platform.

In addition, since February 2018 voluntary market making activity has been introduced in the spot section of the gas exchange MGAS. Such activity is based on the service provided by some Liquidity Providers, in order to boost liquidity and trading activity on the same exchange, initially for the day-ahead market but with possible future extension to the within-day section and to the forward section of the MGAS.

Management believes that these measures have increased, and will further increase, the level of liquidity in the Italian spot market of gas.

Natural gas prices in the retail sector

Following the liberalization of the natural gas sector introduced in the year 2000 by Decree No. 164, prices of natural gas in the wholesale market which includes industrial and power generation customers are freely negotiated. However, the ARERA holds a power of surveillance on this matter (see below) under Law No. 481/1995 (establishing the ARERA) and Legislative Decree No. 164/2000. Furthermore, the ARERA is still entrusted (as per the Presidential Decree dated October 31, 2002) with the power of regulating natural gas prices to residential customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which sell natural gas to residential customers are currently required to offer to those customers the regulated tariffs set by ARERA beside their own price proposals.

In 2013, a new tariff regime was enacted for Italian residential clients who are entitled to be safeguarded in accordance with current regulations. Clients who are eligible for the tariff mechanism set by the ARERA are residential clients (including residential buildings consuming less than 200,000 CM/y). With Resolution No. 196 effective from October 1, 2013, the ARERA reformulated the pricing mechanism of gas supplies to those customers by providing a full indexation of the raw material cost component of the tariff to spot prices versus the previous regime that provided a mix between an oil-based indexation and spot prices.

The new tariff regime intended to partially offset the negative impact born by wholesalers by introducing a pricing component intended to cover the risks and costs of the supplies to wholesalers. Furthermore, it was provided a stability mechanism whereby a wholesaler part of a long-term, take-or-pay gas supply contract could opt to be reimbursed for the possible negative difference between the oil-linked costs of gas supplies and spot prices in the two thermal years following the implementation of the new regime; conversely, in case spot prices fall below the oil-linked cost of gas supplies in the following two thermal years, the same wholesaler had to refund customers of the difference. Based on this compensation mechanism, which expired in September 2016, Eni totaled about €160 million of reimbursement over three thermal years, starting in October 2013 and ending in September 2016.

This tariff regime also reduced the tariff components intended to cover storage and transportation costs. Finally, it also increased the specific pricing component intended to remunerate certain marketing costs incurred by retail operators, including administrative and retention costs, losses incurred due to customer default and a return on capital employed.

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Furthermore, the new tariff mechanism indexed to TTF (Title Transfer Facility) for residential clients will be applicable until the end of thermal year 2017 – 2018.

However, the Law 124/17 provided the complete abrogation of the tariffs for gas and power effective from July 1, 2019. The Law 124/17 will be implemented through a Ministerial Decree that is still under discussion. Referring to the electricity and gas markets, residential customers would choose prices on the free market, potentially, lower than the regulated ones.

Similarly other Regulatory Authorities in European countries where Eni is present have issued regulations referring to hub component in the pricing formulas related to retail clients, as well as measures to boost liquidity and competitiveness in the gas market.

Refining and marketing of petroleum products

Refining. The regulations introduced with Law No. 9/1991 and No. 239/2004 (Article 1, paragraphs 56, 57 and 58) significantly changed the norms introduced in the 1930’s that required that any refining activity be handled under a concession from the State. Today an authorization is required to set up new processing and storage plants and for any change in the capacity of mineral processing plants, while all other changes that do not affect capacity can be freely implemented. Another simplification measure was introduced by Law Decree No. 5/2012 that defined mineral oil processing and storage plants as “strategic settlements” that need authorization from the State, in agreement with the relevant Region, and imposes a single process of authorization that must be closed within 180 days, subject to the authorizations requested by environmental regulations. Management expects no material delays in obtaining relevant concessions for the upgrading of the Sannazzaro and Taranto refineries as planned in the medium term.

Marketing. Following the enactment of the above-mentioned Law Decree No. 1 on January 24, 2012, certain measures are expected to be introduced in order to increase levels of competition in the retail marketing of fuels. The rules regulating relations between oil companies and managers of service stations have been changed introducing the difference between principal and non-principal of a service station. Starting from June 30, 2012, principals will be allowed to freely supply up to 50% of their requirements. In such case, the distributing company will have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also provides for an expansion of non-oil sales. Eni expects developments on this issue to further increase pressure on selling margins in the retail marketing of fuels and to reduce opportunities of increasing Eni’s market share in Italy. Furthermore, the law 205/2017 provides some measures for preventing of tax evasion in the sale of oil products that in the past produced anticompetitive effects on the sector. The law requires the advance payment of Value Added Tax (VAT) on oil products before the extraction from deposits or the sale to consumer.

Service stations. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; and (iv) the opening up of the logistics segment by permitting third-party access to unused storage capacity for petroleum products. With the same goal of renewing the Italian distribution network, Law No. 57 of March 5, 2001 provides that the Ministry of Economic Development is to prepare guidelines for the modernization of the network, and the Regions shall follow those guidelines in the preparation of regional plans. The subsequent Ministerial Decree of October 31, 2001 establishes the criteria for the closing down of incompatible stations, the approval of the plan, the renewal of the network, the opening up of new stations and the regulations of the operations of

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service stations on matters such as automation, working hours and non-oil activities. After the approval of Law No. 133/2008, Article 28 of Law Decree No. 98/2011 converted into Law No. 111/2011, contains new guidelines for improving market efficiency and service quality and increasing competition. Among other things, it requires that from July 6, 20112 all service stations must be provided with self-service equipment and that Regions will update their regulations in order to allow the sale of non-oil products in all service stations. Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside city areas. Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations, which might limit the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the obligation to undertake non-oil activities and the liberalization of opening hours.

The new regulatory framework provided by the legislative decree No 257/2016 – implementing EU Directive 2014/94/UE on alternative fuel infrastructures – could involve a significant development in the fuel market for transport sector.

In order to mitigate environmental impacts of the transport sector, the legislation sets forth minimum requirements for the construction of infrastructure for the development of alternative fuels.

The law includes measures simplifying administrative procedures for the granting of government permits related to the construction of the main logistic infrastructures for the country. The legislation established, furthermore, an adequate number of charging stations accessible to the public to be created throughout the country by 2020

Finally, Law no. 124/2017 aims to promote the structural reorganization of the fuel distribution network also in order to increase competition and efficiency. The law requires the closure of fuel stations that are incompatible with road safety regulations and environmental streamlining procedures for the decommissioning.

Management believes that these measures will favor competition in the Italian retail market and enhance the competitiveness of efficient players.

Petroleum product prices. Petroleum products’ prices were completely deregulated in May 1994 and are now freely established by operators. Oil and gas companies periodically report their recommended prices to the Ministry of Economic Development; such recommendations are considered by service station operators in establishing retail prices for petroleum products.

Compulsory stocks. According to Legislative Decree of January 31, 2001, No. 22 (“Decree 22/2001”) enacting Directive No. 1993/98/EC (which regulates the obligation of Member States to keep a minimum amount of stocks of crude oil and/or petroleum products) compulsory stocks, must be at least equal to the quantities required by 90 days of consumption of the Italian market (net of oil products obtained by domestically produced oil). In order to satisfy the agreement with the International Energy Agency (Law No. 883/1977), Decree No. 22/2001 increased the level of compulsory stocks to reach at least 90 days of net import, including a 10% deduction for minimum operational requirements. Decree No. 22/2001 states that compulsory stocks are determined each year by a decree of the Minister for Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil company on a site-by-site basis. The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC (imposing an obligation on Member States to maintain minimum stocks of crude oil and/or petroleum products), sets forth in particular: (a) that a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development that should be in charge of: (i) the purchase, holding, sell and transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain. As of December 31, 2017, Eni owned 5.4 mmtonnes of oil products inventories, of which 3.5 mmtonnes as “compulsory stocks”, 1.7 mmtonnes related to operating inventories in refineries and deposits (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.2 mmtonnes related to specialty products. Eni’s compulsory stocks were held in term of crude oil (35%), light and medium distillates (35%), refinery feedstock (22%), fuel oil (4%) and other products (4%) were located throughout the Italian territory both in refineries (85%) and in storage sites (15%).

Competition

Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union

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entered into force on December 1, 2009 (“Article 101” and “Article 102”, respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (EU Regulation 139). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self-assessment by the undertakings that such conducts does not infringe the Treaty. In addition, the burden of proving an infringement of Article 101(1) or of Article 102 of the Treaty shall rest on the party or the authority alleging the infringement. The undertaking or association of undertakings claiming the benefit of Article 101(3) of the Treaty shall bear the burden of proving that the conditions of that paragraph are fulfilled. The regulation defines the functions of authorities guaranteeing competition in Member States and the powers of the Commission and of national courts. The Competition Authorities of the Member States shall have the power to apply Articles 101 and 102 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions:

•

requiring that an infringement be brought to an end;

•

ordering interim measures;

•

accepting commitments; and

•

imposing fines, periodic penalty payments or any other penalty provided for in their national law.

National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by the Commission binding on the undertakings; and (iv) find that Articles 101 and 102 of the Treaty are not applicable to an agreement for reasons of Community public interest. Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the “EEA Agreement”), which are analogous to the competition rules of the Lisbon Treaty (ex Treaty of Rome) and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority. In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the “Italian Antitrust Law”). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the Italian Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers.

Property, plant and equipment

Eni has freehold and leasehold interests in real estate in numerous countries throughout the world. Management believes that certain individual petroleum properties are of major significance to Eni as a whole. Management regards an individual petroleum property as material to the Group in case it contains 10% or more of the Company’ worldwide proved oil&gas reserves and management is committed to invest material amounts of expenditures in developing it in the future. See “Exploration & Production” above for a description of Eni’s both material and other properties and reserves and sources of crude oil and natural gas.

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Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

This section is the Company’s analysis of its financial performance and of significant trends that may affect its future performance. It should be read in conjunction with the Key Information presented in Item 3 and the Consolidated Financial Statements and related Notes thereto included in Item 18. The Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards as issued by the IASB.

This section contains forward-looking statements, which are subject to risks and uncertainties. For a list of important factors that could cause actual results to differ materially from those expressed in the forward-looking statements, see the cautionary statement concerning forward-looking statements on page ii.

Executive summary

Key consolidated financial data


		2017		2016		2015
		(€ million)
Net sales from operations from continuing operations			66,919		55,762		72,286
Operating profit (loss) from continuing operations			8,012		2,157		(3,076)
Net profit (loss) attributable to Eni from continuing operations			3,374		(1,051)		(7,952)
Net profit (loss) attributable to Eni from discontinued operations					(413)		(826)
Net profit (loss) attributable to Eni			3,374		(1,464)		(8,778)
Net cash provided by operating activities – continuing operations			10,117		7,673		12,875
Capital expenditures – continuing operations			8,681		9,180		10,741
Disposal of assets, consolidated subsidiaries and businesses			5,455		1,054		2,258
Shareholders’ equity including non-controlling interest at year end			48,079		53,086		57,409
Net borrowings at year end			10,916		14,776		16,871
Net profit (loss) attributable to Eni basic and diluted from continuing operations	(€ per share)		0.94		(0.29)		(2.21)
Dividend per share	(€ per share)		0.80		0.80		0.80
Ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage)(1)			0.23		0.28		0.29

(1)

For a discussion of the usefulness and a reconciliation of these non-GAAP financial measures with the most directly comparable GAAP financial measures see – “Liquidity and capital resources – Financial Conditions” below.

Reported earnings

Net profit attributable to Eni’s shareholders for the full year of 2017 was €3,374 million, a noticeable improvement over 2016, when a loss of €1,464 million was incurred from both continuing and discontinued operations, with the latter due to a charge on the Saipem shareholding following the loss of control over the investee. The reported operating profit for the full year of 2017 was €8,012 million, sharply higher than in 2016 (up by €5,855 million). The Eni Group recorded a substantial recovery in profitability across all business segments. This trend benefitted from higher commodity prices and margins and the progress in implementing the Group’s strategy driven by a faster time-to-market of discoveries, profitable production growth, efficiency gains, restructuring of the long-term gas contracts portfolio, as well as the restructuring of refining and petrochemical hubs.

Leveraging on the turnaround achievements, Eni was able to fully capture an ongoing recovery in the oil price scenario, with Brent crude oil prices up by 24% y-o-y driven by better market fundamentals. The downstream businesses were helped by higher global demand for commodities.

The 2017 result was also helped by the net gains of €2,739 million recorded on the divestment of a 40% interest in the Zohr gas field offshore Egypt and of a 25% interest in natural gas-rich Area 4 offshore Mozambique, which effect was offset for two thirds by the recognition of a number of special charges and write-downs. Finally, the Group profit & loss benefitted from a lower tax rate of 51% in line with the

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Group historical average, while in 2016 the tax rate was much higher at 217%. This trend was explained by the recovery in profit before taxes of the E&P segment, which helped the Company offset against the taxable income a higher share of deductible expenses, including those incurred under PSA contracts, and to dilute the incidence of non-deductible expenses.

Adjusted results

Adjusted operating profit and adjusted net profit are determined by excluding inventory holding gains or losses and extraordinary and non-recurring gains and losses (pre and post-tax, respectively).

Adjusted operating profit (or loss) and adjusted net profit (or loss) provide management with an understanding of the results from our base operations by excluding the effects of certain disposals and special charges or gains that do not reflect the ordinary results of our operations. Adjusted measures of profitability are used to evaluate our period-over-period operating performance, as management believes these provide more comparable measures as they adjust for disposals and special charges or gains not reflective of the normal trend results of our business. These Non-GAAP performance measures may be useful to an investor in evaluating the underlying operating performance of our business, because the items excluded from the calculation of such measures can vary substantially from company to company depending upon accounting methods, management’s judgement, book value of assets, capital structure and the method by which assets were acquired, among other factors.

In 2017, gains on disposals, asset revaluations, impairment losses, inventory holding profit or losses and other special charges were a net positive of €995 million in net profit and of €2,209 million in operating profit. Excluding these gains/charges, the adjusted net profit for the year was €2,379 million compared to a loss of €340 million in 2016, while the Group adjusted operating profit was €5,803 million, more than doubling from 2016 when adjusted operating profit was €2,315 million. The €3.5 billion increase of adjusted operating profit was explained for €3.1 billion by price and margins increases driven by the improved commodity environment and for €0.6 billion by volumes growth and efficiency and optimization gains, partly offset by OPEC cuts and one-off effects amounting to €0.2 billion.

The Group underlying performance – i.e net of non-recurring or extraordinary gains and losses and the inventory holding gain or losses – was driven by an improved performance in the E&P segment that doubled its operating profit at €5,173 million. This was due to higher hydrocarbons prices, production growth, capital and cost discipline and continued exploration success. Hydrocarbons production was 1.719 mmBOE/d, growing by 2.9% y-o-y.

The G&P segment reverted to profit after many years of unprofitable performances at €214 million leveraging on the renegotiation of long-term gas supply contracts, lower logistic costs and better results at the LNG, trading and power businesses.

The R&M and Chemical segment reported the best performance in years at €991 million (up by 70% y-o-y) driven by a recovery in commodity margins and the benefits of the restructuring plan of refineries and petrochemical hubs, cost efficiencies and the shift in the product mix towards specialties and higher value-added products (green fuels and chemicals). Those developments helped the business leverage an improved trading environment.

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The table below sets forth for the reported periods details of certain, identified gains and charges included in the net results.

	Year ended December 31,
Eni Group	2017		2016		2015
	(€ million)
(Profit) loss on inventory		(219)		(175)		1,136
Environmental provisions		208		193		225
Impairment losses (impairments reversals), net		(221)		(459)		6,534
Impairment of exploration projects				7		169
Net gains on disposal of assets		(3,283)		(10)		(407)
Risk provisions		448		151		211
Provision for redundancy incentives		49		47		30
Fair value gains/losses on commodity derivatives		146		(427)		164
Reclassification of currency derivatives and translation effects to management measure of business performance		(248)		(19)		(63)
Estimate revision of revenues accrued in the gas retail business		64		161		484
Valuation allowance of doubtful accounts(1)		616		410
Write-off of the damaged units of the EST conversion plant at the Sannazzaro refinery				193
Provision for removal and clean-up of EST conversion plant				24
Compensation gain on part of a third-party insurer relating to the EST plant incident				(217)
Other		231		279		301
Total net charges (gains) in operating profit		(2,209)		158		8,784
Finance expenses		502		116		286
of which: reclassification of currency derivatives and translation effects to management measure of business performance		248		19		63
Capital gains on disposal of investments		(163)		(57)		(33)
Write downs of investments and financing receivables		537		483		506
Write down of deferred tax assets/utilization of deferred tax liabilities				170		1,740
Tax effects relating to the US tax reform		115
Tax effects on the above listed items and other items		160		(214)		(1,607)
Tax effects on (profit) loss on inventory		63		55		(354)

Net (charges) gains in net profit		(995)		711		9,322
Net (charges) gains attributable to non-controlling interest						53
Net (charges) gains attributable to Eni		(995)		711		9,269

(1)

Includes credit losses in E&P for receivables in Nigeria and Venezuela and in the retail G&P business for the estimate made in accordance with the expected loss accounting model net of the estimate made in accordance to the incurred loss accounting for credit losses.

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The table below provides a reconciliation of those Non-GAAP measures to the most comparable performance measures calculated in accordance with IFRS.

	Year ended December 31,
	2017		2016		2015
	(€ million)
GAAP measure of operating profit		8,012		2,157		(3,076)
Inventory holding (gains) and losses		(219)		(175)		1,136
Identified net (gains) losses(1)		(1,990)		333		6,426
Non-GAAP measure of operating profit		5,803		2,315		4,486
GAAP measure of net profit		3,374		(1,051)		(7,952)
Inventory holding (gains) and losses, post tax		(156)		(120)		782
Identified net (gains) losses, post tax(1)		(839)		831		7,973
Non-GAAP measure of net profit		2,379		(340)		803

(1)

2015 data includes elimination upon consolidation of intercompany transactions with discontinued operations.

In 2017, net cash provided by operating activities amounted to €10,117 million. The closing of the divestment of Eni’s assets in Mozambique and Egypt and other disposals generated €5,455 million of proceeds. These inflows funded financial requirements for capital expenditures (€9,191 million including investments) and the payment of Eni’s dividend (the final dividend for fiscal year 2016 and the 2017 interim dividend totaling €2,880 million).

Management also assessed the Group net cash provided by operating activities excluding movements in working capital net of the inventory holding gain, which resulted in €8,458 million. This cash flow was negatively impacted by:

(i)

Credit losses amounting to €616 million which included the recognition of a valuation allowance for doubtful accounts of our E&P business in connection with receivables in Nigeria and Venezuela, and the difference between the allowance for doubtful accounts made in accordance to the “expected loss” accounting model vs. the incurred loss accounting in the retail G&P business. The expected loss accounting model is due to be adopted in the statutory accounts starting from 2018;

(ii)

an extraordinary payment made for a tax settlement in Angola (€150 million) relating to past reporting periods.

Management assessed the progress made in 2017 to lower the Brent price level at which the Group was able to fund its capital expenditures and dividend payments through cash flow from operations. To that end it is worth noting that the disposals of a 40% interest in the Zohr gas field and of a 25% interest in Area 4 in Mozambique had retroactive economic effects, which means that the consideration received from the buyers included the reimbursement of the capex incurred by Eni in connection with those interests from the beginning of 2017 up to the completion date. Furthermore, Eni cashed in approximately €0.2 billion of advances in connection with future supplies of gas to our state-owned partners in Egypt as part of the agreements to accelerate the development plans of the Zohr gas field.

Cash flow from operating activities including changes in working capital was netted of these advances and other minor items to €9.99 billion, whereas capex for the FY 2017 was netted of the share reimbursed by the buyers of the minority interests in the Zohr and Mozambique projects and other minor items to €7.62 billion, respectively, yielding a surplus of approximately €2.4 billion, which funded approximately 80% of the total amount of the cash dividend (€2.9 billion). Consequently, on the basis of the Group cash flow sensitivity to the Brent scenario which is assuming an increase of approximately €0.2 billion in cash flow for each one-dollar increase in the Brent price (and vice versa), the organic cash neutrality for funding FY capex and the floor dividend would have been achieved at 57$/BBL, better than management’s expectations at 60$/BBL and in line with the long-term Company’s target of a cash neutrality structurally below the 60$/BBL threshold. Going forward we will seek to further drive lower our cash neutrality.

At December 31, 2017, the Group’s net debt decreased by €3,860 million to €10,916 million. The Group ratio of finance debt to total equity at year-end 2017 was 0.51. However, in assessing the Group financial structure, management is using a measure of indebtedness which subtracts cash and cash equivalents and other very liquid financial assets from finance debt. This Non-GAAP measure of

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indebtedness is defined “net borrowings” (see Glossary). The ratio of net borrowings to total equity is defined “Leverage” (see Glossary) and is commonly used by management in assessing the Group financial condition (see paragraph “Financial condition” below). Leverage at year-end 2017 decreased to 0.23 down from 0.28 at the end of 2016.

In 2018, we are projecting a capital expenditures budget of approximately €7.7 billion and a production growth rate of approximately 4% compared to 2017. Finally, we are projecting a cash dividend for the full year 2018 of €0.83 per share. See “Management expectations of operations”.

Trading environment


	2017		2016		2015
Average price of Brent dated crude oil in U.S. dollars(1)		54.27		43.69		52.46
Average price of Brent dated crude oil in euro(2)		48.03		39.47		47.26
Average EUR/USD exchange rate(3)		1.130		1.107		1.110
Standard Eni Refining Margin (SERM)(4)		5.0		4.2		8.3
Euribor – three month euro rate %(3)		(0.33)		(0.26)		(0.02)

(1)

Price per barrel. Source: Platt’s Oilgram.

(2)

Price per barrel. Source: Eni’s calculations based on Platt’s Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB).

(3)

Source: ECB.

(4)

In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields.

When the term margin is used in the following discussion, it refers to the difference between the average selling prices and reflects the trading environment and are, to a certain extent, a gauge of industry profitability.

Eni’s results of operations and the year-to-year comparability of its financial results are affected by a number of external factors which exist in the industry environment, including changes in oil, natural gas and refined products prices, industry-wide movements in refining margins and fluctuations in exchange rates and interest rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas business and, to a lesser extent, of the refining and marketing business. See “Item 3 – Risk factors”.

In 2017, the trading environment was characterized by a recovery in crude oil prices, particularly in the last part of the year. This was driven by a better balance between global demand and supplies on the back of the agreement reached 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. This recovery was not fully reflected in Eni’s average hydrocarbon realizations because of the slow recovery of gas realizations on equity production, also reflecting time lags in oil-linked price formulas.

Eni’s refining margins (Standard Eni Refining Margin – SERM) which represents the benchmark for the level of profitability of Eni’s refineries before fixed cash expenses, increased from a year ago (up by 19%) to 5 $/BBL benefitting from higher relative prices of products compared to the cost of the petroleum feedstock. This trend has weakened in the fourth quarter 2017 due to a swift upward movements in the Brent price. The Company managed to reduce its breakeven margin and to align it with the current trading environment.

The exchange rate of euro against the dollar was 1.130, with an appreciation of 2.1% compared to the average exchange rate recorded in 2016.

Critical accounting estimates

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the carrying amounts of assets and liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure

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of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience or other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas assets, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets, equity-accounted investments and goodwill, decommissioning and restoration liabilities, business combinations, pensions and other post-retirement benefits, and recognition of environmental liabilities. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A summary of significant estimates is provided in “Item 18 – note 6 – of the Notes on Consolidated Financial Statements”.

2015 – 2017 Group results of operations

Overview of the profit and loss account for three years ended December 31, 2015, 2016 and 2017

The table below sets forth a summary of Eni’s profit and loss account for the periods indicated. All line items included in the table below are derived from the Consolidated Financial Statements prepared in accordance with IFRS.

	Year ended December 31,
	2017		2016		2015
	(€ million)
Net sales from operations		66,919		55,762		72,286
Other income and revenues(1)		4,058		931		1,252
Total revenues		70,977		56,693		73,538
Operating expenses		(55,412)		(47,118)		(59,967)
Other operating (expense) income		(32)		16		(485)
Depreciation, depletion and amortization		(7,483)		(7,559)		(8,940)
Impairment reversal (impairment losses), net		225		475		(6,534)
Write-off		(263)		(350)		(688)
OPERATING PROFIT (LOSS)		8,012		2,157		(3,076)
Finance income (expense)		(1,236)		(885)		(1,306)
Income (expense) from investments		68		(380)		105
PROFIT (LOSS) BEFORE INCOME TAXES		6,844		892		(4,277)
Income taxes		(3,467)		(1,936)		(3,122)
Net profit (loss) – continuing operations		3,377		(1,044)		(7,399)
Net profit (loss) – discontinued operations				(413)		(1,974)
Net profit (loss)		3,377		(1,457)		(9,373)
Attributable to:
Eni’s shareholders:		3,374		(1,464)		(8,778)
- continuing operations		3,374		(1,051)		(7,952)
- discontinued operations				(413)		(826)
Non-controlling interest:		3		7		(595)
- continuing operations		3		7		553
- discontinued operations						(1,148)

(1)

Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income.

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The table below sets forth certain income statement items as a percentage of net sales from operations for the periods indicated.

	Year ended December 31,
	2017		2016		2015
	(%)
Operating expenses		82.8		84.5		83.0
Depreciation, depletion, amortization, impairments reversal (impairment losses), net, write-off		11.2		13.3		22.4
OPERATING PROFIT		12.0		3.9		(4.3)

2017 compared to 2016. See management discussion under paragraph “Executive summary” on page 99 for an overview of the Group’s results from continuing operations. Net profit attributable to Eni’s shareholders amounted to €3,374 million for 2017, an increase of €4,838 million compared to the net loss of €1,464 million reported in 2016.

2016 compared to 2015. Net loss attributable to Eni’s shareholders including both continuing operations and discontinued operations amounted to €1,464 million for 2016. The loss of the discontinued operations pertaining to Eni’s shareholders (€413 million) was affected by the recognition of a charge of €441 million due to the alignment of Eni’s retained interest in Saipem with its market value the date of the loss of control (January 22, 2016). The market value of the retained interest in the former subsidiary was the carrying amount of such interest upon initial recognition for the subsequent accounting under the equity method (€564 million to which a share capital increase of €1,069 million is to be added).

Discontinued operations

The table below sets forth net profit (loss) attributable to discontinued operations for the periods indicated.

	Year ended December 31,
	2017	2016		2015
	(€ million)
Net profit – discontinued operations			(413)		(1,974)
attributable to:
- Eni			(413)		(826)
- non-controlling interest					(1,148)

Based on the accounting of IFRS 5 for disposal groups, gains and losses pertaining to the discontinued operations include only those earned from transactions with third parties. Until such time as Saipem was a subsidiary of the Eni Group (i.e. end of the reporting period 2015), gains and losses on intercompany transactions have been eliminated upon consolidation. These comprised mainly revenues earned by Saipem for the supply of capital goods and maintenance services to Eni’s Group companies, which were eliminated upon consolidation, positively affecting results of the continuing operations, while negatively affecting the results of operations of the discontinued operations. This effect did not recur in 2016 due to the derecognition of Saipem effective January 1, 2016. Furthermore, the 2015 loss from discontinued operations included the alignment of Saipem’s net assets to its market capitalization at the balance sheet date leading to a loss of €393 million.

Analysis of the line items of the profit and loss account of continuing operations

a) Total revenues

Eni’s revenues from continuing operations were €70,977 million, €56,693 million and €73,538 million for the years ended December 31, 2017, 2016 and 2015, respectively. Total revenues consist of net sales from operations and other income and revenues. Eni’s net sales from operations from continuing operations amounted to €66,919 million, €55,762 million and €72,286 million for the year ended December 31, 2017, 2016 and 2015, respectively, and its other income and revenues totaled €4,058 million, €931 million and €1,252 million, respectively, in these periods.

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Net sales from operations from continuing operations

The table below sets forth, for the periods indicated, net sales from operations from continuing operations generated by each of Eni’s business segments including intragroup sales, together with consolidated net sales from operations.

	Year ended December 31,
	2017		2016		2015
	(€ million)
Exploration & Production		19,525		16,089		21,436
Gas & Power		50,623		40,961		52,096
Refining & Marketing and Chemicals		22,107		18,733		22,639
Corporate and other activities		1,462		1,343		1,468
Consolidation adjustments(1)		(26,798)		(21,364)		(25,353)
NET SALES FROM OPERATIONS FROM CONTINUING OPERATIONS		66,919		55,762		72,286

(1)

Intragroup sales are included in net sales from operations in order to give a more meaningful indication as to the volume of the activities to which sales from operations by segment may be related. The largest intragroup sales are recorded by the Exploration & Production segment. “Item 18 – note 46 – of the Notes on Consolidated Financial Statements” for a breakdown of intragroup sales by segment for the reported years.

2017 compared to 2016. Eni’s net sales from operations (revenues) from continuing operations for 2017 (€66,919 million) increased by €11,157 million from 2016 (or up by 20%) primarily reflecting higher realizations on oil, products and natural gas due to the recovery in commodity prices. Changes in sales volumes of products sold were immaterial.

Revenues generated by the Exploration & Production segment (€19,525 million) increased by €3,436 million (or up by 21.4%). This was due to higher average realizations on equity hydrocarbons (up by 20.3% on average in dollar terms) driven by increasing prices for the marker Brent (up by 24.2%) and gas benchmarks in Europe, in the United States and elsewhere which however appreciated by a smaller amount than oil realizations due to time lags in oil-linked pricing formulas.

Revenues generated by the Gas & Power segment (€50,623 million) increased by €9,662 million (or up by 23.6%). The increase reflected higher commodity prices and volumes purchased to be resold in the business of crude oil and refined products trading, as well as higher gas and power selling prices.

Revenues generated by the Refining & Marketing and Chemical segment (€22,107 million) increased by €3,374 million (or up by 18%) mainly reflecting a recovery in the commodities prices. The average selling prices of gasoline and gasoil reported an increase of 19% and 24%, respectively. The average selling prices in the Chemical business increased by 16% due to the recovery in the monomers (intermediates up by 27% and polymers up by 13%).

2016 compared to 2015. Eni’s net sales from operations (revenues) from continuing operations for 2016 (€55,762 million) decreased by €16,524 million from 2015 (or down by 22.9%) primarily reflecting lower realizations on oil, products and natural gas due to significantly lower commodity prices. Changes in sales volumes of products sold were immaterial.

Revenues generated by the Exploration & Production segment (€16,089 million) decreased by €5,347 million (or down by 24.9%). This was due to lower average realizations on equity hydrocarbons (down by 20.1% on average in dollar terms) driven by declining prices for the marker Brent (down by 16,7%) and gas benchmarks in Europe, in the United States and elsewhere also considering the time lags in oil-linked formulas. The reduction was also negatively affected by the Val d’Agri shutdown, which lasted four and half months. The negative price impact was mainly recorded at concession contracts, while PSA contracts are insulated from the scenario due to the cost recovery mechanism.

Revenues generated by the Gas & Power segment (€40,961 million) decreased by €11,135 million (or down by 21.4%). The reduction reflected lower gas and power selling prices as well as lower commodity prices in the business of crude oil and refined products trading, which impact was however offset at the

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operating profit level by a corresponding decrease in the supply costs of the commodities. Furthermore, revenues were also negatively affected by a downward revision of revenues accrued on the sale of gas and power to retail customers in Italy (€161 million) dating back to past reporting periods prior to 2015.

Revenues generated by the Refining & Marketing and Chemical segment (€18,733 million) decreased by €3,906 million (or down by 17.3%) mainly reflecting lower average selling prices driven by weaker commodity prices. The average selling prices in the Chemical business declined by 10% due to lower price of polymers (down by 6.7% and down by 6.3% the average price of elastomers and styrenics, respectively), reflecting the impact of scenario and competitive pressure.

Other income and revenues from continuing operations

2017 compared to 2016. Eni’s other income and revenues from continuing operations for 2017 (€4,058 million) increased by €3,127 million from 2016 primarily reflecting gains on the disposal of a 40% interest in the Zohr gas field in Egypt (€1,281 million) and of a 25% interest in natural gas-rich Area 4 offshore Mozambique (€1,985 million).

2016 compared to 2015. Eni’s other income and revenues from continuing operations for 2016 (€931 million) decreased by €321 million from 2015 (or down by 26%) primarily reflecting the circumstance that in 2015 the Group recorded gains on the disposal of non-strategic assets in the E&P segment, mainly in Nigeria.

b) Operating expenses

The table below sets forth the components of Eni’s operating expenses for the periods indicated.

	Year ended December 31,
	2017		2016		2015
	(€ million)
Purchases, services and other		52,461		44,124		56,848
Payroll and related costs		2,951		2,994		3,119
Operating expenses		55,412		47,118		59,967

2017 compared to 2016. Operating expenses from continuing operations for 2017 (€55,412 million) increased by €8,294 million y-o-y, up by 17.6%, primarily reflecting higher supply costs of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstock and hydrocarbons purchased for resale). Purchases, services and other costs included €660 million relating mainly to environmental provisions and the recognition of losses on certain contractual and commercial disputes (€360 million in 2016). Payroll and related costs (€2,951 million) decreased by €43 million from 2016, down by 1.4%, mainly due to the lower average number of employees and the appreciation of euro vs. the dollar and the GBP.

2016 compared to 2015. Operating expenses from continuing operations for 2016 (€47,118 million) decreased by €12,849 million y-o-y, down by 21.4%, primarily reflecting lower supply costs of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstock and hydrocarbons purchased for resale). Purchases, services and other costs included €360 million relating mainly to environmental provisions (€436 million in 2015). Payroll and related costs (€2,994 million) decreased by €125 million from 2015, down by 4%, due to lower average number of employees outside Italy.

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c) Depreciation, depletion, amortization, impairments (impairment reversals) net and write-off

The table below sets forth a breakdown of depreciation, depletion, amortization, impairments (impairment reversals) net and write-off for the periods indicated.

	Year ended December 31,
	2017		2016		2015
	(€ million)
Exploration & Production		6,747		6,772		8,080
Gas & Power		345		354		363
Refining & Marketing and Chemicals		360		389		454
Corporate and other activities		60		72		71
Impact of unrealized intragroup profit elimination(1)		(29)		(28)		(28)
Total depreciation, depletion and amortization		7,483		7,559		8,940
Impairment losses		862		1,067		6,537
Reversals of impairment losses		(1,087)		(1,542)		(3)
Write-off		263		350		688
Total depreciation, depletion, amortization, impairment losses (impairment reversals), net and write off		7,521		7,434		16,162

(1)

This item concerned mainly intra-group sales of goods and capital, recorded at period end in the assests of the purchasing business segment.

2017 compared to 2016. In 2017, depreciation, depletion and amortization charges (€7,483 million) decreased by €76 million from 2016, or 1%, mainly in the Exploration & Production segment (with a decrease of €25 million) reflecting lower development capital expenditures of the year (down by 6.9%) and the euro appreciation, partially offset by start-ups and ramp-ups of new projects, and in the Refining & Marketing segment due to the write-off, reported in 2016, of the damaged units of the EST conversion plant following the accident occurred in December 2016.

In 2017, the Group recorded reversals of prior impairment losses in the E&P segment, at oil&gas properties for €808 million. These were driven by upward reserve revisions, lower future development and operating expenses, as well as a favourable impact in connection with the new corporate tax regime in the USA. The Gas & Power segment recorded the reversal of asset impairment losses recorded in previous reporting periods relating for €184 million to the alignment of the book value of the Hungarian gas distribution activity to its fair value, in light of a sale negotiation ongoing at the balance sheet date which may lead to a sale being completed in 2018. In the Refining & Marketing and Chemicals segment, an asset impairment reversal of €76 million reflected improved profitability prospects of the Chemical business. These reversals were partly offset by impairment losses relating to oil&gas properties in the upstream business (€650 million) driven by the project re-phasing or cancellation and downward reserve revisions. Finally, investments made for compliance and stay-in-business purposes were fully impaired at cash generating units previously written-off in the Refining & Marketing business, which were confirmed to lack any prospects of profitability (€130 million).

The write-off amounting to €263 million, mainly related to the costs of exploratory wells lacking the requisites for continuing capitalization because they did not encounter commercial quantities of hydrocarbons or due to lack of management commitment in pursuing further appraisal activity in Egypt, Norway and the Ivory Coast.

2016 compared to 2015. In 2016, depreciation, depletion and amortization charges (€7,559 million) decreased by €1,381 million from 2015, or 15.4%, mainly in the Exploration & Production segment (with a decrease of €1,308 million) reflecting lower capital expenditures of the year (down by 16.2%) and the lower carrying amounts of certain oil&gas properties following the impairment losses booked in 2015 (€5,212 million).

In 2016, the Group recorded reversals of prior impairment losses at oil&gas properties for €1,440 million. These were determined by an upward revision to the long-term price of the benchmark Brent to 70 $/BBL, up from the previous 65 $/BBL assumption, which drove the financial projections of the

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2017 – 2020 industrial plan and the recoverability of oil&gas assets carrying amounts in the 2016 financial statements. These reversals were partly offset by impairment losses related to gas properties in the upstream business driven by a lowered price outlook in Europe and other oil&gas properties due to contractual changes, reserves revision and a higher country risk (overall amount of €756 million). Finally, investments made for compliance and stay-in-business purposes were fully impaired at cash generating units previously written-off in the Refining & Marketing and Chemicals segment, which were confirmed to lack any prospects of profitability (€104 million), while the Gas & Power segment recorded an impairment loss of €81 million related to a gas transport infrastructure and LNG carriers.

The write-off amounting to €350 million, mainly related to the costs of exploratory wells lacking the requisites for continuing capitalization because they did not encounter commercial quantities of hydrocarbons or due to lack of management commitment. The item also comprised the write-off of the damaged units of the EST conversion plant at the Sannazzaro Refinery due to the accident occurred in December 2016 (€193 million).

d) Operating profit (loss) by segment

The table below sets forth Eni’s operating profit from continuing operations by business segment for the periods indicated.

	Year ended December 31,
	2017		2016		2015
	(€ million)
Exploration & Production		7,651		2,567		(959)
Gas & Power		75		(391)		(1,258)
Refining & Marketing and Chemicals		981		723		(1,567)
Corporate and other activities		(668)		(681)		(497)
Impact of unrealized intragroup profit elimination		(27)		(61)		1,205
Operating profit (loss)		8,012		2,157		(3,076)

The table below sets forth operating profit (loss) from continuing operations for each of Eni’s business segments as a percentage of each segment’s net sales from operations from continuing operations (including intragroup sales) for the periods presented.

	Year ended December 31,
	2017		2016		2015
	(%)
Exploration & Production		39.2		16.0		(4.5)
Gas & Power		0.1		(1.0)		(2.4)
Refining & Marketing and Chemicals		4.4		3.9		(6.9)
Group		12.0		3.9		(4.3)

Exploration & Production. In 2017, the Exploration & Production segment reported an operating profit of €7,651 million, with an increase of €5,084 million compared to the operating profit of €2,567 million reported in 2016, due to an ongoing recovery in crude oil prices (the Brent benchmark in dollar terms was up by 24.2%; however, it was up by 21.7% in euro terms) and production growth. This result was also positively influenced by the net gains recorded on the disposal of a 40% interest in the Zohr asset (€1,281 million) and of a 25% interest in the exploration Area 4 offshore Mozambique (€1,985 million), the reversal of previously booked impairment losses at certain oil&gas CGUs driven by upward reserve revisions, updated projections of operating expenses and capital expenditures and the positive effect of the US tax reform. This gains were partially offset by impairment losses recorded at certain oil&gas projects in Venezuela and the related current trade receivables as discussed below, valuation allowances for doubtful accounts, as well as the recognition of losses on certain contractual and commercial disputes.

Eni is currently engaged in executing two large petroleum projects in Venezuela: the Perla offshore gas project operated by the local company Cardón IV, a 50-50 joint-venture with another international oil company, and the PetroJunín onshore oil project jointly operated with PDVSA according to regime of the

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“Empresa Mixta”. Eni has invested approximately €1.5 billion to develop the two projects. Furthermore, a significant amount of overdue trade receivables was outstanding at the reporting date for the supply of the gas produced by the j.v. Cardón IV to PDVSA. Those trade receivables amounted to approximately €500 million before any valuation allowance and were held by both the venture and Eni’s subsidiaries operating in the Country. With a view to incorporating the Venezuela counterparty risk and the uncertainty relating the possible evolution of the difficult financial condition of the Country in assessing the recoverability of the Company’s investments and trade receivables, management has reviewed the empirical evidence and official statistics relating to the recent history of sovereign financial crises. Based on these findings and considering that Eni’s gas supplies are strategic and vital to the Country, management elaborated a possible scenario of the evolution of the Venezuelan financial crisis to drive internal estimates of our assets recoverability in Venezuela. Furthermore, considering a deteriorating operational environment and the financial risks underlying assets’ recoverability, management reclassified 315 mmBOE of undeveloped gas reserves to the unproved category, in accordance with the applicable US SEC regulation. These drivers led us to recognize asset impairment losses and a credit valuation allowance for a total amount of approximately €760 million.

Also Nigeria is experiencing a situation of financial stress which drove us to the recognition of significant credit losses. The amount of overdue receivables due to Eni at the balance sheet date was $1 billion which comprised the cash calls owed by the National oil Company “NNPC” at petroleum projects operated by Eni. Those receivables related to previous reporting periods. To collect those amounts Eni and its counterpart agreed upon a Repayment Agreement, whereby Eni expects to be reimbursed of the overdue amounts through the sale of the profit oil attributable to NNPC in certain rig-less petroleum initiatives which will be developed in future years. Those credits are stated in the financial statements net of a discount factor determined by utilizing the risk-adjusted weighted average cost of the capital to the Group to incorporate the mineral risk. NNPC has regularly funded the cash calls for the years 2016 and 2017, which led management to confirm the recoverability of the overdue cash calls. Other overdue credits were written down to reflect the counterparty risk in light of the deteriorated financial situation of the Country with a charge to profit of €258 million and related mainly to disputed receivables for cost recovery, considering lack of any progress in the course of the year to agree on a repayment plan.

In 2017, the Company’s liquids and gas realizations increased on average by 20.3% in dollar terms, driven by an increase in international oil prices for market benchmarks (Brent crude prices increased by 24.2%). Eni’s average oil realizations increased on average by 27.8%. Eni’s average gas realizations increased only by 12.8% because of time lags in oil-linked formulas.

In 2016, the Exploration & Production segment reported an operating profit of €2,567 million, with an increase of €3,526 million from the operating loss of €959 million reported in 2015. This change mainly reflected the impairment charges of €5,212 million recorded in 2015 due to a downward revision of the oil scenario, while in 2016 net impairment reversals of €684 million were recorded due to a hike in management long-term oil price assumptions.

In 2016, the Company’s liquids and gas realizations decreased on average by 20.1% in dollar terms, driven by a decline in international oil prices for market benchmarks (Brent crude prices decreased by 16.7%). Eni’s average oil realizations decreased on average by 15.4%. Eni’s average gas realizations decreased by 28.2% and were negatively impacted by the weak scenario and time lags in oil-linked formulas.

In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of core business performance across reporting periods. Excluding the below-listed gains and charges, the E&P segment reported a Non-GAAP operating profit of €5,173 million, with an increase of €2,679 million from 2016, or 107.4%. The increase was driven by a recovery in the commodity environment which drove increased oil&gas realizations in dollar terms (up by 20.3% on average) and production growth. These positives were partly offset by higher write-offs of unsuccessful exploratory wells and higher expenses.

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	Year ended December 31,
	2017		2016		2015
Exploration & Production	(€ million)
GAAP operating profit (loss)		7,651		2,567		(959)
Net gains on disposal of assets		(3,269)		(2)		(403)
Impairment losses (impairment reversals), net		(158)		(677)		5,381
Environmental provisions		46
Risk provisions		366		105
Reclassification of currency derivatives and translation effects to management measure of business performance		(68)		(3)		(59)
Valuation allowance of disputed receivables and others		442		410
Other		163		94		222
Total gains and charges		(2,478)		(73)		5,141
Non-GAAP operating profit (loss)		5,173		2,494		4,182

Gas & Power. In 2017, the Gas & Power segment reported an operating profit of €75 million, improving by €466 million compared to 2016 when the segment reported an operating loss of €391 million. This result was driven by the economic benefits from the renegotiation of gas supply contracts as well as lower logistic costs and improved performance in trading, LNG and Power businesses. Result also includes the reversal of asset impairment losses recorded in previous reporting periods for €146 million, mainly relating to the alignment of the book value of the Hungarian gas distribution activity to its fair value, in light of a sale negotiation ongoing at the balance sheet date which may lead to a sale being completed in 2018. Furthermore, from 2017, the profit/loss on stock has been included in the business underlying performance due to a changed regulatory framework on gas storage in Italy, on which basis management has elected to leverage gas stocks as a way to improve margins.

These positives were partly offset by lower gains in connection with the effects of fair-valued commodity derivatives that lacked the formal criteria to be accounted as hedges under IFRS.

In 2016, the Gas & Power segment reported an operating loss of €391 million, improving by €867 million compared to 2015 when the segment reported an operating loss of €1,258 million. The 2015 result was negatively affected by a downward estimate revision of revenues accrued on the sale of gas and power (€484 million) to retail customers in Italy dating back to past reporting periods and the establishment of a provision for the above mentioned accruals (€226 million). In 2016, accrued revenues were revised lower by €161 million relating reporting periods prior to 2015. Furthermore, commodity derivatives lacking criteria for being accounted as hedges generated approximately €500 million of higher gains in 2016.

In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, the G&P segment reported a Non-GAAP operating profit of €214 million, with an increase of €604 million from 2016, reflecting the benefits of the renegotiation process of long-term contracts, lower logistic costs and a better performance of the LNG, retail and trading businesses.

The items excluded from GAAP operating profit in determining the Non-GAAP measure of profitability mainly include certain commodity fair-valued derivatives and accruals measurements. Particularly, we enter into commodity and currency derivatives to reduce our exposure to (i) the commodity risk due to different indexation between the purchase cost and the selling price of gas and power or to lock in a commercial margin once a sale contract has been signed or it is highly probable, and (ii) the underlying exchange rate risk due to the fact that our selling prices are indexed to the euro and our supply costs are denominated in dollars. These derivatives normally hedge net Group exposure to commodities and exchange rates but do not meet the requirements for being accounted as hedges in accordance to IFRS. Therefore, in explaining year-on-year charges and in evaluating the business performance management believes that is appropriate to identify the fair value of commodity derivatives because they relate to transactions that will close in subsequent reporting periods or we estimate the portion of gains and losses on the settlement of certain commodity derivatives where underlying physical transaction has yet to be settled with the delivery of the underlying commodity. Furthermore, albeit the Group classifies within net finance expense those gains and losses on currency derivatives, as well as on the alignment of trade

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receivable and payables denominated in dollars into the accounts of euro subsidiaries at the closing rate, we believe that it is appropriate to consider those gains and losses on currency derivatives and alignment differences of our trade payables and receivables as part of the underlying business performance. Other special gains or losses comprise the re-measurement of revenues accrued in the retail gas and power business because they relate to past reporting periods. Finally, from 2017 management has excluded from GAAP operating profit the difference between the allowance for doubtful accounts incurred in the reporting period and the amount of credit loss determined in accordance to the expected loss model.

From 2017, the recognition of the inventory holding (gains) losses has been discontinued in the Gas & Power segment adjusted result considering that inventory levels have been minimized and the fact that management is leveraging inventories to improve margins.

	Year ended December 31,
	2017		2016		2015
Gas & Power	(€ million)
GAAP operating profit (loss)		75		(391)		(1,258)
(Profit) loss on inventory				90		132
Impairment losses (impairment reversals), net		(146)		81		152
Allowance for doubtful accruals in the retail G&P				17		226
Provision for redundancy incentives		38		4		6
Fair value gains/losses on commodity derivatives		157		(443)		90
Reclassification of currency derivatives and translation effects to management measure of business performance		(171)		(19)		(9)
Estimate revision of revenues accrued in the retail G&P		64		161		484
Revision of estimated revenues accruals in the retail G&P (difference between incurred loss vs. expected loss model)		223
Other		(26)		110		51
Total gains and charges		139		1		1,132
Non-GAAP operating profit (loss)		214		(390)		(126)

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Refining & Marketing and Chemicals. In 2017, the Refining & Marketing and Chemicals segment reported an operating profit of €981 million, with an improvement of €258 million y-o-y, driven by higher refining margins, particularly in the nine months of the year, and which also benefitted from the restructuring of Eni refineries and petrochemicals hubs implemented over the latest years. Refinery optimization helped Eni to reduce the break-even margin below the 4 $/BBL threshold and capture the upside in the scenario recorded in the first nine months of 2017. Operating profit included also the gain from the licensing of the EST conversion technology to Sinopec. These positives were partly offset by lower plant availability at the Sannazzaro refinery in connection with the shutdown of the EST unit, which is undergoing a rebuilding. The marketing business performed well due to effective commercial initiatives, mainly in the segment of premium products and services.

In the Chemical business, the optimized plant setup at core hubs and the focus of the product portfolio towards higher-value segments enabled the company to leverage the upside in the trading environment and to achieve volume upsides.

Better industrial trends were partly offset by a lower inventory gain.

In 2016, the Refining & Marketing and Chemicals segment reported an operating profit of €723 million, reversing an operating loss of €1,567 million reported in 2015. The improvement of €2,290 million was mainly due to lower assets impairments because a €1 billion charge was recognized in 2015 at the Chemical business to align its carrying amount with the expected fair value based on a sale transaction then ongoing designed to establish an industrial joint venture. Furthermore, in 2015 an inventory write-down of €877 million (pre-tax) was accounted for in the profit and loss because of the fall in oil commodity prices to align the net realizable value of the inventories to prices current at the balance sheet date. In 2016, following a late-year recovery in price scenario, the write down resulted in a gain on stock. The 2016 operating profit in the Refining & Marketing and Chemicals segment was also negatively affected by the write-off related to the EST conversion plant, at Sannazzaro Refinery, following an event occurred in December 2016, and the provision for removal and clean-up (a total amount of €217 million), partially offset by the recognition of third-party insurance compensation (€122 million)

The main item excluded from GAAP operating profit in determining the Non-GAAP measure of profitability is the inventory holding gain (or loss). Inventory holding gains or losses represent the difference between the cost of sales of the volumes sold during the period calculated using the cost of supplies incurred during the same period and the cost of sales calculated using the weighted average cost method. Under the weighted average cost method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant impact on reported income thereby affecting comparability. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a weighted average cost method basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a quarterly or monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. We regard the inventory holding gain or loss, including any write-down to align the carrying amounts of inventories to their net realizable value at the reporting date, as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies.

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In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the inventory holding gain (or loss) and the other gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, the R&M and Chemical segment reported a Non-GAAP operating profit of €991 million, with an increase of €408 million from 2016. The segment base performance in 2017 benefited from the industrial trends outlined above and of a better trading environment.

	Year ended December 31,
	2017		2016		2015
Refining & Marketing and Chemicals	(€ million)
GAAP operating profit (loss)		981		723		(1,567)
(Profit) loss on inventory		(213)		(406)		877
Environmental provisions		136		104		137
Impairment losses (impairment reversals), net		54		104		1,150
Net gains on disposal of assets		(13)		(8)		(8)
Provision for redundancy incentives		(6)		12		8
Other		52		54		98
Total gains and charges		10		(140)		2,262
Non-GAAP operating profit (loss)		991		583		695

R&M and Chemicals: charges were mainly composed of the write down of capital expenditures relating to certain Cash Generating Units in the refining business, which were impaired in previous reporting periods and continued to lack any profitability prospects (€130 million) and environmental provisions (€111 million). The Chemicals business recorded the reversal of an asset impairment for €76 million due to improved profitability prospects of the single Cash Generation Unit of the Chemical business, environmental provisions and restoration costs incurred at industrial hubs which were restructured (€48 million) and impairment losses of an investment and of the financing receivables due by an industrial joint venture because of lower profitability prospects (€207 million).

Corporate and Other activities. These activities are mainly cost centers comprising holdings and treasury, headquarters, central functions like information technology, human resources, self-insurance activities, as well as the Group environmental clean-up and remediation activities performed by the subsidiary Syndial.

The aggregate Corporate and Other activities reported an operating loss of €668 million in 2017 representing an increase of €13 million from 2016, or 1.9%, mainly reflecting the recognition of risk provisions related to environmental issues and other, that were partly offset by the implementation of cost efficiency measures.

The aggregate Corporate and Other activities reported an operating loss of €681 million in 2016 representing an increase of €184 million from 2015, or 37%, mainly reflecting the recognition of risk provisions related to environmental issues and other that were partly offset by the implementation of cost efficiency measures.

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e) Net finance expenses

The table below sets forth a breakdown of Eni’s net financial expenses for the periods indicated:

	Year ended December 31,
	2017		2016		2015
	(€ million)
Gain (loss) on derivative financial instruments		837		(482)		160
of which – Derivatives on exchange rate		809		(494)		96
– Derivatives on interest rate		28		(12)		31
Exchange differences, net		(905)		676		(354)
Net income from financial activities held for trading		(111)		(21)		3
Interest income		12		15		19
Finance expense from banks on short and long-term debt		(751)		(757)		(838)
Finance expense due to the passage of time (accretion discount)		(264)		(312)		(291)
Other finance income and expense, net		(127)		(110)		(171)
		(1,309)		(991)		(1,472)
Finance expense capitalized		73		106		166
		(1,236)		(885)		(1,306)

2017 compared to 2016. In 2017, net finance expenses were €1,236 million, down by €351 million compared to 2016 reflecting the recording of currency losses partly offset by positive fair value adjustments on currency derivatives (for a net negative effect of €278 million), with the latter lacking the formal criteria to be designated as hedges under IFRS. Furthermore, a loss from financial activities held for trading (€111 million) was recorded due to the translation differences, which were offset by a corresponding gain on exchange derivatives that did not satisfy the criteria for hedge accounting. Other net finance income and expense, referred to the impairment of operating financing receivables.

2016 compared to 2015. In 2016, net finance expenses were €885 million, down by €421 million compared to 2015 reflecting the recording of currency gains partly offset by negative fair value adjustments on currency derivatives (for a net positive effect of €440 million), with the latter lacking the formal criteria to be designated as hedges under IFRS. Furthermore, lower finance expense on debt were recorded due to the reduction in net borrowings and to lower interest rates reflecting accommodative monetary policies adopted by the Central Banks worldwide. These positives were partly offset by impairment losses on certain financing receivables granted to equity-accounted entities which are currently executing industrial projects on Eni’s behalf (€121 million). Furthermore, a discount expense of €129 million was recognized relating to certain receivable in the E&P segment owed by certain NOCs due to agreements to repay the overdue amount in instalments with the proceeds associated with mineral initiatives. On that basis, the discount rate utilized reflected also the mineral risk.

f) Net income from investments

2017 compared to 2016. In 2017 the Group reported a net profit from investments of €68 million related to:

(i)

dividends received from entities accounted for at cost (€205 million) relating to Nigeria LNG Ltd (€167 million) and Saudi European Petrochemical Co (€21 million);

(ii)

net gains on the divestment of interests (€163 million) mainly relating to the disposal of the Gas & Power retail activity in Belgium.

These positives were partly offset by:

(i)

a loss of €267 million recorded on equity-accounted entities, mainly in the E&P segment (€99 million) and in the Chemical business (€61 million). This also included a loss of €101 million recorded on the equity-accounted interest retained in Saipem, which was driven by the recognition of asset impairment charges and other extraordinary expenses by the investee;

(ii)

other net losses mainly relating to an impairment charge recorded in the G&P segment referred to the interest in Unión Fenosa Gas SA (€35 million) due to a reduced profitability outlook.

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2016 compared to 2015. In 2016 the Group reported a net loss from investments of €380 million and mainly related to: (i) results of equity-accounted entities (an overall net loss of €326 million), mainly reported by the Exploration & Production segment due to a weaker commodity scenario and the economic difficulties recorded in certain Countries with a negative impact on the level of inflation and exchange rates. Particularly, the segment incurred a loss of €144 million mainly related to our joint ventures in Venezuela (PetroSucre, which book value was completely written off, Cardón IV and PetroBicentenario) driven by changed economics due to the local currency devaluation and rising inflation leading to escalating operating costs; (ii) a loss of €144 million was recorded on the equity-accounted interest retained in Saipem. This was driven by the recognition of asset impairment charges and other extraordinary expenses accounted for in Saipem’s results due to the impairment review performed by the investee at its CGUs based on its updated industrial plan. That plan, announced in October 2016, factored in a slower recovery in the oil market and in investment plans of the international oil companies; (iii) net losses on the divestment of interests (€14 million) mainly relating to the disposal of the residual 2.22% interest in Snam (€32 million), offset by gains on the divestment of interests (€18 million) mainly of the 100% share in Slovenija doo, Eni Hungaria Zrt and other non-core interests; (iv) other losses mainly relating to an impairment charge recorded in G&P related to the interest in Unión Fenosa Gas SA (€84 million) due to a reduced profitability outlook and the impairment of receivables in the E&P segment owed by the equity-accounted PetroSucre SA for dividends resolved but yet to be paid (€65 million). These losses were partly offset by dividends received from entities accounted for at cost (€143 million) relating to Nigeria LNG Ltd (€76 million) and Saudi European Petrochemical Co (€45 million).

These gains are further explained in “Item 18 – note 20 – Investments – of the Notes on Consolidated Financial Statements”.

g) Taxes

2017 compared to 2016. In 2017, income taxes amounted to €3,467 million, up by €1,531 million compared to 2016, or 79%. This increase reflected higher income before taxes which was up by €5,952 million compared to 2016.

Tax rate was 51% compared to 217% recorded in 2016. This trend was explained by a recovery in profit before taxes of the E&P segment which helped the Company offset against the taxable income a higher share of deductible expenses, including those incurred under PSA contracts, and to dilute the incidence of non-deductible expenses. The reduction also reflected the recognition of deferred taxes in connection with the FID of the Coral project in Mozambique and the production start-up in Ghana.

Taxes included the tax effects relating to operating special items, the write-off of deferred tax asset of subsidiaries in the USA following the recognition of the effect of the newly enacted tax regime (€115 million), offset by the recognition of higher deferred tax asset at Versalis driven by the projection of improving future taxable earnings.

2016 compared to 2015. In 2016, income taxes amounted to €1,936 million, down by €1,186 million compared to 2015, or 38%. These lower charges mainly reflected lower write-downs of deferred tax assets in connection with improved projections of future taxable profit against which those assets would be utilized compared to 2015. Particularly, in 2015 deferred taxes were written down by €1,740 million relating to foreign subsidiaries of the E&P segment and Italian subsidiaries due to a deteriorated profitability outlook. By contrast, the write-downs of deferred tax assets in 2016 were offset by write-ups. In addition, considering the expected outcome of ongoing negotiations to settle disputed receivables owed by the Nigerian national oil company, the Company utilized a provision for deferred tax liabilities for €380 million as those receivables were considered tax-deductible.

In 2015 and in 2016, the Group reported tax rate was much higher than the Group historical tax rates. This negative trend was negatively affected by the increased share of taxable profit earned in PSA contracts which bear higher-than-average rates of tax. Furthermore, in many jurisdictions where the Group reported pre-tax losses, the Company was not in the position of recognizing deferred tax assets, due to lack of sufficient future taxable profit against which those tax assets would be utilized.

Management is estimating that in the four-year plan 2018 – 2021 the Group tax rate will benefit of a growing contribution to the Group pre-tax profit of E&P countries characterized by a lower-than-average tax rate.

Liquidity and capital resources

Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures and acquisitions over the past three years were financed primarily by a combination of funds generated from

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operations, borrowings and divestments of minority interests in certain of our exploration assets and other non-strategic activities. The Group continually monitors the balance between cash flow from operating activities and net expenditures targeting a sound and balanced financing structure.

The following table summarizes the Group cash flows and the principal components of Eni’s change in cash and cash equivalent for the periods indicated.

	Year ended December 31,
	2017		2016		2015
	(€ million)
Net profit (loss) – continuing operations		3,377		(1,044)		(7,399)
Adjustments to reconcile net profit to net cash provided by operating activities:
- amortization and depreciation charges, impairment losses, write-off and other non monetary items		8,720		7,773		17,216
- net gains on disposal of assets		(3,446)		(48)		(577)
- dividends, interest, taxes and other changes		3,650		2,229		3,215
Changes in working capital related to operations		1,440		2,112		4,781
Dividends received, taxes paid, interest (paid) received during the period		(3,624)		(3,349)		(4,361)
Net cash provided by operating activities – continuing operations		10,117		7,673		12,875
Net cash provided by operating activities – discontinued operations						(1,226)
Net cash provided by operating activities		10,117		7,673		11,649
Capital expenditures – continuing operations		(8,681)		(9,180)		(10,741)
Capital expenditures – discontinued operations						(561)
Capital expenditures		(8,681)		(9,180)		(11,302)
Acquisition of investments and businesses		(510)		(1,164)		(228)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments		5,455		1,054		2,258
Other cash flow related to investing activities () (*)		(32)		5,736		(1,651)
Changes in short and long-term finance debt		(1,712)		(766)		2,126
Dividends paid and changes in non-controlling interests and reserves		(2,883)		(2,885)		(3,477)
Effect of changes in consolidation, exchange differences and cash and cash equivalents related to discontinued operations		(65)		(3)		(780)
Change in cash and cash equivalent for the year		1,689		465		(1,405)
Cash and cash equivalent at the beginning of the year		5,674		5,209		6,614
Cash and cash equivalent at year end		7,363		5,674		5,209

(*)

For 2016, the item also includes the reimbursement of intercompany financing loans owed to Eni by Saipem for € 5,818 million.

(**)

Net cash used in investing activities included investments in and divestments of certain financial assets (mainly bank deposits) to absorb temporary surpluses of cash or as part of our ordinary management of financing activities. Due to their nature and the circumstance that they are very liquid, these financial assets are netted against finance debt in determining net borrowings. Furthermore, due to the Company’s decision to retain a cash reserve composed of held-for-trading securities, net cash used in investing activities also included investments and divestments of those securities. Also these held-for-trading financial assets are netted against finance debt in determining the Group net borrowings. For more information on their composition see Note No. 9 to the Consolidated Financial Statements. For the definition of net borrowings, see “Financial Condition” below. Cash flows of such investing activity were as follows:

(€ million)	2017		2016		2015
Investing activity:
- securities		(316)		(1,317)		(140)
- financing receivables		(72)		(272)		(343)
		(388)		(1,589)		(483)
Disposal:
- securities		223				1
- financing receivables		506		6,860		182
		729		6,860		183
Net cash flows used in investing activity		341		5,271		(300)

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The table below sets forth the principal components of Eni’s change in net borrowings(1) for the periods indicated.

	Year ended December 31,
	2017		2016		2015
	(€ million)
Net cash provided by operating activities		10,117		7,673		11,649
Capital expenditures		(8,681)		(9,180)		(11,302)
Acquisitions of investments and businesses		(510)		(1,164)		(228)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments		5,455		1,054		2,258
Other cash flow related to capital expenditures, investments and divestments		(373)		465		(1,351)
Net borrowings(1) of divested companies		261		5,848		83
Exchange differences on net borrowings and other changes		474		284		(818)
Dividends paid and changes in minority interest and reserves		(2,883)		(2,885)		(3,477)
Change in net borrowings(1)		3,860		2,095		(3,186)
Net borrowings(1) at the beginning of the year		14,776		16,871		13,685
Net borrowings(1) at year end		10,916		14,776		16,871

(1)

Net borrowings is a non-GAAP financial measure. For a discussion of the usefulness of net borrowings and its reconciliation with the most directly comparable GAAP financial measures see “Financial Condition” below.

Analysis of certain components of Eni’s change in net borrowings

In 2017, adjustments to reconcile net profit to net cash provided by operating activities mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization, impairment charges and reversals and the write-off of tangible and intangible assets (€7,521 million) and gains on disposals (€3,446 million). Adjustments to net profit also included accrued income taxes (€3,467 million) and interest expense (€671 million), which were more than offset by amounts actually paid (€3,437 million and €582 million, respectively). Net profit was negatively impacted by extraordinary credit losses amounting to €616 million which included the recognition of a valuation allowance for doubtful accounts in the E&P business and in the retail G&P business. Taxes paid included an extraordinary payment made for a tax settlement in Angola (€150 million) relating to past reporting periods.

In 2016, adjustments to reconcile net profit from continuing operations to net cash provided by operating activities from continuing operations mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization, impairment charges and reversals and the write-off of tangible and intangible assets (€7,434 million). Adjustments to net profit also included accrued income taxes (€1,936 million) and interest expense (€645 million), which were more than offset by amounts actually paid (€2,941 million and €780 million, respectively).

a) Changes in working capital related to operations

In 2017, working capital generated an inflow of €1,440 million. This was mainly due to a positive balance between trade receivables collected and trade payables paid (a net inflow of €941 million) which reflected the higher volume of trade receivables due subsequently to the reporting date which were sold to financing institutions compared to the previous reporting period (about €282 million) and also the adjustment in connection with the allowance for doubtful accounts in the retail Gas & Power segment.

Finally, other positive working capital adjustments related risk provisions and a positive adjustment relating the item other current assets and liabilities (up by €749 million) which mainly reflected the impairment of receivables in the E&P segment and a change in the derivatives fair value.

In 2016, working capital generated an inflow of €2,112 million. This was mainly due to a positive balance between trade receivables collected and trade payables paid (a net inflow of €2,781 million) which reflected the higher volume of trade receivables due subsequently to the reporting date which were sold to financing institutions compared to the previous reporting period (about €1 billion). This inflow was partly offset by utilizations of the risk provision for €1,043 million, part of which related to the settlement of

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obligations towards third parties mainly in the G&P segment also in relation to the final award of an arbitration procedure involving a long-term gas buyer. Conversely an advance made to the same buyer in the previous reporting period was utilized. Finally the working capital inflow was partly absorbed by a reimbursement in-kind of a financing receivable due by an equity-accounted entity operating a gas field in Venezuela with trading receivables (€300 million) due by the Venezuelan state-owned oil company (PDVSA). Finally a positive adjustment related the item other current assets and liabilities (up by €647 million) which mainly reflected the impairment of receivables owed by National Oil Companies due to the expected outcome of ongoing negotiations to settle disputed amounts. The G&P segment was the main driver of the cash inflow from working capital in 2016, reflecting also non-recurring trends. We expect that the G&P working capital contribution will normalize going forward.

b) Investing activities

	Year ended December 31,
	2017		2016		2015
	(€ million)
Exploration & Production		7,739		8,254		9,980
Gas & Power		142		120		154
Refining & Marketing and Chemicals		729		664		628
Corporate and other activities		87		55		64
Impact of unrealized intragroup profit elimination		(16)		87		(85)
Capital expenditures – continuing operations		8,681		9,180		10,741
Capital expenditures – discontinued operations						561
Capital expenditures		8,681		9,180		11,302
Acquisitions of investments and businesses		510		1,164		228
		9,191		10,344		11,530
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments		(5,455)		(1,054)		(2,258)

Capital expenditures totaled €8,681 million and €9,180 million, respectively in 2017 and in 2016.

For a discussion of capital expenditures by business segment and a description of year-on-year changes see below “Capital expenditures by segment”.

Acquisition of investments and businesses totaled €510 million in 2017 and €1,164 million in 2016. In 2017, acquisition of investments mainly related to the subscription of a share capital increase at equity-accounted entities engaged in the development of Eni’s projects, in detail: (i) the Coral FLNG SA (€443 million) which is engaged in the development of a floating production and storage unit of LNG in natural gas-rich Area 4 offshore Mozambique; and (ii) Lotte Versalis Elastomers Co Ltd (€45 million) which is engaged in the production of premium elastomers in South Korea.

In 2016, they comprised the subscription of the share capital increase of Saipem (€1,069 million) and minor contribution to equity-accounted entities.

In 2017, disposals amounted to €5,455 million and mainly related to: (i) the sale to ExxonMobil of a 25% interest in natural gas-rich Area 4 offshore Mozambique where development activities are ongoing to put into production the significant gas resources discovered by Eni. The net cash consideration amounted to €2,061 million including the corresponding portion of net borrowings of the business divested to the buyer amounting to €264 million; (ii) the sale of a 40% stake in the Zohr project located in Egypt sold to BP and Rosneft (€2,526 million); (iii) the sale of the whole interest in the consolidated company Eni Gas & Power NV and its subsidiary Eni Wind Belgium NV, operating in the gas & power retail activities in Belgium. The sale price amounted to €302 million including cash divested of €8 million.

In 2016, disposals amounted to €1,054 million and mainly related to: (i) the divestment of the 12.503% interest in Saipem SpA to CDP Equity SpA in January 2016 (€463 million), an interest in Snam due to exercise of the conversion right by bondholders (€332 million) as well as fuel distribution activities in Eastern Europe.

In 2016, other cash flow related to investing activities were positive for €465 million and included the reimbursement in-kind of a financing receivable owed by our equity-accounted entity Cardón IV for €300

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million. Cardón IV reimbursed Eni with a trade receivable due by the Venezuelan State-owned oil company (PDVSA) on the supplies of gas volume produced at the Perla project. Furthermore, the production restart of the Kashagan field and the achievement of a production milestone in the fourth quarter of 2016 triggered the reimbursement of the first instalment of a receivable of the divestment of an interest of 1.71% of the project to the Kazakh national oil company occurred in 2008, with a cash-in of €152 million. A second instalment was reimbursed in 2017.

c) Dividends paid and changes in non-controlling interests and reserves

In 2017, dividends paid and changes in non-controlling interests and reserves (€2,883 million) related almost exclusively to cash dividends to Eni shareholders (€2,880 million, of which €1,440 million relating to the 2017 interim dividend and €1,440 million to the final dividend for fiscal year 2016).

In 2016, dividends paid and changes in non-controlling interests and reserves (€2,885 million) related almost exclusively to cash dividends to Eni shareholders (€2,881 million, of which €1,441 million relating to the 2016 interim dividend and €1,440 million to the final dividend for fiscal year 2015.

Financial condition

Management assesses the Group’s capital structure and capital condition by tracking net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, a liquidity reserve made of held-for-trading securities and finally other liquid assets not related to operations (financing receivables and securities). The Company is retaining a liquidity reserve, which comprises very liquid investments, mainly sovereign and corporate securities which management has selected based on their creditworthiness. This cash reserve was established by investing part of the proceeds from the disposal plan carried out in the latest years.

Those securities amounted to €6,219 million as of end of 2017 and were accounted as mark-to-market financial instruments. For further information see “Item 18 – note 9 – Financial assets held for trading – of the Notes on Consolidated Financial Statements”. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow.

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways in which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced compared to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to other companies.

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The tables below set forth the calculations of net borrowings and leverage for the periods indicated and their reconciliation to the most directly comparable GAAP measure.

	As of December 31,
	2017						2016
	Short-term		Long-term		Total		Short-term		Long-term		Total
	(€ million)
Finance debt (short-term and long-term debt)		4,528		20,179		24,707		6,675		20,564		27,239
Cash and cash equivalents		(7,363)				(7,363)		(5,674)				(5,674)
Securities held for trading and other securities held for non operating purposes		(6,219)				(6,219)		(6,404)				(6,404)
Non operating financing receivables		(209)				(209)		(385)				(385)
Net borrowings		(9,263)		20,179		10,916		(5,788)		20,564		14,776

		As of December 31,
		2017		2016
Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS	(€ million)		48,079		53,086
Ratio of finance debt to total shareholders’ equity including non-controlling interest			0.51		0.51
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest			(0.29)		(0.23)
Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage)			0.23		0.28

In 2017, net borrowings amounted to €10,916 million, representing a €3,860 million decrease from 2016. This reduction was driven by net cash flow from operations amounting to €10,117 million and the finalization of portfolio transactions as part of the Dual Exploration Model (the disposal of a 40% interest in Zohr in Egypt and of a 25% interest in Area 4 offshore Mozambique) and other non-strategic assets (retail activity in Belgium). Income taxes on the disposals of Eni’s interests in Zohr and in Area 4 in Mozambique (€0.44 billion) were netted against cash flow from disposals, as provided by international accounting standards. Cash flow from operations was also influenced by a higher level of receivables due beyond the end of the reporting period being sold to financing institutions compared to the amount sold at the end of the previous reporting period (approximately €0.3 billion).

The ratio of finance debt to total equity was 0.51 at 2017 year-end.

The Group Non-GAAP measure of its financial condition “Leverage” was 0.23 at December 31, 2017 reporting a decrease from 0.28 as of the end of 2016. This decline was driven by lower net borrowing, the effects of which were partly offset by a reduction in the Group total equity as explained below.

Total equity decreased by €5,007 million from December 31, 2016. This was due to the negative foreign currency translation differences (€5,573 million) due to a 13.9% appreciation of the euro against the US dollar at year end (the exchange rate recorded on December 31, 2017 at 1.202, compared to 1 euro = 1.055 euro US$ at December 31, 2016), as well as dividend distribution of €2,880 million. These negatives were partly offset by profit for the year.

Total debt of €24,707 million consisted of €4,528 million of short-term debt (including the portion of long-term debt due within twelve months equal to €2,286 million) and €20,179 million of long-term debt.

Total debt included unsecured bonds for €17,965 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to €2,199 million (including accrued interest and discount). Bonds issued in 2017 amounted to €1,817 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (89%), U.S. dollar (8%), British pound (2%) and 1% in other currencies.

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Capital expenditures by segment

Exploration & Production. In 2017, capital expenditures of the Exploration & Production segment amounted to €7,739 million, mainly related to the development of oil&gas reserves (€7,236 million). Significant expenditures were directed mainly outside Italy, in particular in Egypt, Ghana, Angola, Congo, Algeria, Iraq and Norway. Exploration expenditures (€442 million) were directed in particular in Cyprus, Norway, Mexico, Egypt, Libya and Ivory Coast.

In 2016, capital expenditures of the Exploration & Production segment amounted to €8,254 million, mainly related to the development of oil&gas reserves (€7,770 million). Significant expenditures were directed mainly outside Italy, in particular in Egypt, Angola, Kazakhstan, Indonesia, Iraq, Ghana and Norway. Development expenditures in Italy also comprised the upgrading of certain plants at the Viggiano oil center in Val d’Agri, which did not alter the plant set up. This upgrading addressed certain objections made by jurisdictional Authorities about the proper function of the plants and were duly authorized by the competent department of the Italian Ministry of Economic Development. Due to this upgrading, plant activities were regularly restarted following notification by the public prosecutor that it has definitively repealed the plant seizure, as well as sidetrack and workover activities in mature fields. Exploration expenditures (€417 million) were directed in particular in Egypt, Indonesia, Libya and Angola.

Gas & Power. In 2017, capital expenditures in the Gas & Power segment totaled €142 million and mainly related to gas marketing initiatives (€102 million) and to the flexibility and upgrading initiatives of combined cycle power plants (€36 million).

In 2016, capital expenditures in the Gas & Power segment totaled €120 million and mainly related to initiatives to improve flexibility of the combined-cycle power plants (€41 million) and to develop the gas marketing activity (€69 million).

Refining & Marketing and Chemicals. In 2017, capital expenditures in the Refining & Marketing and Chemicals segment amounted to €729 million and regarded mainly: (i) refining activity in Italy and outside Italy (€395 million) aiming fundamentally at reconstruction works of the EST conversion plant at the Sannazzaro refinery, maintain plants’ integrity, reconversion of refinery system, as well as initiatives in the field of health, security and environment; (ii) marketing activity, mainly regulation compliance and stay in business initiatives in the refined product retail network in Italy and in the Rest of Europe (€131 million); (iii) upgrading activities (€84 million); upkeeping of plants (€42 million); maintenance (€42 million), as well as environmental protection, safety and environmental regulation (€35 million) in the Chemicals segment (€203 million).

In 2016, capital expenditures in the Refining & Marketing and Chemicals segment amounted to €664 million and regarded mainly: (i) refining activities in Italy and outside Italy (€298 million) aiming fundamentally at plants improving, as well as initiatives in the field of health, security and environment; (ii) marketing activity, mainly regulation compliance and stay in business initiatives in the refined product retail network in Italy and in the Rest of Europe (€123 million); (ii) upgrading and maintenance at petrochemical plants (€200 million).

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Recent developments

The table below sets forth certain indicators of the trading environment for the periods indicated:

	Three months ended December 31		Three months ended March 31,		Three months ended March 31,
	2017		2017		2018
Average price of Brent dated crude oil in U.S. dollars(1)		61.39		53.78		66.82
Average EUR/USD exchange rate(2)		1.177		1.065		1.229
Standard Eni Refining Margin (SERM)(3)		4.3		4.2		3.0

(1)

Price per barrel. Source: Platt’s Oilgram.

(2)

Source: ECB.

(3)

In $/BBL, FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields.

In the period January 1 – March 31, 2018 the Brent crude oil price was 66.82 $/BBL on average, 24.2% higher than in the first quarter of 2017. This trend will positively affect reported revenues, profitability and cash flow of our Exploration & Production segment, partly offset by the depreciation of the USD.

Significant transactions

In 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.

In 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.

The Company’s Annual General Shareholders Meeting scheduled on May 10, 2018, has been convened to approve the full year dividend proposal of €0.80 per share of which €0.40 paid as interim dividend in September 2017. Eni expects to pay the balance of the dividend for fiscal year 2017 amounting to €0.40 per share in May 2018. The total cash out is estimated at approximately €1.4 billion.

Management’s expectations of operations

Exploration & Production

Management intends to boost the cash generation in the E&P segment leveraging on profitable production growth, capital discipline, effective project execution and strict control of operating expenses and working capital.

Exploration will continue driving the Company’s growth in the short and long-term. In the next four years, our exploration activities will focus on supporting the replacement of produced reserves and on contributing to cash generation. Our priorities in exploration will be:

The discovery of reserves near-field and in proximity to fields under development, where we can leverage on existing infrastructures in order to readily put into production the discovered resources, ensuring fast contribution to cash flows;

ii)

Initiatives in operated licenses with high working interests targeting conventional resources, where in case of material discoveries we can apply our dual exploration model;

iii)

A resumption of activities in high-risk, high-rewards plays.

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Our dual exploration model contemplates both the rapid development of the discovered resources and the divestment of stakes of our exploration discoveries in order to accelerate the conversion of our resources into cash, as witnessed by the closing in 2017 of the deals relating to the divestiture of a 40% interest in the Zohr gas field in Egypt and of a 25% of gas-rich Area 4 offshore Mozambique.

We expect to increase our hydrocarbons production at an average rate of 3.5% across the 2018 – 2021 plan period. This grow will be fuelled organically by new fields start-ups, full production at the fields started in 2017, particularly the Zohr gas field, and continuing production optimization to fight fields natural decline. The main start-ups across the plan period include the gas phase of the Offshore Cape Three Points project in Ghana, development of satellites fields in the Block 15/06 off Angola, the production start-up at Area 1 offshore Mexico and at the Merakes field in Indonesia, additional ramp-ups of the Great Nooros Area fields in Egypt and the high-grading of the Karachaganak field and upgrading of our main fields in Libya. New field start-ups and production ramp-ups will add approximately 700 KBOE/d in 2021. Production optimizations will add 200 KBOE/d in 2021. We believe that those production targets have good visibility because they related to already-sanctioned projects, most of which are operated by Eni, and to incremental development phases at our existing profit centers.

Oil price assumptions are particularly significant when it comes to assessing the Company’s future production performance considering the entitlement mechanism under Eni’s PSAs and similar contractual schemes. The Company estimates that production entitlements in its current portfolio of PSAs vary on average by approximately 2,000 BBL/d for each $1 change in oil prices compared to current Eni’s assumptions for oil prices. We note that in case oil prices differ significantly from our own forecasts, the result of the above mentioned sensitivity of production to oil price changes may be significantly different.

To factor in possible risks of unfavorable geopolitical developments in our countries of operations, which may lead to temporary production losses and disruptions in connection with, among others, acts of war, sabotage, social unrest, clashes and other form of civil disorder, we have applied a haircut to our future production levels based on management’s appreciation of those risks, past experience and other considerations. However, this contingency factor does not cover worst-case developments and extreme events, which could determine prolonged production shutdowns. It is worth mentioning that we expect to reduce our exposure to Libya over the plan period as a result of the slowdown in our exploration and development activities in recent years due to an uncertain political outlook.

Our production plans are incorporating our Brent price scenario of 60 $/BBL in 2018 and a gradual increase 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 2021 onwards crude oil prices will grow in line with a projected inflationary rate). See “Item 4 – Exploration & Production”. Our pricing assumptions are based on the progressive rebalancing of global oil markets, which in our view will be supported in the short-term by the agreement between Opec members and other producing countries to curb production, effective until the end of 2018, and going forward by (i) the effects of the curtailment in expenditures made by international oil companies during the downturn which could led to supply shortage and (ii) a strengthening macroeconomic outlook. However, there are some risks to this outlook, including the role of OPEC and its ability to control global prices and the pace at which unconventional oil producers in the US will be able to bring production back to markets, leveraging the short-cycle nature of this business and rising productivity. We note that the pace of recovery in crude oil prices has slowed down in February and in March and that forward curves of crude oil prices remains in backwardation for long-dated maturities.

Due to those risks and uncertainties, management intends to retain a strong focus on capital and cost discipline and on reducing the time-to-market of our reserves. First, our capital projects will be carefully selected against our scenario assumptions and minimum requirements of internal rates of return. We intend to reduce financial exposure leveraging on a phased approach in developing our projects and on monitoring idle capital employed. Secondly, we plan to continue our focus on delivering our planned projects on time and on budget. Several of our projects are complex due to scale and reach of operations, environmentally-sensitive locations, external conditions, including offshore operations, industry limits and other considerations including the risk factors described in Item 3. These constraints and factors might cause delays and cost overruns. We plan to mitigate those risks in the future by continuing deployment of our skills and by our model of project execution driven by: (i) parallel execution of the main project activities, including discovery appraisal and pre-fid activities; (ii) the in-sourcing of critical engineering and project management phases, for example we are directly managing hook-up and commissioning; (iii) the

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design-to-cost method whereby the Company has redirected its exploration efforts towards mature and low-complexity areas where we can achieve fast time-to-market and cost synergies. Furthermore, phased project development and strict integration between exploration and development have improved the overall project execution and cost efficiency. Finally, we plan to seek opportunities for further reductions in our development and operating costs, for example by reducing the downtime at our facilities and other measures. The mentioned drivers will underpin the profitability of our production going forward, despite our projections of rising trends in the supply costs of materials and equipment in the range of a few percentage points. Due to those drivers and our estimation that in recent years our discovery costs have been efficient, we believe that the price breakeven of our ongoing projects under execution has decreased over the latest years.

Management also plans to increase the share of operated production in the Company’s portfolio. We expect to operate more than 74% of the plan period production. Project operatorship enables the Company to better schedule and control project execution, expenditures and timely achievement of project milestones and to mitigate project risks.

Gas & Power

We expect a weak outlook in the Gas & Power segment due to structural headwinds in the industry as we forecast sluggish demand growth, oversupplies and strong competition across all of our main markets in Europe, including Italy. In spite of a better macroeconomic environment, demand growth will be dampened by rising competition from renewables and increasing energy efficiency. Rising global supplies of LNG will drive continuing competition and pricing pressure. LNG supplies will be fueled by the coming on stream of several export terminals in the United States which will monetize the country’s large reserves of shale gas and the start-up of large LNG projects in the Pacific area. Finally, a new, large project to export gas via pipeline to Europe is expected to start operations in 2020, which will link the Italian market to gas fields in Azerbaijan, and possible regulatory developments might increase the liquidity of the Italian spot market by granting access to gas infrastructures (namely, Italian LNG re-gasification terminals and transport capacity at the main European backbones conveying gas from Northern Europe to Italy) to new comers. These trends are expected to be exacerbated by the constraints of the long-term supply contracts with take-or-pay clauses, which will trigger pricing competition among wholesale operators to limit the financial exposure arising from the contracts in case of volumes off-taken below the minimum take. Based on those expectations, there are market risks to the differential between spot prices at Italian hubs and at European hubs, which management leverages to recover the fixed expenses in the gas wholesale business.

Against this scenario, the Company priority in its Gas & Power business is to strengthen profitability and cash generation. The main drivers to achieve these goals will be the renegotiations of our long-term gas supply contracts to align pricing and volume terms to current market conditions and dynamics, by achieving consistency between supply costs and selling prices on the main markets, considering expectations for an alignment of spot prices at the Italian hubs to those of continental hubs and the fact that our long – term contracts are mainly indexed to spot prices at continental hubs, and minimum off-takes in line with end-markets demand. We plan to optimize our logistic costs, by leveraging on asset-backed activities and eventually on possible regulatory developments intended to increase markets liquidity. We expect better results in our LNG, trading and retail businesses. In LNG, we will leverage on the integration with our upstream operations to extract more value from the development of our gas reserves. We are planning for the achievement of 12 million tonnes per year of contracted volumes in 2021, of which 8 million will come from our equity production in Africa and Far East. In this way, we will seek to capture market opportunities through the flexibilities of our upstream portfolio. In the Gas & Power retail business, the Company’s marketing effort will address retail customers in Italy and in the European markets where we operate in order to valorize the existing customer base against the backdrop of escalating competitive pressures. This will be achieved by the offer of new products and services, brand identity, the administrative advantages of the dual offer of gas and electricity, a competitive cost to serve and continuing innovation in processes, promotion and customer care and post-sale assistance also leveraging on the deployment of digitalization.

Finally, the Company intends to capture margins improvements by means of trading activities by entering into derivative contracts both in the commodity and the financial trading venues in order to capture possible favorable trends in market prices, within the limits set by internal policies and guidelines that define the maximum tolerable level of market risk. As part of this strategy, the Company intends to

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improve results of operations by effectively managing the flexibilities associated with the Company’s assets (gas supply contracts, transportation rights, storage capacities, unutilized power capacity). This can be achieved through strategies of asset-backed trading by entering into derivative contracts to leverage on commodity price volatility, the risks of which might be absorbed in part or entirely by the natural hedge granted by the asset availability. Asset-backed activities may lead to gains, as well as losses the amount of which could be significant. For further information on the market risk and how the Company manages it see “Item 11 – Quantitative and Qualitative Disclosures about Market Risk”.

Based on the above outlined trends and industrial actions, management expects that we will retain profitable, cash-positive operations in the Company’s gas marketing business over the plan period. Our profitability outlook factors in the expected benefits of the ongoing renegotiations of the Company long-term supply contracts, which the Company is seeking to finalize during the plan period, as well as other circumstances subject to risks and uncertainties described in Item 3.

Refining & Marketing

The outlook of the European refining sector is challenging due to structural headwinds in the industry pressured by overcapacity and rising competition from cheaper products streams from the Middle East and other areas, as fuel demand is projected to recover moderately. Management expects refining margins to hover around the 5 $/BBL level in the next four years and beyond. Currently, our refining business breaks even at around 4 $/BBL. A further appreciation of the euro vs. the dollar could negatively affect this target.

