UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
————————————————————
Form 20-F

(Mark One)

	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2011
OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____ to _____
OR
	SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of event requiring this shell company report

Commission file number: 1-14090
——————————Eni SpA (Exact name of Registrant as specified in its charter)
Republic of Italy (Jurisdiction of incorporation or organization)
1, piazzale Enrico Mattei - 00144 Roma - Italy (Address of principal executive offices)
Alessandro Bernini
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 American Depositary Shares	New York Stock Exchange* New York Stock Exchange
(Which represent the right to receive two Shares)	* Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
Ordinary shares of euro 1.00 each 4,005,358,876

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 (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 have 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 

* This requirement does not apply to the registrants until their fiscal year ending December 31, 2011.

Indicate by check mark if 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

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

	I	Page
Certain Defined Terms	I	ii
Presentation of Financial and Other Information	I	ii
Statements Regarding Competitive Position	I	ii
Glossary	I	iii
Abbreviations and Conversion Table	I	vi

II I I III I

PART I	I		I
Item 1.	I	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS	I	1
Item 2.	I	OFFER STATISTICS AND EXPECTED TIMETABLE	I	1
Item 3.	I	KEY INFORMATION	I	1
I	I	Selected Financial Information	I	1
I	I	Selected Operating Information	I	3
I	I	Exchange Rates	I	5
I	I	Risk Factors	I	5
Item 4.	I	INFORMATION ON THE COMPANY	I	25
I	I	History and Development of the Company	I	25
I	I	Business Overview	I	30
I	I	Exploration & Production	I	30
I	I	Gas & Power	I	59
I	I	Refining & Marketing	I	74
I	I	Engineering & Construction	I	81
I	I	Petrochemicals	I	83
I	I	Corporate and Other activities	I	85
I	I	Research and Development	I	86
I	I	Insurance	I	89
I	I	Environmental Matters	I	89
I	I	Regulation of Eni’s Businesses	I	96
I	I	Property, Plant and Equipment	I	106
I	I	Organizational Structure	I	106
Item 4A.	I	UNRESOLVED STAFF COMMENTS	I	106
Item 5.	I	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	I	107
I	I	Executive Summary	I	107
I	I	Critical Accounting Estimates	I	109
I	I	2008-2010 Group Results of Operations	I	112
I	I	Liquidity and Capital Resources	I	125
I	I	Recent Developments	I	130
I	I	Management's Expectations of Operations	I	131
Item 6.	I	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	I	139
I	I	Directors and Senior Management	I	139
I	I	Compensation	I	145
I	I	Board Practices	I	156
I	I	Employees	I	162
I	I	Share Ownership	I	165
Item 7.	I	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	I	166
I	I	Major Shareholders	I	166
I	I	Related Party Transactions	I	166
Item 8.	I	FINANCIAL INFORMATION	I	167
I	I	Consolidated Statements and Other Financial Information	I	167
I	I	Significant Changes	I	167
Item 9.	I	THE OFFER AND THE LISTING	I	168
I	I	Offer and Listing Details	I	168
I	I	Markets	I	169
Item 10.	I	ADDITIONAL INFORMATION	I	171
I	I	Memorandum and Articles of Association	I	171
I	I	Material Contracts	I	177
I	I	Exchange Controls	I	177
I	I	Taxation	I	178
I	I	Documents on Display	I	182
Item 11.	I	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	I	183
Item 12.	I	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	I	184
12A.	I	Debt Securities	I	184
12B.	I	Warrants and Rights	I	184
12C.	I	Other Securities	I	184
12D.	I	American Depositary Shares	I	184
II	I	I	I	I
PART II	I	I	I	I
Item 13.	I	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	I	186
Item 14.	I	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	I	186
Item 15.	I	CONTROLS AND PROCEDURES	I	186
Item 16.	I	I	I	II
16A.	I	Board of Statutory Auditors Financial Expert	I	187
16B.	I	Code of Ethics	I	187
16C.	I	Principal Accountant Fees and Services	I	187
16D.	I	Exemptions from the Listing Standards for Audit Committees	I	188
16E.	I	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	I	188
16F.	I	Change in Registrant’s Certifying Accountant	I	188
16G.	I	Significant Differences in Corporate Governance Practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual	I	189
16H.	I	Mine Safety Disclosure	I	191
PART IIII	I	I	I	II
Item 17.	I	FINANCIAL STATEMENTS	I	192
Item 18.	I	FINANCIAL STATEMENTS	I	192
Item 19.	I	EXHIBITS	I	192

i

Certain disclosures contained herein including, without limitation, information appearing in "Item 4 – Information on the Company", and in particular "Item 4 – Exploration & Production", "Item 5 – Operating and Financial Review and Prospects" and "Item 11 – Quantitative and Qualitative Disclosures about Market Risk" contain forward-looking statements regarding future events and the future results of Eni that are based on current expectations, estimates, forecasts, and projections about the industries in which Eni operates and the beliefs and assumptions of the management of Eni. Eni may also make forward-looking statements in other written materials, including other documents filed with or furnished to the U.S. Securities and Exchange Commission (the "SEC"). In addition, Eni’s senior management may make forward-looking statements orally to analysts, investors, representatives of the media and others. In particular, among other statements, certain statements with regard to management objectives, trends in results of operations, margins, costs, return on capital, risk management and competition are forward looking in nature. Words such as ‘expects’, ‘anticipates’, ‘targets’, ‘goals’, ‘projects’, ‘intends’, ‘plans’, ‘believes’, ‘seeks’, ‘estimates’, variations of such words, and similar expressions are intended to identify such forward-looking statements. These forward-looking statements are only predictions and are subject to risks, uncertainties, and assumptions that are difficult to predict because they relate to events and depend on circumstances that will occur in the future. Therefore, Eni’s actual results may differ materially and adversely from those expressed or implied in any forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 20-F under the section entitled "Risk Factors" and elsewhere. Any forward-looking statements made by or on behalf of Eni speak only as of the date they are made. Eni does not undertake to update forward-looking statements to reflect any changes in Eni’s expectations with regard thereto or any changes in events, conditions or circumstances on which any such statement is based. The reader should, however, consult any further disclosures Eni may make in documents it files with the SEC.

CERTAIN DEFINED TERMS

In this Form 20-F, the terms "Eni", the "Group", or the "Company" refer to the parent company Eni SpA and its consolidated subsidiaries and, unless the context otherwise requires, their respective predecessor companies. All references to "Italy" or the "State" are references to the Republic of Italy, all references to the "Government" are references to the government of the Republic of Italy. For definitions of certain oil and gas terms used herein and certain conversions, see "Glossary" and "Conversion Table".

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

The Consolidated Financial Statements of Eni, included in this annual report, have been prepared in accordance with IFRS 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" and "U.S. $" are to the currency of the United States, and references to "euro" 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 Eni’s business activities: Exploration & Production, Gas & Power, Refining & Marketing, Engineering & Construction, Petrochemicals and other activities.

STATEMENTS REGARDING COMPETITIVE POSITION

Statements made in "Item 4 – Information on the Company" referring to Eni’s competitive position are based on the Company’s belief, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and Eni’s internal assessment of market share based on publicly available information about the financial results and performance of market participants. Market share estimates contained in this document are based on management estimates unless otherwise indicated.

ii

GLOSSARY

A glossary of oil and gas terms is available on Eni’s web page at the address eni.com. Below is a selection of the most frequently used terms.

Financial terms
Leverage	A non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’ equity, including minority interest. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure which in the case of the Company refers to IFRS, 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 which in the case of the Company refers to IFRS, see "Item 5 – Financial Condition".
TSR (Total Shareholder Return)	Management uses this measure to asses the total return of the Eni share. It is calculated on a yearly basis, keeping account of changes in prices (beginning and end of year) and dividends distributed and reinvested at the ex-dividend date.
Business terms
AEEG (Authority for Electricity and Gas)	The Regulatory Authority for Electricity and Gas is the Italian independent body which regulates, controls and monitors the electricity and gas 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.
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 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.
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.

iii

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.
EPIC	Engineering, Procurement, Installation and Construction.
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.
Mineral Storage	According to Legislative Decree No. 164/2000, these are volumes required for allowing optimal operation of natural gas fields in Italy for technical and economic reasons. The purpose is to ensure production flexibility as required by long-term purchase contracts as well as to cover technical risks associated with production.
Modulation Storage	According to Legislative Decree No. 164/2000, these are volumes required for meeting hourly, daily and seasonal swings in demand.
Natural gas liquids (NGL)	Liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that were previously defined as natural gasoline, are natural gas liquids.
Network Code	A code containing norms and regulations for access to, management and operation of natural gas pipelines.
Over/Under lifting	Agreements stipulated between partners which regulate the right of each to its share in the production for a set period of time. Amounts lifted by a partner different from the agreed amounts determine temporary Over/Under lifting situations.
Possible reserves	Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
Probable reserves	Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
Primary balanced refining capacity	Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d.
Production Sharing Agreement ("PSA")	Contract 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

iv

	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.
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.
Strategic Storage	According to Legislative Decree No. 164/2000, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system.
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.
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.

v

ABBREVIATIONS

mmCF	=	million cubic feet	ktonnes	=	thousand tonnes
BCF	=	billion cubic feet	mmtonnes	=	million tonnes
mmCM	=	million cubic meters	MW	=	megawatt
BCM	=	billion cubic meters	GWh	=	gigawatthour
BOE	=	barrel of oil equivalent	TWh	=	terawatthour
KBOE	=	thousand barrel of oil equivalent	/d	=	per day
mmBOE	=	million barrel of oil equivalent	/y	=	per year
BBOE	=	billion barrel of oil equivalent	E&P	=	the Exploration & Production segment
BBL	=	barrels	G&P	=	the Gas & Power segment
KBBL	=	thousand barrels	R&M	=	the Refining & Marketing segment
mmBBL	=	million barrels	E&C	=	the Engineering & Construction segment
BBBL	=	billion barrels

CONVERSION TABLE

1 acre	=	0.405 hectares
1 barrel	=	42 U.S. gallons
1 BOE	=	1 barrel of crude oil	=	5,550 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 0.00615 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)

(*) In presenting data on production volumes and reserves for total hydrocarbons, natural gas volumes have been converted to oil-equivalent barrels on the basis of a certain equivalency. In 2010, Eni updated the natural gas conversion factor from 5,742 to 5,550 standard cubic feet of gas per barrel of oil equivalent. This update reflected changes in Eni’s gas properties that took place in recent years and was assessed by collecting data on the heating power of gas in all Eni’s 230 gas fields on stream at the end of 2009. The effect of this update on production expressed in BOE was 26 KBOE/d for the full year 2010 and on the initial reserves balances as of January 1, 2010 amounted to 106 mmBOE. Other per-BOE indicators were only marginally affected by the update (e.g. realization prices, costs per BOE) and also negligible was the impact on depletion charges. Other oil companies may use different conversion rates.

vi

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 issued by the International Accounting Standards Board (IASB). The tables below show Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2007, 2008, 2009, 2010 and 2011. The selected historical financial data presented herein are derived from Eni’s Consolidated Financial Statements included in Item 18.

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,

2007 2008 2009 2010 2011

(euro million except data per share and per ADR)

CONSOLIDATED PROFIT STATEMENT DATA
Net sales from operations	87,204		108,082		83,227		98,523		109,589
Operating profit by segment (1)
Exploration & Production	13,433		16,239		9,120		13,866		15,887
Gas & Power	4,465		4,030		3,687		2,896		1,758
Refining & Marketing	686		(988	)	(102	)	149		(273	)
Petrochemicals	100		(845	)	(675	)	(86	)	(424	)
Engineering & Construction	837		1,045		881		1,302		1,422
Other activities (2)	(444	)	(466	)	(436	)	(1,384	)	(427	)
Corporate and financial companies (2)	(312	)	(623	)	(420	)	(361	)	(319	)
Impact of unrealized intragroup profit elimination (3)	(26	)	125				(271	)	(189	)
Operating profit	18,739		18,517		12,055		16,111		17,435
Net profit attributable to Eni	10,011		8,825		4,367		6,318		6,860
Data per ordinary share (euro) (4)
Operating profit:
- basic	5.11		5.09		3.33		4.45		4.81
- diluted	5.11		5.09		3.33		4.45		4.81
Net profit attributable to Eni basic and diluted	2.73		2.43		1.21		1.74		1.89
Data per ADR ($) (4) (5)
Operating profit:
- basic	14.01		14.97		9.27		11.81		13.40
- diluted	14.00		14.97		9.27		11.81		13.40
Net profit attributable to Eni basic and diluted	7.48		7.14		3.36		4.62		5.26

1

As of December 31,

2007 2008 2009 2010 2011

(euro million except number of shares and dividend information)

CONSOLIDATED BALANCE SHEET DATA
Total assets	101,460	116,673	117,529	131,860	142,945
Short-term and long-term debt	19,830	20,837	24,800	27,783	29,597
Capital stock issued	4,005	4,005	4,005	4,005	4,005
Minority interest	2,439	4,074	3,978	4,522	4,921
Shareholders’ equity - Eni share	40,428	44,436	46,073	51,206	55,472
Capital expenditures	10,593	14,562	13,695	13,870	13,438
Weighted average number of ordinary shares outstanding (fully diluted - shares million)	3,668	3,639	3,622	3,622	3,623
Dividend per share (euro)	1.30	1.30	1.00	1.00	1.04
Dividend per ADR ($) (4)	3.74	3.72	2.91	2.64	2.90

(1)	i	From 2009, gains and losses on non-hedging commodity derivative instruments, including both fair value re-measurement and gains and losses on settled transactions are reported as items of operating profit. Also results of the gas storage business are reported within the Gas & Power segment reporting unit, as part of the regulated businesses results, following the restructuring of Eni’s regulated gas businesses in Italy. In past years, results of the gas storage business were reported within the Exploration & Production segment. Prior year data have been restated.
(2)	i	From 2010 certain environmental provisions incurred by the Parent Company Eni SpA due to inter-company guarantees on behalf of Syndial have been reported within the segment reporting unit "Other activities". Data for the years 2008 and 2009 have been restated by increasing the operating loss of the "Other activities" segment by euro 120 million and euro 54 million, respectively. Prior-year data have not been restated.
(3)	i	This item mainly pertained to intra-group sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of the end of the period.
(4)	i	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 2011 is based on the proposal of Eni’s management which is submitted to approval of the Annual General Shareholders’ Meeting scheduled on April 30 and May 8, 2012 on first and second calls, respectively.
(5)	i	Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/U.S.$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2007 through 2010 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 2011 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 (euro 1.04 per ADR) at the Noon Buying Rate recorded on the payment date on September 29, 2011, while the balance of euro 1.04 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2011. The balance dividend for 2011 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 24, 2012 to holders of Eni shares, being the ex-dividend date May 21, while ADRs holders will be paid late in May 2012 being May 23 the ex-dividend date for ADRs holders.

2

Selected Operating Information

The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2007, 2008, 2009, 2010 and 2011. Data on production of oil and natural gas and hydrocarbon production sold includes Eni’s share of production of affiliates and joint ventures accounted for under the equity method of accounting. In presenting data on production volumes and reserves for total hydrocarbons, natural gas volumes have been converted to oil-equivalent barrels on the basis of a certain equivalency. In 2010, Eni updated the natural gas conversion factor from 5,742 to 5,550 standard cubic feet of gas per barrel of oil equivalent. This update reflected changes in Eni’s gas properties that took place in recent years and was assessed by collecting data on the heating power of gas in all Eni’s 230 gas fields on stream at the end of 2009. Other per-BOE indicators were only marginally affected by the update (e.g. realization prices, costs per BOE) and also negligible was the impact on depletion charges. Other oil companies may use different conversion rates.

Year ended December 31,

2007 2008 2009 2010 2011

Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL)	3,127	3,243	3,377	3,415	3,134
of which developed	1,953	2,009	2,001	1,951	1,850
Proved reserves of liquids of equity-accounted entities at period end (mmBBL)	142	142	86	208	300
of which developed	26	33	34	52	45
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF) (1)	16,549	17,214	16,262	16,198	15,582
of which developed	10,967	11,138	11,650	10,965	10,363
Proved reserves of natural gas of equity-accounted entities at period end (BCF)	3,022	3,015	1,588	1,684	4,700
of which developed	428	420	234	246	53
Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end (1)	6,010	6,242	6,209	6,332	5,940
of which developed	3,862	3,948	4,030	3,926	3,716
Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end	668	666	362	511	1,146
of which developed	101	107	74	96	54
Reserves replacement ratio (2)	138	135	96	125	142
Average daily production of liquids (KBBL/d) (3)	1,020	1,026	1,007	997	845
Average daily production of natural gas available for sale (mmCF/d) (3)	3,819	4,143	4,074	4,222	3,763
Average daily production of hydrocarbons available for sale (KBOE/d) (3)	1,684	1,748	1,716	1,757	1,523
Hydrocarbon production sold (mmBOE)	611.4	632.0	622.8	638.0	548.5
Oil and gas production costs per BOE (4)	6.90	7.65	7.41	8.89	10.86
Profit per barrel of oil equivalent (5)	14.19	16.00	8.14	11.91	16.98

(1)	i	Includes approximately 749, 746, 769, 767 and 767 BCF of natural gas held in storage in Italy as of December 31, 2007, 2008, 2009, 2010 and 2011, respectively.
(2)		Referred to Eni’s subsidiaries and its equity-accounted entities. Consists of: (i) the increase in proved reserves attributable to: (a) purchases of minerals in place; (b) revisions of previous estimates; (c) improved recovery; and (d) extensions and discoveries, less sales of minerals in place; divided by (ii) production during the year as set forth in the reserve tables, in each case prepared in accordance with Topic 932. See the unaudited supplemental oil and gas information in "Item 18 – Notes to the Consolidated Financial Statements". Expressed as a percentage.
(3)	i	Referred to Eni’s subsidiaries and its equity-accounted entities. Natural gas production volumes exclude gas consumed in operations (296, 281, 300, 318 and 321 mmCF/d in 2007, 2008, 2009, 2010 and 2011, respectively).
(4)		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".
(5)		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.

3

Selected Operating Information continued

Year ended December 31,

2007 2008 2009 2010 2011

Sales of natural gas to third parties (6)	78.75	83.69	83.79	75.81	78.16
Natural gas consumed by Eni (6)	6.08	5.63	5.81	6.19	6.21
Sales of natural gas of affiliates (Eni’s share) (6)	8.74	8.91	7.95	9.41	9.53
Total sales and own consumption of natural gas of the Gas & Power segment (6)	93.57	98.23	97.55	91.41	93.90
E&P natural gas sales in Europe and in the Gulf of Mexico (6)	5.39	6.00	6.17	5.65	2.86
Worldwide natural gas sales (6)	98.96	104.23	103.72	97.06	96.76
Transport of natural gas for third parties in Italy (6)	30.89	33.84	37.32	47.87	43.18
Length of natural gas transport network in Italy at period end (7)	31.1	31.5	31.5	31.7	32.0
Electricity sold (8)	33.19	29.93	33.96	39.54	40.28
Refinery throughputs (9)	37.15	35.84	34.55	34.80	31.96
Balanced capacity of wholly-owned refineries (10)	544	544	554	564	574
Retail sales (in Italy and rest of Europe) (9)	11.80	12.03	12.02	11.73	11.37
Number of service stations at period end (in Italy and rest of Europe)	6,441	5,956	5,986	6,167	6,287
Average throughput per service station (in Italy and rest of Europe) (11)	2,486	2,502	2,477	2,353	2,206
Petrochemical production (9)	8.80	7.37	6.52	7.22	6.25
Engineering & Construction order backlog at period end (12)	15,390	19,105	18,730	20,505	20,417
Employees at period end (units)	75,125	78,094	77,718	79,941	78,686

(6)	i	Expressed in BCM.
(7)	i	Expressed in thousand kilometers.
(8)	i	Expressed in TWh.
(9)	i	Expressed in mmtonnes.
(10)	i	Expressed in KBBL/d.
(11)	i	Expressed in thousand liters per day.
(12)	i	Expressed in euro million.

4

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 euro)

Year ended December 31,
2007	1.49	1.29	1.37	1.46
2008	1.60	1.24	1.47	1.39
2009	1.51	1.25	1.39	1.44
2010	1.46	1.19	1.33	1.34
2011	1.49	1.29	1.39	1.29

(1) Average of the Noon Buying Rates for the last business day of each month in the period.

High Low At period end

(U.S. dollars per euro)

October 2011	1.42	1.32	1.40
November 2011	1.38	1.33	1.34
December 2011	1.35	1.29	1.29
January 2012	1.32	1.27	1.32
February 2012	1.35	1.30	1.34
March 2012	1.33	1.30	1.33

Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the Telematico 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, 2012 was $1.3334 per euro 1.00.

Risk Factors

Competition

There is strong competition worldwide, both within the oil industry and with other industries, to supply energy to the industrial, commercial and residential energy markets.

Eni faces strong competition in each of its business segments. In the current uncertain financial and economic environment, we expect that prices of energy commodities, in particular oil and gas, will be very volatile, with average prices and margins influenced by changes in supply and demand. This is likely to exacerbate competition in all our businesses, which may impact costs and margins.

• In the Exploration & Production business Eni faces competition from both international oil companies 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 in many of these markets because of its relatively smaller size compared to other international oil companies, particularly when bidding for large scale or capital intensive projects, and may be exposed to industry-wide cost increases to a greater extent compared to its larger competitors given its potentially smaller market power with respect to suppliers. If, as a result of those competitive pressures, Eni fails to obtain new exploration and development acreage, to apply and develop new technologies, and to control cost increases, its growth prospects and future results of operations and cash flows may be adversely affected;

• In its natural gas business, Eni faces increasingly strong competition on both the Italian market and the European market driven by slow demand growth in the face of large gas availability on the marketplace. Gas

5

	supplies to Europe have been fuelled by material investments to expand the import capacity of the pipelines coming from Russia and Algeria which have been executed by a number of operators, including Eni, in recent years. Furthermore, we estimated that some 65 BCM of liquefaction capacity were added to worldwide gas availability in the three-year period 2008-2010 by upstream operators. This development coupled with an ongoing shift in the United States from gas imports to use of internal non-conventional gas resources caused the diversion of important LNG volumes to Europe where they are marketed at certain continental spot markets which have become increasingly liquid. Oversupplies on the European market coupled with weak demand growth triggered intense pricing competition among gas operators which squeezed profitability and reduced sales opportunities in the whole sector. This was due to decoupling trends between on one hand the rising cost of gas supplies that are mainly indexed to the price of oil and its derivatives as provided by pricing formulas in long-term supply contracts, and on the other hand weak selling prices at continental hubs pressured by competition. Those trends helped explain why the Company’s Gas & Power segment reported sharply lower results in 2011 (down by 39.3% compared to 2010) on the back of operating losses reported by its Marketing business. We believe that the outlook for our gas marketing business will remain weak in the short to medium term as the factors described above, in particular weak demand, oversupply and competition take time to be reversed. Management believes that a better balance between demand and supply on the European market is unlikely to be achieved before 2014. The described trends may negatively affect the Company’s future results of operations and cash flows in its natural gas business, also taking into account the Company’s contractual obligations to off-take minimum annual volumes of natural gas in accordance to its long-term gas supply contracts that include take-or-pay clauses. See the sector-specific risk section below;
•	Eni also faces competition from large, well-established European utilities and other international oil and gas companies in growing its market share and acquiring or retaining clients. A number of large clients, particularly electricity producers and large industrial buyers, in both the domestic market and other European markets have entered the wholesale market of natural gas by directly purchasing gas from producers or sourcing it at the continental spot markets adding further pressures on the economics of gas operators, including Eni. Management believes that this trend will continue in the future. At the same time, a number of national gas producers from countries with large gas reserves are planning to sell natural gas directly to final clients, which would threaten the market position of companies like Eni which resell gas purchased from producing countries to final customers. These developments may increase the level of competition in both the Italian and other European markets for natural gas and reduce Eni’s operating profit and cash flows. Finally, following a decree from the Italian Government to spur competition in Italy, management expects that the Company’s margins on sales to residential customers and the service sector will be reduced due to the administrative implementation of a less favorable indexation of the raw material cost in supplies to such customers than in the past (see sector-specific risk factors below);
•	In its domestic electricity business, Eni competes with other producers and traders from Italy or outside of Italy who sell electricity on the Italian market. The Company expects in the near future that increasing competition due to the weak GDP growth expected in Italy and Europe over the next one to two years will cause other players to place excess production on the Italian market;
•	In the retail marketing of refined products both in Italy and abroad, Eni competes with third parties (including international oil companies and local operators such as supermarket chains) to obtain concessions to establish and operate service stations. Eni’s service stations compete primarily on the basis of pricing, services and availability of non-petroleum products. In Italy, there is an ongoing pressure from political and administrative entities, including the Italian Antitrust Authority, to increase the level of competition in the retail marketing of fuels. The above mentioned decree from the Italian Government targeted the Italian fuel retail market too, by relaxing commercial ties between independent operators of service stations and oil companies, enlarging the options to build and operate fully-automated service stations, and opening up the merchandising of various kinds of goods and services at service stations. Eni expects developments in this field to further increase pressure on selling margins in the retail marketing of fuels and to reduce opportunities of increasing market share in Italy;
•	In the Petrochemical segment, we face strong competition from well-established international players and state-owned petrochemical companies, particularly in the most commoditized market segments. Many of those competitors may benefit from cost advantages due to larger scale, looser environmental regulations, availability of oil-based feedstock, and more favorable location and proximity to end-markets. Excess capacity and sluggish economic growth may exacerbate competitive pressures. The Company expects continuing margin pressures in the foreseeable future as a result of those trends; and
•	Competition in the oil field services, construction and engineering industries is primarily based on technical expertise, quality and number of services and availability of technologically advanced facilities (for example, vessels for offshore construction). Lower oil prices could result in lower margins and lower demand for oil services. The Company’s failure or inability to respond effectively to competition could adversely impact the Company’s growth prospects, future results of operations and cash flows.

Risks associated with the exploration and production of oil and natural gas and other Group’s operations

The exploration and production of oil and natural gas requires high levels of capital expenditures and entails certain economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical

6

characteristics of oil and natural gas fields. In addition, the Group engages in processing, transportation, refining and petrochemical activities, storage and distribution of petroleum products, natural gas transportation, distribution and storage, and production of base chemical and specialty products, which involve a wide range of operational risks.

Eni’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in those industries. The Company seeks to minimize these operational risks by carefully designing and building its facilities, including wells, industrial complexes, plants and equipment, pipelines, storage sites and distribution networks, and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, and increase in cost, legal liability and/or damage or destruction of crude oil or natural gas wells as well as equipment and other property, all of which could lead to a disruption in operations. We also face risks once production is discontinued, because our activities require environmental site remediation.

In exploration and production, we encounter risks related to the physical characteristics of our oil or 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 risks of fire or explosion. Accidents at a single well can lead to loss of life, damage or destruction to property, environmental damage and consequently potential economic losses that could have a material and adverse effect on the business, results of operation and prospects of the Group.

Eni’s activities in the Refining & Marketing and Petrochemicals sectors also entail additional health, safety and environmental risks related to the overall life cycle of the products manufactured, as well as raw materials used in the manufacturing process, such as catalysts, additives and monomer feedstock. These risks can arise from the intrinsic characteristics of the products involved (flammability, toxicity, or long-term environmental impacts such as greenhouse gas emissions), their use, emissions and discharges resulting from their manufacturing process, and from recycling or disposing of materials and wastes at the end of their useful life.

In the transportation area, the type of risk depends not only on the hazardous nature of the products transported, but also on the transportation methods used (mainly pipelines, maritime, river-maritime, rail, road, 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 dedicates a great deal of efforts and attention to safety, health, the environment and the prevention of risks; in pursuing compliance with applicable laws and policies; and in responding and learning from unexpected incidents. Nonetheless, 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 maintains insurance coverage that include coverage for physical damage to our assets, third party liability, workers’ compensation, pollution and other damage to the environment and other coverage. Our insurance is subject to caps, exclusion and limitation, and there is no assurance that such coverage will adequately protect us against liabilities from all potential consequences and damages. In light of the accident at the Macondo well in the Gulf of Mexico, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher retentions. Also, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.

Our oil and natural gas offshore operations are particularly exposed to health, safety, security and environmental risks

We have material operations relating to the exploration and production of hydrocarbons located offshore. In 2011, approximately 60% of our total oil and gas production for the year derived from offshore fields, mainly in Egypt, Norway, Italy, Angola, Gulf of Mexico, UK, Congo, Nigeria and Libya. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. As recent events in the Gulf of Mexico have shown, the potential impacts of offshore accidents and spills to health, safety, security and the environment can be catastrophic due to the objective difficulties in handling hydrocarbons containment and other factors. Also offshore operations are subject to marine perils, including severe 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, environmental damage, and could result in regulatory action, legal liability, loss of revenues and damage to our reputation and could have a material adverse effect on our operations or financial condition. On March 25, 2012 a gas leak following a well operation occurred at a wellhead platform of the Elgin/Franklin gas field which is located in the UK North Sea. The field is operated by an international oil company. We believe that this oil company is taking all necessary steps to handle the situation. We have a 21.87% interest in the field. We are closely monitoring the situation to assess any possible liability to Eni which may arise from the incident.

7

We expect that tightening regulation in oil and gas activities following the Macondo accident will lead to rising compliance costs and other restrictions

The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production interests, 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. Following the Macondo incidents in the Gulf of Mexico, the U.S. government imposed a moratorium on certain offshore drilling activities, which was subsequently lifted in October 2010. Our activities in the Gulf of Mexico slowed down as a result of a stricter authorization process for the permits concessions. After the termination of the moratorium, in the first months of 2011, the suspended operations were restarted and the planned operations for 2011 were completed as scheduled with negligible impact on the Company’s production for the year. We expect that governments throughout the world will implement stricter regulation on environmental protection, risk prevention and other forms of restrictions to drilling and other well operations. These new regulations and legislation, as well as evolving practices, could increase the cost of compliance and may also require changes to our drilling operations and exploration and development plans and may lead to higher royalties and taxes.

Exploratory drilling efforts may be unsuccessful

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 are often uncertain, and drilling operations may be unsuccessful as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or fires, blow-outs and various forms of accidents, marine risks such as collisions and adverse weather conditions and shortages or delays in the delivery of equipment. Exploring or drilling in offshore areas, particularly in deep waters, is generally more complex and riskier than in onshore areas; the same is true for exploratory activity in remote areas or in challenging environmental conditions such as those we are experiencing in the Caspian region or Alaska. Failure to discover commercial quantities of oil and natural gas could have an adverse impact on Eni’s future growth prospects, results of operations and liquidity. Because Eni plans to invest significant capital expenditures in executing high risk exploration projects, it is likely that Eni will incur significant exploration and dry hole expenses in future years. Eni plans to explore for oil and gas offshore; a number of projects are planned in deep and ultra-deep waters or at deep drilling depths, where operations are more difficult and costly than in other areas. Deep water operations generally require a significant amount of time before commercial production of reserves can commence, increasing both the operational and financial risks associated with these activities. The Company plans to conduct risky exploration projects offshore Gabon, Togo, Congo, Mozambique, in the Arctic and Barents Sea, the Black Sea and the Caspian Sea, among others. In 2011, the Company invested approximately euro 1.2 billion in executing exploration projects and it plans to spend approximately euro 1.4 billion per annum on average over the next four years which represents a steep increase from management’s previous plans.

Furthermore, shortage of deep water rigs and failure to find additional commercial reserves could reduce future production of oil and natural gas which is highly dependent on the rate of success of exploratory activity.

Development projects bear significant operational risks which may adversely affect actual returns on such projects

Eni is progressing or plans to start several development projects to produce and market hydrocarbon reserves. Certain projects target to develop reserves in high risk areas, particularly offshore and in remote and hostile environments. 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 co-venturers, governments, suppliers, customers or others including, for example, Eni’s ability to negotiate favorable long-term contracts to market gas reserves; the development of reliable spot markets that may be necessary to support the development of particular production projects, or commercial arrangements for pipelines and related equipment to transport and market hydrocarbons. Furthermore, projects executed with partners and co-venturers reduce the ability of the Company to manage risks and costs, and Eni could have limited influence over and control of the operations, behaviors and performance of its partners;

• timely issuance of permits and licenses 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, for example by obtaining more favorable contractual terms by suppliers of goods and services;

• the ability to design development projects as to prevent the occurrence of technical inconvenience;

• delays in manufacturing and delivery of critical equipment, or shortages in the availability of such equipment, causing cost overruns and delays;

8

• 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;

• changes in operating conditions and costs. Over the last several years, the industry has been impacted by rising costs for certain critical productive factors including specialized labor, procurement costs and costs for leasing third party equipment or purchase services such as drilling rigs as a result of industry-wide cost inflation and growing complexity and scale of projects, including environmental and safety costs. Furthermore, there has been an evolution in the location of our projects, as we have been discovering increasingly important volumes of reserves in remote and harsh environments (i.e. the Barents Sea, Alaska, the Yamal Peninsula, the Caspian Sea and Iraq) where we are experiencing significantly higher operating costs and environmental, safety and other costs than in other areas of activity. The Company expects that costs in its upstream operations will continue to rise in the foreseeable future;

• 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.

Delays and differences between scheduled and actual timing of critical events, as well as cost overruns may adversely affect the actual returns of our development projects. Finally, developing and marketing hydrocarbons reserves typically requires 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 commercial potential, sanctioning a development project and building and commissioning 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 with respect to prices/costs assumed when the investment decision was actually made, leading to lower rates of return. For example, we have experienced material cost increase and overruns and a substantial delay in the scheduling of production start-up at the Kashagan field, where development is ongoing. These negative trends were driven by a number of factors including depreciation of the U.S. dollar versus the euro and other currencies; cost escalation of goods and services required to execute the project; an original underestimation of the costs and complexity to operate in the North Caspian Sea due to lack of benchmarks; design changes to enhance the operability and safety standards of the offshore facilities. The partners of the venture are currently discussing with Kazakh Authorities an update of the expenditures to complete the Phase 1 which were included in the development plan approved in 2008. The consortium partners continue to target the achievement of first commercial oil production by end of 2012 or in early 2013.

See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the Kashagan project.

In the event 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 charges associated with reduced future cash flows of those projects on capitalized costs.

Inability to replace oil and natural gas reserves could adversely impact results of operations and financial condition

Eni’s results of operations and financial condition are substantially dependent on its ability to develop and sell oil and natural gas. 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") and similar contractual schemes. In accordance with such 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 expenditures. In 2011, the Company’s reserve replacement was negatively affected by lower entitlements in its PSAs for an estimated amount of 97 mmBOE, which however did not impair the Company’s ability to fully replace reserves produced in the year. See "Item 4 – Business Overview – Exploration & Production" and "Item 5 – Outlook". 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, negotiation with countries and other owners of known reserves and acquisitions. In a number of reserve-rich countries, national oil companies control a large portion of oil and gas reserves that remain to be developed. To the extent that national oil companies decide to develop those reserves without the participation of international oil companies or if our Company fails to establish partnership with national oil companies, our ability to access or develop additional reserves will be limited.

An inability to replace produced reserves by finding, acquiring and developing additional reserves could adversely impact future production levels and growth prospects. If we are unsuccessful, we may not meet our long-term targets of production growth and reserve replacement, and our future total proved reserves and production will decline, negatively affecting Eni’s future results of operations and financial condition.

9

Changes in crude oil and natural gas prices may adversely affect Eni’s results of operations

The exploration and production of oil and gas is a commodity business with a history of price volatility. The single largest variable that affects the Company’s results of operations and financial condition is crude oil prices. Lower crude oil prices have an adverse impact on Eni’s results of operations and cash flows. Eni generally does not hedge exposure to fluctuations in future cash flows due to crude oil price movements. As a consequence, Eni’s profitability depends heavily on crude oil and natural gas prices.

Crude oil and natural gas prices are subject to international supply and demand and other factors that are beyond Eni’s control, including among other things:

(i)	the control on production exerted by the Organization of the Petroleum Exporting Countries ("OPEC") member countries which control a significant portion of the world’s supply of oil and can exercise substantial influence on price levels;
(ii)	global geopolitical and economic developments, including sanctions imposed on certain oil-producing countries on the basis of resolutions of the United Nations or bilateral sanctions;
(iii)	global and regional dynamics of demand and supply of oil and gas; we believe that the current economic slowdown may have affected global demand for oil. The economic downturn has particularly hit gas demand in Europe and Italy in the second half of 2011 and we expect a moderate recovery beginning in 2012 and continuing over the next few years. However, there are still risks of a financial collapse of the eurozone which could trigger a new wave of financial crises and push the world back into recession, leading to lower demand for oil and gas and lower prices;
(iv)	prices and availability of alternative sources of energy. We believe that gas demand in Europe in 2011 has been impacted by a shift to the use of coal in firing power plants due to the fact of being relatively cheaper than gas, as well as a rising contribution of renewable energies in satisfying energy requirements. We expect those trends to continue in the future;
(v)	governmental and intergovernmental regulations, including the implementation of national or international laws or regulations intended to limit greenhouse gas emissions, which could impact the prices of hydrocarbons; and
(vi)	success in developing and applying new technology.

All these factors can affect the global balance between demand and supply for oil and prices of oil.