Against this backdrop, the Company priority is to retain profitable and cash-positive operations even in a depressed downstream oil environment, by further reducing the breakeven margin of Eni refineries, targeting 3 $/BBL by the end of 2018. The planned initiatives to achieve this goal include the completion of the Gela project designed to transform this refinery into a green refinery, i.e. a refinery able to process renewable feedstock, the second phase of the Venice refinery upgrading, optimization of plant setup and feedstock supply, improved conversion capacity and continued efficiency gains in logistics, energy management and capital discipline. The rebuilding of the EST conversion unit at the Sannazzaro Refinery will be another driver to achieve the target break-even margin. In Marketing activities, where we expect competitive pressure to continue due to muted demand trends, we are planning to improve results of operations mainly by focusing on innovation of products and services anticipating customer needs, strengthening our line of premium products, as well as efficiency in the marketing and distribution activities. Further value will be extracted by the development of our initiatives in the segment of sustainable mobility. Finally, operation efficiency will be supported by our planned deployment of digitalization technologies. We believe that this action will support the achievement of profitable and cash-positive operations at our scenario assumptions.

Chemical

The outlook in the Chemical business is supported by an improving macroeconomic outlook, tempered by structural headwinds in the industry pressured by overcapacity and rising competition from cheaper products streams from the Middle East, Far East and the US. In addition, our petrochemical commodities are exposed to the volatility of the crude oil-based feedstock costs. Over the last few years, we have restructured our business by reducing capacity at low-margin products, divesting or exiting unprofitable lines, plant optimization and other efficiency measures as well as a shift in our product portfolio towards specialties, green chemicals and products with high technology content, which are less exposed to the scenario volatility. Looking forward we believe that further steps are needed to preserve profitable and cash-positive operations. The industrial plan identified the following lines of action: strengthening the productive footprint by means of improved asset integration, increasing efficiency and reliability as well as plant utilization rates; upgrading the product mix by developing differentiated products, green products and new applications through internal R&D and the acquisition of new technologies; and expanding internationally leveraging on joint-venture projects targeting markets with growth opportunities and access to competitive feedstock and outlets. We believe that this action will support the achievement of profitable and cash-positive operations at our scenario assumptions.

Capital expenditures plan

Over the next four years, the Company plans to invest something below €32 billion, unchanged from the previous plan, to support continued organic growth in oil&gas production; approximately 80% of

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planned capital expenditures will be directed to the Exploration & Production segment. The remaining part will fund our ongoing expansion program in the green businesses and selective growth opportunities in the R&M and Chemical segment. Eni’s capital expenditures program is reflective of uncertainties about future trends in the oil markets. We intend to retain strict financial discipline going forward by focusing on the more profitable projects in portfolio and project re-phasing and modularization to reduce our financial exposure. In 2018 we expect to make capital expenditures of approximately €7.7 billion assuming an exchange rate of 1.17 €/$.

Development of oil&gas reserves will attract some €24 billion, of which approximately €16 billion directed to new field start-ups and ramp-ups, while the remaining to production optimization. Project start-ups and plateau enhancement at existing fields will be geographically diversified and executed mainly in Egypt, with the ramp-up of the very important Zohr gas field, Norway, Libya, Nigeria, Kazakhstan and Indonesia, while development activities will continue in Mozambique. Egypt will attract approximately 20% of the Group development expenditures over the plan period. By the end of 2018, we expect to make six main FIDs that, together with our ongoing projects, will entirely cover our production growth up to 2021.

Exploration capex will amount to €2 billion. Our projects will comprise near-field activities designed to provide fast production support and contribution 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.

We are planning to invest approximately €3.5 billion in R&M and Chemical. In R&M our main capital projects include completion of the Gela reconfiguration project, the rebuilding of the EST unit at the Sannazzaro refinery and various initiatives of plant upgrading, as well as network upgrading. In the Chemical business the planned initiatives include plant upgrading and selected growth projects. Finally, we will invest approximately more than €1.8 billion in the green business, the bulk of which will be directed to develop photovoltaic and other renewable-related power plants at our industrial hubs in Italy, or as part of selected E&P properties outside Italy, targeting an installed production capacity of 1 gigawatt at the end of the plan period.

Management expects to pursue strict capital discipline when assessing individual capital projects. Management is assuming a long-term oil price of 72 $/BBL for the Brent benchmark, which is adjusted to take account of expected inflation rates from 2022 onwards. The internal rate of return of each project is compared to the relevant hurdle rate, differentiated by business segment and country of operation. These hurdle rates are calculated taking into account: (i) the weighted average cost of capital (“WACC”) to the Group. In 2017, management assessed that the cost of capital to the Group increased marginally from 2016 mainly due to higher yields on risk-free assets reflecting an improved macroeconomic outlook. Furthermore, we recorded an appreciation of the country risk, which factors in the perceived level of risk associated with our countries of operations in terms of current trends and conditions in the macroeconomic, business, regulatory and socio-political framework, as well as the consensus outlook. A country risk premium is added to the Group WACC and a premium for the business risk in determining the hurdle rates, which are utilized by management in its final investment decisions.

Liquidity and leverage

Considering the uncertainties about future trends in market fundamentals and price volatility, management’s priorities remain to maximize the Group’s cash generation and to preserve a solid balance sheet. We believe the initiatives implemented by management during the downturn intended to lower the cost base, to select capital expenditures and to streamline operations together with the monetization of part of our recent exploration discoveries have improved the Company’s competitive position and strengthened its capital structure. In future years we will continue to focus on financial discipline, which means project selection and cost control, and sustainable growth which will drive profitable production increases, reserve replacement, margin expansion and improving results at our mid and downstream businesses. We expect that better business effectiveness and efficiency and improved operations profitability will help reduce the Brent price at which the Company will be able to fund through cash flow from operations both the planned capital expenditures and the dividend. We are estimating that in 2018 our cash neutrality will be at 55 $ / BBL assuming an average €/$ exchange rate of 1.17, and then will progressively decline in the low fifties by end of the plan period. These targets are reflective of the Company’s initiatives in lowering its cost base and in optimizing its capital plan without impairing its ability to pursue its growth objectives.

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During the downturn, in spite of the sharp contraction in net cash provided by operating activities due to lower oil prices, the Company has managed to maintain its key ratio of net borrowings to equity – leverage – within the ceiling of 0.3 through a combination of cost cuts, asset disposals, capital expenditures curtailments and working capital optimization. At the end of 2017, our leverage stood at 0.23. Looking ahead, we are lowering the target leverage in a range of 0.2 – 0.25. Management believes that the target range leverage is consistent with the Company’s business profile, which features a large exposure to the Exploration & Production segment, and with an uncertain commodity scenario.

Our cash flow projections are exposed to the volatility in the oil price environment and in the USD vs. the EUR exchange rate. Currently, based on our portfolio of oil&gas properties, we estimate that, holding all other factors constant, our net profit and cash flow from operations vary by approximately €0.2 billion for each dollar change in Brent prices on a yearly basis compared to our price forecast. We note that the Brent price in the period January 1 to March 31, 2018 was approximately 66.8 $/BBL on average (it was 54 $/BBL on average in the period January 1 to March 31, 2017). We retain some levels of financial flexibility that we may use in case oil prices should take another leg down in the cycle in the remainder of the year or in subsequent years. Particularly, approximately 50% of the planned investment at the end of the 2018 – 2021 plan has been allocated to projects yet to be sanctioned. In addition, we retain cash reserves and committed and uncommitted borrowing facilities and we are planning to make additional asset disposals in the range of €1.5 billion by 2020 leveraging on our strategy of fast monetizing our high working interests in recent hydrocarbons discoveries.

For planning purposes, management assumed a EUR/USD exchange rate in the range of 1.17 – 1.25 U.S. dollars per euro in the 2018 – 2021 period. Given the sensitivity of Eni’s results of operations to movements in the euro versus the U.S. dollar exchange rate, trends in the currency market represent a factor of risk and uncertainty. Currently, we are estimating that our cash flow from operations minus cash flow from investing/divesting activities varies by approximately €0.2 billion for each 5 cent USD/EUR change. We note that in the period January 1 to March 31, 2018 the EUR/USD exchange rate was approximately 1.23 and appreciated year-on-year. This trend is expected to negatively affect the reported amount of revenues, operating profit and cash flow in our E&P segment. See “Item 3 – Risk factors”.

Dividend policy

Management is committed to a progressive distribution policy in line with our plans of underlying earnings and cash flow growth and considering the scenario evolution. Dividend growth will be driven by the results that ultimately will be achieved in implementing our strategy and by our ability to reduce the expected Brent prices at which the Company’s cash flows from operating activities are able to fund planned capital expenditures and dividend payments. Considering the Company’s outlook of improving results and better business performance and the progress achieved so far in delivering on our financial and industrial targets, management is forecasting to increase the 2018 dividend to €0.83 per share compared to €0.80 per share for fiscal year 2017. Furthermore, the Company is exploring a resumption of the share repurchase program, which management views as a flexible tool to return shareholders cash in excess of that committed to achieve the targeted range of leverage.

In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year.

The expectations described above are subject to risks, uncertainties and assumptions associated with the oil&gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. There are a number of factors that could cause actual results and developments to differ materially, including, but not limited to, political instability in Libya and other countries, crude oil and natural gas prices; demand for oil&gas in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies and climates in countries and regions where Eni operates; regulatory developments; the risk of doing business in developing countries; governmental approvals; global political events and actions, including war, terrorism and sanctions; project delays; material differences from reserves estimates; inability to find and develop reserves; technological development; technical difficulties; market competition; the actions of field partners, including the inability of joint venture partners to fund their share of operating or developments activities; industrial actions by workers; environmental risks, including adverse weather and natural disasters; and other changes to business conditions. Please refer to “Item 3 – Risk factors”.

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Off-balance sheet arrangements

Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in “Item 18 – note 38 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”. Eni’s principal contractual obligations, including commitments under take-or-pay or ship-or-pay contracts in the gas business, are described under “Contractual obligations” below. See the Glossary for a definition of take-or-pay or ship-or-pay clauses.

Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the Company’s financial condition, results of operations, liquidity or capital resources.

Eni has provided various forms of guarantees on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. In addition, Eni has provided guarantees on the behalf of consolidated companies, primarily relating to performance under contracts. These arrangements are described in “Item 18 – note 38 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”.

Contractual obligations

The amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments.

	Total		2018		2019		2020		2021		2022		2023 and thereafter
	(€ million)
Total debt		25,620		5,253		4,148		2,867		1,280		1,262		10,810
Long-term finance debt		22,276		2,000		4,084		2,857		1,279		1,246		10,810
Short-term finance debt		2,242		2,242
Fair value of derivative instruments		1,102		1,011		64		10		1		16
Interest on finance debt		3,513		582		511		411		304		250		1,455
Guarantees to banks		473		473
Non-cancelable operating lease obligations(1)		4,532		883		525		485		371		329		1,939
Decommissioning liabilities(2)		14,786		348		411		398		375		207		13,047
Environmental liabilities		2,673		317		311		282		228		178		1,357
Purchase obligations(3)		107,830		10,989		9,862		8,223		8,233		8,071		62,452
Natural gas to be purchased in connection with take-or-pay contracts(4)		100,244		8,644		8,708		7,452		7,542		7,553		60,345
Natural gas to be transported in connection with ship-or-pay contracts(4)		4,687		1,272		760		516		468		380		1,291
Other ship-or-pay obligations		589		110		99		87		73		59		161
Other purchase obligations(5)		2,310		963		295		168		150		79		655
Other obligations(6)		128		11		3		2		2		2		108
of which:
- Memorandum of intent relating to Val d’Agri		128		11		3		2		2		2		108
TOTAL		159,555		18,856		15,771		12,668		10,793		10,299		91,168

(1)

Operating leases primarily regarded FPSO vessels, assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.

(2)

Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.

(3)

Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.

(4)

Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay or ship-or-pay clauses whereby the Company obligations consist of offtaking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities. See “Item 4 – Gas & Power – Natural Gas Purchases” and “Item 3 – Risk Factors – Risks in the G&P business.

(5)

Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the United States of euro 948 million.

(6)

In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to defined benefit pension plans (See Note 31 to the Consolidated Financial Statements).

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The table below summarizes Eni’s capital expenditures commitments for property, plant and equipment as of December 31, 2017. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. Such costs are included in the amounts shown below.

	Total		2018		2019		2020		2021		2022 and subsequent years
	(€ million)
Committed projects		23,859		6,309		5,688		4,717		3,375		3,770

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 as to be unable to meet short-term finance requirements and to settle obligations.

Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements. The Group has also established a cash reserve, which consists of cash on hand and very liquid financial assets (short-term deposits and held-for-trading securities). This cash reserve according to management plans can alternatively be used to absorb temporary swings in cash flows from operations, to provide financial flexibility to pursue the Group development programs or to fund the Group contractual obligations with respect to the repayment of financing debt at maturity over a 24-month horizon. For a description of how the Company manages the liquidity risk see “Item 18 – note 38 of the Notes on Consolidated Financial Statements”.

Working capital

Management believes that, taking into account unutilized credit facilities, the Company’s liquidity reserves, our credit rating and access to capital markets, Eni has sufficient working capital for its foreseeable requirements.

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amount due. For a description of how the Company manages the credit risk see “Item 18 – note 38 of the Notes on Consolidated Financial Statements”.

For information about credit losses in 2017 and the allowance for doubtful accounts see “Item 18 – note 11 of the Notes on Consolidated Financial Statements”.

Market risk

In the normal course of its operations, Eni is exposed to market risks deriving from fluctuations in commodity prices and changes in the euro versus other currencies exchange rates, particularly the U.S. dollar, and in interest rates. For a description of how the Company manages the Market risk see “Item 18 – note 38 of the Notes on Consolidated Financial Statements”.

Research and development

For a description of Eni’s research and development operations in 2017, see “Item 4 – Research and development”.

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Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

Directors and Senior Management

The following table lists the Company’s Board of Directors as at March 2018:

Name	Position	Year elected or appointed		Age
Emma Marcegaglia	Chairman		2014		52
Claudio Descalzi	CEO		2014		63
Andrea Gemma	Director		2014		44
Pietro A. Guindani	Director		2014		60
Karina A. Litvack	Director		2014		55
Alessandro Lorenzi	Director		2011		69
Diva Moriani	Director		2014		49
Fabrizio Pagani	Director		2014		51
Domenico Livio Trombone	Director		2017		57

In accordance with Article 17.1 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members.

The current Board of Directors was elected by the ordinary Shareholders’ Meeting held on April 13, 2017 which also established the number of Directors at nine for a term of three financial years. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the financial statements for the year ending December 31, 2019.

The Board of Directors is appointed by means of a slate voting system: slates may be presented by the shareholders representing at least 0.5% of share capital. According to the Eni By-laws, three out of nine Directors are appointed from among the candidates of the non-controlling shareholders.

Emma Marcegaglia, Claudio Descalzi, Andrea Gemma, Diva Moriani, Fabrizio Pagani and Domenico Livio Trombone were the candidates of the Ministry of the Economy and Finance. Pietro A. Guindani, Karina Litvack and Alessandro Lorenzi were the candidates of institutional investors (non-controlling shareholders). The Shareholders’ Meeting appointed Emma Marcegaglia as the Chairman of the Board of Directors and, on April 13, 2017, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company.

Three Directors out of nine, including the Chairman, were drawn from the less represented gender, reaching the ratio of one-third of the Directors as provided by the law.

The following provides details on the personal and professional profiles of the Directors.

Emma Marcegaglia was born in Mantua in 1965 and has been Chairman of Eni since May 2014. She has been Chairman of the Fondazione Eni Enrico Mattei since November 2014. She is also Chairman and CEO of Marcegaglia Holding SpA and Deputy Chairman and CEO of the subsidiary companies operating in the processing of steel. She is also Chairman and CEO of Marcegaglia Investments Srl, the holding company of the diversified activities of the group. She is President of Businesseurope and of the Luiss Guido Carli University, a member of the Board of Directors of Bracco SpA and Gabetti Property Solutions SpA. From 1994 to 1996 she was National Deputy President of Young Entrepreneurs of Confindustria, from 1997 to 2000 she was President of the European Confederation of the Young Entrepreneurs (YES), from 1996 to 2000 President of Young Italian Entrepreneurs of Confindustria and from 2000 to 2002 she was Vice President of Confindustria for Europe. From May 2004 to May 2008 she was Confindustria Vice President for infrastructures, energy, transport and environment and Italian Representative of the top High Level Group for energy, competitiveness and environment set up by the European Commission. From May 2008 to May 2012 she was President of Confindustria. She was a member of the Management Board of Banco Popolare and Director of Finecobank SpA and Italcementi SpA. She also held the position of Chairman of the Aretè Onlus Foundation. She graduated with a degree in business administration from the Bocconi University in Milan and attended a Master’s in Business Administration at New York University.

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Claudio Descalzi was born in Milan and has been Eni’s CEO since May 2014. He is a member of the General Board and of the Advisory Board of Confindustria and Director of Fondazione Teatro alla Scala. He is a member of the National Petroleum Council for 2016/2017. He joined Eni in 1981 as Oil & Gas field petroleum engineer and then became project manager for the development of North Sea, Libya, Nigeria and Congo. In 1990 he was appointed Head of Reservoir and operating activities for Italy. In 1994, he was appointed Managing Director of Eni’s subsidiary in Congo and in 1998 he became Vice President & Managing Director of Naoc, a subsidiary of Eni in Nigeria. From 2000 to 2001 he held the position of Executive Vice President for Africa, Middle East and China. From 2002 to 2005 he was Executive Vice President for Italy, Africa, Middle East, covering also the role of member of the board of several Eni subsidiaries in the area. In 2005, he was appointed Deputy Chief Operating Officer of Eni’s Exploration & Production Division. From 2006 to 2014 he was President of Assomineraria and from 2008 to 2014 he was Chief Operating Officer of Eni’s Exploration & Production Division. From 2010 to 2014 he held the position of Chairman of Eni UK. In 2012, Claudio Descalzi was the first European in the field of Oil & Gas to receive the prestigious “Charles F. Rand Memorial Gold Medal 2012” award from the Society of Petroleum Engineers and the American Institute of Mining Engineers. He is a Visiting Fellow at The University of Oxford. In December 2015 he was made a member of the “Global Board of Advisors of the Council on Foreign Relations”. In December 2016 he was awarded an Honorary Degree in Environmental and Territorial Engineering by the Faculty of Engineering of the University of Rome, Tor Vergata. He graduated with a degree in physics in 1979 from the University of Milan.

Andrea Gemma was born in Rome in 1973 and has been Director of Eni since May 2014. He is Professor of Private Law at The Third University of Rome and was visiting professor at European Universities and at Villanova University. Member of the Strategic Board of the American University of Rome and Appeal Court Lawyer. He is also Chairman of Serenissima SGR SpA and member of the Board of Directors of Banca UBAE SpA and of Global Capital PLC. He is President of Board of Statutory Auditors of PS Reti S.p.A. and Sirti S.p.A. He is also Official Receiver of Valtur SpA, Liquidator of Novit Assicurazioni SpA and Sequoia Partecipazioni SpA.

Pietro A. Guindani was born in Milan in 1958 and has been Director of Eni since May 2014. Since July 2008 he has been Chairman of the Board of Directors of Vodafone Italia SpA, where between 1995-2008 he was Chief Financial Officer and subsequently Chief Executive Officer. He previously held positions in the Finance Departments of Montedison and Olivetti and started his career in Citibank after graduating in Business at the Università Luigi Bocconi in Milan. He is currently also Board member of Salini-Impregilo SpA, the Italian Institute of Technology and Cefriel-Polytechnic of Milan. He is Board Member of Confindustria and Member of the Executive Board of Confindustria Digitale; he is President of Asstel-Assotelecomunicazioni and Vice President responsible for Universities, Innovation and Human Capital of Assolombarda. He was also Director of Société Française du Radiotéléphone – SFR S.A. (2008-2011), Pirelli & C. SpA (2011-2014), Carraro SpA (2009-2012), Sorin SpA (2009-2012) and Finecobank SpA (2014-2017).

Karina A. Litvack was born in Montreal in 1962 and has been a Director of Eni since May 2014. She is currently a member of the Global Advisory Council in Cornerstone Capital Inc., a member of the Advisory Board in Bridges Ventures LLC, a member of the CEO Sustainability Advisory Panel in SAP AG, a member of Business for Social Responsibility and of Yachad, a member of the Advisory Council for Transparency International UK and a member of the Senior Advisory Panel of Critical Resource. From 1986 to 1988 she was a member of the Corporate Finance team of PaineWebber Incorporated. From 1991 to 1993 she was a Project Manager of the New York City Economic Development Corporation. In 1998 she joined F&C Asset Management plc where she held the position of Analyst Ethical Research, Director Ethical Research and Director Head of Governance and Sustainable Investments (2001-2012). She was also a member of the Board of the Extractive Industries Transparency Initiative (2003-2009) and of the Primary Markets Group of the London Stock Exchange Primary Markets Group (2006-2012). She graduated in Political Economy at the University of Toronto and in Finance and International Business from Columbia University Graduate School of Business.

Alessandro Lorenzi was born in Turin in 1948 and has been Director of Eni since May 2011. He is a founding partner of Tokos Srl, a consulting firm for securities investment, Director of Ersel SIM SpA and of Mutti SpA. He began his career at SAIAG SpA in the Administration and Control area. In 1975 he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat V.I. SpA, Head of Administration, Finance and Control, Head of Personnel of Orlandi SpA in Modena (1977-1980) and

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Project Manager (1981-1982). In 1983 he joined GFT Group where he was Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of GFT Group (1984-1988), Head of Finance and Control of GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995 he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998 he was appointed Operating Officer and was subsequently Director of Ersel SIM SpA until June 2000. In 2000 he became Executive Officer of Planning and Control at the Ferrero Group and General Manager of Soremartec, the technical research and marketing company of the Ferrero Group. In May 2003 he was appointed CFO of Coin Group and in 2006 he became Chief Corporate Officer at Lavazza SpA, becoming Board member from 2008 to June 2011. From July 2011 to September 2017 he was Chairman of Società Metropolitana Acque Torino SpA.

Diva Moriani was born in Arezzo in 1968 and has been a Director in Eni since May 2014. She is currently Executive Vice Chairman of Intek Group SpA, Vice Chairman of KME AG, a German holding company of KME Group, Director of KME S.r.l., Member of the Supervisory Board of KME Germany GmbH and Director of Assicurazioni Generali SpA, Moncler SpA, Dynamo Academy, Dynamo Foundation and Associazione Dynamo. From 2007 to 2012 she was CEO of I2Capital Partners, a private equity fund sponsored by Intek Group SpA, with an investment strategy focused on “Special Situations” and from 2014 to 2017 CEO of KME AG. She graduated in Economics at the University of Florence.

Fabrizio Pagani was born in Pisa in 1967 and has been a Director in Eni since May 2014. He is currently the Head of the Technical Secretariat of the Ministry of Economy and Finance. He was Deputy Director of the International Training Programme for Conflict Management at the High School S. Anna in Pisa from 1995 to 1998, Professor of International Law in the Faculty of Political Science at the University of Pisa from 1993 to 2001, Deputy Chief of the Legislative Office at the Department of European Affairs from 1998 to 1999 and Counsellor for International Affairs in the Ministry of Industry and Foreign Trade from 1999 to 2001. He was Senior Advisor at the OECD from 2002 to 2006, Head of the Office of the State Undersecretary, within the Prime Minister Office from 2006 to 2008, board member of SACE SpA from 2007 to 2008, Political Counsellor of the OECD General Secretary from 2009 to 2011, Director of the G8/G20 Office at the OECD from 2011 to 2013 and Senior Economic Counsellor to the Prime Minister and G20 Sherpa from 2013 to 2014. He was a NATO Fellow and was a visiting scholar at Columbia University, New York. He graduated in international studies at the Scuola Superiore Sant’Anna, Pisa, and has a Master Degree from the European University Institute, Florence.

Domenico Livio Trombone was born in Potenza in 1960 and has been Director of Eni since April 2017. He is a certified chartered accountant and a certified public auditor. He is partner of Studio Trombone Dottori Commercialisti e Associati. He is currently Chairman of the Board of Directors of Carimonte Holding SpA, of Consorzio Cooperative Costruzioni – CCC, of Focus Investments SpA and of Società Gestione Crediti Delta SpA. Furthermore, he is Director of La Centrale Finanziaria Generale SpA and of Aeroporto Guglielmo Marconi di Bologna SpA. He is also Chairman of the Board of Statutory Auditors of Associazione Costruttori Italiani Macchine Attrezzature per Ceramica (Acimac), Coop Alleanza 3.0 Sc and of Unipol Banca S.p.A. He is standing Statutory Auditor, among the others, of: Arca Assicurazioni SpA, Arca Vita SpA, CCFS Soc. Coop, Cooperare SpA, Parco SpA, Popolare Vita SpA, Unipol Finance Srl and Unipol Investment SpA. He is Liquidator in Italcarni Sc and Judicial Commissioner and Liquidator in Open.Co S.c. He is technical consultant in legal proceedings, coadjutor in bankruptcy proceedings, liquidator, trustee in bankruptcy and judicial commissioner. Over the years he held positions in banks, in asset management and insurance companies. More in detail, he was standing Statutory Auditor in Carimonte Holding SpA, Unicredit Servizi Informativi SpA, Immobiliare Nettuno Srl and Gespro SpA. From April 2006 to March 2007 he was Director of Aurora Assicurazioni SpA. From October 2007 until the merger of the Company in FonSai SpA, he was Chairman of the Board of Statutory Auditors in Unipol Assicurazioni SpA. Until December 2008 he was Director in Banca Popolare del Materano SpA and BNT Consulting SpA. From April 2010 to October 2011 he was Chairman of the Board of Directors in BAC Fiduciaria SpA. From April 2009 to December 2011 he was Chairman of the Board of Statutory Auditors in Arca Impresa Gestioni SGR SpA. From April 2007 until April 2012 he was Chairman of the Board of Statutory Auditors in Cassa di Risparmio di Cento SpA. Since April 2010 to May 2016 he held the position of Chief Executive Officer in Carimonte Holding SpA. From December 2011 to December 2012 he was independent Director in Serenissima SGR SpA. From December 2011 to April 2016 he was Director and Vice Chairman in Gradiente SGR SpA. From April 2007 to April 2016 he was Standing Statutory Auditor of Unipol Gruppo Finanziario SpA. He graduated in Economics from the University of Modena.

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Senior Management

The table below sets forth the composition of Eni’s Senior Management as at December 31, 2017. It includes the CEO, as General Manager of Eni SpA, as well as the Chief Officers and the Executives who report directly to the CEO and to the Board, and on its behalf, to the Chairman, and the CEOs of Eni subsidiaries who are members of Eni’s Management Committee.

Name	Management position	Year first appointed to current position	Total number of years of service at Eni		Age
Claudio Descalzi	CEO and General Manager of Eni	2014		36		62
Luca Bertelli	Chief Exploration Officer	2014		33		59
Roberto Casula	Chief Development, Operations & Technology Officer	2014		29		55
Claudio Granata	Chief Services and Stakeholder Relations Officer	2014		34		57
Massimo Mantovani	Chief Gas & LNG Marketing and Power Officer	2016		24		54
Massimo Mondazzi	Chief Financial Officer	2014		25		54
Giuseppe Ricci	Chief Refining & Marketing Officer	2016		32		59
Antonio Vella	Chief Upstream Officer	2014		34		60
Marco Bollini	Legal Affairs Department Senior Executive Vice President	2016		20		51
Marco Petracchini	Internal Audit Department Senior Executive Vice President	2011		18		53
Roberto Ulissi	Corporate Affairs and Governance Department Senior Executive Vice President and Board Secretary and Corporate Governance Counsel	2006		11		55
Marco Bardazzi	External Communication Department Executive Vice President	2015		2		50
Luca Cosentino	Energy Solutions Department Executive Vice President	2015		14		56
Lapo Pistelli	International Affairs Department Executive Vice President	2017		2		53
Luca Franceschini	Integrated Compliance Department Executive Vice President	2016		26		51
Jadran Trevisan	Integrated Risk Management Executive Vice President	2016		17		56
Alberto Chiarini	CEO of Eni gas e luce SpA	2017		28		54
Daniele Ferrari	CEO of Versalis SpA	2011		6		56
Vincenzo Maria Larocca	CEO of Syndial SpA	2016		31		56

The Chief Exploration Officer, the Chief Development, Operations & Technology Officer, the Chief Upstream Officer, the Chief Gas & LNG Marketing and Power Officer, the Chief Refining & Marketing Officer, the Chief Financial Officer, the Chief Services & Stakeholder Relations Officer, the Senior Executive Vice President Legal Affairs Department, the Senior Executive Vice President Internal Audit Department, the Senior Executive Vice President Corporate Affairs and Governance Department, as well as the Executive Vice President Energy Solutions Department, the Executive Vice President External Communication Department, the Executive Vice President International Affairs Department, the Executive Vice President Integrated Compliance Department, the Executive Vice President Integrated Risk Management, the Chief Executive Officer of Versalis SpA, the Chief Executive Officer of Eni gas e luce SpA, and the Chief Executive Officer of Syndial SpA are members of the Management Committee, which provides advice and support to the Chief Executive Officer. Other managers may be invited to attend meetings based on the agenda. The Chairman of the Board is invited to attend meetings. The duties of Committee Secretary are performed by the Senior Executive Vice President Corporate Affairs and Governance Department.

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The Chief Financial Officer has been appointed as Officer in charge of preparing Company’s financial reports pursuant to Italian law by the Board of Directors, acting upon a proposal of the CEO in agreement with the Chairman, following consultation with the Nomination Committee and with the approval of the Board of Statutory Auditors.

The Senior Executive Vice President of the Internal Audit Department is appointed by the Board of Directors, acting upon a proposal of the Chairman in agreement with the Chief Executive Officer (in his capacity as Director in charge of the internal control and risk management system), following consultation with the Board of Statutory Auditors and the Nomination Committee and with the favorable opinion of the Control and Risk Committee.

The Board Secretary and Corporate Governance Counsel is appointed by the Board of Directors upon a proposal of the Chairman.

Other members of Eni’s senior management are appointed by Eni’s CEO and may be removed without cause.

Senior Managers

Luca Bertelli was born in Sesto Fiorentino on 5 October 1958. He graduated with honours in geology in 1983 from the University of Florence. In 1984 he joined Eni’s geophysics division, working first as a researcher in the development of 3D seismic prospecting technology and subsequently as a manager of 3D seismic prospecting programmes, specialising in seismic-stratigraphy. In 1994 he was appointed manager of seismic-stratigraphy applications and in 1999 he increased the technical-managerial scope of his activities becoming manager of geological and geophysical services in Eni.

At the end of 2001, his career took a new international turn holding positions of increasing managerial complexity over a period of eight years, starting in Norway where he was Technical Director and Deputy Managing Director at Norsk Agip in Norway. In 2003 he was appointed Managing Director of Eni Indonesia and in 2006 he moved to Egypt as General Manager and Managing Director, a position he also held at Eni Angola in 2007. In 2009 he returned to Eni’s headquarters as Senior Vice Chairman of Global Exploration. He was appointed Executive Vice President of Exploration and Unconventional at the beginning of 2010. Since July 1, 2014, he has been Eni’s Chief Exploration Officer.

Roberto Casula was born in Cagliari in 1962. He graduated in mining engineering from the University of Cagliari. He joined Eni in 1988 as a Reservoir Engineer. He spent the first years of his professional life working in oil fields in Italy before moving to West Africa, where he was appointed Chief Development Engineer. He returned to Headquarters in 1997 as coordinator of Business Development activities for Africa and the Middle East, contributing to a number of new initiatives and portfolio activities. In 2000, he became Technical Services Manager and in 2001 moved to the Middle East as Project Director on a giant gas production project. From 2004 to 2005, he held a number of managerial positions in Eni’s Exploration & Production Division, eventually becoming the Chief Executive Officer of Eni Mediterranea Idrocarburi S.p.A., where he was involved in oil and gas exploration and production in Sicily. At the end of 2005, he was appointed Managing Director of Eni’s subsidiaries in Libya, where he remained for two years and concluded the renegotiation of oil contracts and launched an important programme of social projects. In October 2007, he became head of operational and business activities for sub-Saharan Africa as Senior Vice President. In December 2011, he was appointed Executive Vice President of Eni’s Exploration & Production Division and his responsibilities were extended to include the entire African continent and the Middle East region, also coordinating the Mozambique programme for the development of the Mamba and Coral discoveries. From 2014 to May 2016, he was a member of the Board of Directors of the Eni Foundation.

He has been Chairman of Versalis S.p.A. since January 2017. He has been Chairman of the Italian Petroleum and Mining Association since May 2016. Since July 1, 2014, he has been Eni’s Chief Development, Operations & Technology Officer.

Claudio Granata was born in Rome in 1960. Graduating with a degree in economics, he joined the Eni group in 1983. From 1983 to 1994 worked as a labour market and social welfare expert with ASAP (the trade union association for Eni Companies). From 1994 to 1999 he continued his experience with Eni Corporate as an expert in industrial relations. In 2000 he was made responsible for Staff and Organisation within Eni Servizi Amministrativi, a company that was set up to centralise Eni’s administrative activities.

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In 2001 he took over the management of Eni’s territorial divisions, restructuring the management of staff by geographical area and in 2003 he took on the role of Business HR for Eni Corporate, ensuring support for departments in the management and development of Eni Corporate’s managerial resources during a period of profound change (2002-2004), which was characterised by the mergers of Snam and AgipPetroli and the restructuring of staff organisation. In the same year he was also appointed head of Human Resources and Organisation of SOFID (Eni’s financial services company).

In 2006 he was appointed Human Resources Director of the E&P Division, where he oversaw the planning, management, development and compensation processes for human resources and organisation activities. He also collaborated with the top management in the reorganisation of macro processes for the division and promoted change management initiatives.

He became a board member of Eni International Resources Ltd in 2006 and was Chairman of the board of Eni International Resources Ltd from 2012 to 2013. From 2012 to March 2015 he was a board member of Eni UK ltd.

In 2013 he was appointed Executive Vice President Sustainable Development, Safety, Environment and Quality at E&P, responsible for overseeing safety, environment and quality processes to promote integration with operational processes and contribute to improvements in “time to market” and efficiency. From 2014 to May 2016, he was a member of the Board of Directors of the Eni Foundation. He has been Chairman of the board of Eni Corporate University since November 2014. He has been Chief Services & Stakeholder Relations Officer in Eni since 1 July 2014.

Massimo Mantovani was born in Milano in 1963. He graduated with a degree in law from the University of Milan and holds a Master’s Degree from the University of London. He is the author of numerous publications. After qualifying to practice law in Italy and UK he worked for few years in private legal practice in Milan and London. In 1993 he joined Eni’s Legal Department, specializing in international negotiations and contracts, specifically on international gas/LNG supplies and projects and joint ventures for the commercialization and transport of gas. In 2001 he was appointed legal Director of Eni’s Gas & Power Division. His main task was participating to the management for Eni of the start-up phase of the liberalization of the gas market in Italy and the unbundling of the national and international network for the transport of gas. In October 2005 he was appointed Senior Executive Vice President of Legal Affairs in Eni S.p.A.

He has been Chief Legal and Regulatory Affairs in Eni from 2014 to 2016, the department managed all legal and energy regulatory issues of Eni and its non-listed subsidiaries. From 17 October 2016 to 3 August 2017 he has been Chief Midstream Gas & Power Officer.

From 2005 to 2016 he was member of Eni S.p.A. Watch Structure. He was a member of the Board of Directors in Snam Rete Gas S.p.A. from 2005 to 2012 and of the Board of University of Bologna from 2011 to 2012.

He has been Chairman of Syndial S.p.A. from 2016 to 2017. Since November 2016 Mr. Mantovani seats on behalf of Eni in the Governing Board and in the Executive Committee of Eurogas, the association representing the European gas sectors firms. He is Chairman of Anigas, the Italian association of Gas industry, from December 2017 and member of the Confindustria Energia presidential board.

Between 2011 and 2014 he has been a member of the anticorruption working group for the B20, coordinator for activities relating to the development of an international regulatory framework for the B20 held in Russia in 2013 and leading expert for the 2014 B20 in Australia.

He is Eni’s Chief Gas & Lng Marketing and Power Officer since 4 August 2017.

He is Chairman of Eni Trading & Shipping S.p.A. since November 2016 and from February 2018 he has also been appointed CEO of the company in charge of Gas, LNG and Power activities.

Massimo Mondazzi was born in Monza in 1963. He graduated in Economics and Business Administration from Bocconi University Milan in 1987.. He joined Eni in 1992 after acquiring considerable professional experience in industrial companies and also as a management consultant. He worked in the Administration and Control area of the Exploration and Production Division until 2006, becoming Director. From 2006 to 2009 he was Director of Planning and Control for the Eni Group, before returning to E&P as Executive Vice President for the Central Asia, Far East and Pacific Region business areas. In this role he contributed to the consolidation of Eni’s activities in the Exploration and Production division, to the launch of new development projects and to Eni’s entry into new countries. On December 5, 2012 he was appointed Chief Financial Officer of Eni and Officer charged with preparing the company’s financial reports pursuant to Article 154-bis of Legislative Decree No. 58/1998. He is Chairman of Agi S.p.A. since 2013. From 2014 until September 2016, alongside his role as Eni’s Chief Financial Officer, he was also responsible for Eni’s Integrated Risk Management department.

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Giuseppe Ricci was born in Casale Monferrato in 1958. He has a degree in chemical engineering. He joined Eni in 1985 initially working in the study and development of new refining processes at the Sannazzaro refinery, before becoming involved in the creation and consolidation of the joint venture with Kuwait Petroleum at the Milazzo refinery. In 2000 he returned to head office as where he was responsible for Refining Processes Development and oversaw the performance optimisation at the refining facilities of Agip Petroli. He left central technologies to take over, in 2004, as director of the Gela Refinery, a particularly challenging assignment both from a managerial perspective and in terms of the refining cycle and the complexity of the plant; in 2006 he was appointed managing director of the refinery. In June 2010 he was made Senior Vice President of the Industrial Sector for Refining & Marketing, with responsibility for the refineries, storage deposits, oil pipelines and plant and facilities in Italy, as well as the management of subsidiary and associated companies in Italy and abroad. As Industrial Director he also held a series of additional responsibilities, such as the chairmanship of Gela and Milazzo. In 2012 he took on the delicate role of Eni’s Executive Vice President Health, Safety Environment and Quality with responsibility for providing the guidelines, coordination and control of safety, industrial health, product safety, the environment and quality. Since 2016 he has been a board member of Eniservizi. He was appointed as Chief Refining & Marketing Officer on September 12, 2016.

Antonio Vella was born in 1957. He graduated with a degree in engineering from the Turin Polytechnic in 1982 and joined the Eni Group in 1983. He began his career as an oil engineer at Agip in Libya, where he was involved in upstream onshore and offshore operations. From 1988 to 1991, he was project manager for EniChem’s petrochemical plants and refineries in Italy. In 1991, he was appointed project manager for the development of Libyan oil fields and in 1993, he moved to Egypt, initially as Operations Manager and subsequently as General Manager and Managing Director of Petrobel, where he was responsible for all of Eni’s upstream operations in Egypt. In 1999, he was appointed District General Manager of Nigerian Agip Oil Co (NAOC), and in 2000, became Vice Chairman and Managing Director of the Eni companies in Nigeria NAOC, NAE (Nigerian Agip Exploration) and AENR (Agip Energy). In 2002, he became regional Vice President for Australasia, Russia, Azerbaijan and then, in 2005, a Member of the Board of Directors and Managing Director of Eni Algeria. From 2006 to 2009, he was regional Senior Vice President for North Africa and the Middle East (Algeria, Tunisia, Egypt, Libya, Mali, Morocco, Iran, Iraq and Saudi Arabia) for Eni’s Exploration & Production Division. In 2009, he was appointed Executive Vice President Operations for the Exploration & Production Division. In December 2012, he was appointed Executive Vice President for Central Asia, the Far East and the Pacific Area. Since July 2014, he has been a Board Member of Eni Foundation. Since July 1, 2014, he has been Chief Upstream Officer.

Marco Bollini was born in Milan in 1966. He graduated with a degree in law from the University of Milan and he is registered to practice law on the special list of the Ordine degli Avvocati (the Italian bar association) of Milan. After graduating, he worked as a lawyer for a few years in a law firm in Milan. He joined Eni in 1997 in the Legal Department of Agip S.p.A., mainly following international legal projects until 2001 when he took on the responsibility of International Legal Assistance of Exploration and Production Division. In 2005 he was appointed Legal Director of the Gas &Power Division, further diversifying his business knowledge. In 2007, he is back in the Exploration & Production Division as Legal Director. In 2008, following the centralization of the Eni’s legal function into one Legal Department, he took on responsibility for the legal assistance to the company’s activities outside Europe. In 2013 he was appointed Executive Vice President International Business Legal Area and, in 2015, he became Executive Vice President International and Finance Legal Affairs of Eni, with a strong exposure to international matters, with a particular focus on the Upstream business and management of partnerships and M&A transactions. Since 2016, he has been a Board Member of Eni Foundation. He was appointed Senior Executive Vice President Legal Affairs on October 17, 2016.

Marco Petracchini was born in Rome in 1964. He graduated Cum Laude with a degree in economics from La Sapienza University in Rome in 1989. After graduation, he was hired by Esso Italiana where he held various positions in the IT, Finance and Auditing sectors. He joined Eni in 1999 in the Internal Audit Department, gradually taking on positions of increasing responsibilities: Head of Downstream Audit activities and Head of Support Process Audit activities (in particular IT and Fraud Audit). He is also a Member of the Watch Structure of Eni SpA and Secretary of the Control and Risk Committee of Eni SpA. He holds international qualifications as well, in detail: Certified Internal Auditor (CIA), Certified Fraud Examiner (CFE), Certified Risk Management Assurance (CRMA). He is currently a Board Member of AiiA (Italian Internal Auditors Association). He is Eni’s Senior Executive Vice President Internal Audit Department.

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Roberto Ulissi was born in Rome in 1962. He’s a lawyer. After a number of years spent as a lawyer at the Bank of Italy, in 1998, he was appointed General Manager at the Ministry of the Economy and Finance, head of the Banking and Financial System and Legal Affairs Department. He was a Board member of Telecom Italia (and Chairman of the Audit Committee), Ferrovie dello Stato, Alitalia, Fincantieri and a government representative on the Governing Council of the Bank of Italy. He is a board member and Vice Chairman of Banor SIM. He was also a member of numerous Italian and European committees representing the Ministry of the Economy, including, at a national level, the Commission for the Reform of Corporate Law (Commission “Vietti”) and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also special professor of banking law at the University of Cassino. He is Grande Ufficiale della Repubblica Italiana. Since 2006, he has been Senior Executive Vice President Corporate Affairs and Governance and a Board Member of Eni International BV. He is currently Board Secretary of Eni and, since 2014, Corporate Governance Counsel.

Marco Bardazzi was born in Prato in 1967. He is a professional journalist working in the media world for 28 years before joining Eni in 2015. He has gained extensive experience on foreign policy and digital communications, particularly in Europe and America. Between 2009 and 2015 he was Managing Editor and Digital Editor at “La Stampa”. He was a key member of the team that worked on the transformation of a traditional newspaper to an integrated digital news organization, creating an innovative “concentric circles” multiplatform newsroom. He was one of the co-founders of “Europa” a partnership between La Stampa, Le Monde, El País, The Guardian, Gazeta Wyborcza and Suddeutsche Zeitung. Before joining “La Stampa”, he was U.S. correspondent for the Italian news agency ANSA between 2000 and 2009, covering every aspect of American life for the Italian media. Among other things, he covered the Bush-Gore electoral race for the White House in 2000, the first international Al Qaeda trial in Manhattan, the September 11 attack on America, the wars in Afghanistan, and Iraq and the 2004 and 2008 presidential campaigns. He has visited and reported on the Guantanamo detention camp at the U.S. Navy Guantanamo Bay base in Cuba. He won the Saint-Vincent Award for Journalism for a series of reports on the death penalty in the USA. He covered the 2008 financial crisis, and he reported extensively on the American digital, energy and automobile industries.

He holds an Associate of Arts degree in History from American Public University. His latest book is “L’Ultima Notizia” (with Massimo Gaggi, Rizzoli 2010), an essay on digital transformation in the media business. He is an external lecturer in the Masters in Journalism in ALMED-Università Cattolica del Sacro Cuore, Milan.. He is a Visiting Fellow at the University of Oxford. In 2017 he was appointed as a Director of Agi SpA and Eni Gas e Luce. Since February 2015, he has been External Communication Department Executive Vice President.

Luca Cosentino was born in Venice on August 1, 1961. He graduated cum laude with a degree in geology in 1985 from the University of Padua and joined Eni in 1986. He spent the first years of his professional life in the Reservoir Department, within the reservoir modeling group. Between 1992 and 1996, he worked in different operational positions in Italy and abroad in the reservoir sector. From 1996 to 2003, he worked as Project Manager with IFP (Institut Français du Petrol, France), in Venezuela and in the Persian Gulf. In this period, he also taught at the IFP School and published several technical papers, including a book on Integrated Reservoir Studies. Upon his return to Eni in 2003, he was appointed Head of the Reservoir Department and, in 2004, Head of the Reservoir Modeling Department. From 2005 to 2010, he was in Libya, initially as Operation and Asset Manager with Eni North Africa and then as Member of the Management Committee in the operating company Eni Oil, later Mellitah Oil & Gas. From 2010 to 2013, he has been Managing Director of Eni Congo. In 2013, he was appointed Senior Vice President Non Operated Business Performance and Stranded Resources Valorization. Since November 1, 2015, he has been Executive Vice President Energy Solutions Department.

Lapo Pistelli was born in Florence in 1964. Having graduated with honors in 1988 in International Law at the Political Science faculty “Cesare Alfieri” at the University of Florence, he started working at a research center, while serving for two mandates in the local administration of Florence. He was member of the Italian Parliament from 1996 to 2015 (1996/2004 and 2008/2015), and also member of the European Parliament (2004/2008). As an Italian MP, he was member of the Committees on Constitutional Affairs, European Affairs and on International Affairs. As a MEP in Brussels, he worked at the Economic and Monetary Affairs and Foreign Affairs Committees. During this period, he has also been the President of the EU-South Africa Delegation and a member of the Italian Delegation to the OSCE, where he conducted several monitoring missions in transitional democracies.

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He served as Deputy Minister of Foreign Affairs and International Cooperation of Italy from 2013 to 2015. He resigned from all his institutional and political roles in July 2015, when he entered Eni as Senior Vice President for Strategic Analysis for Business Development Support. He was appointed Executive Vice President in April 2017. He taught and lectured at the University of Florence, the Overseas Studies Program of Stanford University and many others international academic institutions. He regularly contributed to many European and American think tanks and research centers specialized in international relations. He is a member of the board of the European Council on Foreign Relations (ECFR), of the Istituto Affari Internazionali (IAI), of the editorial board of Oil and of the scientific committee of EastWest. As a journalist, he regularly publishes in various newspapers issues related to European and international affairs and on specialized magazines, such as Limes. He authored several publications: in his last book, Il nuovo sogno arabo – Dopo le rivoluzioni, Feltrinelli 2012, he analyses the origin and challenges of the ‘Arab Spring’ and its impact on the geo-political scenario in North Africa and the Middle East.

Luca Franceschini was born in Milan in 1966. He is a graduate in Law from the University of Milan and is registered to practice law on the special list of the Ordine degli Avvocati (the Italian Bar association) in Rome. He first joined in Eni in 1991 in the legal department of Agip S.p.A., initially involved in disputes and providing legal assistance to the procurement area, before going on to delivering legal support for a range of national and international projects in the Exploration & Production sector. In 2000, in the context of the process for the liberalisation of the natural gas sector, he was involved in the spin-off of the gas storage business and the creation and launch of Sogit SpA, for which he became head of Legal and Corporate Affairs. He made his return to Eni Spa in 2005 as head of Italian Legal Assistance in the Gas & Power division. Following the concentration of all legal functions in Eni’s central Legal Department, he was engaged in providing legal support in the regulatory and antirust areas, gradually extending his responsibilities and becoming, in 2009, head of Legal Assistance for the business and Antitrust issues in Italy, as well as council for legal assistance for the activities of the Refining & Marketing sector. He was also a member of the boards of directors of both Italgas and Stogit. In 2015 he was appointed as Eni’s Executive Vice President for Legal and Regulatory Compliance. He was appointed as Executive Vice President of Integrated Compliance on September 12, 2016.

Jadran Trevisan was Born in Milan in 1961. He has a degree in philosophy and a Master’s in business administration from SOGEA, the management school of Confindustria Liguria. After a short period at Gabetti, in 1991 he joined the Fininvest Group, where he was involved in financial communications and was part of the project for the listing of Mediaset for which, in 1995, he became the Investor Relations Manager. In 2000 he joined Eni as head of Investor Relations, where, in addition to participating in a number of significant extraordinary operations (the listing of Snam Rete Gas, the de-listing of Italgas), he oversaw relations with institutional investors. In 2006 he was appointed head of Business Strategy at Eni’s E&P division, where he was involved in the acquisition of significant assets and companies operating in the upstream sector. In 2008 he was appointed CFO of the recently acquired subsidiary Distrigas, where, for the following three years, he was engaged in consolidating and aligning the company’s business and financial processes with those of Eni and rationalising the company structure. In 2011 he was part of the project for the creation of Eni Trading & Shipping SpA, becoming its Senior Vice President for Operations & Control. From the end of 2012 until July 2015 he was Senior Vice President Credit and in August 2015 he was appointed Senior Vice President for Integrated Risk Management. Since September 12, 2016 he reports directly to the Chief Executive Officer in his role as Executive Vice President Integrated Risk Management.

Alberto Chiarini was born in Milan in 1963. After taking a degree in political science and a specialization at the Scuola Enrico Mattei, he joined Eni in 1989. He began his career in an international context, where he had assignments of growing responsibility in the Finance function in a number of countries (including the United Kingdom, Congo, Libya and Netherlands), until he raised to the position of Managing Director of Eni UK. He returned to Italy in 2006 as head of Planning and Control at the Exploration and Production division. Later, he was appointed as Eni’s Executive Vice President Global Procurement and Strategic Sourcing. In 2011, he was appointed Chief Executive Officer of Syndial, the Eni subsidiary that provides integrated services in the field of environmental remediation. By the end of 2013, he was appointed Chief Financial and Compliance Officer of Saipem SpA, holding the levers of Finance, Legal Affairs & Compliance and ICT, overseeing in particular the recapitalization and refinancing of the company. In 2016, he was appointed Chief Retail Market Gas & Power Officer of Eni SpA. In this role he led the spin-off of the retail gas & power business of Eni and the establishment, in 2017, of Eni gas e luce

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SpA, the new Eni subsidiary dedicated to commercialization of gas, power and services. Since then, he is Chief Executive Officer of Eni gas e luce SpA, and in this role he is leading a major transformation of the company, based on products innovation and business processes digitalization.

Daniele Ferrari, 56, is Chief Executive Officer of Versalis SpA and Chairman of Matrica SpA, the joint-venture with Novamont on renewable chemistry. Under his leadership in 2012, the Eni chemical company has undertaken a significant strategic move from a former “Polimeri Europa” into a new “Versalis” through the repositioning of its asset base, geography and portfolio by emphazising R&D, leveraging licensing and new global partnerships. With over 30 years in the chemical industry, he began his career at InterWat (Idreco group), a water treatment engineering company. In 1982 he moved to the Refining Technology unit of Agip Petroli and in 1986 he joined the Milan-based offices of ICI (Imperial Chemical Industries) where he held positions in a variety of areas including sales, technical development, chemicals and plastics marketing, and eventually serving as senior executive in 1990. Internationally, in 1992, he moved to the UK to join the “Klea” Fluorocarbons & Lubricants business headquarters following the business global development and subsequently taking over the position of EMEA Commercial Director of the business. In 1996 he headed to the ICI’s Polyurethanes Brussels-based headquarters to serve as Global Business Unit Director for PU Intermediates. When Huntsman Corporation acquired the bulk of the ICI business in 1999 and the Rhodia-Albright & Wilson’s European business, he was appointed Managing Director of the newly-integrated Huntsman Surface Science-Italy and, later Vice President EMEA of the Brussels-based Huntsman Performance Products Division in 2004. He was then named in 2008 President of the Performance Products Global Division, based in Houston, TX. Daniele Ferrari is also: President of PlasticsEurope, the European association of plastics manufacturers; Board member of CEFIC (Conseil Européen de l’Industrie Chimique, Brussels) and member of the Nominee Committee; Vice President of Federchimica (Italian Chemical Industry Council) for European Affairs and Economy; Board member of the OUBEP (Oxford University Business Economics Program); member of the Board of Directors and Chairman of the Compensation Committee of Venator Materials Plc.

Vincenzo Maria Larocca was born in Alberobello (BA) in 1961. He graduated in Law at Bari University and he started working for Eni in 1986 in the legal department providing national and international legal assistance for Enichem SpA. Then in 1993 he was responsible for International and community rights for Enichem SpA. At the same time as a member of “High Legal Strategy Group - Legal” and “Working Party on Competition Law”, which was created by the Cefic (Conseil Européen des Fèdèrations de l’industrie chimique) for the monitoring of the evolution of the community rights, he represented Enichem and Federchimica. In 2002 he became Legal Affairs and Secretariat Director at Polimeri Europa. As such he dealt with matters related to extraordinary operations portfolio, contentious and environmental matters. In 2006 he was responsible for the Legal Assistance for petrolchemistry and Syndial SpA, with a particular focus on HSE and environmental law. Then in 2007 as a Legal Director he provided consultancy for Refining & Marketing Division in Italy and abroad. In 2008 he was appointed General Counsel of Industial Activities in Italy providing legal assistance in terms of exploration & production, refinery of crude oil and distribution of petrol, petrolchemistry and other activities. In addition, he provided legal assitance for HSE. In 2010 as SVP General Counsel for the Legal Compliance department he dealt with legal assistance related to business responsability, anticorruption, penal law and HSE for Eni. In 2011 he also managed the legal assistance for procurement at the headquarters and subsidiaries and in 2015 he was Legal and Penal Direction EVP. He has been CEO for Syndial SpA since September 2016.

Compensation

Board members’ emoluments are determined by the Shareholders’ Meeting, while the emoluments of the Chairman and CEO, in relation to the powers entrusted to them, are determined by the Board of Directors, which considers relevant proposals made by the Compensation Committee after examining the opinion of the Board of Statutory Auditors.

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Moreover, in accordance with the applicable Italian laws and regulations (Article 123-ter of Legislative Decree No. 58 of February 24, 1998 and Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications) and in line with the Corporate Governance Code recommendations for Italian listed companies, the Board of Directors approves and submits to the annual Shareholders’ Meeting advisory vote, the first section of the Remuneration Report which describes the Remuneration Policy Guidelines adopted for Directors and other Managers with strategic responsibilities(9).

The main elements of the 2018 remuneration policy and of the compensation paid in 2017 to Directors, Statutory Auditors, CEO and General Manager and other Managers with strategic responsibilities, are described below.

2018 Remuneration Policy Guidelines

This chapter contains the Remuneration Policy Guidelines approved by the Board of Directors on March 15, 2018 for Directors and for other Managers with strategic responsibilities.

The 2018 Remuneration Policy Guidelines contain no substantial changes compared with what was previously described in the first section of the 2017 Remuneration Report examined by shareholders at the annual meeting of 13 April 2017, which was approved by favorable vote of 96.33% of those in attendance.

In this chapter, we also present the remuneration for Directors with delegated powers (i.e. the Chairman and the Chief Executive Officer and General Manager), as recommended by the Compensation Committee and having heard the opinion of the Board of Statutory Auditors, approved by the Board of Directors on 19 June and 27 July 2017. These resolutions were passed in line with the 2017 Remuneration Policy Guidelines and with the conditions of the 2017-2019 Long-Term Incentive Plan.

The Board took account of the elimination of the previous restrictions concerning the reduction of remuneration for executive directors of listed companies that are controlled, directly or indirectly, by government entities and of the results of comparative remuneration analyses with similar panels.

Market references and peer group

For the Chief Executive Officer and General Manager, the positioning of the Company’s remuneration is assessed by comparing similar roles only in the international Oil & Gas sector, with regard to upstream activities in particular, and in line with the company’s strategy to increase its focus on the business. More specifically, the comparator group includes the main listed companies in the Oil & Gas sector, which are Eni competitors at the international level and possess comparable business characteristics (Anandarko, Apache, BP, Chevron, Conoco Phillips, ExxonMobil, Marathon Oil, Shell, Statoil and Total).

This panel also constitutes the Peer Group used for the relative comparison of Eni performance in the new Long-Term Performance Share Plan.

For the Chairman and the Non-Executive Directors, the positioning of remuneration is assessed by comparing similar roles in the “Top Italy” panel, composed of the main companies listed on the FTSE MIB (Assicurazioni Generali, Atlantia, Enel, Intesa Sanpaolo, Leonardo, Luxottica, Mediaset, Mediobanca, Poste Italiane, Snam, Terna, TIM, Unicredit).

For Managers with strategic responsibilities, the positioning of remuneration is assessed by comparing roles with the same level of managerial responsibility and complexity in national and international panels of companies in the industrial sector.

(9)

Those persons who have the power and responsibility, directly or indirectly, for planning, directing and controlling Eni fall under the definition of “Managers with strategic responsibilities”, pursuant to Consob regulations. Eni Managers with strategic responsibilities, other than Directors and Statutory Auditors, are those who sit on the Management Committee and, in any case, those who report directly to the Chief Executive Officer.

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General principle of clawback

Clawback mechanisms will be adopted, through a specific regulation proposed by the Compensation Committee and approved by the Board of Directors, allowing the variable remuneration components already paid and/or granted to be reclaimed, or those subject to deferral to be withheld, where their achievement was based on data that was subsequently proven to be manifestly misstated, or allowing the recoupment of all the incentives for the year (or years) in which subsequent checks confirm the fraudulent alteration of the results data used to obtain the right to incentives, and/or the commission of serious and deliberate violations of the law and/or regulations, the Code of Ethics or the Company rules, if relevant to the employment and trust relationship, without prejudice to any other action permitted by law and regulations to protect the interests of the Company. The regulation provides that the activation of recoupment claims (or revocation of incentives awarded but not yet paid) must take place, once the checks have been completed, within three years of payment (or award) in the case of error, and within five years in the case of fraud.

Chairman of the Board of Directors

Remuneration for the delegated powers

The 2018 Remuneration Policy Guidelines for the Chairman provide for total fixed remuneration of €500,000 gross, which includes: €90,000 gross for the position, as determined by the Shareholders’ Meeting of 13 April 2017 and remuneration for exercise of delegated powers of €410,000 gross, as approved by the Board of Directors on 19 June 2017, taking account of the outcome of the comparative analyses of remuneration related to median levels in the benchmark market and the complexity of the position.

The 2018 Remuneration Policy provides also for life insurance policy and permanent disability insurance policy due to injury or illness contracted in the workplace or elsewhere.

Payments due in the event of termination of office or employment

No specific severance payments are provided for the Chairman, nor do any agreements exist for indemnities in the case of resignation or early termination of office.

Non-executive directors

Remuneration for participation on Board Committees

The 2018 Policy Guidelines for Non-Executive and/or Independent Directors provide for the maintenance of the additional annual remuneration for participating on Board Committees, as approved by the Board of Directors on 13 April 2017 and in line with the median levels recorded in the reference market, taking due account of the commitment in terms of frequency and duration of meetings, as follows:

•

for the Control and Risk Committee, annual remuneration consists of €70,000 for the Chairman and €50,000 for the other members;

•

for the Compensation Committee and the Sustainability and Scenarios Committee, the annual remuneration consists of €50,000 for the Chairman and €35,000 for the other members;

•

for the Nomination Committee, the annual remuneration consists of €40,000 for the Chairman and €30,000 for the other members.

Payments due in the event of termination of office or employment

No specific severance payments are provided for the Non-Executive Directors, nor do any agreements exist for indemnities in the case of resignation or early termination of office.

Chief Executive Officer and General Manager

The 2018 Remuneration Policy Guidelines for the Chief Executive Officer and General Manager of the Company are in line with the 2017 Remuneration Guidelines and reflect the decisions of the Board of Directors of 19 June and 27 July 2017 as well as the model of organization and corporate governance adopted by the Company.

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In particular, the 2018 remuneration policies take account of: i) the end of the regulatory restrictions concerning the remuneration of executive directors of listed companies subject to government control; ii) the conditions of the 2017-2019 Long-Term Plan approved by the Shareholders Meeting of 13 April 2017 in accordance with Article 114-bis of the Consolidated Law on Financial Intermediation; and iii) the outcome of the comparative studies conducted by considering the total median remuneration of the companies within the Peer Group, appropriately compared to dimensional characteristics of Eni.

Fixed remuneration

Annual fixed remuneration (FR) approved by the Board of Directors on 19 June 2017 for the position of Chief Executive Officer and of General Manager totals €1,600,000 gross, which includes: i) annual remuneration of €600,000 gross for the position of Chief Executive Officer, including annual remuneration of €80,000 gross for the position of member of the Board as approved by the Shareholders Meeting of 13 April 2017; ii) base salary of €1,000,000 gross for the employment relationship as General Manager. This remuneration encompasses any emoluments due for participation in the meetings of the Boards of Directors of other Eni subsidiaries and/or shareholdings.

In his capacity as Senior Manager, the General Manager is also entitled to receive an allowance for travel, in Italy and abroad, in line with the applicable provisions under the relevant national collective bargaining agreement for senior managers of industrial companies and with supplementary company-level agreements.

Variable remuneration

Short-Term Monetary Plan with deferral

The Short-term Incentive Plan with deferral, as approved by the Shareholders’ Meeting of 13 April 2017 under the Remuneration Policy Guidelines and as described in the 2017 Remuneration Report, a portion of the incentive to be paid annually and a portion to be deferred for a three-year period, as described below.

The 2018 Short-Term Monetary Plan with deferral is linked to the achievement of the 2017 objectives approved by the Board of Directors on February 28, 2017.

Achievement of the objectives is assessed net of any exogenous effects (e.g. oil and gas prices or euro/dollar exchange rates) and in application of a predetermined method of gap analysis as approved by the Compensation Committee.

The 2018 targets approved by the Board on 15 March 2018 for the 2019 short-term variable incentive system with deferral call for maintenance of a structure that is focused on essential milestones in line with the Strategic Plan and balanced in respect of the interests of the various stakeholders in terms of: economic and financial results (25%), operating results and sustainability of the economic performance (25%), environmental sustainability and human capital (25%), efficiency and financial strength (25%). The value of each objective, at target performance level, is aligned with the budgeted value.

In particular, with regard to the objectives of Environmental Sustainability and Human Capital, the use of the Severity Incident Rate (SIR) aims to focus Eni’s commitment on reducing severe incidents, given that Eni has already achieved excellent results in terms of reducing the overall number of injuries.

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More specifically, SIR measures the frequency of total injuries recordable over the number of hours worked and assigns them increasing weights depending on the severity of the incident. In addition, our retention of the CO2 emissions target for operated production confirms Eni’s strategic commitment to reducing the emission of greenhouse gases that are connected with climate change and is consistent with the target for 2025 announced to investors.

In line with the general remuneration policy principles, the STI Plan features the characteristics described below.

Each objective is predetermined and measured in accordance with a performance scale of 70 to 150 points (target=100), in relation to the weight assigned to each target (below 70 points, the performance of each target is considered to be zero). For the purposes of the incentive award, the minimum overall performance is 85 points. The total incentive is determined with reference to a minimum (performance=85), target (performance=100) and maximum (performance=150) multiplier, equal respectively to 85%, 100% and 150% to be applied in relation to performance achieved by Eni over the previous year.

Total incentive (TI) is calculated using the following formula:

TI= FR x ITarget x Multiplier

Where “ITarget” is the incentive percentage at target performance level, which is set at 150% of total fixed remuneration for the Chief Executive Officer.

The Plan conditions state that the total incentive is divided into two portions.

a portion paid annually (Iannual) equal to 65% of the total incentive.

Iannual = TIx 65%

The levels of the portion of the incentive payable on a year base, depending on the performance levels achieved, are shown in the table below.

Annual performance	<85	85	100	150
		threshold	target	max
Annual incentive (% of Fixed Rem)	0%	83%	98%	146%

a deferred portion equal to 35% of the total incentive, subject to further performance conditions during a three-year vesting period.

The deferred portion payable at the end of the vesting period is determined by multiplying the initial deferred portion by the payment multiplier. The latter is given by the average of the three annual multipliers, each determined during the three-year period in relation to the performance achieved, based on Eni’s annual objectives. The multiplier of the deferred portion depends on the performance achieved, with reference to a minimum (performance=85), target (performance=100) and maximum (performance=150) incentive level, equal respectively to 85%, 130% and 230% of total fixed remuneration.

The Deferred Incentive (DI) payable at the end of the three-year deferment period is calculated using the following formula:

DI = TI x 35% x Multiplier

The levels of the payable deferred portion, depending on the performance levels achieved throughout the three-year period, are shown in the table below.

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	Annual performance			<85			85 threshold			100 target			150 max
	Deferred incentive (% of Fixed Rem)			0%			38%			68%			181%

Long-Term share incentives

The Chief Executive Officer participates in the Long-Term Incentive Share Plan 2017-2019, which also applies to Senior Managers, deemed critical for the business, approved by the Shareholders’ Meeting on April 13, 2017.

The Plan ensures the following objectives, in line with international best practices:

•

strengthening the culture of management of business risk from the perspective of shareholders by incentivizing through share ownership;

•

setting a more challenging minimum incentive threshold, positioned at median level;

•

further aligning performance conditions with the long-term expectations of shareholders, by reference to:

(i)

performance of the Company’s Total Shareholder Return over a three-year period compared with that of the Reference Stock Market Index, compared with the same performance of the main international competitors (Peer Group);

(ii)

incentivize the capacity to develop industrial assets, measured using the increase in the Net Present Value of hydrocarbon reserves in the medium-long term (in accordance with the assessment method defined by the SEC), measured in relative terms compared with the designated peer group.

The Plan provides for three annual awards starting from 2017, each with a three-year vesting period and is subject to performance conditions, during the three-year vesting period, in accordance with the following parameters and related weightings:

The difference between the TSR of Eni Shares and the TSR of the FTSE MIB index of Borsa Italiana, adjusted by the Eni Correlation Coefficient, compared with the equivalent adjusted TSR measure for each company in the Peer Group, as shown in the following formula (50% weight):

TSRA - (TSRI x ρ A,I)

where:

TSRA:

TSR of Eni or of one of the companies in the Peer Group;

TSRI:

TSR of the Reference Stock Market Index of the company to which TSRA applies;

ρ A,I:

Correlation Coefficient between the financial return of the share and the financial return of the reference market (FTSE MIB, S&P 500, FTSE 100, CAC 40, AEX, OBX).

This indicator was introduced in order to neutralize the potential effects of the performance of the respective stock market on the performance of each share. More specifically, this neutralisation is proportionate to the correlation between the stock and the market over the same three-year period by using the correlation coefficient.

Net Present Value of proven reserves (NPV) vs the Peer Group, measured in terms of the annual percentage change, calculating the average annual performance in the three-year period (50% weight).

The reference Peer Group is described in the “Market references and Peer Group” section (Anadarko, Apache, BP, Chevron, Conoco Phillips, ExxonMobil, Marathon Oil, Shell, Statoil and Total).

For the Chief Executive Officer and General Manager, the Plan conditions provide for the annual award of shares for a value equivalent to 150% (Itarget) of total fixed remuneration, using the following formula.

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	No. of Attributed Shares =			FR x % Itarget
				PriceAttr

Where the price of the award (PriceAttr) is calculated as the average of daily official prices (source Bloomberg) recorded in the 4 months before the date of the Board of Directors meeting that annually approves the plan rules and the award to the Chief Executive Officer and General Manager.

The granting of shares at the end of the three-year vesting period is determined using a final multiplier to be applied to awarded shares (calculated as the weighted average of the multipliers of each parameter) determined over the vesting period in relation to the position reached in the peer group.

Each multiplier may be between 0 and 180%, with a threshold set at the median level, in accordance with the scale shown below:

Performance Scale – Multiplier
Ranking
1st	2nd	3rd	4th	5th	6th	7th	8th	9th	10th	11°
Multiplier
180%	160%	140%	120%	100%	80%	0%	0%	0%	0%	0%
					Median positioning

Grantable shares are calculated using the following formula:

No. of Granted Shares = No. of Attributed Shares x Multiplier

The threshold, targets and maximum value of Shares (as a percentage of fixed remuneration) grantable to the Chief Executive Officer and General Manager at the end of the vesting period, net of changes in the share price over the same period, are given below.

	Weighted average 3-year performance			<26.6			26.6 threshold (*)			100 target			180 max
	Value of Shares (% of Fixed Rem)			0%			40%			150%			270%

For executives still in services, the rules of the Plan state that 50% of the shares granted at the end of the vesting period are to remain restricted for one year after the granting date.

Non-monetary Benefits

The Remuneration Policy provides for a life insurance policy and a permanent disability insurance policy covering injury or illness contracted in the workplace or elsewhere, and, as per provisions contained in the national collective bargaining agreement and the supplementary company agreements for Eni senior managers, for enrolment in the supplementary pension plan (FOPDIRE10) and in the supplementary health plan (FISDE11), together with a company car for business and personal use.

Pay Mix

The remuneration package for the Chief Executive Officer and General Manager includes a fixed component, a short-term variable component and a long-term variable component, comprising a short-term incentive deferral and the long-term share incentive valued using the international recognized methodologies for remuneration benchmarks.

(10)

Defined-contribution and individual-capitalization contractual pension fund (www.fopdire.it).

(11)

Fund that reimburses healthcare spending for active or retired senior management and their family members (www.fisde-eni.it).

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The pay mix, calculated by considering fixed remuneration as the base, is weighted significantly towards the variable components, with a dominant weighting attributed to the long-term component.

Payments due in the event of termination of office or employment

For the Chief Executive Officer and General Manager, based on a proposal by the Compensation Committee and having heard the opinion of the Board of Statutory Auditors, the Board of Directors resolved on 19 June 2017 to maintain the severance payments in the event of termination of office or of employment established in the 2017 Remuneration Policy Guidelines. These payments are as follows:

An indemnity for the administrative relationship in the event of dismissal without cause and/or non-renewal of the office, including in the event of resignation due to a substantive reduction of delegated powers. This indemnity has been set at two years of fixed remuneration for the position, for a total of €1,200,000, in accordance with European Commission Recommendation no. 385 of 30 April 2009;

An indemnity in the event of the consensual termination of the employment relationship in relation to termination of the associated administrative position in addition to standard post-employment benefits. This indemnity has been set, taking due account of the provisions of the appropriate national collective bargaining agreement, in accordance with the parameters and policies defined for Eni Managers with strategic responsibilities, equal to two years of annual fixed and variable remuneration for the General Manager position, excluding the Long-Term Share Incentive Plan and with mutual exemption from any obligation of advance notice, without payment of the related indemnity. In reference to criterion 6.C.1, letter g), of the Italian Corporate Governance Code, this indemnity is not due in the following cases: i) dismissal for “just cause” under Article 2119 of the Italian Civil Code; ii) resignation as Chief Executive Officer prior to the expiry of the term in office not justified by a reduction of delegated powers; iii) in the event of death as governed by Article 2122 of the Italian Civil Code; iv) dismissal from the role of Chief Executive Officer for just cause.

With reference to long-term incentives, in the event of early termination for the Chief Executive Officer and General Manager, due to resignation and not justified by a substantial reduction in powers or of termination for cause, all rights to the award and payment of incentives shall lapse. In the event of termination related to expiry of the term on the Board of Directors without renewal12, the long-term incentives awarded during the term shall vest in accordance with the terms and conditions established by the respective regulations.

In order to safeguard the company’s interests from potential competitive risks related to the considerable international importance of the professional and managerial background of the Chief Executive Officer and General Manager, on 27 July 2017, the Board of Directors, based on the recommendation of the Compensation Committee and having obtained a favourable opinion of the Board of Statutory Auditors, has also resolved to maintain the non-competition agreement in place since 2014, while extending the clause to geographical areas and industries that have taken on greater strategic importance over the last three years.

More specifically, the agreement, which can be activated at the sole discretion of the Board through the exercise of an option right13, has the following characteristics: i) a validity of 12 months post-termination; ii) restricted markets extended from exploration and production to also include the midstream sector; iii) 18 restricted countries with the addition of Mexico to those that were envisaged during the previous term (Algeria, Angola, Congo, Egypt, Ghana, Indonesia, Iraq, Italy, Kazakhstan, Libya, Mozambique, Nigeria, Norway, Russia, UK, USA, Venezuela); iv) additional confidentiality and non-solicitations restrictions.

Payment for the non-competition agreement provides for maintaining two components calculated on the basis of current remuneration levels and the extension of commitments undertaken: i) a fixed component in the amount of €1,800,000; ii) a variable component to be determined by the Board of Directors, based on a recommendation by the Compensation Committee, in line with the average annual

(12)

It should be noted that, under Italian law, directors of joint-stock companies may not be appointed for terms of longer than three financial years, and their terms expire on the date of the meeting of shareholders held to approve the financial report for the last financial year of their term (Article 2383, second paragraph, of the Italian Civil Code).

(13)

Payment of the option right, for a total of €500,000, was paid in full as reported on page 24 of Eni’s 2015 Remuneration Report (Section II, Table 1, note 4 b).

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performance over the previous three years, as follows: for performance below the target, this component will be set to zero; for performance on target, it will be €500,000; and for maximum performance, it will be €1,000,000. The average annual performance shall be calculated on the basis of annual performance achieved under the short-term monetary incentive plan.

2017 POLICIES FOR MANAGERS WITH STRATEGIC RESPONSIBILITIES

For Managers with Strategic Responsibilities, the 2018 Remuneration Policy Guidelines are unchanged on those for 2017, maintaining remuneration plans that are strictly in line with those of the Chief Executive Officer and General Manager, to better guide and align managerial action with the objectives set out in the Company’s Strategic Plan, and with the provisions and protections laid down by the national collective bargaining agreement for senior managers.

In particular the new Long-Term Share Incentive Plan and Short-Term Variable Incentive Plan with Deferral – intended for the Chief Executive Officer and General Manager will also apply to Managers with Strategic Responsibilities.

Fixed remuneration

Fixed remuneration is based on the role and responsibilities assigned, taking into consideration a graduated and a generally median to below-median positioning versus national and international executive markets for comparable roles. It may be updated periodically during the annual salary review for all managers.

Given current market comparators and trends, the 2018 Guidelines provide for a selective approach to salary reviews, while maintaining appropriate levels to ensure competitiveness and motivation.

More specifically, the proposed actions will include measures to adjust fixed/one-off remuneration for those in positions that have seen a significant increase in responsibility or scope, and to reflect needs for retention and excellent performance.

In addition, as Eni officers, Managers with Strategic Responsibilities are entitled to receive the allowances due for travel in Italy and abroad, in line with applicable provisions of the relevant national collective bargaining agreement for senior managers and supplementary Company agreements.

Variable incentive plans

Short-term Variable Incentive Plan with deferral

The Short-Term Incentive Plan with deferral, already described for the Chief Executive Officer and General Manager, will be implemented in 2018.

The targets set for Managers with Strategic Responsibilities are consistent with those assigned to the Chief Executive Officer and General Manager, on the basis of the same balancing of stakeholder interests, in addition to relevant individual targets, consistent with the responsibilities of the role played and the provisions of the Company’s Strategic Plan. For Managers with Strategic Responsibilities the target incentive levels for the Short-term Incentive Plan with deferral differ depending on the role’s level of responsibility and complexity and is limited to a maximum up of 100% of fixed remuneration, with a maximum incentive level payable for the annual and deferred portions of 98% and 121% of fixed remuneration, respectively.

Long-term variable incentive plan

Managers with Strategic Responsibilities participate in the Long-Term Performance Share Plan (LTI) 2017-2019, approved by the Shareholders’ Meeting on April 13, 2017.

The Plan is directed at managers who are critical for the business and envisages three annual awards, starting in 2017, with the same performance conditions and characteristics as those described above for the Chief Executive Officer and General Manager.

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For Managers with Strategic Responsibilities, the value of the shares to be awarded each year differs depending upon the level of their role and is limited, to a maximum of 75% of fixed remuneration, with the maximum award corresponding to 135% of fixed remuneration, calculated with reference to the grant price of the shares.

Benefits

In line with national collective bargaining agreement and supplementary Company-level agreements for Eni managers, the Policy Guidelines provide for life and disability insurance cover (due to workplace or other injury or illness), as well as enrolment in the supplementary pension plan (FOPDIRE) and health plan (FISDE), together with a company car for business and personal use, and the possible assignment of housing based on operational and mobility requirements.

Pay Mix

In line with market best practice, as well as the valuation methods used for the Chief Executive Officer and General Manager the average target pay mix of the remuneration package for Managers with strategic responsibilities who are eligible for the Short-Term Monetary Plan with deferral and the Long-Term Performance Share Plan) features a balance between fixed and variable components that is weighted towards medium-long term variable incentives.

Payments due in the event of consensual termination of employment

Managers with Strategic Responsibilities, as well as Eni senior managers, are entitled to the severance benefits for employment termination established by law and applicable national collective bargaining agreement, together with any termination indemnities agreed on an individual basis, in accordance with the criteria established by Eni for cases of early termination, within the limits of the protection envisaged by the applicable national collective bargaining agreement, and consistent with application criterion 6.C.1 lett.g) of the Italian Corporate Governance Code. These criteria take into account the position held, the retirement age and actual age of the manager at the time employment is terminated and the annual remuneration received. For cases of termination that present high competitive risks relating to the criticality of the position held by the Manager, agreements containing non-competition clauses may also be entered into with payments defined in relation to the remuneration received and the scope, duration and effectiveness of the agreement.

COMPENSATION AND OTHER INFORMATION

Implementation of the 2017 remuneration policies

The following is a description of the remuneration decisions taken in 2017 for the Chairman of the Board of Directors, Non-executive Directors, Chief Executive Officer and General Manager, and other Managers with strategic responsibilities, in relation to their time in office.

Implementation of the 2017 remuneration policies for Directors and Managers with strategic responsibilities, as verified by the Remuneration Committee in conjunction with its periodic assessment as provided for in the Corporate Governance Code, was in line with the 2017 Remuneration Policy approved by the Board of Directors on 28 February 2017, taking account of the provisions of the resolutions of the Board of Directors of 13 April 2017 and 19 June 2017 concerning, respectively, remuneration for Non-Executive Directors serving on Board Committees and the remuneration of Directors with delegated powers.

Remuneration paid and or awarded in 2017

In this section, we describe the remuneration paid and/or awarded in 2017 to the Chairman of the Board of Directors, to Non-Executive Directors, to the Chief Executive Officer and General Manager, and to other Managers with strategic responsibilities in accordance with the 2017 Remuneration Policy and in relation to the performance achieved during the period in which they held their respective roles.

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Remuneration paid/awarded in 2017 is shown in Section “Compensation Paid in 2017”, on individual basis for the Chairman of the Board of Directors, the Non-Executive Directors, and the Chief Executive Officer and General Manager and in aggregate form for other Managers with strategic responsibilities.

Chairman of the Board of Directors Emma Marcegaglia

Fixed remuneration

The Chairman was paid the following amounts: i) up to 12 April 2017, the prorated amount of fixed remuneration for the role and for the delegated powers, approved respectively by the Shareholders’ Meeting on 8 May 2014 and by the Board of Directors on 28 May 2014; ii) since 13 April 2017, the prorated amount of fixed remuneration for the role and for the delegated powers, approved respectively by the Shareholders’ Meeting on 13 April 2017 and by the Board of Directors on 19 June 2017.

Non-monetary benefits

The Chairman, in accordance with the resolution of the Board of Directors of 28 May 2014 and 19 June 2017, was granted a life insurance policy and a permanent disability insurance policy covering injury or illness contracted in the workplace or elsewhere.

Non-Executive Directors

The Non-Executive Directors were paid the fixed remuneration approved by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting on 13 April 2017 in the amount of €80,000 gross. Non-Executive Directors were also paid the prorated amount of additional remuneration payable for participation on Board Committees, as approved by the Board of Directors on 12 March 2015 for remuneration up to 12 April 2017 and on 13 April 2017 for remuneration subsequent to that date, in line with the 2017 remuneration policies.

Chief Executive Officer and General Manager Claudio Descalzi

Fixed remuneration

The Chief Executive Officer and General Manager was paid the following: i) up to 12 April 2017, the prorated amount of fixed remuneration approved by the Board of Directors on 28 May 2014; ii) since 13 April 2017, the prorated amount of fixed remuneration approved by the Board of Directors on 19 June 2017.

2017 Annual Monetary Incentive

For the 2017 Annual Monetary Incentive Plan, the Chief Executive Officer and General Manager was paid an annual gross variable incentive of €1,674 thousand in 2017 in relation to 2016 performance (124 points) as approved by the Board of Directors on 28 February 2017.

2012-2014 Deferred Monetary Incentive

In 2017 the Chief Executive Officer and General Manager received the Deferred Monetary Incentive awarded in 2014, in his capacity as COO of the E&P Division, in the amount of €465 thousand in relation to the final multiplier verified over the vesting period (123%) as approved by the Board of Directors on 28 February 2017.

2015-2017 Deferred Monetary Incentive

The Chief Executive Officer and General Manager was awarded a gross deferred monetary incentive of €864 thousand in 2017 in relation to the 2016 EBT performance, as approved by the Board of Directors on 28 February 2017.

2014-2016 Long-Term Monetary Incentive

In 2017, the Chief Executive Officer and General Manager was paid the Long-Term Monetary Incentive awarded in 2014 in the amount of €729 thousand, in relation to the final multiplier verified over the vesting period (54%) as approved by the Board of Directors on 19 June 2017.

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2017-2019 Long-Term Equity-based Incentive Plan

In 2017, the Chief Executive Officer and General Manager was awarded 177,968 Eni shares in 2017 as approved by the Board of Directors on 26 October 2017. The number of shares awarded was determined based on the percentage of 150% to be applied to total fixed remuneration and the award price of €13.4856, calculated in accordance with the parameters of the plan.

Non-monetary benefits

In line with the resolutions of the Board of Directors of 28 May 2014 and 19 June 2017, the Chief Executive Officer and General Manager was granted a life insurance policy and a permanent disability insurance policy covering injury or illness contracted in the workplace or elsewhere, as well as, in compliance with the provisions of Italy’s national collective bargaining agreement and the supplementary company agreements for Eni senior managers, the enrolment in the supplementary pension plan (FOPDIRE) and supplementary health plan (FISDE), together with a company car for business and personal use.

Managers with strategic responsibilities

Fixed remuneration

In 2017, within the context of the annual salary review process envisaged for all managers, selective adjustments were made to fixed remuneration for current Managers with strategic responsibilities, in cases of promotion to more senior levels, or in line with necessary market-driven adjustments.

2017 Annual Monetary Incentive

In 2017, annual variable incentives were paid to Managers with strategic responsibilities in accordance with the Remuneration Policy and based on performance achieved in 2016. In particular, the incentive is linked to performance against a range of metrics related to business and sustainability objectives (safety, environmental protection, stakeholder relations), as well as relevant individual targets, consistent with the provisions of the Eni Strategic Plan.

2012-2014 Deferred Monetary Incentive Plan

Managers with strategic responsibilities were paid deferred monetary incentives awarded in 2014, on the basis of the final multiplier verified in the vesting period (123%), approved by the Board of Directors on 28 February 2017.

2015-2017 Deferred Monetary Incentive Plan

Managers with strategic responsibilities were granted deferred monetary incentive awards on the basis of the 2016 EBT results, approved by the Board of Directors on 28 February 2017, as proposed by the Remuneration Committee in accordance with the 2017 Remuneration Policy.

2014-2017 Long-Term Monetary Incentive Plan

Managers with strategic responsibilities were paid in 2017 Long-Term monetary incentives awarded in 2014, on the basis of the final multiplier verified in the vesting period (54%), approved by the Board of Directors on 19 June 2017.

2017-2019 Long-Term Share-based Incentive Plan

In accordance with the resolution of the Board of Directors at its meeting of 26 October 2017, managers with strategic responsibilities were granted the first award for the Plan.

Severance indemnity for end-of-office or termination of employment

During 2017, Managers with strategic responsibilities who accepted enhanced voluntary termination offers were paid, in addition to amounts due under legal and contractual obligations, additional amounts defined in line with company policy on early retirement.

Non-monetary benefits

For Managers with strategic responsibilities, in line with provisions in Italy’s national collective bargaining agreement and supplementary corporate agreements for Eni managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (FOPDIRE) as well as in the supplementary health plan (FISDE), life and disability insurance cover, together with a company car for business and personal use.

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Incentives vested and payable and/or awardable in 2018

This section describes the incentives vested and payable and/or awardable in 2018 to the Chief Executive Officer and General Manager and to other Managers with strategic responsibilities in relation to the verification of 2017 performance.

Chief Executive Officer and General Manager Claudio Descalzi

2018 Annual Monetary Incentive and Short-Term Incentive Plan with deferral

With reference to the remuneration policy in force during 2017, the following incentives in the period from 1 January to 31 December 2017 vested in favour of the Chief Executive Officer and General Manager:

2014-2017 term, up to 12 April 2017. The Board of Directors, on 28 May 2014, approved the procedures and parameters for determining the variable remuneration, corresponding to target and maximum levels of 100% and 130% of fixed remuneration of €1,350,000, determined on the basis of a performance scale of 85-130 points. Therefore, in relation to the performance achieved in 2017 (134 points, reduced to 130 as the maximum applicable score), is payable an annual incentive of €491 thousand, calculated pro rata for the period from 1 January 2017 to 12 April 2017.

2017-2020 term, starting 13 April 2017, the Board of Directors, on 19 June 2017, approved the procedures and parameters for determining the variable remuneration of the Chief Executive Officer and General Manager, corresponding to target and maximum levels of 100% and 150% of fixed remuneration of €1,600,000 euro, determined on the basis of a performance scale of 85-150 points and divided into a portion payable in the year and a deferred portion equal, respectively, to 65% and 35% of the total incentive. therefore, in relation to the performance achieved in 2017 (134 points), is payable an annual portion of €1,506 thousand, in addition to a deferred portion awardable of €811 thousand, calculated pro rata for the period from 13 April 2017 to 31 December 2017.

2015-2017 Deferred Monetary Incentive

The incentive awarded in 2015, payable in 2018, vested in favour of the Chief Executive Officer and General Manager in the amount of €1,469 thousand, determined on the basis of the final multiplier verified over the vesting period (170%), as approved by the Board of Directors on 15 March 2018.

Managers with strategic responsibilities

2018 Short-Term Incentive with deferral

The incentives payable/awardable in 2018 based on performance achieved in 2017 vested in favour of the Managers with strategic responsibilities, in the aggregate amounts that will be disclosed in the 2019 Remuneration Report. More specifically, these incentives were related to company performance and a series of business targets, sustainability targets (i.e. safety, environmental protection, relations with stakeholders), and individual targets assigned in relation to the scope of responsibilities of the given role, in line with the provisions of Eni’s Strategic Plan.

2015-2017 Deferred Monetary Incentive

The incentive awarded in 2015, payable in 2018, vested in favour of the Managers with strategic responsibilities, determined on the basis of the final multiplier verified over the vesting period (170%), as approved by the Board of Directors on 15 March 2018. The total aggregate amount of such incentives will be published in 2019 Remuneration Report.

COMPENSATION PAID IN 2017

The table below lists the individual remunerations to the Directors, Statutory Auditors, Chief Executive Officer and General Managers and, in aggregate form, to other Managers with strategic responsibilities. The remunerations received from subsidiaries and/or affiliates, except those waived or paid to the Company, are shown separately. All parties who filled these roles during the period are included, even if they only held office for a fraction of the year.

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In particular:

•

the column labelled “Fixed Remuneration” reports fixed remuneration and fixed salary from employment due for the year (on an accrual basis), gross of social security contributions and taxes to be paid by the employee. Details of the compensation are provided in the notes, and any indemnities or payments with reference to the employment relationship are indicated separately;

•

the column labelled “Remuneration for participation on Committees” reports (on an accrual basis) the compensation due to Directors for participation in Committees established by the Board. In the notes, compensation for each Committee in which each Director participates is indicated separately;

•

the column labelled “Variable non-equity remuneration” under the item “Bonuses and other incentives” shows the incentives paid during the year due to rights vested following the assessment and approval of related performance results by relevant corporate bodies, in accordance with that specified, in greater detail, in the Table “Monetary incentive plans for the Chief Executive Officer and General Manager and other Managers with strategic responsibilities”;

•

the column labelled “Profit-sharing” does not show any figures since no profit-sharing mechanisms are in place;

•

the column labelled “Benefits in kind” reports (on an accrual and taxability basis) the value of any fringe benefits awarded;

•

the column labelled “Other remuneration” reports (on an accrual basis) any other remuneration deriving from other services provided;

•

the column labelled “Total” reports the sum of the amounts of all the previous items;

•

the column labelled “Fair value of equity compensation” reports the relevant fair value for the year related to the existing stock option plans, estimated in accordance with the international accounting standards that allocate the related cost in the vesting period;

•

the column labelled “Severance indemnity for end-of-office or termination of employment” reports indemnities accrued, even if not yet paid, for terminations that occurred during the financial year, or in relation to the end of term in office and/or employment.

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Remuneration paid to Directors, Statutory Auditors, the Chief Executive Officer and General Manager and to other Managers with strategic responsibilities

(amounts in euro thousands)

	Note	Position	Period for which the position was held		Expiration of office(*)		Fixed remuneration		Remuneration for participation in Committees		Variable non-equity remuneration			Non- monetary benefits		Other remuneration		Total		Fair value of equity- based remuneration		Severance Indemnity for end of office of termination of employment
Name	Note	Position	Period for which the position was held		Expiration of office(*)		Fixed remuneration		Remuneration for participation in Committees		Bonuses and other incentives		Profit sharing	Non- monetary benefits		Other remuneration		Total		Fair value of equity- based remuneration
Board of Directors
Emma Marcegaglia	(1)	Chairman		01.01-12.31		2020		426 (a)											426
Claudio Descalzi	(2)	Chief Executive Officer and General Manager		01.01-12.31		2020		1,537 (a)				2,403 (b)			15 (c)				3,955		40
Andrea Gemma	(3)	Director		01.01-12.31		2020		80 (a)		119 (b)									199
Pietro Angelo Guindani	(4)	Director		01.01-12.31		2020		80 (a)		75 (b)									155
Karina Litvack	(5)	Director		01.01-12.31		2020		80 (a)		73 (b)									153
Alessandro Lorenzi	(6)	Director		01.01-12.31		2020		80 (a)		98 (b)									178
Diva Moriani	(7)	Director		01.01-12.31		2020		80 (a)		112 (b)									192
Fabrizio Pagani	(8)	Director		01.01-12.31		2020		80 (a)		61 (b)							21 (c)		162
Alessandro Profumo	(9)	Director		01.01-04.13		2017		23 (a)		11 (b)									34
Domenico Livio Trombone	(10)	Director		04.13-12.31		2020		57 (a)		47 (b)									104
Board of Statutory Auditors
Matteo Caratozzolo	(11)	Chairman		01.01-04.12		2017		23 (a)									110 (b)		133
Rosalba Casiraghi	(12)	Chairman		04.13-12.31		2020		57 (a)											57
Enrico Maria Bignami	(13)	Statutory auditor		04.13-12.31		2020		50 (a)											50
Paola Camagni	(14)	Statutory auditor		01.01-12.31		2020		70 (a)									100 (b)		170
Alberto Falini	(15)	Statutory auditor		01.01-04.12		2017		20 (a)									93 (b)		113
Marco Lacchini	(16)	Statutory auditor		01.01-04.12		2017		20 (a)											20
Andrea Parolini	(17)	Statutory auditor		04.13-12.31		2020		50 (a)											50
Marco Seracini	(18)	Statutory auditor		01.01-12.31		2020		70 (a)									97 (b)		167
Other Managers with strategic responsibilities(**)	(19)	Remuneration in the company that prepares the Financial Statements						8,794				8,267			200		155		17,416		63		70
	Remuneration from subsidiaries and associates							0		0		0			0		0		0		0		0
	Total							8,794 (a)				8,267 (b)			200 (c)		155 (d)		17,416		63		70 (e)
								11,677		596		10,670			215		576		23,734		103		70

Note

(*)

The term of office expires with the Shareholders’ Meeting approving the Financial Statements for the year end in 31 December 2019.

(**)

Managers who were permanent members of the Company’s Management Committee during the year together with the Chief Executive Officer, or who reported directly to the CEO (nineteen managers).

(1)

Emma Marcegaglia — Chairman of the Board of Directors

(a) The amount includes: i) the fixed remuneration of €90 thousand set by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting on 13 April 2017; ii) pro quota of fixed remuneration for the delegated powers approved by the Board for the 2014-2017 and 2017-2020 terms, equal to €41.9 and €293.8 thousand, respectively.

(2)

Claudio Descalzi — Chief Executive Officer and General Manager

(a) The amount includes: i) the pro-rata fixed remuneration for the position of Chief Executive Officer for the 2014-2017 and 2017-2020 terms, coming to €155.8 and €430 thousand respectively; ii) the pro-rata fixed remuneration for the position of General Manager for the 2014-2017 and 2017-2020 terms, coming to €194.3 and €757.1 thousand, respectively.

To this amounts are to be added the indemnities due for transfers, in Italy and abroad, in line with the provisions of the relevant national collective labour agreement for senior managers and the Company’s complementary agreements for an amount of €17.7 thousand.

(b) The amount includes the annual variable incentive of €1,674 thousand and the Long-Term Monetary Incentive of €729 thousand assigned in 2014 and paid in 2017 in relation to the performance targets achieved during the 2014-2016 vesting period. To this amount is added the Deferred Monetary Incentive assigned in 2014, for the position of COO of the E&P Division, paid in 2017 for an amount of €465 thousand in relation to performance targets achieved during the 2014-2016 vesting period.

(c) The amount includes the taxable value of insurance and welfare coverage, complementary pensions and the car for business and personal use.

(3)

Andrea Gemma — Director

(a) The amount corresponds to the fixed remuneration set by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting of 13 April 2017.

(b) The amount includes the pro-rata remuneration set by the Board of Directors for participating in the Committees for the 2014-2017 and 2017-2020 terms, and in particular €47.2 thousand for participating in the Control and Risk Committee; €35.8 thousand for the Compensation Committee; €5.7 thousand for Sustainability and Scenarios Committee; €30.1 thousand for the Nomination Committee.

(4)

Pietro Angelo Guindani — Director

(a) The amount corresponds to the fixed remuneration set by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting of 13 April 2017.

(b) The amount includes the pro-rata remuneration set by the Board of Directors for participating in the Committees for the 2014-2017 and 2017-2020 terms, and in particular: €33.6 thousand for participating in the Compensation Committee; €41.5 thousand for the Sustainability and Scenarios Committee.

(5)

Karina Litvack — Director

(a) The amount corresponds to the fixed remuneration set by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting of 13 April 2017.

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(b) The amount includes the pro-rata remuneration set by the Board of Directors for participating in the Committees for the 2014-2017 and 2017-2020 terms, and in particular: €36.8 thousand for participating in the Control and Risk Committee; €5.7 thousand for the Compensation Committee; €30.7 thousand for the Sustainability and Scenarios Committee.

(6)

Alessandro Lorenzi — Director

(a) The amount corresponds to the fixed remuneration set by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting of 13 April 2017.

(b) The amount includes the pro-rata remuneration set by the Board of Directors for participating in the Committees for the 2014-2017 and 2017-2020 terms, and in particular: €67.2 thousand for participating in the Control and Risk Committee; €30.8 thousand for the Compensation Committee.

(7)

Diva Moriani — Director

(a) The amount corresponds to the fixed remuneration set by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting of 13 April 2017.

(b) The amount includes the pro-rata remuneration set by the Board of Directors for participating in the Committees for the 2014-2017 and 2017-2020 terms, and in particular: €47.2 thousand for participating in the Control and Risk Committee; €30.8 thousand for the Compensation Committee; €34.3 thousand for the Nomination Committee.

(8)

Fabrizio Pagani — Director

(a) The amount corresponds to the fixed remuneration set by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting of 13 April 2017.

(b) The amount includes the pro-rata remuneration set by the Board of Directors for participating in the Committees for the 2014-2017 and 2017-2020 terms, and in particular: €33.6 thousand for participating in the Sustainability and Scenarios Committee; €27.2 thousand for the Nomination Committee.

(9)

Alessandro Profumo — Director

(a) The amount corresponds to the pro-rata annual fixed remuneration until 13 April 2017, set by the Shareholders’ Meeting on 8 May 2014.

(b) The amount includes the pro-rata remuneration set by the Board of Directors for participating in the Committees for the 2014-2017, and in particular: €5.7 thousand for participating in the Sustainability and Scenarios Committee and €5.7 thousand for the Nomination Committee.

(10)

Domenico Livio Trombone — Director

(a) The amount corresponds to the pro-rata annual fixed remuneration set by the Shareholders’ Meeting on 13 April 2017.

(b) The amount includes the pro-rata remuneration set by the Board of Directors for participating in the Committees for the 2017-2020 term, and in particular: €25.1 thousand for participating to the Sustainability and Scenario Commitee; €21,5 thousand for the Nomination Committee.

(11)

Matteo Caratozzolo — Chairman of the Board of the Statutory Auditors

(a) The amount corresponds to the pro-rata annual fixed remuneration until 13 April 2017, set by the Shareholders’ Meeting on 8 May 2014.

(b) The amount includes remuneration for serving as Statutory Auditor on the Boards of subsidiaries or associated companies and in particular: €45 thousand as Chairman of the Board of Statutory Auditors of Eni Fuel SpA; €19.5 thousand as Chairman of the Board of Statutory Auditors of Eni Adfin; €45 thousand as Chairman of TTPC SpA.

(12)

Rosalba Casiraghi — Chairman of the Board of the Statutory Auditors

(a) The amount corresponds to the pro-rata annual fixed remuneration since 13 April 2017, set by the Shareholders’ Meeting.

(13)

Enrico Maria Bignami — Statutory Auditor

(a) The amount corresponds to the pro-rata annual fixed remuneration set by the Shareholders’ Meeting on 13 April 2017.

(14)

Paola Camagni — Statutory Auditor

(a) The amount corresponds to the fixed remuneration set by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting of 13 April 2017.

(b) The amount includes remuneration for serving as Statutory Auditor on the Boards of subsidiaries or associated companies and in particular: €19.5 thousand as Chairman of the Board of Statutory Auditors of AGI SpA; €27 thousand as Chairman of the Board of Statutory Auditors of Eni East Africa SpA; €23.3 thousand as Statutory Auditor of Syndial; €30 thousand as Auditor of Eni Angola SpA.

(15)

Alberto Falini — Statutory Auditor

(a) The amount corresponds to the pro-rata annual fixed remuneration until 13 April 2017, set by the Shareholders’ Meeting on 8 May 2014.

(b) The amount includes remuneration for serving as Statutory Auditor on the Boards of subsidiaries or associated companies and in particular: €45 thousand as Chairman of the Board of Statutory Auditors of Eni Angola SpA; €18 thousand as Chairman of the Board of Statutory Auditors of Eni Timor Leste SpA; €30 thousand as Auditor for TTPC SpA.

(16)

Marco Lacchini — Statutory Auditor

(a) The amount corresponds to the pro-rata annual fixed remuneration until 13 April 2017, set by the Shareholders’ Meeting on 8 May 2014.

(17)

Andrea Parolini — Statutory Auditor

(a) The amount corresponds to the pro-rata annual fixed remuneration set by the Shareholders’ Meeting on 13 April 2017.

(18)

Marco Seracini — Statutory Auditor

(a) The amount corresponds to the fixed remuneration set by the Shareholders’ Meeting on 8 May 2014 and confirmed by the Shareholders’ Meeting of 13 April 2017.

(b) The amount includes remuneration for serving as Statutory Auditor on the Boards of subsidiaries or associated companies and in particular: €27 thousand as Chairman of the Board of Statutory Auditors of LNG Shipping SpA; €27 thousand as Chairman of the Board of Statutory Auditors of Ing. Luigi Conti Vecchi; €30 thousand as Statutory Auditor of Eni Fuel SpA; €13 thousand as Statutory Auditor of Eni Adfin SpA.

(19)

Other Managers with strategic responsibilities

(a) The amount of €8,794 thousand for Gross Annual Salary is supplemented by the indemnities owed for transfers, in Italy and abroad, in line with the provisions of of the relevant national collective labour agreement and with the Company’s additional agreements, as well as other indemnities related to employment for a total of €437 thousand.

(b) The amount includes the payment of €2,946 thousand related to the deferred and long-term monetary incentives assigned in 2014 for performance targets achieved in the 2014-2016 vesting period, as well as the pro-rata amounts of the long-term Incentive Plans (DMI and LTMI), paid upon consensual termination as defined in the respective Plan Regulations. (c) The amount includes the taxable value of insurance and welfare coverage, complementary pensions and the car for business and personal use. (d) Amounts due to for the positions held by Managers with strategic responsibilities in the Supervisory Body established under the Company’s Model 231 and the Manager responsible for the preparation of the Company’s financial statements.

(e) The amount includes severance payments and early retirement incentives paid in relation to employment termination.

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OTHER INFORMATION

Accrued compensation

Total compensation accrued in the year 2017 pertaining to all the Board members amounted to €14.5 million; it amounted to €0.760 million in the case of the Statutory Auditors. Such amounts include, in addition to each item of emolument reported in the table above, amounts accrued in the year for pension benefits, social security contributions and other elements of the remuneration associated with roles performed, which represent a cost for the Company.

For the year ended December 31, 2017, remuneration of persons in key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, and other Managers with strategic responsibilities (with reference to all those individuals who, during the course of the 2016 period, filled said roles, even if only for a fraction of the year) amounted to €43 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2017. The breakdown is as follow:


			2017
			(€ million)
Fees and salaries			25
Post-employment benefits			2
Other long-term benefits			9
Indemnity upon termination of the office			7
			43

The above amounts include salaries, fees for attending meetings, lump-sum amounts paid in lieu of expense reimbursements, stock-based compensation and other deferred incentive bonuses, health and pension contributions and amounts accrued to the reserve for employee termination indemnities, which is used to pay severance pay, as required by Italian law to employees upon termination of employment. The members of the Board of Directors in their capacity as such are not entitled to receive such severance pay.

As of December 31, 2017, the total amount accrued to the reserve for employee termination indemnities with respect to Chief Executive Officer and General Manager, Chief Operating Officers and other Managers with strategic responsibilities (with reference to the employed ones who, during the course of the 2017 period, filled said roles, even if only for a fraction of the year), was €1,483 thousand.

Name		(€ thousand)
Claudio Descalzi	Chief Executive Officer	358
Senior Managers(a)		1,124
		1,483

(a)

No. 18 Managers

Board practices

Corporate Governance

The Corporate Governance structure of Eni follows the Italian traditional management and control model, whereby corporate management is the responsibility of the Board of Directors, which is the core of the organizational system, while supervisory functions are allocated to the Board of Statutory Auditors. The Company’s accounts are independently audited by an accredited Audit Firm appointed by the Shareholders’ Meeting. Eni complies with the Corporate Governance Code for listed companies (on the Italian Stock Exchange) approved by Italian Corporate Governance Committee (hereinafter “Corporate Governance Code” or “Code”), lastly on July 9, 2015.

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The names of Eni’s Directors, their positions, the year in which each of them was initially appointed as a Director and their ages are reported in the related table above.

Board of Directors’ duties and responsibilities

The Board of Directors has the fullest powers for the ordinary and extraordinary management of the Company in relation to its purpose. In a resolution dated April 13, 2017, the Board, while exclusively reserving to itself the most important strategic, operational and organizational powers, in addition to those that cannot be delegated by law, appointed Claudio Descalzi as CEO and General Manager, entrusting him with the fullest powers for the ordinary and extraordinary management of the Company, with the exception of those powers that cannot be delegated under current law and those retained by the Board.

In the same resolution, the Board of Directors resolved to confirm to the Chairman a major role in internal controls and not operational functions. In particular, with reference to Internal Audit, the Board of Directors resolved that, in accordance with the Corporate Governance Code, the Head of the Internal Audit Department reports to the Board, and on its behalf, to the Chairman, without prejudice to its functional reporting to the Control and Risk Committee and the Chief Executive Officer, as the director in charge of the internal control and risk management system. The Chairman is also involved in the appointment of the primary Eni officers in charge of internal controls and risk management, as well as in approving internal rules governing the Internal Audit process. In addition, the Chairman carries out her statutory functions as legal representative, managing institutional relationships in Italy, together with the Chief Executive Officer.

Finally, the Board of Directors entrusted the Board Secretary with the role of Corporate Governance Counsel, who reports hierarchically and functionally to the Board and, on its behalf, to the Chairman. He lends assistance and independent legal advice to the Board and the Directors and periodically presents to the Board of Directors a report on the functioning of Eni’s Corporate Governance system.

On April 13, 2017, the Board reserved to itself the strategic, operational and organizational powers briefly described below:

•

defines the system and rules of Corporate Governance for the Company and the Group;

•

establishes the Board’s internal committees, appoints their members and chairmen, determines their duties and compensation, and approves their procedural rules and annual budgets;

•

expresses the general criteria for determining the maximum number of offices that a Company Director may hold in other companies;

•

delegates and revokes the powers of the CEO and the Chairman, establishing the limits and procedures for exercising those powers and determining the compensation associated with these duties;

•

establishes the basic structure of the organizational, administrative and accounting arrangements of the Company (including the internal control and risk management system), of its strategically important subsidiaries and of the Group as a whole. It evaluates the adequacy of these arrangements;

•

establishes the guidelines for the internal control and risk management system, so that the main risks facing the Company and its subsidiaries are correctly identified and adequately measured, managed and monitored, determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives. It sets the financial risk limits of the Company. It also examines the main business risks, which are identified taking into account the characteristics of the activities carried out by the Company and its subsidiaries and which are reported by the Chief Executive Officer at least quarterly. Moreover, it evaluates, every six months, the adequacy of the internal control and risk management system with respect to the characteristics of the Company and its risk profile, as well as the system’s effectiveness;

•

approves at least annually the Audit Plan drawn up by the Senior Executive Vice President of the Internal Audit Department. It also evaluates the findings contained in the recommendation letter, if any, of the Audit Firm and in its statement on the key issues that arose during the statutory audit;

•

defines the strategic guidelines and objectives of the Company and the Group, including sustainability policies. It examines and approves the budgets and strategic, industrial and financial

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plans of the Group, periodically monitoring their implementation, as well as agreements of a strategic nature for the Company. It examines and approves the plan for the Company’s non-profit activities and approves operations not included in the plan whose cost exceeds €500,000;

•

examines and approves the annual financial report (which includes Eni’s draft Financial Statements and the Consolidated Financial Statements) and the semi-annual and quarterly financial reports required by applicable law. It reviews and approves the Sustainability Reporting when it is not already contained in the financial report;

•

receives reports from Directors with delegated powers at Board meetings, or on at least a bi-monthly basis, on the actions taken in exercising their delegated powers;

•

receives a report from the Board’s internal committees on at least a semi-annual basis;

•

assesses general developments in the operations of the Company and of the Group, paying particular attention to conflicts of interest and comparing the results with budget forecasts;

•

evaluates and approves transactions of the Company and its subsidiaries with related parties provided for in the procedure approved by the Board14, as well as transactions in which the CEO has an interest;

•

evaluates and approves any transaction executed by the Company and its subsidiaries that has a significant strategic, economic, financial or asset impact on the Company;

•

appoints and removes the Chief Operating Officers, the Officer in charge of preparing financial reports, the Senior Executive Vice President of the Internal Audit Department and the Eni Watch Structure. It ensures the designation of a manager responsible for shareholder relations;

•

examines and approves the Remuneration Report and, in particular, the Remuneration Policy for Directors and Managers with strategic responsibilities to be presented to the Shareholders’ Meeting. It also defines the criteria for remunerating the senior executives of the Company and of the Group and takes steps to implement compensation plans based on shares or other financial instruments approved by the Shareholders’ Meeting;

•

resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the strategically important subsidiaries;

•

formulates the proposals to present to the Shareholders’ Meeting; and

•

examines and resolves on other issues that Directors with delegated powers believe should be presented to the Board due to their particular importance or sensitivity.

In accordance with Article 23.2 of the By-laws, the Board also resolves on mergers and proportional spin-offs of companies in which Eni’s shareholding is at least 90%; the establishment and closing of branches; and the amendment of the By-laws to comply with the provisions of law.

In accordance with the By-laws, the Chairman and the Chief Executive Officer retain representative powers for the Company.

Directors’ independence

On the basis of statements made by the Directors and other information available to the Company, during its meeting of April 13, 2017 and, after an investigation by the Nomination Committee, at its meeting of February 15, 2018, the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Trombone satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Trombone have been deemed independent by the Board pursuant to the criteria and parameters recommended by the Corporate Governance Code. Chairman Marcegaglia, in compliance with the Corporate Governance Code, could not be deemed independent as she is a significant representative of the Company.

At the last assessment, the Board of Directors also evaluated that the commercial relationships between Eni and Vodafone Italy, a company of which Director Guindani is a significant representative, and between Eni and Selecta SpA and between Eni and companies of KME Group, companies subject to significant influence by Director Moriani, are not significant for the purpose of assessing the independence of these Directors, having regard to the nature and the amounts of these relationships. The relationships

(14)

The Board of Directors, on November 18, 2010, approved the Management System Guideline (MSG) “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”, which has been applied since January 1, 2011, to ensure transparency and substantial and procedural fairness of transactions with related parties. The Board modified this MSG on January 19, 2012 and, lastly, on April 4, 2017.

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were evaluated on the basis of statements made by the Directors and other information available to the Company, and taking into account that – due to the nature of the companies mentioned above – transactions between these companies and Eni were subject to related parties’ transactions regulation and to reporting to the Company’s body.

The Board of Statutory Auditors ascertained that the Board of Directors correctly applied the assessment criteria and procedures for evaluating the independence of its members.

The independence criteria may not be equivalent to the independence criteria set forth in the NYSE listing standards applicable to a U.S. domestic company.

Board Committees

The Board of Directors has established four internal Committees to provide it with recommendations and advice: (a) the Control and Risk Committee; (b) the Remuneration Committee; (c) the Nomination Committee; and (d) the Sustainability and Scenarios Committee. Committees under letters (a), (b) and (c) are recommended by the Corporate Governance Code. The composition, duties and operational procedures of these committees are governed by their own rules, which are approved by the Board, in compliance with the criteria outlined in the Corporate Governance Code.

The Committees recommended by the Corporate Governance Code are composed of no fewer than three members and, in any case, less than a majority of members of the Board. The composition is described in the following sections pertaining each Committee.

All Board Committees report to the Board of Directors, at least once every six months, on activities carried out. In addition, the Chairmen of the Committees report to the Board at each meeting of the Board on the key issues examined by the Committees in their previous meetings.

In the exercise of their functions, the Committees have the right to access any information and Company functions necessary to perform their duties. They are also provided with adequate financial resources, in accordance with the terms established by the Board of Directors, and can avail themselves of external advisers.

The Chairman of the Board of Statutory Auditors or a Statutory Auditor designated by him, participates in Control and Risk Committee and Remuneration Committee meetings and may participate in other Committees’ meetings. Furthermore, Committees may invite other persons to attend the meetings in relation to individual items on the agenda.

The CEO and the Chairman may attend the meetings of the Nomination Committee and of the Sustainability and Scenarios Committee. Furthermore, they may attend Control and Risk Committee meetings, unless matters relating to them are discussed. Finally, they may attend Remuneration Committee meetings upon the invitation of its Chairman, except when the meetings are examining proposals regarding their remuneration15.

The Board Secretary and Corporate Governance Counsel coordinates the secretaries of the Board Committees, receiving at this end information on the calendar of the meetings and the items in the Committees’ agendas, the notices of the meetings, as well as their signed minutes.

Minutes of all Committee meetings are usually drafted by their respective secretaries. The current members of the Control and Risk Committee, Remuneration Committee, Nomination Committee and Sustainability and Scenarios Committee were appointed by the Board of Directors on April 13, 2017.

Remuneration Committee

Members: Andrea Gemma (Chairman), Pietro A. Guindani, Alessandro Lorenzi, Diva Moriani.

The Remuneration Committee is made up of non-executive, independent Directors. All the members possess adequate professional requirements and expertise for carrying out the duties assigned to the Committee. The Committee’s rules require that at least one of its members possess adequate knowledge and experience of financial matters or remuneration policies, as assessed by the Board at the time of his or her appointment.

(15)

Rules of the Remuneration Committee establish that “no Director and, in particular, no Director with delegated powers may take part in meetings of the Committee during which Board proposals regarding his remuneration are being discussed, unless are deemed proposals on all the members of the Committees established within the Board of Directors.”

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Established by the Board of Directors for the first time in 1996, in accordance with the By-laws, the Committee provides recommendations and advice to the Board of Directors. More specifically, the Committee:

submits the Remuneration Report and in particular the Remuneration Policy for Directors and Managers with strategic responsibilities to the Board of Directors for approval, prior to its presentation at the Shareholders’ Meeting called to approve the year’s financial statements, in accordance with the time limits set by applicable law;

periodically evaluates the adequacy, overall consistency and effective implementation of the Policy, formulating proposals, as appropriate, for approval by the Board of Directors;

presents proposals for the remuneration of the Chairman and the Chief Executive Officer, including the various components of compensation and non monetary benefits;

presents proposals for the remuneration of Board Committee members;

having examined the Chief Executive Officer’s indication, proposes general criteria for the compensation of Managers with strategic responsibilities, the annual and Long-Term incentive plans, including equity-based ones, sets performance objectives and assesses performance against them, in connection with the determination of the variable portion of the remuneration for Directors with delegated powers and with the implementation of the approved incentive plans;

monitors execution of decisions taken by the Board;

reports at the first available meeting of the Board of Directors through the Committee Chairman on the most significant issues addressed by the Committee during the meetings. It also reports to the Board on its activities at least every six months and no later than the time limit for the approval of the Annual Report and the Interim Report at 30 June, at the Board meeting designated by the Chairman of the Board of Directors.

Furthermore, in exercising its functions, the Committee may issue opinions as required by Company procedures in relation to operations with related parties, in accordance with specified procedures.

During 2017, the Remuneration Committee met a total of ten times, with an average attendance of 98% of its members and an average duration of 2 hours and 35 minutes. At least one member of the Board of Statutory Auditors participated in each meeting as well as, following the renewal of corporate bodies, the Chairman of the Board of Auditors.

Earlier in the year, the Committee focused its activities in particular on the following topics:

review, with the assistance from leading law firms, of relevant updates to legal and regulatory requirements governing Directors or Managers severance arrangements under Italy’s national collective bargaining regime (CCNL);

ii.

periodic evaluation of Remuneration Policy, as implemented in 2016, also with a view to developing new Policy proposals for 2017, which provided for the introduction of a new and generally simplified variable incentive system, as discussed in greater detail in the 2017 Remuneration Report;

iii.

verification of the Company’s 2016 results for the purpose of implementing the Short- and Long-Term variable incentive plans, using a predetermined gap analysis method approved by the Committee in order to neutralise the positive or negative impact of exogenous factors and enable the objective assessment of the performance achieved;

iv.

definition of 2017 performance targets relevant to the variable incentive plans, with the introduction in the new Short-Term Incentive Plan with deferral, of the new “Severity Incident Rate” metric, which measures both the frequency and severity of injuries, replacing the previous metric, the Total Recordable Incident Rate (TRIR);

definition of proposals for the implementation of the Deferred Monetary Incentive Plan for the Chief Executive Officer and General Manager, as well as for other senior executives;

vi.

definition of proposals for the new Short-Term and Long-Term Share Incentive Plans 2017-2019. The procedures and characteristics of the LTI Plan are described in the Information Document examined for subsequent approval by the Shareholders’ Meeting, in accordance with Art. 114-bis of the Consolidated Law on Financial Intermediation, and in the 2017 Remuneration Report;

vii.

review of the 2017 Eni Remuneration report;

viii.

review of the outcome of the meetings conducted with main institutional investors, before the 2017 Shareholders’ Meeting, in order to maximize shareholder consensus on the 2017 Remuneration Policy, as well as develop voting projections with the support of an international consultant.

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ix.

definition, following the appointment of the corporate bodies, of the proposals for the remuneration of the Directors with delegated powers (Chairman – Chief Executive Officer and General Manager) for the 2017-2020 term, in particular with regard to the fixed component, consistently with the Eni 2017 Remuneration Policy and with the conditions of the 2017-2019 Long-Term Incentive Plan, approved by the Shareholders’ Meeting of April 13, 2017.

As regards further important activities carried out during the second half of the year, the Committee:

examined the 2017 Shareholders’ Meeting vote results, with regard to the Eni Remuneration Report as well as to the 2017-2019 Long-Term Share Incentive Plan, compared to the results of the main Italian and European listed companies and of the Peer Group.

ii.

finalised the proposal (2017 grant) for the implementation of the 2017-2019 Long-Term Share Incentive Plan for the Chief Executive Officer and General Manager and for Mangers with strategic responsibilities;

iii.

review of the outcome of the first cycle of engagement conducted, after the 2017 Shareholders’ Meeting, with various Eni institutional investors and leading proxy advisors, as well as additional planned activities in the run up to the 2018 Shareholders’ Meeting, to enable the broadest possible understanding and sharing of the Policy;

iv.

started the review of 2018 Remuneration Policy Guidelines, with the support of the competent Company functions, in the light of the monitoring conducted of the developments in the regulatory framework and in market standards of reporting on remuneration issues.

The composition and appointment, as well as the duties and operational procedures, of the Committee are governed by the Rules approved by the Board of Directors, available to the public on the Company’s website (https://www.eni.com/docs/en_IT/enicom/company/governance/rules-of-the-remuneration-committee.
pdf).

Control and Risk Committee

Members: Alessandro Lorenzi (Chairman), Andrea Gemma, Karina Litvack and Diva Moriani16.

The Control and Risk Committee is entrusted with supporting, on the basis of an appropriate control process, the Board of Directors in evaluating and making decisions concerning the internal control and risk management system and in approving the periodical financial reports. It is entirely made up of non-executive and independent Directors17 who possess the necessary expertise consistent with the duties they are required to perform18.

In particular, at their appointment, the Directors Lorenzi, Litvack and Moriani were identified by the Board as members with “adequate experience in the area of accounting and finance or risk management”, as recommended by the Corporate Governance Code.

The Committee advises the Board of Directors and specifically issues its prior opinion: a) and drafts recommendations concerning the guidelines for the internal control and risk management system so that the main risks faced by the Company and its subsidiaries can be correctly identified and appropriately measured, managed and monitored and also supports the Board in determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives; b) on the assessment, performed by the Board of Directors, on the main company risks, identified taking into account the characteristics of the activities carried out by the company or its subsidiaries; c) on the evaluation, performed at least every six months, of the adequacy of the internal control and risk management system, taking account of the characteristics of the Company and its risk profile, as well as its effectiveness. To this end, at least once every six months it reports to the Board of Directors, on the occasion of the approval of the annual and semi-annual financial reports, on its activities and on the adequacy of the internal control and risk management system at the meeting of the Board of Directors indicated by the Chairman of the Board of Directors; d) on the approval, at least once a year, of

During 2017 the composition of the Control and Risk Committee was: i) Lorenzi, Gemma, Moriani until the Shareholders’ Meeting of April 13, and ii) Lorenzi, Gemma, Litvack and Moriani, after April 13, 2017.

In accordance with the rules of the Control and Risk Committee, the Committee is made up of three to four non-executive Directors, all of whom are independent. Alternatively, the Committee may be made up of non-executive Directors, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. In any case, the number of members shall be fewer than the number representing a majority on the Board.

The Governance system put in place by Eni establishes that at least two members of the Committee– and not just one as recommend by the Corporate Governance Code for listed companies – must possess adequate experience in financial and accounting matters or in risk management, as assessed by the Board of Directors at the time of their appointment.

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the Audit Plan prepared by the Senior Executive Vice President of the Internal Audit Department; e) on the description, in the annual Corporate Governance Report, of the main features of the internal control and risk management system, and how the different subjects involved therein are coordinated, providing its evaluation of the overall adequacy of the system itself; and f) on the evaluation of the findings reported by the Audit Firm in any recommendations letter it may issue and in the latter’s report on the main issues arising during the audit.

The Committee furthermore: a) issues opinions to the Board of Directors on specific aspects concerning the identification of the main risks faced by the Company; b) examines and issues an opinion on the adoption and amendment of the rules on the transparency and the substantive and procedural fairness of transactions with related parties and those in which a Director or Statutory Auditor holds a personal interest or an interest on behalf of a third party, while performing additional duties assigned it by the Board of Directors, including examining and issuing an evaluation on specific types of transactions, except for those relating to compensation; and c) gives an opinion on the fundamental guidelines of the Regulatory System, the regulatory instruments to be approved by the Board of Directors, their amendment or update and, upon request by the CEO, on specific aspects in relation to the instruments implementing the fundamental guidelines.

In addition, the Committee, in assisting the Board of Directors: a) evaluates, together with the Officer in charge of preparing financial reports and after having consulted the Audit Firm and the Board of Statutory Auditors, the proper application of accounting standards and their consistency in preparing the Consolidated Financial Statements, prior to their approval by the Board of Directors; b) examines and evaluates Reports prepared by the CFO/Officer in charge of preparing financial reports through which it shall give its opinion to the Board of Directors on the appropriateness of the powers and resources assigned to the Officer himself and on the proper application of accounting and administrative procedures, enabling the Board to exercise its legally mandated supervision tasks; c) at the request of the Board, it supports, with adequate preliminary activities, the Board of Directors’ assessments and resolutions on the management of risks arising from detrimental facts of which the Board may have become aware and d) monitors the independence, adequacy, efficiency and effectiveness of the Internal Audit Department and oversees its activities with respect to the duties of the Board of Directors in this area, and on its behalf, of the Chairman, ensuring that they are performed with the necessary independence and required level of objectivity, competence and professional diligence, in accordance with the Code of Ethics of Eni SpA and international standards.

A favorable opinion of the Committee is required for the approval to the Board on proposals by the Chairman in agreement with the CEO concerning the appointment, the removal and, consistent with the Company’s policies, the structure of the fixed and variable compensation of the Senior Executive Vice President of the Internal Audit Department, as well as on the adequacy of the resources provided to the latter to perform his duties.

The Committee also: a) evaluates, on the occasion of his appointment, whether the Senior Executive Vice President of the Internal Audit Department meets the integrity, professionalism, competence and experience requirements and, on an annual basis, assesses their fulfilment; b) examines the results of the audit activities performed by the Internal Audit Department; c) examines the periodic reports prepared by the Senior Executive Vice President of the Internal Audit Department as to whether it contains adequate information on the activities carried out, on the manner in which risk management is conducted and on compliance with risk containment plans, as well as assesses the appropriateness of the internal control and risk management system. It also examines the reports prepared promptly by the Senior Executive Vice President of the Internal Audit Department on events of particular importance; and d) examines the information received from the Senior Executive Vice President of the Internal Audit Department and promptly reports its assessment to the Board of Directors in the case of: (i) significant deficiencies in the system for preventing irregularities and fraudulent acts, and irregularities or fraudulent acts committed by management personnel or by employees that perform important roles in the design or operation of the internal control and risk management system; and (ii) circumstances that may affect the maintenance of the independence of the Internal Audit Department and of auditing activities.

The Committee may also ask the Internal Audit Department to perform audits on specific operational areas, providing simultaneous notice to the Chairman of the Board of Statutory Auditors. The Committee also examines and assesses: a) communications and information received from the Board of Statutory

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Auditors and its members regarding the internal control and risk management system, including those concerning the findings of enquiries conducted by the Internal Audit Department in connection with reports received (whistleblowing), including anonymous reports; b) half yearly reports issued by Eni’s Watch Structure, including in its capacity as Guarantor of the Code of Ethics, as well as the timely updates provided by the Structure, after the updates have been given to the Chairman of the Board and to the CEO, about any particular material or significant situation detected in the performance of its duty; c) information on the internal control and risk management system, including that provided in the course of periodic meetings with the competent Company structures; and d) enquiries and reviews concerning the internal control and risk management system carried out by third parties.

Furthermore, the Committee oversees the activities of the Legal Affairs Department in case of judicial inquiries, carried out in Italy and/or abroad, in relation to which the CEO and/or the Chairman of the Company and/or a member of the Board of Directors and/or an Executive reporting directly to the CEO, even if no longer in office, have received a notice of investigation for crimes against the Public Administration and/or corporate crimes and/or environmental crimes, related to their mandate and their scope of responsibility.

The composition and appointment, as well as duties and operational procedures of the Committee, are governed by rules approved by the Board of Directors lastly on May 9, 2017 available to the public at the Company’s website.

Nomination Committee

Members: Diva Moriani (Chairman), Andrea Gemma, Fabrizio Pagani and Domenico Livio Trombone.

The Nomination Committee is made up of non-executive Directors, a majority of whom are independent.

The Committee provides recommendations and advice to the Board of Directors. More specifically, the Committee:

assists the Board of Directors in formulating any criteria for the appointment of those persons indicated in letter b) below, and of the members of the other boards and bodies of Eni’s subsidiaries and associated companies;

provides evaluations to the Board of Directors on the appointment of executives and members of the boards and bodies of the Company and of its subsidiaries, proposed by the Chief Executive Officer and/or the Chairman of the Board of Directors, whose appointment falls under the Board’s responsibility and oversees the associated succession plans. Where possible and appropriate, and with due regard to the shareholding structure, the Committee proposes the CEO succession plan to the Board of Directors;

acting upon a proposal of the Chief Executive Officer, examines and evaluates criteria governing the succession planning for the Company’s managers with strategic responsibilities;

proposes candidates to serve as Directors to the Board of Directors in the event one or more positions need to be filled during the course of the financial year (Article 2386, first paragraph, of the Italian Civil Code), ensuring compliance with the requirements regarding the minimum number of independent Directors and the percentage reserved for the less represented gender;

proposes to the Board of Directors candidates for the position of Director to be submitted to the Shareholders’ Meeting of the Company, taking account of any recommendations received from shareholders, in the event it is not possible to draw the required number of Directors from the slates presented by shareholders;

oversees the annual self-assessment program on the performance of the Board of Directors and its Committees, in compliance with the Corporate Governance Code, and deals with the preliminary activity for appointing an external consultant for such self-assessment. On the basis of the results of the self-assessment, the Committee provides its opinions to the Board of Directors regarding the size and composition of the Board or its Committees, as well as, the skills and managerial and professional qualifications it feels should be represented within the same Board and Committees so that the Board itself can give its opinion to the shareholders prior to the appointment of the new Board;

proposes to the Board of Directors the slate of candidates for the position of Director to be submitted to the Shareholders’ Meeting if the Board decides to opt for the process envisaged in Article 17.3, first period, of the By-laws;

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in compliance with the Corporate Governance Code, proposes to the Board of Directors guidelines regarding the maximum number of positions of Director or Statutory Auditor that a Company Director may hold and performs the preliminary activity for the associated periodic checks and evaluations for submission to the Board;

periodically verifies that the Directors satisfy the independence and integrity requirements, and ascertains the absence of circumstances that would render them incompatible or ineligible;

provides its opinion to the Board of Directors on any activities carried out by the Directors in competition with the Company;

through the Chairman of the Committee, informs the Board of Directors on the main issues examined by the Committee thereof during the first available meeting of the Board; furthermore, the Committee reports to the Board of Directors, at least once every six months and no later than the deadline for the approval of the annual and semi-annual financial report, on the activity carried out as well as on the adequacy of the appointment system, at the Board meeting indicated by the Chairman of the Board of Directors.

The preliminary examination of corporate affairs or governance issues is carried out jointly with the Senior Executive Vice President Corporate Affairs and Governance who, in this case, participates in the Committee meetings.

The composition, appointment, duties and operational procedures of the Nomination Committee are governed by rules approved by the Board of Directors on July 30, 2014, and amended on April 7, 2016 and on May 9, 2017, available to the public at the Company’s website.

Sustainability and Scenarios Committee

Members: Pietro A. Guindani (Chairman), Karina Litvack, Fabrizio Pagani and Domenico Trombone.

The Sustainability and Scenarios Committee is made up of non-executive Directors, a majority of whom are independent.

The Sustainability and Scenarios Committee provides recommendations and advice to the Board of Directors on scenarios and sustainability, i.e. the processes, projects and activities aimed at ensuring the Company’s commitment to sustainable development along the value chain, particularly with regard to: health, well-being and safety of people and communities; respect and the protection of rights, particularly of the human rights; local development; access to energy, energy sustainability and climate change; environment and efficient use of resources; integrity and transparency; and innovation.

Board of Statutory Auditors

The current Board of Statutory Auditors was appointed by the Ordinary Shareholders’ Meeting of April 13, 2017 for a term of three financial years. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the Financial Statements for the year ending December 31, 2019.

Name	Position	Year first appointed to Board of Statutory Auditors
Rosalba Casiraghi	Chairman	2017
Enrico Maria Bignami	Auditor	2017
Paola Camagni	Auditor	2014
Andrea Parolini	Auditor	2017
Marco Seracini	Auditor	2014
Stefania Bettoni	Alternate	2014
Claudia Mezzabotta	Alternate	2017

Paola Camagni, Andrea Parolini, Marco Seracini and Stefania Bettoni (Alternate) were candidates listed in the slate presented by the Ministry of the Economy and Finance; Rosalba Casiraghi (Chairman), Enrico Maria Bignami and Claudia Mezzabotta (Alternate) were candidates listed in the slate presented by non-controlling shareholders.

The Auditors are appointed by means of a slate voting system: the lists are presented by shareholders representing at least 0.5% of the share capital. Two standing Statutory Auditors and one Alternate Auditor are selected from among the candidates of the non-controlling shareholders. The Chairman of the Board of Statutory Auditors is appointed by the Shareholders’ Meeting from among the Auditors chosen by the non-controlling shareholders.

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In accordance with the provisions designed to ensure gender balance, two Statutory Auditor were drawn from the less represented gender.

The Auditors must satisfy the independence, professional and integrity requirements established by Italian regulations. Article 28 of the By-laws specifies that the professionalism requirements may be fulfilled by having at least three years’ experience in: (i) professional or teaching activities pertaining to commercial law, business economics and corporate finance, or (ii) experience in executive positions in the fields of engineering and geology. U.S. Regulations for Audit Committees require that at least one member of the Board of Statutory Auditors be a financial expert and have adequate knowledge of the functions of the Audit Committee and experience in the analysis and application of generally accepted accounting standards, the preparation and auditing of Financial Statements and internal control processes. In addition, the Board of Statutory Auditors, acting as the Internal Control and Financial Auditing Committee pursuant to Legislative Decree no. 39/2010 (Consolidate Law on Statutory Audits of annual accounts and consolidated accounts), must satisfy the requirement imposed by Art. 19 of that law, providing that “the members of the internal control and financial auditing committee, as a body, are competent in the sector in which the company being audited operates”.

Pursuant to the Consolidated Law on Financial Intermediation, the Board of Statutory Auditors monitors: (i) compliance with the law and the Company’s By-laws; (ii) observance of the principles of sound administration; (iii) the appropriateness of the Company’s organizational structure for matters within the scope of the Board’s Authority, the adequacy of the internal control system and the administrative and accounting system and the reliability of the latter in accurately representing the Company’s transactions; (iv) the procedures for implementing the Corporate Governance rules provided for in the Corporate Governance Code, which the Company has adopted; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements.

In addition, pursuant to Article 19 of Legislative Decree No. 39/2010, in its role as the “internal control and financial auditing committee” the Board of Statutory Auditors: a) informs the Board of Directors of the conclusion of the statutory audit and transmits to the Board the “additional report” of the audit firm adding proper evaluation if deemed necessary; b) oversees the financial reporting process and presents recommendations to ensure its integrity; c) controls the effectiveness of internal quality control system and Risk Management, the effectiveness of internal audit, with reference to the financial reporting process, without violating its independence; d) oversees the statutory audit of annual accounts and consolidated accounts, also considering results of quality control of the audit activity performed by the public authority responsible for regulating the Italian financial markets; e) verifies and monitors the independence of the audit Firm with particular reference to non-audit services; f) is responsible of the procedure to select the audit Firm, making a recommendation to the Shareholders’ Meeting for the appointment of the audit Firm.

The responsibilities assigned under the Legislative Decree No. 39/2010 to the “internal control and financial auditing committee” are consistent and substantively in line with the duties already assigned to the Board of Statutory Auditors of Eni, with specific consideration of its role as Audit Committee pursuant to the “U.S. Sarbanes-Oxley Act” (discussed in greater detail below).

In accordance with law, the Board of Statutory Auditors presents the results of its supervisory activity in a report to the Shareholders Meeting. This report is made available in its entirety to the public within the time limits applicable to the Financial Statements.

On March 22, 2005, the Board of Directors, electing the exemption granted by the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as of June 1, 2005, would perform, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and U.S. SEC rules. On June 15, 2005, the Board of Statutory Auditors approved the internal rules, later updated, concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s website. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by U.S. SEC include:

•

evaluating the offers submitted by external Auditors for their engagement and providing a reasoned recommendation to the Shareholders’ Meeting concerning the engagement or removal of the external Auditor;

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•

overseeing the work of the external Auditor engaged to audit the accounts or perform other audit, review or certification services;

•

examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management;

•

making recommendations to the Board of Directors on the resolution of disagreements between management and the auditor regarding financial reporting;

In addition the Board of statutory auditor:

•

approves the procedures for: a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters;

•

examines reports from the CEO and the CFO concerning: i) any significant deficiency in the design or operation of internal controls which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information and any material weakness in internal controls; and ii) any fraud that involves management or other employees who have a significant role in the Company’s internal controls.

The Board of Statutory Auditors, in the performance of its duties, is supported by Company’s departments, in particular the Internal Audit Department and the Administrative and Financial Statement Department.

Eni Watch Structure and Model 231

In accordance with the Italian regulations concerning the “administrative liability of legal entities deriving from criminal offences”, contained in Legislative Decree No. 231 of June 8, 2001 (henceforth, “Legislative Decree No. 231/2001”), legal entities, including corporations, may be held liable – and consequently fined or subject to prohibitions – in relation to certain crimes attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in a high ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni Board of Directors – in its Meetings of December 15, 2003 and January 28, 2004 – approved an organizational, management and control model pursuant to Legislative Decree No. 231 of 2001 (Model 231) and created the Watch Structure. Moreover, as a result of changes in the Italian legislation governing the matter and of the Company’s organizational structures, on March 14, 2008, the Board of Directors updated Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of the Eni Code of Conduct of 1998 – which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni relates on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. Since its first adoption, Model 231 has been updated very frequently, in most cases in response to new provisions of law coming into force as well as to organizational changes in the company’s structure. Most recently, the Board of Directors, in its meeting of November 23, 2017 approved the updating of Model 231 and Eni’s Code of Ethics.

The synergies between the Code of Ethics– an integral part and essential general principle of Model 231 – and Model 231 are highlighted by the assignment, to the Eni Watch Structure, of the function of Guarantor of the Code of Ethics. At present, the Watch Structure of Eni is composed of three external members, including the Chairman, and four internal members. The internal members are Company executives in charge of Legal Affairs, labor law matters and disputes, Internal Audit and Integrated Compliance. External members are independent professionals, experts in law and/or economic matters. Also in order to grant the Watch Structure the greatest extent of autonomy and independence, the set of rules adopted by the Watch Structure provide for specific quorum to convene and to pass resolutions so to ensure that all resolutions are effectively adopted with the favourable vote of the majority of the external members.

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Audit Firm

The auditing of the Company’s accounts is entrusted, in accordance with the law, to an independent Audit Firm appointed by the Shareholders’ Meeting on the basis of a reasoned recommendation of the Board of Statutory Auditors.

In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the Audit Firm issue a report on the Annual Report on Form 20-F, in compliance with the auditing principles generally accepted in the United States. Moreover, the Audit Firm is required to issue an opinion on the efficacy of the internal control system applied to financial reporting.

For the most part, the subsidiaries’ financial statements are subject to auditing by Eni’s Audit Firm. Moreover, Eni’s Audit Firm, for the purpose of issuing an opinion on the Consolidated Financial Statements, assumes responsibility for the auditing activities performed by other audit firms with respect to subsidiaries’ financial statements, which, taken together, account for an immaterial share of consolidated assets and revenues.

Acting on the Board of Statutory Auditors’ reasoned proposal, the Shareholders’ Meeting of April 29, 2010 appointed EY SpA for the financial years 2010-2018.

Court of Auditors (Corte dei conti)

The financial management of Eni is subject to the control of the Court of Auditors in order to preserve the integrity of the public finances. This task is carried out by the Magistrate of the Court of Auditors, Adolfo Teobaldo De Girolamo, appointed by the Presidential Council of the Court of Auditors on December 22, 2014. The Magistrate of the Court attends the meetings of the Board of Directors.

Employees

As of December 31, 2017, Eni had a total of 32,934 employees, with a decrease of 602 employees, or down by 1.8% from December 31, 2016, which mainly reflects a decrease of 565 employees working outside Italy.

The reduction of personnel headcount is mainly due to slight efficiency actions and other strategic operations. The most significant ones are: sale of Eni Gas & Power NV/SA and its subsidiary Eni Wind Belgium NV/SA, which comprises Eni’s gas & power retail operations in Belgium, sale of 25% indirect interest stake in Mozambique Area 4 and the agreement to sell 98.99% of Tigàz Zrt to MET Holding AG, aimed at the completion of the exit from the gas sector in Hungary in line with its disposals and asset rationalization plan started in 2016.

Employees at year end

	2017		2016		2015(1)
	(number)
Exploration & Production		11,970		12,494		12,821
Gas & Power		4,313		4,261		4,484
Refining & Marketing and Chemicals		10,916		10,858		10,995
Corporate and Other activities		5,735		5,922		5,896
		32,934		33,536		34,196

(1)

Excluding the operating segment E&C divested in January 2016.

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The table below sets forth Eni’s employees as of December 31, 2015, 2016 and 2017 in Italy and outside Italy:



		2017		2016		2015(1)
		(number)
Exploration & Production	Italy		4,510		4,608		4,572
	Outside Italy		7,460		7,886		8,249
			11,970		12,494		12,821
Gas & Power	Italy		2,282		2,032		2,023
	Outside Italy		2,031		2,229		2,461
			4,313		4,261		4,484
Refining & Marketing and Chemicals	Italy		8,580		8,577		8,635
	Outside Italy		2,336		2,281		2,360
			10,916		10,858		10,995
Corporate and other activities	Italy		5,501		5,693		5,650
	Outside Italy		234		229		246
			5,735		5,922		5,896
Total	Italy		20,873		20,910		20,880
	Outside Italy		12,061		12,626		13,316
			32,934		33,536		34,196
of which senior managers			1,012		1,036		1,061

(1)

Excluding the operating segment E&C divested in January 2016.

We seek to maintain constructive relationship with labor unions.

Share ownership

As of March 9, 2018, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 298,774 less than 0.1% of Eni’s share capital outstanding as of the same date. Eni issues only ordinary shares, each bearing one-vote right; therefore shares held by those persons have no different voting rights. The breakdown of share ownership for each of those persons is provided below.

Name	Position	Number of shares owned
Board of Directors
Emma Marcegaglia	Chairman		87,010(1)
Claudio Descalzi	CEO		39,455
Board of Statutory Auditors			none
Senior Managers			172,309(2)

(1)

Of which No. 597 shares held through a trust company, No. 7,143 shares held under Asset Management jointly with a third person, and No. 45,000 shares held as naked owner jointly with a third person.

(2)

Of which No. 14,390 shares owned by spouses not legally separated and by underage children.

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Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major Shareholders

The Ministry of Economy and Finance controls Eni as a result of the shares directly owned and those indirectly owned through Cassa Depositi e Prestiti SpA (CDP), in which the Ministry of Economy and Finance holds a 82.77% stake.

As of March 9, 2018, the total amount of Eni’s voting securities owned by these shareholders was:

Title of class	Number of shares owned		Percent of class
Ministry of Economy and Finance		157,552,137		4.34
Cassa Depositi e Prestiti SpA		936,179,478		25.76

The following table shows the percentage of Eni’s share capital owned, either directly or indirectly, by persons that as of March 9, 2018 have notified that their holding exceeds the threshold of 3% pursuant to Article 120 of the Legislative Decree No. 58/1998 (as amended by article 1 of Legislative Decree No. 25 of February 15, 2016) and to the Consob Regulation No. 11971/1999 (as amended by Consob Resolution No. 19614 of May 26, 2016)1.

Title of class	Percent of class
none		none

Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012, modified Italian legislation governing the special powers of the Italian State to comply with European rules. See “Item 10 – Additional information – Limitations on changes in control of the Company (Special Powers of the Italian State)”. As of March 16, 2018, there were 39,074,162 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately 2.2% of Eni’s share capital. See “Item 9 – The offer and the listing”.

Related party transactions

In the ordinary course of its business, Eni enters into transactions concerning the exchange of goods, provision of services and financing with non-consolidated subsidiaries and affiliates, as well as other companies owned or controlled by the Italian Government. All such transactions are conducted on an arm’s length basis and in the interest of Eni companies.

Amounts and types of trade and financial transactions with related parties and their impact on consolidated earnings and cash flow, and on the Group’s assets and financial condition are reported in “Item 18 – note 47 of the Notes on Consolidated Financial Statements”.

(1)

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Item 8. FINANCIAL INFORMATION

Consolidated Statements and other financial information

See “Item 18 – Financial Statements”.

Legal proceedings

Eni is a party to a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, Eni believes that the foregoing will likely not have a material adverse effect on Eni’s Consolidated Financial Statements.

For a description of legal proceedings in which Eni is involved and which may affect Eni’s financial position and results of operations see “Item 18 – note 38 of the Notes on Consolidated Financial Statements”.

Dividends

Eni is committed to a progressive dividend policy that is linked to expected future growth in earnings and cash flow. For the year 2018 management is planning to distribute a full-year dividend of €0.83 per share, up by approximately 4% vs. 2017. The Company’s dividend policy going forward and the sustainability of the dividends that the Company is planning to distribute over the next four years will depend upon a number of factors including achievement of the Company's industrial targets, future levels of profitability and cash flow provided by operating activities, a sound balance sheet structure, capital expenditures and development plans, in light of the oil price and exchange rate assumptions adopted by management and other planning assumptions described in “Item 5 – Management's expectations of operations”. The parent company's net profit and, therefore, the amounts of earnings available for the payment of dividends will also depend on the level of dividends received from Eni’s subsidiaries. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year. For further information on the Company’s dividend policy see “Item5 – Management’s expectations of operations.”

At the General Shareholders’ Meeting scheduled on May 10, 2018, management intends to propose the distribution of a dividend of €0.80 per share for fiscal year 2017, of which €0.40 paid as interim dividend in September 2017.

Total cash outlay for the 2017 balance dividend is expected at approximately €1.4 billion (whereas €1.4 billion were distributed in September 2017) if the General Shareholders’ Meeting approves the annual dividend.

Significant changes

See “Item 5 – Recent developments” for a discussion of significant events occurred after 2017 year end up to the latest practicable date.

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Item 9. THE OFFER AND THE LISTING

Offer and listing details

The principal trading market for the ordinary shares of Eni SpA (Eni), without indication of par value (the “Shares”), is the Mercato Telematico Azionario (Electronic Share Market or “MTA”). MTA, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA (Borsa Italiana). Eni’s American Depositary Receipts (ADRs), each representing two Shares, are listed on the New York Stock Exchange.

The table below sets forth the reported high and low reference prices of Shares on MTA and of ADRs on the New York Stock Exchange, respectively. See “Item 3 – Key information – Exchange rates” regarding applicable exchange rates during the periods indicated below.

	MTA				New York Stock Exchange
	High		Low		High		Low
	(euro per share)				(U.S.$ per ADR)
Year ended December 31,
2013		19.480		15.290		52.120		40.390
2014		20.410		13.290		55.300		32.810
2015		17.430		13.140		39.290		29.280
2016		15.470		10.930		33.330		25.000
2017		15.720		12.960		34.090		29.540
Year ended December 31,
2016
First quarter		13.800		10.930		31.050		25.000
Second quarter		14.580		12.320		33.330		28.170
Third quarter		14.900		12.310		33.250		27.650
Fourth quarter		15.470		12.260		32.240		26.260
2017
First quarter		15.720		14.120		33.260		30.070
Second quarter		15.240		13.160		33.900		30.060
Third quarter		14.000		12.960		33.080		29.540
Fourth quarter		14.720		13.690		34.090		31.870
2018
First quarter (to March 27, 2018)		14.960		13.330		37.390		33.030
Month of
October 2017		14.070		13.770		33.140		31.870
November 2017		14.720		13.690		34.090		32.330
December 2017		14.140		13.800		33.430		32.640
January 2018		14.960		13.830		37.390		33.610
February 2018		14.590		13.352		36.830		33.040
March 2018 (through March 27, 2018)		14.240		13.330		35.330		33.030

Since June 27, 2017, Citibank N.A. (the “Depositary”) functions as depositary bank issuing ADRs pursuant to a deposit agreement (the “Deposit Agreement”) among Eni, the Depositary and the beneficial owners (“Beneficial Owners”) and registered holders from time to time of the ADRs issued hereunder.

As of March 16, 2018, there were 39,074,162 ADRs outstanding, representing 78,148,324 ordinary shares or approximately 2.2% of all Eni’s shares outstanding, held by 96 holders of record (including the Depository Trust Company) in the United States, 95 of which are U.S. residents. Since certain of such ADRs are held by nominees, the number of holders may not be representative of the number of Beneficial Owners in the United States or elsewhere.

The Shares are included in the FTSE MIB Index (the “FTSE MIB”), the primary benchmark index for the Italian Stock Exchange. Capturing approximately 80% of the domestic market capitalization, the FTSE

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MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on MTA and the Investment Vehicles Market (MIV) and seeks to replicate the broad sector weights of the Italian Stock Exchange. The constituents of the FTSE MIB are selected based on market capitalization of free float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for free float and foreign ownership limits. FTSE MIB is the principal indicator used to track the performance of the Italian Stock Exchange and is the basis for future and option contracts traded on the Italian Derivatives Market (IDEM) managed by Borsa Italiana. The Shares are a component of the FTSE MIB, with a weighting of approximately 10%, as established by FTSE Russel after the quarterly rebalancing for FTSE MIB effective March 19, 2018.

A two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana. Besides Shares traded on MTA, futures and options contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the Italian Securitized Derivatives Market (SeDeX). IDEM facilitates the trading of futures and options contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic regulated market where it is possible to trade securitized derivatives (for instance, covered warrants and certificates).

Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an “official price”, calculated as the weighted average price of the total volume of each security traded in the market during the session without taking into account the contracts concluded with cross trades and block trades, and a “reference price”, calculated as the closing auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective January 11, 2018: (i) ± 5.0% (or such other amount established by Borsa Italiana in the “Guide to the Parameters” for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price shall be the previous day’s reference price, in the opening auction, or the auction price, in the continuous trading phase); and (ii) ± 3.5% (or such other amount established by Borsa Italiana in the “Guide to the Parameters”) with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). Where the price of a contract that is being concluded exceeds one of the price variation limits referred to above, trading in that security will be automatically suspended and a volatility auction phase begun for a certain period of time.

Markets

Consob is the public authority responsible for regulating and supervising the Italian securities markets to, inter alia, ensure the transparency and regularity of the dealings and protect the investing public. Borsa Italiana, which is part of London Stock Exchange Group, following the merger effective October 1, 2007, is a joint stock company authorized by Consob to operate, inter alia, regulated markets in Italy; it is responsible for the organization and management of the Italian Stock Exchange. One of the fundamental characteristics of the financial market organization in Italy is the separation of responsibility for supervision (Consob and the Bank of Italy) from that of market management (Borsa Italiana). Main responsibilities of Borsa Italiana are the admission, exclusion and suspension of financial instruments and intermediaries to and from trading and the surveillance of the markets.

According to Consob regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for, which, inter alia, are MTA (for example, shares, convertible bonds, pre-emptive rights, warrants and Funds), ETFplus (for example, Exchange Traded Funds, Exchange Traded Commodities, Exchange Traded Notes, Structured ETFs and Actively managed ETFs), IDEM (futures and options contracts whose underlying assets are financial instruments, interest rates, foreign currencies, goods or related indexes), SeDeX (covered warrants and certificates), MOT (bond market) and MIV (market for investment vehicles), as well as the admission to listing on and trading on these markets.

According to the regulatory framework introduced by Markets in Financial Instruments Directive No. 2014/65/EU as amended (“MiFID II”), as implemented in Italy, and Regulation (EU) No. 600/2014 (“MiFIR”), applicable from 3 January 2018, and Consob regulations, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities (MTFs) or Systematic Internalisers. A MTF is a multilateral system, operated by an investment firm or a market operator, which brings together

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multiple third-party buying and selling interests in financial instruments – in the system and in accordance with non-discretionary rules – in a way that results in a contract. A Systematic Internaliser is an investment firm or a bank which, on an organized, frequent systematic and substantial basis, deals on own account when executing client orders outside a Regulated Market, an MTF or an Organized Trading Facility (“OTF”) without operating a multilateral system. Following the transposition in Italy of MiFID II and the application of MiFIR, OTFs are now included among the “trading venues” that are subject to regulation. An OTF is a multilateral system which is not a Regulated Market or an MTF and in which multiple third-party buying and selling interests in bonds, structured finance products, emission allowances or derivatives are able to interact in the system in a way that results in a contract.

According to Legislative Decree No. 58 of February 24, 1998, as amended from time to time (“Decree No. 58”, the Consolidated Law on Financial Intermediation), the provision of investment services and activities to the public on a professional basis is, inter alia, reserved to investment firms, EU investment companies, Italian banks, EU banks and companies of non-EU countries (“authorized persons”). The Bank of Italy and Consob shall exercise supervisory powers over authorized persons. They shall each supervise the observance of regulatory and legislative provisions according to their respective responsibilities. In particular, in connection with the pursuance of the safeguarding of faith in the financial system, the protection of investors, the stability and correct operation of the financial system, the competitiveness of the financial system and the observance of financial provisions, the Bank of Italy shall be responsible for risk containment, asset stability and the sound and prudent management of intermediaries whilst Consob shall be responsible for the transparency and correctness of conduct. Besides, for the purposes of the application of certain provisions of MiFIR the Bank of Italy and Consob are the Italian competent authorities: Consob is competent, inter alia, as far as the protection of the investors, the orderly functioning and soundness of the financial markets or of the commodity markets are concerned whereas the Bank of Italy is competent as far as the stability of the whole or part of the financial system is concerned.

The Bank of Italy and Consob also regulate the operation of the clearing and settlement service for transactions involving financial instruments as well as the performance of central securities depository services, in line with the European framework – in particular, the Regulation (EU) No. 648/2012, as amended from time to time, (“EMIR”) and the Regulation (EU) No. 909/2014, as amended from time to time, (“Central Securities Depositories Regulation”). The regulations and measures of general application adopted by Consob and the Bank of Italy are available on the website of Consob (www.consob.it) or Bank of Italy (www.bancaditalia.it).

The regulations adopted by Borsa Italiana are available on its website (www.borsaitaliana.it).

Item 10. ADDITIONAL INFORMATION

Memorandum and Articles of Association

Company register

“Eni SpA” is the company resulting from the privatization of Ente Nazionale Idrocarburi, a public agency, established by Law No. 136 of February 10, 1953 and it is registered in the Rome Companies Register, with identification number (and tax number) 00484960588, and VAT number 00905811006. The Company’s registered office is in Rome, Italy, and the Company has two branch offices in San Donato Milanese (Milan).

The full text of Eni’s By-laws is attached as an exhibit to this Annual Report (last amended on November 20, 2014). See “Exhibit 1”.

Company objects and purpose

In accordance with Article 4 of Eni’s By-laws, the Company purpose includes the direct and/or indirect exercise, through equity holdings in companies or other entities of: activities in the field of hydrocarbons and natural gases, in compliance with the terms of concessions provided for by law; activities in the field of chemicals, nuclear fuels, geothermal energy, renewable energy sources and energy in general, in the design and construction of industrial plants, in the mining industry, in the metallurgy industry, in the

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textile machinery industry, in the water sector, including water diversion, potabilization, purification, distribution and reuse; in the environmental protection sector and in the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the aforementioned activities. The Company performs and manages the technical and financial coordination of subsidiaries and associated companies and provides financial assistance to them. Moreover, the Company may acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties.

Directors’ issues

Eni’s Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, the Board has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting.

If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one from among its members.

The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on matters regarding major strategic, operational and organizational decisions.

According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance.

The Board of Directors may at any time revoke the powers delegated, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time.

The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors.

In accordance with Eni’s By-laws, for a Board meeting to be valid, a majority of serving Directors must be present. Resolutions shall be approved by a majority of the votes of the Directors present; in the event of a tie, the person who chairs the meeting shall have a casting vote.

For further information on Directors’ duties and responsibilities and, in particular, the role of the Chairman see “Item 6 – Board of Directors’ duties and responsibilities”.

Interests in Company’s transactions

As provided by the Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company transactions, he shall disclose it to the Board of Directors and to the Board of Statutory Auditors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the Consob (“Commissione Nazionale per le Società e la Borsa” is the public authority responsible for regulating the Italian financial markets) regulation on transactions with related parties (the “Consob Regulation”), the Board of Directors – on November 18, 2010 – unanimously approved the Management System Guidelines “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”1 (“MSG”), which has been in effect from January 1, 20112 to ensure the transparency and substantial and procedural fairness of transactions with related parties and with parties that are of interest to Eni’s Directors and Statutory Auditors, carried out by Eni itself or its subsidiaries. This MSG and the subsequent amendments received the preliminary favorable opinion, expressed unanimously, of the Control and Risk Committee, composed entirely of independent Directors

(1)

The Board of Directors modified this Management System Guideline on January 19, 2012 and lastly on April 4, 2017.

(2)

This MSG replaced the previous regulation issued by the Board of Directors on the matter on February 12, 2009. The new provisions regarding information to be provided to the public, under both the Consob Regulation and the MSG, have been applied since December 1, 2010.

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as per the requirements set out in the Corporate Governance Code, which Eni has adopted, and in accordance with the Consob Regulation. The MSG sets out monitoring and evaluation requirements for the preliminary phase and for carrying out a transaction with a party in which a Director or Statutory Auditor has an interest. In this regard, both in the preliminary and deliberation phase, a thorough, documented examination of the reasons for the transaction, highlighting the Company’s interest in carrying it out and the soundness and fairness of the underlying terms, is required. Directors involved in matters subject to Board resolution normally shall not participate in the relevant discussion and decision and shall leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction falls under his duties, he shall in any case abstain from taking part in the transaction and shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In any case, if the transaction is under the responsibility of the Board of Directors of Eni, a non-binding opinion from the Control and Risk Committee is required.

Moreover, to ensure compliance with the procedures envisaged by the above mentioned MSG, Directors and Statutory Auditors issue a declaration, every six months and/or when there is any change, in which they state their potential interests related to Eni and its subsidiaries. In any case the Directors and the Statutory Auditors report in good time the single transactions that Eni intends to carry out in which they have an interest. Directors report the interest to the Chief Executive officer (or the Chairman, in the case of interests of the Chief Executive Officer), who will in turn notify the other Directors and the Board of Statutory Auditors. Statutory Auditors report the interest to the other Statutory Auditors and the Chairman of the Eni SpA Board of Directors.

Compensation

Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian law, while the compensation of Directors with delegated powers in accordance with the By-laws (such as the Board Chairman and the CEO), or that participate in Board Committees, shall be determined by the Board of Directors, upon the proposal of the Remuneration Committee, after examining the opinion of the Board of Statutory Auditors (for more details about the compensation policy in 2017, see “Item 6 – Compensation”).

Borrowing powers

The power to borrow is included in the Company purpose. Moreover, in accordance with Article 11 of the By-laws, the Company may issue bonds, including convertibles bonds and warrants, in compliance with the law.

Retirement and shareholdings

There are no provisions in the By-laws relating to either retirement based on age-limit requirements and the number of shares required for a Director to qualify.

Company’s shares

In accordance with Article 5 of the By-laws, the Company’s share capital amounts to €4,005,358,876.00, fully paid, and is represented by 3,634,185,330 ordinary registered shares without indication of par value. As required by the Italian law on the dematerialization of financial instruments, Eni’s shares (the “Shares”) must be held with “Monte Titoli SpA” (the Italian Central Securities Depository) and their beneficial owners may exercise their rights through special deposit accounts opened with intermediaries, such as banks, brokers and securities dealers.

Shares are indivisible and each share is entitled to one vote. Shareholders are allowed to vote at ordinary and extraordinary Shareholders’ Meeting, including by proxy or by mail or, if envisaged in the notice calling the Meeting, by electronic means.

Moreover, in accordance with Article 9 of the By-laws, the Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration to Eni employees, pursuant to Article 2349 of the Italian Civil Code. This power has not been exercised.

In 1995, Eni established a sponsored American Depositary Receipts program directed at U.S. investors.

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Each Eni ADR is equal to two Eni ordinary shares; Eni ADRs are listed on the NYSE.

Dividend rights

Shareholders have the right to participate in profits and any other rights as provided by the law and subject to any applicable legal limitations. Specifically, the ordinary Shareholders’ Meeting called to approve the annual Financial Statements may allocate the net income resulting after allotment to the legal reserve to the payment of a final dividend per share. In addition, during the course of the financial year, the Board of Directors may distribute, as allowed by the By-laws, interim dividends to the shareholders. Entitlement to dividends not collected within five years of the day on which they become payable shall lapse in favor of the Company and such dividends shall be allocated to reserves.

Voting rights

The general provisions on share “voting rights” are described at the paragraph “Shareholders’ Meeting” below. In relation to the appointment of the Board of Directors (Eni’s Board is not a “staggered board”) and the Board of Statutory Auditors (see “Item 6”), Eni’s By-laws provide for a slate voting system. In particular, pursuant to Article 17 of the By-laws and in accordance with applicable law, slates may be presented both by shareholders, either severally or jointly, representing at least 1% of the share capital, or any other threshold established by Consob in its regulation (lastly, on January 25, 2017, Consob confirmed a threshold of 0.5% for Eni, given its market capitalization), or by the Board of Directors. Each shareholder may, severally or jointly, submit and vote on a single slate only.

There are no provisions in Eni’s By-laws relating to: rights to share in Company profits; redemption provisions; sinking fund provisions; liability to further capital calls by the Company.

Liquidation rights

In the event the Company is wound up, the Shareholders’ Meeting shall decide the manner of its liquidation and appoint one or more liquidators, establishing their powers and remuneration. In accordance with Italian law, shareholders would be entitled to the distribution of the remaining liquidated assets of the Company in proportion to their shareholdings, only after payment of all the Company’s liabilities and satisfaction of all other creditors.

Change in shareholders’ rights

A shareholders’ resolution is required to make changes in shareholders’ rights. Italian law gives shareholders the right to withdraw in the event of an amendment of the provisions of the By-laws relating to, among other matters, voting and dividend rights, approved by resolution of the Shareholders’ Meeting with the attendance and decision making quorum established by law for extraordinary meetings.

Shareholders’ Meeting

The Shareholders’ Meeting resolves on the issues set forth by applicable law and Eni’s By-laws, in “ordinary” or “extraordinary” form. The ordinary and the extraordinary Shareholders’ Meetings are normally held after a single call, with the majorities required by law in this case. The Board of Directors may, if deemed necessary, establish that both the ordinary and the extraordinary Shareholders’ Meetings shall be held after more than one call; their resolutions at first, second or third call must be passed with the majorities required by law in each case.

Shareholders’ Meetings shall normally be held at the Company’s registered office, unless otherwise decided by the Board of Directors, provided however they are held in Italy.

The Shareholders’ Meeting shall be called by way of a notice published on the Company website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. The notice calling the meeting, the content of which is defined by the law and Eni’s By-laws, contains all the information for attending and voting at the meeting, including information on proxy voting and voting by mail (the information is also available on the Company’s website) and, if envisaged, it may include instructions for participating in the Shareholders’ Meeting by means of telecommunication systems, as well as exercising the right to vote by electronic means. The Board of Directors shall make a report on each of the items on the agenda available to the public at the Company’s registered office, on the Company’s website and by other means envisaged by Consob regulations by the same date of the publication of the notice calling the Shareholders’ Meeting for each of

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the items on the agenda. Specific legal provisions may require other terms of publication of the Board of Directors report (i.e. in case of extraordinary transactions). An ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year (on December 31), to approve the financial statements, since the Company is required to draw up Consolidated Financial Statements.

The right to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the Shareholders’ Meeting. Credit and debit records entered on the authorized intermediaries’ accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise voting rights at the Shareholders’ Meeting. The statement, issued by the authorized intermediary, must reach the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting, or by any other deadline established by Consob regulations issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the Meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. For the purposes of these provisions, reference is made to the date of first call, provided that the dates of any subsequent calls are indicated in the notice calling the Meeting; otherwise, the date of each call is deemed the reference date.

Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy or in electronic form in the manner set forth by current law. Electronic notification of the proxy may be made through a special section of the Company website as indicated in the notice calling the Meeting. In order to simplify proxy voting by shareholders who are employees of the Company or of its subsidiaries and belong to shareholders’ associations that meet applicable statutory requirements, locations for communications and collection of proxies shall be made available in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations.

The right to vote may also be exercised by mail in accordance with the applicable laws and regulations. If provided for in the notice calling the meeting, those persons entitled to vote may participate in the Shareholders’ Meeting by means of telecommunication systems and exercise their right to vote by electronic means in accordance with the provisions of the law, applicable regulations and the Shareholders’ Meeting Rules.

The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda, as provided for by applicable laws and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting including for calls subsequent to the first. Such proxy shall not be valid for items in respect of which no voting instructions have been provided.

The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting.

The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved by resolution of the ordinary Shareholders’ Meeting on December 4, 1998, in order to guarantee an efficient conduct of meetings and the right of each shareholder to express his or her opinion on the items on the agenda.

During Shareholders’ Meetings, the Board of Directors provides broad disclosure on items examined and shareholders can request information on issues in the agenda. Information is provided taking into account applicable rules on inside information.

Stock ownership limitation and voting rights restrictions

There are no limitations imposed by Italian law or by Eni’s By-laws on the rights of non-residents in Italy or foreign persons to hold shares or vote other than the limitations described below (which are equally applicable to both residents and non-residents of Italy).

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In accordance with Article 6 of the By-laws, and in application of the special rules pursuant to Article 33 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), no shareholder may hold, in any capacity, directly or indirectly, more than 3% of the Company’s share capital. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved.

Pursuant to Article 32 of the By-laws and the above mentioned provision of law, shareholdings owned by the Ministry of the Economy and Finance, public entities or organizations controlled by them are exempt from this ban.

Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors.

Limitation on changes in control of the Company (Special Powers of the Italian State)

The special powers apply to companies that hold strategic assets vital to the interests of the Italian State as defined by the ministerial regulations which implement the relevant law.

The current legislation governing the special powers briefly include: a) veto power (or the power of imposing conditions or requirements) over transactions involving strategic assets that could result in a situation, not regulated by Italian or EU laws, that threatens serious injury to interests regarding networks and systems security, as well as continuity of supply; and b) power of attaching conditions or opposing the acquisition by an entity outside of the EU of shareholdings that determine the control of a company that holds, directly or indirectly, strategic assets, when such an acquisition may result in a threat of serious injury to the above mentioned essential interests of the Italian State (see also the provisions of Decree Law No. 148 of October 16, 2017, ratified with amendments by Law No. 172 of December 4, 2017, reported below). The shareholding of third parties who have entered into a shareholders’ agreement with the buyer is taken into account in the calculation of above mentioned relevant shareholdings.

With particular reference to the power referred to in letter b), the legislation establishes notification obligations for the buyer entity outside of the EU to the Italian Presidency of the Council of Ministers as well as procedural terms. Until such notification and thereafter, up to the expiration of the term for the possible exercise of power, the voting rights and any other non-financial right related to the significant shareholding may not be exercised.

In the case of non-fulfillment of imposed conditions, throughout the relevant period, the voting rights and any other non-financial right related to the significant shareholding may not be exercised. The resolutions adopted with the decisive vote of such shareholding, or otherwise the resolutions or acts adopted in breach or default of the imposed conditions are void. In addition, unless the fact constitutes a crime, failure to comply with imposed conditions entail for the purchaser a fine.

In case of opposition, the buyer may not exercise the voting rights and any other non-financial right related to the significant shareholding, which must be sold within a year. In case of non-compliance, at the request of the Government, the Court will order the sale of the significant shareholding. Shareholders’ Meeting resolutions adopted with the decisive vote of such participation shall be void.

(3)

This provision has been modified by the Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012. For more details see the paragraph “Limitation on changes in control of the Company (Special Powers of the Italian State)” below.

(4)

The prior provisions (Article 2 of Decree Law No. 332/1994, ratified by Law No. 474/1994 and its implementing decrees), as well as the provisions of the By-laws which were inconsistent with the new rules, lapsed at the issuance of Decree of the President of the Italian Republic No. 85 of March 25, 2014, in force since June 7, 2014.

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The legislation provides for a general rule that the acquisition, for any reason, by an entity outside of the EU of stock of company that holds strategic assets be allowed on condition of reciprocity, in compliance with international agreements signed by Italy or the EU.

These powers are exercised exclusively on the basis of objective and non-discriminatory criteria.

Decree Law No. 148 of October 16, 2017, ratified with amendments by Law No. 172 of December 4, 2017, extended the special powers of the Italian State to high-technology industries5. Furthermore, with regard to investments in companies with strategic assets by a non-EU investor, the decree added two assessment criteria for the exercise of the special powers, namely a threat to security or to public order6, in addition to safeguarding the essential interests of the State.

Albeit with some amendments, the provisions regarding the stock ownership limitations and voting rights restrictions pursuant to Article 3 of Law No. 474/1994 are still in force.

In order to “promote privatization and the spread of investment in shares” of companies in which the Italian State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily controlled by the Italian State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and extraordinary Shareholders’ Meetings. Making this amendment to the By-laws would lead to the shareholding limit referred to in Article 6.1 of the By-laws being removed. At the present time, however, Eni’s By-laws do not contain any of such provisions.

Shareholder ownership thresholds

There are no By-law provisions governing the disclosure of the ownership threshold because the matter is regulated by Italian law. Pursuant to the Consolidated Law on Finance7 and the Consob Regulation8, any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%9, 5%, 10%, 15%, 20%, 25%, 30%, 50%, 66.6% and 90% must be notified to the investee company and to Consob. The same disclosure requirements refer to holdings that drop below one of the specified thresholds.

Such disclosures shall be made – using the forms contained in Annex 4A to the above Regulation – without delay and, in any case, within four days of the transaction, starting from the day on which the subject gains knowledge of the transaction that can lead to the obligation, regardless of the date of execution, or from the date on which the subject obliged to make the disclosure gains knowledge of the event that leads to changes in the share capital as contemplated in the Consob Regulation.

For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria10. The obligation to notify also applies to any direct or indirect holding owned through ADRs.

Specific disclosure requirements (with partially different thresholds) are connected to investments in financial instruments and for aggregate investments11.

(5)

Article 2, paragraph 1-ter of Decree-law no. 148/2017 establishes that one or more governmental implementing regulations shall identify, for the purpose of assessing the presence of a threat to security or public order, high-technology sectors, including: (a) critical or sensitive infrastructure, including data storage and management and financial infrastructure; (b) critical technologies, including artificial intelligence, robotics, semiconductors, potential dual-use technologies, network security, space or nuclear technology; (c) security of supply of critical inputs; (d) access to sensitive information or the capacity to control sensitive information.

(6)

In order to determine if a foreign investment could impact security or public order, Decree-law no. 148/2017 establishes that it is possible to take into consideration the circumstance of a foreign investor being controlled by the government of another non-EU country, including by way of significant financing.

(7)

Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122.

(8)

Article 117 of Consob Decision No. 11971/1999 and subsequent amendments.

(9)

The Legislative Decree No. 25/2016, in force since March 18, 2016, modified the Article 120 of the Legislative Decree No. 58/1998, increasing this holding threshold from 2% to 3%. Moreover, Consob may, by means of measures justified by the need to protect investors, as well as corporate control market and capital market efficiency and transparency, envisage – for a limited period of time – lower thresholds by its decree for companies with an elevated current market value and particularly extensive shareholding structure.

(10)

Article 118 of Consob Decision No. 11971/1999 and subsequent amendments.

(11)

Article 119 of Consob Decision No. 11971/1999 and subsequent amendments.

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Under the above mentioned Decree Law No. 148/2017, in the case of the purchase of a stake in quoted issuers equal or above the thresholds of 10%, 20% and 25% of the relevant share capital in listed companies, the investor shall state the objectives it intends to pursue in the following six months. The declaration shall state under the responsibility of the declarant: a) the means of financing the acquisition; b) whether acting alone or in concert; c) whether it intends to stop or continue its purchases, and whether it intends to acquire control of the issuer or anyway have an influence on the management of the company and, in such cases, the strategy it intends to adopt and the transactions to be carried out; d) its intentions as to any agreements and shareholders’ agreements to which it is party; e) whether it intends to propose the integration or revocation of the issuer’s administrative or control bodies. Consob can identify, with its own regulation, the cases where the aforementioned declaration is not due, taking into account the characteristics of the entity making the declaration or of the company whose shares have been purchased.

The declaration shall be transmitted to the company whose shares have been purchased and to Consob and shall be subject to public disclosure in accordance with the terms and conditions established by Consob Regulation.

Voting rights attached to listed shares which have not been notified pursuant to the above mentioned disclosure requirements may not be exercised. Any resolution or act adopted in violation of such limitation, with the contribution of those undisclosed shares, could be voided if challenged in court, under the Italian Civil Code.

According to the Italian Civil Code (Article 2359-bis), a subsidiary may acquire shares of the parent company only within the limits of distributable profits and available reserves as resulting from the last approved balance sheet. Only fully-paid shares can be purchased. The purchase must be approved by the Shareholders’ Meeting and, in any case, the nominal value of shares purchased may not exceed one-fifth of the capital of the parent company – if the latter is a listed company – taking into account for this purpose the shares held by the same parent company or its subsidiaries.

The Consolidated Law on Finance provides rules governing cross-holdings. In particular, except for the cases contemplated by the above mentioned Article 2359-bis of the Italian Civil Code, in case of a reciprocal participation exceeding the limit of 3% of the shares, the company that exceeds the limit successively cannot exercise its right to vote relative to the shares held in excess of such threshold and must sell such shares within the following 12 months. In the event of failure to dispose of the shares by such time limit, the voting rights shall be suspended with respect to the entire shareholding. Where it is not possible to ascertain which of the two companies was the last to exceed the limit, the suspension of voting rights and the disposal requirement shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.

The above mentioned limit is increased to 5% (or to 10% if the issuer is a small or medium enterprise as per Article 1, letter w-quater.1 of the Consolidated Law on Finance) if the threshold is exceeded by both companies subsequent to an agreement authorized in advance by the ordinary shareholders’ meetings of the companies concerned.

If a person holds an interest exceeding the aforementioned threshold of a listed company, such listed company or any person controlling such listed company may not acquire an interest exceeding such a limit in a listed company controlled by the former. In the event of non-compliance, the voting rights attached to the shares in excess of the limit specified shall be suspended. Where it is not possible to ascertain which of the two persons was the last to exceed the limit, the suspension shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.

The limitations described above are not applicable in the case of a takeover bid or exchange tender offer to acquire at least 60% of the ordinary shares of a listed company.

Under the Consolidated Law on Finance, any agreement, in any form, regarding the exercise of voting rights in a listed company or in its parent company, must be, within five days of stipulation: (i) notified to Consob; (ii) published in abstract form, in the Italian daily press; (iii) filed with the Register of Companies in which the listed company is registered; and (iv) notified to the company with listed shares. In the event of

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non-compliance with these requirements, the agreements shall be null and void and the voting rights attached to the relevant shares may not be exercised and any resolution or act adopted with the contribution of such shares may be challenged under the Italian Civil Code.

The same provisions also apply to agreements, in any form, that: (a) create obligations of consultation prior to the exercise of voting rights in a listed company and in its controlling companies; (b) set limits on the transfer of the related shares or of other financial instruments that entitle holders to buy or subscribe them; (c) provide for the purchase of the shares or of the above mentioned financial instruments; (d) have as their object or effect the exercise, jointly or otherwise, of dominant influence on such companies; and (d-bis) which aim to encourage or frustrate a takeover bid or an exchange tender offer, including commitments relating to non-participation in a takeover bid.

Finally, pursuant to Law No. 287 of October 10, 1990, any merger or acquisition of (legal or factual) sole or joint control over a company or any change of control over a company is subject to the prior authorization by the Italian Antitrust Authority12 if the companies involved exceed given turnover thresholds. If the said merger, acquisition or change of control would create or strengthen a dominant position in the Italian market in a manner that eliminates or significantly reduces competition, the Italian Antitrust Authority can either prohibit the transaction or make it subject to remedies preventing a restriction of competition. Moreover, if the transaction or the companies involved exceed other thresholds set by European or other countries’ legislations (e.g. other turnover thresholds or thresholds referred to transaction’s value or market shares of the parties), the transaction can also be subject to the prior authorization by competition authorities of other jurisdictions.

Changes in share capital

Eni’s By-laws do not provide for more stringent conditions than are required by law.

Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. Under Italian law, shareholders have a pre-emptive right to subscribe newly issued shares and corporate bonds convertible into shares in proportion to their respective shareholdings. If the Company’s interest so requires, the pre-emptive right may be waived or limited by the shareholders’ resolution authorizing the share capital increase. The shareholders’ pre-emptive right is also waived if the shareholders’ resolution authorizing the share capital increase provides for the subscription of new issues of shares in the form of contributions in-kind.

Material contracts

None.

Exchange controls

Under current Italian exchange control regulations, no limits exist on the amount of payments that Eni may remit to residents of the United States. Laws and regulations concerning foreign exchange controls do require, however, that an accredited intermediary must handle all payments or transfer of funds made by an Italian resident to a non-resident.

Taxation

The information set forth below is only a summary; Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction.

Italian taxation

The following is a summary of the material Italian tax consequences of the ownership and disposition of shares or ADRs as at the date hereof and does not purport to be a complete analysis of all potential tax effects relevant to the ownership or disposition of shares or ADRs.

(12)

Autorità garante per la concorrenza e il mercato (AGCM - www.agcm.it)

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Income tax

Dividends regarding income of financial year 2017 paid in 2018, received by Italian resident individuals in relation to interest exceeding 2% of the voting rights or 5% of the share capital (“substantial interest”) are included in the taxable income subject to personal income tax to the extent of 58.14% of their amount. Personal income tax applies at progressive rates ranging from 23% to 43% plus local surtaxes. Dividends received by Italian resident individuals in relation to non-substantial interest not related to the conduct of a business are subject to a substitute tax of 26% withheld at the source by the dividend paying agent. This being the case, the dividend is not to be included in the individual’s tax return. If the non-substantial interest is related to the conduct of a business, dividends received in respect of 2017 profits are included in the taxable business income for 58.14% of their amount. The 26% substitute tax regime will apply also to substantial interest dividends, regarding income from financial year 2018.