Lower oil and gas prices over prolonged periods may also adversely affect Eni’s results of operations and cash flows by: (i) reducing rates of return of development projects either planned or being implemented, leading the Company to reschedule, postpone or cancel development projects, or accept a lower rate of return on such projects; (ii) reducing the Group’s liquidity, entailing lower resources to fund expansion projects, further dampening the Company’s ability to grow future production and revenues; and (iii) triggering a review of future recoverability of the Company’s carrying amounts of oil and gas properties, which could lead to the recognition of significant impairment charges.

Uncertainties in Estimates of Oil and Natural Gas Reserves

Numerous uncertainties are inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of proved reserve estimates depends on a number of factors, assumptions and variables, among which the most important are the following:

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

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

• whether the prevailing tax rules, other government regulations and contractual conditions will remain the same as on the date estimates are made;

• results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may require 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. In particular the reserve estimates are subject to revisions as prices fluctuate due to the cost recovery mechanism under the Company’s PSAs and similar contractual schemes.

Many of these factors, assumptions and variables involved in estimating proved reserves are beyond Eni’s control and may change over time and impact the estimates of oil and natural gas reserves. Accordingly, the estimated reserves could be significantly different from the quantities of oil and natural gas that will ultimately be recovered. Additionally, 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.

10

Oil and gas activity may be subject to increasingly high levels of income taxes

The oil&gas industry is subject to the payment of royalties and income taxes which tend to be higher than those payable in many other commercial activities. In addition, 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 42%. In 2011, management estimates that the tax rate of the Company’s Exploration & Production segment was approximately 58%, which is calculated excluding the impact of an adjustment to deferred taxation triggered by a change of tax rate applicable to a Company’s production sharing agreement.

Management believes that the marginal tax rate in the oil&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 profit before income taxes in its oil and gas operations would have a negative impact on Eni’s future results of operations and cash flows.

In the current uncertain financial and economic environment, governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal framework for the oil&gas industry, including the risk of increased taxation, nationalization and expropriations.

Political Considerations

A substantial portion of our oil and gas reserves and gas supplies are located in politically, socially and economically unstable countries where we are exposed to material disruptions to our operations

Substantial portions of Eni’s hydrocarbon reserves are located in countries outside the EU and North America, some of which may be politically or economically less stable than EU or North American countries. As of December 31, 2011, approximately 80% of Eni’s proved hydrocarbon reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supplies comes from countries outside the EU and North America. In 2011, approximately 60% of Eni’s supplies of natural gas came from such countries. See "Item 4 – Gas & Power – Natural Gas Supplies". Adverse political, social and economic developments in any of those countries may affect Eni’s ability to continue operating in an economic way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. Particularly Eni faces risks in connection with the following issues:

(i)	lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights;
(ii)	unfavorable developments in laws, regulations and contractual arrangements leading, for example, to expropriations or forced divestitures of assets and unilateral cancellation or modification of contractual terms.
	Eni is facing increasing competition from state-owned oil companies who are partnering with 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 change contractual terms and other conditions of oil and gas projects in order to obtain a larger profit share from a given project, thereby reducing Eni’s profit share. Furthermore, as of the balance sheet date receivables for euro 504 million relating to cost recovery under a petroleum contract in a non-OECD country were the subject of an arbitration proceeding. In Kazakhstan we signed a preliminary settlement agreement with the Kazakh Authorities to solve certain claims relating the recovery of expenditures incurred to develop the Karachaganak field which is operated by a consortium of contractor companies (being 32.5% Eni’s interest in the initiative). The agreement, effective from June 30, 2012 after the satisfaction of conditions precedent, involves Kazakhstan’s KazMunaiGas (KMG) acquiring a 10% interest in the project. This will be done by each of the contracting companies transferring 10% of their rights and interest in the Karachaganak Final Production Sharing Agreement (FPSA) to KMG. The contracting companies will receive $1 billion net cash post-tax consideration ($325 million being Eni’s share);
(iii)	restrictions on exploration, production, imports and exports;
(iv)	tax or royalty increases (including retroactive claims); and
(v)	civil and social unrest leading to sabotages, acts of violence and incidents.

See "Item 4 – Exploration & Production – Oil and Natural Gas Reserves". While the occurrence of those events is unpredictable, it is likely that the occurrence of such events could cause Eni to incur material losses or facility disruptions, by this way adversely impacting Eni’s results of operations and cash flows.

Risks associated with continuing political instability in North Africa and Middle East

In the course of 2011, several North African and Middle Eastern oil producing countries experienced an extreme level of political instability that has resulted in changes in governments, unrest and violence and consequential

11

economic disruptions. As of end of 2011, approximately 30% of the Company’s proved oil & gas reserves were located in North Africa.

The situation was particularly serious in Libya where the political instability escalated to turn out into an internal revolution and conflict. In 2010, approximately 15% of Eni’s production originated from Libya and a material amount of Eni’s proved reserves were located in Libya. The situation of conflict forced Eni to shut down almost all its producing facilities including exports through the GreenStream gas pipeline for a period of eight months, with the sole exception of certain gas fields to support local production of electricity for humanitarian purposes. The temporary shut down of the Company’s production operations and gas exports negatively affected the operating and financial performance of the Exploration & Production segment. Management estimated a loss of approximately 200 KBOE/d on average for the full year 2011 as a result of the Libyan disruptions. In the final months of 2011 due to the conclusion of the internal conflict and the ongoing gradual return to political and social normality in the country, the Company has been able to progressively restart production at its sites and facilities and reopen the GreenStream pipeline. Currently, Eni’s production in Libya is flowing near pre-crisis levels; management expects that the Company’s production in Libya will achieve 230-240 KBOE/d on average for the full year 2012 compared to 108 KBOE/d in 2011 and 267 KBOE/d in 2010.

Loss of Libyan gas during 2011 also negatively impacted results of operations of the Gas & Power segment due to a worsened supply mix and lower sales to certain Italian shippers who import the Libyan gas to Italy.

See Item 4 for additional details of our operations in Libya and the impact of recent developments on our operations.

Our activities in Iran could lead to sanctions under relevant U.S. legislation

Eni is currently conducting oil and gas operations in Iran. The legislation and other regulations of the United States that target Iran and persons who have certain dealings with Iran may lead to the imposition of sanctions on any persons doing business in Iran or with Iranian counterparties.

The United States enacted the Iran Sanctions Act of 1996 (as amended, "ISA"), which required the President of the United States to impose sanctions against any entity that is determined to have engaged in certain activities, including investment in Iran’s petroleum sector. The ISA was amended in July 2010 by the Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010 ("CISADA"). As a result, in addition to sanctions for knowingly investing in Iran’s petroleum sector, parties engaging in business activities in Iran now may be sanctioned under the ISA for knowingly providing to Iran refined petroleum products, and for knowingly providing to Iran goods, services, technology, information or support that could directly and significantly either: (i) facilitate the maintenance or expansion of Iran’s domestic production of refined petroleum products, or (ii) contribute to the enhancement of Iran’s ability to import refined petroleum products. CISADA also expanded the menu of sanctions available to the President of the United States by three, from six to nine, and requires the President to impose three of the nine sanctions, as opposed to two of six, if the President has determined that a party has engaged in sanctionable conduct. The new sanctions include a prohibition on transactions in foreign exchange by the sanctioned company, a prohibition of any transfers of credit or payments between, by, through or to any financial institution to the extent the interest of a sanctioned company is involved, and a requirement to "block" or "freeze" any property of the sanctioned company that is subject to the jurisdiction of the United States. Investments in the petroleum sector that commenced prior to the adoption of CISADA appear to remain subject to the pre-amended version of the ISA, except for the mandatory investigation requirements described below, but no definitive guidance has been given. The new sanctions added by CISADA would be available to the President with respect to new investments in the petroleum sector or any other sanctionable activity occurring on or after July 1, 2010.

CISADA also adopted measures designed to reduce the President’s discretion in enforcement under the ISA, including a requirement for the President to undertake an investigation upon being presented with credible evidence that a person is engaged in sanctionable activity. CISADA also added to the ISA provisions that an investigation need not be initiated, and may be terminated once begun, if the President certifies in writing to the U.S. Congress that the person whose activities in Iran were the basis for the investigation is no longer engaging in those activities or has taken significant steps toward stopping the activities, and that the President has received reliable assurances that the person will not knowingly engage in any sanctionable activity in the future. The President also may waive sanctions, subject to certain conditions and limitations.

The United States maintains broad and comprehensive economic sanctions targeting Iran that are administrated by the U.S. Treasury Department’s Office of Foreign Assets Control ("OFAC sanctions"). These sanctions generally restrict the dealings of U.S. citizens and persons subject to the jurisdiction of the United States. In addition, we are aware of initiatives by certain U.S. states and U.S. institutional investors, such as pension funds, to adopt or consider adopting laws, regulations or policies requiring divestment from, or reporting of interests in, companies that do business with countries designated as states sponsoring terrorism. CISADA specifically authorized certain state and local Iran

12

related divestment initiatives. If our operations in Iran are determined to fall within the scope of divestment laws or policies, sales resulting from such divestment laws and policies, if significant, could have an adverse effect on our share price. Even if our activities in and with respect to Iran do not subject us to sanctions or divestment, companies with investments in the oil and gas sectors in Iran may suffer reputational harm as a result of increased international scrutiny.

Other sanctions programs have been adopted by various governments and regulators with respect to Iran, including a series of resolutions from the United Nations Security Council, and measures imposed by various countries based on and to implement these United Nations Security Council resolutions. On July 26, 2010, the European Union adopted new restrictive measures regarding Iran (referred to as the "EU measures"). Among other things, the supply of equipment and technology in the following sectors of the oil and gas industry in Iran are prohibited: refining, liquefied natural gas, exploration and production. The prohibition extends to technical assistance, training and financing and financial assistance in connection with such items. Extension of loans or credit to, acquisition of shares in, entry into joint ventures with or other participation in enterprises in Iran (or Iranian owned enterprises outside of Iran) engaged in any of the targeted sectors also is prohibited.

Eni Exploration & Production segment has been operating in Iran for several years under four Service Contracts (South Pars, Darquain, Dorood and Balal, these latter two projects being operated by another international oil company) entered into with the National Iranian Oil Co (NIOC) between 1999 and 2001, and no other exploration and development contracts have been entered into since then. Under such Service Contracts, Eni has carried out development operations in respect of certain oil fields, and is entitled to recovery of expenditures made, as well as a service fee. The service contracts do not provide for payments to be made by Eni, as contractor, to the Iranian Government (e.g. leasing fees, bonuses, significant amounts of local taxes); all material future cash flows relate to the payment to Eni of its dues. All projects mentioned above have been completed or substantially completed; the last one, the Darquain project, is in the process of final commissioning and is being handed over to the NIOC. In this respect, we expect to incur operating costs in the range of approximately US$10 to US$20 million per year over the next few years for contractual support activities and services.

Eni Exploration & Production projects in Iran are currently in the cost recovery phase. Therefore, Eni has ceased making any further investment in the country and is not planning to make additional capital expenditures in Iran in future years.

In 2011, Eni’s production in Iran averaged 6 KBOE/d, representing less than 1% of the Eni Group’s total production for the year. Eni’s entitlement in 2011 represented less than 3% of the overall production from the oil and gas fields that we have developed in Iran. Eni does not believe that the results from its Iranian exploration and production have or will have a material impact on the Eni Group’s results.

After passage of CISADA, Eni engaged in discussions with officials of the U.S. State Department, which administers the ISA, regarding Eni’s activities in Iran. On September 30, 2010, the U.S. State Department announced that the U.S. Government, pursuant to a provision of the ISA added by CISADA that allows it to avoid making a determination of sanctionability under the ISA with respect to any party that provides certain assurances, would not make such a determination with respect to Eni based on Eni’s commitment to end its investments in Iran’s energy sector and not to undertake new energy-related activity. The U.S. State Department further indicated at that time that, as long as Eni acts in accordance with these commitments, we will not be regarded as a company of concern for our past Iran-related activities.

On November 21, 2011, President Barack Obama issued an executive order (the "Iran Executive Order") authorizing sanctions on persons that are determined to have engaged in, after the date of the Iran Executive Order, certain activities in support of Iran’s energy and petrochemicals sector that are not specifically targeted by the ISA as amended by CISADA. Those activities include the provision to Iran of goods, services, technology or support that have a fair market value above certain monetary thresholds and that could directly and significantly contribute to the maintenance or enhancement of Iran’s ability to develop its petroleum resources or to the maintenance or expansion of Iran’s domestic production of petrochemical products. The type of sanctions from which the President may select is essentially identical to those contemplated by the ISA and CISADA, and other aspects of the Iran Executive Order similarly parallel the ISA, as amended by CISADA. As discussed above, pursuant to the Darquain service contract, entered into prior to the date of the Iran Executive Order, Eni is providing services in advance of the hand over to NIOC and has certain technical assistance and service obligations, and an obligation to provide, upon request, spare parts and supplies for the maintenance and operation of the field following hand over to NIOC. Nevertheless, the U.S. State Department has stated that the completion of existing contracts is not sanctionable under the Iran Executive Order. Accordingly, we do not believe that Eni’s activities in Iran are sanctionable under the Iran Executive Order. However, if Eni’s activities in Iran are determined to be targeted activities under the Iran Executive Order, or any of Eni’s activities in Iran are determined to be pursuant to an expansion, renewal or amendment of our pre-existing contracts, or a new contract, Eni may be subject to sanctions thereunder, and Eni has no assurances that the U.S. State Department’s 2010 determination of non-sanctionability under the ISA would similarly extend to sanctions under such Order. If sanctions were imposed, their impact could be material and adverse to Eni.

13

With respect to segments other than Exploration & Production, our Refining & Marketing segment has historically purchased amounts of Iranian crude oil under a term contract with the NIOC and on a spot basis. We purchased 980 ktonnes, 1.63 mmtonnes and 976 ktonnes in 2009, 2010 and 2011, respectively. We paid NIOC $419 million in 2009, $888 million in 2010 and $742 million in 2011 for those purchases.

In addition, in 2009 and 2010 we purchased crude oil from international traders and oil companies who, based on bills of loading and shipping documentation available to us, we believe purchased the crude oil from Iranian companies. Purchases were mainly on spot basis. In 2009, we purchased 278 ktonnes of crude oil amounting to $147 million; in 2010, we purchased 2.09 mmtonnes of crude oil amounting to $1.1 billion.

Eni has no involvement in Iran’s refined petroleum sector and does not export refined petroleum to Iran. In addition, we have occasionally entered into licensing agreement with certain Iranian counterparties for the supply of technologies in the petrochemical sector.

On December 31, 2011, the United States enacted the National Defense Authorization Act for the Fiscal Year 2012 (the "2012 NDAA"), which includes sanctions targeting certain financial transactions involving Iran and in particular its banking institutions, including the Central Bank of Iran. These new sanctions, if fully implemented by the United States, are expected to make purchases of Iranian crude from Iran much more difficult due to the involvement of the Central Bank of Iran in such purchases. On January 23, 2012 the EU adopted a Council decision intended to forbid the import, purchase and transport of Iranian crude oil and petroleum products, except for supply contracts entered into before January 23, 2012 and to be performed not later than July 1, 2012. The decision allows for the supply of Iranian crude oil and petroleum products (or the proceeds derived from their supply) for the reimbursement of outstanding amounts due to entities under the jurisdiction of EU Member States, arisen with respect to contracts concluded before January 23, 2012. We do not believe that any possible termination of our purchases of crude oil from Iran would materially affect our refining and supply operations.

We will continue to monitor closely legislative and other developments in the United States and the European Union in order to determine whether our remaining interests in Iran could subject us to application of either current or future sanctions under the OFAC sanctions, the ISA, the EU Measures or otherwise. If any of our activities in and with respect to Iran are found to be in violation of any Iran-related sanctions, and sanctions are imposed on Eni, it could have an adverse effect on our business, plans to raise financing, sales and reputation.

We have commercial transactions with Syria where we mainly purchase from time to time volumes of crude oil

Our operations in Syria have mainly been limited to transactions carried out by our Refining & Marketing segment with Syrian Petrol Co, an entity controlled by the Syrian Government, for the purchase of crude oil under term purchase contracts or on a spot basis, based on prevailing market conditions.

We purchased 241 ktonnes, 321 ktonnes and 243 ktonnes in 2009, 2010 and 2011, respectively. We paid Syrian Petrol Co $92 million in 2009, $163 million in 2010 and $175 million in 2011 for those purchases.

In 2010, we purchased 115 ktonnes of crude oil amounting to $59 million and 165 ktonnes of crude oil amounting to $123 million in 2011, in each case from international traders who, based on bills of loading and shipping documentation available to us, we believe purchased those raw materials from Syrian companies.

In 2010, our Engineering & Construction segment was awarded by Dijla Petroleum Co, an affiliate of the Syrian National Oil Company, a contract for the central processing facility to be installed at the Khurbet East oil field, on Block 26.

Other than as described above, Eni is not currently investing in the country, and it has no contractual arrangements in place to invest in the country. However, we have recently been exploring investment opportunities in Syria.

Cyclicality of the Petrochemical Industry

The petrochemical industry is subject to cyclical fluctuations in demand in response to economic cycles, with consequential effects on prices and profitability exacerbated by the highly competitive environment of this industry. Eni’s petrochemical operations have been in the past and may be adversely affected in the future by worldwide economic slowdowns, intense competitive pressures and excess installed production capacity. Furthermore, Eni’s petrochemical operations have been facing increasing competition from Asian companies and national oil companies’ petrochemical divisions which can leverage on long-term competitive advantages in terms of lower operating costs and feedstock purchase costs. Particularly, Eni’s petrochemical operations are located mainly in Italy and Western Europe where the regulatory framework and public environmental sensitivity are generally more stringent than in other

14

countries, especially Far East countries, resulting in higher operating costs of our petrochemical operation compared to the Company’s Asiatic competitors due to the need to comply with applicable laws and regulations in environmental and other related matters. Additionally, our petrochemical operations lack sufficient scale and competitiveness in a number of sites. Due to weak industry fundamentals, intense competitive pressures and high feedstock costs, our petrochemical operations incurred substantial operating losses in recent years. In 2011, our petrochemicals operations reported deeper operating loss compared to the year earlier, down to euro 424 million, due to sharply lower margins which were impaired by higher oil-based feedstock costs, and lower sales volumes which were affected by the economic downturn in the last part of the year. Looking forward, management expects that a weak economic outlook may affect overall demand for our products. Furthermore, continuing escalating costs of crude oil represent a risk to the profitability of the Company’s petrochemical operations as it may be difficult transferring higher feedstock costs to end-prices of products due to the high level of competition in the industry and the commoditized nature of many of Eni’s products.