Dividends received by Italian investment funds, foreign open-ended investment funds authorized to market their securities in Italy pursuant to the Law Decree June 6, 1956, No. 476, converted into Law July 25, 1956, No. 786, and società di investimento a capitale variabile (SICAV) are not subject to substitute tax but are included in the aggregate income of the investment fund or SICAV. The investment fund or SICAV will not be subject to tax on the dividends. A withholding tax of 26% may apply on income of the investment fund or SICAV derived by unitholders or shareholders through distribution and/or upon redemption or disposal of the units and shares.

Dividends received by real estate funds to which the provisions of Law Decree No. 351 of September 25, 2001, as subsequently amended, apply, are not subject to any substitute tax nor to any other income tax in the hands of the fund. The income of the real estate fund is subject to tax, in the hands of the unitholder, depending on status and percentage of participation, or, when earned by the fund, through distribution and/or upon redemption or disposal of the units.

Dividends received by a pension fund (subject to the regime provided for by Article 17 of the Italian Legislative Decree No. 252 of December 5, 2005) and deposited with an authorized intermediary, will not be subject to substitute tax, but must be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to a 20% substitute tax.

Dividends paid to non-Italian residents are subject to the same substitute tax levied at source by the dividend paying agent at the rate of 26%, provided that the interest is not connected to an Italian permanent establishment.

Dividends are subject to a 1,20% substitute tax introduced by the Financial Bill for 2008 where the conditions in Article 27, paragraph 3-ter, Presidential Decree No. 600 of 1973 are met, i.e. dividends are paid to companies and entities subject to a corporate income tax in a European Union Member State or in Norway.

The substitute tax may also be reduced under the Tax Treaty in force between Italy and the country of residence of the Beneficial Owner of the dividend. Italy has executed income Tax Treaties with approximately 90 foreign countries, including all EU Member States, Argentina, Australia, Brazil, Canada, Japan, New Zealand, Norway, Switzerland, the United States and some countries in Africa, the Middle East and the Far East. Generally speaking, it should be noted that Tax Treaties are not applicable where the holder is a tax-exempt entity or, with few exceptions, a partnership or a trust.

In order to obtain the Treaty benefit of a reduced substitute tax rate at the same time of payment, the Beneficial Owner must file an application to the dividend paying agent chosen by the Depositary stating the existence of the conditions for the applicability of the Treaty benefit, together with a certification issued by the foreign tax authorities stating that the shareholder is a resident of that country for Treaty purposes.

Under the Tax Treaty between the United States and Italy, dividends derived and beneficially owned by a U.S. resident who holds less than 25% of the Company’s shares are subject to an Italian withholding or substitute tax at a reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed establishment in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax

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at the statutory rate of 26%. Based on the certification procedure required by the Italian Tax Authorities, to benefit from the direct application of the 15% substitute tax the U.S. shareholder must provide the dividend paying agent with a certificate obtained from the U.S. Internal Revenue Service (the IRS) with respect to each dividend payment. The request for this certificate must include a statement, signed under penalty of perjury, attesting that the shareholder is a U.S. resident individual or corporation, and does not maintain a permanent establishment in Italy, and must set forth other required information. The normal time for processing requests for certification by the IRS is normally about six to eight weeks.

Where the Beneficial Owner has not provided the above mentioned documentation, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. The U.S. recipient will then be entitled to claim from the Italian Tax Authorities the difference (treaty refund) between the domestic rate and the Treaty one by filing specific forms (certificate) with the Italian Tax Authorities.

As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the American Depositary Shares (ADSs), such tax or other governmental charge shall be paid by the Holder hereof to the Depositary. The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities until such payment is made. The Depositary may also deduct from any distributions on or in respect of Deposited Securities, or may sell by public or private sale for the account of the Holder hereof any part or all of such Deposited Securities (after attempting by reasonable means to notify the Holder hereof prior to such sale), and may apply such deduction or the proceeds of any such sale in payment of such tax or other governmental charge, the Holder hereof remaining liable for any deficiency, and shall reduce the number of ADSs to reflect any such sales of shares. Pursuant to the Deposit Agreement, the Depositary and the Custodian may make and maintain arrangements to enable persons that are considered United States residents for purposes of applicable law to receive any tax rebates (pursuant to an applicable Treaty or otherwise) or other tax related benefits relating to distributions on the ADSs to which such persons are entitled. Notwithstanding any other terms of the Deposit Agreement or the ADR, absent the gross negligence or bad faith of, respectively, the Depositary and the Company, the Depositary and the Company assume no obligation, and shall not be subject to any liability, for the failure of any Holder or Beneficial Owner, or its agent or agents, to receive any tax benefit under applicable law or Tax Treaties. The Depositary shall not be liable for any acts or omissions of any other party in connection with any attempts to obtain any such benefit, and Holders and Beneficial Owners hereby agree that each of them shall be conclusively bound by any deadline established by the Depositary in connection therewith.

Capital gains tax

This paragraph concerns and applies to capital gains out of the scope of a business activity carried out in Italy.

Profits gained by Italian resident individuals, in financial year 2018, upon the sale of a substantial interest are included in the taxable base subject to personal income tax for 58.14% of their amount, while gains realized in 2019 will be subject to substitute tax for 26%.

For gains deriving from the sale of non-substantial interest, two different systems may be applied at the option of the shareholder as an alternative to the filing of the tax return:

•

the so-called “administered savings” tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (26%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and

•

the so-called “portfolio management” tax regime (risparmio gestito) which is applicable when the shares form part of a portfolio managed by an Italian asset management company. The accrued net profit of the portfolio is subject to a 26% substitute tax to be applied by the portfolio.

Gains realized by non-residents from non-substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax.

On the contrary, gains realized by non-residents from substantial interests even in listed companies are deemed to be realized in Italy and consequently are subject to the capital gains tax.

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However, double taxation treaties may eliminate the capital gains tax. Under the income tax convention between the United States and Italy, a U.S. resident will not be subject to the capital gains tax unless the shares or ADRs form part of the business property of a permanent establishment of the holder in Italy or pertain to a fixed establishment available to a shareholder in Italy for the purposes of performing independent personal services. U.S. residents who sell shares may be required to produce appropriate documentation establishing that the above mentioned conditions of non taxability pursuant to the convention have been satisfied.

Financial Transactions Tax

Italian Law No. 228 of December 24, 2012 has introduced a Financial Transactions Tax which applies to the transfer of shares, ADR and other financial instruments issued by companies resident in Italy. The tax rate applicable is 0.10% for ADR negotiated in regulated markets (like the NYSE).

Non-Italian intermediaries, involved in the transactions of Eni ADR, must withhold and pay the Financial Transactions Tax. For this purpose, non-Italian intermediaries can appoint an Italian Tax Representative, according to the Italian tax law.

Inheritance and gift tax

Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of November 24, 2006, effective from November 29, 2006, and Law No. 296 of December 27, 2006, the transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no consideration) and the creation of liens on such assets for a specific purpose are taxed as follows:

(a)

4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the transfer is subject to tax on the value exceeding €1,000,000 (per beneficiary);

(b)

6 per cent: if the transfer if made to brothers and sisters; in this case, the transfer is subject to the tax on the value exceeding €100,000 (per beneficiary);

(c)

6 per cent: if the transfer is made to relatives up to the fourth degree, to persons related by direct affinity, as well as to persons related by collateral affinity up to the third degree; and

(d)

8 per cent: in all other cases.

If the transfer is made in favor of persons with severe disabilities, the tax applies on the value exceeding €1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001 for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift, the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place.

United States taxation

The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S. Holders that hold Shares or ADSs as capital assets, and does not purport to address all material tax consequences of the ownership of Shares or ADSs. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to-market, certain insurance companies, broker-dealers, investors liable for alternative minimum tax, investors that actually or constructively own 10% or more of the combined voting power of Eni SpA’s voting stock or of the total value of Eni SpA’s stock, a person that purchases or sells Shares or ADSs as part of a wash sale for U.S. federal income tax purposes, investors that hold Shares or ADSs as part of a straddle or a hedging or conversion transaction and investors whose “functional currency” is not the U.S. dollar.

This summary is based on the tax laws of the United States (including the Internal Revenue Code of 1986, as amended, (the “Code”), its legislative history, existing and proposed regulations thereunder, published rulings and court decisions) as in effect on the date hereof, and which are subject to change (or changes in interpretation), possibly with retroactive effect. The summary is based in part on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their own tax advisors to determine the U.S. federal, state and local and foreign tax consequences to them of the ownership and disposition of Shares or ADSs.

If a partnership holds the Shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the Shares or ADSs should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the Shares or ADSs.

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As used in this section, the term “U.S. Holder” means a beneficial owner of Shares or ADSs that is: (i) a citizen or resident of the United States; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust.

The discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. In particular, U.S. Holders are urged to confirm their eligibility for benefits under the income tax convention between the United States and Italy with their advisors and to discuss with their advisors any possible consequences of their failure to qualify for such benefits. In general, and taking into account the earlier assumptions, for U.S. federal income tax purposes, U.S. Holders who own ADRs evidencing ADSs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for Shares generally will not be subject to U.S. federal income tax.

Dividends

Subject to the passive foreign investment company (PFIC), rules discussed below, distributions paid on the shares will generally be treated as dividends for U.S. federal income tax purposes to the extent paid out of Eni SpA’s current or accumulated earnings and profits as determined for U.S. federal income tax purposes, but will not be eligible for the dividends-received deduction generally allowed to U.S. corporations. To the extent that a distribution exceeds Eni SpA’s earnings and profits, it will be treated, first, as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in the Shares or ADSs, and thereafter as capital gain. A U.S. Holder will be subject to U.S. federal taxation, on the date of actual or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian Tax Authorities. For non-corporate U.S. Holders, dividends paid that constitute qualified dividend income will be taxable at the preferential rates applicable to long-term capital gains provided that such person holds the Shares or ADSs for more than 60 days during the 121 day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends paid by the Group with respect to the Shares or ADSs will generally be qualified dividend income. The amount of the dividend distribution that must be included in the income of a U.S. Holder will be the U.S. dollar value of the euro payments made, determined at the spot EUR/USD rate on the date the dividend distribution is includible in such person’s income, regardless of whether the payment is in fact converted into U.S. dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the U.S. Holder includes the dividend payment in income to the date he or she converts the payment into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes.

Subject to certain conditions and limitations, Italian tax withheld from dividends will be treated as a foreign income tax eligible for credit against the U.S. Holder’s U.S. federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the preferential rates. To the extent a refund of the tax withheld is available to a U.S. Holder under Italian law or under the income tax convention between the United States and Italy, the amount of tax withheld that is refundable will not be eligible for credit against his or her U.S. federal income tax liability. See “Italian taxation – Income tax” above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the shares will be income from sources outside the United States and will, generally be “passive” income for purposes of computing the foreign tax credit allowable to you.

Sale or exchange of shares

Subject to the PFIC rules discussed below, a U.S. Holder generally will recognize gain or loss for U.S. federal income tax purposes on the sale or exchange of Shares or ADSs equal to the difference between the U.S. Holder’s adjusted basis in the Shares or ADSs (determined in U.S. dollars), as the case may be, and the amount realized on the sale or exchange (or if the amount realized is denominated in a foreign currency its U.S. dollar equivalent, determined at the spot rate on the date of disposition). Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a non corporate U.S. Holder is generally taxed at preferential rates. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes.

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PFIC rules

Eni believes that Shares and ADSs should not be treated as stock of a PFIC for U.S. federal income tax purposes, but this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, a U.S. Holder would be treated as having realized such gains and certain “excess distributions” ratably over the holding period for the Shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, a U.S. Holder’s Shares or ADSs will be treated as stock in a PFIC if Eni SpA were a PFIC at any time during the period the Shares or ADSs were held. Dividends received from Eni SpA will not be eligible for the preferential tax rates applicable to qualified dividend income if Eni SpA is treated as a PFIC with respect to the U.S. Holders either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income.

Documents on display

Eni’s Annual Report and Accounts and any other document concerning the Company are also available online on the Company website at: http://www.eni.com/en_IT/documentation/documentation.page?type=bil-rap.

The Company is subject to the information requirements of the U.S. Security Exchange Act of 1934 applicable to foreign private issuers.

In accordance with these requirements, Eni files its Annual Report on Form 20-F and other related documents with the U.S. SEC. It’s possible to read and copy documents that have been filed with the U.S. SEC at the U.S. SEC’s public reference room located at 100 F Street NE, Washington, DC 20549, USA.

You may also call the U.S. SEC at +1 800-SEC-0330 or log on to www.sec.gov.

It is also possible to read and copy documents referred to in this Annual Report on Form 20-F at the New York Stock Exchange, 20 Broad Street, 17th floor, New York, USA.

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Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the possibility that the exposure to fluctuations in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the EUR/USD exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil&gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity.

The impact of changes in crude oil prices on the Company’s downstream gas and refining and marketing businesses and petrochemical operations depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the EUR/USD exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated products as in the case of gas prices. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa.

As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, optimization and risk management activities, as well as exceptionally to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil&gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives.

The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of undertaking finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department and its subsidiaries Eni Finance International, Eni Finance USA and Banque Eni, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping, that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni SpA and Eni Finance International manage subsidiaries’ financing requirements in and outside Italy, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies are managed by the parent company. The commodity risk of each business unit (Eni’s business lines or subsidiaries) is pooled and managed by the parent company Midstream business department, with Eni Trading & Shipping executing the negotiation of commodity derivatives.

During 2013, the above mentioned centralized model for the execution of financial derivatives has been ring fenced in light of the relevant new financial regulations which became effective (EMIR/Dodd Frank). Eni’s activities are in compliance with regulatory requirements for execution of financial derivatives on European and non-European Regulated Markets, on Multilateral Trading Facilities, on Organized Trading Facilities or bilaterally with OTC counterparties.

In addition to the reinforcement of the centralized execution model, as required by the new financial regulation, in 2013 the EMIR concepts of “risk reducing” and “non-risk reducing” derivatives were introduced. Activities in financial derivatives were thus classified in order to clearly: a) isolate ex ante non-risk reducing activities; b) define a priori the types of OTC derivative contracts included in the hedging portfolios and the eligibility criteria, and stating that the transactions in contracts included in the hedging portfolios are limited to covering risks directly related to commercial or treasury financing activities; and c) provide for a sufficiently disaggregate view of the hedging portfolios in terms of for example asset class, product and time horizon, in order to establish the direct link between the portfolio of hedging transactions and the risks that this portfolio seeks to hedge. A derivative can be qualified a risk reducing instrument when, by itself or in combination with other derivative contracts (so-called macro or portfolio hedging) it:

(i)

directly or through closely correlated instruments (so-called proxy hedging) covers the risks arising from potential changes in value, direct or caused by fluctuation of interest rates, inflation rates, foreign exchange rates or credit risk, of different assets under Eni control or that Eni will have under its controls in the normal course of business; or

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(ii)

qualifies as a hedging contract pursuant to IFRS.

Use of financial derivatives (in euro or currencies different from euro) is allowed with the following risk reducing purposes:

•

Back to back: includes market risk-free instruments that are negotiated in accordance to an execution criteria and normally settled with an intermediation fee. They normally comply with hedge accounting requirements or own use exemption. These are transaction-based activities characterized by a substantial absence of market risk. A hedging instrument can be considered back to back when the financial derivative is structured as to match as much as possible asset class, size and maturity of the hedged position. As a result the combination of the hedged item, normally a single asset/contract or an order received by mean of an internal derivative, and the hedging instrument, i.e. the financial derivative, is substantially market risk free or is exposed only to a basic risk related to the ineffective portion of the hedging item. In addition, the hedging item may entail counterparty risk and operational risk. These derivatives are normally accounted for as hedges for financial statement purposes.

•

Flow hedging: flow hedging seeks to optimize Group hedging requirements by pooling different positions retained by the business units and then by entering derivative instruments to hedge net exposures, in accordance to a portfolio basis. A central department processes a continuous flow of orders from the Group various business units and then acts as a single broker on financial markets. Flow hedging is characterized by the lack of direct control by the central broker entity on the received orders, which are normally related to assets managed by the business units. The central broker entity can normally rely on a continuous flow of hedging orders that can be predictable to a large extent, on the basis of the regular hedging programs made by the Group’s business units. The central entity is therefore in the position to net opposite orders, by retaining the level of risk necessary to cover timing, volume and asset class mismatch among orders. The benefits are the maximization of integration across the whole of the Group assets portfolio and the related netting potential, avoiding unnecessary derivatives, thus reducing costs and aggregated notional amounts of hedging programs. Flow hedging is managed on a portfolio basis and is dynamic by nature, since resulting net position is normally adjusted in order to take into account new orders received and maximum allowed exposure, related to timing, volume and asset classes mismatch. Those derivatives are accounted to profit and loss as the hedging of net exposures does not qualify as hedges under IFRS.

•

Asset-backed hedging: is a portfolio-based activity performed to protect assets extrinsic value which is the fair value that a third party would potentially pay to buy the flexibility associated to assets available to the Group. It is normally characterized by a maximum level of market risk related to the size of managed assets and the volatility of underlying commodities. The more flexible is an asset the higher is its extrinsic value that can be normally quantified as an option premium, linked to the price of an underlying commodity, volatility, time, interest rate. In order to protect the value of asset flexibility a business unit may transfer to a central entity part or the whole of asset flexibility or a portfolio of flexibilities and the central entity will hedge such flexibility on financial markets so to lock its value by monetizing it via derivatives. Hedging strategies adopted for asset-backed hedging are normally portfolio based, very dynamic and entail large use of proxies. Depending on the optimization model such strategies are continuously adjusting relevant hedging ratios buying and selling same financial products several times, since the underlying asset flexibility to be hedged is changing depending on price level, price volatility, time to delivery, etc. These derivatives may lead to gains as well as losses which in each case may be significant are accounted through profit and loss as they lack the hedge requirements provided by IFRS. However, we believe that the risks associated with those derivatives are mitigated by the natural hedge granted by the asset availability.

•

Portfolio management: is a portfolio based activity performed on a combination of underlying positions, such as physical assets (production plants, transmission infrastructures, storages, etc.), commercial assets (spot and forward short/medium/long term supply and sale contracts with physical delivery) and related financial derivatives. Normally, the target of a portfolio management activity is to optimize managed assets’ base by running quantitative models which, given production/consumption forecasts, prices scenarios and logistic flexibility/constraints, determine the optimal configuration in term of volume, price and flexibility for physical and commercial assets in the portfolio. Financial derivatives are then used in the portfolio management activity in order to manage the overall risk level associated to such optimal configuration within a set tolerance or to balance the combined risk-reward profile of the

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portfolio in line with company’s targets. Market risk associated to portfolio management is proportional to assets size and maturity and volatility/correlation of underlying markets. Financial derivatives are normally used to hedge the resulting net position, but they might hedge also single physical/commercial assets included in the portfolio. The activity is dynamic by nature, since optimization models are run periodically, even on a daily and infra-daily timescale, in order to rebalance optimal configuration in view of actual or forecast changes in volumes, prices and flexibility. As a consequence financial Derivatives are also managed dynamically, with a continuous adjustment that might lead to buy and sell the same financial product several times. These derivatives may lead to gains, as well as losses which in each case may be significant and are accounted through profit as they lack the hedge requirements provided by IFRS.

Pursuant to internal policy, all derivatives transactions concerning interest rates and foreign currencies are executed for risk reducing purposes, as described above. Only commodity derivatives can also be executed in the context of non-risk reducing operations and be consequently classified as Proprietary Trading, which is an ancillary activity not related to industrial assets that makes use of financial derivatives which are entered into with the objective to obtain an uncertain profit, if favorable market expectations occur.

Eni monitors on a daily basis that every activity involving derivatives is correctly classified according to the risk reducing taxonomy (i.e. back to back, flow hedging, asset-backed hedging or portfolio management), is directly or indirectly related to the hedged industrial assets and effectively optimizes the risk profile to which Eni is, or could be, exposed. When some derivatives fail to prove their risk reducing purpose, they are reclassified as Proprietary Trading. Provided that Proprietary Trading is segregated ex ante from other activities, its resulting market risk exposure is subject to specific limits expressed in terms of Stop Loss, VaR and notional. The aggregated notional amounts of non risk reducing derivatives at Group level are constantly benchmarked with the thresholds required by relevant international financial regulations.

Please refer to “Item 18 – note 38 of the Notes on Consolidated Financial Statements” for a qualitative and quantitative discussion of the Company’s exposure to market risks. Please also refer to “Item 18 – notes 15, 23, 28, 33 and 34 of the Notes on Consolidated Financial Statements” for details of the different derivatives owned by the Company in these markets.

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The following ADS fees are payable under the terms of the Deposit Agreement:

Service	Rate	By Whom Paid
(1) Issuance of ADSs (e.g., an issuance upon a deposit of Shares, upon a change in the ADS(s)-to-Share(s) ratio, or for any other reason), excluding issuances as a result of distributions described in paragraph (4) below.	Up to U.S. $5.00 per 100 ADSs (or fraction thereof) issued.	Person receiving ADSs.
(2) Cancellation of ADSs (e.g., a cancellation of ADSs for delivery of deposited Shares, upon a change in the ADS(s)-to-Share(s) ratio, or for any other reason).	Up to U.S. $5.00 per 100 ADSs (or fraction thereof) cancelled.	Person whose ADSs are being cancelled.
(3) Distribution of cash dividends or other cash distributions (e.g., upon a sale of rights and other entitlements).	Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held.	Person to whom the distribution is made.
(4) Distribution of ADSs pursuant to (i) stock dividends or other free stock distributions, or (ii) an exercise of rights to purchase additional ADSs.	Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held.	Person to whom the distribution is made.
(5) Distribution of securities other than ADSs or rights to purchase additional ADSs (e.g., spin-off shares).	Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held.	Person to whom the distribution is made.
(6) ADS Services.	Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held on the applicable record date(s) established by the Depositary.	Person holding ADSs on the applicable record date(s) established by the Depositary.

Direct and indirect payments by the Depositary

The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the program and the listing of Eni’s ADSs on the NYSE. These expenses are mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing U.S. SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities.

For the year 2017, the Depositary will reimburse to Eni up to $1,800,000 in connection with the above mentioned expenditures.

The Depositary has also agreed to waive certain standard fees associated with the administration of the ADR Program.

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PART II

Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

Item 15. CONTROLS AND PROCEDURES

Disclosure controls and procedures

In designing and evaluating the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”), the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and the Company’s management necessarily was required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.

It should be noted that the Company has investments in certain non-consolidated entities. As the Company does not control or manage these entities, its disclosure controls and procedures with respect to such entities are necessarily more limited than those it maintains with respect to its consolidated subsidiaries.

The Company’s management, with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Rule 13a-14(c) under the Exchange Act as of the end of the period covered by this Annual Report on Form 20-F. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rules 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of an internal control system may change over time.

The Internal Control Committee assists the Board of Directors in setting out the main principles for the internal control system so as to appropriately identify and adequately evaluate, manage, and monitor the main risks related to the Company and its subsidiaries, by laying down the compatibility criteria between said risks and sound corporate management. In addition, this Committee assesses, at least annually, the adequacy, effectiveness, and actual operations of the internal control system.

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The Company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (CoSO) in 2013. Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2017.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2017, has been audited by E&Y SpA, an independent registered public accounting firm, as stated in its report that is included on page F-2 of this Annual Report on Form 20-F.

Changes in Internal Control over Financial Reporting

There have not been changes in the Company’s Internal Control over Financial Reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 16. [RESERVED]

Item 16A. Board of Statutory Auditors financial expert

Eni’s Board of Statutory Auditors has determined that the five members of Eni’s Board of Statutory Auditors are “audit committee financial expert”: Rosalba Casiraghi, who is the Chairman of the Board, Enrico Maria Bignami, Paola Camagni, Andrea Parolini and Marco Seracini. All members are independent.

Item 16B. Code of Ethics

Eni adopted a Code of Ethics that applies to all Eni’s employees including Eni’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. Eni published its Code of Ethics on Eni’s website. It is accessible at www.eni.com, under the section Corporate Governance. A copy of this Code of Ethics is included as an exhibit to this Annual Report on Form 20-F.

Eni’s Code of Ethics contains ethical guidelines, describes corporate values and requires standards of business conduct and moral integrity. The ethical guidelines are designed to deter wrongdoing and to promote honest and ethical conduct, compliance with applicable laws and regulations and internal reporting of violations of the guidelines. The code affirms the principles of accounting transparency and internal control and endorses human rights and the issue of the sustainability of the business model.

Item 16C. Principal accountant fees and services

EY SpA has served as Eni principal independent public auditor for fiscal years 2017 and 2016 for which audited Consolidated Financial Statements appear in this Annual Report on Form 20-F.

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The following table shows total fees paid by Eni, its consolidated and non-consolidated subsidiaries and Eni’s share of fees incurred by joint ventures for services provided by Eni to its public auditors EY SpA and its respective member firms, for the years ended December 31, 2017 and 2016, respectively:

	Year ended December 31,
	2017		2016
	(€ thousand)
Audit fees		23,193		21,433
Audit-related fees		1,712		1,874
Tax fees
All other fees		12
Total		24,917		23,307

Audit fees include professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements, including the audit on the Company’s internal control over financial reporting.

Audit-related fees include assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit fees in this Item. The fees disclosed in this category mainly include audits of pension and benefit plans, merger and acquisition due diligence, audit and consultancy services rendered in connection with acquisition deals, certification services not provided for by law and regulations and consultations concerning financial accounting and reporting standards.

Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning. The fees disclosed in this category mainly include fees billed for the assistance with compliance and reporting of income and value-added taxes, assistance with assessment of new or changing tax regimes, tax consultancy in connection with merger and acquisition deals, services rendered in connection with tax refunds, assistance rendered on occasion of tax inspections and in connection with tax claims and recourses and assistance with assessing relevant rules, regulations and facts going into Eni correspondence with tax authorities.

All other fees include products and services provided by the principal accountant, other than the services reported in Audit fees, Audit-related fees and Tax fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations.

Pre-approval policies and procedures of the Internal Control Committee

The Board of Statutory Auditors has adopted a pre-approval policy for audit and non-audit services that set forth the procedures and the conditions pursuant to which services proposed to be performed by the principal auditors may be pre-approved. Such policy is applied to entities within the Eni Group which are either controlled or jointly controlled (directly or indirectly) by Eni SpA. According to this policy, permissible services within the other audit services category are pre-approved by the Board of Statutory Auditors. The Board of Statutory Auditors approval is required on a case-by-case basis for those requests regarding: (i) audit-related services; and (ii) non-audit services to be performed by the external auditors which are permissible under applicable rules and regulations. In such cases, the Company’s Internal Audit Department is charged with performing an initial assessment of each request to be submitted to the Board of Statutory Auditors for approval. The Internal Audit Department periodically reports to Eni’s Board of Statutory Auditors on the status of both pre-approved services and services approved on a case-by-case basis rendered by the external auditors.

During 2016, no audit-related fees, tax fees or other non-audit fees were approved by the Board of Statutory Auditors pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (c) of Rule 2-01 of Regulation S-X.

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Item 16D. Exemptions from the Listing Standards for Audit Committees

Making use of the exemption provided by Rule 10A-3(c)(3) for non-U.S. private issuers, Eni has identified the Board of Statutory Auditors as the body that, starting from June 1, 2005, performs the functions required by the U.S. SEC rules and the Sarbanes-Oxley Act to be carried out by the audit committees of non-U.S. companies listed on the NYSE (see “Item 6 – Board of Statutory Auditors” above).

Item 16E. Purchases of equity securities by the issuer and affiliated purchasers

The issuer and its affiliated purchasers have not executed any purchase of equity securities of the issuer since the end of 2014 and up to and as of the date of the 20-F filing for the year ended December 31, 2017.

Item 16F. Change in Registrant’s Certifying Accountant

Not applicable.

Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual

Corporate Governance. Eni’s Governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted. This model differs from the U.S. one-tier model in which the Board of Directors is the sole corporate body responsible for management, with an Audit Committee established within the Board performing monitoring activities. The following offers a description of the most significant differences between corporate governance practices adopted by U.S. domestic companies under the NYSE standards and those followed by Eni, including with reference to Corporate Governance Code for Italian listed companies, which Eni has adopted (hereinafter the Corporate Governance Code).

Independent Directors

NYSE standards. In accordance with NYSE standards, the majority of the members on the Boards of Directors of U.S. companies must be independent. A Director qualifies as independent when the Board affirmatively determines that such Director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a Director may not be deemed independent if he or she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he or she is an employee of the issuer or a partner of the Auditor). In addition, a Director cannot be considered independent in the three-year “cooling-off” period following the termination of any relationship that compromised a Director’s independence.

Eni standards. In Italy, the Consolidated Law on Financial Intermediation states that at least one of the Directors or two, if the Board is composed of more than seven members, must meet the independence requirements for Statutory Auditors of listed companies. In particular, a Director may not be deemed independent if he/she or an immediate family member has a relationship with the issuer, with its Directors or with the companies in the same group of the issuer that could influence the independence of judgement.

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Eni’s By-laws require that at least one Director – if the Board has no more than five members – or at least three Directors – if the Board is composed of more than five members – must satisfy the independence requirements. The Corporate Governance Code provides for additional independence requirements, recommending that the Board of Directors includes an adequate number of independent non-executive Directors. In particular, for issuers belonging to FTSE-MIB index of the Italian Stock Market, like Eni, the Corporate Governance Code recommends that at least one-third of the members of the Board of Directors shall be independent Directors. In any event, independent Directors shall not be fewer than two. Independence is defined as not being currently or recently involved in any direct or indirect relationship with the issuer or other parties associated with the issuer and that may influence his/her independent judgment. After the appointment of a Director who qualifies as independent and subsequently, upon the occurrence of circumstances affecting the independence requirements and in any case at least once a year, the Board of Directors assesses the independence of the Director. The Board of Statutory Auditors verifies the correct application of the criteria and procedures adopted by the Board of Directors to evaluate the independence of its members. The Board of Directors shall disclose the result of its evaluations, after the appointment, through a press release to the market and, subsequently, in the Annual Corporate Governance Report. In accordance with Eni’s By-laws, if a Director, who qualifies as independent, does not or no longer satisfies the independence requirements established by law, the Board declares the Director disqualified and provides for their substitution. Directors shall notify the Company if they should no longer satisfy the independence and integrity requirements or if cause for ineligibility or incompatibility should arise.

Meetings of non-executive Directors

NYSE standards. Non-executive Directors, including those who are not independent, must meet on a regular basis without the executive Directors. In addition, if the group of non-executive Directors includes Directors who are not independent, independent Directors should meet separately at least once a year.

Eni standards. Pursuant to Corporate Governance Code, independent Directors shall meet at least once a year without the other Directors. During 2017, Eni’s independent Directors had numerous opportunities to meet, informally, to hold discussions and exchange opinions.

Audit Committee

NYSE standards. Listed U.S. companies must have an Audit Committee that satisfies the requirements of Rule 10A-3 under the Securities Exchange Act of 1934 and that complies with the provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual.

Eni standards. At its Meeting of March 22, 2005, the Board of Directors, as permitted by the rules of the U.S. Securities and Exchange Commission applicable to foreign issuers listed on regulated U.S. markets, assigned to the Board of Statutory Auditors, effective from June 1, 2005 and within the limits set by Italian law, the functions specified and the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and the U.S. SEC rules (see “Item 6 – Board of Statutory Auditors” earlier). Under Section 303A.07 of the NYSE Listed Company Manual, audit committees of U.S. companies have additional functions and duties which are not mandatory for non-U.S. private issuers and which are therefore not included in the list of functions reported in “Item 6 – Board of Statutory Auditors”.

Nominating/Corporate Governance Committee

NYSE standards. U.S. listed companies must have a Nominating/Corporate Governance Committee (or equivalent body) composed entirely of independent Directors whose functions include, but are not limited to, selecting qualified candidates for the office of Director for submission to the Shareholders’ Meeting, as well as developing and recommending corporate governance guidelines to the Board of Directors. This provision is not binding for non-U.S. private issuers.

Eni standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a nomination committee the majority of whose members shall be independent Directors. The Nomination Committee of Eni is made up of three to four Directors, a majority of whom shall be independent in accordance with the recommendations of the Corporate Governance Code1. On

(1)

The Committee is currently made up of four Directors, three of whom are independent.

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April 13, 2017, the Board of Directors of Eni established the Nomination Committee, chaired by Diva Moriani (independent Director) and composed of Andrea Gemma (independent Director), Fabrizio Pagani (non-executive Director) and Domenico Livio Trombone (independent Director). Further details on this Committee are reported in the Item 6.

Remuneration Committee

NYSE standards. U.S. listed companies must have a Remuneration Committee composed entirely of independent Directors who must satisfy the independence requirements provided for its members. The Remuneration Committee must have a written charter that addresses the Committee’s purpose and responsibilities within the limit set forth by the listing rules. The Remuneration Committee may, in its sole discretion, retain or obtain the advice of a compensation consultant, independent legal counsel or other adviser and shall be directly responsible for the appointment, compensation and oversight of the work of any compensation consultant, independent legal counsel or other adviser retained by it. These provisions are not binding for non-U.S. private issuers.

Eni standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a Remuneration Committee made up of three to four non-executive Directors, all of whom shall be independent or, alternatively, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. At least one of the Committee’s members shall have an adequate understanding of and experience in financial matters or compensation policies. First established by the Board of Directors in 1996, the Remuneration Committee is currently chaired by Director Andrea Gemma. The other members include directors Pietro Guindani, Alessandro Lorenzi and Diva Moriani. The composition and functions of the Remuneration Committee are outlined in the committee charter (“Rules”) available on the Company’s website (https://www.eni.com/docs/en_IT/enicom/company/governance/rules-of-the-remuneration-committee.pdf). Further details on this Committee are reported in the Item 6.

Code of Business Conduct and Ethics

NYSE standards. The NYSE listing standards require each U.S. listed company to adopt a Code of Business Conduct and Ethics for its Directors, Officers and employees, and to promptly disclose any waivers of the code for Directors or Executive Officers.

Eni standards. At its Meetings of December 15, 2003 and January 28, 2004, the Board of Directors of Eni approved an organizational, management and control model pursuant to Italian Legislative Decree No. 231 of 2001 (hereinafter “Model 231”) and established the associated Eni Watch Structure. Moreover, after subsequent approvals of the updates to Model 231 in response to changes in the Italian legislation governing the matter and in the Company organizational structures, on March 14, 2008, the Board of Directors approved the overall revision of Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of Eni’s Code of Conduct of 1998. Most recently, the Board of Directors, in its meeting held on November 23, 2017, approved the updating of Model 231 and Eni’s Code of Ethics. The CEO is supported in this activity by the “Technical Committee 231”, consisting of members from the Company’s Legal Affairs, Integrated Compliance Department, Human Resources and Organization and Internal Audit units. Eni’s Code of Ethics, which is an integral part of Model 231, sets out a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all its business activities are conducted in compliance with the law, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all the stakeholders with whom Eni interacts on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. All Eni personnel, without exception or distinction, starting with Directors, senior management and members of the Company’s bodies, as also required under U.S. SEC rules and the Sarbanes-Oxley Act, are committed to observing and enforcing the principles set out in the Code of Ethics in the performance of their functions and duties. The synergies between the Code of Ethics and Model 231 are underscored by the designation of the Eni Watch Structure, established under Model 231, as the Guarantor of the Code of Ethics. The Guarantor of the Code of Ethics acts to ensure the protection and promotion of the above principles. Every six months, it presents a report on the implementation of the Code to the Control and Risk Committee, to the Board of Statutory Auditors and to the Chairman and the CEO, who in turn reports on this to the Board of Directors. At present, the Watch

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of
Eni S.p.A.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Eni S.p.A. (the Company) as of December 31, 2017 and 2016, the related consolidated profit and loss accounts and consolidated statements of comprehensive income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated April 6, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young S.p.A.

We have served as the Company’s auditor since 2010.

Rome, Italy

April 6, 2018

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of
Eni S.p.A.

Opinion on Internal Control over Financial Reporting

We have audited Eni S.p.A.’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Eni S.p.A. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2017 and 2016, the related consolidated profit and loss accounts and consolidated statements of comprehensive income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”) and our report dated April 6, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young S.p.A.

Rome, Italy

April 6, 2018

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CONSOLIDATED BALANCE SHEET
(euro million)

		December 31, 2017				December 31, 2016
	Note	Total amount		of which with related parties		Total amount		of which with related parties
ASSETS
Current assets
Cash and cash equivalents	(8)		7,363				5,674
Financial assets held for trading	(9)		6,012				6,166
Financial assets available for sale	(10)		207				238
Trade and other receivables	(11)		15,737		907		17,593		1,100
Inventories	(12)		4,621				4,637
Current tax assets	(13)		191				383
Other current tax assets	(14)		729				689
Other current assets	(15) (34)		1,573		30		2,591		57
			36,433				37,971
Non-current assets
Property, plant and equipment	(16)		63,158				70,793
Inventory – compulsory stock	(17)		1,283				1,184
Intangible assets	(18)		2,925				3,269
Equity-accounted investments	(20)		3,511				4,040
Other investments	(20)		219				276
Other financial assets	(21)		1,675		1,214		1,860		1,349
Deferred tax assets	(22)		4,078				3,790
Other non-current assets	(23) (34)		1,323		46		1,348		13
			78,172				86,560
Assets held for sale	(35)		323				14
TOTAL ASSETS			114,928				124,545
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	(24)		2,242		164		3,396		191
Current portion of long-term debt	(29)		2,286				3,279
Trade and other payables	(25)		16,748		2,808		16,703		2,289
Income tax payable	(26)		472				426
Other tax payable	(27)		1,472				1,293
Other current liabilities	(28) (34)		1,515		60		2,599		88
			24,735				27,696
Non-current liabilities
Long-term debt	(29)		20,179				20,564
Provisions for contingencies	(30)		13,447				13,896
Provisions for employee benefits	(31)		1,022				868
Deferred tax liabilities	(32)		5,900				6,667
Other non-current liabilities	(33) (34)		1,479		23		1,768		23
			42,027				43,763
Liabilities directly associated with assets held for sale	(35)		87
TOTAL LIABILITIES			66,849				71,459
SHAREHOLDERS' EQUITY	(36)
Non-controlling interest			49				49
Eni shareholders' equity
Share capital			4,005				4,005
Reserve related to cash flow hedging derivatives net of tax effect			183				189
Other reserves			42,490				52,329
Treasury shares			(581)				(581)
Interim dividend			(1,441)				(1,441)
Net profit (loss)			3,374				(1,464)
Total Eni shareholders' equity			48,030				53,037
TOTAL SHAREHOLDERS' EQUITY			48,079				53,086
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			114,928				124,545

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CONSOLIDATED PROFIT AND LOSS ACCOUNT
(euro million except as otherwise stated)


			2017				2016				2015
	Note		Total amount		of which with related parties		Total amount		of which with related parties		Total amount		of which with related parties
REVENUES		(39)
Net sales from operations				66,919		1,567		55,762		1,238		72,286		1,342
Other income and revenues				4,058		41		931		74		1,252		69
				70,977				56,693				73,538
COSTS		(40)
Purchases, services and other				(52,461)		(9,164)		(44,124)		(8,212)		(56,848)		(6,882)
Payroll and related costs				(2,951)		(34)		(2,994)		(24)		(3,119)		(55)
Other operating (expense) income				(32)		331		16		247		(485)		96
Depreciation and amortization				(7,483)				(7,559)				(8,940)
Net (impairments) reversals				225				475				(6,534)
Write-off of tangible and intangible assets				(263)				(350)				(688)
OPERATING PROFIT (LOSS)				8,012				2,157				(3,076)
FINANCE INCOME (EXPENSE)		(41)
Finance income				3,924		191		5,850		157		8,635		83
Finance expense				(5,886)		(4)		(6,232)		(145)		(10,104)		(50)
Net Finance income (expense) from financial assets held for trading				(111)				(21)				3
Derivatives financial instruments				837				(482)		27		160
				(1,236)				(885)				(1,306)
INCOME (EXPENSE) FROM INVESTMENTS		(42)
Share of profit (loss) from equity-accounted investments				(267)				(326)				(471)
Other gain (loss) from investments				335				(54)				576
				68				(380)				105
PROFIT (LOSS) BEFORE INCOME TAXES				6,844				892				(4,277)
Income taxes		(43)		(3,467)				(1,936)				(3,122)
Net profit (loss) for the year - Continuing operations				3,377				(1,044)				(7,399)
Net profit (loss) for the year - Discontinued operations								(413)				(1,974)		142
Net profit (loss) for the year				3,377				(1,457)				(9,373)
Attributable to Eni
– continuing operations				3,374				(1,051)				(7,952)
– discontinued operations								(413)				(826)
				3,374				(1,464)				(8,778)
Attributable to non-controlling interest		(36)
– continuing operations				3				7				553
– discontinued operations												(1,148)
				3				7				(595)
Earnings per share attributable to Eni (€ per share)		(44)
Basic				0.94				(0.41)				(2.44)
Diluted				0.94				(0.41)				(2.44)
Earnings per share attributable to Eni – Continuing operations (€ per share)		(44)
Basic				0.94				(0.29)				(2.21)
Diluted				0.94				(0.29)				(2.21)

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(euro million)

		Eni shareholders’ equity
	Note	Share capital		Legal reserve of Eni SpA		Reserve for treasury shares		Reserve related to the fair value of cash flow hedging derivatives net of the tax effect		Reserve related to the fair value of available- for-sale financial instruments net of the tax effect		Reserve for defined benefit plans net of the tax effect		Other reserves		Cumulative currency translation differences		Treasury shares		Retained earnings		Interim dividend		Net profit (loss) for the year		Other comprehensive income (loss) related to discontinued operations		Total		Non- controlling interest		Total shareholders’ equity
Balance at December 31, 2016	(36)		4,005		959		581		189		4		(112)		211		10,319		(581)		40,367		(1,441)		(1,464)				53,037		49		53,086
Net profit for the year																									3,374				3,374		3		3,377
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss in later periods
Remeasurements of defined benefit plans net of tax effect	(36)												(4)																(4)				(4)
													(4)																(4)				(4)
Items that may be reclassified to profit or loss in later periods
Currency translation differences	(36)												2				(5,575)												(5,573)				(5,573)
Change of the fair value of other available-for-sale financial instruments net of tax effect	(36)										(4)																		(4)				(4)
Change of the fair value of cash flow hedge derivatives net of tax effect	(36)								(6)																				(6)				(6)
Share of “Other comprehensive income” on equity-accounted entities	(36)														69														69				69
									(6)		(4)		2		69		(5,575)												(5,514)				(5,514)
Total comprehensive income (loss) of the year									(6)		(4)		(2)		69		(5,575)								3,374				(2,144)		3		(2,141)
Transactions with shareholders
Dividend distribution of Eni SpA (€0.40 per share in settlement of 2016 interim dividend of €0.40 per share)	(36)																						1,441		(2,881)				(1,440)				(1,440)
Interim dividend distribution of Eni SpA (€0.40 per share)	(36)																						(1,441)						(1,441)				(1,441)
Dividend distribution of other companies																															(3)		(3)
Allocation of 2016 net loss																					(4,345)				4,345
																					(4,345)				1,464				(2,881)		(3)		(2,884)
Other changes in shareholders’ equity
Other changes																	74				(56)								18				18
																	74				(56)								18				18
Balance at December 31, 2017	(36)		4,005		959		581		183				(114)		280		4,818		(581)		35,966		(1,441)		3,374				48,030		49		48,079
Balance at December 31, 2015	(36)		4,005		959		581		(474)		8		(101)		180		9,129		(581)		51,985		(1,440)		(8,778)		20		55,493		1,916		57,409
Net profit (loss) for the year																									(1,464)				(1,464)		7		(1,457)
Other items of comprehensive income (loss)
Items that are not reclassified to profit or (loss) in later periods
Remeasurements of defined benefit plans net of tax effect	(36)												(19)																(19)				(19)
													(19)																(19)				(19)
Items that may be reclassified to profit or (loss) in later periods
Currency translation differences	(36)												8				1,190												1,198				1,198
Change of the fair value of other available-for-sale financial instruments net of tax effect	(36)										(4)																		(4)				(4)
Change of the fair value of cash flow hedge derivatives net of tax effect	(36)								663																				663				663
Share of “Other comprehensive income” on equity-accounted entities	(36)														32														32				32
									663		(4)		8		32		1,190												1,889				1,889
Total comprehensive income (loss) of the year									663		(4)		(11)		32		1,190								(1,464)				406		7		413
Transactions with shareholders
Dividend distribution of Eni SpA (€0.40 per share in settlement of 2015 interim dividend of €0.40 per share)	(36)																				(1,028)		1,440		(1,852)				(1,440)				(1,440)
Interim dividend distribution of Eni SpA (€0.40 per share)	(36)																						(1,441)						(1,441)				(1,441)
Dividend distribution of other companies																															(4)		(4)
Allocation of 2015 net loss																					(10,630)				10,630
																					(11,658)		(1)		8,778				(2,881)		(4)		(2,885)
Other changes in shareholders’ equity
Exclusion from the scope of consolidation of Saipem group following the sale of the control																															(1,872)		(1,872)
Reclassification to profit and loss account of amounts previously recognized in other comprehensive income related to Saipem																					(8)						(20)		(28)				(28)
Other changes															(1)						48								47		2		49
															(1)						40						(20)		19		(1,870)		(1,851)
Balance at December 31, 2016	(36)		4,005		959		581		189		4		(112)		211		10,319		(581)		40,367		(1,441)		(1,464)				53,037		49		53,086

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued)
(euro million)

	Eni shareholders’ equity
	Share capital		Legal reserve of Eni SpA		Reserve for treasury shares		Reserve related to the fair value of cash flow hedging derivatives net of the tax effect		Reserve related to the fair value of available- for-sale financial instruments net of the tax effect		Reserve for defined benefit plans net of the tax effect		Other reserves		Cumulative currency translation differences		Treasury shares		Retained earnings		Interim dividend		Net profit (loss) for the year		Other comprehensive income (loss) related to discontinued operations		Total		Non- controlling interest		Total shareholders’ equity
Balance at December 31, 2014		4,005		959		6,201		(284)		11		(122)		207		4,439		(581)		49,068		(2,020)		1,303				63,186		2,455		65,641
Net loss for the year																								(8,778)				(8,778)		(595)		(9,373)
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss in later periods
Remeasurements of defined benefit plans net of tax effect												14																14		1		15
Reclassification of ’’Other comprehensive loss" related to discontinued operations												8														(8)
												22														(8)		14		1		15
Items that may be reclassified to profit or loss in later periods
Currency translation differences												(1)				4,722				54								4,775		62		4,837
Change of the fair value of other available-for-sale financial instruments net of tax effect										(3)																		(3)				(3)
Change of the fair value of cash flow hedge derivatives net of tax effect								(194)																				(194)		3		(191)
Share of “Other comprehensive income” on equity-accounted entities														(9)														(9)				(9)
Reclassification of ’’Other comprehensive income" related to discontinued operations								4								(32)										28
								(190)		(3)		(1)		(9)		4,690				54						28		4,569		65		4,634
Total comprehensive income (loss) of the year								(190)		(3)		21		(9)		4,690				54				(8,778)		20		(4,195)		(529)		(4,724)
Transactions with shareholders
Dividend distribution of Eni SpA (€0.56 per share in settlement of 2014 interim dividend of €0.56 per share)																						2,020		(4,037)				(2,017)				(2,017)
Interim dividend distribution of Eni SpA (€0.40 per share)																						(1,440)						(1,440)				(1,440)
Dividend distribution of other companies																														(21)		(21)
Allocation of 2014 net loss																				(2,734)				2,734
Payments and reimbursements by/to minority shareholders																														1		1
																				(2,734)		580		(1,303)				(3,457)		(20)		(3,477)
Other changes in shareholders’ equity
Elimination of intercompany profit between companies with different Group interest																				(28)								(28)		28
Exclusion from the scope of consolidation of non-significant companies and changes in non-controlling interests																				(7)								(7)		(10)		(17)
Reclassification of the reserve for treasury shares						(5,620)														5,620
Other changes														(18)						12								(6)		(8)		(14)
						(5,620)								(18)						5,597								(41)		10		(31)
Balance at December 31, 2015		4,005		959		581		(474)		8		(101)		180		9,129		(581)		51,985		(1,440)		(8,778)		20		55,493		1,916		57,409

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CONSOLIDATED STATEMENT OF CASH FLOWS
(euro million)


	Note		2017		2016		2015
Net profit (loss) of the year – Continuing operations				3,377		(1,044)		(7,399)
Adjustments to reconcile net profit (loss) to net cash provided by operating activities
Depreciation and amortization		(40)		7,483		7,559		8,940
Net Impairments (reversals)		(40)		(225)		(475)		6,534
Write-off of tangible and intangible assets		(40)		263		350		688
Share of (profit) loss of equity-accounted investments		(42)		267		326		471
Gain on disposal of assets, net				(3,446)		(48)		(577)
Dividend income		(42)		(205)		(143)		(402)
Interest income				(283)		(209)		(164)
Interest expense				671		645		659
Income taxes		(43)		3,467		1,936		3,122
Other changes				894		(9)		586
Changes in working capital:
- inventories			(346)		(273)		1,638
- trade receivables			657		1,286		4,944
- trade payables			284		1,495		(2,342)
- provisions for contingencies			96		(1,043)		43
- other assets and liabilities			749		647		498
Cash flow from changes in working capital				1,440		2,112		4,781
Net change in the provisions for employee benefits				38		22		(3)
Dividends received				291		212		545
Interest received				104		160		81
Interest paid				(582)		(780)		(692)
Income taxes paid, net of tax receivables received				(3,437)		(2,941)		(4,295)
Net cash provided by operating activities – Continuing operations				10,117		7,673		12,875
Net cash provided by operating activities – Discontinued operations								(1,226)
Net cash provided by operating activities				10,117		7,673		11,649
– of which with related parties		(47)		(2,843)		(3,749)		(3,966)
Investing activities:
- tangible assets		(16)		(8,490)		(9,067)		(11,177)
- intangible assets		(18)		(191)		(113)		(125)
- investments		(20)		(510)		(1,164)		(228)
- securities				(316)		(1,336)		(201)
- financing receivables				(657)		(1,208)		(1,103)
- change in payables in relation to investing activities and capitalized depreciation				152		(8)		(1,058)
Cash flow from investing activities				(10,012)		(12,896)		(13,892)
Disposals:
- tangible assets				2,745		19		427
- intangible assets				2				32
- consolidated subsidiaries and businesses net of cash and cash equivalent disposed of		(37)		2,662		(362)		73
- tax on disposals				(436)
- investments				482		508		1,726
- securities				224		20		18
- financing receivables				999		8,063		533
- change in receivables in relation to disposals				(434)		205		160
Cash flow from disposals				6,244		8,453		2,969
Net cash used in investing activities				(3,768)		(4,443)		(10,923)
– of which with related parties		(47)		(3,115)		3,752		(1,583)

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Notes on Consolidated Financial Statements

1 Basis of preparation

The Consolidated Financial Statements of the Eni Group have been prepared in accordance with International Financial Reporting Standards (IFRS)1 as issued by the International Accounting Standards Board (IASB). Oil and natural gas exploration and production activity is accounted for in accordance with internationally accepted accounting standards taking into account the requirements in IFRSs that apply.

The Consolidated Financial Statements have been prepared under the historical cost convention, taking into account, where appropriate, value adjustments, except for certain items that under IFRSs must be measured at fair value as described in the note 3 “Significant accounting policies”.

The 2017 Consolidated Financial Statements included in the Annual Report on Form 20-F, approved by the Eni’s Board of Directors on April 5, 2018, were audited by the external auditor Ernst & Young SpA. The external auditor of Eni SpA, as the main external auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other external auditors, Ernst & Young SpA takes the responsibility of their work.

The Consolidated Financial Statements are presented in euro and all values are rounded to the nearest million euros (€ million).

2 Principles of consolidation

Subsidiaries

The Consolidated Financial Statements comprise the financial statements of the parent Company Eni SpA and those of its subsidiaries, being those entities over which the Company has control, either directly or indirectly, through exposure or rights to their variable returns and the ability to affect those returns through its power over the investees. To have power over an investee, the investor must have existing rights that give it the current ability to direct the relevant activities of the investee, i.e. the activities that significantly affect the investee’s returns.

For entities acting as sole-operator in the management of oil&gas contracts on behalf of companies participating in a joint project, the activities are financed proportionally based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenues and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognized directly in the financial statements of the companies involved based on their own share. Some subsidiaries are not consolidated because they are immaterial, either individually or in the aggregate; this exclusion has not produced significant2 effects on the Consolidated Financial Statements3.

Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases. 100% of assets, liabilities, income and expenses of consolidated subsidiaries are combined with those of the parent in the Consolidated Financial Statements; the net book value of these subsidiaries is eliminated against the corresponding portion of the shareholders’ equity. Equity and net profit attributable to non-controlling interests are included in specific line items of equity and profit and loss account.

When the proportion of the equity held by non-controlling interests changes, any difference between the consideration paid/received and the amount by which the non-controlling interests are adjusted is

(1)

IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations prepared by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC).

(2)

According to the requirements of the Conceptual Framework for Financial Reporting, “information is material if omitting it or misstating it could influence decisions that users make on the basis of financial information about a specific reporting entity”.

(3)

Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”.

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attributed to the Group shareholders’ equity. Conversely, the sale of equity interests with loss of control determines the recognition in the profit and loss account of: (i) any gain/loss calculated as the difference between the consideration received and the corresponding transferred portion of equity; (ii) any gain or loss recognized as a result of the re-measurement of any investment retained in the former subsidiary to its fair value; and (iii) any amount related to the former subsidiary previously recognized in other comprehensive income which can be reclassified subsequently to the profit and loss account4. Any investment retained in the former subsidiary is recognized at its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria.

Interests in joint arrangements

A joint arrangement is an arrangement of which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.

A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Investments in joint ventures are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.

A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have enforceable rights to the assets, and enforceable obligations for the liabilities, relating to the arrangement. Judgment is required in assessing whether a joint arrangement creates enforceable rights and obligations; this assessment is made considering the design and purpose of the joint arrangement, the terms of the contractual arrangements, as well as any other facts and circumstances that are relevant for this assessment. In the Consolidated Financial Statements the Eni’s share of the assets/liabilities and revenues/expenses of joint operations is recognized upon rights and obligations to the arrangements.

After the initial recognition, the assets/liabilities and revenues/expenses of the joint operations are measured in accordance with the measurement criteria applicable to each case. Immaterial joint operations are accounted for using the equity method or, if this does not result in a misrepresentation of the Company’s financial position and performance, at cost net of any impairment losses.

Interests in associates

An associate is an entity over which Eni has significant influence, that is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control of those policies. Investments in associates are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.

Consolidated companies’ financial statements are audited by external auditors who audit also the information required for the preparation of the Consolidated Financial Statements.

The equity method of accounting

Investments in unconsolidated subsidiaries, joint ventures and associates are accounted for using the equity method5.

Under the equity method, investments are initially recognized at cost, allocating, similarly to business combinations procedures, the purchase price of the investment to the investee’s assets/liabilities; if this allocation is provisionally recognized at initial recognition, it can be retrospectively adjusted within one year from the date of initial recognition, to reflect new information obtained about facts and circumstances that existed at the date of initial recognition. Subsequently, the carrying amount is adjusted to reflect: (i) the investor’s share of the profit or loss of the investee after the date of acquisition; and (ii) the investor’s share of the investee’s other comprehensive income. Changes in the net assets of an equity-accounted investee, not arising from the investee’s profit or loss or other comprehensive income, are recognized in the investor’s profit and loss account, as they basically represent a gain or loss from a disposal of an interest in the

(4)

Conversely, any amount related to the former subsidiary previously recognized in other comprehensive income, which cannot be reclassified subsequently to the profit and loss account, are reclassified in another item of equity.

(5)

In the case of step acquisition of significant influence (or joint control), the investment is recognized, at the acquisition date of significant influence (joint control), at the amount deriving from the use of the equity method assuming the adoption of this method since initial acquisition; the “step-up” of the carrying amount of interests owned before the acquisition of significant influence (joint control) is taken to equity.

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investee’s equity. Distributions received from an equity-accounted investee reduce the carrying amount of the investment. In applying the equity method, consolidation adjustments are considered (see also the accounting policy for “Subsidiaries”). When there is objective evidence of impairment (see also the accounting policy for “Current financial assets”), the recoverability is tested by comparing the carrying amount and the related recoverable amount determined by adopting the criteria indicated in the accounting policy for “Property, plant and equipment”. The losses arising from the application of the equity method exceeding the carrying amount of the investment, recognized in the profit and loss account within “Income (expense) from investments”, are allocated to any financial receivable from the investee for which settlement is neither planned nor likely to occur in the foreseeable future (the so-called long-term interests) and which is, in substance, an extension of the investment in the investee.

Immaterial subsidiaries, joint ventures and associates are accounted for at cost, net of any impairment losses, if this does not result in a misrepresentation of the Group financial position and performance. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognized in the profit and loss account within “Other gain (loss) from investments”. The reversal cannot exceed the previously recognized impairment losses.

The sale of equity interests with loss of joint control or significant influence over the investee determines the recognition in the profit and loss account of: (i) any gain/loss calculated as the difference between the consideration received and the corresponding transferred share; (ii) any gain or loss recognized as a result of the re-measurement of any investment retained in the former joint venture/associate to its fair value6; and (iii) any amount related to the former joint venture/associate previously recognized in other comprehensive income which can be reclassified subsequently to profit and loss account7. Any investment retained in the former joint venture/associate is recognized at its fair value at the date when joint control or significant influence is lost and shall be accounted for in accordance with the applicable measurement criteria.

The investor’s share of losses of an equity-accounted investee, that exceeds the carrying amount of the investment, is recognized in a specific provision only to the extent the investor is required to fulfill legal or constructive obligations of the investee or to fund its losses.

Business combinations

Business combinations are recognized by applying the acquisition method. The consideration transferred in a business combination is measured at the acquisition date and is the sum of the acquisition-date fair values of the assets transferred, the liabilities incurred, as well as any equity instruments issued by the acquirer. Acquisition-related costs are accounted for as expenses when they are incurred.

At the acquisition date, the acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values8, unless another measurement basis is required by IFRSs. The excess of the consideration transferred over the Group’s share of the net of the acquisition-date amounts of the identifiable assets acquired and liabilities assumed is recognized as goodwill; a gain from a bargain purchase is recognized in the profit and loss account.

Any non-controlling interest is measured as the proportionate share in the recognized amounts of the acquiree’s identifiable net assets at the acquisition date (partial goodwill method); as an alternative, it is allowed the recognition of the entire amount of goodwill deriving from the acquisition, including also the goodwill attributable to non-controlling interests (full goodwill method). In the last case, non-controlling interests are measured at their fair value, which therefore includes the goodwill attributable to them9. The choice of measurement basis of goodwill (partial goodwill method vs. full goodwill method) is made on a transaction-by-transaction basis.

(6)

If the retained investment continues to be accounted for using the equity method, no remeasurement to fair value is recognized in the profit and loss account.

(7)

Conversely, any amount related to the former joint venture/associate previously recognized in other comprehensive income, which cannot be reclassified subsequently to the profit and loss account, are reclassified in another item of equity.

(8)

Fair value measurement principles are described below in the accounting policy for “Fair value measurements”.

(9)

The choice between partial goodwill and full goodwill method is made also for business combinations resulting in the recognition of a gain on bargain purchase in the profit and loss account.

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In a business combination achieved in stages, the purchase price is determined by summing the fair value of previously held equity interests in the acquiree and the consideration transferred for the acquisition of control; the previously held equity interests are re-measured at their acquisition-date fair value and the resulting gain or loss, if any, is recognized in the profit and loss account. Furthermore, on obtaining control, any amount of the acquiree previously recognized in other comprehensive income is charged to the profit and loss account, or in another item of equity when the amount cannot be reclassified to the profit and loss account.

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognized at the acquisition date shall be retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date.

The acquisition of interests in a joint operation in which the activity constitutes a business is recognized applying the relevant principles for business combinations.

Intragroup transactions

All balances and transactions between consolidated companies, including unrealized profits arising from such transactions, have been eliminated.

Unrealized profits arising from transactions between the Group and its equity-accounted entities are eliminated to the extent of the Group’s interest in the equity-accounted entity. In both cases, unrealized losses are not eliminated when they provide evidence of an impairment loss of the asset transferred.

Foreign currency translation

The financial statements of foreign operations having a functional currency other than the euro, that represents the parent’s functional currency, are translated into euro using the spot exchange rates on the balance sheet date for assets and liabilities, historical exchange rates for equity and average exchange rates for the profit and loss account and the statement of cash flows (source: Reuters — WMR).

The cumulative amount of the resulting translation differences is presented in the separate component of the Group shareholders’ equity “Cumulative currency translation differences”10. Cumulative exchange differences are reclassified to the profit and loss account when the entity disposes the entire interest in a foreign operation or when the partial disposal involves the loss of control, joint control or significant influence of a foreign operation. On a partial disposal that does not involve loss of control of a subsidiary that includes a foreign operation, the proportionate share of the cumulative exchange differences is reattributed to the non-controlling interests in that foreign operation. On a partial disposal that does not involve loss of joint control or significant influence, the proportionate share of the cumulative exchange differences is reclassified to the profit and loss account. The repayment of share capital made by a subsidiary having a functional currency other than the euro, without a change in the ownership interest, implies that the proportionate share of the cumulative amount of exchange differences relating to the subsidiary is reclassified to the profit and loss account.

The financial statements of foreign operations which are translated into euro are denominated in the foreign operations’ functional currencies which generally is the U.S. dollar.

(10)

When the foreign subsidiary is partially owned, the cumulative exchange differences, that are attributable to the non-controlling interests, are allocated to and recognized as part of “Non-controlling interest”.

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The main foreign exchange rates used to translate the financial statements into the parent’s functional currency are indicated below:

(currency amount for €1)	Annual average exchange rate 2017		Exchange rate at December 31, 2017		Annual average exchange rate 2016		Exchange rate at December 31, 2016		Annual average exchange rate 2015		Exchange rate at December 31, 2015
U.S. Dollar		1.13		1.20		1.11		1.05		1.11		1.09
Pound Sterling		0.88		0.89		0.82		0.86		0.73		0.73
Norwegian Krone		9.33		9.83		9.29		9.09		8.95		9.60
Australian Dollar		1.47		1.53		1.49		1.46		1.48		1.49

3 Significant accounting policies

The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below.

Oil and natural gas exploration, appraisal, development and production expenditure

Acquisition of exploration rights

Costs incurred for the acquisition of exploration rights (or their extension) are initially capitalized within the line item “Intangible assets” as “exploration rights — unproved” pending determination of whether the exploration and appraisal activities in the reference areas are successful or not. Unproved exploration rights are not amortized, but reviewed to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review is based on the confirmation of the commitment of the Company to continue the exploration activities and on the analysis of facts and circumstances that can show the existence of uncertainties related to the recoverability of the carrying amount. If no future activity is planned, the carrying amount of the related exploration rights is recognized in the profit and loss account as write-off. Lower value exploration rights are pooled and amortized on a straight-line basis over the estimated period of exploration. In the event of a discovery of proved reserves (i.e. upon recognition of proved reserves and internal approval for development), the carrying amount of the related unproved exploration rights is reclassified to “proved exploration rights”, within the line item “Intangible assets”. When the reclassification is recognized, as well as whether there is any indication of impairment, the carrying amount of exploration rights to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration rights are amortized according to the unit of production method (the so-called UOP method, described in the accounting policy for “UOP depreciation, depletion and amortization”).

Acquisition of mineral interests

Costs incurred for the acquisition of mineral interests are capitalized in connection with the assets acquired (such as exploration potential, possible and probable reserves and proved reserves). When the acquisition is related to a set of exploration potential and reserves, the cost is allocated to the different assets acquired based on their expected discounted cash flows.

Acquired exploration potential is measured under the criteria indicated in the accounting policy for “Acquisition of exploration rights”. Costs associated with proved reserves are amortized on a UOP basis (see the accounting policy for “UOP depreciation, depletion and amortization”). Expenditure associated with possible and probable reserves (unproved mineral interests) is not amortized until classified as proved reserves; in case of a negative result, it is written-off.

Exploration and appraisal expenditure

Geological and geophysical exploration costs are recognized as an expense as incurred.

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Costs directly associated with an exploration well are initially recognized within tangible assets in progress, as “exploration and appraisal costs — unproved” (exploration wells in progress) until the drilling of the well is completed and can continue to be capitalized in the following 12-month period pending the evaluation of drilling results (suspended exploration wells). If, at the end of this period, it is ascertained that the result is negative (no hydrocarbon found) or that the discovery is not sufficiently significant to justify the development, the wells are declared dry/unsuccessful and the related costs are written-off. Conversely, these costs continue to be capitalized if and until: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well, and (ii) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project; on the contrary, the capitalized costs are recognized in the profit and loss account as write-off. Analogous recognition criteria are adopted for the costs related to the appraisal activity. When proved reserves of oil and/or natural gas are determined, the relevant expenditure recognized as unproved is reclassified to proved exploration and appraisal costs, within tangible assets in progress. When the reclassification is recognized, as well as whether there is any indication of impairment, the carrying amount of the costs to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration and appraisal costs are depreciated according to the UOP method (see the accounting policy for “UOP depreciation, depletion and amortization”).

Development expenditure

Development expenditure, including the costs related to unsuccessful and damaged development wells, are capitalized as “Tangible asset in progress — proved”. Development expenditures are costs incurred to obtain access to proved reserves and provide facilities to extract, gather and store the oil&gas. They are amortized, from the commencement of production, generally on a UOP basis (see the accounting policy for “UOP depreciation, depletion and amortization”). When development projects are unfeasible/not carried on, the related costs are written-off when it is decided to abandon the project. Development costs are tested for impairment in accordance with the criteria described in the accounting policy for “Property, plant and equipment”.

UOP depreciation, depletion and amortization

Proved oil&gas assets are depreciated generally under the UOP method, as their useful life is closely related to the availability of oil&gas reserves, by applying, to the depreciable amounts at the end of each quarter a rate representing the ratio between the volumes extracted during the quarter and the reserves existing at the end of the quarter, increased by the volumes extracted during the quarter. This method is applied with reference to the smallest aggregate representing a direct correlation between expenditures to be depreciated and oil&gas reserves. Proved exploration rights and acquired proved mineral interests are amortized over proved reserves; proved exploration and appraisal costs and development expenditure are depreciated over proved developed reserves.

Production costs

Production costs are those costs incurred to operate and maintain wells and field equipment and are recognized as an expense as incurred.

Production Sharing Agreements and buy-back contracts

Oil and gas reserves related to Production Sharing Agreements and buy-back contracts are determined on the basis of contractual terms related to the recovery of the contractor’s costs to undertake and finance exploration, development and production activities at its own risk (Cost Oil) and the Company’s stipulated share of the production remaining after such cost recovery (Profit Oil). Revenues from the sale of the production entitlements against both Cost Oil and Profit Oil are accounted for on an accrual basis, whilst exploration, development and production costs are accounted for according to the above-mentioned accounting policies. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons that corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense.

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Decommissioning and restoration liabilities

Costs expected to be incurred with respect to the plugging and abandonment of a well, dismantlement and removal of production facilities, as well as site restoration, are capitalized, consistently with the accounting policy described under “Property, plant and equipment”, and then depreciated on a UOP basis.

Property, plant and equipment

Property, plant and equipment, including investment properties, are recognized using the cost model and stated at their purchase or construction cost including any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management. When a substantial period of time is required to make the asset ready for use, the purchase price or construction cost includes the borrowing costs incurred that could have otherwise been avoided if the expenditure had not been made.

In the case of a present obligation for dismantling and removal of assets and restoration of sites, the initial carrying amount of an item of property, plant and equipment includes the estimated (discounted) costs to be incurred when the removal event occurs (a corresponding amount is recognized as part of a specific provision). Changes in provisions due to the passage of time and changes in discount rates are recognized as described in the accounting policy for “Provisions, contingent liabilities and contingent assets”11.

Property, plant and equipment are not revalued for financial reporting purposes.

Assets under finance lease, or under arrangements that do not take the legal form of a finance lease but substantially transfer all the risks and rewards of ownership of the leased asset, are recognized, at the commencement of the lease term, at fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments. Leased assets are included within property, plant and equipment. A corresponding financial debt to the lessor is recognized. These assets are depreciated as described below. If there is no reasonable certainty that the lessee will obtain ownership by the end of the lease term, the assets are depreciated over the shorter of the lease term and the useful life of the asset.

Expenditures on upgrading, revamping and reconversion are recognized as items of property, plant and equipment when it is probable that they will increase the expected future economic benefits of the asset. Assets acquired for safety or environmental reasons, although not directly increasing the future economic benefits of any particular existing item of property, plant and equipment, qualify for recognition as assets when they are necessary to obtain future economic benefits from other assets.

Depreciation of tangible assets begins when they are available for use, i.e. when they are in the location and condition necessary for it to be capable of operating as planned. Property, plant and equipment are depreciated on a systematic basis, using a straight-line method over their useful life. The useful life is the period over which an asset is expected to be available for use by the Company. When tangible assets are composed of more than one significant part with different useful lives, each part is depreciated separately. The depreciable amount is the asset’s carrying amount less its residual value at the end of its useful life, if it is significant and can be reasonably determined. Land is not depreciated, even when purchased with a building. Tangible assets held for sale are not depreciated (see the accounting policy for “Assets held for sale and discontinued operations”). A change in the depreciation method, deriving from changes in the asset’s useful life, in its residual value or in the pattern of consumption of the future economic benefits embodied in the asset, shall be recognized prospectively.

Assets that can be used free of charge by third parties are depreciated over the shorter term of the duration of the concession or the asset’s useful life.

Replacement costs of identifiable parts in complex assets are capitalized and depreciated over their useful life; the residual carrying amount of the part that has been substituted is charged to the profit and loss account. Leasehold improvement costs are depreciated over the useful life of the improvements or, if

(11)

These liabilities relate essentially to assets in the Exploration & Production segment. Decommissioning and restoration liabilities associated with tangible assets of Refining & Marketing and Chemical and Gas & Power segments are recognized when the cost is actually incurred and the amount of the liability can be reliably estimated, considering that undetermined settlement dates for assets dismantlement and restoration do not allow a discounting estimate of the obligation. With regard to this, Eni performs periodic reviews of its tangible assets of Refining & Marketing and Chemical and Gas & Power segments for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability.

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lower, over the residual length of the lease, considering any renewal period if renewal depends entirely on the lessee and is virtually certain. Expenditures for ordinary maintenance and repairs are recognized as an expense as incurred.

The carrying amount of property, plant and equipment is reviewed for impairment whenever there is any indication that the carrying amounts of those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying amount with the recoverable amount, which is the higher of the asset’s fair value less costs of disposal and its value in use. Value in use is the present value of the future cash flows expected to be derived from continuing use of the asset and, if significant and reliably measurable, the cash flows expected to be obtained from its disposal at the end of its useful life, after deducting the costs of disposal. Expected cash flows are determined on the basis of reasonable and supportable assumptions that represent management’s best estimate of the range of economic conditions that will exist over the remaining useful life of the asset, giving greater weight to external evidence.

With reference to commodity prices, management assumes the price scenario adopted for economic and financial projections and for whole life appraisal for capital expenditures. In particular, for the cash flows associated to oil, natural gas and petroleum products prices (and prices derived from them), the price scenario is approved by the Board of Directors and is based on management’s long-term planning assumptions and, if there is a sufficient liquidity and reliability level, on the forward prices prevailing in the marketplace. When commodity prices fluctuate quite considerably, management considers the most updated variables available.

Discounting is carried out at a rate that reflects a current market assessment of the time value of money and of the risks specific to the asset that are not reflected in the expected future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific country risk of the asset. These adjustments are measured considering information from external parties. WACC differs considering the risk associated with each operating segments where the asset operates. In particular, for the assets belonging to the Gas & Power segment and the Chemical business, taking into account their different risk compared with Eni as a whole, specific WACC rates have been defined on the basis of a sample of companies operating in the same segment/business, adjusted to take into consideration the risk premium of the specific country of the activity. For the other segments/businesses, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate deriving, through an iteration process, from a post-tax valuation. Valuation is carried out for each single asset or, if the recoverable amount of a single asset cannot be determined, for the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the so-called “cash-generating unit”. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognized in the profit and loss account. The reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.

The carrying amount of property, plant and equipment is derecognized on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is recognized in the profit and loss account.

Intangible assets

Intangible assets are identifiable non-monetary assets without physical substance, controlled by the Company and able to produce future economic benefits, and goodwill acquired in business combinations. An asset is classified as intangible when management is able to distinguish it clearly from goodwill. This condition is normally met when: (i) the intangible asset arises from contractual or other legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or together with other assets. An entity controls an intangible asset if it has the power to obtain the future economic benefits flowing from the underlying asset and to restrict the access of others to those benefits.

Intangible assets are initially recognized at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes.

Intangible assets with finite useful lives are amortized on a systematic basis over their useful life estimated as the period over which the assets will be available for use by the Company; the amount to be

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amortized and the recoverability of the carrying amount are determined in accordance with the criteria described in the accounting policy for “Property, plant and equipment”.

Goodwill and intangible assets with indefinite useful lives are not amortized. Their carrying amounts are tested for impairment at least annually and whenever there is any indication of impairment. Goodwill is tested for impairment at the lowest level within the entity at which it is monitored for internal management purposes. When the carrying amount of the cash-generating unit, including goodwill allocated thereto, calculated considering any impairment loss of the non-current assets belonging to the cash-generating unit, exceeds its recoverable amount12, the excess is recognized as an impairment loss. The impairment loss is allocated first to reduce the carrying amount of goodwill; any remaining excess is allocated to the other assets of the unit pro-rata on the basis of the carrying amount of each asset in the unit, up to the recoverable amount of assets with finite useful lives. An impairment loss recognized for goodwill is not reversed in a subsequent period13.

Directly attributable customer acquisition costs are capitalized when the following conditions are met: (i) the capitalized costs can be measured reliably; (ii) there is a contract binding the customer for a specified period of time; and (iii) it is probable that the costs will be recovered through the revenues from the sales, or, where the customer withdraws from the contract in advance, through the collection of a penalty.

Costs of technological development activities are capitalized when: (i) the cost attributable to the development activity can be measured reliably; (ii) there is the intention and the availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate probable future economic benefits.

The carrying amount of intangible assets is derecognized on disposal or when no future economic benefits are expected from its use or disposal; any arising gain or loss is recognized in the profit and loss account.

Grants related to assets

Government grants related to assets are recognized by deducting them in calculating the carrying amount of the related assets when there is reasonable assurance that the Company will comply with the conditions attaching to them and the grants will be received.

Inventories

Inventories, including compulsory stock, are measured at the lower of purchase or production cost and net realizable value. Net realizable value is the amount expected to be realized from the sale of inventories in the ordinary course of business less the estimated costs of completion and the estimated costs necessary to make the sale, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual selling price. Inventories which are principally acquired with the purpose of selling in the near future and generating a profit from fluctuations in price are measured at fair value less costs to sell. Materials and other supplies held for use in production are not written down below cost if the finished products in which they will be incorporated are expected to be sold at or above cost.

The cost of inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted average cost method on a three-month basis, or on a different time period (e.g. monthly), when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost of inventories of the Chemical business is determined by applying the weighted average cost on an annual basis.

When take-or-pay clauses are included in long-term gas purchase contracts, pre-paid gas volumes that are not withdrawn to fulfill minimum annual take obligations, are measured using the pricing formulas contractually defined. They are recognized under “Other assets” as “Deferred costs” as a contra to “Other payables” or, after the settlement, to “Cash and cash equivalents”. The allocated deferred costs are charged

(12)

For the definition of recoverable amount see the accounting policy for “Property, plant and equipment”.

(13)

Impairment losses recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized.

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to the profit and loss account: (i) when natural gas is actually withdrawn — the related cost is included in the determination of the weighted average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to withdraw the previously pre-paid gas, within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizable value, determined adopting the same criteria described for inventories.

Financial instruments

Current financial assets

Cash and cash equivalents include cash on hand, demand deposits, as well as financial assets originally due within 90 days, readily convertible to known amount of cash and subject to an insignificant risk of changes in value.

Available-for-sale financial assets include financial assets other than derivative financial instruments, loans and receivables, held for trading financial assets and held-to-maturity financial assets.

Held-for-trading financial assets and available-for-sale financial assets are measured at fair value with gains or losses recognized in the line item of the profit and loss account “Finance income (expense)” and in the equity reserve14 related to other comprehensive income, respectively. Changes in fair value of available-for-sale financial assets recognized in equity are charged to the profit and loss account when the assets are derecognized or impaired. The objective evidence that an impairment loss has occurred is verified considering, inter alia, significant breaches of contracts, serious financial difficulties or the risk of bankruptcy and other financial reorganization of the counterparty; impairment losses of available-for-sale financial assets are included in the carrying amount.

Interests and dividends on financial assets measured at fair value are accounted for on an accrual basis in “Finance income (expense)”15 and “Other gain (loss) from investments”, respectively. When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame established generally by regulation or convention in the marketplace concerned, the transaction is accounted for on the settlement date.

Receivables are measured at amortized cost (see the accounting policy for “Non-current financial assets”).

Non-current financial assets

Investments

Investments in equity instruments16 are measured at fair value, with gains or losses recognized in the equity reserve related to other comprehensive income; the amounts recognized in equity are reclassified to the profit and loss account when the investment is impaired or derecognized.

When investments do not have a quoted price in an active market and their fair value cannot be reliably measured, they are measured at cost, net of any impairment losses; impairment losses shall not be reversed17.

Receivables and held-to-maturity financial assets

Receivables and held-to-maturity financial assets are accounted for at cost, that is the fair value of the initial consideration plus directly attributable transaction costs (e.g. fees, transaction costs, etc.). The initial carrying amount is then adjusted to take into account principal repayments, plus or minus the cumulative

(14)

Changes in the carrying amount of available-for-sale financial assets relating to changes in foreign exchange rates are recognized in the profit and loss account.

(15)

Interests accrued on held for trading financial assets impact the total fair value measurement of the instrument and are recognized, within the line item “Finance income (expense)”, in the sub-item “Net finance income on financial assets held for trading”. Conversely, interests accrued on financial assets available-for-sale are recognized, within the line item “Finance income (expense)”, in the sub-item “Finance income”.

(16)

For investments in joint ventures and associates, see “The equity method of accounting”.

(17)

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amortization of any difference between the initial amount and the maturity amount and minus any reductions for impairment or uncollectibility. Amortization is carried out on the basis of the effective interest rate represented by the rate that equalizes, at the moment of the initial recognition, the present value of expected cash flows to the initial carrying amount (so-called “amortized cost method”). Receivables for finance leases are recognized at an amount equal to the present value of the lease payments and the purchase option price or any residual value; the amount is discounted at the interest rate implicit in the lease.

If there is objective evidence that an impairment loss has been incurred (see also the accounting policy for “Current financial assets”), the impairment loss is measured as the difference between the carrying amount and the present value of the expected cash flows discounted at the effective interest rate computed at initial recognition, or at the moment of its updating to reflect re-pricings contractually established. Receivables and held-to-maturity financial assets are presented net of the allowance for impairment losses; when the impairment loss is definite, the allowance for impairment losses is reversed for charges, otherwise for excess. Changes to the carrying amount of receivables or financial assets in accordance with the amortized cost method are recognized as “Finance income (expense)”.

Financial liabilities

Financial liabilities, other than derivative financial instruments, are recognized initially at the fair value of the consideration received less the directly attributable transaction costs, and are subsequently measured at amortized cost (see above the accounting policy for “Non-current financial assets”).

Derivative financial instruments

Derivative financial instruments, including embedded derivatives (see below) that are separated from the host contract, are assets and liabilities measured at their fair value.

Derivatives are designated as hedging instruments when the relationship between the derivative and the hedged item is formally documented and the hedge is regarded as highly effective and reviewed on an ongoing basis. When derivatives hedge the risk of changes in the fair value of the hedged item (fair value hedge, e.g. hedging of the variability in the fair value of fixed interest rate assets/liabilities), the derivatives are measured at fair value through profit and loss account. Consistently, the carrying amount of the hedged item is adjusted to reflect, in the profit and loss account, the changes in fair value of the hedged item attributable to the hedged risk; this applies even if the hedged item should be otherwise measured.

When derivatives hedge the exposure to variability in cash flows of the hedged item (cash flow hedge, e.g. hedging the variability in the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), the changes in the fair value of the derivatives, that are designated as effective hedging instruments, are initially recognized in the equity reserve related to other comprehensive income and then reclassified to the profit and loss account in the same period during which the hedged transaction affects the profit and loss account.

The changes in the fair value of derivatives, that are not designated as effective hedging instruments, are recognized in the profit and loss account. In particular, the changes in the fair value of non-hedging derivatives on interest rates and exchange rates are recognized in the profit and loss account line item “Finance income (expense)”, conversely, the changes in the fair value of non-hedging derivatives on commodities are recognized in the profit and loss account line item “Other operating (expense) income”.

Embedded derivatives in hybrid instruments are separated from the host contract and accounted for as a derivative if the hybrid instruments are not measured at fair value with changes in fair value recognized in the profit and loss account and if the economic characteristics and risks of the embedded derivatives are not closely related to those of the host contracts. The entity assesses the existence of embedded derivatives to be separated when it becomes party to the contract and, afterwards, when a change in the terms of the contract that modifies its cash flows, occurs.

Contracts to buy or sell commodities entered into and continue to be held for the purpose of their receipt or delivery in accordance with the Group’s expected purchase, sale or usage requirements are recognized on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption).

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Offsetting of financial assets and liabilities

Financial assets and liabilities are set off in the balance sheet if the Group currently has a legally enforceable right to set off and intends to settle on a net basis (or to realize the asset and settle the liability simultaneously).

Derecognition of financial assets and liabilities

Transferred financial assets are derecognized when the contractual rights to receive the cash flows from the financial assets are realized, expired or transferred. Financial liabilities are derecognized when they are extinguished, or when the obligation specified in the contract is discharged, cancelled or expired.

Provisions, contingent liabilities and contingent assets

A provision is a liability of uncertain timing or amount at the balance sheet date. Provisions are recognized when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated. The amount recognized as a provision is the best estimate of the expenditure required to settle the present obligation or to transfer it to third parties at the balance sheet date. The amount recognized for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any compensation or penalties arising from failure to fulfill these obligations. Where the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued are the present value of the expenditures expected to be required to settle the obligation at a discount rate that reflects the Company’s average borrowing rate taking into account the risks associated with the obligation. The increase in the provision due to the passage of time is recognized as “Finance income (expense)”.

Where an obligation exists for an item of property, plant and equipment (e.g. site dismantling and restoration), the provision is recognized together with a corresponding amount as part of the related item of property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset.

A provision for restructuring costs is recognized only when the Company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring.

Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates. Changes in provisions are recognized in the same profit and loss account line item where the original provision was charged, or, when the liability regards tangible assets (e.g. site dismantling and restoration), changes in the provision are recognized with a corresponding entry to the assets to which they refer, to the extent of the assets’ carrying amounts; any excess amount is recognized in the profit and loss account.

Contingent liabilities are disclosed as follows: (i) possible, but not probable obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Contingent assets, that are possible assets arising from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company, are not recognized unless the realization of economic benefits is virtually certain. Contingent assets are disclosed when an inflow of economic benefits is probable. Contingent assets are assessed periodically to ensure that developments are appropriately reflected in the financial statements; if it has become virtually certain that an inflow of economic benefits will arise, the asset and the related income are recognized in the financial statements of the period in which the change occurs.

Employee benefits

Employee benefits are considerations given by the Group in exchange for service rendered by employees or for the termination of employment.

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Post-employment benefit plans, including informal arrangements, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. Under defined contribution plans, the Company’s obligation, which consists in making payments to the State or to a trust or a fund, is determined on the basis of contributions due.

The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits.

Net interest includes the return on plan assets and the interests cost to be recognized in the profit and loss account. Net interest is measured by applying to the liability, net of any plan assets, the discount rate used to calculate the present value of the liability; net interest of defined benefit plans is recognized in “Finance income (expense)”.

Re-measurements of the net defined benefit liability, comprising actuarial gains and losses, resulting from changes in the actuarial assumptions used or from changes arising from experience adjustments, and the return on plan assets excluding amounts included in net interest, are recognized within the statement of comprehensive income. Re-measurements of the net defined benefit liability, recognized in the equity reserve related to other comprehensive income, are not reclassified to the profit and loss account in a subsequent period.

Obligations for long-term benefits are determined by adopting actuarial assumptions. The effects of re-measurements are taken to profit and loss account in their entirety.

Treasury shares

Treasury shares are recognized as deductions from equity at cost. Any gain or loss resulting from subsequent sales is recognized in equity.

Revenues and costs

Revenues from the sale of products and the rendering of services are recognized when the significant risks and rewards of ownership have been transferred to the customer or when the transaction can be considered settled and the associated revenue can be reliably measured. In particular, revenues are recognized for the sale of:

•

crude oil, generally upon shipment;

•

natural gas and electricity, upon delivery to the customer;

•

petroleum products sold to retail distribution networks, generally upon delivery to the service stations, whereas all other sales of petroleum products are generally recognized upon shipment; and

•

chemical products and other products, generally upon shipment.

Revenues are recognized upon shipment when, at that date, significant risks are transferred to the buyer.

Revenues from crude oil and natural gas production from properties in which Eni has an interest together with other producers are recognized on the basis of Eni’s net working interest in those properties (entitlement method). Higher/lower production volume withdrawn as compared to Eni’s net working interest volume is recognized at current prices at the balance sheet date.

Revenues arising from rendering of services are recognized by reference to the stage of completion at the end of the reporting period, provided that: (i) the amount of revenues can be measured reliably; (ii) it is probable that the economic benefits associated with the transaction will flow to the entity; (iii) the stage of completion of the transaction at the end of the reporting period can be measured reliably; and (iv) the related costs can be measured reliably. When the outcome of the transaction involving the rendering of services cannot be estimated reliably, revenue is recognized only to the extent of the expenses recognized that are recoverable.

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Revenues are measured at the fair value of the consideration received or receivable net of returns, discounts, rebates, bonuses and related taxes. Amounts collected or to be collected on behalf of third parties are not revenues.

Award credits, related to customer loyalty programs, are recognized as a separately identifiable component of the sales transaction in which they are granted. Therefore, the consideration allocated to the award credits, measured by reference to their fair value, represents deferred revenues and it is recognized in the line item “Other liabilities”. The deferred revenues are reversed in the profit and loss account at the redemption or forfeiture of the award credits by customers. When goods or services are exchanged for goods or services that are of a similar nature and value, the exchange is not regarded as a transaction which generates a revenue.

Costs are recognized when the related goods and services are sold or consumed during the year, when they are allocated on a systematic basis or when their future economic benefits cannot be identified. Costs associated with emission quotas, determined on the basis of the market prices, are recognized in relation to the amount of the carbon dioxide emissions that exceed free allowances. Costs related to the purchase of the emission rights are recognized as intangible assets net of any imbalance between the amount of actual emissions and the free allowances. Revenues related to emission quotas are recognized when they are sold and, if applicable, purchased emission rights are considered the first to be sold. Monetary receivables granted to replace the free award emission rights are recognized as a contra to the line item “Other income and revenues”.

Operating lease payments are recognized as an expense over the lease term. The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalized (see above the accounting policy for “Intangible assets”), are included in the profit and loss account when they are incurred.

Grants not related to assets are recognized in the profit and loss account on an accrual basis matching the related costs when incurred.

Share-based payments

The line item “Payroll and related costs” includes the cost of the share-based incentive plan, consistently with its actual remunerative nature.18 The cost of the share-based incentive plan is measured by reference to the fair value of the equity instruments granted and the estimate of the number of shares that eventually vest; the cost is recognised on an accrual basis pro rata temporis over the vesting period, that is the period between the grant date and the settlement date. A corresponding credit is recognised within equity. The fair value of the shares underlying the incentive plan is measured at the grant date, taking into account the estimate of achievement of market conditions (e.g. Total Shareholder Return), and is not adjusted in subsequent periods; when the achievement is linked also to non-market conditions (e.g.conditional on the employees remaining in service for the vesting period and non-market conditions), the number of shares expected to vest is adjusted during the vesting period to reflect the updated estimate of these conditions. If, at the end of the vesting period, the incentive plan does not vest because of failure to satisfy the performance conditions, the portion of cost related to market conditions is not reversed to the profit and loss account.

Exchange differences

Revenues and costs associated with transactions in foreign currencies are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the spot exchange rate on the balance sheet date and any resulting exchange differences are included in the profit and loss account within “Finance income (expense)” or, if designated as hedging instruments for the foreign currency risk, in the same line item in which the economic effects of the hedged item are recognized. Non-monetary assets and liabilities denominated in foreign currencies, measured at cost, are not retranslated subsequent to initial recognition. Non-monetary items measured at fair value, recoverable amount or net realizable value are retranslated using the exchange rate at the date when the value is determined.

(18)

The current share-based incentive plan, to be settled by treasury shares, was approved by the shareholders’ meeting held on April 13, 2017.

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Dividends

Dividends are recognized at the date of the general shareholders’ meeting in which they were declared, except when the sale of shares before the ex-dividend date is certain.

Income taxes

Current income taxes are determined on the basis of estimated taxable income. The estimated liability is included in “Income taxes payable”. Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the taxation authorities, using tax rates and the tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets and liabilities are recognized for temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates and tax laws that have been enacted or substantively enacted for future years. Deferred tax assets are recognized when their recoverability is considered probable; in particular, deferred tax assets are recoverable when it is probable that sufficient taxable profit will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carry-forward of unused tax credits and unused tax losses are recognized to the extent that their recoverability is probable. Income tax assets that are uncertain in the amount to be recovered are recognized in accordance to the probable threshold.

Relating to the taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint arrangements, the related deferred tax liabilities are not recognized if the investor is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets and liabilities are included in non-current assets and liabilities and are offset at a single entity level if related to off-settable taxes. The balance of the offset, if positive, is recognized in the line item “Deferred tax assets”, if negative, in the line item “Deferred tax liabilities”. When the results of transactions are recognized directly in shareholders’ equity, the related current and deferred taxes are also charged to the shareholders’ equity.

Assets held for sale and discontinued operations

Non-current assets and current and non-current assets included within disposal groups, are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through their continuing use. For this to be the case, the sale must be highly probable and the asset or the disposal group must be available for immediate sale in its present condition. When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retained after the sale. The classification of non-current assets (or disposal groups) as held for sale requires the management to perform subjective judgements based on assumptions deemed reasonable in consideration of the information available at the time.

Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognized in the balance sheet separately from other assets and liabilities.

Immediately before the initial classification of a disposal group as held for sale, the assets and liabilities of the disposal group are measured in accordance with applicable IFRSs. Subsequently, non-current assets held for sale are not depreciated and they are measured at the lower of the fair value less costs to sell and their carrying amount. After the classification as held for sale of an equity-accounted investment, the investment, or the portion of the investment, that meets the criteria to be classified as held for sale, is no longer accounted for using the equity method; therefore, in this case, the carrying amount of the investment in accordance with the equity method represents the carrying amount for the measurement as non-current asset held for sale. Any retained portion of the equity-accounted investment that has not been classified as held for sale is accounted for using the equity method until disposal of the portion that is classified as held for sale takes place. After the disposal takes place, any retained investment is measured in accordance with the measurement criteria indicated in the accounting policy for “Non-current financial assets — Investments”, unless the retained interest continues to be an equity-accounted investment.

Any difference between the carrying amount of the non-current assets and the fair value less costs to sell is taken to the profit and loss account as an impairment loss; any subsequent reversal is recognized up to the cumulative impairment losses, including those recognized prior to qualification of the asset as held

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for sale. Non-current assets classified as held for sale and disposal groups, are considered a discontinued operation if, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss recognized on the disposal, are indicated in a separate line item of the profit and loss account, net of the related tax effects; the economic figures of discontinued operations are indicated also for prior periods presented in the financial statements.

If events or circumstances occur that no longer allow to classify a non-current asset or a disposal group as held for sale, the non-current asset or the disposal group is reclassified into the original line items of the balance sheet and measured at the lower of: (i) its carrying amount at the date of classification as held for sale adjusted for any depreciation, amortizations, impairment losses and reversals that would have been recognized had the asset or disposal group not been classified as held for sale, and (ii) its recoverable amount at the date of the subsequent decision not to sell. If the interruption of a plan of sale concerns a subsidiary, joint operation, joint venture, associate, or a portion of an interest in a joint venture or an associate, financial statements for the period since classification as held for sale are amended.

If a discontinued operation is reclassified as held for use, its results previously presented in the separate line item of the profit and loss account are reclassified and included in income from continuing operations for all periods presented.

Fair value measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (not in a forced liquidation or a distress sale) at the measurement date (exit price). Fair value measurement is based on the market conditions existing at the measurement date and on the assumptions of market participants (market-based measurement). A fair value measurement assumes that the transaction to sell the asset or transfer the liability takes place in the principal market for the asset or liability, or in the absence of a principal market, in the most advantageous market to which the entity has access, independently from the entity’s intention to sell the asset or transfer the liability to be measured.

A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. Highest and best use is determined from the perspective of market participants, even if the entity intends a different use; an entity’s current use of a non-financial asset is presumed to be its highest and best use, unless market or other factors suggest that a different use by market participants would maximize the value of the asset.

The fair value of a liability, both financial and non-financial, or of a Company’s own equity instrument, in the absence of a quoted price, is measured from the perspective of a market participant that holds the identical item as an asset at the measurement date. The fair value of financial instruments takes into account the counterparty’s credit risk for a financial asset (Credit Valuation Adjustment, CVA) and the entity’s own credit risk for a financial liability (Debit Valuation Adjustment, DVA).

In the absence of available market quotation, fair value is measured by using valuation techniques that are appropriate in the circumstances, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs.

4 Financial statements19

Assets and liabilities on the balance sheet are classified as current and non-current. Items on the profit and loss account are presented by nature20. Assets and liabilities are classified as current when: (i) they are expected to be realized/settled in the entity’s normal operating cycle or within twelve months after the

(19)

The financial statements are the same presented in the last Annual Report on Form 20-F; in the statement of cash flows, the tax cash flows, readily identifiable as attributed to a disposal transaction, are separately presented within the net cash used in investing activities.

(20)

Further information on financial instruments as classified in accordance with IFRS is provided in note 38 — Guarantees, commitments and risks — Other information about financial instruments.

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balance sheet date; (ii) they are cash or cash equivalents unless they are restricted from being exchanged or used to settle a liability for at least twelve months after the balance sheet date; or (iii) they are held primarily for the purpose of trading. Derivative financial instruments held for trading are classified as current, apart from their maturity date. Non hedging derivative financial instruments, which are entered into to manage risk exposures but do not satisfy the formal requirements to be considered as hedging, and hedging derivative financial instruments are classified as current when they are expected to be realized/settled within twelve months after the balance sheet date; on the contrary they are classified as non-current.

The statement of comprehensive income shows net profit integrated with income and expenses that are recognized directly in equity according to IFRS.

The statement of changes in shareholders’ equity includes the total comprehensive income for the year, transactions with shareholders in their capacity as shareholders and other changes in shareholders’ equity.

The statement of cash flows is presented using the indirect method, whereby net profit is adjusted for the effects of non-cash transactions.

5 Changes in accounting policies

The adoption of the amended IFRSs effective from January 1, 2017, did not have a significant impact on the consolidated financial statements.

6 Significant accounting estimates or judgments

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses recognized in the financial statements, as well as amounts included in the notes thereto, including disclosure of contingent assets and contingent liabilities. Estimates made are based on complex or subjective judgements and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgements and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, decommissioning and restoration liabilities, business combinations, employee benefits and recognition of environmental liabilities. Although the Company uses its best estimates and judgements, actual results could differ from the estimates and assumptions used. The accounting estimates and judgements relevant for the preparation of the Consolidated Financial Statement are described below.

Oil and natural gas activities

Engineering estimates of the Company’s oil&gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil&gas reserves can be categorized as “proved”, the accuracy of any reserve estimate depends on the quality of available data, the engineering and geological interpretation of such data and management’s judgment.

The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is made within a year after well completion. The evaluation process of a discovery, which requires performing additional appraisal activities on the potential oil and natural gas field and establishing the optimum development plans, can take longer, in most cases, depending on the complexity

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of the project and on the size of capital expenditures required. During this period, the costs related to these exploration wells remain suspended on the balance sheet. In any case, all such carried costs are reviewed on at least an annual basis to confirm the continued intent to develop, or otherwise to extract value from the discovery.

Field reserves will be categorized as proved only when all the criteria for attribution of proved status have been met. Initially, all booked reserves are classified as proved undeveloped. Subsequently, volumes are reclassified from proved undeveloped to proved developed as a consequence of development activity. Generally, reserves are booked as proved developed when the first oil or gas is produced. Major development projects typically take one to four years from the time of initial booking to the start of production. Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision. Upward or downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of production sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion charges and impairment charges. Depreciation and depletion rates of oil&gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation and depletion charge. Conversely, a decrease in estimated proved developed reserves increases depreciation and depletion charge. Estimated proved reserves are affected, inter alia, by the trend of reference oil and gas commodity prices and by the specific legal agreement for the oil&gas activity.

In addition, estimated proved reserves are used to calculate future cash flows from oil&gas properties, which are used to assess any impairment loss. The larger is the volume of estimated reserves, the lower is the likelihood of asset impairment.

Impairment of assets

Assets are impaired when there are events or changes in circumstances that indicate that carrying amounts of the assets are not recoverable. Such impairment indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance, a reduced capacity utilization of plants and, for oil&gas properties, significant downward revisions of estimated proved reserve quantities or significant increase of the estimated development costs. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain and complex matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for demand and supply conditions on a global or regional scale. Similar remarks are valid for assessing the physical recoverability of assets recognized in the balance sheet (deferred costs — see also the accounting policy for “Inventories”) related to natural gas volumes not withdrawn under long-term supply contracts with take-or-pay clauses, as well as for assessing the recoverability of deferred tax assets. The amount of an impairment loss is determined by comparing the carrying amount of an asset with its recoverable amount. Recoverable amount of an asset is the higher of an asset’s fair value less costs of disposal and its value in use. The estimate of an asset’s value in use is based on the present value of the future cash flows expected to be derived from continuing use of the asset and, if significant and reasonably determinable, the cash flows expected to be obtained from the disposal of the asset at the end of its useful life after deducting the costs of disposal. The expected future cash flows used for impairment analyses are based on judgemental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate which considers the risks specific to the asset. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and undeveloped proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, field decline rates, market demand and other factors. The cash flows associated to oil&gas commodities are estimated on the basis of forward market information, if there is a sufficient

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liquidity and reliability level, on the consensus of independent specialized analysts and on management’s forecasts about the evolution of the supply and demand fundamentals. The discount rate reflects the current market valuation of the time value of money and of the specific risks of the asset not reflected in the estimate of the future cash flows.

Goodwill and intangible assets with indefinite useful lives are not subject to amortization. The Company tests for impairment such assets on an annual basis and whenever there is any indication that they may be impaired. In particular, goodwill impairment is based on the lowest level (cash-generating unit) to which goodwill can be allocated on a reasonable and consistent basis. A cash-generating unit is the smallest aggregate on which the Company, directly or indirectly, evaluates the return on the capital expenditures. If the recoverable amount of a cash-generating unit, to which goodwill has been allocated, is less than its carrying amount, goodwill allocated to that cash-generating unit is impaired up to that difference; if the carrying amount of goodwill is lower than the amount of the impairment loss, the other assets of the cash-generating unit are impaired pro-rata on the basis of their carrying amounts for the residual difference, up to the recoverable amount of assets with finite useful lives.

Decommissioning and restoration liabilities

The Group holds provisions for dismantling and removing items of property, plant and equipment, and restoring land or seabed at the end of the oil and gas production activity. Estimating obligations to dismantle, remove and restore items of property, plant and equipment is complex. It requires management to make estimates and judgements with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations. The complexity of these estimates is also due to the accounting that requires the initial recognition of the present value of the decommissioning and restoration liabilities as a part of the cost of property, plant and equipment. Then the carrying amount of decommissioning and restoration liabilities is adjusted to reflect the passage of time and any change in the estimates following the modification of amount and timing of future cash flows and discount rates adopted. The discount rate used to determine the provision is based on complex and subjective managerial judgements.

Business combinations

Accounting for business combinations requires the allocation of the purchase price to the identifiable assets and liabilities of the acquired business generally at their fair values. Any positive residual difference is recognized as goodwill. Any negative residual difference is recognized in the profit and loss account. If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognized at the acquisition date are retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date. Management uses all available information to make these fair value measurements and, for major business combinations, engages independent external advisors; the purchase price allocation, that requires, also in consideration of the available information, management to make complex judgements, is also relevant for the application of the equity method.

Environmental liabilities

As other oil&gas companies, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil&gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental provisions are recognized when it becomes probable that a liability will be incurred and the liability can be reliably estimated. Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible

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effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements.

Employee benefits and share-based payments

Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, mortality rates, estimated retirement dates and medical cost trends. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds). The inflation rates reflect market conditions observed in the reference currency area; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved.

Differences in the amount of the net defined benefit liability (asset), deriving from the re-measurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Re-measurements are recognized within statement of comprehensive income for defined benefit plans and within the profit and loss account for long-term plans.

Similarly to the approach followed for the fair value measurement of financial instruments, the fair value of the shares underlying the incentive plan is measured by using complex valuation techniques and identifying, through structured and/or subjective judgements, the assumptions to be adopted.

Other provisions

In addition to liabilities related to environmental, decommissioning and restoration liabilities and employee benefits, Eni recognizes provisions primarily related to legal, trade and tax proceedings. These provisions are estimated on the basis of managerial judgements related to the amounts to recognize and the timing of future cash outflows. After the initial recognition, provisions are periodically reviewed and adjusted to reflect the current best estimate.

Revenues and receivables

Revenues from the sale of electricity and gas to retail customers include amount accrued for electricity and gas supplied between the date of the last (actual or estimated) meter reading invoiced and the end of the year. These estimates consider information provided by the grid managers about the volumes allocated among the customers of the secondary distribution network, about the actual and estimated volumes consumed by customers, as well as they rely on other factors, considered by management, which can impact on them. Therefore accrued revenues derive from complex estimates based on distributed and allocated volumes, communicated by third parties; these revenues may be adjusted, according to the applicable regulations, within the fifth year subsequent the one in which they were accrued.

Complex and/or subjective judgments are required in assessing the recoverability of overdue receivables and determining whether an allowance against those receivables is required. Factors considered include, among others, the credit rating of the counterparty (if available), the amount and timing of anticipated future payments, any collateral held as a security and other credit enhancements, as well as any possible actions that can be taken to mitigate the risk of non-payment.

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7 IFRSs not yet adopted

On May 28, 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” (hereinafter IFRS 15), which sets out the requirements for recognizing and measuring revenue arising from contracts with customers, including construction contracts. In particular, IFRS 15 requires that, to recognize revenue, an entity shall apply the following five steps: (i) identifying the contract with the customer; (ii) identifying the performance obligations (that are promises in a contract to transfer goods and/or services to a customer); (iii) determining the transaction price; (iv) allocating the transaction price to each performance obligation on the basis of the relative stand-alone selling prices of each good or service promised in the contract; and (v) recognizing revenue when a performance obligation is satisfied. Moreover, IFRS 15 includes more disclosure requirements about the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. IFRS 15 shall be applied for annual reporting periods beginning on or after January 1, 2018. Furthermore, on April 12, 2016, the IASB issued the document “Clarifications to IFRS 15 Revenue from Contracts with Customers”, which provides clarifications to support implementation of the new standard. The clarifications to IFRS 15 shall be applied for annual reporting periods beginning on or after January 1, 2018.

In 2017, the Group completed the analytical activities aimed to identify the areas affected by the adoption of IFRS 15 and assess the related impacts on the financial statements. In particular, as already indicated in the interim consolidated report, the affected areas relate essentially to:

(i)

in the Exploration & Production segment, the accounting for agreements with partners within oil & gas operations, due to the fact that they do not meet the definition of a customer. In particular, the case concerns the accounting for amounts of production lifted by a partner within oil & gas operations different from its proportionate entitlement (the so called lifting imbalances), by recognizing revenues on the basis of the quantities actually sold (the so called sales method) instead of the entitled quantities (the so called entitlement method). The adoption of the sales method results in recognizing revenues and related expenses on the basis of the quantities actually lifted and sold;

(ii)

in the Gas & Power segment, the capitalization of the costs of obtaining contracts with customers, if the entity expects to recover them, and their amortization over the expected duration of the contract.

On initial application of the new IFRS, Eni intends to use the cumulative effect method under which the cumulative effect of applying the new standard at the beginning of the year of initial application is recognized as an adjustment to the opening balance of equity at January 1, 2018, considering only contracts not completed at January 1, 2018, and without restating the comparative reporting periods.

In particular, based on information available and considering the above-mentioned cases, the effect of the adoption of IFRS 15, net of tax, is represented by a decrease in equity of €43 million arising from the adjustment, according to the sales method, of the underlifting imbalances existing at the end of the 2017 reporting period (€103 million), partially offset by a positive change of €60 million arising from the capitalization of the costs of obtaining contracts with customers, net of their amortization. Moreover, in terms of presentation in the financial statements, the adoption of IFRS 15 involves limited reclassifications of revenue to other line items of the profit and loss account without impacting operating result, net result and equity. On July 24, 2014, the IASB completed its project to replace IAS 39 by issuing the final version of IFRS 9 “Financial Instruments” (hereinafter IFRS 9). In particular, IFRS 9: (i) changes the classification and measurement approach for financial assets, basing it on the characteristics of the financial instrument and on the business model adopted by the entity for managing it; (ii) introduces a new impairment model for financial assets, which considers the expected credit losses; and (iii) includes an improved hedge accounting model. IFRS 9 shall be applied for annual reporting periods beginning on or after January 1, 2018.

The accounting areas affected by the new standard relate essentially to: (i) the adoption of the expected credit loss model for impairment of financial assets, which involves the recognition of the expected loss on financial assets, taking into account a forward-looking approach based on the probability of default of the counterparty and the loss given default; and (ii) the fair value measurement of investments in equity instruments, when the cost is not an appropriate estimate of the fair value.

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In particular, in 2017, the Group completed the activities aimed to define and implement the expected credit loss model for the impairment of financial assets, which essentially requires:

(i)

the adoption of internal credit rating, already used for credit worthiness, to determine probability of default of counterparties; for government entities (e.g. National Oil Companies), the probability of default, represented essentially by probability of a delayed payment, is determined by using, as input data, the country risk premium adopted to determine WACC for impairment of non-financial assets;

(ii)

the identification of the exposure to be considered, having regard to any credit enhancements (e.g.collaterals, guarantees, insurance contracts, countervailable payables, etc.);

(iii)

for retail customers, not characterized by internal credit rating, the implementation of a simplified approach based on a provision matrix aimed to categorize customers by homogeneous risk characteristics;

(iv)

the estimate of loss given default, considering the previous experiences and the range of recovery tools that can be activated (e.g. extrajudicial and/or legal proceedings, etc.)21.

With reference to investments in equity instruments, IFRS 9 requires their fair value measurement, while allowing their measurement at cost only when the cost can be considered an appropriate estimate of the fair value. Eni will elect to present in other comprehensive income the changes in the fair value of its investments in equity instruments, while recognizing in profit and loss account dividends from these investments; these changes in fair value are not reclassified to profit and loss account22.

On initial application of the new IFRS, considering the complexity of the restatement at the beginning of the first comparative period without the use of hindsight, the impacts of the new classification and measurement requirements, including impairment of financial assets, will be recognized as an adjustment to the opening balance of equity at January 1, 2018; with reference to hedge accounting, the adoption of the new requirements will not have significant impacts.

In particular, based on information available and considering the above-mentioned cases, the effect of the adoption of IFRS 9, net of tax, is represented by an increase of equity for €322 million arising from the fair value measurement of investments in equity instruments (€678 million); offset by the additional impairment losses (€356 million) of financial assets recognized under the expected credit loss model.

On January 13, 2016, the IASB issued IFRS 16 “Leases” (hereinafter IFRS 16), which replaces IAS 17 and related interpretations. In particular, IFRS 16 defines a lease as a contract that conveys to the lessee the right to control the use of an identified asset for a period of time in exchange for consideration. The new IFRS eliminates the classification of leases as either operating leases or finance leases for the preparation of lessees’ financial statements; for all leases with a term of more than 12 months, the lessee shall recognize an asset, as the right-of-use, and a liability, as the present value of the lease payments. Conversely, a lessor continues to classify its leases as operating leases or finance leases. IFRS 16 enhances disclosures both for lessees and for lessors. IFRS 16 shall be applied for annual reporting periods beginning on or after January 1, 2019. Eni is currently analyzing the new requirements also in order to determine the impacts on the Group’s financial statements.

On December 8, 2016, the IASB issued the IFRIC Interpretation 22 “Foreign Currency Transactions and Advance Consideration” (hereinafter IFRIC 22), which sets out that the exchange rate to use on initial recognition of an asset, expense or income related to an advance consideration, previously paid or received in a foreign currency, is the rate used at the date of initial recognition of the non-monetary asset or non-monetary liability arising from the payment or receipt of that advance consideration. The IFRIC 22 shall be applied for annual reporting periods beginning on or after January 1, 2018.

On May 18, 2017, the IASB issued IFRS 17 “Insurance Contracts” (hereinafter IFRS 17), which sets out the accounting for the insurance contracts issued and the reinsurance contracts held. IFRS 17, which replaces IFRS 4 “Insurance Contracts”, shall be applied for annual reporting periods beginning on or after January 1, 2021.

(21)

For exposures arising from intragroup transactions, the recovery rate is assumed to be 100% in consideration of the possibility of providing for capital contribution to the investees in order to guarantee their solvency.

(22)

Alternatively, IFRS 9 permits to present in profit and loss account the changes in fair value of investments in equity instruments; the election about the presentation of these fair value changes is made on an instrument-by-instrument basis.

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On June 7, 2017, the IASB issued IFRIC 23 “Uncertainty over Income Tax Treatments” (hereinafter IFRIC 23), which clarifies the accounting for (current and/or deferred) tax assets and liabilities when there is uncertainty over income tax treatments. IFRIC 23 shall be applied for annual reporting periods beginning on or after January 1, 2019.

On October 12, 2017, the IASB issued the amendments to IAS 28 “Long-term Interests in Associates and Joint Ventures” (hereinafter the amendments to IAS 28), which clarify that entities account for long-term interests in an associate or joint venture, that, in substance, form part of the entity’s net investment in the investee and for which settlement is neither planned nor likely to occur in the foreseeable future, using the provisions of IFRS 9, including those related to impairment. The amendments to IAS 28 shall be applied for annual reporting periods beginning on or after January 1, 2019.

On February 7, 2018, the IASB issued the amendments to IAS 19 “Plan Amendment, Curtailment or Settlement” (hereinafter the amendments to IAS 19), which require to use updated actuarial assumptions to determine current service cost and net interest, when an amendment, curtailment or settlement to an existing defined benefit pension plan takes place, for the remainder reporting period after the change of the plan. The amendments to IAS 19 shall be applied for annual reporting periods beginning on or after January 1, 2019. On December 8, 2016, the IASB issued the document “Annual Improvements to IFRS Standards 2014 – 2016 Cycle”, which includes, basically, technical and editorial changes to existing standards. The amendments to the standards shall be applied for annual reporting periods beginning on or after January 1, 201823.

On December 12, 2017, the IASB issued the document “Annual Improvements to IFRS Standards 2015 – 2017 Cycle”, which includes, basically, technical and editorial changes to existing standards. The amendments to the standards shall be applied for annual reporting periods beginning on or after January 1, 2019.

Eni is currently reviewing these new IFRSs (other than IFRS 9 and 15) to determine the likely impact on the Group’s financial statements.

Current assets

8 Cash and cash equivalents

Cash and cash equivalents of €7,363 million (€5,674 million at December 31, 2016) included financial assets with maturity of up to three months at the date of inception amounting to €5,591 million (€4,379 million at December 31, 2016) and mainly included short-term deposits with financial institutions having notice of more than 48 hours.

The average maturity of financial assets due within 90 days was 7 days and the average interest rate was negative and amounted to 0.03% (negative 0.01% at December 31, 2016).

9 Financial assets held for trading

(€ million)	December 31, 2017		December 31, 2016
Quoted bonds issued by sovereign states		1,022		996
Other		4,990		5,170
		6,012		6,166

Financial assets held for trading of €6,012 million (€6,166 million at December 31, 2016) related to Eni SpA for €5,793 million (€6,062 million at December 31, 2016) and to Eni Insurance DAC for €219 million (€104 million at December 31, 2016).

(23)

The clarification of the scope of the IFRS 12 “Disclosure of Interests in Other Entities” has been applied from January 1, 2017.

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The Company has established a liquidity reserve as part of its internal targets and financial strategy with a view of ensuring an adequate level of flexibility to the Group development plans and of coping with unexpected fund requirements or difficulties in accessing financial markets. The management of this liquidity reserve is performed through trading activities in view of the financial optimization of returns, within a predefined and authorized level of risk tolerance, targeting the preservation of the invested capital and the ability to promptly convert it into cash.

Financial assets held for trading of Eni SpA include securities subject to lending agreements of €845 million (€665 million at December 31, 2016).

The breakdown by currency is provided below:

(€ million)	December 31, 2017		December 31, 2016
Euro		4,232		4,319
U.S. dollar		1,025		699
Swiss franc		461		413
British pound		198		632
Australian dollar		79		51
Canadian dollar		17		52
		6,012		6,166

The breakdown by issuing entity and credit rating is presented below:

	Nominal value (€ million)		Fair Value (€ million)		Rating – Moody’s	Rating – S&P
Quoted bonds issued by sovereign states
Fixed rate bonds
Italy		478		477	Baa2	BBB
Poland		53		52	A2	BBB+
United States of America		53		45	Aaa	AA+
Spain		45		41	Baa2	BBB+
Slovenia		33		34	Baa1	A+
Japan		25		21	A1	A+
Ireland		10		10	A2	A+
Canada		11		9	Aaa	AAA
Chile		8		9	Aa3	A+
Slovakia		5		4	A2	A+
Sweden		4		4	Aaa	AAA
Netherlands		2		2	Aaa	AAA
South Korea		1		1	Aa2	AA
		728		709
Floating rate bonds
Italy		300		304	Baa2	BBB
Belgium		7		7	Aa3	AA
United States of America		2		2	Aaa	AA+
		309		313
Total quoted bonds issued by sovereign states		1,037		1,022
Other Bonds
Fixed rate bonds
Quoted bonds issued by industrial companies		2,036		1,922	from Aaa to Baa3	from AAA to BBB-
Quoted bonds issued by financial and insurance companies		1,437		1,409	from Aaa to Baa3	from AAA to BBB-
Quoted bonds issued by supranational institutions		28		25	from Aaa to Aa3	from AAA to AA-
		3,501		3,356
Floating rate bonds
Quoted bonds issued by financial and insurance companies		840		842	from Aaa to Baa3	from AAA to BBB-
Quoted bonds issued by industrial companies		789		754	from Aaa to Baa3	from AAA to BBB-
Quoted bonds issued by supranational institutions		45		38	from Aaa to Aa3	from AAA to AA-
		1,674		1,634
Total other bonds		5,175		4,990
Total other financial assets held for trading		6,212		6,012

The fair value hierarchy is level 1 for €5,140 million and level 2 for €872 million. During 2017, there were no transfers between the different hierarchy levels of fair value.

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10 Financial assets available for sale

(€ million)	December 31, 2017		December 31, 2016
Securities held for non-operating purposes
Quoted bonds issued by sovereign states		190		210
Quoted securities issued by financial institutions		17		28
		207		238

The breakdown by currency is provided below:

(€ million)	December 31, 2017		December 31, 2016
Euro		176		199
U.S. Dollar		31		39
		207		238

At December 31, 2017, bonds issued by sovereign states amounted to €190 million (€210 million at December 31, 2016). The breakdown is presented below:

	Nominal value (€ million)		Fair Value (€ million)		Nominal rate of return (%)	Maturity date	Rating – Moody’s	Rating – S&P
Fixed rate bonds
Belgium		27		30	from 3.75 to 4.25	from 2019 to 2021	Aa3	AA
Spain		25		27	from 1.40 to 5.50	from 2018 to 2021	Baa2	BBB+
France		17		19	from 1.00 to 3.25	from 2018 to 2023	Aa2	AA
Poland		15		18	from 4.50 to 6.38	from 2019 to 2022	A2	BBB+
Ireland		17		18	from 0.80 to 4.50	from 2019 to 2022	A2	A+
Iceland		14		15	from 2.50 to 5.88	from 2020 to 2022	A3	A
Italy		14		15	from 0,65 to 3,50	from 2018 to 2020	Baa2	BBB
Portugal		7		8	4.75	2019	Ba1	BBB-
Czech Republic		7		8	3.63	2021	A1	AA-
Slovenia		8		8	2.25	2022	Baa1	A+
Slovakia		7		7	1.50	2018	A2	A+
United States of America		6		6	from 1.25 to 3.13	from 2019 to 2020	Aaa	AA+
Canada		5		5	1.63	2019	Aaa	AAA
Finland		5		5	1.75	2019	Aa1	AA+
Netherlands		1		1	4.00	2018	Aaa	AAA
Total		175		190

Quoted securities amounting to €17 million (€28 million at December 31, 2016) were issued by financial institutions with a rating from Aaa to Aa1 (Moody’s) and from AAA to AA+ (S&P).

The Group’s insurance company Eni Insurance DAC held securities of €207 million at the balance sheet date (€238 million at December 31, 2016). From 2016, European insurance companies have been waived from retaining certain amounts of financial assets to fund the loss provisions based on new capital and solvency requirements enacted by the EU Solvency II Directive. Therefore, those securities are no longer held for operating purposes and are part of the Group liquidity reserve.

The effects of fair value measurement of securities are set out below:

(€ million)	Fair value		Deferred tax liabilities		Other reserves of shareholders' equity
Carrying amount at December 31, 2016		5		(1)		4
Changes recognized in equity		(5)		1		(4)
Carrying amount at December 31, 2017

The fair value was determined based on market quotations. The fair value hierarchy is level 1.

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11 Trade and other receivables

(€ million)	December 31, 2017		December 31, 2016
Trade receivables		10,182		11,186
Financing receivables
- for operating purposes – short-term		84		86
- for operating purposes – current portion of long-term receivables		23		72
- for non-operating purposes		209		385
		316		543
Other receivables
- from disposals		597		171
- other		4,642		5,693
		5,239		5,864
		15,737		17,593

Trade receivables decreased by €1,004 million, of which €706 million related to the Gas & Power segment.

At December 31, 2017, Eni sold without recourse trade receivables due in 2018 for €2,051 million (€1,769 million at December 31, 2016 due in 2017). Derecognized receivables related to the Gas & Power segment for €1,722 million and to the Refining & Marketing and Chemical segment for €329 million (€1,434 million e €335 million at December 31, 2016, respectively).

Receivables are stated net of the valuation allowance for doubtful accounts of €2,729 million (€2,371 million at December 31, 2016):

(€ million)	Trade receivables		Financing receivables		Other receivables		Total
Carrying amount at December 31, 2016		1,817		68		486		2,371
Additions		539		31		388		927
Deductions		(448)		(1)		(6)		(455)
Other changes		(60)		(8)		(77)		(114)
Carrying amount at December 31, 2017		1,848		90		791		2,729

Additions to the allowance for doubtful accounts amounted to €539 million (€503 million in 2016) and related essentially to: (i) the Gas & Power segment for €446 million, particularly in the retail business. Eni adopted mitigation measures regarding the counterparty risk leveraging on specific actions of credit recovery and specialized external services; (ii) the Exploration & Production segment for €55 million and include impairments of trade receivables towards Venezuelan counterparties for €19 million.

Deductions amounting to €448 million (€607 million in 2016) related to the Gas & Power segment for €400 million and related to the recognition of losses on doubtful accounts in the retail business.

The aging of trade and other receivables is presented below:

	December 31, 2017				December 31, 2016
(€ million)	Trade receivables		Other receivables		Trade receivables		Other receivables
Neither impaired nor past due		8,800		4,604		9,243		4,869
Impaired (net of the valuation for doubtful accounts)		567		31		759		432
Not impaired and past due in the following periods:
- within 90 days		478		21		744		58
- 3 to 6 months		46		9		49		81
- 6 to 12 months		147		202		69		249
- over 12 months		144		372		322		175
		815		604		1,184		563
		10,182		5,239		11,186		5,864

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The Group has not booked any counterparty loss on certain trade and other receivables which were overdue at the balance sheet date, because they pertained to highly-rated Italian and foreign public administrations, to other highly-reliable counterparties for supplies of oil, natural gas, refined and chemical products and to retail customers of the Gas & Power segment overdue by less than 90 days.

Trade receivables of the Exploration & Production segment outstanding at December 31, 2017 amounted to €1,323 million (€1,764 million at December 31, 2016) and included receivables of €438 million (€611 million at December 31, 2016) in connection with supplies of equity hydrocarbons to State-owned oil companies in Egypt. The overdue amount of €420 million ($443 million) outstanding as of 31 December 2016 was completely collected during 2017 through the implementation of commercial and industrial agreements with the counterparties which dated back to 2015 when the Company started its actions to address the issue of overdue trade receivables in Egypt. Furthermore, the amount included receivables due by State-owned companies in Iran. The overdue amount of €264 million outstanding as of 31 December 2016 was completely collected in 2017 through the implementation of a Settlement Agreement signed in 2015. Under the terms of the agreement, an Eni’s subsidiary imported and traded volumes of crude oil owned by the Iranian state companies, attributing Eni a rate of the proceeds of each deal.

Trade receivables in currencies other than euro amounted to €2,942 million (€3,629 million at December 31, 2016).

Financing receivables not associated with operating activities amounted to €209 million (€385 million at December 31, 2016) and related to: (i) deposits of Eni Insurance DAC for €127 million (€225 million at December 31, 2016); (ii) restricted deposits in escrow for €68 million of Eni Trading & Shipping SpA (€137 million at December 31, 2016) of which €39 million with BNP Paribas and €29 million with third counterparties.

Financing receivables in currencies other than euro amounted to €82 million (€121 million at December 31, 2016).

Other receivables net of allowances for doubtful account were as follows:

(€ million)	December 31, 2017		December 31, 2016
Receivables originated from divestments		597		171
Accounts receivable from
- joint venture partners in exploration and production		3,369		4,111
- prepayments for services		261		372
- insurance companies		157		147
- non-financial government entities		2		49
- factoring arrangements		28		81
- non-Italian oil entities for oil tax refunds		32		40
- other receivables		793		893
		4,642		5,693
		5,239		5,864

Receivables from divestments amounted to €597 million (€171 million at December 31, 2016) and related: (i) for €153 million (€166 million at December 31, 2016) to the third and last instalment of a receivable on the divestment of a 1.71% interest in the Kashagan project to the local partner KazMunayGas based on the agreements defined between the international partners of the North Caspian Sea PSA and the Kazakh government, which enacted a new contractual framework for managing project operations. The repayment scheme of the receivable was triggered by achievement of the agreed target production level of the Kashagan field that was reached in 2016; (ii) the current portion of the deferred consideration of the divestment of the two interests of respectively 10% and 30% in the Zohr project in Egypt for an overall amount of €442 million ($530 million). The recovery of the receivable is expected by May and June 2018. The non-current portion is provided in note 23 — Other non-current assets.

Other receivables of €4,642 million (€5,693 million at December 31, 2016) included €3,369 million (€4,111 million at December 31, 2016) of receivables owed by Eni’s partners in unincorporated joint ventures that are currently executing exploration and production projects. The largest outstanding amount

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as of December 31, 2017 related to local partners in Nigeria (€1,507 million) and among these, in particular: (a) receivables for the cash calls due by the Nigerian national oil company NNPC for €713 million (€716 million at December 31, 2016). Changes from the previous year related to receivables accrued during the year for €484 million and collections of €398 million, of which €350 million related to receivables accrued during the year. The closing balance included overdue receivables of €646 million ($775 million) relating to the cash calls due by the State oil Company in projects operated by Eni subject to a repayment agreement. Under the terms of the agreement, the overdue amounts will be reimbursed to Eni through the sale of the production entitlement pertaining to the State Company derived from development projects with low risk profile (rigless). Based on Eni’s Brent price scenario, the reimbursement will be accomplished over a time horizon of three to five years. Consequently, these overdue receivables of €570 million ($684 million) are stated in the balance sheet net of discount factor; (b) a receivable related to contractual recovery of costs incurred for an operated oil project under arbitration procedure of €153 million. The opening balance of €382 million included another receivable related to a non-operated oil project that has been completely written down in 2017 for €214 million. The assumptions for the recovery of the outstanding receivable through a commercial agreement are confirmed.

Additions to the allowance for doubtful accounts of other receivables of €388 million mainly related to the Exploration & Production segment for €375 million and were mainly taken in connection with the receivables described in the paragraph above and towards the State owned Venezuelan company PDVSA.

Other receivables in currencies other than euro amounted to €4,799 million (€5,253 million at December 31, 2016).

Because of the short-term maturity and conditions of remuneration of trade and other receivables, the fair value approximated the carrying amount.

Receivables with related parties are described in note 47 — Transactions with related parties.

12 Inventories

	December 31, 2017								December 31, 2016
(€ million)	Crude oil, gas and petroleum products		Chemical products		Other		Total		Crude oil, gas and petroleum products		Chemical products		Other		Total
Raw and auxiliary materials and consumables		785		140		1,640		2,565		550		135		1,903		2,588
Products being processed and semi-finished products		133		7				140		99		9		1		109
Work in progress						1		1						2		2
Finished products and goods		1,287		489		83		1,859		1,394		389		86		1,869
Certificates and emission rights						56		56						69		69
		2,205		636		1,780		4,621		2,043		533		2,061		4,637

Other inventories of raw and auxiliary materials and consumables of €1,640 million (€1,903 million at December 31, 2016) related to the Exploration & Production segment for €1,441 million (€1,699 million at December 31, 2016) and primarily comprised materials relating to perforation activities and the maintenance of infrastructures and facilities.

Certificates and emission rights of €56 million (€69 million at December 31, 2016) are measured at the fair value determined based on market quotations. The fair value hierarchy is level 1.

Inventories of €86 million (€82 million at December 31, 2016) were pledged to guarantee the estimated imbalance in volumes input to/off-taken from the national gas network operated by Snam Rete Gas SpA.

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Changes in inventories and in the loss provision were as follows:

	2017						2016
(€ million)	Gross carrying amount		Loss provision		Net carrying amount		Gross carrying amount		Loss provision		Net carrying amount
Carrying amount at the beginning of the year		4,892		(255)		4,637		4,887		(308)		4,579
Changes		314				314		(29)				(29)
New or increased provisions				(81)		(81)				(125)		(125)
Deductions				18		18				163		163
Currency translation differences		(254)		22		(232)		61		(5)		56
Other changes		(86)		51		(35)		(27)		20		(7)
Carrying amount at the end of the year		4,866		(245)		4,621		4,892		(255)		4,637

Changes of the period amounting to €314 million related to the business lines Refining & Marketing for €192 million and Chemical for €129 million. Loss provision of €245 million related to the Exploration & Production segment for €191 million.

13 Current tax assets

(€ million)	December 31, 2017		December 31, 2016
Italian subsidiaries		99		134
Subsidiaries outside Italy		92		249
		191		383

Income taxes are described in note 43 — Income tax expense.

14 Other current tax assets

(€ million)	December 31, 2017		December 31, 2016
VAT		452		447
Excise and customs duties		217		161
Other taxes and duties		60		81
		729		689

15 Other current assets

(€ million)	December 31, 2017		December 31, 2016
Fair value of derivative financial instruments		1,231		2,248
Other current assets		342		343
		1,573		2,591

The fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments.

Other assets amounting to €342 million (€343 million at December 31, 2016) included gas volumes prepayments of €63 million that were made in previous reporting periods due to the take-or-pay obligations in the Company’s long-term supply contracts, as the Company is forecasting to make-up the underlying gas volumes in the next 12 months (€90 million at December 31, 2016). The non-current portion is indicated in note 23 — Other non-current assets.

Transactions with related parties are described in note 47 — Transactions with related parties.

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Non-current assets

16 Property, plant and equipment

(€ million)	Land		Buildings		Plant and machinery		Industrial and commercial equipment		Other assets		Tangible assets in progress and advances		Total
2017
Net book amount at the beginning of the year		448		810		50,270		300		309		18,656		70,793
Additions		2		20		153		27		52		8,236		8,490
Depreciation				(71)		(6,996)		(63)		(69)				(7,199)
Net (impairments) reversals		(5)		(5)		436		(1)		(5)		(213)		207
Disposals		(12)		(3)		3				(6)		(1,430)		(1,448)
Write-off						(3)		(2)				(234)		(239)
Currency translation differences		(2)		(3)		(5,272)		(8)		(18)		(1,722)		(7,025)
Other changes		47		87		10,571		(17)		(2)		(11,107)		(421)
Net book amount at the end of the year		478		835		49,162		236		261		12,186		63,158
Gross book amount at the end of the year		571		3,490		160,751		1,264		1,954		15,747		183,777
Provisions for depreciation and impairments		93		2,655		111,589		1,028		1,693		3,561		120,619
2016
Net book amount at the beginning of the year		510		818		40,667		326		403		25,281		68,005
Additions		1		22		204		32		42		8,766		9,067
Depreciation				(66)		(7,087)		(66)		(89)				(7,308)
Net (impairments) reversals		(64)		(3)		345		(1)		(17)		(174)		86
Write-off						(198)		(2)				(89)		(289)
Currency translation differences		1		1		1,329				4		551		1,886
Reclassification to assets held for sale		(8)		(2)		(1)								(11)
Other changes		8		40		15,011		11		(34)		(15,679)		(643)
Net book amount at the end of the year		448		810		50,270		300		309		18,656		70,793
Gross book amount at the end of the year		537		3,416		167,007		1,415		2,160		22,737		197,272
Provisions for depreciation and impairments		89		2,606		116,737		1,115		1,851		4,081		126,479

A breakdown by segment of capital expenditures is provided below:


(€ million)	2017		2016
Capital expenditures
Exploration & Production		7,638		8,217
Gas & Power		87		66
Refining & Marketing and Chemical		712		655
Corporate and other activities		69		42
Elimination of intragroup profits		(16)		87
		8,490		9,067

Capital expenditures included capitalized finance expenses of €72 million (€105 million in 2016) related to the Exploration & Production segment (€56 million). The interest rates used for capitalizing finance expense ranged from 1.6% to 2.7% (2.7% to 5.3% at December 31, 2016).

The main depreciation rates used were substantially unchanged from the previous year and ranged as follows:

(%)
Buildings			2 - 10
Mineral exploration wells and plants			UOP
Refining and chemical plants			2 - 17
Gas pipelines and compression stations			2 - 12
Power plants			5
Other plant and machinery			6 - 12
Industrial and commercial equipment			5 - 25
Other assets			10 - 20

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The criteria adopted by Eni for determining net (impairments) reversals is reported in note 19 — Impairment/reversal of tangible and intangible assets.

Disposals of €1,448 million included the disposal of a 40% interest in the Zohr asset in Egypt for €1,328 million to BP (10%) and Rosneft (30%) with a gain of €1,281 million. The deferred consideration amounted to €553 million ($663 million), of which €442 million ($530 million) will be collected by June 2018 (Notes 11 — Trade and other receivables and note 23 — Other non-current assets).

Write-off of €239 million (€289 million in 2016) related for €237 million to the Exploration & Production (€93 million in 2016), of which €217 million relating to suspended exploration wells that did not encountered enough quantities of commercial hydrocarbons to justify their completion as productive wells in particular in Egypt, Norway and Ivory Coast.

The amount of €7,025 million relates to currency translations from U.S. dollar for €6,533 million.

Other negative changes of €421 million included the net effect of the divestment to ExxonMobil of a 35.7% interest in the joint operation Mozambique Rovuma Venture SpA (former Eni East Africa SpA), concessionaire of the Area 4 offshore Mozambique where development is underway, for €648 million. This effect was partially offset by an increase in capitalized asset retirement costs in the Exploration & Production segment amounting to €355 million (€665 million at December 31, 2016) mainly due to a decrease in the discount rate curve, especially for the U.S. dollar, to the recognition of new retirement obligations and the revision of cost estimates.

Property, plant and equipment include costs related to exploration activities and appraisal and tangible assets in progress and advances of the Exploration & Production segment:

(€ million)	Exploratory wells in progress		Exploratory wells completed and being evaluated		Exploratory successful wells in progress		Exploration activity and appraisal		Unproved mineral interest		Wells and installments in progress		Abandonment costs		Other tangible assets in progress		Total
2017
Book amount at the beginning of the year		221		1,684		913		2,818		2,450		11,690		82		14,222		17,040
Additions		351						351		112		7,190				7,302		7,653
Net (impairments) reversals						(13)		(13)		147		(111)				36		23
Write-off		(11)		(217)				(228)				(2)				(2)		(230)
Reclassifications		(438)		173		(117)		(382)		(7)		(9,538)		(11)		(9,556)		(9,938)
Other changes and currency translation differences		(15)		(377)		(294)		(686)		(312)		(2,676)		(34)		(3,022)		(3,708)
Book amount at the end of the year		108		1,263		489		1,860		2,390		6,553		37		8,980		10,840
2016
Book amount at the beginning of the year		93		1,737		807		2,637		2,212		19,458				21,670		24,307
Additions		402						402		2		7,777				7,779		8,181
Net (impairments) reversals						(5)		(5)		190		(210)				(20)		(25)
Write-off				(109)				(109)				(6)		27		21		(88)
Reclassifications		(282)		6		78		(198)		(35)		(15,699)				(15,734)		(15,932)
Other changes and currency translation differences		8		50		33		91		81		370		55		506		597
Book amount at the end of the year		221		1,684		913		2,818		2,450		11,690		82		14,222		17,040

Reclassifications of €9,938 million mainly related to: (i) development wells and plants in progress for €9,538 million; (ii) exploratory successful wells for €382 million following the production start-up of the underlying projects during 2017 in Angola, Ghana, Indonesia and Egypt.

Changes in exploration and appraisal activities comprised: (i) reclassifications of €438 million of exploratory wells in progress to completed exploration wells that are suspended pending final determination; (ii) write-offs of €228 million related to unsuccessful exploration wells.

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The following information relates to the stratification of the suspended wells pending final determination (aging):


(€ million)	2017		2016		2015
Costs for exploratory wells suspended at the beginning of the period		1,684		1,737		1,568
Increases for which is ongoing the determination of proved reserves		451		282		550
Amounts previously capitalized and expensed in the period		(217)		(109)		(501)
Reclassification to successful exploratory wells following the estimation of proved reserves		(278)		(276)		(30)
Disposals		(199)				(4)
Currency translation differences		(178)		50		154
Costs for exploratory wells suspended at the end of the period		1,263		1,684		1,737


	2017				2016				2015
	(€ million)		(number of wells in Eni’s interest)		(€ million)		(number of wells in Eni’s interest)		(€ million)		(number of wells in Eni’s interest)
Costs capitalized and suspended for exploratory well activity
- within 1 year		222		7.95		16		1.05		368		5.32
- between 1 and 3 years		241		3.87		609		10.25		634		11.14
- beyond 3 years		800		21.44		1,059		21.55		735		18.97
		1,263		33.26		1,684		32.85		1,737		35.43
Costs capitalized for suspended wells
- fields including wells drilled over the last 12 months		148		5.88		9		0.55		368		5.32
- fields for which the delineation campaign is in progress		261		4.69		251		3.51		228		4.13
- fields including commercial discoveries that proceeds to sanctioning		854		22.69		1,424		28.79		1,141		25.98
		1,263		33.26		1,684		32.85		1,737		35.43

Unproved mineral interests include costs allocated to unproved reserves following business combinations or costs incurred to acquire individual properties. Unproved mineral interests were as follows:

(€ million)	Congo		Nigeria		Turkmenistan		USA		Algeria		Egypt		Total
2017
Book amount at the beginning of the year		1,254		938		138		113				7		2,450
Additions										112				112
Net (impairments) reversals		72				75								147
Reclassification to proved mineral interest		(7)												(7)
Other changes and currency translation differences		(157)		(113)		(21)		(14)		(7)				(312)
Book amount at the end of the year		1,162		825		192		99		105		7		2,390
2016
Book amount at the beginning of the year		1,021		908		165		109				9		2,212
Additions												2		2
Net (impairments) reversals		190												190
Reclassification to proved mineral interest						(31)						(4)		(35)
Other changes and currency translation differences		43		30		4		4						81
Book amount at the end of the year		1,254		938		138		113				7		2,450

Unproved mineral interest of €2,390 million comprised a property known as Oil Prospecting License 245 (“OPL 245”), located offshore Nigeria, with a net book value of €818 million, which corresponded to the price paid to the Nigeria Government to acquire a 50% interest in OPL 245, with the partner Shell acquiring the remaining 50%. As of December 31, 2017, the net book value of the property was €1,107 million, including capitalized exploration costs and pre-development costs. The acquisition of OPL

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245 is subject to judicial proceedings in Italy and in Nigeria for alleged corruption and money laundering in respect of the Resolution Agreement signed on April 29, 2011, relating to the purchase of the license by Eni and Shell. Those proceedings are disclosed in note 38 — Guarantees, Commitments and Risks. Additions of the year of €112 million related to the extension of an oil contract in Algeria.

Accumulated provisions for impairments amounted to €16,005 million (€17,558 million at December 31, 2016).

At December 31, 2017, Eni pledged property, plant and equipment for €24 million primarily as collateral against certain borrowings (same amount as of December 31, 2016).

Government grants recorded as a decrease of property, plant and equipment amounted to €110 million (€90 million at December 31, 2016).

Assets acquired under financial lease agreements amounted to €29 million (same amount as of December 31, 2016) and related to service stations of the Refining & Marketing business line.

Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 38 — Guarantees, commitments and risks — Liquidity risk.

Property, plant and equipment under concession arrangements are described in note 38 — Guarantees, commitments and risks — Assets under concession arrangements.

Property, plant and equipment by segment

(€ million)	December 31, 2017		December 31, 2016
Property, plant and equipment, gross
Exploration & Production		152,608		165,559
Gas & Power		5,333		6,276
Refining & Marketing and Chemical		24,554		24,119
Corporate and other activities		1,866		1,886
Elimination of intragroup profits		(584)		(568)
		183,777		197,272
Accumulated depreciation, amortization and impairment losses
Exploration & Production		95,775		101,131
Gas & Power		3,954		4,584
Refining & Marketing and Chemical		19,625		19,477
Corporate and other activities		1,525		1,518
Elimination of intragroup profits		(260)		(231)
		120,619		126,479
Property, plant and equipment, net
Exploration & Production		56,833		64,428
Gas & Power		1,379		1,692
Refining & Marketing and Chemical		4,929		4,642
Corporate and other activities		341		368
Elimination of intragroup profits		(324)		(337)
		63,158		70,793

17 Inventory — compulsory stock

Compulsory inventories of €1,283 million (€1,184 million at December 31, 2016) were primarily held by Italian subsidiaries for €1,267 million (€1,167 million at December 31, 2016) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws.

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18 Intangible assets

(€ million)	Exploration rights		Industrial patents and intellectual property rights		Concessions, licenses, trademarks and similar items		Service concession arrangements		Intangible assets in progress and advances		Other intangible assets		Intangible assets with finite useful lives		Intangible assets with indefinite useful lives – Goodwill		Total
2017
Net book amount at the beginning of the year		1,092		255		259		31		148		164		1,949		1,320		3,269
Additions		91		5		17		1		60		17		191				191
Amortization		(65)		(110)		(84)		(2)				(25)		(286)				(286)
Net (impairments) reversals		18												18				18
Write-off		(24)												(24)				(24)
Currency translation differences		(115)				(1)						(2)		(118)		(23)		(141)
Other changes		(2)		32		49				(74)		(14)		(9)		(93)		(102)
Net book amount at the end of the year		995		182		240		30		134		140		1,721		1,204		2,925
Gross book amount at the end of the year		1,504		2,485		1,466		52		140		1,101		6,748
Provisions for amortization and impairments		509		2,303		1,226		22		6		961		5,027
2016
Net book amount at the beginning of the year		735		363		276		32		148		166		1,720		1,314		3,034
Additions		15		6		26		1		49		16		113				113
Amortization		(18)		(113)		(81)		(2)				(39)		(253)				(253)
Net (impairments) reversals		385										4		389				389
Write-off		(61)												(61)				(61)
Currency translation differences		36										(4)		32		6		38
Other changes				(1)		38				(49)		21		9				9
Net book amount at the end of the year		1,092		255		259		31		148		164		1,949		1,320		3,269
Gross book amount at the end of the year		2,216		2,462		1,467		52		153		2,599		8,949
Provisions for amortization and impairments		1,124		2,207		1,208		21		5		2,435		7,000

Exploration rights of €995 million (€1,092 million at December 31, 2016) comprised the residual book value of license and leasehold property acquisition costs relating to areas with proved reserves, which are amortized based on the UOP criteria and are regularly reviewed for impairment. Furthermore, they include the cost of unproved areas which are suspended pending a final determination of the success of the exploratory activity or until management confirms its commitment to the initiative. Capital expenditures of €91 million in the year (€15 million in 2016) related to signature bonus for the acquisition of new exploration acreage in Cyprus, Myanmar, Ivory Coast and the Isatay block in Kazhakstan.

The breakdown of exploration rights by type of asset was as follows:

(€ million)	December 31, 2017		December 31, 2016
Proved licence and leasehold property acquisition costs		403		497
Unproved licence and leasehold property acquisition costs		586		579
Other mineral interests		6		16
		995		1,092

Concessions, licenses, trademarks and similar items for €182 million (€255 million at December 31, 2016) primarily comprised transmission rights for natural gas imported from Algeria of €141 million (€223 million at December 31, 2016).

Industrial patents and intellectual property rights of €240 million (€259 million at December 31, 2016) related to Eni gas e luce SpA for €121 million and Eni SpA for €108 million (€235 million at December 31, 2016) and essentially concerned costs for the acquisition and internal development of software and rights for the use of production processes and software.

Intangible assets in progress and advances of €134 million (€148 million at December 31, 2016) related for €78 million (€89 million at December 31, 2016) to capital expenditures in progress on natural gas pipelines for which Eni has acquired transport rights.

Other intangible assets with finite useful lives of €140 million (€164 million at December 31, 2016) comprised: (i) royalties for the use of licenses by Versalis SpA for €37 million (€40 million at December 31, 2016); (ii) the estimated costs of Eni’s social responsibility projects in relation to oil development programs in Val d’Agri and in the North Adriatic area connected to mineral rights under concession for €35 million (€41 million at December 31, 2016) following commitments made with the Basilicata Region, the Emilia Romagna Region and the Province and Municipality of Ravenna.

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Other changes of goodwill of €93 million in 2017 related to the change in the scope of consolidation due to the sale to third parties of the company Eni Gas & Power NV subsidiary to which included the goodwill deriving from the former acquisition in Belgium of Nuon Belgium NV was allocated.

The criteria adopted by Eni for determining net impairments/reversals and the relevant breakdown by segment are reported in note 19 — Impairment/reversal of tangible and intangible assets.

The main amortization rates used were substantially unchanged from the previous year and ranged as follows:

(%)
Exploration rights			UOP - 33
Transport rights of natural gas			3
Other concessions, licenses, trademarks and similar items			3 - 33
Service concession arrangements			20 - 33
Other intangible assets			4 - 20

The carrying amount of goodwill at the end of the year was €1,204 million (€1,320 million at December 31, 2016) net of cumulative impairments charges amounting to €2,414 million (€2,524 million at December 31, 2016).

A breakdown of the stated goodwill by operating segment is provided below:

(€ million)	December 31, 2017		December 31, 2016
Gas & Power		932		1,025
Exploration & Production		179		202
Refining & Marketing		93		93
		1,204		1,320

More information about goodwill is reported in note 19 — Impairment/reversal of tangible and intangible assets.

19 Impairment/reversal of tangible and intangible assets


(€ million)	2017		2016
Impairment losses
Tangible assets		(848)		(1,067)
Intangible assets		(14)
		(862)		(1,067)
less:
- reversal of tangible assets		1,055		1,153
- reversal of intangible assets		32		389
		225		475

In assessing whether impairment is required, the carrying amounts of the assets are compared with their recoverable amounts. The recoverable amount is the higher between an asset’s fair value less costs to sell and its value-in-use. In the event of an asset’s impairment being reversed, the reversal may not raise the carrying amount above the value it would have stood at taking into account depreciation, if no impairment had originally been recognized.

Given the nature of Eni’s activities, information on asset fair value is usually difficult to obtain unless negotiations with a potential buyer are ongoing. Therefore, the recoverability is verified by estimating assets’ values-in-use (VIU). The valuation is carried out for individual assets or for the smallest identifiable group of assets that generates cash inflows that are largely independent from the cash inflows from other assets, or groups of assets (cash generating unit — CGU). The Group has identified the following CGUs: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields when technical, economic or contractual features make underlying cash flows interdependent; (ii) in the Gas & Power

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segment, in addition to the CGUs to which goodwill arisen from business combinations was allocated, electricity generation plants, international pipelines and LNG vessels; (iii) in the Refining & Marketing business line, refining plants, retail networks and assets related to other distribution channels grouped by country of operations and type of network (retail outlets located along ordinary routes and high-ways, wholesale facilities); and (iv) the Chemical business line has been assessed to be a single CGU.

The value-in-use is calculated by discounting the estimated future cash flows deriving from the continuing use of the CGUs and, if significant and reasonably determinable, the cash flows deriving from disposal at the end of their useful lives. Cash flows are determined based on the best information available at the time of the assessment. Cash flow projections for the first four years of each CGU evaluation are extracted from the Company’s four-year plan adopted by the top management. The plan includes data points on expected oil&gas production volumes, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates. The estimation of CGUs’ terminal values is based on cash flow projections beyond the four-year plan horizon, which are estimated based on management’s long-term assumptions regarding the main macroeconomic variables (inflation rates, commodity prices, etc.) and considering the expected useful lives of the Company’s CGUs and certain assumptions regarding future trends in revenues and costs. In the case of the oil&gas CGUs, management assumed the residual life of the reserves and the associated projections of operating costs and development expenditures. The CGUs of the Refining & Marketing business line and power plants are evaluated based on the plant economic and technical life and the associated, normalized projections of operating costs and expenditures to support plant efficiency. The CGUs of the gas market business to which goodwill has been allocated are evaluated based on the perpetuity method of the last year-plan result assuming nominal growth rates equal to 0%. The terminal value of the Chemical business integrated CGU considers the average economic useful life of the underlying assets and factors a normalized EBITDA (to reflect the cyclicality of the sector) defined based on the average contribution margin of the plan. In projecting future commodity prices, management assumed the price scenario adopted for the economic and financial projections of the Company’s four-year industrial plans and for the assessment of capital projects returns. The Company’s price scenario is approved by the Board of Directors and is based on internal assumptions about future trends in the fundamentals of demand and supply of crude oil and other commodities as benchmarked against the market consensus forecasts and on forward prices of commodities for future delivery in case the level of liquidity and reliability of future contracts is deemed fair.

Values-in-use is estimated by discounting post-tax cash flows at a rate, which corresponds for the Exploration & Production and Refining & Marketing to the Company’s weighted average cost of capital (WACC) net of the risk factors attributable to the Gas & Power segment and the Chemical business line, the WACC of which is assessed on a stand-alone basis. Then the discount rates are adjusted to factor in risks specific to each country of activity (adjusted post-tax WACC). Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

At the date of Eni’s valuations relating to the recoverability of fixed assets, the impairment indicators related to external factors showed an improvement in respect to the external scenario utilized in 2016 impairment review.

During 2017, the oil market staged a gradual recovery, which gained strength in the last part of the year, driven by improving market fundamentals. Global demand for crude oil increased due to macroeconomic expansion and oversupplies were curbed due to full implementation of the OPEC agreement on production cuts, joined also by important non-OPEC countries (in particular Russia) and the decision to extend it throughout 2018. These developments allowed for a reduction in global levels of crude oil inventories that had slowed down the recovery in prices in the first half of the year. Based on those improved fundamentals and considering the existing uncertainties about the medium-term evolution of the demand and supply balance, 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 $71.4) in elaborating the Group financial projections of the 2018 – 2021 industrial plan and the estimations of asset recoverability as of December 31, 2017. The profitability margin of the refining activity was confirmed at 5$/bl for the long period; stable forecasts also for gas prices at the main European hubs and for the spreads between those prices and the projected spot prices in Italy. The price/margin scenario in the petrochemical business is expected to improve driven by a better macroeconomic outlook. The long-term forecasts are expected to be weak for the clean spark spread of electricity due to oversupply and competition from other fuel/sources of power generation.

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At the balance sheet date, the market capitalization of Eni amounting to €50 billion exceeded the book value of the consolidated net assets equal to €48 billion. Despite the Group outlook of its impairment indicators has somewhat improved from one year ago, management tested for impairment the totality of the Group’s fixed assets as provided by the Company’s internal guidelines.

The 2017 WACC of Eni, which is the driver for calculating the WACC of the oil&gas and refining business segments to assess the value-in-use of their relevant CGUs, recorded a marginal increase, up by 0.4 percentage point to 6.8% compared to 2016. This increase was driven by a of the projections of higher risk-free yields. The WACC used in the Chemical business line decreased by 0.5 percentage point to 8.5% driven by a reduced share volatility of the panel of quoted chemical companies utilized to estimate the WACC of the Eni chemical business. The WACC in the Gas & Power segment increased by 0.2 percentage points to 6% due to a higher country risk of some activities outside Europe. The adjusted WACC rates for 2017 highlighted dispersion of values reflecting a noticeable increase in the country risk in certain upstream areas. The adjusted WACC rates used for impairment test purposes in 2017 ranged from 5.3% to 15.8% in the Exploration & Production segment.

In the Exploration & Production segment the Company recorded reversals of previous impairment losses before taxes for a total of €776 million reflecting upward reserves revisions and costs reductions in relation to assets located in the UK, Turkmenistan and Congo and the effects of the US tax reform. Impairment losses for a total of €636 million before taxes mainly concerned assets in Algeria, Italy, USA, Congo and Venezuela driven by downward reserve revisions, re-phasing of development plans, project cancellation and the country risk. The post-tax WACC relating to reversals of impairments of more than €100 million are in a range of 5.5 – 13.5%, corresponding to pre-tax rates ranging from 8.6% to 25.6%, respectively.

In the Refining & Marketing business line the Company recorded impairment losses for €130 million related to the investments of the year for compliance and stay-in-business related to CGUs fully impaired in prior years for which profitability expectations have remained unchanged from the previous-year impairment review.

In the Gas & Power segment the Company recorded net reversals of previous impairment losses for €146 million primarily reflecting alignment to fair value of the gas distribution activities in Hungary for which the Company signed a preliminary selling agreement in 2018. Such effect was partially offset by the impairment of certain power plants due to a negative margins outlook and of a gas transportation infrastructure deriving from the increase in the discount rate adjusted for the country risk.

A breakdown by segment of impairments of tangible assets recorded and the associated tax effect is provided below:


(€ million)	2017		2016
Impairments
Exploration & Production		(636)		(740)
Gas & Power		(56)		(167)
Refining & Marketing and Chemical		(131)		(120)
Corporate and other activities		(25)		(40)
		(848)		(1,067)
Tax effects
Exploration & Production		91		216
Gas & Power		12		35
Refining & Marketing and Chemical		35		32
Corporate and other activities		6
		144		283
Impairments net of the relevant tax effects
Exploration & Production		(545)		(524)
Gas & Power		(44)		(132)
Refining & Marketing and Chemical		(96)		(88)
Corporate and other activities		(19)		(40)
		(704)		(784)

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A breakdown by segment of reversals of tangible assets recorded and the associated tax effect is provided below:


(€ million)	2017		2016
Reversals
Exploration & Production		776		1,055
Gas & Power		202		86
Refining & Marketing and Chemical		77		12
		1,055		1,153
Tax effects
Exploration & Production		(171)		(315)
Gas & Power		(5)		(28)
Refining & Marketing and Chemical		(24)		(3)
		(200)		(346)
Reversals net of the relevant tax effects
Exploration & Production		605		740
Gas & Power		197		58
Refining & Marketing and Chemical		53		9
		855		807

Goodwill acquired through business combinations has been allocated to the CGUs that are expected to benefit from the synergies of the acquisition.

The amount of goodwill outstanding at the reporting date mainly related to the Gas & Power segment. A breakdown is disclosed below.

(€ million)	December 31, 2017		December 31, 2016
Domestic gas market		835		835
Foreign gas market		97		190
- of which European market		95		188
		932		1,025

Goodwill allocated to the CGU domestic gas market was recognized upon the buy-out of the former Italgas SpA minorities in 2003 through a public offering (€706 million). The acquired entity engaged in the retail sale of gas to the residential sector and middle and small-sized businesses in Italy. In addition, further goodwill amounts have been allocated over the years following business combinations with small, local companies selling gas to residential customers in focused territorial reach and municipalities synergic to Eni’s activities. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of this CGU including any allocated goodwill.

Goodwill allocated to the CGU European gas market, amounting to €95 million, was recorded following the business combinations of Altergaz SA (now Eni Gas & Power France SA) in France. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of the CGU including any allocated goodwill.

In assessing the recoverability of the carrying amount of the Gas & Power CGUs, including the allocated portion of goodwill, management determined the value in use of those CGUs considering the sales margin exclusively of the retail market (excluding the wholesale margins on sales to wholesalers, industrial and power generation customers). The assessment was performed considering the cash flows of the four-year plan approved by management and incorporating the perpetuity of the last year of the plan to determine the terminal value by assuming a nominal long-term growth rate equal to zero, unchanged from the previous reporting period. These cash flows were discounted by using the post-tax WACC adjusted considering the specific country risk of 4.6% for Italy and 5.2% for Europe. Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.

The excess of the recoverable amount of the CGU Domestic gas market over its carrying amount including the allocated portion of goodwill (headroom) amounting to €1,303 million would be reduced to

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zero under each of the following alternative hypothesis: (i) a decrease of 65% on average in the projected commercial margins; (ii) an increase of 9.7 percentage points in the discount rate; and (iii) a negative nominal growth rate of 16.8%.

20 Investments

Equity-accounted investments

(€ million)	2017								2016
(€ million)	Investments in unconsolidated entities controlled by Eni		Joint ventures		Associates		Total		Investments in unconsolidated entities controlled by Eni		Joint ventures		Associates		Total
Book amount at the beginning of the year		168		2,675		1,197		4,040		175		1,275		1,403		2,853
Additions and subscriptions				63		444		507		8		1,085		63		1,156
Divestments and reimbursements						(462)		(462)						(138)		(138)
Share of profit of equity-accounted investments		9		49		66		124		10		50		17		77
Share of loss of equity-accounted investments		(7)		(340)		(6)		(353)		(8)		(208)		(154)		(370)
Deduction for dividends		(32)		(41)		(13)		(86)		(2)		(45)		(53)		(100)
Changes in the scope of consolidation		2						2		5		564				569
Currency translation differences		(13)		(127)		(128)		(268)		5		12		29		46
Other changes		(11)		53		(35)		7		(25)		(58)		30		(53)
Book amount at the end of the year		116		2,332		1,063		3,511		168		2,675		1,197		4,040

In 2017, acquisitions and capital increases of €507 million mainly related to capital contributions to companies engaged in the execution of industrial projects in the interest of Eni: (i) Coral FLNG Ltd (€443 million) which is engaged in the development of a floating production and storage unit of LNG in natural gas-rich Area 4 offshore Mozambique; and (ii) Lotte Versalis Elastomers Co Ltd (€45 million) which is engaged in the production of premium elastomers in South Korea.

Divestments and reimbursements of €462 million related to: (i) the sale of a 25% stake in Coral FLNG SA for €222 million following closing of the sale to ExxonMobil of 50% of the interest held by Eni in Area 4 in Mozambique; and (ii) capital reimbursements of €165 million relating to Coral FLNG SA, €48 million relating to Angola LNG Ltd and €27 million relating United Gas Derivatives Co.

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Eni’s share of profit of equity-accounted investments and deductions for dividends pertained to the following entities:

	2017						2016
(€ million)	Share of profit of equity- accounted investments		Deduction for dividends		% of the investment		Share of profit of equity- accounted investments		Deduction for dividends		% of the investment
Angola LNG Ltd		45				13.60
Eni BTC Ltd				27		100.00		6				100.00
PetroJunín SA		26				40.00		30				40.00
Unimar Llc		3		24		50.00				16		50.00
United Gas Derivatives Co		16		12		33.33		14		14		33.33
Gas Distribution Company of Thessaloniki – Thessaly SA		9		12		49.00		10		10		49.00
PetroSucre SA										30		26.00
Other investments		25		11				17		30
		124		86				77		100

Eni’s share of losses of equity-accounted investments related to the following entities:

	2017				2016
(€ million)	Share of loss of equity- accounted investments		% of the investment		Share of loss of equity- accounted investments		% of the investment
Cardón IV SA		184		50.00		20		50.00
Saipem SpA		101		31.00		144		30.76
Unión Fenosa Gas SA		28		50.00				50.00
Matrìca SpA		17		50.00		4		50.00
PetroSucre SA						92		26.00
Angola LNG Ltd						62		13.60
PetroBicentenario SA						26		40.00
Other investments		23				22
		353				370

Considering risks and uncertainties in connection with the financial outlook of Venezuela, the Company assessed the recoverability of the book value of two equity-accounted entities that are currently engaged in the execution of oil&gas projects in the Country. The two projects are the development of the Perla offshore gas field, operated by the local company Cardón IV, a joint venture with another international oil company, and of the PetroJunín crude oil onshore field, operated by PetroJunín, a joint venture with the state oil company PDVSA under the regime of “Empresa Mixta”. The carrying amounts before any valuation allowance of these two assets comprised current trade receivables and non-current activities, including tangible and intangible assets, equity investments and financing loans related to operations, for an amount of approximately €2 billion. To assess the recoverability of those assets, management performed a review based on empirical evidence and official statistics of the most recent financial crises of sovereign states. On this basis and considering that Eni's gas supplies are strategic and vital to the Country, in determining the recoverable value of the aforementioned assets, management carried out a risk appreciation by projecting a deferral in the timing of credit collection. Furthermore, considering the deterioration in the country's operating environment and the financial risks of recovering the invested capital, management reclassified the proved undeveloped reserves of Perla to the unproved category (315 mmBOE) in line with the US SEC rules on the recognition of proved reserves. Based on these drivers, in the 2017 financial statements management recorded impairment losses at Eni's above mentioned assets in Venezuela for an overall amount of €758 million.

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The accounting under the equity method of Saipem SpA resulted in a loss of €101 million due to the recognition by the investee of restructuring costs, losses from legal proceedings and impairment losses of tangible assets mainly in the offshore drilling business which is impacted by the oil scenario. As of December 31, 2017, the net book value of Eni’s investment in Saipem of €1,413 million was aligned with the corresponding share of the equity of the investee. However, the book value exceeded by about 20% the fair value represented by the market capitalization of Saipem. This impairment indicator is reflective of investor uncertainty about the rebalancing of the fundamentals in the oil sector and the timing of recovery in capital expenditures plans by the clients of the Engineering & Construction sector. The reasonableness of the evaluation was stress-tested applying contingencies to turnover levels and contract margins that confirmed the outcomes of the assessment.

Currency translation differences of €268 million were primarily related to translation of entities accounts denominated in U.S. dollar (€189 million).

Other changes related to the impairment of Unión Fenosa Gas SA for €35 million (€84 million in 2016) due to lower profitability prospects.

The net carrying amount of equity-accounted investments was related to the following entities:

	December 31, 2017						December 31, 2016
(€ million)	Net carrying amount		Number of shares held		% of the investment		Net carrying amount		Number of shares held		% of the investment
Investments in unconsolidated entities controlled by Eni
Eni BTC Ltd		63		34,000,000		100.00		106		34,000,000		100.00
Other investments (*)		53						62
		116						168
Joint ventures
Saipem SpA		1,413		308,767,968		31.00		1,497		3,087,679,689		30.76
Unión Fenosa Gas SA		350		273,100		50.00		434		273,100		50.00
PetroJunín SA		210		96,084,000		40.00		211		96,084,000		40.00
Gas Distribution Company of Thessaloniki – Thessaly SA		137		121,092,526		49.00		150		130,491,508		49.00
Lotte Versalis Elastomers Co Ltd		114		30,179,999		50.00		74		19,200,000		50.00
AET – Raffineriebeteiligungsgesellschaft mbH		32		1		33.33
Cardón IV SA								197		8,605		50.00
Unimar Llc								42		50		50.00
Other investments (*)		76						70
		2,332						2,675
Associates
Angola LNG Ltd		802		1,483,352,000		13.60		916		1.551.760.000		13.60
United Gas Derivatives Co		82		2,600,000		33.33		117		950,000		33.33
Novamont SpA		71		6,667		25.00		77		6,667		25.00
Coral FLNG SA		54		2,500,000		25.00
AET – Raffineriebeteiligungsgesellschaft mbH								34		1		33.33
Other investments (*)		54						53
		1,063						1,197
		3,511						4,040

(*)

Each individual amount included herein was lower than €25 million.

Equity-accounted investments by industry segment are disclosed in note 46 — Information by industry segment and by geographical area.

Carrying amounts of equity-accounted investments included differences between the purchase price of the interest acquired and the book value of the corresponding fraction of net equity amounting to €70 million related to Novamont SpA for €43 million and Unión Fenosa Gas SA for €27 million. These surpluses are due to the long-term profitability outlook of these companies.

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As of December 31, 2017, the market value of the investments listed in stock markets was as follows:

			Number of shares held						% of the investment						Share price (€)						Market value (€ million)
Saipem SpA					308,767,968						31.00						3.806						1,175

The table below sets out the provisions for losses included in the provisions for contingencies of €182 million (€151 million at December 31, 2016), primarily related to the following equity-accounted investments:

(€ million)	December 31, 2017		December 31, 2016
Industria Siciliana Acido Fosforico – ISAF – SpA (in liquidation)		95		95
Matrìca SpA		38
VIC CBM Ltd		30		34
PetroBicentenario SA		12		6
Société Centrale Eletrique du Congo SA		6		7
Other investments		1		9
		182		151

Other investments

	2017								2016
(€ million)	Investments in unconsolidated entities controlled by Eni		Associates		Other investments - valued at cost		Total		Investments in unconsolidated entities controlled by Eni		Associates		Other investments - valued at fair value		Other investments - valued at cost		Total
Net book amount at the beginning of the year		29		10		237		276		25		10		368		257		660
Additions and subscriptions						3		3		5		3						8
Divestments and reimbursements		(6)				(13)		(19)						(368)		(31)		(399)
Currency translation differences				(1)		(22)		(23)				(2)				6		4
Other changes		(9)		(4)		(5)		(18)		(1)		(1)				5		3
Value at the end of the year		14		5		200		219		29		10				237		276
Gross book amount at the end of the year		15		5		207		227		30		10				240		280
Accumulated impairment charges		1				7		8		1						3		4

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The net carrying amount of other investments of €219 million (€276 million at December 31, 2016) was related to the following entities:

	December 31, 2017						December 31, 2016
(€ million)	Net carrying amount		Number of shares held		% of the investment		Net carrying amount		Number of shares held		% of the investment
Investments in unconsolidated entities controlled by Eni (*)		14						29
Associates		5						10
Other investments:
- Nigeria LNG Ltd		99		118,373		10.40		112		118,373		10.40
- Darwin LNG Pty Ltd		32		213,995,164		10.99		49		213,995,164		10.99
- other (*)		69						76
		200						237
		219						276

(*)

Each individual amount included herein was lower than €25 million.

Additional information is included in note 48 — Other information about investments.

21 Other financial assets

(€ million)	December 31, 2017		December 31, 2016
Financing receivables held for operating purposes		1,602		1,785
Securities held for operating purposes		73		75
		1,675		1,860

Financing receivables held for operating purposes are stated net of the valuation allowance for doubtful accounts of €640 million (€480 million at December 31, 2016).

(€ million)	Reserve of allowance for doubtful accounts of financing receivables
Amount at December 31, 2016		480
Additions		211
Currency translation differences		(49)
Other changes		(2)
Amount at December 31, 2017		640

Financing receivables held for operating purposes of €1,602 million (€1,785 million at December 31, 2016) primarily pertained to loans granted by the Exploration & Production segment (€1,433 million) and the Gas & Power segment (€96 million).

Financing receivables granted to joint ventures and associates amounted to €1,214 million (€1,350 million at December 31, 2016). The greatest exposure is towards the joint venture Cardón IV SA (Eni’s interest 50%) in Venezuela, which is currently operating and developing the Perla offshore gas field. At December 31, 2017, the exposure of Eni towards the joint venture amounted to €955 million (€1,054 million at December 31, 2016).

Additions to the allowance for doubtful accounts of financing receivables of €211 million included: (i) a €102 million loss taken at a financing receivable granted to Matrìca SpA (Eni’s share 50%), a joint venture with Novamont SpA for the production of chemical products from renewable sources. The loan was granted to the joint venture to fund the “Polo Verde” project of Porto Torres, Sardinia. Such impairment was driven by expectations for a lower repayment capacity of the venture considering the

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industrial risks of the project; (ii) €109 million related to a financing receivables in the Exploration & Production segment primarily related to the shareholder loan granted to Cardón IV SA for €77 million due to the impairment loss taken at the underlying industrial project (see note 20 — Investments).

Financing receivables held for operating purposes in currencies other than euro amounted to €1,428 million (€1,606 million at December 31, 2016).

Financing receivables held for operating purposes due beyond five years amounted to €1,393 million (€1,519 million at December 31, 2016).

The valuation at fair value of financing receivables of €1,610 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from -0.2% to 2.5% (-0.2% and 2.6% at December 31, 2016). Fair value estimation of financing receivables did not include the shareholders’ loan towards the joint venture Cardón IV, which recoverability will depend on the cash flows generated by the venture and the ability of Venezuela to overcome the ongoing financial crisis. The fair value of this receivable equals the value-in-use of the underlying mineral project, which future cash flows have been estimated factoring in the sovereign risk determined based on the range of possible developments in the Country financial scenario.

Securities of €73 million (€75 million at December 31, 2016), designated as held-to-maturity investments, are listed bonds issued by sovereign states for €69 million (€71 million at December 31, 2016) and by the European Investment Bank for €4 million (same amount as of December 31, 2016).

Securities amounting to €20 million (same amount as of December 31, 2016) were pledged as guarantee of the deposit for gas cylinders as provided for by the Italian law.

The following table analyses securities per issuing entity:

	Amortized cost (€ million)		Nominal value (€ million)		Fair Value (€ million)		Nominal rate of return (%)	Maturity date	Rating - Moody’s	Rating - S&P
Sovereign states
Fixed rate bonds
Italy		24		25		26	from 0.35 to 4.75	from 2018 to 2025	Baa2	BBB
Spain		15		14		15	from 1.40 to 4.30	from 2019 to 2020	Baa2	BBB+
Ireland		9		8		9	4.50	2018	A2	A+
Iceland		3		3		3	2.50	2020	A3	A
Poland		2		2		2	4.20	2020	A2	BBB+
Slovenia		2		2		2	4.13	2020	Baa1	A+
Belgium		2		2		2	1.40	2018	Aa3	AA
Floating rate bonds
Italy		12		11		11		from 2018 to 2019	Baa2	BBB
Total sovereign states		69		67		70
European Investment Bank		4		4		4		2018	Aaa	AAA
		73		71		74

Securities having a maturity within five years amounted to €72 million.

The fair value of securities was derived from quoted market prices.

Receivables with related parties are described in note 47 — Transactions with related parties.

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22 Deferred tax assets

Deferred tax assets are stated net of amounts of deferred tax liabilities that can be offset for €4,269 million (€4,286 million at December 31, 2016).

(€ million)	Deferred tax assets		Provisions for impairments		Total
Amount at December 31, 2016		9,412		(5,622)		3,790
Additions		2,341		(212)		2,129
Deductions		(1,588)		349		(1,239)
Currency translation differences		(862)		202		(660)
Other changes		37		21		58
Amount at December 31, 2017		9,340		(5,262)		4,078

Deferred tax assets related for €2,070 million (€1,690 million at December 31, 2016) to the parent company Eni SpA and other Italian subsidiaries that were part of the consolidated accounts for Italian tax purposes. Those assets were recorded on the pre-tax loss of the year and on the recognition of deferred deductible expenses within the limits of the amounts expected to be recovered in future years based on availability of expected future taxable profit.

Deferred tax assets are further described in note 32 — Deferred tax liabilities.

Income taxes are described in note 43 — Income taxes.

23 Other non-current assets

(€ million)	December 31, 2017		December 31, 2016
Tax receivables from:
- Italian tax authorities
- income tax		62		73
- interest on tax credits		64		64
		126		137
- non-Italian tax authorities		381		365
		507		502
Other receivables:
- related to divestments		118		222
- other non-current		44		52
		162		274
Fair value of derivative financial instruments		80		108
Other asset		574		464
		1,323		1,348

Receivables from divestments amounting to €118 million (€222 million at December 31, 2016) were net of the accumulated provisions for impairments of €125 million and included the present value of long-term portion of €111 million ($133 million) of the receivable related to the divestment of a 10% stake of the Zohr asset in Egypt finalized in February 2017. The current portion of the receivables is indicated in note 11 — Trade and other receivables. The accumulated provisions for impairments of €125 million related to a receivable deriving from the sale of an asset in Nigeria and included the impairment of the year of €44 million.

The fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments.

Other non-current assets amounted to €574 million (€464 million at December 31, 2016) included €56 million of deferred costs for take-or-pay gas volumes in connection to the Company’s long-term supply contracts (€113 million at December 31, 2016). The portion that Eni plans to recover within the term of 12 months is indicated in note 15 — Other current assets.

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Transactions with related parties are described in note 47 — Transactions with related parties.

Current liabilities

24 Short-term debt

(€ million)	December 31, 2017		December 31, 2016
Commercial papers		1,664		2,738
Banks		201		155
Other financial institutions		377		503
		2,242		3,396

The decrease in short-term debt of €1,154 million primarily related to net reimbursements for €581 million and currency translation differences relating to foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for €574 million.

Commercial papers of €1,664 million (€2,738 million at December 31, 2016) were issued by the Group’s financial subsidiaries Eni Finance USA Inc for €1,070 million (€1,750 million at December 31, 2016) and Eni Finance International SA for €594 million (€988 million at December 31, 2016).

The breakdown by currency of short-term debt is provided below:

(€ million)	December 31, 2017		December 31, 2016
Euro		904		1,405
U.S. dollar		1,329		1,982
Other currencies		9		9
		2,242		3,396

As of December 31, 2017, the weighted average interest rate on short-term debt was 1.3% (0.9% as of December 31, 2016).

As of December 31, 2017, Eni retained undrawn uncommitted borrowing facilities amounting to €11,584 million (€12,267 million at December 31, 2016). Those facilities bore interests and charges for undrawn that reflect prevailing market conditions.

As of December 31, 2017, Eni was in compliance with covenants and other contractual provisions in relation to borrowing facilities.

Because of the short-term maturity and conditions of remuneration of short-term debts, the fair value approximated the carrying amount.

Payables due to related parties are described in note 47 — Transactions with related parties.

25 Trade and other payables

(€ million)	December 31, 2017		December 31, 2016
Trade payables		10,890		11,038
Advances		797		526
Other payables
- related to capital expenditures		2,094		2,158
- others		2,967		2,981
		5,061		5,139
		16,748		16,703

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Down payments and advances for €797 million (€526 million at December 31, 2016) related to the Exploration & Production segment for €444 million (€153 million at December 31, 2016) and included €180 million of advances denominated in local currency relating to future supplies of equity hydrocarbons to our Egyptian State-owned partners in relation to the operations of Eni’s Concession Agreements in the Country for the next four-year period and in particular, among these, the Zohr project. Those advances have further reduced the Group net exposure towards the Country.

Other payables were as follows:

(€ million)	December 31, 2017		December 31, 2016
Payables related to capital expenditures due to
Suppliers in relation to investing activities		1,804		1,835
Joint venture partners in exploration and production activities		264		219
Other		26		104
		2,094		2,158
Other payables
Joint venture partners in exploration and production activities		1,968		2,057
Employees		184		180
Social security entities		84		94
Non-financial government entities		23		6
Other		708		644
		2,967		2,981
		5,061		5,139

Because of the short-term maturity and conditions of remuneration of trade payables, the fair value approximated the carrying amount.

Payables due to related parties are described in note 47 — Transactions with related parties.

26 Income tax payable

(€ million)	December 31, 2017		December 31, 2016
Italian subsidiaries		174		97
Non-Italian subsidiaires		298		329
		472		426

Income tax payable is described in note 43 — Income taxes.

27 Other tax payable

(€ million)	December 31, 2017		December 31, 2016
Excise and customs duties		824		634
Other taxes and duties		648		659
		1,472		1,293

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28 Other current liabilities

(€ million)	December 31, 2017		December 31, 2016
Fair value of derivatives financial instruments		1,011		2,108
Other liabilities		504		491
		1,515		2,599

Fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments.

Other current liabilities of €504 million (€491 million at December 31, 2016) included the current portion of advances received from Suez following a long-term agreement for supplying natural gas and electricity for €68 million (€73 million at December 31, 2016). Non-current portion is disclosed in note 33 — Other non-current liabilities.

Transactions with related parties are described in note 47 — Transactions with related parties.

Non-current liabilities

29 Long-term debt and current portion of long-term debt

	December 31, 2017						December 31, 2016
(€ million)	Long-term portion		Short-term portion		Total		Long-term portion		Short-term portion		Total
Banks		3,200		801		4,001		4,014		272		4,286
Ordinary bonds		16,520		1,445		17,965		16,044		2,959		19,003
Convertible bonds		387				387		383				383
Other financial institutions		72		40		112		123		48		171
		20,179		2,286		22,465		20,564		3,279		23,843

The following table reflects long-term debt and current portion of long-term debt as of December 31, 2017 by maturity:

	At December 31,			Long-term maturity
(€ million)	Maturity range	31.12.2017		2019		2020		2021		2022		After		Total		Current maturity 2018
Banks	2018 – 2032		4,001		1,290		729		341		143		697		3,200		801
Ordinary bonds	2018 – 2043		17,965		2,486		2,371		934		697		10,032		16,520		1,445
Convertible bonds	2022		387								387				387
Other financial institutions	2018 – 2032		112		45		3		3		3		18		72		40
			22,465		3,821		3,103		1,278		1,230		10,747		20,179		2,286

Long-term debt and current portion of long-term debt of €22,465 million (€23,843 million at December 31, 2016) decreased by €1,378 million. The decrease comprised new issuance of €1,842 million net of repayments made for €2,973 million and, as decrease, currency translation differences relating foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for €236 million.