Risks in the Company Gas & Power business segment

i) Risks associated with the Trading Environment and Competition in the Industry

In 2011, the Company’s results of operations and cash flow were negatively affected by sharply lower unit margins due to increasing competitive pressures arising from large gas availability on the marketplace and weak demand growth. We expect continuing competitive pressures and market imbalances to affect our results in 2012 and beyond

Management expects the outlook in the gas sector in Italy and Europe to remain unfavorable over the short to the medium term. In 2011, gas demand in Europe fell by 10% (down by 6% in Italy) due to the economic downturn, an expansion in the use of renewable sources, a shift to coal in thermoelectric production due to cost advantages, as well as unusual weather conditions. The profitability of the gas sector in 2011 was severely hit by reduced demand, oversupply and the high rate of liquidity at the continental hubs. Reduced sales opportunities forced operators to aggressively compete on pricing, particularly those operators which were exposed the most to take-or-pay supply contracts. On their part, large clients adopted opportunistic supply patterns, in order to take advantage of the large availability of spot gas on the marketplace. These drivers led to a squeeze in marketing margins due to decoupling trends between on one hand the rising cost of gas supplies that are indexed to the price of oil and its derivatives as provided by pricing formulas in long-term supply contracts, on the other hand weak selling prices at continental hubs which have become the prevailing benchmark in selling contracts. In Italy competitive pressures dragged down gas margins, too. Against this backdrop, Eni’s gas marketing business reported operating losses down to euro 710 million, reversing the prior-year profit of euro 555 million.

Management forecasts that weak gas demand due to the current economic downturn, the persistence of oversupplies on the marketplace and strong competition will represent risk factors to the profitability outlook of the Company gas marketing business over the next two to three years. Short-term perspectives are anticipated to be extremely unfavorable in Italy where the economic recovery is feeble, risks are ongoing of gas being replaced by coal in the thermoelectric production as well as renewables, and finally gas margins are expected to be pressured by recently announced liberalization measures by the Italian Government intended to reduce the cost of gas to residential users (see below). Furthermore, management expects that the price of gas to industrial and other large clients will progressively converge to the pricing level at the continental hubs. It is likely that those trends will negatively impact the Marketing business future results of operations and cash flows by pressuring gas margins, also considering Eni’s obligations under its take-or-pay supply contracts (see below).

We expect that current imbalances between demand and supply in the European gas market will persist for sometime

Management estimates that gas demand will grow at an average rate of approximately 2% in Italy and Europe till 2020. Those estimates have been revised downward from previous management projections to factor in the risks associated with a number of ongoing trends:

• uncertainties and volatility in the macroeconomic cycle; particularly the current downturn in Europe will weigh on the short-term perspectives of a rapid recovery in gas demand;

• growing adoption of consumption patterns and life-styles characterized by wider sensitivity to energy efficiency; and

• EU policies intended to reduce GHG emissions and promote renewable energy sources. For further information about the Company’s outlook for gas demand see "Item 4 – Gas & Power".

The projected moderate dynamics in demand will not be enough to balance current oversupplies on the marketplace over the next two to three years according to management’s estimates. Gas oversupplies have been increasing in recent years as new, large investments to upgrade import pipelines to Europe have come online from

15

Russia, Libya and Algeria, and large availability of LNG on a worldwide scale has found an outlet at the European continental hubs driving the development of very liquid spot gas markets. Furthermore, in the near future management expects the start-up of new infrastructures in various European entry points which will add approximately 50-60 BCM of new import capacity over the next few years. Those include the Medgaz pipeline connecting Algeria to the Iberian Peninsula, the Nord Stream pipeline connecting Russia to Germany through the Baltic Sea as well as new LNG facilities, particularly a new plant is set to commence operations in the Netherlands with a process capacity of up to 12 BCM. Further 27 BCM of new supplies will be secured by a second line of the Nord Stream later and new storage capacity will come online. In Italy, the gas offered will increase moderately in the next future as a new LNG plant is expected to start operations at Livorno with a 4 BCM treatment capacity and effects are in place of Law Decree No. 130/2010 about storage capacity (see below) which is expected to increase by 4 BCM by 2015. In addition the GreenStream pipeline is expected to achieve full operations in 2012 and gas supplies from Libya will be restarted. These developments will be tempered by an expected increase in worldwide gas demand driven by economic growth in China and other emerging economies, a slowdown in additions of new worldwide LNG capacity, and mature field decline in Europe.

Those trends represent risks to the Company’s future results of operations and cash flows in its gas business, particularly our internal forecast about a rebalancing between demand and supplies in Europe which we expect by the end of our four-year industrial plan. See "Item 4 – Gas & Power" for further information about our long-term expectations on gas demand and supply.

Current, negative trends in gas demands and supplies may impair the Company’s ability to fulfill 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 of supplying the Italian gas market, Eni has signed a number of long-term gas supply contracts with key producing countries that supply the European gas markets. These contracts have been ensuring approximately 80 BCM of gas availability from 2010 (including the Distrigas portfolio of supplies and excluding Eni’s other subsidiaries and affiliates) with a residual life of approximately 17 years and a pricing mechanism that indexes the cost of gas to the price of crude oil and its products (gasoil, fuel oil, etc.). These contracts provide take-or-pay clauses whereby the Company is required to collect minimum pre-determined 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, applied to uncollected volumes up to the minimum contractual quantity. The take-or-pay clause entitles the Company to collect pre-paid volumes of gas in later years during the period of contract execution. Amounts of cash pre-payments and time schedules for collecting pre-paid gas vary from contract to contract. Generally speaking, cash pre-payments are calculated on the basis of the energy prices current in the year of non-fulfillment with the balance due in the year when the gas is actually collected. Amounts of pre-payments range from 10 to 100 percent of the full price. The right to collect pre-paid gas expires within a ten-year term in some contracts or remains in place until contract expiration in other arrangements. In addition, rights to collect pre-paid gas in future years can be exercised provided that the Company has fulfilled its minimum take obligation in a given year and within the limit of the maximum annual quantity that can be collected in each contractual year. In this case, Eni will pay the residual price calculating it as the percentage that complements 100%, based on the arithmetical average of monthly base prices current in the year of the off-take. Similar considerations apply to ship-or-pay contractual obligations.

Management believes that the current outlook for weak gas demand growth and large gas availability on the marketplace, the possible evolution of sector-specific regulation, as well as strong competitive pressures on the marketplace represent risk factors to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts.

Since the beginning of the downturn in the European gas market late in 2009, Eni has incurred the take-or-pay clause as the Company collected lower volumes than its minimum take obligations in each of those years accumulating deferred costs for an amount of euro 2.22 billion (net of limited amounts of volume make-up) and has paid the associated cash advances amounting to euro 1.76 billion, being the difference between said amounts the payable towards gas suppliers outstanding as of the balance sheet date in 2011.

Considering ongoing market trends and the Company’s outlook for its sales volumes which are anticipated to grow at a moderate pace to 2015, as well as the benefit associated with contract renegotiations which may temporarily reduce the annual minimum take, management believes that it is likely that in the next two to three years Eni will fail to fulfill its minimum take obligations associated with its supply contracts thus triggering the take-or-pay clause and the obligation to pay cash advances in relation to substantial amounts of gas.

In case Eni fails to off-take the contractual minimum amounts, it will be exposed to a price risk, because the purchase price Eni will ultimately be required to pay is based on prices prevailing after the date on which the off-take obligation arose. In addition, Eni is subject to the risk of not being able to dispose of pre-paid volumes. The Company also expects to incur financing costs to pay cash advances corresponding to contractual minimum amounts. As a result, the Company’s selling margins, results of operations and cash flow may be negatively affected.

16

For further information on the Company’s take-or-pay contracts see "Item 4 – Gas & Power – Purchases".

Eni plans to increase natural gas sales in Europe. If Eni fails to achieve projected growth targets, this could adversely impact future results of operations and liquidity

Over the medium term, Eni plans to increase its natural gas sales in Europe leveraging on its natural gas availability under take-or-pay purchase contracts, availability of transport rights and storage capacity, and widespread commercial presence in Europe. Should Eni fail to increase natural gas sales in Europe as planned due to poor strategy execution or competition, Eni’s future growth prospects, results of operations and cash flows might be adversely affected also taking account that Eni might be unable to fulfill its contractual obligations to purchase certain minimum amounts of natural gas based on its take-or-pay purchase contracts currently in force.

ii) Risks associated with sector-specific regulations in Italy

The natural gas market in Italy is highly regulated in order to favor the opening of the market and development of competition

The main aspects of the Italian gas sector regulations are rules to access to infrastructures (transport backbones, storage fields, distribution networks and LNG terminals), criteria to establish tariffs for transport, distribution, re-gasification and storage services and the functional unbundling of undertakings owning and managing gas infrastructures which prevent a controlling entity from interfering in the decision-making process of such undertakings. Also the Italian Authority for Electricity and Gas ("AEEG") is entrusted with certain powers in the matters of approving specific codes for each regulated activity, and monitoring natural gas prices and setting pricing mechanisms for supplies to users which are entitled to be safeguarded in accordance with applicable regulations. Those clients which mainly include households and residential customers (services, hospitals, large retailers, small commercial activities, etc.) have right to obtain gas from their suppliers at a regulated tariff set by the Authority (see below).

Law Decree No. 1 enacted by the Italian Government on January 24, 2012, the so called Liberalization Decree, is expected to have major impacts on the Italian gas sector, including an obligation on part of Eni to divest its interest in Snam (see below).

In 2011, new legislation went into effect which implemented a mechanism of market shares as per Legislative Decree No. 130 of August 13, 2010. This legislation replaced the previous system of antitrust thresholds defined by Legislative Decree No. 164 of May 23, 2000. The new decree has introduced a 40% ceiling to the wholesale market share of every Italian gas operator that inputs gas into the Italian backbone network. This ceiling is raised to 55% for Eni, having it committed itself to build new storage capacity in Italy for a total of 4 BCM within five years from the enactment of the decree. In case of violation of the mandatory thresholds, the law provides for a mandatory gas release at regulated prices up to 4 BCM over a two-year period following the ascertainment of the ceiling breach.

Eni believes that this new gas regulation will increase the competitiveness of the wholesale natural gas market in Italy.

Risks associated with the regulatory powers entrusted to the Italian Authority for Electricity and Gas in the matter of pricing to residential customers

The Authority for Electricity and Gas is entrusted with certain powers in the matters of natural gas pricing. Specifically, the Authority for Electricity and Gas holds a general 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 consuming less than 50,000 CM/y (qualified as non eligible customers as of December 31, 2002 as defined by Legislative Decree No. 164/2000 recently modified by Resolution ARG/gas No. 71/2011) taking into account the public goal of containing the inflationary pressure due to rising energy costs. Accordingly, decisions of the Authority for Electricity and Gas 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 indexation mechanism set by the Authority for Electricity and Gas with Resolution No. 64/2009 basically provides that the cost of the raw material in pricing formulas to the residential sector be indexed to movements in a basket of hydrocarbons. In 2010, the Authority for Electricity and Gas with Resolution ARG/gas 89/10 amended that indexation mechanism and established a fixed reduction of 7.5% of the raw material cost component in the final price of supplies to residential users in the thermal year October 1, 2010-September 30, 2011. This resolution negatively affected Eni’s results of operations in its gas marketing business for fiscal year 2011.

Again in 2011 with Resolution ARG/gas 77/11, the AEEG provided a reduction of 6.5% of the raw material cost component for the thermal year October 1, 2011-September 30, 2012. The resolution will negatively affect Eni’s results

17

of operations and cash flows in 2012. The Company believes that it is possible that in the near future the AEEG could enact new measures that will impact the indexation mechanism of the cost of gas in supplies to residential customers.

In particular the Italian decree on liberalizations puts the AEEG in charge of gradually introducing reference to the price of certain benchmarks quoted at continental hubs in the indexation mechanism of the cost of gas in the pricing of sales to the above mentioned customers. Management believes that this new pending rule will negatively affect the profitability of the Company sales in those market segments because currently and for years to come the prices at continental hubs are lower than the oil-linked prices that to date have been used to set prices for residential customers.

Due to the regulated access to natural gas transport infrastructures in Italy, Eni may not be able to sell in Italy all the natural gas volumes it planned to import and, as a consequence, the Company may be unable to sell all the natural gas volumes which it is committed to purchase under take-or-pay contract obligations

Other risk factors deriving from the regulatory framework are associated with the regulation of access to the Italian gas transport network that is currently set by Decision No. 137/2002 of the Authority for Electricity and Gas. The decision is fully-incorporated into the network code presently in force. The decision sets priority criteria for transport capacity entitlements at points where the Italian transport network connects with international import pipelines (the so-called entry points to the Italian transport system). Specifically, operators that are party to take-or-pay contracts, such as Eni, are entitled to a priority right in allocating available transport capacity within the limit of average daily contractual volumes. Gas volumes exceeding average daily contractual volumes get no priority right. In case of congestion at any entry points, such volumes are entitled to available capacity on a proportionate basis together with all pending requests for capacity assignments. Under its take-or-pay purchase contracts, Eni may off-take daily volumes in excess of average daily contractual volumes. This flexibility is important to Eni’s commercial programs as it is used when demand peaks, usually during the wintertime. Eni believes that Decision No. 137/2002 is in contrast with the rationale of the European regulatory framework on the gas market as provided by European Directive No. 2003/55/EC. The Company, based on that belief, has commenced an administrative procedure to repeal Decision No. 137/2002 before an administrative Court which recently confirmed in part Eni’s position. An administrative appeal court has also confirmed the Company’s position. Specifically, the Court stated that the purchase of the contractual flexibility is an obligation on part of the importer, which responds to a collective interest. According to the Court, there is no reasonable motivation whereby volumes corresponding to such contractual flexibility should not be granted a priority right in accessing the network in case congestion occurs. At the moment, however, no case of congestion occurred at entry points to the Italian transport infrastructure so as to impair Eni’s marketing plans.

Management believes that Eni’s results of operations and cash flows could be adversely affected should a combination of market conditions and regulatory constraints prevent Eni from fulfilling its minimum take contract obligations. See "Item 5 – Outlook".

The Italian Government has taken steps to increase competition in the Italian natural gas market, including a mandatory disposal of Eni’s interest in Snam. Such regulatory developments may adversely affect Eni’s results of operations and cash flows

Italian administrative and governmental institutions and political forces have been arguing for a higher degree of competition in the Italian natural gas market and this may produce significant developments in this area.

Particularly, both the Italian Authority for Electricity and Gas and the Italian Antitrust Authority (the “Antitrust Authority”) have conducted several reviews and inquiries on the status of the Italian natural gas market, targeting the overall level of competition, the degree of opening to competition of the residential sector, levels of entry-exit barriers, and other areas such as sub-investment in the storage sector. Both the Authority for Electricity and Gas and the Antitrust Authority have concluded that the vertical integration of Eni in the supply, transport, distribution, storage and marketing of gas may hamper development of a competitive gas market in Italy.

On January 24, 2012, the Italian Government enacted Law Decree No. 1, the so called Liberalization Decree, establishing new measures to enhance competition in the Italian natural gas market. The Decree was promulgated by the Italian Parliament at the end of March 2012. In addition to the above mentioned provision about the adoption of a more competitive pricing mechanism in supplies to residential customers, the Decree opened up the process of mandatory divestiture of Eni’s interest in Snam. The Decree calls for the Italian Prime Minister to promulgate an act to set criteria, terms and conditions of the divestment, including the residual stake that Eni is allowed to retain in the divested entity. These criteria, terms and conditions are expected by the end of May 2012.

Management believes the institutional debate on the degree of competition in the Italian natural gas market and the regulatory activity to be critical and cannot exclude negative impacts deriving from developments on these matters on Eni’s future results of operations and cash flows.

18

For more information on these issues see "Item 4 – Regulation – Gas & Power".

Antitrust and competition law

The Group’s activities are subject to antitrust and competition laws and regulations in many countries of operations, especially in Europe. In the years prior to 2008, Eni recorded significant loss provisions due to unfavorable developments in certain antitrust proceedings before the Italian Antitrust Authority, and the European Commission. It is possible that the Group may incur significant loss provisions in future years relating to ongoing antitrust proceedings or new proceedings that may possibly arise. The Group is particularly exposed to this risk in its natural gas, refining and marketing and petrochemicals activities due to the fact that Eni is the incumbent operator in those markets in Italy and a large European player. In 2011 we accrued a risk provision amounting to euro 69 million to take into account a sentence of an European judicial authority regarding a charge against the Company involving alleged anti-competitive practices in the field of elastomers in the petrochemicals sector. See “Item 18 – Note 34 to the Consolidated Financial Statements” for a full description of Eni’s main pending antitrust proceedings. Furthermore, based on the findings of antitrust proceedings, plaintiffs could seek payment to compensate for any alleged damages as a result of antitrust business practices on part of Eni. Both these risks could adversely affect the Group’s future results of operations and cash flows.

Environmental, Health and Safety Regulation

Eni may incur material operating expenses and expenditures in relation to compliance with applicable environmental, health and safety regulations

Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil and gas operations, products and other activities. Generally, these laws and regulations require the 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, as well as refining, petrochemicals and other Group 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 oil, natural gas, refining, petrochemical and other Group’s operations.

These laws and regulations also regulate emissions of substances and pollutants, 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.

Breach of environmental, health and safety laws exposes the Company’s employees to criminal and civil liability and the Company to the incurrence of liabilities associated with compensation for environment health or safety damage 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 can be liable due to negligent or willful conduct on part of its employees as per 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 to comply with laws and regulations addressing safeguard of the environment, safety on the workplace, health of employees and communities involved by the Company operations, including:

• costs to prevent, control, eliminate or reduce certain types of air and water emissions and handle waste and other hazardous materials, including the costs incurred in connection with government action to address climate change;

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

• damage compensation claimed by individuals and entities, including local, regional or state administrations, caused by our activities or accidents; and

• costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging.

In addition, growing public concerns in the EU and globally that rising greenhouse gas emissions and climate change may significantly affect the environment and society could adversely affect our businesses, including the

19

possible enactment of stricter regulations that increase our operating costs, affect product sales and reduce profitability. For more discussion about this topic see "Item 4 – Environmental Regulations".

Furthermore, in the countries where we operate or expect to operate in the near future, new laws and regulations, the imposition of tougher license requirements, increasingly strict enforcement or new interpretations of existing laws and regulations or the discovery of previously unknown contamination may also cause us to incur material costs resulting from actions taken to comply with such laws and regulations, including:

• modifying operations;

• installing pollution control equipment;

• implementing additional safety measures; and

• performing site clean-ups.

As a further result of any new laws and regulations or other factors, we may also have to curtail, modify or cease certain operations or implement temporary shutdowns of facilities, which could diminish our productivity and materially and adversely impact our results of operations, including profits.