Eni entered into long-term borrowing facilities with the European Investment Bank. These borrowing facilities are subject to the maintenance of a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees could be required to be agreed upon with the European Investment Bank. In addition, Eni entered into long and medium-term facilities subject to the maintenance of certain financial ratios based on the Consolidated Financial Statements of Eni with

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Citibank Europe Plc, whose non-compliance allows the bank to request an early repayment. At December 31, 2017, debts subjected to restrictive covenants amounted to €1,664 million (€1,953 million at December 31, 2016). Eni was in compliance with those covenants.

Ordinary bonds of €17.965 million (€19,003 million at December 31, 2016) consisted of bonds issued within the Euro Medium Term Notes Program for a total of €16,963 million and other bonds for a total of €1,002 million.

The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2017:

	Amount		Discount on bond issue and accrued expense		Total		Currency		Maturity				Rate %
(€ million)	Amount		Discount on bond issue and accrued expense		Total		Currency		from		to		from		to
Issuing entity
Euro Medium Term Notes
Eni SpA		1,500		16		1,516		EUR				2019				4.125
Eni SpA		1,200		17		1,217		EUR				2025				3.750
Eni SpA		1,000		37		1,037		EUR				2020				4.250
Eni SpA		1,000		32		1,032		EUR				2018				3.500
Eni SpA		1,000		27		1,027		EUR				2029				3.625
Eni SpA		1,000		19		1,019		EUR				2020				4.000
Eni SpA		1,000		8		1,008		EUR				2023				3.250
Eni SpA		1,000		7		1,007		EUR				2026				1.500
Eni SpA		900		(6)		894		EUR				2024				0.625
Eni SpA		800		1		801		EUR				2021				2.625
Eni SpA		800		(2)		798		EUR				2028				1.625
Eni SpA		750		13		763		EUR				2019				3.750
Eni SpA		750		7		757		EUR				2024				1.750
Eni SpA		750		4		754		EUR				2027				1.500
Eni SpA		700				700		EUR				2022				0.750
Eni SpA		650		(1)		649		EUR				2025				1.000
Eni SpA		600		(6)		594		EUR				2028				1.125
Eni Finance International SA		507		15		522		GBP		2018		2021		4.750		6.125
Eni Finance International SA		295		3		298		EUR		2028		2043		3.875		5.441
Eni Finance International SA		155		1		156		YEN		2019		2037		1.955		2.810
Eni Finance International SA		417		(3)		414		USD				2026				variable
		16,774		189		16,963
Other bonds
Eni SpA		375		3		378		USD				2020				4.150
Eni SpA		292				292		USD				2040				5.700
Eni USA Inc		333		(1)		332		USD				2027				7.300
		1,000		2		1,002
		17,774		191		17,965

As of December 31, 2017, ordinary bonds maturing within 18 months of €2,199 million were issued by Eni SpA for €1,795 million and by Eni Finance International SA for €404 million. During 2017, new bonds of €1,817 million were issued by Eni SpA for €1,403 million and Eni Finance International SA for €414 million.

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The following table provides a breakdown of convertible bonds issued by Eni SpA as of December 31, 2017:

(€ million)	Amount		Discount on bond issue and accrued expense		Total		Currency		Maturity		Rate %
Issuing entity
Eni SpA		400		(13)		387		EUR		2022		0.000
		400		(13)		387

The non-dilutive equity-linked bond issued provides for by a redemption value linked to the market price of Eni’s shares. The bondholders have “conversion” rights at certain times and/or in the presence of certain events, while the bonds will be cash-settled. Accordingly, to hedge its exposure, Eni purchased cash-settled call options relating to Eni shares that will be settled on a net cash basis. The convertible bond is measured at amortized cost. The conversion option, embedded in the financial instrument issued, and the call option on Eni’s shares acquired are valued at fair value with effects recognized through profit and loss.

The following table provides a breakdown by currency of long-term debt, its current portion and the related weighted average interest rates.

	December 31, 2017 (€ million)		Average rate (%)		December 31, 2016 (€ million)		Average rate (%)
Euro		20,094		2.4		21,545		2.7
U.S. dollar		1,694		4.8		1,587		5.2
British pound		521		5.3		540		5.3
Japanese yen		156		2.6		171		2.6
		22,465				23,843

As of December 31, 2017, Eni retained undrawn long-term committed borrowing facilities of €5,802 million (€6,236 at December 31, 2016), of which €750 million due in 2018. Those facilities bore interest rates reflecting prevailing conditions on the marketplace.

Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €16.8 billion were drawn as of December 31, 2017.

Fair value of long-term debt, including the current portion of long-term debt amounted to €23,764 million (€25,358 million at December 31, 2016):

(€ million)	December 31, 2017		December 31, 2016
Ordinary bonds		19,219		20,501
Convertible bonds		410		435
Banks		4,021		4,244
Other financial institutions		114		178
		23,764		25,358

Fair value of financial debt was calculated by discounting the expected future cash flows at discount rates ranging from -0.2% to 2.5% (-0.2% and 2.6% at December 31, 2016).

Information on net borrowings

In assessing its capital structure, Eni uses net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS as issued by the IASB less: cash, cash equivalents, held-for-trading securities and other financial assets, and certain highly-liquid investments not related to operations including, among others, non-operating financing receivables and available-for-sale securities not related to operations. Held-for-trading securities and other financial assets

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are part of a strategic reserve of liquidity that management has established by reinvesting proceeds from the Group disposal plans and is intended to provide a certain degree of financial flexibility in case of a prolonged price downturn, tight financial markets or in view of other Company’s purposes. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Available-for-sale securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities.

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways by which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced according to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to calculate leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies.

	December 31, 2017						December 31, 2016
(€ million)	Current		Non- current		Total		Current		Non- current		Total
A. Cash and cash equivalents		7,363				7,363		5,674				5,674
B. Held-for-trading financial assets		6,012				6,012		6,166				6,166
C. Available-for-sale financial assets		207				207		238				238
D. Liquidity (A+B+C)		13,582				13,582		12,078				12,078
E. Financing receivables		209				209		385				385
F. Short-term debt towards banks		201				201		155				155
G. Long-term debt towards banks		801		3,200		4,001		272		4,014		4,286
H. Bonds		1,445		16,907		18,352		2,959		16,427		19,386
I. Short-term debt towards related parties		164				164		191				191
L. Other short-term liabilities		1,877				1,877		3,050				3,050
M. Other long-term liabilities		40		72		112		48		123		171
N. Total borrowings (F+G+H+I+L+M)		4,528		20,179		24,707		6,675		20,564		27,239
O. Net borrowings (N-D-E)		(9,263)		20,179		10,916		(5,788)		20,564		14,776

Financial assets held for trading of €6,012 million (€6,166 million at December 31, 2016) are disclosed in note 9 — Financial assets held for trading.

Available-for-sale securities of €207 million (€238 million at December 31, 2016) were held for non-operating purposes and related to Eni Insurance DAC.

Current financing receivables of €209 million (€385 million at December 31, 2016) were held for non-operating purposes.

Changes in gross borrowings were as following:

(€ million)	Long-term debt and current portion of long-term debt		Short-term debt		Total
Carrying amount at December 31, 2016		23,843		3,396		27,239
Cash flows		(1,131)		(581)		(1,712)
Currency translation differences		(236)		(574)		(810)
Other non-monetary changes		(11)		1		(10)
Carrying amount at December 31, 2017		22,465		2,242		24,707

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30 Provisions for contingencies

(€ million)	Provision for site restoration, abandonment and social projects		Environmental provision		Provision for litigations		Provision for taxes		Loss adjustments and actuarial provisions for Eni’s insurance companies		Provision for redundancy incentives		Provision for onerous contracts		Provision for losses on investments		Provision for OIL insurance cover		Provision for disposal and restructuring		Other(*)		Total
Carrying amount at December 31, 2016		8,419		2,691		954		732		207		176		165		153		88		58		253		13,896
New or increased provisions				217		567		162		181		9				46				16		193		1,391
Initial recognition and changes in estimates		370																						370
Accretion discount		271		(9)		1						1		2								(2)		264
Reversal of utilized provisions		(289)		(237)		(281)		(225)		(190)		(17)		(99)						(13)		(75)		(1,426)
Reversal of unutilized provisions		(10)		(17)		(50)		(52)				(32)		(1)		(10)		(3)				(25)		(200)
Currency translation differences		(646)		(1)		(95)		(66)						(7)		(7)		(1)				(11)		(834)
Other changes		11		9		11		(24)		7		3						(8)		4		(27)		(14)
Carrying amount at December 31, 2017		8,126		2,653		1,107		527		205		140		60		182		76		65		306		13,447

(*)

Each individual amount included herein was lower than €50 million.

The Group makes full provision for the future costs of decommissioning oil and natural gas wells, facilities and related pipelines on a discounted basis upon installation. The decommissioning provisions at the reporting date amounted to €8,126 million and included the discounted estimated costs that the Company expects to incur for decommissioning oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration of the Exploration & Production segment for €7,649 million. Estimate revisions of €370 million were primarily due to a decrease in the discount rate curve in particular for the U.S. dollar, new provisions of the year and the revision of cost estimates. The accretion discount recognized in the profit and loss account for €271 million was determined based on discount rates ranging from -0.1% to 5.9% (from -0.01% to 5.8% at December 31, 2016). Main expenditures associated with decommissioning operations are expected to be incurred over a 45-year period.

Provisions for environmental risks of €2,653 million included the estimated costs for environmental clean-up and remediation of soil and groundwater in areas owned or under concession where the Group performed in the past industrial operations that were progressively divested, shut down, dismantled or restructured. The provision has been accrued because at the balance sheet date there is a legal or constructive obligation for Eni to carry out environmental clean-up and remediation and the expected costs can be estimated reliably. The provision includes the expected charges associated with strict liability related to obligations of cleaning up and remediating polluted areas that met the parameters set by the law at the time when the pollution occurred or because Eni assumed the liability of other operators when took over the ownership of the site. Those environmental provisions are recognized when an environmental project is approved by or filed with the relevant administrative authorities or a constructive obligation has arisen whereby the Company commits itself to performing certain cleaning-up and restoration projects and a reliable cost estimation is available. At December 31, 2017, environmental provision primarily related to Syndial SpA for €2,119 million and to the Refining & Marketing business line for €326 million.

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Provisions for litigations of €1,107 million comprised the expected liabilities associated with legal proceedings and other matters arising from contractual claims, contract renegotiations, including arbitration, fines and penalties due to antitrust proceedings and administrative matters. These provisions represented the Company’s best estimate of the expected probable liabilities associated with pending litigation and commercial disputes and primarily related to the Exploration & Production segment for €494 million and the Gas & Power segment for €457 million.

Provisions for taxes of €527 million included the estimated charges that the Company expects to incur for unsettled tax claims in connection with uncertainties in the application of tax rules at certain Italian and non-Italian subsidiaries in the Exploration & Production segment (€499 million).

Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance DAC of €205 million represented the estimated liabilities accrued on the basis for third parties claims. Against such liability was recorded a receivable of €157 million recognized towards insurance companies for reinsurance contracts.

Provisions for redundancy incentives of €140 million were recognized due to a restructuring program involving the Italian personnel related to past reporting periods.

Provisions for onerous contracts of €60 million related to the execution of contracts where the expected costs exceed the relevant benefits. In particular, the provision comprised the estimated expected losses on unutilized infrastructures for gas transportation. Utilizations of €99 million essentially related to charges for unutilized infrastructures of regasification and gas transportation.

31 Provisions for employee benefits

(€ million)	December 31, 2017		December 31, 2016
TFR		284		298
Foreign defined benefit plans		409		276
FISDE and other foreign medical plans		122		124
Other benefit plans		207		170
		1,022		868

Provisions for benefits upon termination of employment primarily related to a provisions accrued by Italian companies for employee retirement, determined using actuarial techniques and regulated by Article 2120 of the Italian Civil Code.

Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria, Germany and the United Kingdom. Benefits under these plans consist of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to the retirement.

Group companies provide healthcare benefits. Liability to these plans (FISDE and other foreign healthcare plans) and the current cost are limited to the contributions made by the Company for retired managers.

Other benefits primarily consisted of monetary and long-term incentive schemes to Group managers. Provisions for the monetary incentive scheme are assessed based on the estimated bonuses that will be granted to those managers who will achieve certain individual performance goals weighted with the likelihood that the Company delivers the planned profitability targets. The benefit has a three-year vesting period and incurs when the commitment arises towards Eni’s management, based on the achievement of corporate goals. The estimate is subject to adjustments in subsequent years based on the results achieved and the update of the result forecasted (above or below the target). This benefit is applied pro-rata temporis over the three-year period depending on the results of the performance parameters. Provisions for the long-term incentive scheme are assessed based on the estimated trends of a performance indicator as benchmarked against a group of international oil companies. Both of these incentive schemes normally vest over a three-year period.

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Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

	December 31, 2017										December 31, 2016
(€ million)	TFR		Foreign defined benefit plans		FISDE and other foreign medical plans		Other benefit plans		Total		TFR		Foreign defined benefit plans		FISDE and other foreign medical plans		Other benefit plans		Total
Present value of benefit liabilities at beginning of year		298		895		124		170		1,487		281		1,240		156		153		1,830
Current cost				24		2		54		80				28		2		56		86
Interest cost		3		29		2		1		35		6		34		3		1		44
Remeasurements:		(6)		54		(1)		3		50		19		22		(17)		1		25
- actuarial (gains) losses due to changes in demographic assumptions				(14)						(14)		(2)		(2)		(1)		(2)		(7)
- actuarial (gains) losses due to changes in financial assumptions		(5)		71				3		69		11		30		(2)		2		41
- experience (gains) losses		(1)		(3)		(1)				(5)		10		(6)		(14)		1		(9)
Past service cost and (gains) losses settlements				(1)				30		29				(7)		2		(3)		(8)
Plan contributions:				1						1				1						1
- employee contributions				1						1				1						1
Benefits paid		(10)		(37)		(5)		(37)		(89)		(8)		(33)		(6)		(31)		(78)
Reclassification to asset held for sale				(12)				(2)		(14)
Changes in the scope of consolidation		(1)		(15)		(1)		(3)		(20)
Currency translation differences and other changes				59		1		(9)		51				(390)		(16)		(7)		(413)
Present value of benefit liabilities at end of year (a)		284		997		122		207		1,610		298		895		124		170		1,487
Plan assets at beginning of year				619						619				707						707
Interest income				20						20				20						20
Return on plan assets				12						12				42						42
Past service cost and (gains) losses settlements														(3)						(3)
Plan contributions:				24						24				25						25
- employee contributions				1						1				1						1
- employer contributions				23						23				24						24
Benefits paid				(25)						(25)				(19)						(19)
Changes in the scope of consolidation				(15)						(15)
Currency translation differences and other changes				(47)						(47)				(153)						(153)
Plan assets at end of year (b)				588						588				619						619
Net liability recognized at end of year (a-b)		284		409		122		207		1,022		298		276		124		170		868

Employee benefit plans included the liability attributable to joint venture partners operating in exploration and production activities of €177 million (€60 million at December 31, 2016). Eni recorded a receivable for an amount equivalent to such liability.

Foreign defined benefit plans amounting to €409 million (€276 million at December 31, 2016) primarily related to pension plans for €334 million (€184 million at December 31, 2016).

Other employee benefit plans of €207 million (€170 million at December 31, 2016) related to: (i) defined benefit plans for €13 million (€12 million at December 31, 2016) related to the Gas fund; and (ii) long-term benefit plans for €194 million (€158 million at December 31, 2016) of which deferred monetary incentive plans for €120 million (€99 million at December 31, 2016), jubilee awards for €22 million (€28 million at December 31, 2016), long-term incentive plan for €13 million (€14 million at December 31, 2016), isopensione €28 million and other long-term plans for €11 million (€17 million at December 31, 2016).

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Costs charged to the profit and loss account consisted of the following:

(€ million)	TFR		Foreign defined benefit plans		Fisde and other foreign medical plans		Other benefit plans		Total
2017
Current cost				24		2		54		80
Past service cost and (gains) losses on settlements				(1)				30		29
Interest cost (income), net:
- interest cost on liabilities		3		29		2		1		35
- interest income on plan assets				(20)						(20)
Total interest cost (income), net		3		9		2		1		15
- of which recognized in “Payroll and related cost”								1		1
- of which recognized in “Financial income (expense)”		3		9		2				14
Remeasurements for long-term plans								3		3
Total		3		32		4		88		127
- of which recognized in “Payroll and related cost”				23		2		88		113
- of which recognized in “Financial income (expense)”		3		9		2				14
2016
Current cost				28		2		56		86
Past service cost and (gains) losses on settlements				(4)		2		(3)		(5)
Interest cost (income), net:
- interest cost on liabilities		6		34		3		1		44
- interest income on plan assets				(20)						(20)
Total interest cost (income), net		6		14		3		1		24
- of which recognized in “Payroll and related cost”								1		1
- of which recognized in “Financial income (expense)”		6		14		3				23
Remeasurements for long-term plans								(1)		(1)
Total		6		38		7		53		104
- of which recognized in “Payroll and related cost”				24		4		53		81
- of which recognized in “Financial income (expense)”		6		14		3				23

Costs recognized in other comprehensive income consisted of the following:

	2017								2016
(€ million)	TFR		Foreign defined benefit plans		Fisde and other foreign medical plans		Total		TFR		Foreign defined benefit plans		Fisde and other foreign medical plans		Other benefit plans		Total
Remeasurements
Actuarial (gains)/losses due to changes in demographic assumptions				(14)				(14)		(2)		(2)		(1)		1		(4)
Actuarial (gains)/losses due to changes in financial assumptions		(5)		71				66		11		30		(2)		1		40
Experience (gains) losses		(1)		(3)		(1)		(5)		10		(6)		(14)				(10)
Return on plan assets				(12)				(12)				(42)						(42)
		(6)		42		(1)		35		19		(20)		(17)		2		(16)

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Plan assets consisted of the following:

(€ million)	Cash and cash equivalents		Equity securities		Debt securities		Real estate		Derivatives		Investment funds		Assets held by insurance company		Other		Total
December 31, 2017
Plan assets with a quoted market price		16		48		329		10		9		60		13		100		585
Plan assets without a quoted market price														3				3
		16		48		329		10		9		60		16		100		588
December 31, 2016
Plan assets with a quoted market price		105		49		270		11		1		65		14		101		616
Plan assets without a quoted market price														3				3
		105		49		270		11		1		65		17		101		619

Plan assets are generally managed by external asset managers pursuing investment strategies, defined by Eni’s companies, with the aim of ensuring that assets are sufficient to pay the benefits. For this purpose, the investments are aimed at maximizing the expected return and limit the risk level through proper diversification.

The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 2018 consisted of the following:

		TFR		Foreign defined benefit plans		FISDE and other foreign medical plans		Other long-term benefit plans
2017
Discount rate	(%)		1.5		0.6-15.5		1.5		0.0-1.5
Rate of compensation increase	(%)		2.5		1.5-13.5
Rate of price inflation	(%)		1.5		0.6-14.8		1.5		1.5
Life expectations on retirement at age 65	(years)				13-24		24
2016
Discount rate	(%)		1.0		0.6-17.5		1.0		0.0-1.0
Rate of compensation increase	(%)		2.0		1.0-15.0
Rate of price inflation	(%)		1.0		0.6-13.5		1.0		1.0
Life expectations on retirement at age 65	(years)				13-24		24

The following is an analysis by geographical area related to the main actuarial assumptions used in the valuation of the principal foreign defined benefit plans:

		Euro area		Rest of Europe		Africa		Other areas		Foreign defined benefit plans
2017
Discount rate	(%)		1.5-1.8		0.6-2.5		3.7-15.5		4.1-8.0		0.6-15.5
Rate of compensation increase	(%)		1.5-3.0		2.5-3.7		5.0-13.5		1.5-10.0		1.5-13.5
Rate of price inflation	(%)		1.5-1.9		0.6-3.4		3.7-14.8		1.5-4.8		0.6-14.8
Life expectations on retirement at age 65	(years)		21-24		22-24		13-17				13-24
2016
Discount rate	(%)		1.0-2.0		0.6-2.7		3.5-17.5		7.3-8.1		0.6-17.5
Rate of compensation increase	(%)		1.0-3.0		2.3-3.8		5.0-15.0		7.8-10.0		1.0-15.0
Rate of price inflation	(%)		1.0-1.8		0.6-3.4		3.5-13.5		5.0-5.5		0.6-13.5
Life expectations on retirement at age 65	(years)		21-22		23-24		13-15				13-24

The discount rate used was determined on the base of corporate bond yields (rating AA) in countries with a significant market, or in the absence, of government bond yields. The demographic tables adopted are those used by each country for the assessments of IAS 19. The inflation rate is consistent with the discount rate adopted determined based on the inflation rate implicit in the securities financial markets.

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The effects of a possible change in the main actuarial assumptions at the end of the year are listed below:

	Discount rate				Rate of price inflation		Rate of increases in pensionable salaries		Healthcare cost trend rate		Rate of increases to pensions in payment
(€ million)	0.5% Increase		0.5% Decrease		0.5% Increase		0.5% Increase		0.5% Increase		0.5% Increase
December 31, 2017
Effect on DBO
TFR		(13)		14		9
Foreign defined benefit plans		(72)		79		24		20				13
FISDE and other foreign medical plans		(7)		7						7
Other benefit plans		(3)		1		1
December 31, 2016
Effect on DBO
TFR		(15)		16		10
Foreign defined benefit plans		(57)		66		33		15				23
FISDE and other foreign medical plans		(7)		8						8
Other benefit plans		(2)		2		1

The sensitivity analysis was performed based on the results for each plan through assessments calculated considering modified parameters.

The amount of contributions expected to be paid for employee benefit plans in the next year amounted to €123 million, of which €59 million related to defined benefit plans.

The following is an analysis by maturity date of the liabilities for employee benefit plans:

(€ million)	TFR		Foreign defined benefit plans		FISDE and other foreign medical plans		Other benefit plans
December 31, 2017
2018		16		47		5		66
2019		17		65		5		60
2020		18		70		5		46
2021		17		79		5		8
2022		14		84		5		6
2023 and thereafter		202		64		97		31
December 31, 2016
2017		13		31		5		37
2018		14		44		5		59
2019		15		33		5		52
2020		17		33		5		3
2021		19		38		5		3
2022 and thereafter		220		97		99		42

The weighted average duration of the liabilities for employee benefit plans was the following:

		TFR		Foreign defined benefit plans		FISDE and other foreign medical plans		Other benefit plans
2017
Weighted average duration	(years)		10.1		17.5		13.7		3.0
2016
Weighted average duration	(years)		10.3		17.9		13.9		3.4

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32 Deferred tax liabilities

Deferred tax liabilities were recognized net of the amounts of deferred tax assets that can be offset for €4,269 million (€4,286 million at December 31, 2016).

(€ million)	Deferred tax liabilities
Amount at December 31, 2016		6,667
Additions		1,171
Deductions		(835)
Currency translation differences		(1,123)
Other changes		20
Amount at December 31, 2017		5,900

Deferred tax assets and liabilities consisted of the following:

(€ million)	December 31, 2017		December 31, 2016
Deferred tax liabilities		10,169		10,953
Deferred tax assets available for offset		(4,269)		(4,286)
		5,900		6,667
Deferred tax assets not available for offset		(4,078)		(3,790)
Net deferred tax liabilities		1,822		2,877

Net deferred tax liabilities of €1,822 million (€2,877 million at December 31, 2016) included the recognition of the deferred tax effect against equity of the fair value measurement of derivatives designated as cash flow hedge (deferred tax liabilities for €57 million) and the revaluation of defined benefit plans (deferred tax assets for €19 million).

The most significant temporary differences giving rise to net deferred tax liabilities are disclosed below:

(€ million)	Carrying amount at December 31, 2017		Carrying amount at December 31, 2016
Deferred tax liabilities
Accelerated tax depreciation		8,323		8,899
Difference between the fair value and the carrying amount of assets acquired		1,106		1,269
Site restoration and abandonment (tangible assets)		305		348
Application of the weighted average cost method in evaluation of inventories		70		81
Other		365		356
		10,169		10,953
Deferred tax assets, gross
Carry-forward tax losses		(5,240)		(4,722)
Site restoration and abandonment (provisions for contingencies)		(2,747)		(2,881)
Timing differences on depreciation and amortization		(2,164)		(2,260)
Accruals for impairment losses and provisions for contingencies		(1,404)		(1,413)
Impairment losses		(801)		(906)
Over/Underlifting		(395)		(270)
Employee benefits		(194)		(163)
Unrealized intercompany profits		(130)		(118)
Other		(534)		(965)
		(13,609)		(13,698)
Impairments of deferred tax assets		5,262		5,622
Deferred tax assets, net		(8,347)		(8,076)
Net deferred tax liabilities		1,822		2,877

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The following table summarizes the changes in deferred tax liabilities and assets:

(€ million)	Deferred tax liabilities		Deferred tax assets, gross		Impairments of deferred tax assets		Deferred tax assets, net		Net deferred tax liabilities
2017
Carrying amount at the beginning of the year		10,953		(13,698)		5,622		(8,076)		2,877
Additions		1,171		(2,341)		212		(2,129)		(958)
Deductions		(835)		1,588		(349)		1,239		404
Currency translation differences		(1,123)		862		(202)		660		(463)
Other changes		3		(20)		(21)		(41)		(38)
Carrying amount at the end of the year		10,169		(13,609)		5,262		(8,347)		1,822
2016
Carrying amount at the beginning of the year		10,780		(12,307)		5,099		(7,208)		3,572
Additions		1,796		(2,994)		667		(2,327)		(531)
Deductions		(1,486)		1,208		(254)		954		(532)
Currency translation differences		229		(185)		80		(105)		124
Other changes		(366)		580		30		610		244
Carrying amount at the end of the year		10,953		(13,698)		5,622		(8,076)		2,877

The decreases in net deferred tax liabilities of €404 million include €115 million of net impairments of deferred tax assets due to the tax reform implemented in the USA.

Italian taxation law allows the carry-forward of tax losses indefinitely. Foreign taxation laws generally allow the carry-forward of tax losses over a period longer than five years, and in many cases, indefinitely. An average tax rate of 24% was applied to tax losses of Italian subsidiaries to determine the portion of the carry-forwards tax losses, which will be utilized in future years to offset expected taxable profit. The corresponding rate for foreign subsidiaries was 36.7%.

Carry-forward tax losses amounted to €17,773 million out of which €13,545 million can be used indefinitely. Carry-forward tax losses regarded Italian companies for €10,097 million and foreign companies for €7,676 million. Deferred tax assets recognized on these losses amounted to €2,421 million and €2,819 million, respectively.

Provisions for impairments of deferred tax assets of €5,262 million related to Italian companies for €3,947 million and foreign companies for €1,315 million.

33 Other non-current liabilities

(€ million)	December 31, 2017		December 31, 2016
Fair value of derivatives financial instruments		91		161
Income tax liabilities		36		35
Other payables towards tax authorities		9		9
Cautionary deposits		255		265
Other payables		45		51
Other liabilities		1,043		1,247
		1,479		1,768

Fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments.

Cautionary deposits of €255 million (€265 million at December 31, 2016) related for €215 million (€224 million at December 31 2016) to deposits from retail customers for the supply of gas and electricity.

Other liabilities of €1,043 million (€1,247 million at December 31, 2016) included advances received from Suez following a long-term agreement for supplying natural gas and electricity of €584 million (€664 million at December 31, 2016). The current portion is described in note 28 — Other current liabilities.

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Liabilities with related parties are described in note 47 — Transactions with related parties.

34 Derivative financial instruments

	December 31, 2017						December 31, 2016
(€ million)	Fair value asset		Fair value liability		Level of Fair value		Fair value asset		Fair value liability		Level of Fair value
Non-hedging derivatives
Derivatives on exchange rate
- Currency swap		170		86		2		188		268		2
- Interest currency swap		41		45		2		38		83		2
- Outright		3		5		2		17		15		2
		214		136				243		366
Derivatives on interest rate
- Interest currency swap		9		5		2		10		12		2
		9		5				10		12
Derivatives on commodities
- Future		796		771		1		624		611		1
- Over the counter		81		97		2		133		120		2
- Options										1		2
- Other		1		2		2		4		5		2
		878		870				761		737
		1,101		1,011				1,014		1,115
Trading derivatives
Derivatives on commodities
- Over the counter		683		829		2		1,495		1,490		2
- Future		395		390		1		561		574		1
- Options		133		114		2		211		157		2
		1,211		1,333				2,267		2,221
Cash flow hedge derivatives
Derivatives on commodities
- Over the counter		227		21		2		309		150		2
- Future		35				1		1		18		1
		262		21				310		168
Option embedded in convertible bonds		16		16		2		46		46		2
Gross amount		2,590		2,381				3,637		3,550
Offsetting		(1,279)		(1,279)				(1,281)		(1,281)
Net amount		1,311		1,102				2,356		2,269
Of which:
- current		1,231		1,011				2,248		2,108
- non-current		80		91				108		161

Derivative fair values were estimated on the basis of market quotations provided by primary info-provider or, alternatively, appropriate valuation techniques generally adopted in the marketplace.

Fair values of non-hedging derivatives consisted of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives did not relate to specific trade or financing transactions.

Fair values of trading derivatives consisted of derivatives entered for trading purposes and proprietary trading.

Fair value of cash flow hedge derivatives related to the hedges entered by the Gas & Power segment. These derivatives were entered into to hedge variability in future cash flows associated with highly probable future sale transactions of gas or electricity or on already contracted sales due to different indexation mechanism of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. The effects of the measurement at fair value of cash flow hedge derivatives are given in note 36 — Shareholders’ equity and in note 40 — Operating expenses. Information on hedged risks and hedging policies is disclosed in note 38 — Guarantees, commitments and risks — Risk factors.

Options embedded in convertible bonds of €16 million as of December 31, 2017, related to equity-linked cash settled bonds (€46 million at December 31, 2016). More information is disclosed in note 29 — Long-term debt and current portion of long-term debt.

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The offsetting of financial derivatives of €1,279 million (€1,281 million) related to Eni Trading & Shipping SpA for €1,144 million (€1,145 million at December 31, 2016) and Eni Trading & Shipping Inc for €135 million (€136 million at December 31, 2016).

During the 2017, there were no transfers between the different hierarchy levels of fair value.

35 Assets held for sale and liabilities directly associated with assets held for sale

As of December 31, 2017, assets held for sale and the related directly associated liabilities of €323 million and €87 million, respectively, related to: (i) an agreement signed by Eni and MET Holding AG to divest 98.99% (entire stake owned) of Tigáz Zrt and Tigáz DSO (100% Tigáz Zrt) to MET, including Eni’s gas distribution operations in Hungary. The transaction is subject to regulatory approval by the relevant authorities. The carrying amount of assets held for sale and directly associated liabilities amounted to €241 million (of which current assets for €31 million) and €65 million (of which current liabilities for €27 million), respectively; (ii) the sale by Lasmo Sanga Sanga of the business relating to a 26.25% stake (entire stake owned) of the PSA in the Sanga Sanga gas and condensates field. The carrying amount of assets held for sale and directly associated liabilities amounted to €53 million (of which current assets for €37 million) and €22 million (of which current liabilities for €10 million), respectively; (iii) the sale of a 50% (entire stake owned) interest in the joint venture Unimar Llc, a minor investment and tangible assets for a total amount of €29 million.

36 Shareholders’ equity

Non-controlling interest

	Net profit				Shareholders’ equity
(€ million)	2017		2016		December 31, 2017		December 31, 2016
EniPower Mantova SpA		4		5		23		21
Adriaplin Doo		2		2		14		13
Serfactoring SpA		(3)				12		15
		3		7		49		49

Eni shareholders’ equity

(€ million)	December 31, 2017		December 31, 2016
Share capital		4,005		4,005
Legal reserve		959		959
Reserve for treasury shares		581		581
Reserve related to the fair value of cash flow hedging derivatives net of the tax effect		183		189
Reserve related to the fair value of available-for-sale securities net of the tax effect				4
Reserve related to the defined benefit plans net of tax effect		(114)		(112)
Other reserves		280		211
Cumulative currency translation differences		4,818		10,319
Treasury shares		(581)		(581)
Retained earnings		35,966		40,367
Interim dividend		(1,441)		(1,441)
Net profit (loss) for the year		3,374		(1,464)
		48,030		53,037

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Share capital

As of December 31, 2017, the parent company’s issued share capital consisted of €4,005,358,876 represented by 3,634,185,330 ordinary shares without nominal value (same amounts as of December 31, 2016).

On April 13, 2017, Eni’s Shareholders’ Meeting resolved the distribution of a dividend of €0.40 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2016 dividend of €0.80 per share, of which €0.40 per share paid as interim dividend in September 2016.

Legal reserve

This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law.

Reserve for treasury shares

The reserve for treasury shares of €581 million (same amount as of December 31, 2016) represents the reserve that was established in previous reporting period to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings.

Reserves related to the fair value measurement of cash flow hedging derivatives,
available-for-sale financial assets and defined benefit plans

The reserves related to the valuation at fair value of cash flow hedging derivatives, available-for-sale financial instruments and defined benefit plans, net of the related tax effect, consisted of the following:

	Cash flow hedge derivatives						Available-for-sale financial instruments						Defined benefit plans						Total
(€ million)	Gross reserve		Deferred tax liabilities		Net reserve		Gross reserve		Deferred tax liabilities		Net reserve		Gross reserve		Deferred tax liabilities		Net reserve		Gross reserve		Deferred tax liabilities		Net reserve
Reserve as of December 31, 2016		246		(57)		189		5		(1)		4		(99)		(13)		(112)		152		(71)		81
Changes of the year 2017		(59)		14		(45)		(5)		1		(4)		(33)		29		(4)		(97)		44		(53)
Foreign currency translation differences														(1)		3		2		(1)		3		2
Reversal of the year 2017		53		(14)		39														53		(14)		39
Reserve as of December 31, 2017		240		(57)		183								(133)		19		(114)		107		(38)		69
Reserve as of December 31, 2015		(637)		163		(474)		9		(1)		8		(111)		10		(101)		(739)		172		(567)
Changes of the year 2016		360		(90)		270		(3)				(3)		16		(35)		(19)		373		(125)		248
Foreign currency translation differences														(4)		12		8		(4)		12		8
Reversal of the year 2016		523		(130)		393		(1)				(1)								522		(130)		392
Reserve as of December 31, 2016		246		(57)		189		5		(1)		4		(99)		(13)		(112)		152		(71)		81

Other reserves

Other reserves amounting to €280 million (€211 million at December 31, 2016) related to:

•

a reserve of €247 million representing the increase in Eni shareholders’ equity associated with a business combination under common control, whereby the parent company Eni SpA divested its subsidiary Snamprogetti SpA to Saipem Projects SpA (both merged into Saipem SpA) at a price higher than the book value of the interest transferred (same amount as of December 31, 2016);

•

a reserve of €63 million deriving from Eni SpA’s equity (same amount as of December 31, 2016);

•

a reserve of €90 million relating to the share of “Other comprehensive income” on equity accounted entities (€21 million at December 31, 2016);

•

a reserve of €4 million representing the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 48.55% in the subsidiary Tigáz Zrt (same amount as of December 31, 2016);

•

a negative reserve of €124 million representing the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 45.99% in the subsidiary Altergaz SA, now Eni Gas & Power France SA (same amount as of December 31, 2016).

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Cumulative foreign currency translation differences

The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.

Treasury shares

A total of 33,045,197 Eni’s ordinary shares (same amount as of December 31, 2016) were held in treasury for a total cost of €581 million (same amount as of December 31, 2016).

Interim dividend

The interim dividend for the year 2017 amounted to €1,441 million corresponding to €0.40 per share, as resolved by the Board of Directors on September 14, 2017, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 20, 2017.

Distributable reserves

As of December 31, 2017, Eni shareholders’ equity included distributable reserves of approximately €43.2 billion.

Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA
to consolidated net profit and shareholders’ equity

	Net profit				Shareholders’ equity
(€ million)	2017		2016		December 31, 2017		December 31, 2016
As recorded in Eni SpA’s Financial Statements		3,586		4,521		42,529		41,935
Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company		(466)		(5,480)		6,110		12,384
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity		(1)		(44)		145		240
- adjustments to comply with Group account policies		202		(188)		719		461
- elimination of unrealized intercompany profits		(88)		(56)		(807)		(801)
- deferred taxation		144		(210)		(617)		(1,133)
		3,377		(1,457)		48,079		53,086
Non-controlling interest		(3)		(7)		(49)		(49)
As recorded in Consolidated Financial Statements		3,374		(1,464)		48,030		53,037

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37 Other information

Supplemental cash flow information


(€ million)	2017		2016		2015
Disposal of consolidated subsidiaries and businesses
Current assets		166		6,526		44
Non-current assets		814		8,615		125
Net borrowings		(252)		(5,415)		(77)
Current and non-current liabilities		(205)		(6,334)		(45)
Net effect of disposals		523		3,392		47
Reclassification of foreign currency translation differences among other items of comprehensive income				7		(34)
Fair value of share capital held after the sale of control				(1,006)
Gain on disposal		2,148		11		66
Non-controlling interest				(1,872)
Selling price		2,671		532		79
less:
Cash and cash equivalents		(9)		(894)		(6)
Disposal of consolidated subsidiaries and businesses net of cash and cash equivalent		2,662		(362)		73

Cash flow from disposals of 2017 related to: (i) the sale to ExxonMobil of a 25% interest in natural gas-rich Area 4 offshore Mozambique where development activities are ongoing to put into production the significant gas resources discovered by Eni. Particularly in 2017, Eni made the final investment decision (FID) of the Coral FLNG project regarding development of gas reserves. The cash consideration amounted to €2,362 million plus the corresponding portion of net borrowings of the business divested to the buyer amounting to €264 million; (ii) the sale of the whole interest in the consolidated company Eni Gas & Power NV and its subsidiary Eni Wind Belgium NV, operating in the gas & power retail activities in Belgium. The sale price amounted to €302 million including cash divested of €8 million.

38 Guarantees, commitments and risks

Guarantees

	December 31, 2017						December 31, 2016
(€ million)	Unsecured guarantees		Other guarantees		Total		Unsecured guarantees		Other guarantees		Total
Consolidated subsidiaries				5,594		5,594				5,868		5,868
Unconsolidated subsidiaries				181		181				246		246
Consolidated joint operations				1		1				1		1
Joint ventures and associates		6,124		3,922		10,046		6,124		2,112		8,236
Others				352		352				202		202
		6,124		10,050		16,174		6,124		8,429		14,553

Guarantees of €16,174 million (€14,553 million at December 31, 2016) increased by €1,621 million, reflecting new issuance on behalf of third parties who have contractual obligations towards Eni’s affiliates to build and finance the construction of an LNG Floating Production unit for the development of the Coral gas reserves discovered in Area 4 offshore Mozambique. Eni is operator of the project with a 25% interest through a 35.71% stake in the joint operation Mozambique Rovuma Venture SpA (former Eni East Africa SpA) following the sale, finalized in December 2017, to ExxonMobil of a 35.71% interest in the venture (being 50% of the whole Eni interest). The Coral project obtained final investment decision (FID) on 1 June 2017 following the sign of: (i) the Engineering Procurement Construction Installation and Commissioning (EPCIC) contract of a vessel for the floating production of LNG (FLNG) with the Technip — JGC — Samsung Heavy Industries consortium with a value of $5,248 million (€4,375 million); (ii) the project financing agreements with Export Credit Agencies (Sace, BPI, K-Exim, K-Sure e Sinosure) and commercial banks amounting to $4,676 million (€3,898 million). The FLNG plant is designed to treat

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approximately 3.37 million tonnes per year of LNG. A special purpose entity, Coral FLNG SA, will own and operate the unit. Eni retains a 25% interest in his entity, down from a 50% previously held following the divestment to ExxonMobil. The entity will operate under a service agreement with the Concessionaires of Area 4 for the liquefaction, storage and loading of the LNG. The LNG will be supplied to BP under a long-term LNG sale and purchase agreement with a take-or-pay clause and a twenty-year term, providing an option of extending the duration for up to ten consecutive years. Eni has issued through a subsidiary a parent company guarantee, whereby it irrevocably and unconditionally guarantees to the TJS consortium — the beneficiaries — the due and proper performance of the obligations of Coral FLNG SA in connection with execution of the EPCIC contract, up to the maximum liability of $1,312 million (€1,094 million) equal to 25% of the value of the contract. The maximum liability will be automatically reduced by any amount paid to the beneficiaries in respect of the guaranteed obligations. During the construction and the commissioning of the FLNG plant, the project financing agreement will be supported by a debt service undertaking, up to a maximum liability of $6,400 million equal to $1,600 million (€1,334 million) in proportion to Eni’s participating interest equal to 25% in the industrial initiative. Subsequently, in the running phase of the plant, once the performance tests have been validated by the lenders, that guarantee will be released and the financing facility will change into a non-recourse one, terminating the obligations of the Concessionaires and the Sponsors of Area 4. In that phase, the lenders will be assisted only by a guarantee on the perimeter of the project, without giving the gas reserves as guarantee. The financing and any collateral costs will be reimbursed to the lenders through a “pay-when-paid” clause, whereby loan repayments will be made through the cash flows associated with the sale of the LNG arising from the project to the long-term buyer, without any obligations from Eni and the other Sponsors and Concessionaires to guarantee the performance of Coral FLNG SA towards the lenders. Furthermore, the Sponsors subscribed, directly or through their affiliates, a credit facility which committed each Sponsors to finance pro-quota: (i) the share of capital expenditures to be borne by the Mozambique State-owned company ENH up to a maximum liability of $500 million equal to €417 million ($139 million equal to €116 million, being Eni’s share); (ii) the share of the debt service undertaking by ENH up to a maximum liability of $640 million, equal to €533 million ($178 million, equal to €148 million, being Eni’s share). Finally, as provided by the Exploration and Production Concession Contract that regulates the petroleum activities in Area 4, Eni SpA in its capacity as parent company of the operator Mozambique Rovuma Venture SpA has provided concurrently with the approval of the initial development plan of the Area reserves, an irrevocable and unconditional parent company guarantee in respect of any possible claims or any contractual breaches in connection with the petroleum activities to be carried out in the contractual area, including those activities in charge of the special purpose entities like Coral FLNG SA, to benefit of the Government of Mozambique and third parties. The obligations of the guarantor towards the Government of Mozambique are unlimited (non-quantifiable commitments), whereas they provide a maximum liability of $1,500 million (€1,250 million) in respect of third-parties claims. This guarantee will be effective until the completion of any decommissioning activity related to both the development plan of Coral as well as any development plan to be executed within Area 4 (particularly the Mamba project). This parent company guarantee issued by Eni covering 100% of the aforementioned obligations has been taken over by the other concessionaires (Kogas, Galp and ENH) and by ExxonMobil and CNPC shareholders of the joint operation Mozambico Rovuma Venture SpA, in proportion to their respective direct or indirect participating interest in the EPCIC of Area 4. In particular, the retaining interests pertaining to the two other shareholders amounted to 25% for ExxonMobil, following the acquisition of the 35.7% interest in the venture finalized in December 2017, and to 20% for CNPC.

Other guarantees issued on behalf of consolidated subsidiaries of €5,594 million (€5,868 million at December 31, 2016) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for €2,312 million (€1,965 million at December 31, 2016); (ii) VAT recoverable from tax authorities for €1,201 million (€1,380 million at December 31, 2016); (iii) a bank guarantee of €1,010 million (same amount as of December 31, 2016) issued on behalf of GasTerra in order to obtain the renunciation to a temporary seizure order on Eni’s investment in Eni International BV, requested and obtained by a Netherlands Court in July 2016; and (iv) insurance risk for €137 million reinsured by Eni (€141 million at December 31, 2016). At December 31, 2017, the underlying commitment covered by such guarantees was €5,563 million (€5,784 million at December 31, 2016).

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Other guarantees issued on behalf of unconsolidated subsidiaries of €181 million (€246 million at December 31, 2016) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for €176 million (€240 million at December 31, 2016). At December 31, 2017, the underlying commitment covered by such guarantees was €12 million (€53 million at December 31, 2016).

Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates of €10,046 million (€8,236 million at December 31, 2016) primarily consisted of: (i) an unsecured guarantee of €6,122 million (same amount as of December 31, 2016) given by Eni SpA to Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) for the proper and timely completion of a project relating to the Milan-Bologna fast track railway by CEPAV (Consorzio Eni per l’Alta Velocità) Uno (associated company of Saipem); consortium members, excluding Saipem Group, gave Eni liability of surety letters and bank guarantees amounting to 10% of their respective portion of the work; (ii) unsecured guarantees and other guarantees given to banks in relation to loans and lines of credit received for €1,623 million (€82 million at December 31, 2016), of which €1,334 million related to guarantees issued as part of the development project of the gas reserves at the Coral discovery in Area 4 offshore Mozambique on behalf of Coral South FLNG DMCC with respect to the financing agreements of the project with Export Credit Agencies and banks; and (iii) guarantees given to third parties relating to bid bonds and performance bonds for €2,122 million (€1,705 at December 31, 2016), of which €1,094 million related to guarantees issued for the construction of the FLNG as part of the development project of the gas reserves at the Coral project offshore Mozambique and €1,008 million given on behalf of Saipem Group (€1,705 million at December 31, 2016). At December 31, 2017, the underlying commitment covered by such guarantees was €2,594 million (€2,109 million at December 31, 2016).

Unsecured and other guarantees given on behalf of third parties of €352 million (€202 million at December 31, 2016) primarily consisted of: (i) a guarantee issued on a pro-quota basis in the interest of ENH for the development of the Coral offshore project for €148 million ($178 million, Eni’s interest 25%); (ii) guarantees issued on behalf of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni’s interest 13.6%) as security against payment commitments of fees in connection with the regasification activity for €169 million (€193 million at December 31, 2016). At December 31, 2016, the underlying commitment covered by such guarantees was €224 million (€202 million at December 31, 2016).

Commitments and risks

(€ million)	December 31, 2017		December 31, 2016
Commitments		14,498		20,682
Risks		691		605
		15,189		21,287

Other commitments of €14,498 million (€20,682 million at December 31, 2016) related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities and quantified, on the basis of the capital expenditures to be incurred, to €11,289 million (€12,415 million at December 31, 2016); (ii) commitments entered by the Exploration & Production segment for operating leasing contracts (chartering, operation and maintenance) of FPSO vessels for €4,344 million outstanding at December 31, 2016 were set to zero following the start of the development projects in Angola and Ghana operated through the aforementioned FPSO vessels whose acquisition under operating leases entailed the recognition of future non-cancellable fees in the table “Future payments under contractual obligations” of this section; (iii) commitments assumed by Eni USA Gas Marketing Llc towards Angola LNG Supply Service Llc for the acquisition of volumes of regasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031) and towards Gulf LNG Energy for the acquisition of regasification capacity at the Pascagoula terminal (5.8 BCM/y) over a twenty-year period (until 2031). The expected commitments have been estimated at €2,113 million and €948 million, respectively (€2,541 million and €1,156 million at December 31, 2016, respectively) and have been included in off-balance sheet contractual commitments in the table “Future payments under contractual obligations”; and (iv) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest €128 million (€129 million at December 31, 2016) in the future, also on account of Shell Italia E&P SpA, in connection with Eni’s development plan of oilfields in Val d’Agri. The commitment has been included in the off-balance sheet contractual commitments in the following paragraph “Liquidity risk”.

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Risks of €691 million (€605 million at December 31, 2016) primarily concerned potential risks associated with contractual assurances given to acquirers of certain investments and businesses of Eni for €235 million (€334 million at December 31, 2016) and the value of assets of third parties under the custody of Eni for €456 million (€271 million at December 31, 2016).

Non-quantifiable commitments

A parent company guarantee was issued on behalf of Cardón IV SA (Eni’s interest 50%), a joint venture that is currently executing development activities at the Perla gas field located in Venezuela, for the supplying to PDVSA GAS of the volumes of gas produced by the field until end of the concession agreement (2036). This guarantee cannot be quantified because the penalty clause for unilateral anticipated resolution originally set for Eni and the relevant quantification became ineffective due to a revision of the contractual terms. In case of failure on part of the operator to deliver the contractual gas volumes out of production, the claim under the guarantee will be determined by applying the local legislation. Eni share (50%) of the contractual volumes of gas to be delivered to PDVSA GAS amounted to a total of $16 billion (€13.3 billion). Notwithstanding this amount does not properly represent the guarantee exposure, nonetheless such amount represents the maximum financial exposure at risk for Eni. A similar guarantee was issued by PDVSA on behalf of Eni for the fulfillment of the purchase commitments of the gas volumes by PDVSA GAS.

Following the integration signed on April 19, 2011, Eni confirmed to RFI — Rete Ferroviaria Italiana SpA its commitment, previously assumed under the convention signed with Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) on October 15, 1991, to guarantee a correct and timely execution of the section Milano-Brescia of the high-speed railway from Milan to Verona. Such integration provides for CEPAV (Consorzio Eni per l’Alta Velocità) Due to act as general contractor. In order to pledge the guarantee given, the regulation of CEPAV (Consorzio Eni per l’Alta Velocità) Due binds the associates to give proper sureties and guarantees on behalf of Eni.

Eni is liable for certain non-quantifiable risks related to contractual assurances given to acquirers of certain Eni assets, including businesses and investments, against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were operated by Eni. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and liquidity.

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Risk factors

Financial risks

Financial risks are managed in respect of guidelines issued by the Board of Directors of Eni SpA in its role of directing and setting of the risk limits, targeting to align and centrally coordinate Group companies’ policies on financial risks (“Guidelines on financial risks management and control”). The “Guidelines” define for each financial risk the key components of the management and control process, such as the aim of the risk management, the valuation methodology, the structure of limits, the relation model and the hedging and mitigation instruments.

Market risk

Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of handling finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department, Eni Finance International SA, Eni Finance USA Inc and Banque Eni SA, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni’s finance department and Eni Finance International SA manage subsidiaries’ financing requirements in and outside Italy, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies different from commodities are managed by the parent company. The commodity risk associated with commercial exposures of each business unit (Eni’s business line or subsidiaries) is pooled and managed by the Gas & LNG Marketing and Power business line, which manages the market risk component in a view of portfolio, while Eni Trading & Shipping SpA executes the negotiation of commodity derivatives over the market. Eni SpA and Eni Trading & Shipping SpA (also through its subsidiary Eni Trading & Shipping Inc) perform trading activities in financial derivatives on external trading venues, such as European and non-European regulated markets, Multilateral Trading Facility (MTF), Organized Trading Facility (OTF), or similar and brokerage platforms (i.e. SEF), and over the counter on a bilateral basis with external counterparties. Other legal entities belonging to Eni that require financial derivatives enter into these operations through Eni Trading & Shipping and Eni SpA based on the relevant asset class expertise. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to fluctuations in exchange rates relating to those transactions denominated in a currency other than the functional currency (the euro) and interest rates, as well as to optimize exposure to commodity prices fluctuations taking into account the currency in which commodities are quoted. Eni monitors every activity in derivatives classified as risk-reducing (in particular, back-to-back activities, flow hedging activities, asset-backed hedging activities and portfolio-management activities) directly or indirectly related to covered industrial assets, so as to effectively optimize the risk profile to which Eni is exposed or could be exposed. If the result of the monitoring shows those derivatives should not be considered as risk reducing, these derivatives are reclassified in proprietary trading. As the proprietary trading is considered separately from the other activities in specific portfolios of Eni Trading & Shipping, its exposure is subject to specific controls, both in terms of Value at Risk (VaR) and stop loss and in terms of nominal gross value. For Eni, the gross nominal value of proprietary trading activities is compared with the limits set by the relevant international standards. The framework defined by Eni’s policies and guidelines provides that the valuation and control of market risk is performed on the basis of maximum tolerable levels of risk exposure defined in terms of: (i) limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon; (ii) limits of revision strategy, which consist in the triggering of a revision process of the strategy in the event of exceeding the level of profit and loss given; and (iii) VaR which measures the maximum potential loss of the portfolio, given a certain confidence level and holding period, assuming adverse changes in market variables and taking into account of the correlation among the different positions held in the portfolio. Eni’s finance department defines the maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of VaR, pooling Group companies’ risk positions maximizing, when possible, the benefits of the netting activity. Eni’s calculation and valuation techniques for interest rate and foreign currency exchange rate risks are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni Group companies minimize such kinds of market risks by transferring risk exposure to the parent company finance department. Eni’s

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guidelines define rules to manage the commodity risk aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of VaR, limits of revision strategy, stop loss and volumes in connection with exposure deriving from commercial activities, as well as exposure deriving from proprietary trading, exclusively managed by Eni Trading & Shipping. Internal mandates to manage the commodity risk provide for a mechanism of allocation of the Group maximum tolerable risk level to each business unit. In this framework, Eni Trading & Shipping, in addition to managing risk exposure associated with its own commercial activity and proprietary trading, pools the requests for negotiating commodity derivatives and executes them on the marketplace.

According to the targets of financial structure included in the financial plan approved by the Board of Directors, Eni has decided to retain a cash reserve to face any extraordinary requirement. Eni’s finance department, with the aim of optimizing the efficiency and ensuring maximum protection of the capital, manages such reserve and its immediate liquidity within the limits assigned. The management of strategic cash is part of the asset management pursued through transactions on own risk in view of optimizing financial returns, while respecting authorized risk levels, safeguarding the Company’s assets and retaining quick access to liquidity.

The four different market risks, whose management and control have been summarized above, are described below.

Market risk — Exchange rate

Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than the euro (mainly the U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rates fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than the euro are translated from their functional currency into euro. Generally, an appreciation of the U.S. dollar versus the euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s foreign exchange risk management policy is to minimize transactional exposures arising from foreign currency movements and to optimize exposures arising from commodity risk. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries, which prepare financial statements in a currency other than the euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s central finance department, which pools Group companies’ positions, hedging the Group net exposure by using certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value based on market prices provided by specialized info-providers. Changes in fair value of those derivatives are normally recognized through profit and loss, as they do not meet the formal criteria to be recognized as hedges. The VaR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period.

Market risk — Interest rate

Changes in interest rates affect the market value of financial assets and liabilities of the Company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in the management’s finance plans. The Group’s central finance department pools borrowing requirements of the Group companies in order to manage net positions and fund portfolio developments consistent with management plans, thereby maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to manage effectively the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value based on market prices provided from specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account, as they do not meet the formal criteria to be accounted for under the hedge accounting method. VaR deriving from interest rate exposure is measured daily based on a variance/covariance model, with a 99% confidence level and a 20-day holding period.

Market risk — Commodity

Eni’s results of operations are affected by changes in the prices of commodities. A decrease in oil&gas prices generally, has a negative impact on Eni’s results of operations and vice versa, and may jeopardize the

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achievement of the financial targets preset in the Company’s four-year plans and budget. The commodity price risk arises in connection with the following exposures: (i) strategic exposure: exposures directly identified by the Board of Directors as a result of strategic investment decisions or outside the planning horizon of risk. These exposures include those associated with the program for the production of proved and unproved oil&gas reserves, long-term gas supply contracts for the portion not balanced by ongoing or highly probable sale contracts, refining margins identified by the Board of Directors as of strategic nature (the remaining volumes can be allocated to the active management of the margin or to asset-backed hedging activities) and minimum compulsory stocks; (ii) commercial exposure: includes the exposures related to the components underlying the contractual arrangements of industrial and commercial activities and, if related to take-or-pay commitments, to the components related to the time horizon of the four-year plan and budget and the relevant activities of risk management. Commercial exposures are characterized by a systematic risk management activity conducted based on risk/return assumptions by implementing one or more strategies and subjected to specific risk limits (VaR, revision strategy limits and stop loss). In particular, the commercial exposures include exposures subjected to asset-backed hedging activities, arising from the flexibility/optionality of assets; and (iii) proprietary trading exposure: includes operations independently conducted for profit purposes in the short term, and normally not finalized to the delivery, both within the commodity and financial markets, with the aim to obtain a profit upon the occurrence of a favorable result in the market, in accordance with specific limits of authorized risk (VaR, stop loss). In the proprietary trading exposures are included the origination activities, if not connected to contractual or physical assets.

Strategic risk is not subject to systematic activity of management/coverage that is eventually carried out only in case of specific market or business conditions. Because of the extraordinary nature, hedging activities related to strategic risks are delegated to the top management. Strategic risk is subject to measuring and monitoring but is not subject to specific risk limits. If previously authorized by the Board of Directors, exposures related to strategic risk can be used in combination with other commercial exposures in order to exploit opportunities for natural compensation between the risks (natural hedge) and consequently reduce the use of derivatives (by activating logics of internal market). Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable economic results. The commodity risk and the exposure to commodity prices fluctuations embedded in commodities quoted in currencies other than the euro at each business line (Eni’s Divisions or subsidiaries) is pooled and managed by the Portfolio Management unit for commodities, and by Eni’s finance department for exchange rate requirements. The Portfolio Management unit manages business lines’ risk exposures to commodities, pooling and optimizing Group companies’ exposures and hedging net exposures on the trading venues through the trading unit of Eni Trading & Shipping. In order to manage commodity price risk, Eni uses derivatives traded on the organized markets MTF, OTF and derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with the underlying commodities being crude oil, gas, refined products, electricity or emission certificates. Such derivatives are evaluated at fair value based on market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable valuation techniques. VaR deriving from commodity exposure is measured daily based on a historical simulation technique, with a 95% confidence level and a one-day holding period.

Market risk — Strategic liquidity

Market risk deriving from liquidity management is identified as the possibility that changes in prices of financial instruments (bonds, money market instruments and mutual funds) would affect the value of these instruments when evaluated at fair value. In order to manage the investment activity of the strategic liquidity, Eni defined a specific investment policy with aims and constraints in terms of financial activities and operational boundaries, as well as Governance guidelines regulating management and control systems. The setting up and maintenance of the liquidity reserve is mainly aimed to: (i) guarantee of financial flexibility. Liquidity should allow Eni Group to fund any extraordinary need (such as difficulty in access to credit, exogenous shock, macroeconomic environment, as well as merger and acquisitions); and (ii) ensure a full coverage of short-term debts and a coverage of medium and long-term financial debts due within a time horizon of 24 months, even in case of restrictions to credit.

Strategic liquidity management is regulated in terms of VaR (measured based on a parametrical methodology with a one-day holding period and a 99% confidence level), stop loss and other operating limits in terms of concentration, duration, ratings, liquidity and instruments to invest on. Financial

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leverage or short selling is not allowed. Activities in terms of strategic liquidity management started in the second half of the year 2013 and throughout the course of the years 2014 and 2015, the investment portfolio has maintained an average credit rating of A/A-, accordingly with the decrease in the Company’s credit rating.

The following table shows amounts in terms of VaR, recorded in 2017 (compared with 2016) relating to interest rate and exchange rate risks in the first section and commodity risk.

(Value at risk — parametric method variance/covariance; holding period: 20 days; confidence level: 99%)


	2017								2016
(€ million)	High		Low		Average		At year end		High		Low		Average		At year end
Interest rate(a)		3.76		1.72		2.38		2.58		5.27		2.55		3.62		3.42
Exchange rate(a)		0.57		0.08		0.22		0.26		0.34		0.04		0.14		0.17

(a)

Value at risk deriving from interest and exchange rates exposures include the following finance department: Eni Corporate Treasury Department, Eni Finance International SA, Banque Eni SA and Eni Finance USA Inc.

(Value at risk — Historic simulation weighted method; holding period: 1 day; confidence level: 95%)


	2017								2016
(€ million)	High		Low		Average		At year end		High		Low		Average		At year end
Commercial exposures - Management Portfolio(a)		21.14		5.15		12.24		5.15		19.03		4.23		10.24		9.41
Trading(b)		2.29		0.21		0.79		0.66		2.58		0.27		0.87		1.35

(a)

Refers to the Gas & LNG Marketing Power business line (risk exposure from Refining & Marketing business line and Gas & Power Division), Eni Trading & Shipping commercial portfolio, operating branches outside Italy pertaining to the Divisions and from October 2016 the Gas and Luce Business line. For the gas&power business lines, following the approval of the Eni’s Board of Directors on December 12, 2013, VaR is calculated on the so-called Statutory view, with a time horizon that coincides with the year considering all the volumes delivered in the year and the relevant financial hedging derivatives. Consequently, in the year the VaR pertaining to GLP and EGL presents a decreasing trend following the progressive reaching of the maturity of the positions within the annual horizon.

(b)

Cross-commodity proprietary trading, both for commodity contracts and financial derivatives, refers to Eni Trading & Shipping SpA (London-Bruxelles-Singapore) and Eni Trading & Shipping Inc (Houston).

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differently credit risk depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units and Eni’s corporate financial and accounting units are responsible for managing credit risk arising in the normal course of the business.

The Group has established formal credit systems and processes to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. In addition, credit litigation and receivable collection activities are assessed.

Eni’s corporate units define directions and methods for quantifying and controlling customer’s reliability. With regard to risk arising from financial counterparties deriving from current and strategic use of liquidity, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group operating finance department, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity

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derivatives transactions and by Group companies and Divisions, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterparty on a daily basis.

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 finance requirements and to settle obligations. Such a situation would negatively affect Group results, as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. As part of its financial planning process, Eni manages the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs, optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt in terms of: (i) maximum ratio between net financial debt and net equity (leverage); (ii) minimum incidence of medium and long-term debts over the total amount of financial debts; (iii) minimum amount of fixed-rate debts over the total amount of medium and long-term debts; and (iv) minimum level of liquidity reserve. For this purpose, Eni holds a significant amount of liquidity reserve (financial assets plus committed credit lines), which aims to: (i) ensure a full coverage of short-term debt and the coverage of medium and long-term debts with a maturity of 24 months, even in case of restrictions to the credit access; (ii) deal with identified risk factors that could significantly affect the cash flow expected in the Financial Plan (i.e.changes in the scenario and/or production volumes, delays in disposals); (iii) ensuring the availability of an adequate level of financial flexibility to support the Group’s development plans; and (iv) maintaining/improving the current credit rating. The financial asset reserve is employed in short-term marketable financial instruments, favouring investments with very low risk profile.

At present, the Group believes to have access to sufficient funding to meet the current foreseeable borrowing requirements as a consequence of the availability of financial assets and lines of credit and the access to a wide range of funding at competitive costs through the credit system and capital markets.

Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which about €16.8 billion were drawn as of December 31, 2017.

The Group has credit ratings of BBB+ outlook positive and A-2, respectively for long and short-term debt, assigned by Standard & Poor’s and Baa1 outlook stable and P-2, respectively for long and short-term debt, assigned by Moody’s. Eni’s credit rating is linked in addition to the Company’s industrial fundamentals and trends in the trading environment to the sovereign credit rating of Italy. Based on the methodologies used by Standard & Poor’s and Moody’s, a downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni.

In the course of the 2017, Eni issued bonds amounting to €1,8 billion related to the Euro Medium Term Notes Program.

As of December 31, 2017, Eni maintained short-term unused borrowing facilities of €11,625 million, of which €41 million committed. Long-term committed unused borrowing facilities amounted to €5,802 million, of which €750 million were due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions.

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Finance debt repayments including expected payments for interest charges and derivatives

The table below summarizes the Group main contractual obligations for finance liability repayments, including expected payments for interest charges and derivatives.

	Maturity year
(€ million)	2018		2019		2020		2021		2022		2023 and thereafter		Total
December 31, 2017
Non-current financial liabilities		2,000		4,084		2,857		1,279		1,246		10,810		22,276
Current financial liabilities		2,242												2,242
Fair value of derivative instruments		1,011		64		10		1		16				1,102
		5,253		4,148		2,867		1,280		1,262		10,810		25,620
Interest on finance debt		582		511		411		304		250		1,455		3,513
Financial guarantees		473												473

	Maturity year
(€ million)	2017		2018		2019		2020		2021		2022 and thereafter		Total
December 31, 2016
Non-current financial liabilities		2,988		2,090		4,044		2,914		1,285		10,332		23,653
Current financial liabilities		3,396												3,396
Fair value of derivative instruments		2,108		36		76				46		3		2,269
		8,492		2,126		4,120		2,914		1,331		10,335		29,318
Interest on finance debt		696		557		486		386		277		1,605		4,007
Financial guarantees		84												84

Trade and other payables

The table below summarizes the Group trade and other payables by maturity.

	Maturity year
(€ million)	2018		2019 – 2022		2023 and thereafter		Total
December 31, 2017
Trade payables		10,890						10,890
Other payables and advances		5,858		19		26		5,903
		16,748		19		26		16,793

	Maturity year
(€ million)	2017		2018 – 2021		2022 and thereafter		Total
December 31, 2016
Trade payables		11,038						11,038
Other payables and advances		5,665		29		22		5,716
		16,703		29		22		16,754

Expected payments by period under contractual obligations

In addition to trade and financial liabilities represented in the balance sheet, the company is subject to non-cancellable contractual obligations or obligations, the cancellation of which requires the payment of a penalty. These obligations will require cash settlements in future reporting periods. These liabilities are valued based on the net cost for the company to fulfill the contract, which consists of the lowest amount between the costs for the fulfillment of the contractual obligation and the contractual compensation/penalty in the event of the non-performance.

The Company’s main contractual obligations at the balance sheet date comprise take-or-pay clauses contained in the Company’s gas supply contracts or shipping arrangements, whereby the Company obligations consist of off-taking minimum quantities of product or service or, in case of failure, paying the

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corresponding cash amount that entitles the Company the right to collect the product or the service in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors. Other contractual obligations relate to operating leases for FPSO units of the E&P segment, in particular the FPSOs operating in the offshore projects at Cape Three Points in Ghana and at the 15/06 block in Angola, with a duration of between 12 and 21 years.

The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis.

	Maturity year
(€ million)	2018		2019		2020		2021		2022		2023 and thereafter		Total
Operating lease obligations(a)		883		525		485		371		329		1,939		4,532
Decommissioning liabilities(b)		348		411		398		375		207		13,047		14,786
Environmental liabilities		317		311		282		228		178		1,357		2,673
Purchase obligations(c)		10,989		9,862		8,223		8,233		8,071		62,452		107,830
- Gas
- take-or-pay contracts		8,644		8,708		7,452		7,542		7,553		60,345		100,244
- ship-or-pay contracts		1,272		760		516		468		380		1,291		4,687
- Other ship-or-pay obligations		110		99		87		73		59		161		589
- Other purchase obligations(d)		963		295		168		150		79		655		2,310
Other obligations		11		3		2		2		2		108		128
- Memorandum of intent relating Val d’Agri		11		3		2		2		2		108		128
		12,548		11,112		9,390		9,209		8,787		78,903		129,949

(a)

Operating leases primarily regarded assets for drilling activities, time charter and long term rentals of vessels, lands, service stations and office buildings. Such leases generally did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.

(b)

(c)

Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.

(d)

Mainly refers to arrangements to purchase capacity entitlements at certain regasification facilities in the U.S. (€948 million).

Capital investment and capital expenditures commitments

In the next four years, Eni expects capital investments and capital expenditures of €31.6 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects. Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. At this stage, procurement contracts to execute those projects have already been awarded or are being awarded to third parties.

The amounts shown in the table below include committed expenditures to execute certain environmental projects.

	Maturity year
(€ million)	2018		2019		2020		2021		2022 and thereafter		Total
Committed projects		6,309		5,688		4,717		3,375		3,770		23,859

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Other information about financial instruments

The carrying amount of financial instruments and the relevant economic and equity effect consisted of the following:


	2017						2016
(€ million)	Carrying amount		Finance income (expense) recognized in				Carrying amount		Finance income (expense) recognized in
(€ million)	Carrying amount		Profit and loss account		Other comprehensive income		Carrying amount		Profit and loss account		Other comprehensive income
Held-for-trading financial instruments
Securities(a)		6,012		(111)				6,166		(21)
Non-hedging and trading derivatives(b)		209		793				87		(465)
Held-to-maturity financial instruments
Securities(a)		73						75
Available-for-sale financial instruments
Securities(a)		207		9		(4)		238		9		(4)
Receivables and payables and other assets/liabilities valued at amortized cost
Trade receivables and other(c)		15,583		(958)				17,324		(1,116)
Financing receivables(a)		1,918		(116)				2,328		128
Trade payables and other(d)		16,793		(51)				16,754		287
Financing payables(a)		24,707		(1,137)				27,239		(291)
Net assets (liabilities) for hedging derivatives (e)				(42)		(6)				(524)		883

(a)

Income or expense were recognized in the profit and loss account within “Finance income (expense)”.

(b)

In the profit and loss account, economic effects were recognized as loss within “Other operating income (loss)” for €44 million (income for €17 million in 2016) and as income within “Finance income (expense)” for €837 million (loss for €482 million in 2016).

(c)

In the profit and loss account, economic effects were essentially recognized as expense within “Purchase, services and other” for €933 million (expense for €840 million in 2016) (impairments net of reversal) and as expense for €25 million within “Finance income (expense)” (expense for €276 million in 2016) (exchange rate differences at year-end and amortized cost).

(d)

In the profit and loss account, exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were primarily recognized within “Finance income (expense)”.

(e)

In the profit and loss account, income or expense were recognized within “Net sales from operations” and “Purchase, services and other” as expense for €54 million (expense for €523 million in 2016) and as income within “Finance income (expense)” for €12 million (expense for €1 million in 2016) (time value component).

Disclosures about the offsetting of financial instruments

The table below summarizes the disclosures about the offsetting of financial instruments.

(€ million)	Gross amount of financial assets and liabilities		Gross amount of financial assets and liabilities subject to offsetting		Net amount of financial assets and liabilities
December 31, 2017
Financial assets
Trade and other receivables		16,952		1,215		15,737
Other current assets		2,852		1,279		1,573
Financial liabilities
Trade and other liabilities		17,963		1,215		16,748
Other current liabilities		2,794		1,279		1,515
December 31, 2016
Financial assets
Trade and other receivables		18,489		896		17,593
Other current assets		3,872		1,281		2,591
Financial liabilities
Trade and other liabilities		17,599		896		16,703
Other current liabilities		3,880		1,281		2,599

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The offsetting of financial assets and liabilities related to: (i) for €1,279 million (€1,281 million at December 31, 2016) the offsetting assets and liabilities for current financial derivatives pertaining to Eni Trading & Shipping SpA for €1,144 million (€1,145 million at December 31, 2016) and Eni Trading & Shipping Inc for €135 million (€136 million at December 31, 2016); and (ii) for €1,215 million (€896 million at December 31, 2016) the offsetting of receivables and payables pertaining to the Exploration & Production segment towards state entities for €1,041 million (€845 million at December 31, 2016) and the offsetting of trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for €174 million (€51 million at December 31, 2016).

Legal Proceedings

Eni is a party in a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions disclosed in note 30 — Provisions for contingencies and that in some instances it is not possible to make a reliable estimate of contingency losses, Eni believes that the foregoing will likely not have a material adverse effect on the Group Consolidated Financial Statements.

A description of the most significant proceedings currently pending is provided in the following paragraph. Unless otherwise indicated, no provisions have been made for these legal proceedings as Eni believes that negative outcomes are not probable or because the amount of the provision cannot be estimated reliably.

1. Environment, health and safety

1.1 Criminal proceedings in the matters of environment, health and safety

(i) Syndial SpA (company incorporating EniChem Agricoltura SpA — Agricoltura SpA in liquidation — EniChem Augusta Industriale Srl — Fosfotec Srl) — Proceeding about the industrial site of Crotone. In 2010 a criminal proceeding started before the Public Prosecutor of Crotone relating to allegations of environmental disaster, poisoning of substances used in the food chain and omitted clean-up due to the activity at a landfill site which was taken over by Eni’s subsidiary in 1991 following the divestment of an industrial complex by Montedison (now Edison SpA). The landfill site had been filled with industrial waste from Montedison activities until 1989 and then no additional waste was discharged there. Eni’s subsidiary carried out the clean-up of the landfill in 1999 through 2000. The defendants are certain managers at Eni’s subsidiaries that have owned and managed the landfill since 1991. Independent consultants performed an assessment during the 2014. Once the consultants completed their work, the acts returned to the Public Prosecutor of Crotone for the next step and possible indictment. The proceeding continues with the examination of the dismissal request submitted by the defense. The Municipality of Crotone will act as plaintiff. The Prosecutor of Crotone notified the conclusion of the preliminary investigations.

(ii) Syndial SpA and Versalis SpA — Porto Torres — Prosecuting body: Public Prosecutor of Sassari. In July 2011, the Public Prosecutor of Sassari (Sardinia) resolved that a number of officers and senior managers of companies engaging in petrochemical operations at the site of Porto Torres, including the manager responsible for plant operations of the Company’s subsidiary Syndial, would stand trial due to allegations of environmental damage and poisoning of water and crops. The Province of Sassari, the Municipality of Porto Torres and other entities have been acting as plaintiffs. The Judge for the Preliminary Hearing admitted as plaintiffs the above-mentioned parts, but based on the exceptions issued by Syndial on the lack of connection between the action and the charge, denied that the claimants would act as plaintiff with regard to the serious pathologies related to the existence of poisoning agents in the marine fauna of the industrial port of Porto Torres. In February 2013, the Prosecutor of Sassari notified the conclusion of preliminary investigations and requested a new imputation for negligent behaviour instead of illicit conduct. In the conclusions of the preliminary hearing, the Court of Sassari dismissed the accusation because of the statute of limitations. The Public Prosecutor filed an appeal before the Third Instance Court. After a hearing on a question of constitutional legitimacy concerning the period for the statute of limitations for the crime of disaster, the Third Instance Court recognized its validity and therefore accepted the claim and sent all the acts to the Constitutional Court. The Constitutional Court declared the question

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unfounded, considering that the statute of limitations for fraudulent hypothesis and the corresponding culpable hypothesis is an expression of a non-unreasonable legislative discretion, assuming that, in relation to certain culpable offenses causing social alarm, the complexity of the necessary investigations justifies a lengthening of the limitation periods. The Company is awaiting the remission of the documents to the Third Instance Court and, afterwards, to the Office of Public Prosecutor of Sassari.

(iii) Syndial SpA and Versalis SpA — Porto Torres dock. In July 2012, the Judge for the Preliminary Hearing, following a request of the Public Prosecutor of Sassari, requested the performance of a probationary evidence relating to the functioning of the hydraulic barrier of Porto Torres site (ran by Syndial SpA) and its capacity to avoid the dispersion of contamination released by the site in the near portion of sea. Syndial SpA and Versalis SpA have been notified that its chief executive officers and other managers are being investigated. The Public Prosecutor of the Municipality of Sassari requested that the above-mentioned individuals would stand trial. The plaintiffs, the Ministry of Environment and the Sardinia Region, claimed environmental damage in an amount of €1.5 billion. On the hearing dated July 2016, the Judge pronounced an acquittal sentence for all defendants of Syndial and Versalis with respect to the crimes of environmental disaster. Three Syndial managers were found guilty of environmental disaster which took place in the area in the period limited to August 2010 – January 2011 and condemned to one-year prison, with a suspended sentence,. The Judge did not mention any possible malfunctioning of the hydraulic barrier of Porto Torres site or ineffective implementation of any emergency safety measure, as claimed by the Public Prosecutor. Syndial filed an appeal against this decision.

(iv) Syndial SpA — The illegal landfill in Minciaredda area, Porto Torres site. In July 2015, the Judge for the Preliminary Hearing of the Court of Sassari, on request of the Public Prosecutor, seized of the Minciaredda landfill area, near the western border of the Porto Torres site (Minciaredda area). All the indicted have been served a notice of investigation for alleged crimes of carrying out illegal waste disposal and environmental disaster. The seizure provision involved as well Syndial in accordance with the Legislative Degree No. 231 of 2001. With reference to the clean-up activities in the Minciaredda area, on January 27, 2016 the relevant administrative body approved the project for the soil clean-up in the Minciaredda area. Syndial obtained all the necessary ministerial and judicial authorizations to start the remediation project. The Prosecutor notified the conclusion of the preliminary investigations.

(v) Syndial SpA — The Phosphate deposit at Porto Torres site (1). In 2015, the Judge for the Preliminary Hearing of the Court of Sassari, accepting a request of the Public Prosecutor of Sassari, seized — as a preventive measure — the area of “Palte Fosfatiche” (phosphates deposit) located on the territory of Porto Torres site, in relation to alleged crimes of environmental disaster, carrying out of unauthorized disposal of hazardous wastes and other environmental crimes. Subsequent to a specific request, both the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari authorized to implement better delimitations of the landfill area, to provide the area with devices for monitoring the level of environmental pollutants and meteoric waters. The investigations are underway.

(vi) Syndial SpA — Phosphate deposit at Porto Torres site (2). In 2015, the Public Prosecutor at the Court of Sassari seized — as a probative measure — the containment systems for the meteoric waters in the area “Palte Fosfatiche” (phosphates deposit). These waters are being collected by Syndial following authorizations of the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari. The indicted have also been served a notice of investigation for alleged crimes of omitted clean-up and management of radioactive waste. The Public Prosecutor decided to suspend the activities of collection, containment and preservation of the area, in spite that those activities have already been authorized. Syndial filed a request to continue conducting clean-up operations to the Court of Sassari. The investigations are underway.

(vii) Syndial SpA — Public Prosecutor of Gela. The proceeding, involving 17 former managers of the Eni Group, regards alleged crimes of culpable manslaughter and grievous bodily harm related to the death of 12 former employees and alleged work-related diseases that those persons may have contracted at the plant of Clorosoda. Alleged crimes relate to the period from 1969, when the Clorosoda plant commenced the operations until 1998 when the plant was shut down and clean-up activities were performed. The Public Prosecutor requested a medical appraisal on over 100 people that were employed at the above-mentioned plant. This appraisal was performed by independent consultants designated by the Judge for preliminary investigation and did not find any evidence that the various diseases identified from the medical appraisal

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could be directly linked to the exposure to emissions related to the production of chlorine and caustic soda. The consultants also found that production activities were in compliance with applicable laws and regulations on health and safety. Following the outcome of the assessment, the Public Prosecutor of Gela issued a notice of conclusion of preliminary investigations in relation to 4 cases, contesting personal injuries and claimed the indictment only in one case concerning a worker who died in the meantime. Therefore, compared to the initial claim that concerned several (more than one hundred) cases of personal injury and manslaughter, the proceeding was downsized. Following the preliminary hearing dated June 2017, the Judge accepted the defensive arguments and issued a ruling of nonsuit because the case was judged groundless. The Public Prosecutor appealed the first-degree sentence. Also for the proceeding concerning the four cases that are part of a dedicated proceeding, the Judge issued a ruling of nonsuit.

(viii) Syndial SpA — Proceeding on the asbestos at the Ravenna site. A criminal proceeding is pending before the Tribunal of Ravenna about the crimes of culpable manslaughter, injuries and environmental disaster, which would have been allegedly committed by former Syndial employees at the site of Ravenna. The site was taken over by Syndial following a number of corporate mergers and acquisitions. The alleged crimes date back to 1991. In the proceeding there are 75 alleged victims. The plaintiffs include relatives of the alleged victims, various local administrations, and other institutional bodies, including local trade unions. The advocacy of Syndial claimed the statute of limitation about the instance of environmental disaster for certain instances of diseases and deaths. The Judge for the Preliminary Hearing at Ravenna decided that all defendants would stand trial and ascertained the statute of limitation only with reference to certain instances of crime of culpable injury. Syndial signed some settlements. In November 2016, the Judge acquitted the defendants for all the contested cases except for one case for which sentenced 6 of 15 defendants. The defendants, the Prosecutor and the plaintiffs appealed the decision.

(ix) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA — Alleged environmental disaster. A criminal proceeding is pending in relation to crimes allegedly committed by the managers of the Raffineria di Gela SpA and EniMed SpA relating environmental disaster, unauthorized waste disposal and unauthorized spill of industrial wastewater. The Gela Refinery has been sued for administrative offence in accordance with the Law Decree No. 231 of 2001. This criminal proceeding initially regarded soil pollution allegedly caused by spills from 14 tanks of the refinery storage, which had not been provided with double bottoms, and pollution of the sea water near the coastal area adjacent to the site due to the failure of the barrier system implemented as part of the clean-up activities conducted at the site. At the closing of the preliminary investigation, the Public Prosecutor of Gela merged into this proceeding the other investigations related to the pollution occurred at the other sites of the Gela refinery as well as hydrocarbon spills of EniMed. The proceeding is pending at the first hearing.

(x) Proceeding Val d’Agri. On March 2016, the Italian Public Prosecutor’s Office of Potenza started a criminal investigation in order to ascertain the existence of an illegal handling of waste material produced at the Viggiano oil center (COVA), part of the Eni-operated Val d’Agri oil complex. After a two-year investigation, the Prosecutors decided for the domiciliary detention of 5 Eni employees and to put under seizure certain plants functional to the production activity of the Val d’Agri complex which, consequently, was shut down (60 KBOE/d net to Eni). From the commencement of the investigation, Eni has carried out several technical and environmental surveys, with support of independent experts of international reach, who recognized a full compliance of the plant and the industrial process with requirements of the applicable laws, as well as with best available technologies and international best practices. The Company studied certain corrective measures to upgrade plants which, although being not a structural solution, were intended to address the claims made by the public prosecutor about an alleged operation of blending which would have occurred during normal plant functioning. Those measures comprised building a gathering system of inherent liquid associated with the extraction of hydrocarbons at the gas lines. Those corrective measures were favourably reviewed by the public prosecutor, who granted Eni a temporary repeal of the seizure in order to allow the Company perform the works and subsequently, after an inspection, the Prosecutor issued the decision for a definitive release from seizure of the plant while the Region took note of the measure for legal competence. The Company restarted the plant through re-injections into the Costa Molina 2 well on August 2016. Simultaneously, the Company began the review procedure at AIA. In May 2016, the Public Prosecutor’s Office completed the investigations with a request for indictment for all the defendants and the Company. The preliminary hearing ended in April 2017 with confirmation of the indictment for all the defendants and the Company. The trial started in November 2017. The proceeding is at the preliminary hearings.

(xi) Eni SpA — Health investigation related to the COVA center. Beside the criminal proceeding for illegal trafficking of waste, the Public Prosecutor started another investigation in relation to alleged health

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violations. The Public Prosecutor requested the formal opening of an investigation with respect to nine people in relation to alleged violations of the rules providing for the preparation of a Risk Assessment Document of the working conditions at the Val d’Agri Oil Center (COVA). In March 2017, following the request of the Consultant of the Prosecutor, the Labor Inspectorate of Potenza issued a fine against the employers of the COVA for omitted and incomplete assessment of the chemical risks for the COVA center. In October 2017, following the request of the Consultant of the Prosecutor, the National Mining Office for Hydrocarbons and Geo-resources (UNMIG) requested the transfer to a different task of 25 employees of the COVA center for improper assessment of their suitability to the current tasks expressed by the Eni personnel in charge of assessing the health risk profile of employees. Against this decision, the Company filed a formal objection and the UNMIG repealed the resolution issued. Furthermore, in October 2017, the Prosecutor’s Office changed the crime allegations to disaster, murder and negligent personal injury, also alleging breaches of health and safety regulations. Given the level of risk, in December 2017, Eni filed a request for pre-trial hearing for gathering evidence on the matter that was rejected by the Judge.

(xii) Proceeding Val d’Agri — Tank spill. On February 2017, the Carabinieri of NOE department of Potenza ascertained a stream of water contaminated by unknown hydrocarbon traces flowing inside a little shaft located outside the Val d’Agri Oil Center (COVA). The activities carried out by Eni at the COVA aimed at reconstructing the origin of the contamination and have identified the cause in a failure of a tank, while outside of the COVA, following the environmental monitoring implemented, emerged a risk — currently averted — of extension of the contamination in the downstream area of the plant. In executing these activities, Eni performed all the communications provided for by the Legislative Decree 152/06 and started certain emergency safe-keeping operations at the areas subject to contamination outside the COVA. In addition, it is in progress the arrangement plan approved by the relevant Entities is in progress at the internal and external areas of the COVA. Following this event, a criminal investigation was initiated in order to ascertain the existence of illicit environmental pollution against the former and the current COVA officer, the HSE Manager and the Operations Manager in office at the time of the fact. Investigations are ongoing. On April 18, 2017, Eni, on its own initiative, suspended the industrial activity at the COVA, anticipating the provisions of the Regional Council Resolution issued on April 19. On July 2017, Eni restarted the plant’s operational activities. The resumption follows the approval from the Basilicata Region confirming the functionality of the plant and the presence of all necessary safety conditions. During the temporary closure, Eni performed all the requirements provided for by the relevant authorities, including the provision of a double bottom to the tank from which the spillage arose. Negotiations are undergoing for the determination of the compensation of damages suffered by the owners of the areas bordering the COVA and impacted by the event. In February 2018, the Company presented an Extraordinary Appeal to the President of the Republic against the reports of the Italian Department of Firemen dated 30 October 2017 and 15 December 2017 in which Eni is requested to integrate the Safety Report 2016 with the evaluation of possible, highest-risk event, that is an oil spill coming from the bottom of the crude oil storage tanks. With the appeal, Eni stated that it does not consider itself obliged to carry out the integration required, considering that the data acquired in the area affected by the event show that the loss was promptly and efficiently controlled and there were no situations of serious danger to human health and environment.

1.2 Civil and administrative proceedings in the matters of environment, health and safety

(i) Syndial SpA — Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore — Prosecuting body: Ministry for the Environment. In May 2003, the Ministry for the Environment summoned Syndial requesting the compensation of an alleged environmental damage caused by the activity at the Pieve Vergonte plant in the years 1990 through 1996. With a temporarily executive sentence dated July 2008, the District Court of Turin sentenced the subsidiary Syndial SpA to compensate environmental damages amounting to €1,833.5 million, plus legal interests accrued from the filing of the decision. Eni and its subsidiary deemed the amount of the environmental damage to be absolutely groundless as the sentence lacked sufficient elements to support such a material amount of the liability charged with respect to the volume of pollutants ascertained by the Italian Environmental Minister. In July 2009, Syndial filed an appeal against the above-mentioned sentence, and consequently the proceeding continued before a Second Degree Court of Turin that requested a technical appraisal on the matter. The consultants validated the technical appraisal and the other technical assessments that were carried out by the Company together with local and national technical entities. The consultants concluded that: (i) no further measure for environmental restoration is required; (ii) there was no significant and measurable impact on the environment of the ecosystem, therefore no restoration or damage compensation should be

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claimed. The only impact which could be recorded concerned the fishing activity, with an estimated damage of €7 million which could be already restored through the measures proposed by Syndial; (iii) the necessity and convenience of dredging should be definitely excluded, both from the legal and scientific point of view, while confirming technical and scientific correctness of the Syndial’s approach based on the monitoring of the process of natural recovery, which is estimated to require 20 years. In March 2017, the Second Degree Court: (i) excluded the application of compensation for monetary equivalent (Article 18 of Law 349/1986); (ii) annulled the monetary compensation of €1.8 billion requesting Syndial to perform the already approved cleanup project of the polluted areas, which comprise groundwater, as well as compensatory remediation works. The value of these compensatory works required by the Court, in case of Syndial failure or misperformance, is estimated at €9.5 million. The cleanup project filed by Syndial was ratified by local and governmental authorities and is currently being executed. Expenditures expected to be incurred have been provisioned in the environmental provision. Any other claims filed by the Italian Minister for the Environment were rejected (including compensation for non-material damage). On April 4, 2018, the Ministry for the Environment filed an appeal to the Third Instance Court.

(ii) Ministry for the Environment — Augusta harbor. The Italian Ministry for the Environment with various administrative acts required companies that were running plants in the petrochemical site of Priolo to perform safety and environmental remediation works in the Augusta harbor. Companies involved include Eni subsidiaries Versalis, Syndial and Eni Refining & Marketing Division. Pollution has been detected in this area primarily due to a high mercury concentration that is allegedly attributed to the industrial activity of the Priolo petrochemical site. The above-mentioned companies contested these administrative actions, objecting in particular the nature of the remediation works decided and the methods whereby information on the pollutants concentration has been gathered. A number of administrative proceedings started on this matter were subsequently merged before the Regional Administrative Court of Catania. In October 2012, the Court ruled in favor of Eni’s subsidiaries against the Ministry prescriptions about the removal of the pollutants and the construction of a physical barrier. In September 2017, the Ministry notified all the companies involved of a formal notice for the start of remediation and environmental restoration of the Augusta harbor within 90 days. The act, contested by the co-owner companies in December 2017, constitutes a formal notice for environmental damage.

(iii) Claim for preventive technical inquiry — Court of Gela. In February 2012, Eni’s subsidiaries Raffineria di Gela SpA and Syndial SpA and the parent company Eni SpA (involved in this matter through the operations of the Refining & Marketing Division) were notified of a claim issued by 33 parents of children born malformed in the Municipality of Gela between 1992 and 2007. The claim for preventive technical inquiry aimed at verifying the relation of causality between the malformation pathologies suffered by the children of the plaintiffs and the environmental pollution caused by the Gela site (pollution deriving from activities conducted at the industrial plant by Raffineria di Gela SpA and Syndial SpA), quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. In any case, the same issue was the subject of previous criminal proceedings, of which one closed without ascertainment of any illicit behavior on the part of Eni or its subsidiaries, while a further criminal proceeding is still pending. The consultants appointed by the Court and those designated by the plaintiffs performed a technical appraisal on the matter, reaching very different outcomes. Thus, parties failed to reach a settlement of the matter. On December 2015, the three companies involved were sued in relation to a total of 30 cases of compensation for damages in civil proceedings. The proceedings are still pending.

(iv) Environmental claim relating to the Municipality of Cengio. The Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio summoned Syndial before a Civil Court and sentenced Eni’s subsidiary to compensate the environmental damage relating to the site of Cengio. The request for environmental damage amounted to €250 million to which add health damage to be quantified during the proceeding. The plaintiffs accused Syndial of negligence in performing the clean-up and remediation of the site. In February 2014, the Court ruled a technical appraisal to verify the existence of the environmental damage. Following failed attempts to define a settlement agreement on the matter among the parties involved, the Judge resumed the trial and requested an independent appraisal on the matter.

(v) Syndial SpA and Versalis SpA — Summon for alleged environmental damage caused by illegal waste disposal in the municipality of Melilli (Sicily). In May 2014, the Municipality of Melilli summoned Eni’s subsidiaries Syndial and Versalis for the environmental damage allegedly caused by carrying out illegal waste disposal activities and unauthorized landfill. In particular, the plaintiff claimed the responsibilities of

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Syndial and Versalis for the production of waste and because they commissioned the waste disposal. The plaintiff stated that this illegal handling of waste was part of certain criminal proceedings dating back to 2001 – 2003 which would have allegedly traced the hazardous waste materials back to the Priolo and Gela industrial sites that are managed by the above-mentioned Eni’s subsidiaries (in particular, the waste with high mercury concentration and railway sleepers no longer in use). Such waste was allegedly handled and disposed illegally at an unauthorized landfill owned by a third party (located about 2 kilometers from the town of Melilli). The claim amounted to €500 million and referred to two Group’s subsidiaries and SMA.RI, the company that carries out activities of waste disposal, being jointly and severally liable. In June 2017, the Judge accepted all the defensive instances of Syndial and Versalis stating the requests of the Municipality inadmissible for lack of locus standi and considering the requests as unfounded or unproved, and sentenced the Municipality to the reimbursement of the costs of the proceeding. In September 2017, the Municipality appealed the ruling requesting a new investigation and the admission of a technical appraisal, as well as the suspension of the enforcement of the sentence of first instance.

(vi) Summon for Eni, Raffineria di Gela SpA, EniMed SpA, and Syndial SpA. In December 2015, 273 Gela residents filed an appeal to the Court of Gela requesting to halt all the production activities conducted by Eni’s subsidiaries at Gela site in order to put an end to environmental pollution affecting the health of the local population. The claimants also requested the appointment of commissioners in charge of carrying out the plants shutdown and of continuing implementing of clean-up activities in the area. Besides that, they requested the Court to order the Municipality of Gela — as a competent body in the field of health protection — to adopt certain provisions aimed to preserve the health of the local population. This proceeding arose in connection with an alleged environmental damage caused by the industrial activities of the site and consequent necessity to protect the population from serious harm to the health. The initiative was enforced by certain technical assessments performed by consultants appointed by the Court on the preliminary stage. The aim of these assessments was to establish cause-and-effect relationships between the industrial contamination and congenital anomalies reported in the town of Gela. Following the outcome of the investigation, in December 2017 the Court of Gela rejected all the claims of the plaintiffs and condemned them to pay the expenses of the proceeding. The plaintiffs appealed the decision.

2. Court inquiries

(i) Reorganization procedure of Alitalia Linee Aeree Italiane SpA under extraordinary administration. On January 2013, the Italian airline company Alitalia, which was undergoing a reorganization procedure, summoned Eni, Exxon Italia and Kuwait Petroleum Italia SpA before the Court of Rome, to obtain a compensation for alleged damages caused by a presumed anti-competitive behavior on part of the three petroleum companies in the supply of jet fuel in the years 1998 through 2009. The claim was based on a deliberation filed by the Italian Antitrust Authority in June 2006. The antitrust deliberation accused Eni and other five petroleum companies of anti-competitive agreements designed to split the market for jet fuel supplies and blocking the entrance of new players in the years 1998 through 2006. The antitrust findings were substantially endorsed by an administrative court. Alitalia has made a claim against the three petroleum companies jointly and severally presenting two alternative ways to assess the alleged damages. A first assessment of the overall damages amounted to €908 million. This was based on the presumption that the anti-competitive agreements among the defendants would have prevented Alitalia from autonomously purchasing supplies of jet fuel in the years when the existence of the anti-competitive agreements were ascertained by the Italian Antitrust Authority and in subsequent years until Alitalia ceased to operate airline activity. Alitalia asserted the incurrence of higher supply costs of jet fuel of €777 million excluding interest accrued and other items that add to lower profitability caused by a reduced competitive position in the marketplace estimated at €131 million. Another assessment of the overall damage made by Alitalia stand at €395 million of which €334 million of higher purchase costs for jet fuel and €61 million of lower profitability due to the reduced competitive position on the marketplace. With a decision dated May 2014, the Court of Rome declared the connection with a judgment previously proposed by Alitalia itself before the Court of Milan against other oil companies participating to an alleged cartel agreement. The case was thus summed up by Alitalia before the Court of Milan. In September 2017, the Court of Milan ruled that: (i) the requests of Alitalia for the period 1998 – 2004 were prescribed; (ii) for the period subsequent to June 2006, no further assessment should be carried out, since Alitalia has failed to meet its burden of allegation; (iii) for the period between December 2004 and June 2006, a specific technical appraisal will be carried out. Eni accrued a provision with respect to this proceeding.

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(ii) Eni’s arbitration with GasTerra. In 2013, Eni initiated an arbitration against GasTerra, as part of a long-term supply contract signed in 1986, to obtain a revision of the price charged by GasTerra to Eni for the gas supplied in the 2012 – 2015 period. On that occasion, Eni and GasTerra agreed to apply a provisional price, which was lower than the previous price, until the definition of a new contractual price based on an arrangement between parties or an arbitration award. The arbitration award dismissed Eni’s claim for price revision, without however determining a new price applicable in the relevant period. GasTerra considered that, by dismissing Eni’s claim, the award restored the original contract price, based on which GasTerra now claims an additional amount to be paid by Eni which corresponds to the difference between the provisional price and the contractual price. Eni, relying also on the opinion of its external consultants, does not agree with GasTerra’s interpretation and considers GasTerra’s claim groundless. However, GasTerra, based on its own interpretation, commenced an arbitration and obtained from a Dutch court the provisional seizure of Eni’s investment in its subsidiary Eni International BV (which at the time of the seizure i.e. at the reporting date June 30, 2016, stated consolidated net assets of €34.7 billion) for the alleged receivable due by Eni (equal to €1.01 billion). With respect to the interim seizure measure obtained by GasTerra, Eni offered to GasTerra, who in turn accepted, a bank guarantee of the same amount of the GasTerra claim. This guarantee is expected to remain effective until a final award by the arbitration procedure. The measure, which was granted after a summary review only and without Eni being heard, does not prejudice the outcome on the merits of the claims. The merits of the dispute will be ruled by a new arbitration proceeding.

3. Proceedings concerning criminal/administrative corporate responsibility

(i) EniPower SpA. In June 2004, the Public Prosecutor of Milan commenced inquiries into contracts awarded by Eni’s subsidiary EniPower and on supplies from other companies to EniPower. It emerged that illicit payments were made by EniPower suppliers to a manager of EniPower who was immediately fired. The Court served EniPower (the commissioning entity) and Snamprogetti (now Saipem SpA) (contractor of engineering and procurement services) with notices of investigation in accordance with Legislative Decree No. 231/2001 that establishes that the companies are liable for the crimes committed by their employees who acted on behalf of the employer. In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers under the provisions of Legislative Decree No. 231/2001. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs. In September 2011, the Court of Milan found that nine persons were guilty for the above-mentioned crimes. In addition, they were sentenced jointly and severally to the payment of all damages to be assessed through a specific proceeding and to the reimbursement of the proceeding expenses incurred by the plaintiffs. The Court also resolved to dismiss all the criminal indictments for 7 employees, representing some companies involved as a result of the statute of limitations, while the trial ended with an acquittal of 15 individuals. In relation to the companies involved in the proceeding, the Court found that 7 companies are liable based on the provisions of Legislative Decree No. 231/2001, imposing a fine and the disgorgement of profit. Eni SpA and its subsidiaries, EniPower and Saipem, which took over Snamprogetti, acted as plaintiffs in the proceeding also against the mentioned companies. The Court rejected the position as plaintiffs of the Eni Group companies, reversing the prior decision made by the Court. This decision may have been made based on a pronouncement made by a Supreme Court that stated the illegitimacy of the constitution as plaintiffs against any legal entity, as indicted under the provisions of Legislative Decree No. 231/2001. The condemned parties filed appeal against the above-mentioned decision. The Appeal Court issued a ruling that substantially confirmed the first-degree judgment except for the fact that it ascertained the statute of limitation with regard to certain defendants. In 2015, the Supreme Court annulled the judgment of the Second Degree Court ascribing the judgment to another section that, once more, confirmed the sentence of first instance, excepting the rulings of the previous appeal sentence not subject to annulment, including the statute of limitation. The filing of the statement of grounds is still pending.

(ii) Algeria. Legal proceedings are pending in Italy and outside Italy in connection with an allegation of corruption relating to the award of certain contracts to Eni’s former subsidiary Saipem in Algeria. In February 2011, Eni received from the Public Prosecutor of Milan an information request pursuant to the Italian Code of Criminal Procedure. The request related to allegations of international corruption and pertained to certain activities performed by Saipem Group companies in Algeria (in particular the contract between Saipem and Sonatrach relating to the construction of the GK3 gas pipeline and the contract between Galsi, Saipem and Technip relating to the engineering of the ground section of a gas pipeline). The

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crime of international corruption is among the offenses contemplated by the Italian Legislative Decree No. 231/2001 which provides for corporate liability for crimes committed by employees and prescribes punishments including fines and the disgorgement of profit. Eni also voluntarily provided to the Public Prosecutor documentation relating to the MLE project (in which Eni’s Exploration & Production Division participates), with respect to which investigations in Algeria are ongoing. In November 2012, the Public Prosecutor served Saipem a notice stating that it had commenced an investigation for alleged liability of the company for international corruption in accordance with Legislative Decree No. 231/2001. Furthermore, the Public Prosecutor requested the production of certain documents relating to certain activities in Algeria. Subsequently Saipem was served a notice of seizure, then a request for documentation and finally a search warrant was issued, in order to obtain further documentation, in particular relating to certain intermediary contracts and sub-contracts entered into by Saipem in connection with its Algerian business. Several former Saipem employees were also involved in the proceeding, including the former CEO of Saipem, who resigned from the office in December of 2012, and the former Chief Operating Officer of the Business Unit Engineering & Construction of Saipem, the employment of whom was terminated at the beginning of 2013. In February 2013, on mandate from the Public Prosecutor of Milan, the Italian Finance Police visited Eni’s headquarters in Rome and San Donato Milanese and executed searches and seized documents relating to Saipem’s activity in Algeria. On the same occasion, Eni was served a notice that an investigation had commenced in accordance with Legislative Decree No. 231/2001 with respect to Eni, Eni’s former CEO, Eni’s former CFO and another senior manager. Eni’s former CFO had previously served as Saipem’s CFO, including during the period in which alleged corruption took place and before being appointed as CFO of Eni on August 1, 2008. Following receipt of this notice, Eni conducted an internal investigation with the assistance of external consultants, in addition to the review activities performed by its audit and internal control departments and a team dedicated to the Algerian matters. During 2013, the external consultants reached the following results: (i) the review of the documents seized by the Milan prosecutors and the examination of internal records held by Eni’s global procurement department have not found any evidence that Eni entered into intermediary or any other contractual arrangements with the third parties involved in the prosecutors’ investigation; the brokerage contracts that were identified, were signed by Saipem or its subsidiaries or predecessor companies; and (ii) the internal review made on the MLE project, the only project that Eni understands to be under the prosecutors’ investigation where the client is a Eni Group company has not found evidence that any Eni employee engaged in wrongdoing in connection with the award to Saipem of two main contracts to execute the project (EPC and Drilling). Furthermore, in 2014, with the assistance of external consultants, Eni completed a review of the extent of its operating control over Saipem with regard to both legal, accounting and administrative issues. The findings of that review confirmed the autonomy of Saipem from the parent company during the relevant periods. The findings of Eni’s internal review have been provided to the Judicial Authority in order to reaffirm Eni’s willingness to fully cooperate. In January 2015, the Public Prosecutor notified the conclusion of preliminary investigations relating to Eni, Saipem and eight persons (including, the former CEO and CFO of Eni and the Chief Upstream Officer of Eni who was responsible for Eni Exploration & Production activities in North Africa at the time of the events under investigation). The Public Prosecutor issued a notice of alleged international corruption against all such persons (including Eni and Saipem on the basis of the provisions of Legislative Decree No. 231/2001) in connection with the entry into intermediary contracts by Saipem in Algeria. Furthermore, some of the defendants (including the former CEO and CFO of Eni and the Chief Upstream Officer of Eni) were accused of tax offenses for alleged fraudulent misrepresentation in relation to the accounting treatment of these contracts for the fiscal years 2009 and 2010. After receiving (i) the evidence collected in connection with the Public Prosecutor’s request to take testimony of two individuals under investigation in late 2014, and (ii) the minutes of the preliminary hearing and the documents filed in connection with the conclusion of the preliminary investigation, Eni requested that its consultants perform additional analysis and investigation. As a result, Eni’s consultants reaffirmed their conclusions previously reported to the Company. In February 2015, the Public Prosecutor requested the indictment of all the investigated persons for international corruption as well as the tax offenses mentioned above. In 2015, the Judge for the Preliminary Hearing of the Court of Milan dismissed the case and granted an acquittal in favor of Eni, former Chief Executive Officer and Chief Upstream Officer for all the alleged offenses. In February 2016, the Court of Third Instance, upholding an appeal presented by the Public Prosecutor, reversed the dismissal, annulled the verdict, and remanded the proceedings to another Judge for the Preliminary Hearing in the Court of Milan. As a result of the new preliminary hearing in July 2016, the Judge ordered the trial for all defendants, including Eni. At the hearing on February 26, 2018, the Public Prosecutor, concluding his indictment, requested — among other things — the conviction of Eni for the payment of a pecuniary sanction. The discussion of the defensive arguments of the persons and the legal entities involved will follow. The first instance trial is pending.

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At the end of 2012, Eni contacted the U.S. Department of Justice and the U.S. SEC in order to voluntarily inform them about this matter, and has kept them informed about the developments in the Italian prosecutors’ investigations. Following Eni’s notification in 2012, both the U.S. SEC and the DoJ started their own investigations regarding this matter. Eni has furnished various information and documents, including the findings of its internal reviews, in response to formal and informal requests.

(iii) Block OPL 245 — Nigeria. In July 2014, the Public Prosecutor of Milan served Eni with a notice of investigation relating to potential liability on the part of Eni arising from alleged international corruption, pursuant to Italian Legislative Decree No. 231/2001 whereby companies are liable for the crimes committed by their employees when performing their tasks. As part of the investigation, Eni was also subpoenaed for documents and other evidence. According to the subpoena, the proceeding was commenced following a claim filed by NGO ReCommon relating to alleged corruptive practices that according to the Public Prosecutor allegedly involved the Resolution Agreement made on April 29, 2011 relating to the Oil Prospecting License of the offshore oilfield that was discovered in Block 245 in Nigeria. Eni is fully cooperating with the Public Prosecutor and promptly filed the requested documentation. Furthermore, Eni voluntarily reported the matter to the U.S. Department of Justice and the U.S. SEC. In July 2014, Eni’s Board of Statutory Auditors jointly with the Eni Watch Structure resolved to engage an independent, US-based law firm, expert in anticorruption, to conduct a forensic, independent review of the matter, upon informing the Judicial Authorities. After reviewing the matter, the US lawyers concluded in summary that they detected no evidence of wrongdoing by Eni side in relation to the 2011 transaction with the Nigerian government for the acquisition of the OPL 245 license. The outcome of this review was transmitted to the Judicial Authorities. In September 2014, the Public Prosecutor notified Eni of a restraining order issued by a British judge who ordered the seizure of a bank account not pertaining to Eni domiciled at a British bank following a request from the Public Prosecutor. The order was also notified to certain individuals, including Eni’s CEO and the Chief Development, Operations and Technological Officer, as well as Eni’s former CEO. From the available documents, it was inferred that such Eni officers and former officers were under investigation by the Public Prosecutor of Milan. During a hearing before a court in London in September 2014, Eni and its current executive officers stated their non-involvement in the matter regarding the seized bank account. Following the hearing, the Court reaffirmed the seizure. In December 2016, the Public Prosecutor of Milan notified Eni of the conclusion of the preliminary investigation and requested the indictment of Eni’s CEO, the Chief Development, Operations and Technological Officer and the Executive Vice President for international negotiations, as well as Eni’s former CEO and Eni based on Italian law 231/2001 on corporate entity responsibility. Upon the notification to Eni of the conclusion of the preliminary investigation by the Public Prosecutor, the independent US-based law firm was requested to assess whether the new documentation made available from Italian prosecutors could modify the conclusions of the prior review. The US law firm was also provided with the documentation filed in the Nigerian proceeding mentioned below. The independent U.S. law firm concluded that the reappraisal of the matter in light of the new documentations available did not alter the outcome of the prior review. In December 2017, the Judge ordered the indictment of all the parties mentioned above, and other parties under investigation by the Public Prosecutor, before the Court of Milan. During the first trial hearing in March 2018, the Federal Republic of Nigeria requested permission to join the case as a civil party. Several NGOs, which had made the same request before the Judge of the Preliminary Hearing and been denied, also asked to join as civil parties. At the initial hearing, the court postponed of the trial until May 14, 2018 and transferred the trial to another Section of the Court of Milan that has been designated to preside over the proceeding. The requests by the Federal Republic of Nigeria and NGOs to join as civil parties will be decided at this hearing. In January 2017, Eni’s subsidiary Nigerian Agip Exploration Ltd became aware of an Interim Order of Attachment (“Order”) issued by the Nigerian Federal High Court upon request from the Nigerian Economic and Financial Crimes Commission (EFCC), attaching temporarily the property known as Oil Prospecting License 245 (“OPL 245”) pending a proceeding in Nigeria relating to alleged corruption and money laundering. The Order did not revoke the license but restricted Eni’s ability to dispose of and manage the property. The Order also established that the license would be managed by the Nigerian Department for Petroleum Resources, pending the proceeding ongoing in Nigeria. NAE made an application to discharge the Order (along with the Shell affiliate that holds of the license jointly with NAE). After making this application, Eni became aware of a formal filing of charges by the EFCC against NAE and other parties. Copies of those charges were also filed by the EFCC in the proceeding initiated by NAE and its partner for the discharge of the Order. In March 2017, the Nigerian Court revoked the Order. Eni has provided a copy of the Order and the

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attached documents, including the charges filed by the EFCC, to the US-based law firm engaged to review the OPL 245 transaction, who upon review of such documents, did not modify their conclusion that they did not detect evidence of wrongdoing by Eni side in relation to the acquisition of the OPL 245 from the Nigerian government.

(iv) Congo. In March 2017, the Italian Finance Police served on Eni an information request pursuant to the Italian Code of Criminal Procedure connection with an investigative file opened by the Public Prosecutor of Milan against unknown persons. The request related in particular to the agreements signed by Eni Congo SA with the Ministry of Hydrocarbons of the Republic of Congo in 2013, 2014 and 2015 in relation to exploration, development and production activities concerning certain permits held by Eni Congo SA for Congolese projects and Eni’s relationships with Congolese companies that hold stakes in. In July 2017, the Italian Financial Police served on Eni with another information request and a notice of investigation pursuant to Italian Legislative Decree No. 231/2001 for alleged international corruption. The request expressly stated that it was based in part on the March 2017 information request and concerned the relationship of Eni and its subsidiaries with certain third-party companies from 2012 to the present. Eni has produced all of the documentation requested in the March and July 2017 information requests and has voluntarily disclosed this matter to the relevant US authorities (SEC and DoJ). On January 26, 2018, the Public Prosecutor’s Office requested a six-months extension of the deadline for conducting its preliminary investigation into this matter, from January 31, 2018 until July 30, 2018. In April 2018, the Public Prosecutor of Milan served on Eni SpA a further request for documentation and notified the Chief Development, Operation & Technology Officer of a search order in which he results among the suspects together with another Eni employee.

4. Other proceedings concerning criminal matters

(i) Eni SpA — Refining & Marketing Division — Criminal proceedings on fuel excise tax. A criminal proceeding is currently pending, relating to alleged evasion of excise taxes in the context of the retail sales at the fuel market. In particular, the claim states that the quantity of oil products marketed by Eni was larger than the quantity subjected to the excise tax. This proceeding (no. 7320/2014 RGNR) concerns the reunification of three distinct investigations:

(i)

a first proceeding, opened by the Public Prosecutor’s Office of Frosinone involved a company (Turrizziani Petroli) purchaser of Eni’s fuel. This investigation was subsequently extended to Eni. The Company fully cooperated and provided all data and information concerning the excise tax obligations for the quantities of fuel coming from the storage sites of Gaeta, Naples and Livorno. Eni ensured the best possible collaboration, handing in all the required documentation. Such proceeding referred to quantities of oil products sold by Eni, allegedly larger than the quantity subjected to the excise tax. After the ending of the investigation, the financial police of Frosinone, along with the local Customs Agency, in November 2013 issued a claim related to the missing payment of excise taxes in the 2007 – 2012 period for €1.55 million. In May 2014, the Customs Agency of Rome issued a payment notice relating to the abovementioned claim that was filed by the financial police and Customs Agency of Frosinone. The Company immediately appealed to the Tributary Commission. On March 22, 2018, the Commission filed the ruling of the sentence which accepted Eni’s recourse against the claim of the Custom Agency also condemning the latter to refund the proceeding expenses;

(ii)

a second proceeding concerning a line of investigation of the Public Prosecutor’s Office of Prato, regards the deposit of Calenzano and relates to subtraction of fuel through manipulation of the fuel dispensers, subsequently extended also to the Refinery of Stagno (Livorno);

(iii)

a third proceeding, opened by the Public Prosecutor’s Office of Rome, regarded alleged missing payment of excise tax on the surplus of the unloading products, as the quantity of such products was larger than the quantity reported in the supporting fiscal documents. This proceeding represents a development of the first proceeding mentioned above, and substantially concerns similar facts presenting, however, some differences with regard to the nature of the alleged crimes and the responsibility subjected to verification.

The second and the third proceeding were merged in the proceeding commenced by Public Prosecutor’s Office of Rome. In fact, the Public Prosecutor’s Office of Rome has alleged the existence of a criminal conspiracy aimed at habitual subtraction of oil products at all of the 22 storage sites which are operated by Eni over the national territory. Eni is cooperating with the Prosecutor in order to defend the correctness of its operation. On September 2014, a search was conducted at the office of the former chief

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operating officer of Eni’s Refining & Marketing Division following an order of the Public Prosecutor of Rome. The motivations of the search are the same as the above-mentioned proceeding as the ongoing investigations also relates to a period of time when the officer was in charge at Eni’s Division. On March 2015, the Prosecutor of Rome ordered a search at all the storage sites of Eni’s network in Italy as part of the same proceeding. The search was intended to verify the existence of fraudulent practices aimed at tampering with measuring systems functional to the tax compliance of excise duties in relation to fuel handling at the storage sites. In September 2015, the Public Prosecutor of Rome requested a one-off technical appraisal aimed to verify the compliance of the software installed at certain metric heads previously seized with those lodged by the manufacturer at the Ministry of Economic Development. The technical appraisal verified the compliance of the software tested. On this occasion, the proceeding has been extended to a large number of employees and former employees of the company. In November 2017, the Court of Rome, following the request of the Public Prosecutor, carried out a preventive seizure of the oil products meters at Eni’s refineries and depots in Italy. The Company, considering the consequences connected to a complete shutdown of the refining and fueling activities, has requested the Public Prosecutor to minimize, as much as possible, the impact on customers, companies and service stations. After a few days, the preventive seizure was revoked, due to the commitments undertaken by the Company that is a third party not subject to investigation. Eni continues to provide full cooperation to the judicial authorities. In December 2017, technical consultants of renowned expertise were nominated as part of the procedure, with the aim of verify the integrity of the sites under seizure. The results will be provided to the judicial authorities. The investigations are underway. On March 26, 2018, the Public Prosecutor of Rome notified the conclusion of the preliminary investigations in relation to the criminal proceeding no. 7320/2014 concerning the Calenzano, Livorno, Sannazzaro, Pomezia, Naples, Gaeta and Ortona sites. Based on the outcome of the investigations, as far as Eni is concerned, the proceeding involves former managers and directors of the refineries indicated above concerning alleged aggravated and continuous non-payment of excise duties, alteration and removal of seals, use and possession of false measures and weights. In addition, some deposit employees and their manager were indicted of alleged procedural fraud.

(ii) Public Prosecutor of Milan — Criminal Procedure no. 12333/2017. On 6 February 2018, the Public Prosecutor of Milan notified to an Eni’s manager a search and seizure decree in relation to allegations of associative crime aimed at slander and at reporting false information to a Public Prosecutor. In the decree, the Prosecutor of Milan included, among the other suspects, the former Chief of the Legal and Regulatory Affairs of Eni, currently the Chief Gas & LNG Marketing and Power Officer of the Company. According to the decree, the association would be aimed at interfering with the judicial activity in certain criminal proceedings that involve, among others, Eni and some of its directors and managers. Furthermore, Eni is not under investigation.

5. Tax Proceedings

Settled Proceedings

In Italy

(i) Eni SpA — municipal tax related to certain oil platforms located in the Italian territorial waters. Several tax proceedings were pending in Italy, as certain municipalities claimed Eni SpA omitted payments of a tax on property relating oil platforms located in the territorial waters under the municipality administration. After completing all degrees of judgment before Italian tax courts, in February 2016, the Third Instance Court sentenced that: i) property taxes on platforms are due by Eni; ii) the taxable basis is to be defined by considering the platforms carrying amounts, instead of the replacement cost; iii) sanctions are not applicable. Based on the outcomes of the resolutions, Eni started an extrajudicial procedure to reach settlements on the matter with the local authorities who submitted claims against the Company based on the taxability of oil platforms. Following the expectation of management to successfully conclude these settlements, Eni accrued a tax provision.

(ii) Eni SpA — Excise taxes. Eni defined a settlement with the Customs Agency that definitively closes a tax dispute for alleged culpable omission to pay of excise taxes (for the period 2003 – 2008) due on 650 million cubic meters of natural gas. The initial request presented by the Custom Agency corresponded to €114 million, plus €20 million of interests and €34 million of fines. The Customs Agency reiterated the claim because — even if the incidence of the calorific value has been acknowledged by a technical and

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scientific point of view — at the same time the matter has not been explicitly regulated by an administrative act. This position was also recently confirmed by the Provincial Tax Commission of Milan to which Eni had presented appeal, confirming that the evidences of Eni were founded. Furthermore, the Tax Commission ruled that the claims for the years 2003 and 2004 are prescribed and annulled all the fines, reducing the claim by €90 million (from €168 million to €78 million). Eni and the Customs Agency agreed for an amount close to the one indicated by the Tax Commission.

Outside Italy

(iii) Eni Angola Production BV. The international oil companies operating in Angola, among which Eni, and the tax Authorities of the Country have defined a global settlement agreement that ends a number of disputes that lasted for about 15 years regarding the deductibility of certain costs relating to PSA oil activities, as well as the timing of the deductibility of the investments in progress. This agreement provides for the recognition to the Angolan Authorities of a part of the taxable amounts contested as petroleum income taxes. With regard to Eni, the amount accrued resulted sufficient to sustain the charges of the aforementioned global settlement.

6. Legal proceedings

Settled proceedings

(i) Eni SpA — Industrial site of Praia a Mare. Based on complaints filed by certain offended persons, the Public Prosecutor of Paola started an enquiry about alleged diseases related to tumors that those persons contracted on the workplace. Those persons were employees at an industrial complex owned by a Group subsidiary many years ago. At the trial, 189 persons stand as plaintiff and 107 persons stand as offended party by the alleged crime. Upon conclusion of the preliminary hearing, the Public Prosecutor resolved that all defendants would stand trial for culpable manslaughter, culpable injuries, environmental disaster and negligent conduct about safety measures on the workplace. Following a settlement agreement with Eni, Marzotto SpA signed settlement agreements with all plaintiffs, except for the local administrations. In December 2014, the Court issued an acquittal sentence for all defendants, as the indictment was found groundless. The Public Prosecutor appealed against the sentence. In September 2017, the Second Degree Court upheld the acquittal sentence of the first degree.

(ii) Seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria — Prosecuting body: Public Prosecutor of Castrovillari. Certain areas owned by Eni in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria have been preventively seized by the Judicial Authority, following an investigation about an alleged improper handling of industrial waste from the processing of zinc ferrites at the industrial site of Pertusola Sud,. The circumstances under investigation were similar to those considered in a criminal action for alleged omitted clean-up that was concluded in 2008 without any negative outcome for Eni’s employees. Eni’s subsidiary Syndial SpA has removed any waste materials from the landfills. Besides that, Syndial defined an agreement with the Municipality of Cerchiara and the Municipality of Cassano to settle all claims relating to alleged damages caused by the unauthorized waste disposal in the landfills on the territory of the two Municipalities. The remediation activities were completed and the proceeding was closed in May 2017.

(iii) Iraq — Kazakhstan. A criminal proceeding was pending before the Public Prosecutor of Milan in relation to alleged crimes of international corruption involving Eni’s activities in Kazakhstan regarding the management of the Karachaganak plant and the Kashagan project, as well as handling of assignment procedures of work contracts by Agip KCO. The Company filed the documents collected and fully cooperated with the Public Prosecutor. A number of managers and a former manager were involved in the investigation. The above-mentioned proceeding were combined with another (the so-called “Iraq proceeding”) regarding a parallel proceeding related to Eni’s activities in Iraq. In June 2011, Eni Zubair SpA and Saipem SpA in Fano (Italy) were searched by the Judicial Authorities. The search involved the offices of certain Group employees and of certain third parties in connection with alleged crimes of conspiracy and corruption as part of the “Jurassic” project in Kuwait. Particularly, the alleged crimes would have been committed in order to illicitly influence the award of a construction contract outside Italy where Eni was the commissioning entity. Considering the claims of the Public Prosecutor, Eni and Saipem believed that they were damaged by the crimes committed by their employees. Eni considered those

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employees to have breached the Company’s Code of Ethics. In spite of this, Eni SpA and Saipem SpA were notified of being under investigation pursuant to the Legislative Decree No. 231/2001, which establishes the liability of entities for the crimes committed by their employees. Eni SpA was notified by the Public Prosecutor of a request of extension of the preliminary investigations that has led up to the involvement of another employee, as well as other suppliers in the proceeding. In April 2012, the Public Prosecutor of Milan requested Eni SpA to be debarred for one year and six months from performing any industrial activities involving the production sharing contract. In July 2013, the Judge for Preliminary Investigation rejected the request for precautionary measures requested by the Public Prosecutor of Milan the Court considered the request groundless due to the lack of serious evidence against Eni and accepted the defense arguments for which Eni suffered severe damages from misperformances of some suppliers involved in the Kashagan project. In addition, the Court declared the lack of precautionary requirements considering the reorganization of the activities in Kazakhstan and taking into account of the initiatives of the internal audit promptly adopted by Eni. Based on this decision, in March 2014, Eni’s legal team requested the dismissing of the proceeding. The Prosecutor’s Office accepted the request for dismissal of all the defendants in January 2017 and, finally, the proceeding was closed in March 2017.

(iv) Block Marine XII — Congo. In July 2015, Eni received from the U.S. Department of Justice an order to produce documents in view of the hearing of an Eni employee, relating to the assets “Marine XII” in Congo and relationships with certain persons and companies. According to preliminary informal contacts between Eni’s U.S. lawyers and the DoJ, this hearing is part of a broader investigation, which is currently being carried out with regard to third parties. Eni has completed the production of documents required by the DoJ.

Assets under concession arrangements

Eni operates under concession arrangements mainly in the Exploration & Production segment and the Refining & Marketing business line. In the Exploration & Production segment, contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and, in some legal contexts, private owners. Pursuant to the assignment of mineral concession, Eni sustains all the operational risks and costs related to the exploration and development activities and it is entitled to the productions realized. As a compensation for mineral concessions, Eni pays royalties and taxes in accordance with local tax legislation. In production sharing agreement and service contracts, realized productions are defined based on contractual agreements with State oil companies, which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (Cost Oil) and give entitlement to the own portion of the realized productions (Profit Oil). In the Refining & Marketing business line, several service stations and other auxiliary assets of the distribution service are located in the motorway areas and they are granted by the motorway concession operators following a public tender for the sub-concession of the supplying of oil products distribution service and other auxiliary services. In exchange of the granting of the services described above, Eni provides to the motorway companies fixed and variable royalties based on quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession for no consideration.

Environmental regulations

Risks associated with the footprint of Eni’s activities on the environment, health and safety are described in the “Financial Review”, paragraph “Risk factors and uncertainties”. In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management does not currently expect any material adverse effect upon Eni’s Consolidated Financial Statements, taking account of ongoing remediation actions, existing insurance policies and the environmental risk provision accrued in the Consolidated Financial Statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of ongoing surveys and other possible effects of statements required by Legislative Decree 152/2006; (iii) new developments in environmental regulation (i.e. Law No. 68/2015 on crimes against the environment and European Directive 2015/2193 on medium combustion plants); (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.

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Emission trading

From 2013, the third phase of the European Union Emissions Trading Scheme (EU-ETS) came in force. The new phase marked a significant change in the method of awarding emission allowance from a no-consideration scheme based on historical emissions to allocation through auctioning. For the period 2013 – 2020, the award of free emission allowances is performed based on European benchmarks specific to each industrial segment, except for the thermoelectric sector that is not eligible for allocations for no consideration. This regulatory scheme implies for Eni’s plants subjected to emission trading a lower assignment of emission permits respect to the emissions recorded in the relevant year and, consequently, the necessity of covering the amounts in excess by purchasing the relevant emission allowances on the open market. In 2017, the emissions of carbon dioxide from Eni’s plants were higher than the free allowances assigned to Eni. Against emissions of carbon dioxide amounting to approximately 19.47 million tonnes, Eni was awarded free emission allowances of 8.53 million tonnes, determining a deficit of 10.94 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market.

39 Revenues

Net sales from operations


(€ million)	2017		2016		2015
Revenues from sales and services		66,920		55,764		72,290
Change in contract work in progress		(1)		(2)		(4)
		66,919		55,762		72,286

Revenues from sales were stated net of the following items:


(€ million)	2017		2016		2015
Excise taxes		11,378		11,913		11,889
Services recharged to joint venture partners		4,702		4,441		5,609
Sales to service station managers for sales billed to holders of credit cards		1,675		1,553		1,643
Exchanges of oil sales (excluding excise taxes)		994		878		1,154
		18,749		18,785		20,295

Net sales from operations by industry segment and geographical area of destination are disclosed in note 46 — Information by industry segment and by geographical area.

Net sales from operations with related parties are disclosed in note 47 — Transactions with related parties.

Other income and revenues


(€ million)	2017		2016		2015
Gains from sale of assets and businesses		3,288		14		459
Gains on price adjustments under overlifting/underlifting transactions		166		238		253
Lease and rental income		84		81		85
Contract penalties and other trade revenues		42		72		36
Compensation for damages		9		122		36
Other proceeds(*)		469		404		383
		4,058		931		1,252

(*)

Each individual amount included herein was lower than €50 million.

Gains from the sale of assets and business of €3,288 million related to the divestment of a 25% stake in natural gas-rich Area 4 offshore Mozambique (€1,985 million) and of a 40% stake in the Zohr project (€1,281 million). Compensations for 2016 of €122 million related to a loss in property value following an accident occurred at the EST conversion plant at the Sannazzaro refinery.

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Other income and revenues with related parties are disclosed in note 47 — Transactions with related parties.

40 Costs

Purchase, services and other


(€ million)	2017		2016		2015
Production costs - raw, ancillary and consumable materials and goods		35,907		27,783		39,812
Production costs - services		12,228		12,727		13,197
Operating leases and other		1,684		1,672		2,205
Net provisions for contingencies		886		505		644
Expenses for price variation on overliftling and underlifting operations		145		240		278
Other expenses		1,844		1,512		1,135
		52,694		44,439		57,271
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(224)		(297)		(323)
- capitalized direct costs associated with self-constructed assets - intangible assets		(9)		(18)		(100)
		52,461		44,124		56,848

Purchase, services and other include geological and geophysical expenses related to the exploration activities of the Exploration & Production segment amounting to €273 million (€204 million and €254 million in 2016 and 2015, respectively) and operating leases for €1,022 million (€566 million and €635 million in 2016 and 2015, respectively).

Costs incurred in connection with research and development activities recognized in profit and loss, as they did not meet the requirements to be recognized as long-lived assets, amounted to €185 million (€161 million and €176 million in 2016 and 2015, respectively).

Royalties on the extraction of hydrocarbons amounted to €674 million (€572 million and €865 million in 2016 and 2015, respectively).

Other expenses of €1,844 million (€1,512 million and €1,135 million in 2016 and 2015, respectively) included an allowance for doubtful accounts in of the Gas & Power segment, primarily in the retail business, for €446 million (€399 million and €549 million in 2016 and 2015, respectively).

Future minimum lease payments expected to be paid under non-cancelable operating leases are provided below:


(€ million)	2017		2016		2015
To be paid:
- within 1 year		883		593		495
- between 2 and 5 years		1,710		1,040		1,061
- beyond 5 years		1,939		785		809
		4,532		2,418		2,365

Operating leases primarily comprised long-term rentals of FPSO vessels and, to a lesser extent, rates for drilling rigs, time charter and land, service stations and office buildings. Such leases generally did not include renewal options. There are no significant restrictions provided by these operating leases that may limit the ability of Eni to pay dividends, use assets or take on new borrowing. The increase of

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€2,114 million compared to 2016 in future minimum payments for operating lease obligations is due for €2,280 million to commitments undertaken by the Exploration & Production segment for the operating leases of two FPSO ships following the start-up in 2017 of the development projects in Angola and Ghana.

Risk provisions net of reversal of unused provisions amounted to €886 million (€505 million and €644 million in 2016 and 2015, respectively) and mainly related to net provisions for litigations amounting to €375 million (net provisions of €55 million and €179 million in 2016 and 2015, respectively) and net provisions for environmental liabilities amounting to €200 million (net provisions of €198 million and €232 million in 2016 and 2015, respectively). More information is provided in note 30 — Provisions for contingencies. Risk provisions net of reversal of unused provisions by industry segment are disclosed in note 46 — Information by industry segment and by geographical area.

Payroll and related costs


(€ million)	2017		2016		2015
Wages and salaries		2,447		2,491		2,648
Social security contributions		441		445		453
Cost related to employee benefit plans		113		81		85
Other costs		162		202		182
		3,163		3,219		3,368
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(202)		(215)		(203)
- capitalized direct costs associated with self-constructed assets - intangible assets		(10)		(10)		(46)
		2,951		2,994		3,119

Other costs of €162 million (€202 million and €182 million in 2016 and 2015, respectively) comprised provisions for redundancy incentives of €18 million (€47 million and €31 million in 2016 and 2015, respectively) and costs for defined contribution plans of €90 million (€83 million and €86 million in 2016 and 2015, respectively).

Cost related to employee benefit plans are described in note 31 — Provisions for employee benefits.

Average number of employees

The Group average number and breakdown of employees by category is reported below:


	2017				2016				2015
(number)	Subsidiaries		Joint operations		Subsidiaries		Joint operations		Subsidiaries		Joint operations
Senior managers		995		17		1,018		18		1,044		17
Junior managers		9,089		98		9,160		109		9,091		108
Employees		16,721		371		17,180		384		17,685		379
Workers		5,659		285		5,703		294		5,895		303
		32,464		771		33,061		805		33,715		807

The average number of employees was calculated as the average between the number of employees at the beginning and the end of the period. In 2015, the amount does not include the employees of discontinued operations (Saipem Group). The average number of senior managers included managers employed and operating in foreign countries, whose position is comparable to a senior manager’s status.

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Long-term monetary incentive plan for the managers of Eni

On April 13, 2017, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2017 – 2019 and empowered the Board of Directors to execute the Plan by authorizing it to dispose up to a maximum of 11 million of treasury shares in service of the Plan.

The Long-Term Monetary Incentive Plan 2017 – 2019 provides for three annual awards for the years 2017, 2018 and 2019 and is intended for the Chief Executive Officer of Eni and for the managers of Eni and its subsidiaries who qualify as “senior managers deemed critical for the business”, selected among those who are in charge of tasks directly linked to the Group results or of strategic clout to the business. The Plan provides the granting of Eni shares for no consideration to eligible managers after a three-year vesting period under the condition that they would remain in office until vesting. Considering that this incentive falls within the category of employee compensation, in accordance with IFRS, the cost of the plan is determined based on the fair value of the financial instruments awarded to the beneficiaries and the number of shares that will be effectively granted at the end of the vesting period; the cost is accruing along the vesting period.

The number of shares that will be granted at the end of the vesting period is conditioned on a 50 – 50 basis to actual results of two performance parameters against preset targets: (i) a market condition in terms of Total Shareholder Return (TSR) of the Eni share compared to the TSR of the FTSE Mib index of the Italian Stock Exchange Market, and to a group of Eni’s competitors (“Peers Group”)24 and the TSR of their corresponding stock exchange market25; and (ii) growth in the Net Present Value (NPV) of proved reserves benchmarked against the Peer Group.

Depending on the performance of the parameters mentioned above, the number of shares that will vest may range between 0% and 180% of the initial award. Furthermore, 50% of the shares that will eventually vest is subject to a lock-up clause of one year after the vesting date.

The number of shares initially awarded was 1,719,061; the weighted average fair value of the shares at the same date was €7.99 per share.

The estimation of the fair value was calculated by adopting specific valuation techniques regarding the different performance parameters provided by the plan (the stochastic method for the market condition of the plan and the Black-Scholes model for the component related to the NPV of the reserves) taking into account the fair value of the Eni share at the grant date (€13.81 per share), reduced by dividends expected along the vesting period (5.79% of the share price determined considering the dividends announced in the 12 months before the award), the volatility of the stock (25.12%), the forecasts for the performance parameters, as well as the lower value attributable to the shares considering the lock-up period at the end of the vesting period.

The cost related to the long-term monetary incentive plan 2017 – 2019, recognized as a component of the payroll cost, amounted to €0.4 million with a contra-entry to equity reserves.

The group consists of the following oil companies: ExxonMobil, Chevron, BP, Royal Dutch Shell, Total, ConocoPhillips, Statoil, Apache, Marathon Oil and Anadarko.

The performance condition connected with the TSR in accordance with the international accounting standards represents a so-called market condition.

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Compensation of key management personnel

Compensation of personnel holding key positions in planning, directing and controlling the Eni Group subsidiaries, including executive and non-executive officers, general managers and managers with strategic responsibilities in office during the year (including contributions and ancillary costs) amounted to €43 million, €44 million and €42 million for 2017, 2016 and 2015, respectively, and consisted of the following:


(€ million)	2017		2016		2015
Wages and salaries		25		26		26
Post-employment benefits		2		2		2
Other long-term benefits		9		12		12
Indemnities upon termination of employment		7		4		2
		43		44		42

Compensation of Directors and Statutory Auditors

Compensation of Directors amounted to €14.5 million, €7.1 million and €6.7 million for 2017, 2016 and 2015, respectively. Compensation of Statutory Auditors amounted to €0.760 million, €0.738 million and €0.551 million in 2017, 2016 and 2015, respectively.

Compensation included emoluments and social security benefits due for the office as Director or Statutory Auditor held at the parent company Eni SpA or other Group subsidiaries, which was recognized as a cost to the Group, even if not subject to personal income tax.

Other operating income (loss)

The analysis of net income (loss) on commodity derivatives was as follows:


(€ million)	2017		2016		2015
Net income (loss) on cash flow hedging derivatives		12		(1)		2
Net income (loss) on other derivatives		(44)		17		(487)
		(32)		16		(485)

Net income (loss) on cash flow hedging derivatives related to the ineffective portion of the hedging relationship on commodity derivatives was recognized through profit and loss in the Gas & Power segment.

Net income (loss) on other derivatives included: (i) the fair value measurement and settlement of commodity derivatives which could not be elected for hedge accounting under IFRS because they related to net exposure to commodity risk and derivatives for trading purposes and proprietary trading amounting to a net loss of €44 million (net income of €36 million in 2016 and net loss of €471 million in 2015); and (ii) the fair value valuation at certain derivatives embedded in the pricing formulas of long-term gas supply contracts of the Exploration & Production segment amounting to a net loss of €19 million and €16 million in 2016 and in 2015, respectively.

Operating expenses with related parties are reported in note 47 — Transactions with related parties.

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Depreciation and amortization


(€ million)	2017		2016		2015
Depreciation, depletion and amortization:
- tangible assets		7,199		7,308		8,646
- intangible assets		286		253		303
		7,485		7,561		8,949
less:
- capitalized direct costs associated with self-constructed assets - tangible assets		(2)		(2)		(9)
		7,483		7,559		8,940

Depreciation and amortization by industry segment are disclosed in note 46 — Information by industry segment and by geographical area.

Net impairment (reversal)


(€ million)	2017		2016		2015
Impairments:
- tangible assets		848		1,067		5,993
- intangible assets		14				544
		862		1,067		6,537
less:
- reversal of impairments - tangible assets		(1,055)		(1,153)		(3)
- reversal of impairments - intangible assets		(32)		(389)
		(225)		(475)		6,534

Net impairment (reversal) by industry segment are disclosed in note 46 — Information by industry segment and by geographical area.

Write-off


(€ million)	2017		2016		2015
Write-off
- tangible assets		239		289		678
- intangible assets		24		61		10
		263		350		688

Write-off by industry segment are disclosed in note 46 — Information by industry segment and by geographical area.

41 Finance income (expense)


(€ million)	2017		2016		2015
Finance income (expense)
Finance income		3,924		5,850		8,635
Finance expense		(5,886)		(6,232)		(10,104)
Net finance income (expense) from financial assets held for trading		(111)		(21)		3
		(2,073)		(403)		(1,466)
Income (expense) from derivative financial instruments		837		(482)		160
		(1,236)		(885)		(1,306)

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The breakdown by lenders or type of net finance income or expense is provided below:


(€ million)	2017		2016		2015
Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds		(638)		(639)		(740)
Interest due to banks and other financial institutions		(113)		(118)		(98)
Net finance income (expense) from financial assets held for trading		(111)		(21)		3
Interest from banks		12		15		19
Interest and other income from financial receivables and securities held for non-operating purposes		16		37		2
		(834)		(726)		(814)
Exchange differences
Positive exchange differences		3,549		5,579		8,400
Negative exchange differences		(4,454)		(4,903)		(8,754)
		(905)		676		(354)
Other finance income (expense)
Interest and other income on financing receivables and securities held for operating purposes		128		143		120
Capitalized finance expense		73		106		166
Finance expense due to the passage of time (accretion discount)(a)		(264)		(312)		(291)
Other finance (expense)		(271)		(290)		(293)
		(334)		(353)		(298)
		(2,073)		(403)		(1,466)

(a)

The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities.

Finance income (loss) on derivative financial instruments consisted of the following:


(€ million)	2017		2016		2015
Derivatives on exchange rate		809		(494)		96
Derivatives on interest rate		28		(12)		31
Options				24		33
		837		(482)		160

Net income from derivatives of €837 million (net loss of €482 million and net income of €160 million in 2016 and 2015, respectively) was recognized in connection with fair value valuation of certain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing formulas of commodities in the Gas & Power segment. The lack of formal requirements to qualify these derivatives as hedges under IFRS also entailed the recognition in profit or loss of currency translation differences on assets and liabilities denominated in currencies other than functional currency, as this effect cannot be offset by changes in the fair value of the related instruments.

Net income on options of 2016 of €24 million (net income of €33 million in 2015) related to: (i) the reversal through profit and loss of the fair value reserve relating to the embedded options of the bond convertible into ordinary shares of Snam SpA amounting to an income of €26 million (income of €33 million in 2015); (ii) the fair value of the option embedded in non-dilutive equity-linked convertible bond for a net loss of €2 million.

Finance income (expense) with related parties is disclosed in note 47 — Transactions with related parties.

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42 Income (expense) from investments

Share of profit (loss) of equity-accounted investments


(€ million)	2017		2016		2015
Share of profit from equity-accounted investments		124		77		150
Share of loss from equity-accounted investments		(353)		(370)		(615)
Decreases (increases) in the provision for losses on investments from equity accounted investments		(38)		(33)		(6)
		(267)		(326)		(471)

More information is provided in note 20 – Investments.

Share of profit or loss of equity accounted investments by industry segment is disclosed in note 46 — Information by industry segment and by geographical area.

Other gain (loss) from investments


(€ million)	2017		2016		2015
Dividends		205		143		402
Net gain (loss) on disposals		163		(14)		164
Other net income (expense)		(33)		(183)		10
		335		(54)		576

In 2017, dividend income of €205 million essentially related to Nigeria LNG Ltd for €167 million and to Saudi European Petrochemical Co for €21 million.

In 2016, dividend income of €143 million essentially related to Nigeria LNG Ltd for €76 million and to Saudi European Petrochemical Co for €45 million.

In 2015, dividend income of €402 million primarily related to Nigeria LNG Ltd for €222 million, Snam SpA for €72 million, to Saudi European Petrochemical Co for €69 million and Galp Energia SGPS SA for €21 million.

In 2017, net gain on disposals amounting to €163 million related to the sale of the 100% share capital of Eni Gas & Power NV and its subsidiary Eni Wind Belgium NV.

In 2016, net loss on disposals amounting to €14 million related to: (i) a loss of €32 million for the sale of 2.22% share capital (entire stake owned) of Snam SpA; (ii) a gain of €11 million related to the sale of 100% share capital of Eni Hungaria Zrt and Eni Slovenjia Doo; and (iii) a gain of €6 million related to the sale of 30% share capital (entire stake own) of Pokrovskoe Petroleum BV and the sale of the 60% share capital (entire stake owned) of Zagoryanska Petroleum BV.

In 2015, net gains on disposals amounting to €164 million related to: (i) a gain of €98 million for the sale of an 8% stake in Galp Energia SGPS SA; (ii) a gain of €46 million for the sale of a 6.03% stake in Snam SpA; (iii) a gain of €32 million for the sale of 100% stake in Ceská Republika Sro; (iv) a gain of €31 million for the sale of a 100% stake of Eni Romania Srl; (v) a gain of €6 million for the sale of 32.445% stake (entire stake owned) in Ceská Rafinérská AS (CRC); (vi) a gain of €1 million of 100% stake in Eni Slovensko Spol Sro; and (vii) a loss of €47 million for the sale of a 76% stake in Inversora de Gas Cuyana SA (entire stake owned), a 6.84% stake in Distribudora de Gas Cuyana SA (entire stake owned), a 25% stake in Inversora de Gas del Centro SA (entire stake owned) and a 31.35% stake in Distribudora de Gas del Centro SA (entire stake owned).

In 2017, other net losses of €33 million included the impairment of Unión Fenosa Gas SA for €35 million.

In 2016, other net losses of €183 million included: (i) an impairment for €162 million relating to Unión Fenosa Gas SA (€84 million), PetroSucre SA (€65 million) and Genomatica Inc (€13 million).

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In 2015, other net income of €10 million included: (i) a gain on the remeasurement at market fair value of 77.7 million shares of Snam SpA for €49 million to which the fair value option was applied as provided for by IAS 39; (ii) a reversal of unutilized provision for losses on investments of €10 million relating to Caspian Pipeline Consortium R — Closed Joint Stock Co; and (iii) an impairment for €49 million relating to Unión Fenosa Gas SA.

43 Income taxes


(€ million)	2017		2016		2015
Current taxes:
- Italian subsidiaries		712		195		155
- subsidiaries of the Exploration & Production segment - outside Italy		3,167		2,671		4,015
- other subsidiaries - outside Italy		142		133		218
		4,021		2,999		4,388
Net deferred taxes:
- Italian subsidiaries		(464)		(243)		881
- subsidiaries of the Exploration & Production segment - outside Italy		(162)		(813)		(2,156)
- other subsidiaries - outside Italy		72		(7)		9
		(554)		(1,063)		(1,266)
		3,467		1,936		3,122

Current income taxes payable by Italian subsidiaries amounted to €712 million and were in respect of the Italian corporate taxation IRES for €26 million and IRAP for €20 million and foreign taxes on the share of profit earned outside Italy for €666 million.

The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 24% (27.5% in 2016 and in 2015) and the effective tax charge is the following:


(€ million)	2017		2016		2015
Profit (loss) before taxation		6,844		892		(4,277)
Tax rate (IRES) (%)		24.0		27.5		27.5
Statutory corporation tax charge (credit) on profit or loss		1,643		245		(1,176)
Increase (decrease) resulting from:
- higher tax charges related to subsidiaries outside Italy		1,882		1,152		2,576
- impact pursuant to the write-off of deferred tax assets and recalculation of tax rates		(96)		397		1,514
- effect due to the tax regime provided for intercompany dividends		1		87		114
- Italian regional income tax (IRAP)		77		42		100
- effect due to non-taxable gains/losses on sales of investments		(177)		8		(39)
- impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009		61
- effect due to discontinued operations						(288)
- other adjustments		76		5		321
		1,824		1,691		4,298
Effective tax charge		3,467		1,936		3,122

In 2017, the higher tax charges at non-Italian subsidiaries of €1,882 million related to the Exploration & Production segment for €1,811 million.

In 2016, the higher tax charges at non-Italian subsidiaries of €1,152 million related to the Exploration & Production segment for €1,211 million. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €397 million was incurred at Italian subsidiaries and essentially related to a write-off at deferred tax assets due to projections of lower future taxable profit.

In 2015, the higher tax charges at non-Italian subsidiaries of €2,576 million related to the Exploration & Production segment for €2,410 million, including a write-off of deferred tax assets due to a reduced

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profitability outlook of €1,058 million. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €1,514 million was incurred at Italian subsidiaries and related to a write-off at deferred tax assets due to projections of lower future taxable profit and to a reduction due to a change in the statutory tax rate from 27.5% to 24%, starting from January 1, 2017. The effect due to the Italian regional income tax (IRAP) of €100 million included a write-off at deferred tax assets due to projections of lower future taxable profit for €54 million.

44 Earnings per share

Basic earnings per ordinary share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the period, excluding treasury shares.

The average number of ordinary shares used for the calculation of the basic earnings per share in 2017 was 3,601,140,133 (same amount in 2016 and 2015).

Diluted earnings per share is calculated by dividing the net profit of the period attributable to Eni’s shareholders by the weighted average number of shares fully-diluted including shares outstanding in the year and the number of potential shares to be issued in connection with stock-based compensation plans.

As of December 31, 2017, the shares that could be potentially issued related the estimation of new share that will vest in connection with the long-term monetary incentive plan. The weighted average number of outstanding shares used for calculating the diluted earnings per share is 1,691,413 for 2017 with immaterial impact on the fully-diluted earnings per share. In 2016 and 2015, there were no potential shares with dilutive effects.

Reconciliation of the average number of shares used for the calculation for both basic and diluted earnings per share was as follows:


		2017		2016		2015
Weighted average number of shares used for the calculation of the basic earnings per share			3,601,140,133		3,601,140,133		3,601,140,133
Potential share to be issued for ILT incentive plan			1,691,413
Weighted average number of shares used for the calculation of the diluted earnings per share			3,602,831,546		3,601,140,133		3,601,140,133
Eni’s net profit	(€ million)		3,374		(1,464)		(8,778)
Basic earning (loss) per share	(euro per share)		0.94		(0.41)		(2.44)
Diluted earning (loss) per share	(euro per share)		0.94		(0.41)		(2.44)
Eni’s net profit - Continuing operations	(€ million)		3,374		(1,051)		(7,952)
Basic earning (loss) per share	(euro per share)		0.94		(0.29)		(2.21)
Diluted earning (loss) per share	(euro per share)		0.94		(0.29)		(2.21)
Eni’s net profit - Discontinued operations	(€ million)				(413)		(826)
Basic earning (loss) per share	(euro per share)				(0.12)		(0.23)
Diluted earning (loss) per share	(euro per share)				(0.12)		(0.23)

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45 Exploration for evaluation of oil&gas resources


(€ million)	2017		2016		2015
Revenues related to exploration activity and evaluation		9		4		68
Exploration activity and evaluation costs
- write-off of exploration and evaluation costs		252		170		617
- other exploration costs		273		204		254
Exploration expense for the year		525		374		871
Intangible assets: proved and unproved exploration licence and leasehold property acquisition costs		995		1,092		735
Tangible assets: capitalized exploration and evaluation costs		1,860		2,818		2,637
Total tangible and intangible assets		2,855		3,910		3,372
Provision for decommissioning related to exploration activity and evaluation		81		118		131
Exploration expenditure (net cash used in investing activivties)		442		417		566
Geological and geophysical costs (cash flow from operating activities)		273		204		254
Total exploration effort		715		621		820

46 Information by industry segment and by geographical area

Information by industry segment

Eni’s segmental reporting reflects the Group’s operating segments, whose results are regularly reviewed by the chief operating decision maker (the CEO) to make decisions about resources to be allocated to each segment and to assess segment performance.

Segment performance is evaluated based on operating profit or loss. Other segment information presented to the CEO include segment revenues and directly attributable assets and liabilities.

As of December 31, 2017, Eni had the following reportable segments:

•

Exploration & Production: is engaged in exploring for and recovering crude oil and natural gas, including participation to projects for the liquefaction of natural gas;

•

Gas & Power: is engaged in supply and marketing of natural gas at wholesale and retail markets, supply and marketing of LNG and supply, production and marketing of power at retail and wholesale markets. Gas & Power is engaged in supply and marketing of crude oil and oil products targeting the operational requirements of Eni’s refining business and in commodity trading (including crude oil, natural gas, oil products, power, emission allowances, etc.) targeting to both hedge and stabilize the Group industrial and commercial margins according to an integrated view and to optimize margins.

•

Refining & Marketing and Chemical: is engaged in manufacturing, supply and distribution and marketing activities for oil products and chemical products.

•

Corporate and other activities: represents the key support functions, comprising holdings and treasury, headquarters, central functions like IT, HR, real estate, captive insurance activities, as well as the Group environmental cleanup and remediation activities performed by the subsidiary Syndial. The Energy Solutions Department, which engages in developing the business of renewable energy, is an operating segment, which is reported within Corporate and other activities because it does not meet the materiality threshold for separate segment reporting.

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The information by segmental reporting is the following:

															Discontinued operations
(€ million)	Exploration & Production		Gas & Power		Refining & Marketing and Chemical		Engineering & Construction		Corporate and other activities		Adjustments of intragroup profits		Total		Engineering & Construction		Intragroup eliminations		Continuing operations
2017
Net sales from operations(a)		19,525		50,623		22,107				1,462
Less: intersegment sales		(12,394)		(10,777)		(2,336)				(1,291)
Net sales to customers		7,131		39,846		19,771				171				66,919						66,919
Operating profit		7,651		75		981				(668)		(27)		8,012						8,012
Net provisions for contingencies		479		(20)		182				245				886						886
Depreciation and amortization		6,747		345		360				60		(29)		7,483						7,483
Net impairments (reversals)		(158)		(146)		54				25				(225)						(225)
Write-off		260		2		1								263						263
Share of profit (loss) of equity-accounted investments		(99)		(10)		(57)				(101)				(267)						(267)
Identifiable assets(b)		66,661		11,058		11,599				1,108		(610)		89,816
Unallocated assets														25,112
Equity-accounted investments		1,234		509		321				1,447				3,511
Identifiable liabilities(c)		17,273		8,851		4,005				4,053		(306)		33,876
Unallocated liabilities														32,973
Capital expenditure		7,739		142		729				87		(16)		8,681
2016
Net sales from operations(a)		16,089		40,961		18,733				1,343
Less: intersegment sales		(9,711)		(8,898)		(1,605)				(1,150)
Net sales to customers		6,378		32,063		17,128				193				55,762						55,762
Operating profit		2,567		(391)		723				(681)		(61)		2,157						2,157
Net provisions for contingencies		123		50		171				438		(277)		505						505
Depreciation and amortization		6,772		354		389				72		(28)		7,559						7,559
Net impairments (reversals)		(700)		81		104				40				(475)						(475)
Write-off		153		2		195								350						350
Share of profit (loss) of equity-accounted investments		(198)		19		(3)				(144)				(326)						(326)
Identifiable assets(b)		75,716		12,014		10,712				1,146		(520)		99,068
Unallocated assets														25,477
Equity-accounted investments		1,626		592		289				1,533				4,040
Identifiable liabilities(c)		17,433		8,923		3,968				3,939		(332)		33,931
Unallocated liabilities														37,528
Capital expenditure		8,254		120		664				55		87		9,180
2015
Net sales from operations(a)		21,436		52,096		22,639		11,507		1,468
Less: intersegment sales		(12,115)		(9,917)		(2,007)		(1,243)		(1,314)
Net sales to customers		9,321		42,179		20,632		10,264		154				82,550		(10,264)				72,286
Operating profit		(959)		(1,258)		(1,567)		(694)		(497)		(23)		(4,998)		694		1,228		(3,076)
Net provisions for contingencies		221		41		148		104		226		8		748		(104)				644
Depreciation and amortization		8,080		363		454		618		71		(28)		9,558		(618)				8,940
Net impairments (reversals)		5,212		152		1,150		590		20				7,124		(590)				6,534
Write-off		686		2										688						688
Share of profit (loss) of equity-accounted investments		(446)		(2)		(20)		17		(3)				(454)		(17)				(471)
Identifiable assets(b)		73,073		14,290		10,483		13,608		1,117		(543)		112,028
Unallocated assets														26,973
Equity-accounted investments		1,884		690		243		134		36				2,987		(134)				2,853
Identifiable liabilities(c)		17,742		9,313		3,657		5,861		3,824		(199)		40,198
Unallocated liabilities														41,394
Capital expenditure		9,980		154		628		561		64		(85)		11,302

(a)

Before elimination of intersegment sales.

(b)

Includes assets directly associated with the generation of operating profit.

(c)

Includes liabilities directly associated with the generation of operating profit.

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Financial information by geographical area

Identifiable assets and investments by geographical area of origin

(€ million)	Italy		Other European Union		Rest of Europe		Americas		Asia		Africa		Other areas		Total
2017
Identifiable assets(a)		18,449		7,706		6,160		4,406		16,527		35,385		1,183		89,816
Capital expenditure in tangible and intangible assets		1,090		316		387		278		898		5,699		13		8,681
2016
Identifiable assets(a)		18,769		7,370		6,960		5,397		19,471		39,812		1,289		99,068
Capital expenditure in tangible and intangible assets		1,163		331		460		233		1,978		5,004		11		9,180
2015
Identifiable assets(a)		21,360		12,370		7,937		7,442		22,359		38,927		1,633		112,028
Capital expenditure in tangible and intangible assets		1,320		708		1,151		727		2,326		5,020		50		11,302

(a)

Includes assets directly associated with the generation of operating profit.

Sales from operations by geographical area of destination


(€ million)	2017		2016		2015
Italy		21,925		21,280		24,405
Other European Union		19,791		15,808		20,730
Rest of Europe		5,911		4,804		7,125
Americas		5,154		3,212		4,217
Asia		7,523		5,619		9,086
Africa		6,428		4,865		6,482
Other areas		187		174		241
		66,919		55,762		72,286

47 Transactions with related parties

In the ordinary course of its business, Eni enters into transactions regarding:

(a)

exchange of goods, provision of services and financing with joint ventures, associates and non-consolidated subsidiaries;

(b)

exchange of goods and provision of services with entities controlled by the Italian Government;

(c)

exchange of goods and provision of services with companies related to Eni SpA through members of the Board of Directors. Most of these transactions are exempt from the application of the Eni internal procedure of Eni “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties” pursuant to the Consob Regulation, since they relate to ordinary transactions conducted at market or standard conditions, or because under the materiality threshold provided for by the procedure. The solely non-exempted transaction, that was positively examined and valued in application of the procedure, concerned branding and advertising services (for an amount of lower than €1 million) conducted with Vodafone Italia SpA related to Eni SpA through of a member of the Board of Directors; and

(d)

contributions to entities with a non-company form referable to Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment, as well as research and development; and (ii) Eni Enrico Mattei Foundation established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge in the fields of economics, energy and environment, both at the national and international level.

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Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities whose aim is to develop charitable, cultural and research initiatives, are related to the ordinary course of Eni’s business.

Trade and other transactions with related parties

(€ million)	December 31, 2017						2017

	Receivables and other assets		Payables and other liabilities		Guarantees		Costs						Revenues						Other operating (expense) income
Name							Goods		Services		Other		Goods		Services		Other		Other operating (expense) income
Joint ventures and associates
Petrobel Belayim Petroleum Co		86		1,205						3,168						8
Coral FLNG SA		20		4		1,094										26		2
Saipem Group		63		76		7,270				450				5		30		9
Karachaganak Petroleum Operating BV		36		121				652		295		4
Mellitah Oil & Gas BV		5		220				34		461						2
Agiba Petroleum Co		1		83						142
Unión Fenosa Gas SA						57		1				2		202						28
Other(*)		84		22				26		113		1		82		39		7
		295		1,731		8,421		713		4,629		7		289		105		18		28
Unconsolidated entities controlled by Eni
Eni BTC Ltd						169
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		77		1		5										7
Other(*)		20		23		7		4		10				2		4		1
		97		24		181		4		10				2		11		1
		392		1,755		8,602		717		4,639		7		291		116		19		28
Entities controlled by the Government
Enel Group		123		187				19		603				94		70				285
Snam Group		187		351				68		1,153				83		2
Terna Group		35		31				84		122		6		98		56				15
GSE - Gestore Servizi Energetici		69		219				303		6		197		470		211		21		2
Italgas Group		14		180		1				678		3		8		10
Other(*)		50		21				2		27		9		11		4		1		1
		478		989		1		476		2,589		215		764		353		22		303
Pension funds and foundations		1		2								25		1
Groupement Sonatrach – Agip «GSA» e Organe Conjoint des Opérations «OC SH/FCP»		39		145				19		484		27				42
		910		2,891		8,603		1,212		7,712		274		1,056		511		41		331

(*)

Each individual amount included herein was lower than €50 million.

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(€ million)
	December 31, 2015						2015
	Receivables and other assets		Payables and other liabilities		Guarantees		Costs						Revenues						Other operating (expense) income
Name							Goods		Services		Other		Goods		Services		Other		Other operating (expense) income
Continuing operations
Joint ventures and associates
Agiba Petroleum Co		6		60						187
CEPAV (Consorzio Eni per l’Alta Velocità) Due				1
CEPAV (Consorzio Eni per l’Alta Velocità) Uno						6,122
Karachaganak Petroleum Operating BV		48		171				748		403		8				10
Mellitah Oil & Gas BV		8		16				46		339						19
Petrobel Belayim Petroleum Co		16		183						543
Petromar Lda		2				6
Unión Fenosa Gas SA		1				57														(4)
Other(*)		118		42				27		124		1		60		70		37		(2)
		199		473		6,185		821		1,596		9		60		99		37		(6)
Unconsolidated entities controlled by Eni
Eni México S. de RL de CV						101
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)		65		1		9										3
Other(*)		17		19		3		2		2				4		2		2
		82		20		113		2		2				4		5		2
		281		493		6,298		823		1,598		9		64		104		39		(6)
Entities controlled by the Government
Enel Group		138		203						1,063				196		134				90
Snam Group		144		522		3		137		2,014		5		249		24		1
Terna Group		18		42				109		125		14		77		19		29		12
GSE - Gestore Servizi Energetici		44		63				419		5		35		307		43
Other(*)		22		38						56		6		29		1
		366		868		3		665		3,263		60		858		221		30		102
Pension funds and foundations		1		2						4		50
Groupement Sonatrach – Agip «GSA» e Organe Conjoint des Opérations «OC SH/FCP»		185		300						453		12		35		60
		833		1,663		6,301		1,488		5,318		131		957		385		69		96
Discontinued operations
Joint ventures and associates
CEPAV (Consorzio Eni per l’Alta Velocità) Due		60		99		68				101						145
CEPAV (Consorzio Eni per l’Alta Velocità) Uno		9		3						3						1
KWANDA - Suporte Logistico Lda		69		10								5				8
Mellitah Oil & Gas BV		9								7
Petrobel Belayim Petroleum Co		19														86
Petromar Lda		97		16						16						45
Other(*)		14		27				10		54				1		21		1
		277		155		68		10		181		5		1		306		1
Unconsolidated entities controlled by Eni
Other(*)		1		1						2
		1		1						2
Entities controlled by the Government
Snam Group		25		46												36
Other(*)				5						3
		25		51						3						36
Pension funds and foundations												1
		303		207		68		10		186		6		1		342		1
		1,136		1,870		6,369		1,498		5,504		137		958		727		70		96

(*)

Each individual amount included herein was lower than €50 million.

The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

•

guarantees issued on a pro-quota basis granted to Coral FLNG SA on behalf of the Consortium TJS for the contractual obligations assumed following the award of the EPCIC contract for the construction of a floating gas liquefaction plant (for more information see note 38 — Guarantees, commitments and risks);

•

Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co, Groupement Sonatrach — Agip «GSA», Organe Conjoint des Opérations «OC SH/FCP» and, only for Karachaganak Petroleum Operating BV, purchase of oil products by Eni Trading & Shipping SpA; services charged to Eni’s associates are invoiced on the basis of incurred costs;

•

engineering, construction and drilling services by the Saipem Group mainly for the Exploration & Production segment and guarantees issued by Eni SpA relating to bid bonds and performance bonds;

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•

performance guarantees given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations and sales of LNG;

•

a guarantee issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd; and

•

services for environmental restoration to Industria Siciliana Acido Fosforico — ISAF SpA (in liquidation).

The most significant transactions with entities controlled by the Italian Government concerned:

•

sale of fuel, sale and purchase of gas, acquisition of power distribution services and fair value of derivative financial instruments with Enel Group;

•

acquisition of natural gas transportation, distribution and storage services with the Snam Group and the Italgas Group on the basis of tariffs set by the Italian Regulatory Authority for Energy, Networks and Environment and purchase and sale of natural gas for granting the balancing of the system on the basis of prices referred to the quotations of the main energy commodities;

•

sale and purchase of electricity, the acquisition of domestic electricity transmission service on the basis of prices referred to the quotations of the main energy commodities, and derivatives on commodities entered to hedge the price risk related to the utilization of transport capacity rights with the Terna Group;

•

sale and purchase of electricity, gas, environmental certificates and sale of oil products with GSE — Gestore Servizi Energetici for the setting-up of a specific stock held by the Organismo Centrale di Stoccaggio Italiano (OCSIT) according to the Legislative Decree No. 249/2012.

Transactions with pension funds and foundation concerned:

•

provisions to pension funds of €34 million; and

•

contributions and service provisions to Eni Foundation of €2 million and to Eni Enrico Mattei Foundation for €4 million.

Financing transactions with related parties

(€ million)
	December 31, 2017						2017
Name	Receivables		Payables		Guarantees		Charges		Gains
Continuing operations
Joint ventures and associates
Coral South FLNG D MCC						1,334
Cardón IV SA		955								86
Angola LNG Ltd						233
Matrìca SpA										9
Shatskmorneftegaz Sarl		101								6
Société Centrale Electrique du Congo SA		66		43
Saipem Group				3		56				13
Coral FLNG SA		56								71
Other(*)		48		49		2		1		5
		1,226		95		1,625		1		190
Unconsolidated entities controlled by Eni
Servizi Fondo Bombole Metano SpA		60		9						1
Eni BTC Ltd				28
Other(*)		1		24
		61		61						1
Entities controlled by the Government
Other(*)				8				3
				8				3
		1,287		164		1,625		4		191

(*)

Each individual amount included herein was lower than €50 million.

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(€ million)
	December 31, 2016						2016
Name	Receivables		Payables		Guarantees		Charges		Gains		Income from equity instruments
Continuing operations
Joint ventures and associates
Cardón IV SA		1,054								96
Matrìca SpA		125						93		9
Shatskmorneftegaz Sarl		69						13		4
Société Centrale Electrique du Congo SA		78						18
Unión Fenosa Gas SA				85
Saipem Group						82				43		27
Other(*)		52				2		17		4
		1,378		85		84		141		156		27
Unconsolidated entities controlled by Eni
Eni BTC Ltd				54
Other(*)		46		52				1		1
		46		106				1		1
Entities controlled by the Government
Other(*)								3
								3
		1,424		191		84		145		157		27

(*)

Each individual amount included herein was lower than €50 million.

(€ million)
	December 31, 2015						2015
Name	Receivables		Payables		Guarantees		Charges		Gains
Continuing operations
Joint ventures and associates
Cardón IV SA		1,112								65
Matrìca SpA		209						10		11
Shatskmorneftegaz Sàrl		63						21
Société Centrale Electrique du Congo SA		94
Unión Fenosa Gas SA				90
Other(*)		52		7		12		19		5
		1,530		97		12		50		81
Unconsolidated entities controlled by Eni
Other(*)		51		111						1
		51		111						1
Entities controlled by the Government
Other(*)		27								1
		27								1
		1,608		208		12		50		83
Discontinued operations
Joint ventures and associates
CEPAV (Consorzio Eni per l’Alta Velocità) Due						150
Other(*)		5
		5				150
		1,613		208		162		50		83

(*)

Each individual amount included herein was lower than €50 million.

The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

•

a bank debt guarantee issued on behalf of Coral South FLNG DMCC (for more information see note 38 — Guarantees, commitments and risks);

•

financing loans granted to Cardón IV SA for the exploration and development activities of a gas field in Venezuela;

•

bank debt guarantees issued on behalf of Angola LNG Ltd;

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•

financing loans, which were completely written down, granted to Matrìca SpA in relation to the “Green Chemistry” project at the Porto Torres plant;

•

financing loans granted to Shatskmorneftegaz Sàrl for the exploration activity of in the Black Sea and to Société Centrale Electrique du Congo SA for the construction of an electric plant in Congo;

•

residual bank debt guarantees issued on behalf of Saipem Group;

•

financing loans granted to Coral FLNG SA for the construction of a floating gas liquefaction plant in the Area 4 in Mozambique (for more information see note 38 – Guarantees, commitments and risks);

•

financing loans granted to Servizi Fondo Bombole Metano SpA for operating activities;

•

a cash deposit at Eni’s financial companies on behalf of Eni BTC Ltd.

Financial charges to related parties do not include impairments of financial receivables of €242 million.

Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows

The impact of transactions and positions with related parties on the balance sheet consisted of the following:

	December 31, 2017						December 31, 2016
(€ million)	Total		Related parties		Impact %		Total		Related parties		Impact %
Trade and other receivables		15,737		907		5.76		17,593		1,100		6.25
Other current assets		1,573		30		1.91		2,591		57		2.20
Other non-current financial assets		1,675		1,214		72.48		1,860		1,349		72.53
Other non-current assets		1,323		46		3.48		1,348		13		0.96
Current financial liabilities		2,242		164		7.31		3,396		191		5.62
Trade and other payables		16,748		2,808		16.77		16,703		2,289		13.70
Other current liabilities		1,515		60		3.96		2,599		88		3.39
Other non-current liabilities		1,479		23		1.56		1,768		23		1.30

The impact of transactions with related parties on the profit and loss accounts consisted of the following:


	2017						2016						2015
(€ million)	Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %
Continuing operations
Net sales from operations		66,919		1,567		2.34		55,762		1,238		2.22		72,286		1,342		1.86
Other income and revenues		4,058		41		1.01		931		74		7.95		1,252		69		5.51
Purchases, services and other		(52,461)		(9,164)		17.47		(44,124)		(8,212)		18.61		(56,848)		(6,882)		12.11
Payroll and related costs		(2,951)		(34)		1.15		(2,994)		(24)		0.80		(3,119)		(55)		1.76
Other operating (expense) income		(32)		331		—		16		247		—		(485)		96		—
Financial income		3,924		191		4.87		5,850		157		2.69		8,635		83		0.96
Financial expense		(5,886)		(4)		0.07		(6,232)		(145)		2.33		(10,104)		(50)		0.49
Derivative financial instruments		837						(482)		27		—		160
Discontinued operations
Total revenues														10,277		344		3.35
Total costs														(12,199)		(202)		1.66

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Main cash flows with related parties are provided below:


(€ million)	2017		2016		2015
Revenues and other income		1,608		1,312		1,411
Costs and other expenses		(5,360)		(5,623)		(5,786)
Other operating income (loss)		331		247		96
Net change in trade and other receivables and liabilities		391		182		105
Net interests		187		133		82
Net cash provided from operating activities - Continuing operations		(2,843)		(3,749)		(4,092)
Net cash provided from operating activities - Discontinued operations						126
Net cash provided from operating activities		(2,843)		(3,749)		(3,966)
Capital expenditure in tangible and intangible assets		(3,838)		(2,613)		(1,151)
Disposal of investments				463
Net change in accounts payable and receivable in relation to investments		425		252		(238)
Change in financial receivables		298		5,650		(194)
Net cash used in investing activities		(3,115)		3,752		(1,583)
Change in financial liabilities		(16)		(192)		13
Net cash used in financing activities		(16)		(192)		13
Total financial flows to related parties		(5,974)		(189)		(5,536)

The impact of cash flows with related parties consisted of the following:


	2017						2016						2015
(€ million)	Total		Related parties		Impact %		Total		Related parties		Impact %		Total		Related parties		Impact %
Cash provided from operating activities		10,117		(2,843)		—		7,673		(3,749)		—		11,649		(3,966)		—
Cash used in investing activities		(3,768)		(3,115)		82.67		(4,443)		3,752		—		(10,923)		(1,583)		14.49
Cash used in financing activities		(4,595)		(16)		0.35		(3,651)		(192)		5.26		(1,351)		13		—

48 Other information about investments

Information on Eni’s investments as of December 31, 2017

The following section provides the information about Eni’s subsidiaries, joint arrangements, associates and other significant investments as of December 31, 2017. Unless otherwise indicated, share capital is represented by ordinary shares directly held by the Group, while ownership interest corresponds to voting rights.

Parent company

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

% Ownership

Eni SpA(#)

Rome

Italy

EUR

4,005,358,876

Cassa Depositi e
Prestiti SpA

25.76

Ministero
dell’Economia e delle
Finanze

4.34

Eni SpA

0.91

Other shareholders

68.99

(#)

Company with shares quoted in the regulated market of Italy or of other EU countries

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Outside Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

% Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Agip Caspian Sea BV

Amsterdam
(Netherlands)

Kazakhstan

EUR

20,005

Eni International BV

100.00

F.C.

Agip Energy and
Natural Resources (Nigeria) Ltd

Abuja (Nigeria)

Nigeria

NGN

5,000,000

Eni International BV
Eni Oil Holdings BV

95.00
5.00

100.00

F.C.

Agip Karachaganak BV

Amsterdam
(Netherlands)

Kazakhstan

EUR

20,005

Eni International BV

100.00

F.C.

Agip Oil Ecuador BV

Amsterdam
(Netherlands)

Ecuador

EUR

20,000

Eni International BV

100.00

F.C.

Agip Oleoducto de Crudos Pesados BV

Amsterdam
(Netherlands)

Ecuador

EUR

20,000

Eni International BV

100.00

Eq.

Burren (Cyprus)
Holdings Ltd
(in liquidation)

Nicosia
(Cyprus)

Cyprus

EUR

1,710

Burren En.(Berm)Ltd

100.00

Co.

Burren Energy
(Bermuda) Ltd

Hamilton
(Bermuda)

United
Kingdom

USD

12,002

Burren Energy Plc

100.00

F.C.

Burren Energy Congo Ltd

Tortola
(British Virgin
Islands)

Republic of
the Congo

USD

50,000

Burren En.(Berm)Ltd

100.00

F.C.

Burren Energy (Egypt)
Ltd

London
(United
Kingdom)

Egypt

GBP

Burren Energy Plc

100.00

Eq.

Burren Energy India Ltd

London
(United
Kingdom)

United
Kingdom

GBP

Burren Energy Plc

100.00

F.C.

Burren Energy Plc

London
(United
Kingdom)

United
Kingdom

GBP

28,819,023

Eni UK Holding Plc
Eni UK Ltd

99.99
(—)

100.00

F.C.

Burren Energy Ship Management Ltd
(in liquidation)

Nicosia
(Cyprus)

Cyprus

EUR

3,420

Burren(Cyp)Hold.Ltd
(L)
Burren En.(Berm)Ltd

50.00

50.00

Co.

Burren Shakti Ltd

Hamilton
(Bermuda)

United
Kingdom

USD

65,300,000

Burren En. India Ltd

100.00

F.C.

Eni Abu Dhabi BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni AEP Ltd

London
(United
Kingdom)

Pakistan

GBP

73,471,000

Eni UK Ltd

100.00

F.C.

Eni Algeria Exploration
BV

Amsterdam
(Netherlands)

Algeria

EUR

20,000

Eni International BV

100.00

F.C.

Eni Algeria Ltd Sàrl

Luxembourg
(Luxembourg)

Algeria

USD

20,000

Eni Oil Holdings BV

100.00

F.C.

Eni Algeria Production
BV

Amsterdam
(Netherlands)

Algeria

EUR

20,000

Eni International BV

100.00

F.C.

Eni Ambalat Ltd

London
(United
Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni America Ltd

Dover, Delaware
(USA)

USA

USD

72,000

Eni UHL Ltd

100.00

F.C.

Eni Angola Exploration
BV

Amsterdam
(Netherlands)

Angola

EUR

20,000

Eni International BV

100.00

F.C.

Eni Angola Production
BV

Amsterdam
(Netherlands)

Angola

EUR

20,000

Eni International BV

100.00

F.C.

Eni Argentina Exploración y Explotación SA

Buenos Aires
(Argentina)

Argentina

ARS

24,136,336

Eni International BV
Eni Oil Holdings BV

95.00
5.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

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Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

% Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Eni Arguni I Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Australia BV

Amsterdam
(Netherlands)

Australia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Australia Ltd

London
(United Kingdom)

Australia

GBP

20,000,000

Eni International BV

100.00

F.C.

Eni BB Petroleum
Inc

Dover, Delaware
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni BTC Ltd

London
(United Kingdom)

United
Kingdom

GBP

34,000,000

Eni International BV

100.00

Eq.

Eni Bukat Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Bulungan BV

Amsterdam
(Netherlands)

Indonesia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Canada Holding Ltd

Calgary
(Canada)

Canada

USD

1,453,200,001

Eni International BV

100.00

F.C.

Eni CBM Ltd

London
(United Kingdom)

Indonesia

USD

2,210,728

Eni Lasmo Plc

100.00

F.C.

Eni China BV

Amsterdam
(Netherlands)

China

EUR

20,000

Eni International BV

100.00

F.C.

Eni Congo SA

Pointe - Noire
(Republic of
the Congo)

Republic of
the Congo

USD

17,000,000

Eni E&P Holding BV
Eni Int. NA NV Sàrl
Eni International BV

99.99
(—)
(—)

100.00

F.C.

Eni Côte d’Ivoire
Ltd

London
(United Kingdom)

Ivory Coast

GBP

Eni UK Ltd

100.00

F.C.

Eni Croatia BV

Amsterdam
(Netherlands)

Croatia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Cyprus Ltd

Nicosia
(Cyprus)

Cyprus

EUR

2,005

Eni International BV

100.00

F.C.

Eni Dación BV

Amsterdam
(Netherlands)

Netherlands

EUR

90,000

Eni Oil Holdings BV

100.00

Eq.

Eni Denmark BV

Amsterdam
(Netherlands)

Greenland

EUR

20,000

Eni International BV

100.00

F.C.

Eni do Brasil
Investimentos em
Exploração e
Produção de
Petróleo Ltda

Rio de Janeiro
(Brazil)

Brazil

BRL

1,593,415,000

Eni International BV
Eni Oil Holdings BV

99.99
(—)

Eq.

Eni East Sepinggan Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Elgin/Franklin Ltd

London
(United Kingdom)

United
Kingdom

GBP

100

Eni UK Ltd

100.00

F.C.

Eni Energy Russia BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Engineering E&P Ltd

London
(United Kingdom)

United
Kingdom

GBP

Eni UK Ltd

100.00

F.C.

Eni Exploration & Production Holding BV

Amsterdam
(Netherlands)

Netherlands

EUR

29,832,777.12

Eni International BV

100.00

F.C.

Eni Gabon SA

Libreville
(Gabon)

Gabon

XAF

13,132,000,000

Eni International BV

100.00

F.C.

Eni Ganal Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

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Company
name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Eni Gas & Power LNG Australia BV

Amsterdam
(Netherlands)

Australia

EUR

10,000,000

Eni International BV

100.00

F.C.

Eni Ghana
Exploration and
Production Ltd

Accra
(Ghana)

Ghana

GHS

21,412,500

Eni International BV

100.00

F.C.

Eni Hewett Ltd

Aberdeen
(United Kingdom)

United Kingdom

GBP

3,036,000

Eni UK Ltd

100.00

F.C.

Eni Hydrocarbons Venezuela Ltd

London
(United Kingdom)

Venezuela

GBP

8,050,500

Eni Lasmo Plc

100.00

F.C.