Security threats require continuous assessment and response measures. Acts of terrorism against our plants and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people.

Eni has incurred in the past and may incur in the future material environmental liabilities in connection to the environmental impact of its past and present industrial activities. Also plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution

Risks of environmental, health and safety incidences and liabilities are inherent in many of Eni’s operations and products. Notwithstanding management’s beliefs that Eni adopts high operational standards to ensure safety of its operations and to protect the environment and health of people and employees, it is possible that incidents like blow-outs, oil spills, contaminations and similar events could occur that would result in damage to the environment, employees and communities. Environmental laws also require the Company to remediate and clean-up the environmental impacts of prior disposals or releases of chemicals or petroleum substances and pollutants by the Company. Such contingent liabilities may exist for various sites that the Company disposed of, closed or shut down in prior years where the Group products have been produced, processed, stored, distributed or sold, such as chemicals plants, mineral-metallurgic plants, refineries and other facilities. The Company is particularly exposed to the risk of environmental liabilities in Italy due to its past and present activities and because several Group industrial installations are or were localized in Italy. In fact, many environmental liabilities have arisen as the Group engaged in a number of industrial activities that were subsequently divested, closed, liquidated or shut down. At those industrial sites Eni has commenced a number of remedial plans to restore and clean-up proprietary or concession areas that were contaminated and polluted by the Group’s industrial activities in previous years. Notwithstanding the Group claimed that it cannot be held liable for such past contaminations as permitted by applicable regulations in case of declaration rendered by a guiltless owner – particularly regulations that enacted into Italian legislation the Directive No. 2004/35/EC, plaintiffs and several public administrations have been acting against Eni to claim both the environmental damage and measures to perform clean-up and remediation projects in a number of civil and administrative proceedings. In 2010, Eni proposed a global transaction to the Italian Ministry for the Environment related to nine sites of national interest where the Group has been performing clean-up activities in order to define the scope of work of each clean-up project and settle all pending administrative and civil litigation. To account for this proposal, the Group accrued a pre-tax risk provision amounting to euro 1.1 billion in its 2010 Consolidated Financial Statements. Discussions with the Italian Ministry for the Environment are ongoing in order to define all aspects of the proposed transaction.

Remedial actions with respect to other Company’s sites are expected to continue in the foreseeable future, impacting our liquidity as the Group has accrued risk provisions to cope with all existing environmental liabilities whereby both a legal or constructive obligation to perform a clean-up or other remedial actions is in place and the associated costs can be reasonably estimated. The accrued amounts represent the management’s best estimates of the Company’s liability.

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) unfavorable developments in ongoing litigation on the environmental status of certain Company’s site where a number of public administrations and the Italian Ministry for 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 future environmental restoration and remediation programs are often inherently difficult to estimate.

20

Legal Proceedings

Eni is defendant in a number of civil actions and administrative proceedings arising in the ordinary course of business. In addition to existing provisions accrued as of the balance sheet date to account for ongoing proceedings, it is possible that in future years Eni may incur significant losses in addition to amounts already accrued in connection with pending 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. See disclosure of pending litigation in “Item 18 – Note 34 to the Consolidated Financial Statements”.

Risks related to Changes in the Price of Oil, Natural Gas, Refined Products and Chemicals

Operating results in Eni’s Exploration & Production, Refining & Marketing, and Petrochemical segments are affected by changes in the price of crude oil and by the impacts of movements in crude oil prices on margins of refined and petrochemical products.

Eni’s results of operations are affected by changes in international oil prices

Overall, lower oil prices have a net adverse impact on Eni’s results of operations. The effect of lower oil prices on Eni’s average realizations for produced oil is generally immediate. Furthermore, Eni’s average realizations for produced oil differ from the price of Brent crude marker primarily due to the circumstance that Eni’s production slate, which also includes heavy crude qualities, has a lower API gravity compared with Brent crude (when processed the latter allows for higher yields of valuable products compared to heavy crude qualities, hence higher market price).

The favorable impact of higher oil prices on Eni’s results of operations may be offset in part by opposite trends in margins for Eni’s downstream businesses

The impact of changes in crude oil prices on Eni’s downstream businesses, including the Gas & Power, the Refining & Marketing and the Petrochemical businesses, depends upon the speed at which the prices of gas and products adjust to reflect movements in oil prices.

In the Gas & Power segment, increases in oil price represent a risk to the profitability of the Company sales as gas supplies are mainly indexed to the cost of oil and certain refined products, while selling prices, particularly outside Italy, are increasingly benchmarked to gas spot prices quoted at continental hubs. In the current trading environment, spot prices at those hubs are particularly depressed due to oversupply conditions. In 2011 the de-coupling between trends in the oil-linked costs of supplies and spot prices of gas sales was the main driver of the operating loss incurred by our gas marketing business. We expect that such unfavorable trend will continue in 2012 and beyond due to ongoing rising trends in crude oil prices and weak spot prices pressured by sluggish industry fundamentals and competition. In addition, the Italian Authority for Electricity and Gas may limit the ability of the Company to pass cost increases linked to higher oil prices onto selling prices in supplies to residential customers and small businesses as the Italian Authority for Electricity and Gas regulates the indexation mechanism of the raw material cost in selling formulas to those customers. Finally, we expect a negative impact on the profitability of our gas sales to residential customers in Italy due to the possible enactment of the Italian law decree on liberalizations. See the paragraph "Risks in the Company’s gas business" above for more information.

In addition, in light of changes in the European gas market environment, Eni has recently adopted new risk management policies. These policies contemplate the use of derivative contracts to mitigate the exposure of Eni’s future cash flows to future changes in gas prices; such exposure had been exacerbated in recent years by the fact that spot prices at European gas hubs have ceased to track the oil prices to which Eni’s long-term supply contracts are linked. These policies also contemplate the use of derivative contracts for speculative purposes whereby Eni will seek to profit from opportunities available in the gas market based, among other things, on its expectations regarding future prices. These contracts may lead to gains as well as losses, which, in each case, may be significant. All derivative contracts that are not entered into for hedging purposes in accordance with IFRS will be accounted through profit and loss, resulting in higher volatility of the gas business’ operating profit. Please see “Item 5 – Financial Review – Management’s Expectations of Operations” and “Item 11 – Quantitative and Qualitative Disclosures About Market Risk”.

In the Refining & Marketing and Petrochemical businesses a time lag exists between movements in oil prices and in prices of finished products.

21

Eni’s results of operations are affected by changes in European refining margins

Results of operations of Eni’s Refining & Marketing segment are substantially affected by changes in European refining margins which reflect changes in relative prices of crude oil and refined products. The prices of refined products depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather. Furthermore, Eni’s realized margins are also affected by relative price movements of heavy crude qualities versus light crude qualities, taking into account the ability of Eni’s refineries to process complex crudes that represent a cost advantage when market prices of heavy crudes are relatively cheaper than the marker Brent price. In 2011, Eni’s refining margins were unprofitable as the high cost of oil was only partially transferred to final prices of fuels at the pump pressured by weak demand, high worldwide and regional inventory levels and excess refining capacity particularly in the Mediterranean area. Management does not expect any significant recovery in industry fundamentals over the short to medium term. The sector as a whole will continue to suffer from weak demand and excess capacity, while the cost of oil feedstock may continue rising and price differentials may remain compressed. In this context, management expects that the Company’s refining margins will remain at unprofitable levels in 2012 and possibly beyond. In addition, due to a reduced outlook for refining margins and the persistence of weak industry fundamentals, management took substantial impairment charges amounting to euro 645 million before tax to align the book value of the Company’s refining plants to their lower values-in-use which impacted 2011 results of operations.

Eni’s results of operations are affected by changes in petrochemical margins

Eni’s margins on petrochemical products are affected by trends in demand for petrochemical products and movements in crude oil prices to which purchase costs of petroleum-based feedstock are indexed. Given the commoditized nature of Eni petrochemical products, it is difficult for the Company to transfer higher purchase costs for oil-based feedstock to selling prices to customers. In 2011, Eni’s petrochemicals business reported wider operating losses down to euro 424 million due to sharply lower margins on basic petrochemicals products, mainly the margin on cracker, reflecting rising oil costs and as demand for petrochemicals commodities plunged in the last quarter of the year dragged down by the economic downturn. Rising oil-based feedstock costs will continue to negatively affect Eni’s results of operations and liquidity in this business segment in 2012.

Risks from Acquisitions

Eni constantly monitors the oil and gas market in search of opportunities to acquire individual assets or companies in order to achieve its growth targets or complement its asset portfolio. Acquisitions entail an execution risk – a significant risk, among other matters, 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. We also may incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets we acquire. If the integration and financial risks connected to acquisitions materialize, our financial performance 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 is higher. Accordingly, the results of operations of the Gas & Power segment and, to a lesser extent, the Refining & Marketing segment, as well as the comparability of results over different periods may be affected by such changes in weather conditions. In general, the effects of climate change could result in less stable weather patterns, resulting in more severe storms and other weather conditions that could interfere with our operations and damage our facilities. Furthermore, our operations, particularly offshore production of oil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to our operations and consequent loss or damage of properties and facilities.

Our crisis management systems may be ineffective

We have 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 time frame could prolong the impact of any disruption and could severely affect business and operations. Likewise, we have crisis management plans and capability to deal with emergencies at every level of our operations. If we do not respond or are not seen to respond in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted.

22

Exposure to financial risk

Eni’s business activities are inherently exposed to financial risk. This includes exposure to the market risk, including commodity price risk, interest rate risk and foreign currency risk, as well as liquidity risk, credit risk and country risk.

For a description of Eni’s exposure to Country risk see paragraph "Political considerations" above.

We are engaged in substantial trading and commercial activities in the physical markets. We also use financial instruments such as futures, options, over the counter (OTC) 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. We also use 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 executing 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’s 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 we believe we have 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.

Commodity risk

Commodity risk is the risk associated with fluctuations in the price of commodities which may impact the Group’s results of operations and cash flow. Exposure to commodity risk is both of a strategic and commercial nature. Generally, the Group does not hedge its strategic exposure to 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 is not covered by contracted sales, its refining margins and other activities. For further discussion on this issues see paragraph "Changes in crude oil and natural gas prices may adversely affect Eni’s results of operations" above and "Item 11 – Quantitative and Qualitative Disclosures about Market Risk".

On the other hand, the Group actively manages its exposure to commercial risk which arises when a contractual sale of a commodity has occurred or it is highly probable that it will occur and the Group aims at locking in the associated commercial margin. The Group’s risk management objectives are to optimize the risk profile of its commercial activities by effectively managing economic margins and safeguarding the value of Eni assets. Also, as part of its risk management activities from 2011 the Group has commenced trading activities in order to seek to profit from short-term market opportunities. The Group’s risk management has evolved particularly in response to the deep changes occurred in the competitive landscape of the gas marketing business, gas volatile margins and development of liquid gas spot markets.

To achieve those targets, Eni enters into commodity derivatives transactions in both commodity and financial markets:

(i)

to hedge the risk of variability in future cash flows on already contracted or highly probable future sales exposed to commodity risk depending on the circumstance that costs of supplies may be indexed to different market and oil benchmarks compared to the indexing of selling prices. As tight correlation exists between such commodity derivatives transactions and underlying physical contracts, those derivatives are treated in accordance with hedging accounting in compliance with IAS 39, where possible; and

(ii)

to pursue speculative purposes such as altering the risk profile associated with a portfolio of contracts (purchase contracts, transport entitlements, storage capacity) or leveraging any pricing differences in the marketplace, seeking to increase margins on existing assets in case of favorable trends in the commodity pricing environment or seeking a potential profit based on expectations of trends in future prices. The Company also intends to implement strategies of dynamic forward trading in order to maximize the economic value of the flexibilities associated with its assets. Price risks related to asset backed trading activities are mitigated by the natural hedge granted by the assets’ availability.

These contracts may lead to gains as well as losses, which, in each case, may be significant. Those derivatives are accounted for through profit and loss, resulting in higher volatility in Eni’s operating profit, particularly in the gas marketing business.

23

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 denominated in euros. Similarly, prices of Eni’s petrochemical products are generally denominated in, or linked to, the euro, whereas expenses in the Petrochemical segment are denominated both in euros and U.S. dollars. 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 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 the notes or other debt instruments issued by the Company could be downgraded.

Interest rate risk

Interest on Eni’s debt is primarily indexed at a spread to benchmark rates such as the Europe Interbank Offered Rate, “Euribor”, and the London Interbank Offered Rate, “Libor”. As a consequence, movements in interest rates can have a material impact on Eni’s finance expense in respect to its debt. Additionally, spreads offered to the Company may rise in connection with variations in sovereign rating risks or company rating risks, as well as the general conditions of capital markets.

Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace in order to meet short-term financial requirements and to settle obligations. Such a situation would negatively impact the Group results of operations and cash flows as it would result in Eni incurring higher borrowing expenses to meet its obligations or, under the worst conditions, the inability of Eni to continue as a going concern. European and global financial markets are currently subject to volatility amid concerns over the European sovereign debt crisis and the slow-down of the global economy. If there are extended periods of constraints in these markets, or if we are unable to access the markets, including due to our financial position or market sentiment as to our prospects, at a time when cash flows from our business operations may be under pressure, our ability to maintain our long-term investment program may be impacted with a consequent effect on our growth rate, and may impact shareholder returns, including dividends or share price.

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 recent years, the Group has experienced a higher than normal level of counterparty failure due to the severity of the economic and financial downturn. In Eni’s 2011 Consolidated Financial Statements, Eni accrued an allowance against doubtful accounts amounting to euro 171 million, mainly relating the Gas & Power business and to a lesser extent, the Refining & Marketing business. Management believes that both businesses are particularly exposed to credit risks due to their large and diversified customer base which include a large number of middle and small businesses and retail customers who are particularly impacted by the current global financial and economic situation.

Critical Accounting Estimates

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

24

notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience and 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 activities, specifically the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and recognition of revenues in the oilfield services construction and engineering businesses. Although management believes these estimates to represent the best outcome of the estimation process, actual results could differ from such estimates, due to, among other things, the following factors: uncertainty, lack or limited availability of information, availability of new informative elements, variations in economic conditions such as prices, costs, other significant factors including evolution in technologies, industrial practices and standards (e.g. removal technologies) and the final outcome of legal, environmental or regulatory proceedings. See “Item 5 – Critical Accounting Estimates”.

Digital infrastructure is an important part of maintaining our operations, and a breach of our 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 our digital infrastructure are critical to maintaining the availability of our business applications, including the reliable operation of technology in our various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. A breach of our digital security, either due to intentional actions or due to negligence, could cause serious damage to business operations and, in some circumstances, could result in injury to people, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs.

Item 4. INFORMATION ON THE COMPANY

History and Development of the Company

Eni SpA with its consolidated subsidiaries engages in the oil and gas exploration and production, gas marketing operations, management of gas infrastructures, power generation, petrochemicals, oilfield services and engineering industries. Eni has operations in 85 countries and 78,686 employees as of December 31, 2011.

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.

Eni’s registered head office is located at Piazzale Enrico Mattei 1, Rome, Italy (telephone number: +39-0659821). Eni branches are located in:

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

• San Donato Milanese (Milan), Piazza Ezio Vanoni, 1.

Internet address: eni.com

The name of the agent of Eni in the United States is Salzano Pasquale, 485 Madison Avenue, New York, NY 10002.

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 41 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the United States, Kazakhstan, Russia, Algeria, Australia, Venezuela, Iraq and Mozambique. In 2011, Eni average daily production amounted to 1,523 KBOE/d on an available for-sale basis. As of December 31, 2011, Eni’s total proved reserves amounted to 7,086 mmBOE; proved reserves of subsidiaries totaled 5,940 mmBOE; Eni’s share of reserves of equity-accounted entities were 1,146 mmBOE. In 2011, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 29,121 million and operating profit of euro 15,887 million.

25

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, managing gas infrastructures for transport, distribution, storage, re-gasification of natural gas, and LNG supply and marketing. This segment also includes the activity of power generation that is ancillary to the marketing of electricity. In 2011, Eni’s worldwide sales of natural gas amounted to 96.76 BCM, including 2.86 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the U.S. Sales in Italy amounted to 34.68 BCM, while sales in European markets were 52.98 BCM that included 3.24 BCM of gas sold to certain importers to Italy.

Through Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipelines for natural gas transport that is approximately 32,000-kilometer long, while outside Italy, Eni holds capacity entitlements on a network of European high pressure pipelines which transport gas produced in Russia, Algeria, Libya and North Europe production basins to European markets. Snam, through its 100 percent-owned subsidiary Italgas and other subsidiaries, engages in the distribution of natural gas in Italy serving 1,330 municipalities through a low pressure network consisting of approximately 50,300 kilometers of pipelines as of December 31, 2011. Snam, through its wholly-owned subsidiary Stoccaggi Gas Italia (Stogit) operates in natural gas storage activities in Italy through eight storage fields. Eni produces power and steam at its operated sites of Livorno, Taranto, Mantova, Ravenna, Brindisi, Ferrera Erbognone, Ferrara and Bolgiano with a total installed capacity of 5.3 GW as of December 31, 2011. In 2011, sales of power totaled 40.28 TWh. Eni operates a re-gasification terminal in Italy and holds interests or capacity entitlements in a number of LNG facilities in Europe, Egypt and in certain projects in the U.S., one of which is being completed. In 2011, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 34,731 million and operating profit of euro 1,758 million.

Eni’s Refining & Marketing segment engages in crude oil supply, refining and marketing of petroleum products mainly in Italy and in the rest of Europe. In 2011, processed volumes of crude oil and other feedstock amounted to 31.96 mmtonnes and sales of refined products were 45.02 mmtonnes, of which 26.01 mmtonnes in Italy. Retail sales of refined products at operated service stations amounted to 11.37 mmtonnes including Italy and the rest of Europe. In 2011, Eni’s retail market share in Italy through its “eni” and “Agip” branded network of service stations was 30.5%. In 2011, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 51,219 million and operating loss of euro 273 million.

Through its wholly-owned subsidiary Eni Trading & Shipping SpA and certain corporate departments, the Group engages in derivative activities targeting the full spectrum of energy commodities on both the physical and financial trading venues. The objective of this activity is to both hedge part of the Group exposure to the commodity risk and optimize commercial margins by entering speculative derivative transactions. Eni Trading & Shipping SpA and its subsidiaries also provide Group companies with crude oil and products supply, trading and shipping services. The results of this entity are reported within the Gas & Power segment with regard to the results recorded on trading gas and electricity derivatives; while the portion of results which pertains to oil and products trading derivatives and supply and shipping services are reported within the Refining & Marketing segment.