Eni India Ltd

London
(United Kingdom)

India

GBP

44,000,000

Eni UK Ltd

100.00

F.C.

Eni Indonesia Ltd

London
(United Kingdom)

Indonesia

GBP

100

Eni ULX Ltd

100.00

F.C.

Eni Indonesia Ots 1 Ltd

Grand Cayman
(Cayman Islands)

Indonesia

USD

1.01

Eni Indonesia Ltd

100.00

F.C.

Eni International NA NV Sàrl

Luxembourg
(Luxembourg)

United Kingdom

USD

25,000

Eni International BV

100.00

F.C.

Eni Investments
Plc

London
(United Kingdom)

United Kingdom

GBP

750,050,000

Eni SpA
Eni UK Ltd

99.99
(—)

100.00

F.C.

Eni Iran BV

Amsterdam
(Netherlands)

Iran

EUR

20,000

Eni International BV

100.00

F.C.

Eni Iraq BV

Amsterdam
(Netherlands)

Iraq

EUR

20,000

Eni International BV

100.00

F.C.

Eni Ireland BV

Amsterdam
(Netherlands)

Ireland

EUR

20,000

Eni International BV

100.00

F.C.

Eni Isatay BV

Amsterdam
(Netherlands)

Kazakhstan

EUR

20,000

Eni International BV

100.00

F.C.

Eni JPDA 03-13 Ltd

London
(United Kingdom)

Australia

GBP

250,000

Eni International BV

100.00

F.C.

Eni JPDA
06-105 Pty Ltd

Perth
(Australia)

Australia

AUD

80,830,576

Eni International BV

100.00

F.C.

Eni JPDA 11-106 BV

Amsterdam
(Netherlands)

Australia

EUR

50,000

Eni International BV

100.00

F.C.

Eni Kenya BV

Amsterdam
(Netherlands)

Kenya

EUR

20,000

Eni International BV

100.00

F.C.

Eni Krueng Mane Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Lasmo Plc

London
(United Kingdom)

United Kingdom

GBP

337,638,724.25

Eni Investments Plc
Eni UK Ltd

99.99
(—)

100.00

F.C.

Eni Lebanon BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

Eq.

Eni Liberia BV

Amsterdam
(Netherlands)

Liberia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Liverpool
Bay Operating
Co Ltd

London
(United Kingdom)

United Kingdom

GBP

Eni UK Ltd

100.00

F.C.

Eni LNS Ltd

London
(United Kingdom)

United Kingdom

GBP

80,400,000

Eni UK Ltd

100.00

F.C.

Eni Marketing
Inc

Dover, Delaware
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni Maroc BV

Amsterdam
(Netherlands)

Morocco

EUR

20,000

Eni International BV

100.00

F.C.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-121

TABLE OF CONTENTS

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Eni México S. de
RL de CV

Lomas De
Chapultepec,
Mexico City
(Mexico)

Mexico

MXN

3,000

Eni International BV
Eni Oil Holdings BV

99.90
0.10

100.00

F.C.

Eni Middle East
BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

Eq.

Eni Middle East
Ltd

London
(United Kingdom)

United
Kingdom

GBP

Eni ULT Ltd

100.00

F.C.

Eni MOG Ltd
(in liquidation)

London
(United Kingdom)

United
Kingdom

GBP

220,711,147.50

Eni Lasmo Plc
Eni LNS Ltd

99.99
(—)

100.00

F.C.

Eni Montenegro
BV

Amsterdam
(Netherlands)

Montenegro

EUR

20,000

Eni International BV

100.00

F.C.

Eni Mozambique
Engineering Ltd

London
(United Kingdom)

United
Kingdom

GBP

Eni UK Ltd

100.00

F.C.

Eni Mozambique
LNG Holding
BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Muara Bakau BV

Amsterdam
(Netherlands)

Indonesia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Myanmar BV

Amsterdam
(Netherlands)

Myanmar

EUR

20,000

Eni International BV

100.00

F.C.

Eni Norge AS

Forus
(Norway)

Norway

NOK

278,000,000

Eni International BV

100.00

F.C.

Eni North Africa
BV

Amsterdam
(Netherlands)

Libya

EUR

20,000

Eni International BV

100.00

F.C.

Eni North Ganal
Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Oil & Gas Inc

Dover,
Delaware (USA)

USA

USD

100,800

Eni America Ltd

100.00

F.C.

Eni Oil Algeria Ltd

London
(United Kingdom)

Algeria

GBP

1,000

Eni Lasmo Plc

100.00

F.C.

Eni Oil Holdings
BV

Amsterdam
(Netherlands)

Netherlands

EUR

450,000

Eni ULX Ltd

100.00

F.C.

Eni Oman BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Pakistan Ltd

London
(United Kingdom)

Pakistan

GBP

90,087

Eni ULX Ltd

100.00

F.C.

Eni Pakistan
(M) Ltd Sàrl

Luxembourg
(Luxembourg)

Pakistan

USD

20,000

Eni Oil Holdings BV

100.00

F.C.

Eni Petroleum Co
Inc

Dover,
Delaware (USA)

USA

USD

156,600,000

Eni SpA
Eni International BV

63.86
36.14

100.00

F.C.

Eni Petroleum US Llc

Dover,
Delaware (USA)

USA

USD

1,000

Eni BB Petroleum Inc

100.00

F.C.

Eni Portugal BV

Amsterdam
(Netherlands)

Portugal

EUR

20,000

Eni International BV

100.00

F.C.

Eni Rapak Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni RD Congo SA

Kinshasa
(Democratic
Republic of the
Congo)

Democratic
Republic of the
Congo

CDF

750,000,000

Eni International BV
Eni Oil Holdings BV

99.99
(—)

Eq.

Eni Rovuma Basin BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni Mozambique
LNG H. BV

100.00

Eq.

Eni South Africa
BV

Amsterdam
(Netherlands)

Republic of
South Africa

EUR

20,000

Eni International BV

100.00

F.C.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-122

TABLE OF CONTENTS

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Eni South China Sea Ltd Sàrl

Luxembourg
(Luxembourg)

China

USD

20,000

Eni International BV

100.00

Eq.

Eni TNS Ltd

Aberdeen
(United Kingdom)

United
Kingdom

GBP

1,000

Eni UK Ltd

100.00

F.C.

Eni Trinidad and Tobago Ltd

Port of Spain
(Trinidad and
Tobago)

Trinidad and
Tobago

TTD

1,181,880

Eni International BV

100.00

F.C.

Eni Tunisia BV

Amsterdam
(Netherlands)

Tunisia

EUR

20,000

Eni International BV

100.00

F.C.

Eni Turkmenistan Ltd

Hamilton
(Bermuda)

Turkmenistan

USD

20,000

Burren En.(Berm)Ltd

100.00

F.C.

Eni UHL Ltd

London
(United Kingdom)

United
Kingdom

GBP

Eni ULT Ltd

100.00

F.C.

Eni UKCS Ltd

London
(United Kingdom)

United
Kingdom

GBP

100

Eni UK Ltd

100.00

F.C.

Eni UK Holding Plc

London
(United Kingdom)

United
Kingdom

GBP

424,050,000

Eni Lasmo Plc
Eni UK Ltd

99.99
(—)

100.00

F.C.

Eni UK Ltd

London
(United Kingdom)

United
Kingdom

GBP

250,000,000

Eni International BV

100.00

F.C.

Eni Ukraine Holdings BV

Amsterdam
(Netherlands)

Netherlands

EUR

20,000

Eni International BV

100.00

F.C.

Eni Ukraine Llc

Kiev
(Ukraine)

Ukraine

UAH

42,004,757.64

Eni Ukraine Hold.BV
Eni International BV

99.99
0.01

100.00

F.C.

Eni Ukraine
Shallow Waters BV

Amsterdam
(Netherlands)

Ukraine

EUR

20,000

Eni Ukraine Hold.BV

100.00

Eq.

Eni ULT Ltd

London
(United Kingdom)

United
Kingdom

GBP

93,215,492.25

Eni Lasmo Plc

100.00

F.C.

Eni ULX Ltd

London
(United Kingdom)

United
Kingdom

GBP

200,010,000

Eni ULT Ltd

100.00

F.C.

Eni USA Gas Marketing Llc

Dover, Delaware
(USA)

USA

USD

10,000

Eni Marketing Inc

100.00

F.C.

Eni USA Inc

Dover, Delaware
(USA)

USA

USD

1,000

Eni Oil & Gas Inc

100.00

F.C.

Eni US Operating Co Inc

Dover, Delaware
(USA)

USA

USD

1,000

Eni Petroleum Co Inc

100.00

F.C.

Eni Venezuela BV

Amsterdam
(Netherlands)

Venezuela

EUR

20,000

Eni Venezuela
E&P Holding

100.00

F.C.

Eni Venezuela E&P
Holding SA

Bruxelles
(Belgium)

Belgium

USD

963,800,000

Eni International BV
Eni Oil Holdings BV

99.99
(—)

100.00

F.C.

Eni Ventures Plc
(in liquidation)

London
(United Kingdom)

United
Kingdom

GBP

278,050,000

Eni International BV
Eni Oil Holdings BV

99.99
(—)

Co.

Eni Vietnam BV

Amsterdam
(Netherlands)

Vietnam

EUR

20,000

Eni International BV

100.00

F.C.

Eni West Timor Ltd

London
(United Kingdom)

Indonesia

GBP

Eni Indonesia Ltd

100.00

F.C.

Eni Yemen Ltd

London
(United Kingdom)

United
Kingdom

GBP

1,000

Burren Energy Plc

100.00

Eq.

EniProgetti Egypt
Ltd
(former Tecnomare
Egypt Ltd)

Cairo
(Egypt)

Egypt

EGP

50,000

EniProgetti SpA
Eni SpA

99.00
1.00

Eq.

Eurl Eni Algérie

Algiers
(Algeria)

Algeria

DZD

1,000,000

Eni Algeria Ltd Sàrl

100.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-123

TABLE OF CONTENTS

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

First Calgary Petroleums LP

Wilmington
(USA)

Algeria

USD

Eni Canada Hold. Ltd
FCP Partner Co ULC

99.99
0.01

100.00

F.C.

First Calgary Petroleums Partner Co ULC

Calgary
(Canada)

Canada

CAD

Eni Canada Hold. Ltd

100.00

F.C.

Ieoc Exploration BV

Amsterdam
(Netherlands)

Egypt

EUR

20,000

Eni International BV

100.00

F.C.

Ieoc Production BV

Amsterdam
(Netherlands)

Egypt

EUR

20,000

Eni International BV

100.00

F.C.

Lasmo Sanga Sanga Ltd

Hamilton
(Bermuda)

Indonesia

USD

12,000

Eni Lasmo Plc

100.00

F.C.

Liverpool Bay Ltd

London
(United
Kingdom)

United
Kingdom

USD

Eni ULX Ltd

100.00

F.C.

Nigerian Agip CPFA Ltd

Lagos
(Nigeria)

Nigeria

NGN

1,262,500

NAOC Ltd
Agip En Nat Res.Ltd
Nigerian Agip E. Ltd

98.02
0.99
0.99

Co.

Nigerian Agip
Exploration Ltd

Abuja
(Nigeria)

Nigeria

NGN

5,000,000

Eni International BV
Eni Oil Holdings BV

99.99
0.01

100.00

F.C.

Nigerian Agip Oil Co Ltd

Abuja
(Nigeria)

Nigeria

NGN

1,800,000

Eni International BV
Eni Oil Holdings BV

99.89
0.11

100.00

F.C.

OOO ‘Eni Energhia’

Moscow
(Russia)

Russia

RUB

2,000,000

Eni Energy Russia BV
Eni Oil Holdings BV

99.90
0.10

100.00

F.C.

Zetah Congo Ltd

Nassau
(Bahamas)

Republic of
the Congo

USD

300

Eni Congo SA
Burren En.Congo Ltd

66.67
33.33

Co.

Zetah Kouilou Ltd

Nassau
(Bahamas)

Republic of
the Congo

USD

2,000

Eni Congo SA
Burren En.Congo Ltd
Third parties

54.50
37.00
8.50

Co.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-124

TABLE OF CONTENTS

Gas & Power

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Eni gas e luce SpA

San Donato
Milanese (MI)

Italy

EUR

750,000,000

Eni SpA

100.00

F.C.

Eni Gas Transport Services Srl

San Donato
Milanese (MI)

Italy

EUR

120,000

Eni SpA

100.00

Co.

Eni Trading & Shipping SpA

Rome

Italy

EUR

60,036,650

Eni SpA

100.00

F.C.

EniPower Mantova SpA

San Donato
Milanese (MI)

Italy

EUR

144,000,000

EniPower SpA
Third parties

86.50
13.50

86.50

F.C.

EniPower SpA

San Donato
Milanese (MI)

Italy

EUR

944,947,849

Eni SpA

100.00

F.C.

LNG Shipping SpA

San Donato
Milanese (MI)

Italy

EUR

240,900,000

Eni SpA

100.00

F.C.

Trans Tunisian Pipeline Co SpA

San Donato
Milanese (MI)

Tunisia

EUR

1,098,000

Eni SpA

100.00

F.C.

Outside Italy

Adriaplin Podjetje za
distribucijo
zemeljskega plina doo
Ljubljana

Ljubljana
(Slovenia)

Slovenia

EUR

12,956,935

Eni gas e luce SpA
Third parties

51.00
49.00

51.00

F.C.

Eni G&P Trading BV

Amsterdam
(Netherlands)

Turkey

EUR

70,000

Eni International BV

100.00

F.C.

Eni Gas & Power France SA

Levallois Perret
(France)

France

EUR

29,937,600

Eni gas e luce SpA
Third parties

99.87
0.13

99.87

F.C.

Eni Trading & Shipping Inc

Dover, Delaware
(USA)

USA

USD

36,000,000

ETS SpA

100.00

F.C.

Société de Service du
Gazoduc Transtunisien
SA - Sergaz SA

Tunisi
(Tunisia)

Tunisia

TND

99,000

Eni International BV
Third parties

66.67
33.33

66.67

F.C.

Société pour la
Construction du
Gazoduc Transtunisien
SA - Scogat SA

Tunisi
(Tunisia)

Tunisia

TND

200,000

Eni International BV
Eni SpA
LNG Shipping SpA
Trans Tunis.P.Co SpA

99.85
0.05
0.05
0.05

100.00

F.C.

Tigáz-Dso Földgázelosztó kft

Hajdúszoboszló
(Hungary)

Hungary

HUF

31,033,000,000

Tigáz Zrt

100.00

98.99

F.C.

Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság

Hajdúszoboszló
(Hungary)

Hungary

HUF

8,486,070,500

Eni SpA
Third parties

98.99
1.01

98.99

F.C.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-125

TABLE OF CONTENTS

Refining & Marketing and Chemical

Refining & Marketing

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Consorzio AgipGas Sabina
(in liquidation)

Cittaducale (RI)

Italy

EUR

5,160

Eni Fuel SpA

100.00

Co.

Ecofuel SpA

San Donato
Milanese (MI)

Italy

EUR

52,000,000

Eni SpA

100.00

F.C.

Eni Fuel SpA

Rome

Italy

EUR

58,944,310

Eni SpA

100.00

F.C.

Raffineria di Gela SpA

Gela (CL)

Italy

EUR

15,000,000

Eni SpA

100.00

F.C.

Servizi Fondo Bombole
Metano SpA

Rome

Italy

EUR

13,580,000.20

Eni SpA

100.00

Co.

Outside Italy

Eni Austria GmbH

Wien
(Austria)

Austria

EUR

78,500,000

Eni International BV
Eni Deutsch.GmbH

75.00
25.00

100.00

F.C.

Eni Benelux BV

Rotterdam
(Netherlands)

Netherlands

EUR

1,934,040

Eni International BV

100.00

F.C.

Eni Deutschland GmbH

Munich
(Germany)

Germany

EUR

90,000,000

Eni International BV
Eni Oil Holdings BV

89.00
11.00

100.00

F.C.

Eni Ecuador SA

Quito
(Ecuador)

Ecuador

USD

103,142.08

Eni International BV
Esain SA

99.93
0.07

100.00

F.C.

Eni France Sàrl

Lyon
(France)

France

EUR

56,800,000

Eni International BV

100.00

F.C.

Eni Iberia SLU

Alcobendas
(Spain)

Spain

EUR

17,299,100

Eni International BV

100.00

F.C.

Eni Lubricants Trading
(Shanghai) Co Ltd

Shanghai
(China)

China

EUR

5,000,000

Eni International BV

100.00

F.C.

Eni Marketing Austria
GmbH

Wien
(Austria)

Austria

EUR

19,621,665.23

Eni Mineralölh.GmbH
Eni International BV

99.99
(—)

100.00

F.C.

Eni Mineralölhandel GmbH

Wien
(Austria)

Austria

EUR

34,156,232.06

Eni Austria GmbH

100.00

F.C.

Eni Schmiertechnik GmbH

Wurzburg
(Germany)

Germany

EUR

2,000,000

Eni Deutsch.GmbH

100.00

F.C.

Eni Suisse SA

Lausanne
(Switzerland)

Switzerland

CHF

102,500,000

Eni International BV

100.00

F.C.

Eni USA R&M Co Inc

Wilmington
(USA)

USA

USD

11,000,000

Eni International BV

100.00

F.C.

Esacontrol SA

Quito
(Ecuador)

Ecuador

USD

60,000

Eni Ecuador SA
Third parties

87.00
13.00

Eq.

Esain SA

Quito
(Ecuador)

Ecuador

USD

30,000

Eni Ecuador SA
Tecnoesa SA

99.99
(—)

100.00

F.C.

Oléoduc du Rhône SA

Valais
(Switzerland)

Switzerland

CHF

7,000,000

Eni International BV

100.00

Eq.

OOO “Eni-Nefto”

Moscow
(Russia)

Russia

RUB

1,010,000

Eni International BV
Eni Oil Holdings BV

99.01
0.99

Eq.

Tecnoesa SA

Quito
(Ecuador)

Ecuador

USD

36,000

Eni Ecuador SA
Esain SA

99.99
(—)

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-126

TABLE OF CONTENTS

Chemical

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Versalis SpA

San Donato
Milanese (MI)

Italy

EUR

1,364,790,000

Eni SpA

100.00

F.C.

In Italy

Consorzio Industriale Gas Naturale (in liquidation)

San Donato
Milanese (MI)

Italy

EUR

124,000

Versalis SpA
Raff. di Gela SpA
Eni SpA
Syndial SpA
Raff. Milazzo ScpA

53.55
18.74
15.37
0.76
11.58

Eq.

Outside Italy

Dunastyr Polisztirolgyártó Zártkörûen Mûködõ Részvénytársaság

Budapest
(Hungary)

Hungary

HUF

8,092,160,000

Versalis SpA
Versalis Deutsc.GmbH
Versalis Int.SA

96.34
1.83
1.83

100.00

F.C.

Eni Chemicals
Trading (Shanghai)
Co Ltd
(in liquidation)

Shanghai
(China)

China

USD

5,000,000

Versalis SpA

100.00

Eq.

Versalis Americas Inc

Dover, Delaware
(USA)

USA

USD

100,000

Versalis International
SA

100.00

F.C.

Versalis Congo Sarlu

Pointe-Noire
(Republic of
the Congo)

Republic of
the Congo

CDF

1,000,000

Versalis International
SA

100.00

Eq.

Versalis
Deutschland GmbH

Eschborn
(Germany)

Germany

EUR

100,000

Versalis SpA

100.00

F.C.

Versalis France SAS

Mardyck
(France)

France

EUR

126,115,582.90

Versalis SpA

100.00

F.C.

Versalis International SA

Bruxelles
(Belgium)

Belgium

EUR

15,449,173.88

Versalis SpA
Versalis Deutsc.GmbH
Dunastyr Zrt
Versalis France

59.00
23.71
14.43
2.86

100.00

F.C.

Versalis Kimya Ticaret Limited Sirketi

Istanbul
(Turkey)

Turkey

TRY

20,000

Versalis Int.SA

100.00

Eq.

Versalis Pacific
(India) Private Ltd

Mumbai
(India)

India

INR

238,700

Versalis Pacific
Trading
Third parties

99.99

(—)

Eq.

Versalis Pacific
Trading (Shanghai)
Co Ltd

Shanghai
(China)

China

CNY

1,000,000

Versalis SpA

100.00

F.C.

Versalis Singapore
Pte Ltd

Singapore
(Singapore)

Singapore

SGD

80,000

Versalis SpA

100.00

Eq.

Versalis UK Ltd

London
(United Kingdom)

United
Kingdom

GBP

4,004,042

Versalis SpA

100.00

F.C.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-127

TABLE OF CONTENTS

Corporate and other activities

Corporate and financial companies

Company name

Registered office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

Agenzia Giornalistica
Italia SpA

Rome

Italy

EUR

2,000,000

Eni SpA

100.00

F.C.

Eni Adfin SpA

Rome

Italy

EUR

85,537,498.80

Eni SpA
Third parties

99.67
0.33

99.67

F.C.

Eni Corporate University SpA

San Donato
Milanese (MI)

Italy

EUR

3,360,000

Eni SpA

100.00

F.C.

EniServizi SpA

San Donato
Milanese (MI)

Italy

EUR

13,427,419.08

Eni SpA

100.00

F.C.

Serfactoring SpA

San Donato
Milanese (MI)

Italy

EUR

5,160,000

Eni SpA
Third parties

49.00
51.00

49.00

F.C.

Servizi Aerei SpA

San Donato
Milanese (MI)

Italy

EUR

79,817,238

Eni SpA

100.00

F.C.

Outside Italy

Banque Eni SA

Bruxelles
(Belgium)

Belgium

EUR

50,000,000

Eni International BV
Eni Oil Holdings BV

99.90
0.10

100.00

F.C.

Eni Finance International SA

Bruxelles
(Belgium)

Belgium

USD

2,474,225,632

Eni International BV
Eni SpA

66.39
33.61

100.00

F.C.

Eni Finance USA Inc

Dover, Delaware
(USA)

USA

USD

15,000,000

Eni Petroleum Co Inc

100.00

F.C.

Eni Insurance Designated Activity Company

Dublin
(Ireland)

Ireland

EUR

500,000,000

Eni SpA

100.00

F.C.

Eni International BV

Amsterdam
(Netherlands)

Netherlands

EUR

641,683,425

Eni SpA

100.00

F.C.

Eni International Resources Ltd

London
(United Kingdom)

United
Kingdom

GBP

50,000

Eni SpA
Eni UK Ltd

99.99
(—)

100.00

F.C.

Other Activities

Company name

Registered
office

Country
of operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

In Italy

Anic Partecipazioni SpA (in liquidation)

Gela (CL)

Italy

EUR

23,519,847.16

Syndial SpA
Third parties

99.97
0.03

Eq.

Eni Energia Srl

San Donato
Milanese (MI)

Italy

EUR

10,000

Eni SpA

100.00

Co.

Eni New Energy SpA

San Donato
Milanese (MI)

Italy

EUR

5,000,000.00

Eni SpA

100.00

F.C.

Industria Siciliana
Acido Fosforico - ISAF
- SpA (in liquidation)

Gela (CL)

Italy

EUR

1,300,000

Syndial SpA
Third parties

52.00
48.00

Eq.

Ing. Luigi Conti Vecchi
SpA

Assemini (CA)

Italy

EUR

5,518,620.64

Syndial SpA

100.00

F.C.

Syndial Servizi Ambientali SpA

San Donato
Milanese (MI)

Italy

EUR

424,818,703.05

Eni SpA
Third parties

99.99
(—)

100.00

F.C.

Outside Italy

Eni New Energy Egypt
SAE

Cairo
(Egypt)

Egypt

EGP

250,000

Eni International BV
Ieoc Exploration BV
Ieoc Production BV

99.98
0.01
0.01

Eq.

Oleodotto del Reno SA

Coira
(Switzerland)

Switzerland

CHF

1,550,000

Syndial SpA

100.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

F-128

TABLE OF CONTENTS

Joint arrangements and associates

Exploration & Production

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Mozambique Rovuma Venture SpA(†)
(former Eni East Africa SpA)

San Donato
Milanese (MI)

Mozambique

EUR

20,000,000

Eni SpA
Third parties

35.71
64.29

35.71

J.O.

Società Oleodotti Meridionali -
SOM SpA(†)

San Donato
Milanese (MI)

Italy

EUR

3,085,000

Eni SpA
Third parties

70.00
30.00

70.00

J.O.

Outside Italy

Agiba Petroleum
Co(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

50.00
50.00

Co.

Angola LNG Ltd

Hamilton
(Bermuda)

Angola

USD

10,907,000,000

Eni Angola Prod.BV
Third parties

13.60
86.40

Eq.

Ashrafi Island
Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

25.00
75.00

Co.

Barentsmorneftegaz
Sàrl(†)

Luxembourg
(Luxembourg)

Russia

USD

20,000

Eni Energy Russia BV
Third parties

33.33
66.67

Eq.

Cabo Delgado
Gas Development
Limitada(†)

Maputo
(Mozambique)

Mozambique

MZN

2,500,000

Eni Mozam.LNG H. BV
Third parties

50.00
50.00

Co.

Cardón IV
SA(†)

Caracas
(Venezuela)

Venezuela

VEF

17,210,000

Eni Venezuela BV
Third parties

50.00
50.00

Eq.

Compañia Agua
Plana SA

Caracas
(Venezuela)

Venezuela

VEF

100

Eni Venezuela BV
Third parties

26.00
74.00

Co.

Coral FLNG
SA

Maputo
(Mozambique)

Mozambique

MZN

100,000,000

Eni Mozam.LNG H. BV
Third parties

25.00
75.00

Eq.

Coral South
FLNG DMCC

Dubai
(United Arab
Emirates)

United Arab
Emirates

AED

500,000

Eni Mozam.LNG H. BV
Third parties

50.00
50.00

Eq.

East Delta
Gas Co
(in liquidation)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

37.50
62.50

Co.

East Kanayis
Petroleum Co(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

50.00
50.00

Co.

East Obaiyed
Petroleum
Company(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc SpA
Third parties

50.00
50.00

Co.

El-Fayrouz
Petroleum Co(†)
(in liquidation)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV
Third parties

50.00
50.00

Co.

El Temsah
Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

25.00
75.00

Co.

Enstar Petroleum
Ltd

Calgary
(Canada)

Canada

CAD

0.10

Unimar Llc

100.00

Fedynskmorneftegaz
Sàrl(†)

Luxembourg
(Luxembourg)

Russia

USD

20,000

Eni Energy Russia BV
Third parties

33.33
66.67

Eq.

InAgip doo(†)

Zagreb
(Croatia)

Croatia

HRK

54,000

Eni Croatia BV
Third parties

50.00
50.00

Co.

Karachaganak
Petroleum
Operating BV

Amsterdam
(Netherlands)

Kazakhstan

EUR

20,000

Agip Karachag.BV
Third parties

29.25
70.75

Co.

Karachaganak
Project Development
Ltd (KPD)

Reading,
Berkshire
(United
Kingdom)

United
Kingdom

GBP

100

Agip Karachag.BV
Third parties

38.00
62.00

Eq.

Khaleej Petroleum
Co Wll

Safat
(Kuwait)

Kuwait

KWD

250,000

Eni Middle E. Ltd
Third parties

49.00
51.00

Eq.

Liberty National
Development
Co Llc

Wilmington
(USA)

USA

USD

0(a)

Eni Oil & Gas Inc
Third parties

32.50
67.50

Eq.

Llc
‘Westgasinvest’(†)

Lviv
(Ukraine)

Ukraine

UAH

2,000,000

Eni Ukraine Hold.BV
Third parties

50.01
49.99

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(†)

Jointly controlled entity.

(a)

Shares without nominal value.

F-129

TABLE OF CONTENTS

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Mediterranean Gas Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

25.00
75.00

Co.

Mellitah Oil & Gas BV(†)

Amsterdam
(Netherlands)

Libya

EUR

20,000

Eni North Africa BV
Third parties

50.00
50.00

Co.

Nile Delta Oil Co Nidoco

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

37.50
62.50

Co.

North Bardawil Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV
Third parties

30.00
70.00

Co.

North El Burg Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc SpA
Third parties

25.00
75.00

Co.

Petrobel Belayim Petroleum Co(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

50.00
50.00

Co.

PetroBicentenario SA(†)

Caracas
(Venezuela)

Venezuela

VEF

379,000,000

Eni Lasmo Plc
Third parties

40.00
60.00

Eq.

PetroJunín SA(†)

Caracas
(Venezuela)

Venezuela

VEF

2,402,100,000

Eni Lasmo Plc
Third parties

40.00
60.00

Eq.

PetroSucre SA

Caracas
(Venezuela)

Venezuela

VEF

220,300,000

Eni Venezuela BV
Third parties

26.00
74.00

Eq.

Pharaonic Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

25.00
75.00

Co.

Port Said Petroleum Co(†)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

50.00
50.00

Co.

Raml Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

22.50
77.50

Co.

Ras Qattara Petroleum
Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

37.50
62.50

Co.

Rovuma Basin LNG Land Limitada(†)

Maputo
(Mozambique)

Mozambique

MZN

140,000

Mozamb. Rov. V. SpA
Third parties

33.33
66.67

Co.

Shatskmorneftegaz Sàrl(†)

Luxembourg
(Luxembourg)

Russia

USD

20,000

Eni Energy Russia BV
Third parties

33.33
66.67

Eq.

Shorouk Petroleum Company

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

30.00
70.00

Co.

Société Centrale Electrique
du Congo SA

Pointe-Noire
(Republic of
the Congo)

Republic of
the Congo

XAF

44,732,000,000

Eni Congo SA
Third parties

20.00
80.00

Eq.

Société Italo Tunisienne d’Exploitation Pétrolière SA(†)

Tunisi
(Tunisia)

Tunisia

TND

5,000,000

Eni Tunisia BV
Third parties

50.00
50.00

Eq.

Sodeps - Société de Developpement et d’Exploitation du Permis
du Sud SA(†)

Tunisi
(Tunisia)

Tunisia

TND

100,000

Eni Tunisia BV
Third parties

50.00
50.00

Co.

Tapco Petrol Boru
Hatti Sanayi ve Ticaret
AS(†)

Istanbul
(Turkey)

Turkey

TRY

9,850,000

Eni International BV
Third parties

50.00
50.00

Eq.

Tecninco Engineering Contractors Llp(†)

Aksai
(Kazakhstan)

Kazakhstan

KZT

29,478,455

EniProgetti SpA
Third parties

49.00
51.00

Eq.

Thekah Petroleum Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV
Third parties

25.00
75.00

Co.

Unimar Llc(†)

Houston
(USA)

USA

USD

0(a)

Eni America Ltd
Third parties

50.00
50.00

Co.

United Gas Derivatives
Co

Cairo
(Egypt)

Egypt

USD

195,000,000

Eni International BV
Third parties

33.33
66.67

Eq.

VIC CBM Ltd(†)

London
(United
Kingdom)

Indonesia

USD

1,315,912

Eni Lasmo Plc
Third parties

50.00
50.00

Eq.

Virginia Indonesia Co
CBM Ltd(†)

London
(United
Kingdom)

Indonesia

USD

631,640

Eni Lasmo Plc
Third parties

50.00
50.00

Eq.

Virginia Indonesia Co
Llc

Wilmington
(USA)

Indonesia

USD

Unimar Llc

100.00

Virginia International
Co Llc

Wilmington
(USA)

Indonesia

USD

Unimar Llc

100.00

West Ashrafi Petroleum Co(†)
(in liquidation)

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Exploration BV
Third parties

50.00
50.00

Co.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(†)

Jointly controlled entity.

(a)

Shares without nominal value.

F-130

TABLE OF CONTENTS

Gas & Power

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Mariconsult SpA(†)

Milan

Italy

EUR

120,000

Eni SpA
Third parties

50.00
50.00

Eq.

Società EniPower
Ferrara Srl(†)

San Donato
Milanese
(MI)

Italy

EUR

140,000,000

EniPower SpA
Third parties

51.00
49.00

51.00

J.O.

Transmed SpA(†)

Milan

Italy

EUR

240,000

Eni SpA
Third parties

50.00
50.00

Eq.

Outside Italy

Blue Stream Pipeline Co BV(†)

Amsterdam
(Netherlands)

Russia

USD

22,000

Eni International BV
Third parties

50.00
50.00

50.00

J.O.

Gas Distribution Company of
Thessaloniki - Thessaly SA(†)

Ampelokipi-
Menemeni
(Greece)

Greece

EUR

247,127,605

Eni gas e luce SpA
Third parties

49.00
51.00

Eq.

Gas Supply Company of Thessaloniki - Thessalia SA(†)

Thessaloniki
(Greece)

Greece

EUR

13,761,788

Eni gas e luce SpA
Third parties

49.00
51.00

Eq.

GreenStream BV(†)

Amsterdam
(Netherlands)

Libya

EUR

200,000,000

Eni North Africa BV
Third parties

50.00
50.00

50.00

J.O.

Premium Multiservices SA

Tunisi
(Tunisia)

Tunisia

TND

200,000

Sergaz SA
Third parties

49.99
50.01

Eq.

SAMCO Sagl

Lugano
(Switzerland)

Switzerland

CHF

20,000

Eni International BV
Transmed.Pip.Co Ltd
Third parties

5.00
90.00
5.00

Eq.

Transmediterranean Pipeline
Co Ltd(†)

St. Helier
(Jersey)

Jersey

USD

10,310,000

Eni SpA
Third parties

50.00
50.00

50.00

J.O.

Turul Gázvezeték Építõ es Vagyonkezelõ Részvénytársaság(†)

Tatabànya
(Hungary)

Hungary

HUF

404,000,000

Tigáz Zrt
Third parties

58.42
41.58

Eq.

Unión Fenosa Gas SA(†)

Madrid
(Spain)

Spain

EUR

32,772,000

Eni SpA
Third parties

50.00
50.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(†)

Jointly controlled entity.

F-131

TABLE OF CONTENTS

Refining & Marketing and Chemical

Refining & Marketing

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Arezzo Gas SpA(†)

Arezzo

Italy

EUR

394,000

Eni Fuel SpA
Third parties

50.00
50.00

Eq.

CePIM Centro Padano Interscambio Merci SpA

Fontevivo (PR)

Italy

EUR

6,642,928.32

Ecofuel SpA
Third parties

34.93
65.07

Eq.

Consorzio Operatori GPL
di Napoli

Napoli

Italy

EUR

102,000

Eni Fuel SpA
Third parties

25.00
75.00

Co.

Costiero Gas Livorno SpA(†)

Livorno

Italy

EUR

26,000,000

Eni Fuel SpA
Third parties

65.00
35.00

65.00

J.O.

Disma SpA

Segrate (MI)

Italy

EUR

2,600,000

Eni Fuel SpA
Third parties

25.00
75.00

Eq.

PETRA SpA(†)

Ravenna

Italy

EUR

723,100

Ecofuel SpA
Third parties

50.00
50.00

Eq.

Petroven Srl(†)

Genova

Italy

EUR

156,000

Ecofuel SpA
Third parties

68.00
32.00

68.00

J.O.

Porto Petroli di Genova SpA

Genova

Italy

EUR

2,068,000

Ecofuel SpA
Third parties

40.50
59.50

Eq.

Raffineria di Milazzo ScpA(†)

Milazzo (ME)

Italy

EUR

171,143,000

Eni SpA
Third parties

50.00
50.00

50.00

J.O.

SeaPad SpA(†)

Genova

Italy

EUR

12,400,000

Ecofuel SpA
Third parties

80.00
20.00

Eq.

Seram SpA

Fiumicino (RM)

Italy

EUR

852,000

Eni SpA
Third parties

25.00
75.00

Co.

Sigea Sistema Integrato Genova Arquata SpA

Genova

Italy

EUR

3,326,900

Ecofuel SpA
Third parties

35.00
65.00

Eq.

Termica Milazzo Srl(†)

Milazzo (ME)

Italy

EUR

100,000

Raff. Milazzo ScpA

100.00

50.00

J.O.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(†)

Jointly controlled entity.

F-132

TABLE OF CONTENTS

Refining & Marketing

Outside Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

AET -
Raffineriebeteiligungs
gesellschaft mbH(†)

Schwedt
(Germany)

Germany

EUR

27,000

Eni Deutsch.GmbH
Third parties

33.33
66.67

Eq.

Bayernoil Raffineriegesellschaft mbH(†)

Vohburg
(Germany)

Germany

EUR

10,226,000

Eni Deutsch.GmbH
Third parties

20.00
80.00

20.00

J.O.

City Carburoil SA(†)

Rivera
(Switzerland)

Switzerland

CHF

6,000,000

Eni Suisse SA
Third parties

49.91
50.09

Eq.

Egyptian International Gas Technology Co

Cairo
(Egypt)

Egypt

EGP

100,000,000

Eni International BV
Third parties

40.00
60.00

Co.

ENEOS Italsing Pte Ltd

Singapore
(Singapore)

Singapore

SGD

12,000,000

Eni International BV
Third parties

22.50
77.50

Eq.

FSH Flughafen Schwechat Hydranten-Gesellschaft OG

Wien
(Austria)

Austria

EUR

7,798,020.99

Eni Market.A.GmbH
Eni Mineralölh.GmbH
Eni Austria GmbH
Third parties

14.56
14.56
14.56
56.32

Co.

Fuelling Aviation Services
GIE

Tremblay en
France
(France)

France

EUR

Eni France Sàrl
Third parties

25.00
75.00

Co.

Mediterranée Bitumes SA

Tunisi
(Tunisia)

Tunisia

TND

1,000,000

Eni International BV
Third parties

34.00
66.00

Eq.

Routex BV

Amsterdam
(Netherlands)

Netherlands

EUR

67,500

Eni International BV
Third parties

20.00
80.00

Eq.

Saraco SA

Meyrin
(Switzerland)

Switzerland

CHF

420,000

Eni Suisse SA
Third parties

20.00
80.00

Co.

Supermetanol CA(†)

Jose Puerto
La Cruz
(Venezuela)

Venezuela

VEF

12,086,744.84

Ecofuel SpA
Supermetanol CA
Third parties

34.51(a)
30.07
35.42

50.00

J.O.

TBG Tanklager Betriebsgesellschaft GmbH(†)

Salzburg
(Austria)

Austria

EUR

43,603.70

Eni Market.A.GmbH
Third parties

50.00
50.00

Eq.

Weat Electronic Datenservice GmbH

Düsseldorf
(Germany)

Germany

EUR

409,034

Eni Deutsch.GmbH
Third parties

20.00
80.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(†)

Jointly controlled entity.

(a)

Controlling interest:

Ecofuel SpA
Third parties

50.00
50.00

F-133

TABLE OF CONTENTS

Chemical

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

% Equity
ratio

Consolidation
or valutation
method(*)

Brindisi Servizi Generali Scarl

Brindisi

Italy

EUR

1,549,060

Versalis SpA
Syndial SpA
EniPower SpA
Third parties

49.00
20.20
8.90
21.90

Eq.

IFM Ferrara ScpA

Ferrara

Italy

EUR

5,270,466

Versalis SpA
Syndial SpA
S.E.F. Srl
Third parties

19.74
11.58
10.70
57.98

Eq.

Matrìca SpA(†)

Porto Torres (SS)

Italy

EUR

37,500,000

Versalis SpA
Third parties

50.00
50.00

Eq.

Newco Tech SpA(†)

Novara

Italy

EUR

179,000

Versalis SpA
Genomatica Inc

80.00
20.00

Eq.

Novamont SpA

Novara

Italy

EUR

13,333,500

Versalis SpA
Third parties

25.00
75.00

Eq.

Priolo Servizi ScpA

Melilli (SR)

Italy

EUR

28,100,000

Versalis SpA
Syndial SpA
Third parties

33.11
4.61
62.28

Eq.

Ravenna Servizi Industriali ScpA

Ravenna

Italy

EUR

5,597,400

Versalis SpA
EniPower SpA
Ecofuel SpA
Third parties

42.13
30.37
1.85
25.65

Eq.

Servizi Porto Marghera Scarl

Porto Marghera
(VE)

Italy

EUR

8,695,718

Versalis SpA
Syndial SpA
Third parties

48.44
38.39
13.17

Eq.

Outside Italy

Lotte Versalis
Elastomers Co Ltd(†)

Yeosu
(South Korea)

South Korea

KRW

301,800,000,000

Versalis SpA
Third parties

50.00
50.00

Eq.

Versalis Zeal Ltd(†)

Takoradi
(Ghana)

Ghana

GHS

5,650,000

Versalis Intern. SA
Third parties

80.00
20.00

Eq.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(†)

Jointly controlled entity.

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Other significant investments

Exploration & Production

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

Consolidation
or valutation
method(*)

Consorzio
Universitario in
Ingegneria per
la Qualità e
l’Innovazione

Pisa

Italy

EUR

135,000

Eni SpA
Third parties

20.00
80.00

Co.

Outside Italy

Administradora del
Golfo de Paria
Este SA

Caracas
(Venezuela)

Venezuela

VEF

100

Eni Venezuela BV
Third parties

19.50
80.50

Co.

Brass LNG Ltd

Lagos
(Nigeria)

Nigeria

USD

1,000,000

Eni Int. NA NV Sàrl
Third parties

20.48
79.52

Co.

Darwin LNG Pty Ltd

West Perth
(Australia)

Australia

AUD

692,507,924.87

Eni G&P LNG Aus. BV
Third parties

10.99
89.01

Co.

New Liberty Residential Co Llc

West Trenton
(USA)

USA

USD

0(a)

Eni Oil & Gas Inc
Third parties

17.50
82.50

Co.

Nigeria LNG Ltd

Port Harcourt
(Nigeria)

Nigeria

USD

1,138,207,000

Eni Int. NA NV Sàrl
Third parties

10.40
89.60

Co.

Norsea Pipeline Ltd

Woking Surrey
(United
Kingdom)

United
Kingdom

GBP

7,614,062

Eni SpA
Third parties

10.32
89.68

Co.

North Caspian Operating Co NV

Amsterdam
(Netherlands)

Kazakhstan

EUR

128,520

Agip Caspian Sea BV
Third parties

16.81
83.19

Co.

OPCO - Sociedade Operacional Angola LNG SA

Luanda
(Angola)

Angola

AOA

7,400,000

Eni Angola Prod.BV
Third parties

13.60
86.40

Co.

Petrolera Güiria SA

Caracas
(Venezuela)

Venezuela

VEF

1,000,000

Eni Venezuela BV
Third parties

19.50
80.50

Co.

Point Fortin LNG Exports Ltd

Port of Spain
(Trinidad and
Tobago)

Trinidad and
Tobago

USD

10,000

Eni T&T Ltd
Third parties

17.31
82.69

Co.

SOMG - Sociedade de Operações
e Manutenção de Gasodutos SA

Luanda
(Angola)

Angola

AOA

7,400,000

Eni Angola Prod.BV
Third parties

13.60
86.40

Co.

Torsina Oil Co

Cairo
(Egypt)

Egypt

EGP

20,000

Ieoc Production BV
Third parties

12.50
87.50

Co.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(a)

Shares without nominal value.

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Gas & Power

Outside Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

Consolidation
or valutation
method(*)

Angola LNG Supply Services Llc

Wilmington
(USA)

USA

USD

19,278,782

Eni USA Gas M. Llc
Third parties

13.60
86.40

Co.

Norsea Gas GmbH

Emden
(Germany)

Germany

EUR

1,533,875.64

Eni International BV
Third parties

13.04
86.96

Co.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

Refining & Marketing and Chemical

Refining & Marketing

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

%
Ownership

Consolidation
or valutation
method(*)

Consorzio Nazionale per la Gestione
Raccolta e Trattamento degli Oli Minerali
Usati (former Consorzio Obbligatorio
degli Oli Usati)

Rome

Italy

EUR

36,149

Eni SpA
Third parties

12.43
87.57

Co.

Società Italiana Oleodotti di Gaeta SpA(1)

Rome

Italy

ITL

360,000,000

Eni SpA
Third parties

72.48
27.52

Co.

Outside Italy

BFS Berlin Fuelling
Services GbR

Hamburg
(Germany)

Germany

EUR

91,139

Eni Deutsch.GmbH
Third parties

12.50
87.50

Co.

Compania de Economia Mixta ‘Austrogas’

Cuenca
(Ecuador)

Ecuador

USD

3,028,749

Eni Ecuador SA
Third parties

13.31
86.69

Co.

Dépôt Pétrolier de Fos SA

Fos-Sur-Mer
(France)

France

EUR

3,954,196.40

Eni France Sàrl
Third parties

16.81
83.19

Co.

Dépôt Pétrolier de la Côte d’Azur SAS

Nanterre
(France)

France

EUR

207,500

Eni France Sàrl
Third parties

18.00
82.00

Co.

Joint Inspection Group Ltd

London
(United
Kingdom)

United
Kingdom

GBP

0(a)

Eni SpA
Third parties

12.50
87.50

Co.

S.I.P.G. Société Immobilier Pétrolier de Gestion Snc

Tremblay-En-
France
(France)

France

EUR

40,000

Eni France Sàrl
Third parties

12.50
87.50

Co.

Sistema Integrado de Gestion de Aceites Usados

Madrid
(Spain)

Spain

EUR

175,713

Eni Iberia SLU
Third parties

15.44
84.56

Co.

Tanklager - Gesellschaft Tegel (TGT) GbR

Hamburg
(Germany)

Germany

EUR

8,898

Eni Deutsch.GmbH
Third parties

12.50
87.50

Co.

TAR - Tankanlage Ruemlang AG

Ruemlang
(Switzerland)

Switzerland

CHF

3,259,500

Eni Suisse SA
Third parties

16.27
83.73

Co.

Tema Lube Oil Co Ltd

Accra
(Ghana)

Ghana

GHS

258,309

Eni International BV
Third parties

12.00
88.00

Co.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

(a)

Shares without nominal value.

(1)

Company under extraordinary administration procedure pursuant to law no. 95 of april 3, 1979. The liquidation was concluded on april 28, 2015. The cancellation has been filed and is pending the authorization by the Ministry of Economic Development.

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Corporate and other activities

Corporate and financial companies

In Italy

Company name

Registered
office

Country of
operation

Currency

Share
Capital

Shareholders

% Ownership

Consolidation
or valutation
method(*)

Emittenti Titoli SpA
(in liquidation)

Milan

Italy

EUR

4,264,000

Eni SpA
Emittenti Titoli SpA (L)
Third parties

10.00(a)
0.78
89.22

Co.

Outside Italy

OGCI Climate Investments Llp

London
(United
Kingdom)

United
Kingdom

GBP

0(b)

Eni UK Ltd
Third parties

14.29
85.71

Co.

(*)

F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value

	(a) Controlling interest:			Eni SpA Third parties			10.08 89.92
	(b) Shares without nominal value.

Information on Eni’s consolidated subsidiaries with significant non-controlling interest

In 2017 and 2016, Eni did not own any consolidated subsidiaries with a significant non-controlling interest.

The total shareholders’ equity pertaining to minority interests as of December 31, 2017, amounted to €49 million (same amount as of December 31, 2016).

Changes in the ownership interest without loss of control

In 2017 and 2016, Eni did not report any changes in ownership interest without loss or acquisition of control.

Principal joint ventures, joint operations and associates as of December 31, 2017

Company name

Registered office

Operating office

Business segment

% ownership
interest

% voting
rights

Joint venture

Gas Distribution Company of Thessaloniki - Thessaly SA

Ampelokipi-
Menemeni (Greece)

Greece

Gas & Power

49.00

Lotte Versalis Elastomers Co Ltd

Yeosu
(South Korea)

South Korea

Chemical

50.00

PetroJunín SA

Caracas
(Venezuela)

Venezuela

Exploration &
Production

40.00

Saipem SpA

San Donato Milanese
(MI) (Italy)

Italia

Other Activities

30.54

31.00

Unión Fenosa Gas SA

Madrid (Spain)

Spain

Gas & Power

50.00

Joint Operation

Blue Stream Pipeline Co BV

Amsterdam
(Netherlands)

Russia

Gas & Power

50.00

Mozambique Rovuma Venture SpA (former Eni East Africa SpA)

San Donato Milanese
(MI) (Italy)

Mozambique

Exploration &
Production

35.71

Raffineria di Milazzo ScpA

Milazzo
(ME) (Italy)

Italy

Refining &
Marketing

50.00

Associates

Angola LNG Ltd

Hamilton
(Bermuda)

Angola

Exploration & Production

13.60

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The main line items of profit and loss and balance sheet related to the principal joint ventures, represented by the amounts included in the reports accounted under IFRS of each company, are provided in the table below:


	2017
(€ million)	Saipem SpA		Unión Fenosa Gas SA		PetroJunín SA		Gas Distribution Company of Thessaloniki -Thessaly SA		Lotte Versalis Elastomeres Co		Cardón IV SA		Other joint ventures
Current assets		6,743		610		365		86		43		816		275
- of which cash and cash equivalent		1,751		32				15		30		42		64
Non-current assets		5,847		877		628		289		547		2,756		916
Total assets		12,590		1,487		993		375		590		3,572		1,191
Current liabilities		4,487		234		434		94		70		644		985
- current financial liabilities		189		40						38				640
Non-current liabilities		3,504		580		34		2		292		2,928		124
- non-current financial liabilities		2,929		506						288		1,912		79
Total liabilities		7,991		814		468		96		362		3,572		1,109
Net equity		4,599		673		525		279		228				82
Eni’s ownership interest (%)		31.00		50.00		40.00		49.00		50.00		50.00
Book value of the investment		1,413		350		210		137		114				28
Revenues and other operating income		9,038		1,340		135		54				756		412
Operating expense		(8,172)		(1,308)		(66)		(14)		(4)		(608)		(433)
Depreciation, amortization and impairments		(740)		(89)		(29)		(15)				(357)		(113)
Operating profit		126		(57)		40		25		(4)		(209)		(134)
Finance (expense) income		(223)		(38)		47						(155)		(53)
Income (expense) from investments		(9)		3										(4)
Profit before income taxes		(106)		(92)		87		25		(4)		(364)		(191)
Income taxes		(201)		1		(22)		(7)				(4)		(11)
Net profit		(307)		(91)		65		18		(4)		(368)		(202)
Other comprehensive income		49		(41)		(68)				(6)		26
Total other comprehensive income		(258)		(132)		(3)		18		(10)		(394)		(202)
Net profit attributable to Eni		(101)		(63)		26		9		(2)		(184)		(56)
Dividends received by the joint venture								12						29


	2016
(€ million)	Saipem SpA		Unión Fenosa Gas SA		PetroJunín SA		Gas Distribution Company of Thessaloniki - Thessaly SA		Lotte Versalis Elastomeres Co		Cardón IV SA		Other joint ventures
Current assets		7,783		651		336		34		12		451		197
- of which cash and cash equivalent		1,892		25		2		8		11		31		45
Non-current assets		6,500		1,037		703		285		417		3,628		469
Total assets		14,283		1,688		1,039		319		429		4,079		666
Current liabilities		5,668		232		480		13		36		455		433
- current financial liabilities		206		61										299
Non-current liabilities		3,730		650		32				245		3,230		94
- non-current financial liabilities		3,194		547						245		2,108		36
Total liabilities		9,398		882		512		13		281		3,685		527
Net equity		4,885		806		527		306		148		394		139
Eni’s ownership interest (%)		30.76		50.00		40.00		49.00		50.00		50.00
Book value of the investment		1,497		434		211		150		74		197		72
Revenues and other operating income		10,009		905		105		152				738		275
Operating expense		(9,100)		(921)		(60)		(98)		(1)		(233)		(279)
Other operating profit (loss)														(5)
Depreciation, amortization and impairments		(2,408)		(131)		(40)		(22)				(87)		(169)
Operating profit		(1,499)		(147)		5		32		(1)		418		(178)
Finance (expense) income		(154)		31		94				1		(206)		(20)
Income (expense) from investments		18		13
Profit before income taxes		(1,635)		(103)		99		32				212		(198)
Income taxes		(445)		23		(24)		(12)				(252)		(20)
Net profit		(2,080)		(80)		75		20				(40)		(218)
Other comprehensive income		48		29		18						12		(2)
Total other comprehensive income		(2,032)		(51)		93		20				(28)		(220)
Net profit attributable to Eni		(144)		(82)		30		10				(20)		(125)
Dividends received by the joint venture								10						35

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	2016
(€ million)	Angola LNG Ltd		United Gas Derivatives Co		Other associates
Current assets		507		253		1,338
- of which cash and cash equivalent		339		146		32
Non-current assets		8,376		140		569
Total assets		8,883		393		1,907
Current liabilities		284		41		1,232
- current financial liabilities						25
Non-current liabilities		1,863		1		270
- non-current financial liabilities		1,699				78
Total liabilities		2,147		42		1,502
Net equity		6,736		351		405
Eni’s ownership interest (%)		13.60		33.33
Book value of the investment		916		117		167
Revenues and other operating income		84		102		1,239
Operating expense		(281)		(61)		(1,051)
Other operating profit (loss)						(2)
Depreciation, depletion, amortization and impairments		(188)		(13)		(625)
Operating profit		(385)		28		(439)
Finance (expense) income		(70)		11		224
Profit before income taxes		(455)		39		(215)
Income taxes				5		(108)
Net profit		(455)		44		(323)
Other comprehensive income		200		11		(7)
Total other comprehensive income		(255)		55		(330)
Net profit attributable to Eni		(62)		14		(88)
Dividends received by the associate				14		39

49 Significant non-recurring events and operations

In 2017, in 2016 and 2015, Eni did not report any non-recurring events and operations.

50 Positions or transactions deriving from atypical and/or unusual operations

In 2017, 2016 and 2015 no transactions deriving from atypical and/or unusual operations were reported.

51 Subsequent events

No significant events were reported after December 31, 2017.

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Supplemental oil and gas information (unaudited)

The following information pursuant to “International Financial Reporting Standards” (IFRS) is presented in accordance with FASB Extractive Activities — Oil & Gas (Topic 932). Amounts related to minority interests are not significant.

Capitalized costs

Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization. Capitalized costs by geographical area consist of the following:

(€ million)
2017	Italy		Rest of Europe		North Africa		Egypt		Sub- Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Proved property		16,277		17,600		12,514		15,211		36,976		10,547		12,493		14,840		1,950		138,408
Unproved property		18		356		471		32		2,157		3		1,023		785		185		5,030
Support equipment and facilities		359		39		1,436		191		1,212		101		34		46		14		3,432
Incomplete wells and other		681		345		2,050		1,297		2,679		1,417		421		280		124		9,294
Gross Capitalized Costs		17,335		18,340		16,471		16,731		43,024		12,068		13,971		15,951		2,273		156,164
Accumulated depreciation, depletion and amortization		(13,504)		(12,014)		(10,640)		(10,413)		(25,920)		(1,690)		(10,386)		(12,534)		(1,188)		(98,289)
Net Capitalized Costs consolidated subsidiaries(a)		3,831		6,326		5,831		6,318		17,104		10,378		3,585		3,417		1,085		57,875
Equity-accounted entities
Proved property						67				1,419				581		1,833				3,900
Unproved property				4										85						89
Support equipment and facilities						7										6				13
Incomplete wells and other				1		6				4				93		225				329
Gross Capitalized Costs				5		80				1,423				759		2,064				4,331
Accumulated depreciation, depletion and amortization						(61)				(475)				(611)		(785)				(1,932)
Net Capitalized Costs equity-accounted entities(a)				5		19				948				148		1,279				2,399
2016
Consolidated subsidiaries
Proved property		15,951		18,678		13,492		15,262		38,539		10,790		11,680		17,127		2,085		143,604
Unproved property		18		301		416		55		2,461		1		1,155		903		210		5,520
Support equipment and facilities		357		42		1,627		203		1,375		111		37		77		15		3,844
Incomplete wells and other		724		242		2,347		1,828		5,117		2,565		2,248		317		134		15,522
Gross Capitalized Costs		17,050		19,263		17,882		17,348		47,492		13,467		15,120		18,424		2,444		168,490
Accumulated depreciation, depletion and amortization		(13,022)		(12,113)		(11,374)		(11,022)		(27,264)		(1,608)		(11,000)		(14,301)		(1,227)		(102,931)
Net Capitalized Costs consolidated subsidiaries(a)		4,028		7,150		6,508		6,326		20,228		11,859		4,120		4,123		1,217		65,559
Equity-accounted entities
Proved property				2		82				14				657		2,037				2,792
Unproved property				15										96						111
Support equipment and facilities						8										7				15
Incomplete wells and other				9		5				1,596				24		253				1,887
Gross Capitalized Costs				26		95				1,610				777		2,297				4,805
Accumulated depreciation, depletion and amortization				(20)		(72)				(482)				(682)		(602)				(1,858)
Net Capitalized Costs equity-accounted entities(a)				6		23				1,128				95		1,695				2,947

(a)

The amounts include net capitalized financial charges totalling €969 million in 2017 and €1,090 million in 2016 for the consolidates subsidiaries and €78 million in 2017 and €95 million in 2016 for equity-accounted entities.

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Costs incurred

Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:

(€ million)
2017	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Proved property acquisitions										5										5
Unproved property acquisitions
Exploration		31		242		77		110		65		3		76		106		5		715
Development(a)		251		364		785		3,041		1,939		246		714		292		14		7,646
Total costs incurred consolidated subsidiaries		282		606		862		3,151		2,009		249		790		398		19		8,366
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration				1										90						91
Development(b)						2				9				4		48				63
Total costs incurred equity-accounted entities				1		2				9				94		48				154
2016
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions								2												2
Exploration		27		51		58		306		70				80		26		3		621
Development(a)		387		437		694		1,752		2,019		651		1,232		(5)		1		7,168
Total costs incurred consolidated subsidiaries		414		488		752		2,060		2,089		651		1,312		21		4		7,791
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration				1										13						14
Development(b)						1				28				12		95				136
Total costs incurred equity-accounted entities				1		1				28				25		95				150
2015
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration		28		176		289				196				71		54		6		820
Development(a)		207		1,006		1,574				2,957		819		1,332		745		18		8,658
Total costs incurred consolidated subsidiaries		235		1,182		1,863				3,153		819		1,403		799		24		9,478
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration				1										14		1				16
Development(b)				1		1				112				35		554				703
Total costs incurred equity-accounted entities				2		1				112				49		555				719

(a)

Includes the abandonment costs of the assets for €355 million in 2017, negative for €665 million in 2016 and negative for €817 million in 2015.

(b)

Includes the abandonment costs of the assets negative for €23 million in 2017, negative for €15 million in 2016 and costs for €54 million in 2015.

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Results of operations from oil and gas producing activities

Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to meet Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production. Results of operations from oil and gas producing activities by geographical area consist of the following:

2017	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Revenues:
- sales to consolidated entities		1,619		1,897		1,056				3,888		681		911		932		3		10,987
- sales to third parties				481		3,184		2,128		547		713		291		96		168		7,608
Total revenues		1,619		2,378		4,240		2,128		4,435		1,394		1,202		1,028		171		18,595
Operations costs		(337)		(687)		(504)		(314)		(986)		(396)		(206)		(312)		(48)		(3,790)
Production taxes		(130)				(200)				(331)				(11)				(5)		(677)
Exploration expenses		(26)		(122)		(22)		(191)		(60)				(61)		(39)		(4)		(525)
D.D. & A. and Provision for abandonment(a)		(465)		(838)		(679)		(767)		(2,063)		(289)		(765)		(577)		(59)		(6,502)
Other income (expenses)		1,563		(141)		(162)		690		(716)		(221)		(84)		(342)		2		589
Pretax income from producing activities		2,224		590		2,673		1,546		279		488		75		(242)		57		7,690
Income taxes		(299)		(216)		(1,978)		(214)		(38)		(223)		(67)		(38)		(23)		(3,096)
Results of operations from E&P activities of consolidated subsidiaries		1,925		374		695		1,332		241		265		8		(280)		34		4,594
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties						14				129				22		517				682
Total revenues						14				129				22		517				682
Operations costs						(8)				(37)				(9)		(40)				(94)
Production taxes						(2)				(8)						(146)				(156)
Exploration expenses				(1)										(13)						(14)
D.D. & A. and Provision for abandonment						(1)				(54)				(13)		(271)				(339)
Other income (expenses)				(2)		(2)				26				3		(199)				(174)
Pretax income from producing activities				(3)		1				56				(10)		(139)				(95)
Income taxes						(1)								(4)		(20)				(25)
Results of operations from E&P activities of equity-accounted entities				(3)						56				(14)		(159)				(120)

(a)

Includes asset net reversal amounting to €158 million

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2016	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Revenues:
- sales to consolidated entities		1,217		1,673		932		9		3,178		252		1,027		833		4		9,125
- sales to third parties				432		2,841		1,471		485		606		114		102		165		6,216
Total revenues		1,217		2,105		3,773		1,480		3,663		858		1,141		935		169		15,341
Operations costs		(311)		(599)		(451)		(356)		(968)		(269)		(215)		(325)		(49)		(3,543)
Production taxes		(96)				(176)				(282)				(17)				(5)		(576)
Exploration expenses		(35)		(40)		(45)		(42)		(142)				(39)		(28)		(3)		(374)
D.D. & A. and Provision for abandonment(a)		(923)		(943)		(675)		(691)		(1,093)		(129)		(952)		(480)		(67)		(5,953)
Other income (expenses)		(342)		(232)		(201)		(265)		(917)		(57)		(130)		(120)		(8)		(2,272)
Pretax income from producing activities		(490)		291		2,225		126		261		403		(212)		(18)		37		2,623
Income taxes		159		(1)		(1,618)		(89)		97		(139)		32		(9)		(9)		(1,577)
Results of operations from E&P activities of consolidated subsidiaries		(331)		290		607		37		358		264		(180)		(27)		28		1,046
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties						15								36		493				544
Total revenues						15								36		493				544
Operations costs						(9)								(10)		(54)				(73)
Production taxes						(3)										(121)				(124)
Exploration expenses														(13)						(13)
D.D. & A. and Provision for abandonment						(1)				(26)				(32)		(240)				(299)
Other income (expenses)				(3)		(1)				(26)				(16)		(25)				(71)
Pretax income from producing activities				(3)		1				(52)				(35)		53				(36)
Income taxes						(2)								(6)		(162)				(170)
Results of operations from E&P activities of equity-accounted entities				(3)		(1)				(52)				(41)		(109)				(206)

(a)

Includes asset net reversal amounting to €700 million

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2015 (€ million)	Italy		Rest of Europe		North Africa		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Revenues:
- sales to consolidated entities		2,124		1,828		1,403		3,514		231		628		1,118		29		10,875
- sales to third parties				501		5,681		914		659		854		131		226		8,966
Total revenues		2,124		2,329		7,084		4,428		890		1,482		1,249		255		19,841
Operations costs		(403)		(642)		(948)		(1,099)		(239)		(235)		(453)		(108)		(4,127)
Production taxes		(184)				(240)		(405)				(30)				(9)		(868)
Exploration expenses		(35)		(205)		(164)		(216)				(210)		(35)		(6)		(871)
D.D. & A. and Provision for abandonment(a)		(750)		(2,022)		(2,938)		(3,835)		(109)		(1,491)		(1,775)		(111)		(13,031)
Other income (expenses)		(215)		(142)		(564)		(290)		(156)		(282)		(9)		(23)		(1,681)
Pretax income from producing activities		537		(682)		2,230		(1,417)		386		(766)		(1,023)		(2)		(737)
Income taxes		(182)		589		(2,148)		272		(142)		90		406		(25)		(1,140)
Results of operations from E&P activities of consolidated subsidiaries		355		(93)		82		(1,145)		244		(676)		(617)		(27)		(1,877)
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties						19						68		248				335
Total revenues						19						68		248				335
Operations costs						(9)						(13)		(49)				(71)
Production taxes						(3)								(82)				(85)
Exploration expenses												(16)						(16)
D.D. & A. and Provision for abandonment				(1)		(3)		(432)				(77)		(78)				(591)
Other income (expenses)				(3)		(1)		(35)				(6)		(48)				(93)
Pretax income from producing activities				(4)		3		(467)				(44)		(9)				(521)
Income taxes						(3)						8		(29)				(24)
Results of operations from E&P activities of equity-accounted entities				(4)				(467)				(36)		(38)				(545)

(a)

Includes asset impairments amounting to €5,051 million

Oil and natural gas reserves

Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities — Oil & Gas (Topic 932).

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 un-weighted 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.

In 2017, the average price for the marker Brent crude oil was $54 per barrel.

Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. 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

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required equipment is relatively minor compared to the cost of a new well. 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.

Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation26 of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserves audit is included in the third party audit report27.

In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current costs of operation and development, sale 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 and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided.

In 2017, Ryder Scott Company and DeGolyer and MacNaughton27 provided an independent evaluation of about 29% of Eni’s total proved reserves as of December 31, 201728, confirming, as in previous years, the reasonableness of Eni’s internal evaluations.

In the three years period from 2015 to 2017, 96% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2017, the principal property not subjected to independent evaluation in the last three years was Blacktip (Australia).

Eni operates under production sharing agreements in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 60%, 59% and 52% of total proved reserves as of December 31, 2017, 2016 and 2015, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service and “buy-back” contracts; proved reserves associated with such contracts represented 4%, 5% and 5% of total proved reserves on an oil-equivalent basis as of December 31, 2017, 2016 and 2015, respectively.

Oil and gas reserves quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserves volumes associated with oil and gas deriving from such obligation represent 1.6%, 1.8% and 0.6% of total proved reserves as of December 31, 2017, 2016 and 2015, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption; (iii) the quantities of hydrocarbons related to the Angola LNG plant.

Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced.

From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott.

The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2017.

Including reserves of equity-accounted entities.

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The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2017, 2016 and 2015.

Crude oil (Including Condensate and Natural Gas Liquids)

(million barrels)
2017	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Reserves at December 31, 2016		176		264		454		281		809		767		307		163		9		3,230
of which: developed		132		228		287		205		507		556		124		143		8		2,190
undeveloped		44		36		167		76		302		211		183		20		1		1,040
Purchase of Minerals in Place										2										2
Revisions of Previous Estimates		59		29		73		21		31		29		(69)		19		(1)		191
Improved Recovery				1		6		7						9						23
Extensions and Discoveries				103		1				18				4		3				129
Production		(20)		(37)		(58)		(26)		(90)		(30)		(19)		(23)		(1)		(304)
Sales of Minerals in Place								(3)		(6)										(9)
Reserves at December 31, 2017		215		360		476		280		764		766		232		162		7		3,262
Equity-accounted entities
Reserves at December 31, 2016						13				15						140				168
of which: developed						13				8						22				43
undeveloped										7						118				125
Purchase of Minerals in Place
Revisions of Previous Estimates										(2)						1				(1)
Improved Recovery
Extensions and Discoveries
Production						(1)				(1)						(5)				(7)
Sales of Minerals in Place
Reserves at December 31, 2017						12				12						136				160
Reserves at December 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
consolidated subsidiaries		169		219		306		203		546		547		81		144		5		2,220
equity-accounted entities						12				6						25				43
Undeveloped		46		141		170		77		224		219		151		129		2		1,159
consolidated subsidiaries		46		141		170		77		218		219		151		18		2		1,042
equity-accounted entities										6						111				117

2016	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Reserves at December 31, 2015		228		305		494		327		787		771		262		189		9		3,372
of which: developed		171		237		312		230		511		355		126		149		9		2,100
undeveloped		57		68		182		97		276		416		136		40				1,272
Purchase of Minerals in Place
Revisions of Previous Estimates		(35)		(4)		19		(26)		113		20		73		(1)		1		160
Improved Recovery				1		1														2
Extensions and Discoveries				2		1		8												11
Production		(17)		(40)		(61)		(28)		(91)		(24)		(28)		(25)		(1)		(315)
Sales of Minerals in Place
Reserves at December 31, 2016		176		264		454		281		809		767		307		163		9		3,230
Equity-accounted entities
Reserves at December 31, 2015						13				16						158				187
of which: developed						13				6						29				48
undeveloped										10						129				139
Purchase of Minerals in Place
Revisions of Previous Estimates						1				(1)						(13)				(13)
Improved Recovery
Extensions and Discoveries
Production						(1)										(5)				(6)
Sales of Minerals in Place
Reserves at December 31, 2016						13				15						140				168
Reserves at December 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
consolidated subsidiaries		132		228		287		205		507		556		124		143		8		2,190
equity-accounted entities						13				8						22				43
Undeveloped		44		36		167		76		309		211		183		138		1		1,165
consolidated subsidiaries		44		36		167		76		302		211		183		20		1		1,040
equity-accounted entities										7						118				125

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Crude oil (Including Condensate and Natural Gas Liquids) continued

(million barrels)
2015	Italy		Rest of Europe		North Africa		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Reserves at December 31, 2014		243		331		776		739		697		131		147		13		3,077
of which: developed		184		174		521		470		306		64		116		12		1,847
undeveloped		59		157		255		269		391		67		31		1		1,230
Purchase of Minerals in Place
Revisions of Previous Estimates		10		5		139		143		94		159		64		(2)		612
Improved Recovery						2												2
Extensions and Discoveries						2		14						6				22
Production		(25)		(31)		(98)		(93)		(20)		(28)		(28)		(2)		(325)
Sales of Minerals in Place								(16)										(16)
Reserves at December 31, 2015		228		305		821		787		771		262		189		9		3,372
Equity-accounted entities
Reserves at December 31, 2014						14		17				1		117				149
of which: developed						13		7						26				46
undeveloped						1		10				1		91				103
Purchase of Minerals in Place
Revisions of Previous Estimates								(1)						45				44
Improved Recovery
Extensions and Discoveries
Production						(1)						(1)		(4)				(6)
Sales of Minerals in Place
Reserves at December 31, 2015						13		16						158				187
Reserves at December 31, 2015		228		305		834		803		771		262		347		9		3,559
Developed		171		237		555		517		355		126		178		9		2,148
consolidated subsidiaries		171		237		542		511		355		126		149		9		2,100
equity-accounted entities						13		6						29				48
Undeveloped		57		68		279		286		416		136		169				1,411
consolidated subsidiaries		57		68		279		276		416		136		40				1,272
equity-accounted entities								10						129				139

Natural Gas(a)

(billion cubic feet)
2017	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Reserves at December 31, 2016		977		878		3,738		5,520		2,767		2,485		1,003		353		741		18,462
of which: 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
Purchase of Minerals in Place										1										1
Revisions of Previous Estimates		315		163		66		969		134		(281)		188		(61)		6		1,499
Improved Recovery						(19)														(19)
Extensions and Discoveries				29				64		1,839						4				1,936
Production		(161)		(174)		(640)		(315)		(162)		(96)		(126)		(71)		(38)		(1,783)
Sales of Minerals in Place								(1,887)		(919)										(2,806)
Reserves at December 31, 2017		1,131		896		3,145		4,351		3,660		2,108		1,065		225		709		17,290
Equity-accounted entities
Reserves at December 31, 2016						15				368				4		3,484				3,871
of which: developed						15				104				4		1,782				1,905
undeveloped										264						1,702				1,966
Purchase of Minerals in Place
Revisions of Previous Estimates										13						(1,565)				(1,552)
Improved Recovery
Extensions and Discoveries
Production						(1)				(32)				(4)		(100)				(137)
Sales of Minerals in Place
Reserves at December 31, 2017						14				349						1,819				2,182
Reserves at December 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
consolidated subsidiaries		987		771		1,233		1,421		1,693		1,878		862		171		519		9,535
equity-accounted entities						14				83						1,819				1,916
Undeveloped		144		125		1,912		2,930		2,233		230		203		54		190		8,021
consolidated subsidiaries		144		125		1,912		2,930		1,967		230		203		54		190		7,755
equity-accounted entities										266										266

(a)

Values lower than 1 BCF are not disclosed in this table.

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Natural Gas(a) continued

2016	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Reserves at December 31, 2015		1,304		1,044		3,851		947		2,714		2,354		878		439		771		14,302
of which: developed		1,051		919		1,744		822		1,390		1,830		185		373		585		8,899
undeveloped		253		125		2,107		125		1,324		524		693		66		186		5,403
Purchase of Minerals in Place
Revisions of Previous Estimates		(155)		18		471		25		223		224		200		8		12		1,026
Improved Recovery
Extensions and Discoveries								4,767						15						4,782
Production		(172)		(184)		(584)		(219)		(170)		(93)		(90)		(94)		(42)		(1,648)
Sales of Minerals in Place
Reserves at December 31, 2016		977		878		3,738		5,520		2,767		2,485		1,003		353		741		18,462
Equity-accounted entities
Reserves at December 31, 2015						13				387				12		3,581				3,993
of which: developed						13				85				9		1,295				1,402
undeveloped										302				3		2,286				2,591
Purchase of Minerals in Place
Revisions of Previous Estimates						4				(8)				(1)		(4)				(9)
Improved Recovery
Extensions and Discoveries
Production						(2)				(11)				(7)		(93)				(113)
Sales of Minerals in Place
Reserves at December 31, 2016						15				368				4		3,484				3,871
Reserves at December 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
consolidated subsidiaries		845		801		1,732		799		1,651		2,239		280		338		559		9,244
equity-accounted entities						15				104				4		1,782				1,905
Undeveloped		132		77		2,006		4,721		1,380		246		723		1,717		182		11,184
consolidated subsidiaries		132		77		2,006		4,721		1,116		246		723		15		182		9,218
equity-accounted entities										264						1,702				1,966

2015	Italy		Rest of Europe		North Africa		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
Consolidated subsidiaries
Reserves at December 31, 2014		1,432		1,171		5,291		2,744		2,049		846		468		807		14,808
of which: developed		1,192		887		2,110		1,271		1,553		261		393		675		8,342
undeveloped		240		284		3,181		1,473		496		585		75		132		6,466
Purchase of Minerals in Place
Revisions of Previous Estimates		68		74		163		145		385		24		69		5		933
Improved Recovery
Extensions and Discoveries		4				124						114						242
Production		(200)		(201)		(780)		(171)		(80)		(106)		(94)		(41)		(1,673)
Sales of Minerals in Place								(4)						(4)				(8)
Reserves at December 31, 2015		1,304		1,044		4,798		2,714		2,354		878		439		771		14,302
Equity-accounted entities
Reserves at December 31, 2014						15		351				18		3,353				3,737
of which: developed						15		89				10		6				120
undeveloped								262				8		3,347				3,617
Purchase of Minerals in Place
Revisions of Previous Estimates								36				3		253				292
Improved Recovery
Extensions and Discoveries
Production						(2)						(9)		(25)				(36)
Sales of Minerals in Place
Reserves at December 31, 2015						13		387				12		3,581				3,993
Reserves at December 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
consolidated subsidiaries		1,051		919		2,566		1,390		1,830		185		373		585		8,899
equity-accounted entities						13		85				9		1,295				1,402
Undeveloped		253		125		2,232		1,626		524		696		2,352		186		7,994
consolidated subsidiaries		253		125		2,232		1,324		524		693		66		186		5,403
equity-accounted entities								302				3		2,286				2,591

(a)

Values lower than 1 BCF are not disclosed in this table.

F-150

TABLE OF CONTENTS

Standardized measure of discounted future net cash flows

Estimated future cash inflows represent the revenues that would be received from production and are determined by applying the year-end average prices during the years ended.

Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered.

The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor.

Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the countries in which Eni operates.

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities — Oil & Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

F-151

TABLE OF CONTENTS

The standardized measure of discounted future net cash flows by geographical area consists of the following:

(€ million)
	Italy		Rest of Europe		North Africa		Egypt		Sub - Saharan Africa		Kazakhstan		Rest of Asia		America		Australia and Oceania		Total
December 31, 2017
Consolidated subsidiaries
Future cash inflows		14,339		19,507		31,793		29,156		41,136		30,263		11,826		6,205		2,593		186,818
Future production costs		(5,091)		(5,711)		(6,677)		(6,153)		(14,790)		(6,992)		(3,653)		(2,351)		(590)		(52,008)
Future development and abandonment costs		(3,943)		(5,483)		(4,350)		(4,496)		(6,522)		(2,787)		(3,694)		(1,011)		(318)		(32,604)
Future net inflow before income tax		5,305		8,313		20,766		18,507		19,824		20,484		4,479		2,843		1,685		102,206
Future income tax		(859)		(4,490)		(10,836)		(5,709)		(6,418)		(3,970)		(757)		(699)		(303)		(34,041)
Future net cash flows		4,446		3,823		9,930		12,798		13,406		16,514		3,722		2,144		1,382		68,165
10% discount factor		(1,633)		(1,050)		(4,566)		(6,698)		(5,430)		(9,172)		(1,239)		(777)		(607)		(31,172)
Standardized measure of discounted future net cash flows		2,813		2,773		5,364		6,100		7,976		7,342		2,483		1,367		775		36,993
Equity-accounted entities
Future cash inflows						245				2,062				11		10,797				13,115
Future production costs						(119)				(930)				(6)		(3,291)				(4,346)
Future development and abandonment costs						(1)				(66)						(535)				(602)
Future net inflow before income tax						125				1,066				5		6,971				8,167
Future income tax						(21)				(57)				(1)		(2,459)				(2,538)
Future net cash flows						104				1,009				4		4,512				5,629
10% discount factor						(50)				(471)						(2,475)				(2,996)
Standardized measure of discounted future net cash flows						54				538				4		2,037				2,633
Total consolidated subsidiaries and equity-accounted entities		2,813		2,773		5,418		6,100		8,514		7,342		2,487		3,404		775		39,626
December 31, 2016
Consolidated subsidiaries
Future cash inflows		9,627		12,898		30,847		33,524		38,271		26,903		12,263		5,789		2,815		172,937
Future production costs		(4,136)		(5,240)		(7,481)		(7,927)		(13,913)		(9,247)		(3,498)		(2,935)		(658)		(55,035)
Future development and abandonment costs		(3,641)		(3,575)		(5,904)		(6,981)		(9,392)		(3,268)		(5,047)		(1,313)		(270)		(39,391)
Future net inflow before income tax		1,850		4,083		17,462		18,616		14,966		14,388		3,718		1,541		1,887		78,511
Future income tax		(237)		(1,308)		(9,253)		(5,941)		(4,525)		(2,596)		(953)		(298)		(341)		(25,452)
Future net cash flows		1,613		2,775		8,209		12,675		10,441		11,792		2,765		1,243		1,546		53,059
10% discount factor		(241)		(365)		(4,060)		(8,055)		(4,594)		(6,536)		(1,266)		(501)		(724)		(26,342)
Standardized measure of discounted future net cash flows		1,372		2,410		4,149		4,620		5,847		5,256		1,499		742		822		26,717
Equity-accounted entities
Future cash inflows						259				2,429				33		16,430				19,151
Future production costs						(143)				(974)				(20)		(4,614)				(5,751)
Future development and abandonment costs						(1)				(64)						(1,186)				(1,251)
Future net inflow before income tax						115				1,391				13		10,630				12,149
Future income tax						(21)				(115)				(4)		(3,667)				(3,807)
Future net cash flows						94				1,276				9		6,963				8,342
10% discount factor						(46)				(734)						(4,441)				(5,221)
Standardized measure of discounted future net cash flows						48				542				9		2,522				3,121
Total consolidated subsidiaries and equity-accounted entities		1,372		2,410		4,197		4,620		6,389		5,256		1,508		3,264		822		29,838
December 31, 2015
Consolidated subsidiaries
Future cash inflows		16,760		18,692		58,390				44,114		34,589		13,027		8,101		3,519		197,192
Future production costs		(4,995)		(5,554)		(13,481)				(14,645)		(8,846)		(4,585)		(3,091)		(804)		(56,001)
Future development and abandonment costs		(4,299)		(4,379)		(9,457)				(9,359)		(4,108)		(4,964)		(1,644)		(218)		(38,428)
Future net inflow before income tax		7,466		8,759		35,452				20,110		21,635		3,478		3,366		2,497		102,763
Future income tax		(1,657)		(4,349)		(17,195)				(8,222)		(4,682)		(1,230)		(933)		(604)		(38,872)
Future net cash flows		5,809		4,410		18,257				11,888		16,953		2,248		2,433		1,893		63,891
10% discount factor		(2,077)		(817)		(7,844)				(4,976)		(10,561)		(1,276)		(970)		(901)		(29,422)
Standardized measure of discounted future net cash flows		3,732		3,593		10,413				6,912		6,392		972		1,463		992		34,469
Equity-accounted entities
Future cash inflows						313				3,047				85		18,519				21,964
Future production costs						(177)				(1,021)				(32)		(5,370)				(6,600)
Future development and abandonment costs						(5)				(95)				(22)		(2,118)				(2,240)
Future net inflow before income tax						131				1,931				31		11,031				13,124
Future income tax						(8)				(251)				(10)		(4,088)				(4,357)
Future net cash flows						123				1,680				21		6,943				8,767
10% discount factor						(70)				(1,016)				(2)		(4,358)				(5,446)
Standardized measure of discounted future net cash flows						53				664				19		2,585				3,321
Total consolidated subsidiaries and equity-accounted entities		3,732		3,593		10,466				7,576		6,392		991		4,048		992		37,790

F-152

TABLE OF CONTENTS

Changes in standardized measure of discounted future net cash flows

Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2017, 2016 and 2015, are as follows:

(€ million)
	Consolidated subsidiaries		Equity- accounted entities		Total
2017
Standardized measure of discounted future net cash flows at December 31, 2016		26,717		3,121		29,838
Increase (Decrease):
- sales, net of production costs		(14,125)		(432)		(14,557)
- net changes in sales and transfer prices, net of production costs		23,940		1,482		25,422
- extensions, discoveries and improved recovery, net of future production and development costs		1,697				1,697
- changes in estimated future development and abandonment costs		(2,817)		495		(2,322)
- development costs incurred during the period that reduced future development costs		7,203		45		7,248
- revisions of quantity estimates		5,269		(2,285)		2,984
- accretion of discount		3,864		438		4,302
- net change in income taxes		(6,498)		238		(6,260)
- purchase of reserves in-place		10				10
- sale of reserves in-place		(2,995)				(2,995)
- changes in production rates (timing) and other		(5,272)		(469)		(5,741)
Net increase (decrease)		10,276		(488)		9,788
Standardized measure of discounted future net cash flows at December 31, 2017		36,993		2,633		39,626
2016
Standardized measure of discounted future net cash flows at December 31, 2015		34,469		3,321		37,790
Increase (Decrease):
- sales, net of production costs		(11,222)		(347)		(11,569)
- net changes in sales and transfer prices, net of production costs		(24,727)		(1,586)		(26,313)
- extensions, discoveries and improved recovery, net of future production and development costs		4,563				4,563
- changes in estimated future development and abandonment costs		(2,357)		650		(1,707)
- development costs incurred during the period that reduced future development costs		7,578		151		7,729
- revisions of quantity estimates		2,840		(131)		2,709
- accretion of discount		5,705		514		6,219
- net change in income taxes		9,200		386		9,586
- purchase of reserves in-place
- sale of reserves in-place
- changes in production rates (timing) and other		668		163		831
Net increase (decrease)		(7,752)		(200)		(7,952)
Standardized measure of discounted future net cash flows at December 31, 2016		26,717		3,121		29,838
2015
Standardized measure of discounted future net cash flows at December 31, 2014		56,035		3,558		59,593
Increase (Decrease):
- sales, net of production costs		(14,846)		(179)		(15,025)
- net changes in sales and transfer prices, net of production costs		(70,909)		(2,858)		(73,767)
- extensions, discoveries and improved recovery, net of future production and development costs		524				524
- changes in estimated future development and abandonment costs		(1,711)		(241)		(1,952)
- development costs incurred during the period that reduced future development costs		8,960		604		9,564
- revisions of quantity estimates		12,322		915		13,237
- accretion of discount		11,288		629		11,917
- net change in income taxes		29,530		530		30,060
- purchase of reserves in-place
- sale of reserves in-place		(114)				(114)
- changes in production rates (timing) and other		3,390		363		3,753
Net increase (decrease)		(21,566)		(237)		(21,803)
Standardized measure of discounted future net cash flows at December 31, 2015		34,469		3,321		37,790

F-153

	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.

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)

						Page
	Certain defined terms					ii
	Presentation of financial and other information					ii
	Statements regarding competitive position					ii
	Glossary					iii
	Abbreviations and conversion table					vii
	PART I
	Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS					1
	Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE					1
	Item 3. KEY INFORMATION					1
	Selected Financial Information					1
	Selected Operating Information					3
	Exchange Rates					4
	Risk factors					5
	Item 4. INFORMATION ON THE COMPANY					26
	History and development of the Company					26
	BUSINESS OVERVIEW					32
	Exploration & Production					32
	Gas & Power					63
	Refining & Marketing & Chemicals					68
	Corporate and Other activities					75
	Research and development					75
	Insurance					79
	Environmental matters					79
	Regulation of Eni’s businesses					92
	Property, plant and equipment					97
	Organizational structure					98
	Item 4A. UNRESOLVED STAFF COMMENTS					98
	Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS					99
	Executive summary					99
	Critical accounting estimates					103
	2015-2017 Group results of operations					104
	Liquidity and capital resources					116
	Recent developments					123
	Management’s expectations of operations					123
	Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES					131
	Directors and Senior Management					131
	Compensation					140
	Board practices					156
	Employees					167
	Share ownership					168
	Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS					169
	Major Shareholders					169
	Related party transactions					169
	Item 8. FINANCIAL INFORMATION					170
	Consolidated Statements and other financial information					170
	Significant changes					170
	Item 9. THE OFFER AND THE LISTING					171
	Offer and listing details					171
	Markets					172
	Item 10. ADDITIONAL INFORMATION					173
	Memorandum and Articles of Association					173
	Material contracts					181
	Exchange controls					181
	Taxation					181
	Documents on display					186
	Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK					187
	Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES					190
	Item 12A. Debt securities					190
	Item 12B. Warrants and rights					190
	Item 12C. Other securities					190
	Item 12D. American Depositary Shares					190
	PART II
	Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES					192
	Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS					192
	Item 15. CONTROLS AND PROCEDURES					192
	Item 16. [RESERVED]					193
	Item 16A. Board of Statutory Auditors financial expert					193
	Item 16B. Code of Ethics					193
	Item 16C. Principal accountant fees and services					193
	Item 16D. Exemptions from the Listing Standards for Audit Committees					195
	Item 16E. Purchases of equity securities by the issuer and affiliated purchasers					195
	Item 16F. Change in Registrant’s Certifying Accountant					195
	Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual					195
	Item 16H. Mine safety disclosure					198
	PART III
	Item 17. FINANCIAL STATEMENTS					199
	Item 18. FINANCIAL STATEMENTS					199
	Item 19. EXHIBITS					199

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

	Page
Report of Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheet as of December 31, 2017 and December 31, 2016 and January 1, 2016		F-3
Consolidated profit and loss account for the years ended December 31, 2017, 2016 and 2015		F-4
Consolidated Statements of comprehensive income for the years ended December 31, 2017, 2016 and 2015		F-5
Consolidated Statements of changes in shareholders’ equity for the years ended December 31, 2017, 2016 and 2015		F-6
Consolidated Statement of cash flows for the years ended December 31, 2017, 2016 and 2015		F-8
Notes on Consolidated Financial Statements		F-10

	1.			By-laws of Eni SpA
	8.			List of subsidiaries
	11.			Code of Ethics
	Certifications:
	12.1.			Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
	12.2.			Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
	13.1.			Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
	13.2.			Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
	15.a(i)			Report of DeGolyer and MacNaughton
	15.a(ii)			Report of Ryder Scott Co

	(a) Controlling interest:			Syndial SpA Third parties			48.00 52.00
	(b) Controlling interest:			Eni SpA Third parties			31.00 69.00

	Eni SpA
	/s/ MASSIMO MONDAZZI

	Massimo Mondazzi
	Title: Chief Financial Officer