Eni’s Petrochemical activities include production of olefins and aromatics, basic intermediate products, polyethylene, polystyrenes, and elastomers. Eni’s petrochemical operations are concentrated in Italy and Western Europe. In 2011, Eni sold 4.04 mmtonnes of petrochemical products. In 2011, Eni’s Petrochemical segment reported net sales from operations (including inter-segment sales) of euro 6,491 million and an operating net loss of euro 424 million.

Eni engages in oilfield services, construction and engineering activities through its partially-owned subsidiary Saipem and subsidiaries of Saipem (Eni’s interest being 42.92%). Saipem provides a full range of engineering, drilling and construction services to the oil and gas industry and downstream refining and petrochemicals sectors, mainly in the field of performing large EPC (engineering, procurement and construction) contracts offshore and onshore for the construction and installation of fixed platforms, subsea pipe laying and floating production systems and onshore industrial complexes. In 2011, Eni’s Engineering & Construction segment reported net sales from operations (including intra-group sales) of euro 11,834 million and operating profit of euro 1,422 million.

A list of Eni’s subsidiaries is included as an exhibit to this Annual Report on Form 20-F.

Strategy

Eni’s strategy is to increase the Company’s principal businesses over both the medium and the long-term, with improving profitability.

• In the Exploration & Production business we plan to profitably increase oil and gas production and to fully replace produced reserves. We intend to boost returns by strengthening our competitive position in core areas, increasing the volume of operated production and retaining a solid portfolio of long-term plateau fields. We expect that our exploration activities will play a crucial role in supporting reserve replacement and granting the Group the access to new growth opportunities. Our growth plans will benefit from our ongoing

26

	commitment in establishing and consolidating our partnerships with key host Countries, leveraging the Eni co-operation model. Management expects that a continuing focus on technological innovation, risk prevention and operational efficiency will drive increasing rates of reserve recovery and better cost control.
•	We intend to improve the profitability of our operations in the Gas & Power business by a continuing focus on supply flexibility in order to enhance the competitiveness of the Company’s gas offering as we manage through the downturn. This will be achieved by leveraging the economic benefits associated with ongoing renegotiations of our long-term supply contracts, a diversified and flexible supply mix and extracting value from Eni’s logistics assets and its presence at the continental hubs. We intend to drive sales and margin expansion by developing a pan-European commercial platform and a multi-country approach, boosting LNG sales and enhancing our combined offer of gas and electricity. We intend to retain our large base of residential customers in Italy and Europe by continuing service improvement.
•	Our priority in the Refining & Marketing business is to restore profitability against the backdrop of a depressed trading environment. We plan to step up cost reduction initiatives, energy saving and optimization of plant operations, and integration of refinery cycles in order to drive margin expansion. Management plans to implement selective capital projects for upgrading refinery complexity and securing the safety and reliability of our assets. In the marketing business in Italy we plan to enhance profitability through a number of initiatives for improving service quality, client retention and non-oil profit contribution taking into account a negative outlook for fuel consumption. Outside Italy, Eni will grow strategically in target European markets and divest marginal assets.
•	We believe that our Engineering & Construction business is well positioned to deliver continuing revenue and profitability growth leveraging on its strong order backlog, technologically-advanced assets and competencies in engineering and project management and execution in the more valuable segments of large and complex oil and gas developments.
•	In the petrochemical business, we are seeking to restore the economic equilibrium of Polimeri Europa over the medium-term. We plan to revamp our business strategy targeting a gradual reduction of our exposure to the unprofitable, commoditized productions, while growing the Company’s presence in niche productions, which have shown a good resilience in the face of the downturn, and innovative productions in the field of bio-chemicals which are promising attractive growth rates.

In executing this strategy, management intends to pursue integration opportunities among businesses and within them and to strongly focus on efficiency improvement through technology upgrading, cost efficiencies, commercial and supply optimization and continuing process streamlining across all businesses. Over the next four years, Eni plans to execute a capital expenditure program amounting to euro 59.6 billion to support continuing organic growth in its businesses, mainly the Exploration & Production which will absorb 75% of planned expenditures. That amount includes funds destined to joint venture projects and associates.

For the full year 2012, management expects a capital budget in line with the amounts invested in 2011 (in 2011 capital expenditure amounted to euro 13.44 billion, while expenditures incurred in joint venture initiatives and other investments amounted to euro 0.36 billion).

Eni plans to fund these capital expenditure projects mainly by means of cash flows provided by operating activities. Capital projects will be assessed and implemented in accordance with tight financial criteria. Management plans to progressively reduce the ratio of net borrowings to total equity leveraging on projected cash flows from operations at our Brent scenario of $90 a barrel in 2012 and 2013 and then $85 a barrel. We expect to divest certain non-strategic assets; cash from disposals will help the Company achieve the planned reduction in the ratio. Our financial projections factor in the expected cash outs to remunerate Eni’s shareholders in accordance with our dividend policy which is targeting a progressive increase in the dividend in line with the expected inflationary rate in OECD countries. This dividend policy is based on the Company’s planning assumptions for Brent prices and other assumptions (see "Item 5 – Management’s Expectations of Operations" and "Item 3 – Risk Factors").

For fiscal year 2011, management plans to distribute a dividend of euro 1.04 a share subject to approval from the General Shareholders Meeting scheduled on May 8, 2012; the 2011 dividend represents a 4% increase from the previous year.

Further details on each business segment strategy are discussed throughout this Item 4. For a description of risks and uncertainties associated with the Company’s outlook, and the capital expenditure program see "Item 5 – Management’s Expectations of Operations" and "Item 3 – Risk Factors".

In the next four-year period, Eni plans to make expenditures dedicated to technological research and innovation activities amounting to euro 1.1 billion. Management believes that technological developments may secure long-term competitive advantages to the Company. Eni plans to direct most of its planned resources to improve certain technologies which target to maximize the recovery rate of hydrocarbons from reservoirs, optimize well drilling, completion and performance with a view to employing those techniques in challenging environments, design facilities and installations to develop marginal and deep and ultra-deep fields, as well as commercial development of unconventional resources. Projects in refining will target the development of advanced fuels, lubricants and additives to match an expected demand for high quality automotive products in the future, refining process able to maximize

27

product yields and the development of a gasoil enhanced with bio-components. In petrochemicals our efforts will target product innovation in the valuable segment of elastomers and styrene with a view to strengthening the business competitive position. Important resources are planned to be dedicated to such projects that will enhance the degree of environmental preservation and safety of the Company operations by developing renewable sources of energy, particularly in the field of solar and photovoltaic energy, the recycle of urban waste so as to transform it in refining feedstock, carbon capture and sequestration, operations safety and integrity in upstream, and environmental clean-up and remediation.

Significant Business and Portfolio Developments

The significant business and portfolio developments that occurred in 2011 and to date in 2012 were the following:

• in March 2012, we signed a preliminary agreement with Gazprom to revise the terms of the supply contracts of Russian gas to Eni’s operations in Italy. The economic benefits of the agreement will be retroactive from the beginning of 2011 and will be recognized through profit in 2012. For the agreement to become effective, it is necessary that the existing supply contracts be amended, accordingly;

• we made a large gas discovery off the Mozambique coast with the Mamba South 1 exploratory well (Eni operator with a 70% interest), located in Area 4 in the Rovuma Basin. According to field test results and our internal estimates, we believe that the new discovery may contain substantial amounts of reserves. We achieved further important discoveries in the Northern and Eastern areas of the lease with the Mamba North 1 and Mamba North East 1 wells early in 2012;

• on March 29, 2012 Eni signed agreements with Amorim Energia BV and Caixa Geral de Depósitos, SA (“CGD”), according to which Eni will sell a 5% interest in Galp Energia (Eni’s interest being 33.34%) to Amorim Energia and, following the sale, will cease to be bound by the shareholders agreement currently in place between the three companies. Amorim Energia has agreed to purchase the 5% interest in Galp Energia within 150 days. As part of these agreement Eni has the right to sell up to 18%, which could potentially increase by 2% if convertible bonds are issued, of the share capital of Galp Energia in the market. CGD has a tag along right in relation to its shareholding of 1% of the share capital of Galp Energia in connection with the sales carried out by Eni. After the sale of the 18% interest, Eni will also have the right to sell its remaining shares in Galp Energia. In the case of such further sale, Amorim Energia has a call option which gives it the right to purchase, or designate a third party to purchase, up to 5% of the share capital of Galp Energia. With regards to the sale of the remaining 5.34%, Amorim Energia has a right of first refusal under which it can choose to purchase, or designate a third party to purchase, up to 5.34%, if the call option referred to above has been exercised, or 10.34% if the call option referred to above has not been exercised of the share capital of Galp Energia;

• we achieved a rapid recovery in our production levels in Libya which we were forced to shut down most of our production facilities due to a situation of political and social unrest and internal conflict from February through September 2011. By the end of the year we have restarted the majority of our facilities and reopened the GreenStream export gas pipeline to Italy leveraging on the strong commitment of our global organization and continuing supportive relationship with the Interim Transitional National Council of Libya and the National Oil Company. Production at Eni’s Libyan assets is currently flowing at approximately 240 KBOE/d. Eni is targeting to achieve the pre-crisis production plateau of 280 KBOE/d and full ramp-up by the second half of 2012. We estimated that we incurred a production loss of 200 KBOE/d in 2011 as a result of the disruption in our Libyan activities during the Revolution;

• in February 2012, Eni divested a 16.41% interest in Interconnector (UK) Ltd, a 51% interest in Interconnector Zeebrugge Terminal SCRL and a 10% interest in Huberator SA to Snam and Fluxys G. The three companies manage the underwater gas pipeline linking the United Kingdom (Bacton) and Belgium (Zeebrugge), the Zeebrugge compression station near the Interconnector and the Zeebrugge hub trading platform, respectively. The total amount of the transaction is approximately euro 150 million and its finalization is subject to satisfaction of certain conditions. The closing of the transaction is expected by the second half of 2012;

• in January 2012, Eni completed the acquisition of Nuon Belgium NV and Nuon Power Generation Wallon NV that supply gas and electricity to the industrial and residential segments in Belgium for a cash consideration amounting to euro 214 million;

• in December 2011, the Republic of Kazakhstan (RoK) and the contracting companies in the Karachaganak gas-condensate field in north-west Kazakhstan reached an agreement to settle all pending claims relating to the recovery of costs incurred to develop the field, as well as a number of minor tax disputes. The agreement will support the further development of the field. The agreement, effective from June 30, 2012 on satisfaction of conditions precedent, involves Kazakhstan’s KazMunaiGas (KMG) acquiring a 10% interest in the project. This will be done by each of the contracting companies transferring 10% of their rights and interest in the Karachaganak Final Production Sharing Agreement (FPSA) to KMG. The contracting companies will receive $1 billion net cash consideration ($325 million being Eni’s share). The effects of the agreement on profit and loss and reserve and production entitlements will be recognized in the 2012 financial statements;

• in 2011, Eni finalized the divestment of its interests in importing pipelines of natural gas from Northern Europe (TENP and Transitgas) and Russia (TAG). The divestments have been agreed upon with the European

28

	Commission as remedial actions to settle an antitrust proceeding in the European gas sector. Total consideration amounted to approximately euro 1.5 billion. Eni ship-or-pay contracts will be unaffected; and
•	in June 2011, through its subsidiary Polimeri Europa, Eni signed a cooperation agreement with Novamont SpA to convert Eni’s Porto Torres chemical plant into an innovative bio-based chemical complex to produce bio-plastics and other bio-based petrochemical products (bio-lubricants and bio-additives) for which significant growth is expected in the medium-long term.

In addition, in 2011 Eni closed the following transactions:

• in December 2011, Eni and its partner Repsol (50%-50%) signed a Gas Sales Agreement with the Venezuelan state-owned oil company (PDVSA) which paves the way to the development of the Perla gas discovery off the Venezuelan coast. We regard this as a material development to our business due to the importance of the field reserves. The development plan provides for three phases, targeting production of 1.2 mmCF/d at peak. The investment plan for the first development phase is estimated at $1.4 billion (gross). The national oil company PDVSA is entitled to acquire a 35% interest in the development project by proportionally diluting the interest of each of the international partners;

• in December 2011, Eni and the Angolan authorities signed a Production Sharing Contract for the exploration of Block 35;

• in November 2011, Eni was awarded two operated gas exploration contracts: (i) the Arguni I block (Eni’s interest 100%) located onshore and offshore in the Bintuni Basin near a liquefaction facility; and (ii) the North Ganal Block, located offshore Indonesia near the relevant Jangkrik discovery and the Bontang liquefaction terminal, in a consortium with other international oil companies;

• in November 2011, Eni acquired a 32.5% stake in the Evans Shoal gas discovery in the Timor Sea;

• new exploration successes were achieved in the year with the discoveries of Jangkrik North East (Eni operator with a 55% interest) in Indonesia and Skrugard/Havis (Eni’s interest 30%) in the Barents Sea;

• in September 2011, Eni and Gazprom signed a gas sale agreement regarding the gas produced by the joint venture Severenergia (Eni 29.4%) through the development of the Samburgskoye field. The agreement secured a final investment decision for the field development. Start-up is expected in 2012. In addition, the final investment decision of the Urengoskoye field was sanctioned;

• in April 2011, Eni signed a cooperation agreement with Sonatrach to explore for and develop unconventional hydrocarbons, particularly shale gas plays;

• in April 2011, an agreement was signed with Cadogan Petroleum plc for the acquisition of an interest in two exploration and development licenses located in the Dniepr-Donetz Basin, in Ukraine;

• in January 2011, Eni signed a Memorandum of Understanding with CNPC/Petrochina to pursue joint initiatives targeting development of both conventional and unconventional resources in China and outside China.

In 2011, capital expenditures amounted to euro 13,438 million, of which 89% related to Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 7,357 million) deployed mainly in Norway, Kazakhstan, Algeria, the United States, Congo and Egypt, and exploration projects (euro 1,210 million) carried out mainly in Australia, Angola, Mozambique, Indonesia, Ghana, Egypt, Nigeria and Norway; (ii) the development and upgrading of Eni’s natural gas transport and distribution network in Italy (euro 898 million and euro 337 million, respectively) as well as development and increase of storage capacity (euro 294 million); (iv) projects aimed at improving the conversion capacity and flexibility of refineries, and at building and upgrading service stations in Italy and outside Italy (totaling euro 629 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,090 million). There were no significant acquisitions in the year.

In 2010, capital expenditures amounted to euro 13,870 million, of which 87% related to Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 8,578 million) deployed mainly in Egypt, Kazakhstan, Congo, the United States and Algeria, and exploration projects (euro 1,012 million) carried out mainly in Angola, Nigeria, the United States, Indonesia and Norway; (ii) the development and upgrading of Eni’s natural gas transport and distribution network in Italy (euro 842 million and euro 328 million, respectively) as well as development and increase of storage capacity (euro 250 million); (iv) projects aimed at improving the conversion capacity and flexibility of refineries, and at building and upgrading service stations in Italy and outside Italy (totaling euro 692 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,552 million). There were no significant acquisitions in the year.

In 2009, capital expenditures amounted to euro 13,695 million, of which 86% related to the Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 7,478 million) deployed mainly in Kazakhstan, the United States, Egypt, Congo, Italy and Angola, and exploration projects (euro 1,228 million) carried out mainly in the United States, Libya, Egypt, Norway and Angola; (ii) the acquisition of proved and unproved properties amounting to euro 697 million mainly related to the acquisition of a 27.5% interest in assets with gas shale reserves from Quicksilver Resources Inc and extension of the duration of oil and gas properties in Egypt following the agreement signed in May 2009; (iii) the development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 919 million and euro 278 million, respectively) as well as the development and increase of the storage capacity (euro 282 million); (iv) projects aimed at

29

improving the conversion capacity and flexibility of refineries, and at building and upgrading service stations in Italy and outside Italy (totaling euro 608 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,630 million).

In 2009, Eni’s acquisitions amounted to euro 2.32 billion and mainly related to the completion of the acquisition of Distrigas NV. Following the acquisition of the 57.243% majority stake in the Belgian company Distrigas NV from French company Suez-Gaz de France, Eni made an unconditional mandatory public takeover bid on the minorities of Distrigas (42.76% stake). On March 19, 2009, the mandatory tender offer on the minorities of Distrigas was finalized. Shareholders representing 41.61% of the share capital of Distrigas, including the second largest shareholder, Publigaz SCRL with a 31.25% interest, tendered their shares. The squeeze-out of the residual 1.14% of the share capital was finalized on May 4, 2009. After this, Distrigas shares have been delisted from Euronext Brussels. The total cash consideration amounted to approximately euro 2.05 billion.

.

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 41 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the United States, Kazakhstan, Russia, Algeria, Australia, Venezuela, Iraq and Mozambique. In 2011, Eni average daily production amounted to 1,523 KBOE/d on an available for-sale basis. As of December 31, 2011, Eni’s total proved reserves amounted to 7,086 mmBOE; proved reserves of subsidiaries totaled 5,940 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 1,146 mmBOE.

Eni’s strategy in its Exploration & Production operations is to pursue profitable production growth leveraging on strengthening its leadership in core areas, increasing the volume of operated production and retaining a stable portfolio of long-term plateau fields. We plan to achieve a compound average growth rate in our production of over 3% in the next 2012-2015 four-year period, targeting a production plateau of 2.03 mmBOE/d in 2015. The growth rate has been calculated excluding the impact of disruptions in Libya on the 2011 baseline production. These targets are based on our long-term Brent price assumption of 85 $/BBL. The production outlook for 2012 is based on a progressive recovery in the Company’s Libyan output to achieve the pre-crisis level, coming fully online by the second half of 2012. For further information on this issue as well as certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices see "Item 5 – Management’s Expectations of Operations" and "Item 3 – Risk Factors".

Management plans to achieve the target production plateau in 2015 by continuing development activities and new project start-ups in the main countries of operations including Nigeria, Angola, Norway, Venezuela, the Yamal Peninsula in Russia and Kazakhstan, leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. Over the next four years, we estimate that the main projects due to come onstream will add 700 KBOE/d of production, 80% of which will come from large projects characterized by a steady and long-lasting production plateau.

Management plans to maximize the production recovery rate at our current fields by counteracting natural field depletion. This will require intense development activities of work-over and infilling. We expect that continuing technological innovation and competence build-up will drive increasing rates of reserve recovery. We plan to invest approximately euro 37.6 billion in our development activities over the next four years. An important part of these expenditures will be allocated to certain development projects which will support the Company’s long-term production plateau, particularly we plan to start developing the recent gas discovery offshore Mozambique and to progress large and complex projects in the Barents Sea, Nigeria and Indonesia. We are also planning to maintain a prevailing share of projects regulated by production sharing agreement in our portfolio; this will shorten the cost recovery in an environment of high crude oil prices.

Approximately euro 1.7 billion will be spent to build transportation infrastructures and LNG projects through equity-accounted entities.

Exploration projects will attract some euro 5.5 billion to appraise the latest discoveries made by the Company and to support continuing reserve replacement over the next four years. The most important amounts of exploration expenses will be incurred in Mozambique, the United States, Egypt, Nigeria, Angola, Norway and Indonesia; important resources will be dedicated to explore new areas in Sub-Saharan Africa (the Republic of Liberia, Ghana) and on unconventional plays. Management plans to achieve a balance between exploration projects in conventional fields vs. projects in high risk/high reward basins.

30

Management intends to implement a number of initiatives to support profitability in its upstream operations by exercising tight cost control and reducing the time span which is necessary to develop and market reserves. We expect that costs to develop and operate fields will increase in the next years due to sector-specific inflation, and growing complexity of new projects. We plan to counteract those cost increases by leveraging on cost efficiencies associated with: (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 projects where we serve as operator. 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.

Eni will pursue further growth options by developing unconventional plays, gas-to-LNG projects and integrated gas projects. Eni’s growth plans will be supported by its ongoing commitment in establishing and consolidating its partnerships with key host Countries, leveraging the Eni co-operation model.

Finally, we intend to optimize our portfolio of development properties by focusing on areas where our presence is well established, and divesting non-strategic or marginal assets.

For the year 2012, management plans to spend euro 9.6 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 and 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 and 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 and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve 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 Production Sharing Agreements (PSAs) are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and on 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 reserve governance. The Reserves Department of the Exploration & Production segment is entrusted with the task 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.

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

(1) i See "Item 19 – Exhibits" in the Annual Report on Form 20-F 2009.

31

practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by others 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 of estimating and classifying gross reserves including assessing production profiles, capital expenditures, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department at the head office verifies the production profiles of such properties where significant changes have occurred; (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 Division Reserves Evaluators (DRE), 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 Reserve Department attended the "Politecnico di Torino" and received a Master of Science degree in Mining Engineering in 1985. She has more than 20 years of experience in the oil and gas industry and more than 10 years of experience in evaluating reserves.

Staff involved in the reserves evaluation process fulfils the professional qualifications requested and maintains the highest level of independence, objectivity and confidentiality in accordance with professional rules of conduct. Reserves Evaluators qualifications comply with international standards established 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 reserve audit is included in the third party audit report³. In the preparation of their reports, independent evaluators rely, without independent verification, upon information furnished by Eni with respect to property interests, production, current costs of operations 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, technical analysis relevant to field performance, long-term development plans, future capital and operating costs.

In order to calculate the economic 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 2011 Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of 32% of Eni’s total proved reserves at December 31, 2011⁴, confirming, as in previous years, the reasonableness of Eni internal evaluation⁵.

In the 2009-2011 three year period, 85% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2011, the principal Eni property not subjected to independent evaluation in the last three years was Kashagan (Kazakhstan).

(2)	i	From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott.
(3)	i	See "Item 19 – Exhibits".
(4)	i	Includes Eni’s share of proved reserves of equity-accounted entities.
(5)	i	See "Item 19 – Exhibits".

32

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, 2011, 2010 and 2009. Net proved reserves are set out in more detail under the heading "Supplementary oil and gas information" on page F-115.

HYDROCARBONS
(mmBOE) Italy Rest
of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves

Consolidated subsidiaries
Year ended Dec. 31, 2009	703	590	1,922	1,141	1,221	236	263	133	6,209
Developed	490	432	1,266	799	614	139	168	122	4,030
Undeveloped	213	158	656	342	607	97	95	11	2,179
Year ended Dec. 31, 2010	724	601	2,096	1,133	1,126	295	230	127	6,332
Developed	554	405	1,215	812	543	139	141	117	3,926
Undeveloped	170	196	881	321	583	156	89	10	2,406
Year ended Dec. 31, 2011	707	630	2,031	1,021	950	230	238	133	5,940
Developed	540	374	1,175	742	482	129	162	112	3,716
Undeveloped	167	256	856	279	468	101	76	21	2,224
Equity-accounted entities
Year ended Dec. 31, 2009			15	22		309	16		362
Developed			12	5		44	13		74
Undeveloped			3	17		265	3		288
Year ended Dec. 31, 2010			23	28		317	143		511
Developed			22	5		43	26		96
Undeveloped			1	23		274	117		415
Year ended Dec. 31, 2011			21	83		656	386		1,146
Developed			19	4		5	26		54
Undeveloped			2	79		651	360		1,092
Consolidated subsidiaries
and equity-accounted entities
Year ended Dec. 31, 2009	703	590	1,937	1,163	1,221	545	279	133	6,571
Developed	490	432	1,278	804	614	183	181	122	4,104
Undeveloped	213	158	659	359	607	362	98	11	2,467
Year ended Dec. 31, 2010	724	601	2,119	1,161	1,126	612	373	127	6,843
Developed	554	405	1,237	817	543	182	167	117	4,022
Undeveloped	170	196	882	344	583	430	206	10	2,821
Year ended Dec. 31, 2011	707	630	2,052	1,104	950	886	624	133	7,086
Developed	540	374	1,194	746	482	134	188	112	3,770
Undeveloped	167	256	858	358	468	752	436	21	3,316

33

LIQUIDS
(mmBBL) Italy Rest
of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves

Consolidated subsidiaries
Year ended Dec. 31, 2009	233	351	895	770	849	94	153	32	3,377
Developed	141	218	659	544	291	45	80	23	2,001
Undeveloped	92	133	236	226	558	49	73	9	1,376
Year ended Dec. 31, 2010	248	349	978	750	788	139	134	29	3,415
Developed	183	207	656	533	251	39	62	20	1,951
Undeveloped	65	142	322	217	537	100	72	9	1,464
Year ended Dec. 31, 2011	259	372	917	670	653	106	132	25	3,134
Developed	184	195	622	483	215	34	92	25	1,850
Undeveloped	75	177	295	187	438	72	40		1,284
Equity-accounted entities
Year ended Dec. 31, 2009			13	7		50	16		86
Developed			10	4		7	13		34
Undeveloped			3	3		43	3		52
Year ended Dec. 31, 2010			19	6		44	139		208
Developed			18	4		5	25		52
Undeveloped			1	2		39	114		156
Year ended Dec. 31, 2011			17	22		110	151		300
Developed			16	4			25		45
Undeveloped			1	18		110	126		255
Consolidated subsidiaries
and equity-accounted entities
Year ended Dec. 31, 2009	233	351	908	777	849	144	169	32	3,463
Developed	141	218	669	548	291	52	93	23	2,035
Undeveloped	92	133	239	229	558	92	76	9	1,428
Year ended Dec. 31, 2010	248	349	997	756	788	183	273	29	3,623
Developed	183	207	674	537	251	44	87	20	2,003
Undeveloped	65	142	323	219	537	139	186	9	1,620
Year ended Dec. 31, 2011	259	372	934	692	653	216	283	25	3,434
Developed	184	195	638	487	215	34	117	25	1,895
Undeveloped	75	177	296	205	438	182	166		1,539

34

NATURAL GAS
(BCF) Italy Rest
of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves

Consolidated subsidiaries
Year ended Dec. 31, 2009	2,704	1,380	5,894	2,127	2,139	814	629	575	16,262
Developed	2,001	1,231	3,486	1,463	1,859	539	506	565	11,650
Undeveloped	703	149	2,408	664	280	275	123	10	4,612
Year ended Dec. 31, 2010	2,644	1,401	6,207	2,127	1,874	871	530	544	16,198
Developed	2,061	1,103	3,100	1,550	1,621	560	431	539	10,965
Undeveloped	583	298	3,107	577	253	311	99	5	5,233
Year ended Dec. 31, 2011	2,491	1,425	6,190	1,949	1,648	685	590	604	15,582
Developed	1,977	995	3,070	1,437	1,480	528	385	491	10,363
Undeveloped	514	430	3,120	512	168	157	205	113	5,219
Equity-accounted entities
Year ended Dec. 31, 2009			14	85		1,487	2		1,588
Developed			12	5		217			234
Undeveloped			2	80		1,270	2		1,354
Year ended Dec. 31, 2010			24	118		1,520	22		1,684
Developed			22	4		214	6		246
Undeveloped			2	114		1,306	16		1,438
Year ended Dec. 31, 2011		2	20	338		3,033	1,307		4,700
Developed			17	4		24	8		53
Undeveloped		2	3	334		3,009	1,299		4,647
Consolidated subsidiaries
and equity-accounted entities
Year ended Dec. 31, 2009	2,704	1,380	5,908	2,212	2,139	2,301	631	575	17,850
Developed	2,001	1,231	3,498	1,468	1,859	756	506	565	11,884
Undeveloped	703	149	2,410	744	280	1,545	125	10	5,966
Year ended Dec. 31, 2010	2,644	1,401	6,231	2,245	1,874	2,391	552	544	17,882
Developed	2,061	1,103	3,122	1,554	1,621	774	437	539	11,211
Undeveloped	583	298	3,109	691	253	1,617	115	5	6,671
Year ended Dec. 31, 2011	2,491	1,427	6,210	2,287	1,648	3,718	1,897	604	20,282
Developed	1,977	995	3,087	1,441	1,480	552	393	491	10,416
Undeveloped	514	432	3,123	846	168	3,166	1,504	113	9,866

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 647 mmBOE as of December 31, 2011 (683 and 674 mmBOE as of December 31, 2010 and 2009, respectively). Said volumes are not included in reserves volumes shown in the table herein.

Subsidiaries Equity-accounted entities

2009 2010 2011 2009 2010 2011

(mmBOE)

Additions to proved reserves	605		776		183		(296	)	158		644
of which purchases and sales of reserves-in-place	25		(12	)	(7	)	(314	)
Production for the year	(638	)	(653	)	(568	)	(8	)	(9	)	(9	)

Subsidiaries and
equity-accounted entities

2009 2010 2011

(%)

Proved reserves replacement ratio of subsidiaries and equity-accounted entities 96 125 142

Eni’s proved reserves as of December 31, 2011 totaled 7,086 mmBOE (liquids 3,434 mmBBL; natural gas 20,282 BCF) representing an increase of 243 mmBOE, or 3.6%, from December 31, 2010. All sources additions to proved reserves booked in 2011 were 820 mmBOE, of which 176 mmBOE came from Eni’s subsidiaries and 644 mmBOE from Eni’s share of equity-accounted entities.

35

The effect of higher oil prices on reserves entitlements in certain PSAs and service contracts was estimated to be a 97 mmBOE (the Brent prices used in the reserves estimation process was $111 per barrel in 2011 compared to $79 per barrel in 2010). Higher oil prices also resulted in upward revisions associated with improved economics of marginal productions.

The current SEC rules allow for use of technologies, to estimate proved reserves if such technologies produce consistent and repeatable results. No material quantities were booked under current rules incremental to quantities allowable under former SEC rules as a result of the expanded range of technologies that may be used in the estimation. The methods (or technologies) used in the proved reserves assessment depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modeling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that include 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).

The reserves replacement ratio for Eni’s subsidiaries and equity-accounted entities was 142% in 2011 (125% in 2010 and 96% in 2009). The reserves replacement ratio was calculated by dividing additions to proved reserves by total production, each as derived from the tables of 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 additions. Management considers the reserve replacement ratio to be an important indicator of the Company’s ability to sustain its growth perspectives. 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, as well as changes in oil and gas prices, political risks and geological and environmental risks. Specifically, in recent years Eni’s reserves replacement ratio has been affected by the impact of higher oil prices on reserves entitlements in the Company’s Production Sharing Agreements and similar contractual schemes. In accordance with such contracts, Eni is entitled to a portion of field reserves, the sale of which should cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to determine year-end amounts of Eni’s proved reserves, the lower the number of barrels necessary to cover the same amount of expenditures. In 2011, this trend resulted in a lower amount of booked reserves associated with the Company’s PSAs as the average oil price used in reserve computation was higher than the previous year. See “Item 3 – Risks associated with exploration and production of oil and natural gas and Uncertainties in Estimates of Oil and Natural Gas Reserves”.

The average reserves life index of Eni’s proved reserves was 12.3 years as of December 31, 2011 which included reserves of both subsidiaries and equity-accounted entities.

Eni’s subsidiaries

Eni’s subsidiaries added 176 mmBOE of proved oil and gas reserves in 2011. This comprised 21 mmBBL of liquids and 863 BCF of natural gas. Additions to proved reserves derived from: (i) extensions, discoveries and others were 71 mmBOE, with major increases booked in the United States, Norway, Angola and Nigeria; (ii) revisions of previous estimates were 106 mmBOE mainly reported in Norway, Italy, Egypt, Kazakhstan and Iraq; (iii) improved recovery were 6 mmBOE mainly reported in Norway and Algeria; (iv) sales of mineral-in-place were 9 mmBOE and resulted from the divestment of assets in Nigeria and the United Kingdom; and (v) acquisitions were approximately 2 mmBOE and related to an additional interest in the Annamaria field in Italy.

Eni’s share of equity-accounted entities

Eni reported an increase of 644 mmBOE in its share of equity-accounted entities’ proved oil and gas reserves in 2011. This comprised 99 mmBBL of liquids and 3,028 BCF of natural gas. Additions to proved reserves derived from: (i) extensions, discoveries and other factors were 520 mmBOE, with major increases booked in Russia and Venezuela; (ii) revisions of previous estimates were 123 mmBOE mainly reported in Russia and Angola; and (iii) improved recovery were 1 mmBOE.

36

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2011 totaled 3,316 mmBOE. At year end, proved undeveloped reserves of liquids amounted to 1,539 mmBBL, mainly concentrated in Africa and Kazakhstan. Proved undeveloped reserves of natural gas amounted to 9,866 BCF, mainly located in Africa, Russia and Venezuela. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,284 mmBBL of liquids and 5,219 BCF of natural gas.

In 2011, total proved undeveloped reserves increased by 495 mmBOE due to new projects sanction and upwards and downwards revisions mainly related to contractual and technical revisions, price effect and portfolio operations. Approximately 500 mmBOE were due to new projects sanctions mainly in Russia, Venezuela and the United States.

During 2011, Eni converted 193 mmBOE of proved undeveloped reserves to proved developed reserves due to development activities, production start-up and revisions. The main reclassification to proved developed reserves mainly related to the following fields/projects: Nikaitchuq (the United States); MLE (Algeria); Denise, Belayim and Taurt (Egypt); M’Boundi (Congo); Zamzama (Pakistan); Kitan (Australia); Karachaganak (Kazakhstan); and Tyrihans (Norway).

In 2011, capital expenditures amounted to approximately euro 1.9 billion and were made to progress the development of proved undeveloped reserves.

Reserves that remain proved undeveloped for five or more years are a result of several physical 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 0.8 BBOE of proved undeveloped reserves have remained undeveloped for five years or more with respect to the balance sheet date, mainly related to: (i) the Kashagan project in Kazakhstan (0.4 BBOE) with a reduction of 120 mmBOE compared to 2010. Development activities are progressing and production start-up is targeted by the end of 2012 or in the early 2013. Such PUD reserves will be produced within the limits of the oil processing capacity that is planned to be available at end of Phase 1. For more details regarding this project please refer to part 1, Item 4, page 52, where the project is disclosed. See also our discussion under the "Risk Factors" section about risks associated with oil and gas development projects on page 9; (ii) some Libyan gas fields (0.27 BBOE) where development completion and production start-up 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; and (iii) other minor projects where development activities are progressing.

Delivery commitments

Eni 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 341 mmBOE from producing assets located in Australia, Egypt, India, Indonesia, Libya, Nigeria, Norway, Pakistan, Tunisia and the United Kingdom.

The sales contracts contain a mix of fixed and variable pricing formulas that are generally referenced 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 and supplies from third parties based on existing contracts. Production will account for approximately 69% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, 2011.

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 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

37

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 2011, oil and natural gas production available for sale averaged 1,523 KBOE/d, down by 13.3% from 2010. This reduction was driven by decreased flow from Eni activities in Libya, which was affected by the shut down of almost all the Company’s plants and facilities including the GreenStream pipeline throughout the peak of the country’s internal crisis (approximately 8 months). In the last part of the year the efforts made to restart the GreenStream pipeline and recover production enabled the Company to bring back online some production, partly offsetting the impact of disruptions (down approximately 200 KBOE/d). Our Libyan production for the year averaged 108 KBOE/d. See also our discussion under the "Risk Factors" section about "Political Considerations – North Africa" on page 11. Performance was also negatively impacted by lower entitlements in the Company’s PSAs due to higher oil prices with an overall effect of approximately 30 KBOE/d compared to the previous year. Net of these effects, production for 2011 was in line with 2010. Ramp-ups and start-ups were offset by lower-than-anticipated growth in Iraq and planned facility downtime.

Liquids production (845 KBBL/d) decreased by 152 KBBL/d, or 15.2% due to production losses in Libya and lower entitlements in the Company’s PSAs as well as lower performance in Angola, Nigeria and the United Kingdom. These negatives were partly offset by start-ups/ramp-ups in: (i) Norway with higher production of the Morvin (Eni’s interest 30%) and Tyrihans (Eni’s interest 6.23%) fields; (ii) Italy, due to start-up of the Guendalina (Eni’s interest 80%) and Capparuccia (Eni’s interest 95%) fields; and (iii) Australia, due to start-up of the Kitan (Eni operator with a 40% interest) field.

Natural gas production (3,763 mmCF/d) decreased by 459 mmCF/d (down 10.9%) due to production losses in Libya and lower performance in the United States. Organic growth was achieved in: (i) Congo and Norway due to better performance; and (ii) Egypt, due to start-up of Denise B (Eni’s interest 50%) field and better performance of Tuna (Eni operator with a 50% interest) field.

Oil and gas production sold amounted to 548.5 mmBOE. The 28.5 mmBOE difference over production (577 mmBOE) reflected mainly volumes of natural gas consumed in operations (21.1 mmBOE).

Approximately 63% of liquids production sold (302.6 mmBBL) was destined to Eni’s Refining & Marketing segment (of which 26% was processed in Eni’s refineries); about 31% of natural gas production sold (1,367 BCF) was destined to Eni’s Gas & Power segment.

The tables below provide Eni subsidiaries and its equity-accounted entities’ production, by final product sold of liquids and natural gas by geographical area of each of the last three fiscal years.

LIQUIDS PRODUCTION

2009 2010 2011

(KBBL/d) Eni consolidated subsidiaries Eni share of equity-accounted entities Eni consolidated subsidiaries Eni share of equity-accounted entities Eni consolidated subsidiaries Eni share of equity-accounted entities

Italy	56		61		64
Rest of Europe	133		121		120
North Africa	287	5	297	4	204	5
Sub-Saharan Africa	309	3	318	3	275	3
Kazakhstan	70		65		64
Rest of Asia	56	1	47	1	33	1
Americas	71	8	60	11	55	10
Australia and Oceania	8		9		11
	990	17	978	19	826	19

38

NATURAL GAS PRODUCTION AVAILABLE FOR SALE ⁽¹⁾

2009 2010 2011

(mmCF/d) Eni consolidated subsidiaries Eni share of equity-accounted entities Eni consolidated subsidiaries Eni share of equity-accounted entities Eni consolidated subsidiaries Eni share of equity-accounted entities

Italy	630		648		648
Rest of Europe	608		517		498
North Africa	1,500	3	1,556	3	1,165	4
Sub-Saharan Africa	213		365		422
Kazakhstan	241		221		212
Rest of Asia	391	26	412	24	378	20
Americas	416		385		323
Australia and Oceania	46		91		93
	4,045	29	4,195	27	3,739	24

(1) It excludes production volumes of natural gas consumed in operations. Said volumes were 321, 318 and 300 mmCF/d in 2011, 2010 and 2009, respectively.

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 28 KBOE/d, 105 KBOE/d and 97 KBOE/d in 2011, 2010 and 2009, respectively.

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 Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

2009
Consolidated subsidiaries
Oil and condensate, per BBL	56.02	56.46	56.42	59.75	52.34	55.34	55.66	50.40	57.02
Natural gas, per KCF	9.01	7.06	5.79	1.66	0.45	4.09	4.05	8.14	5.62
Average production cost, per BOE	9.69	8.28	3.99	13.19	5.20	3.44	7.39	9.56	7.41
Equity-accounted entities
Oil and condensates, per BBL			14.60	56.85		9.01	56.41		44.43
Natural gas, per KCF						7.44			6.81
Average production cost, per BOE			10.62	8.87		4.95	23.14		13.72
2010
Consolidated subsidiaries
Oil and condensate, per BBL	72.19	67.26	70.96	78.23	66.74	75.20	72.84	73.00	72.95
Natural gas, per KCF	8.71	7.40	6.87	1.87	0.49	4.35	4.70	7.40	6.01
Average production cost, per BOE	9.42	9.42	5.63	15.19	6.40	5.62	8.15	9.75	8.89
Equity-accounted entities
Oil and condensates, per BBL			16.09	77.78		57.05	71.70		58.86
Natural gas, per KCF						9.87			8.73
Average production cost, per BOE			13.53	9.73		5.05	27.78		17.45
2011
Consolidated subsidiaries
Oil and condensates, per BBL	101.20	97.56	97.63	110.09	98.68	101.09	101.15	98.05	102.47
Natural gas, per KCF	11.56	9.72	5.95	1.97	0.57	5.27	4.02	7.38	6.44
Average production cost, per BOE	11.17	10.31	5.96	18.32	6.37	8.28	12.38	12.14	10.86
Equity-accounted entities
Oil and condensates, per BBL		97.18	17.98	108.92		74.98	93.03		84.78
Natural gas, per KCF		10.65	5.39			15.68			13.89
Average production cost, per BOE		26.91	10.82	11.43		7.68	46.77		26.76

Development activities

In 2011 a total of 407 development wells were drilled (186.1 of which represented Eni’s share) as compared to 399 development wells drilled in 2010 (178 of which represented Eni’s share) and 418 development wells drilled in 2009 (175.1 of which represented Eni’s share). The drilling of 118 wells (39.5 of which represented Eni’s share) is currently underway.

39

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, 2011. 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 Dec. 31

2009 2010 2011 2011

(units) Productive Dry Productive Dry Productive Dry Gross Net

Italy	18.3		23.9	1.0	25.3		3	2
Rest of Europe	12.5		2.9	0.2	3.3	0.3	18	3.9
North Africa	40.7	0.4	44.3	0.3	55.9	1.1	27	12.5
Sub-Saharan Africa	35.8	1.9	28.0	2.5	28.2	1.0	28	6.6
Kazakhstan	3.8		1.8		1.3		13	2.2
Rest of Asia	38.6	4.3	41.7	1.8	39.2	2.5	12	5.4
Americas	15.6	1.0	27.6	0.5	27.6		17	6.9
Australia and Oceania	2.2		1.5		0.4
Total including equity-accounted entities	167.5	7.6	171.7	6.3	181.2	4.9	118.0	39.5

Exploration activities

In 2011, a total of 56 new exploratory wells were drilled (28 of which represented Eni’s share), which includes drilled exploratory wells that have been suspended pending further evaluation, as compared to 47 exploratory wells drilled in 2010 (23.8 of which represented Eni’s share) and 69 exploratory wells drilled in 2009 (37.6 of which represented Eni’s share).

The overall commercial success rate was 42% (38.6% net to Eni) as compared to 41% (39% net to Eni) and 41.9% (43.6% net to Eni) in 2010 and 2009, 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, 2011. 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.

EXPLORATORY WELL ACTIVITY

Net wells completed Wells in progress
at Dec. 31 ^(a)

2009 2010 2011 2011

(units) Productive Dry Productive Dry Productive Dry Gross Net

Italy		1.0		0.5			6.0	4.4
Rest of Europe	4.1	0.2	1.7	1.1	0.3	0.7	21.0	6.5
North Africa	4.8	3.8	9.3	8.1	6.2	3.4	21.0	15.7
Sub-Saharan Africa		2.7	2.3	4.7	0.6	2.6	63.0	18.6
Kazakhstan							13.0	2.3
Rest of Asia	2.3	3.9	1.0	2.8	0.2	7.6	16.0	6.9
Americas	1.0	3.8		6.3	2.5		11.0	3.3
Australia and Oceania	0.8	1.4	1.0	0.4		1.4
Total including equity-accounted entities	13.0	16.8	15.3	23.9	9.8	15.7	151.0	57.7

(a) Includes temporary suspended wells pending further evaluation.

Oil and gas properties, operations and acreage

As of December 31, 2011, Eni’s mineral right portfolio consisted of 1,106 exclusive or shared rights for exploration and development in 41 Countries on five continents for a total acreage of 254,421 square kilometers net to Eni, of which developed acreage of 41,373 square kilometers and undeveloped acreage of 213,048 square kilometers.

In 2011, changes in total net acreage mainly derived from: (i) new leases in Angola, Australia, Ghana, Indonesia, Nigeria, Norway and Ukraine for a total acreage of approximately 14,000 square kilometers; (ii) the total relinquishment of leases in Australia, China, Denmark, Indonesia, Italy, Libya, Pakistan, Nigeria, Saudi Arabia and

40

Yemen, covering an acreage of 72,000 square kilometers; and (iii) the decrease in net acreage due to partial relinquishment or interest reduction in China, Congo, India and Mozambique for a total acreage of approximately 9,000 square kilometers.

The table below provides certain information about the Company’s oil and 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, 2011. A gross acreage is one in which Eni owns a working interest.

December 31, 2010 December 31, 2011

Total net acreage ^(a) Number
of interests Gross developed ^(b) acreage ^(a) Gross undeveloped acreage ^(a) Total gross acreage ^(a) Net
developed ^(b)
acreage ^(a) Net undeveloped acreage ^(a) Total net acreage ^(a)

EUROPE	29,079	286	17,324	24,007	41,331	11,216	14,807	26,023
Italy	19,097	151	10,927	10,721	21,648	9,055	7,817	16,872
Rest of Europe	9,982	135	6,397	13,286	19,683	2,161	6,990	9,151
Croatia	987	2	1,975		1,975	987		987
Norway	2,418	50	2,262	5,838	8,100	337	1,998	2,335
Poland	1,968	3		1,968	1,968		1,968	1,968
United Kingdom	1,151	74	2,110	789	2,899	807	207	1,014
Ukraine		2	50	49	99	30	15	45
Other Countries	3,458	4		4,642	4,642		2,802	2,802
AFRICA	152,671	270	67,154	200,957	268,111	20,167	117,053	137,220
North Africa	44,277	112	31,781	36,772	68,553	13,877	16,655	30,532
Algeria	17,244	39	2,261	17,358	19,619	815	8,250	9,065
Egypt	6,594	52	5,109	10,727	15,836	1,837	4,061	5,898
Libya	18,165	10	17,947	8,687	26,634	8,951	4,344	13,295
Tunisia	2,274	11	6,464		6,464	2,274		2,274
Sub-Saharan Africa	108,394	158	35,373	164,185	199,558	6,290	100,398	106,688
Angola	4,520	68	4,636	20,360	24,996	625	5,593	6,218
Congo	6,074	26	1,835	7,681	9,516	1,012	4,008	5,020
Democratic Republic of Congo	615	1		478	478		263	263
Gabon	7,615	6		7,615	7,615		7,615	7,615
Ghana	1,086	2		5,144	5,144		1,885	1,885
Mali	21,640	1		32,458	32,458		21,640	21,640
Mozambique	12,352	1		12,956	12,956		9,502	9,502
Nigeria	8,439	46	28,902	11,723	40,625	4,653	3,838	8,491
Togo	6,192	2		6,192	6,192		6,192	6,192
Other Countries	39,861	5		59,578	59,578		39,862	39,862
ASIA	112,745	74	17,478	100,759	118,237	5,893	49,391	55,284
Kazakhstan	880	6	324	4,609	4,933	105	775	880
Rest of Asia	111,865	68	17,154	96,150	113,304	5,788	48,616	54,404
China	18,232	10	200	5,326	5,526	39	5,326	5,365
India	10,089	13	206	25,364	25,570	109	9,097	9,206
Indonesia	12,912	12	1,735	27,106	28,841	656	17,063	17,719
Iran	820	4	1,456		1,456	820		820
Iraq	640	1	1,074		1,074	352		352
Pakistan	11,347	18	8,781	14,172	22,953	2,582	6,707	9,289
Russia	1,507	4	3,502	1,495	4,997	1,030	439	1,469
Saudi Arabia	25,844
Timor Leste	6,470	4		8,087	8,087		6,740	6,740
Turkmenistan	200	1	200		200	200		200
Yemen	20,560
Other Countries	3,244	1		14,600	14,600		3,244	3,244
AMERICA	11,187	460	5,979	15,602	21,581	3,052	7,157	10,209
Brazil	745	2	1,513	745	2,258	50	745	795
Ecuador	2,000	1	1,985		1,985	1,985		1,985
Trinidad & Tobago	66	1	382		382	66		66
United States	5,896	442	1,721	7,261	8,982	853	4,270	5,123
Venezuela	1,154	6	378	2,049	2,427	98	816	914
Other Countries	1,326	8		5,547	5,547		1,326	1,326
AUSTRALIA AND OCEANIA	15,279	16	1,980	49,304	51,284	1,045	24,640	25,685
Australia	15,241	15	1,980	48,540	50,520	1,045	24,602	25,647
Other Countries	38	1		764	764		38	38
Total	320,961	1,106	109,915	390,629	500,544	41,373	213,048	254,421

(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.

41

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, 2011 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 bore hole 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 8,477 (3,136.1 of which represent Eni’s share).

Productive oil and gas wells at Dec. 31, 2011 ^(a)

Oil wells Natural gas wells

(units) Gross Net Gross Net

Italy	237.0	191.5	630.0	546.5
Rest of Europe	414.0	63.3	207.0	93.1
North Africa	1,357.0	651.8	144.0	56.0
Sub-Saharan Africa	2,952.0	562.6	479.0	32.1
Kazakhstan	89.0	28.9
Rest of Asia	602.0	381.5	849.0	328.7
Americas	152.0	79.8	344.0	113.2
Australia and Oceania	7.0	3.8	14.0	3.3
Total including equity-accounted entities	5,810.0	1,963.2	2,667.0	1,172.9

(a) Multiple completion wells included above: approximately 2,304 (741.7 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 2011, Eni’s oil and gas production amounted to 181 KBOE/d. Eni’s activities in Italy are deployed in the Adriatic Sea, 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.

The Adriatic and Ionian Sea represents Eni’s main production area in Italy, accounting for 46% of Eni’s domestic production in 2011. Main operated fields are Barbara, Angela-Angelina, Porto Garibaldi, Cervia, Bonaccia, Luna and Hera Lacinia (for an overall production of approximately 270 mmCF/d).

42

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 is fed by 24 production wells and is treated by the Viggiano oil center with an oil capacity of 104 KBBL/d. Oil produced is carried to Eni’s refinery in Taranto via a 136-kilometer long pipeline. Gas produced is treated at the Viggiano oil center and then delivered to the national grid system. In 2011, the Val d’Agri concession produced 95 KBOE/d (52 KBOE/d net to Eni) representing 28% of Eni’s production in Italy. Eni is the operator of 14 production concessions onshore and offshore in Sicily. Its main fields are Gela, Ragusa, Giaurone, Fiumetto and Prezioso, which in 2011 accounted for 11% of Eni’s production in Italy. In 2011, production started-up at the following fields: (i) Guendalina (Eni’s interest 80%) flowing at the initial rate of approximately 3 KBOE/d; and (ii) Capparuccia (Eni’s interest 95%) with production start-up at approximately 4 KBOE/d. During the year Eni finalized the purchase of an additional interest in the Annamaria field (Eni’s interest 100%).

Development activities progressed at the Val d’Agri concession (Eni’s interest 60.77%) with the linkage of Cerro Falcone to the oil treatment center and sidetrack activity as well as upgrading of production facilities. Other activities concerned; (i) sidetrack and workover activities on Calpurnia, Daria (Eni’s interest 51%), Barbara, Clara Nord (Eni’s interest 51%) and Gela fields for the production optimization; (ii) integration and upgrading activities of compression

43

and hydrocarbon treatment facilities at the Crotone power plant; and (iii) completion of development activities at the Tresauro field (Eni’s interest 45%).

In the medium-term, management expects production in Italy to maintain the actual level due to the production ramp-up of the Val d’Agri fields and ongoing new field projects and continuing production optimization activities.

Rest of Europe

Eni’s operations in the Rest of Europe are conducted mainly in Croatia, Norway and the UK. In 2011, the Rest of Europe accounted for 14% of Eni’s total worldwide production of oil and natural gas.

Croatia. Eni has been present in Croatia since 1996. In 2011, Eni’s production of natural gas averaged 27 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, Ana, Vesna, Irina, Marica and Katarina and are operated by Eni through a 50/50 joint operating company with the Croatian oil company INA.

Norway. Eni has been operating in Norway since 1964. 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 128 KBOE/d in 2011.

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 any given number of years with possible extensions.

Eni currently holds interests in 8 production areas in the Norwegian Sea. The principal producing fields are Asgaard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.24%), Mikkel (Eni’s interest 14.9%), Tyrihans (Eni’s interest 6.2%) and Morvin (Eni’s interest 30%) which in 2011 accounted for 76% of Eni’s production in Norway.

The development plan of the Morvin field has been completed with a production peak of 22 KBOE/d reached in the year. Development activities progressed to put in production discovered reserves near the Asgaard field (Eni’s

44

interest 14.82%) with the Marulk development plan (Eni operator with a 20% interest). Production started-up in early days of April 2012 and is expected to reach approximately 20 KBOE/d (4 KBOE/d net to Eni) on average during the year.

Eni holds interests in four production licenses in the Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%) in PL 018, which in 2011 produced approximately 32 KBOE/d net to Eni and accounted for 24% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension. Activities were performed during the year to maintain and optimize the production rate by means of infilling wells, the development of the South Area extension, upgrading of existing facilities and optimization of water injection.

Eni is currently performing exploration and development activities in the Barents Sea. Operations have been focused on developing the Goliat discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest). The license expires in 2042. The project is progressing according to schedule. Start-up is expected in 2013 with the production plateau of 100 KBBL/d.

Eni was awarded three exploration licenses in the Barents Sea: (i) the PL657 license (Eni operator with an 80% interest) in January 2012. In case of exploration success, the project will benefit from the nearby facilities of the Goliat operated field thus significantly reducing time to market; and (ii) in May 2011 the PL608 (Eni’s interest 30%) license located near the Skrugard oil discovery and the PL226B license (Eni’s interest 31%) located in high mineral potential basin.

Exploration activities yielded positive results with the Skrugard and Havis oil and gas discoveries in the PL532 license (Eni’s interest 30%). Both fields are planned to be put in production by means of a fast-track synergic development.

Ukraine. In July 2011, Eni acquired from Cadogan Petroleum plc an interest in two licenses for exploration and development in areas included in the Dniepr-Donetz Basin. Eni acquired 30% with an option to increase its participation to up to 60% in the Pokrovskoe exploration license and the acquisition of 60% interest in the Zagoryanska license.

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, the Irish Sea and certain areas East and West of the Shetland Islands. In 2011, Eni’s net production of oil and gas averaged 76 KBOE/d. Exploration and production activities in the UK are regulated by concession contracts. Eni holds interests in 13 production areas; in 1 of these, the Hewett Area, Eni is operator with an 89% interest. The other main fields are Elgin/Franklin (Eni’s interest 21.87%), West Franklin (Eni’s interest 21.87%), Liverpool Bay (Eni’s interest 53.9%), J Block Area (Eni’s interest 33%), Andrew (Eni’s interest 16.21%), Flotta Catchment Area (Eni’s interest 20%) and MacCulloch (Eni’s interest 40%), which in 2011 accounted for 83% of Eni’s production in the UK. Main development activities concerned: (i) the construction of production platform and drilling activities at the gas and liquids Jasmine field (Eni’s interest 33%) with start-up expected at the end of 2012; (ii) Phase 2 development plan of the West Franklin field (Eni’s interest 21.87%) with the construction of a well-head platform and linkage to the Elgin/Franklin treatment plant. Drilling activities are progressing with start-up expected in 2013; (iii) development activities at the oil and gas Kinnoul field (Eni’s interest 16.67%). The drilling of producing subsea wells has been completed while the linkage to the production facilities of the Andrew field is in progress. Start-up is expected in 2013; and (iv) concept definition activities for the Mariner heavy oil field proceed with target to submit the Field Development Plan and sanction the project early in 2013.

Exploration activities yielded positive results with the appraisal of Culzean discovery continuing (Eni’s interest 16.95%).

45

North Africa Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2011, North Africa accounted for 28% of Eni’s total worldwide production of oil and natural gas. Algeria. Eni has been present in Algeria since 1981. In 2011, Eni’s oil and gas production averaged 69 KBOE/d. Operating activities are located in the Bir Rebaa area in the South-Eastern Desert and include the following exploration and production blocks: (i) Blocks 403a/d (Eni’s interest up to 100%); (ii) Block Rom North (Eni’s interest 35%); (iii) Blocks 401a/402a (Eni’s interest 55%); (iv) Blocks 403 (Eni’s interest 50%) and 404a (Eni’s interest 12.25%); (v) Blocks 208 (Eni’s interest 12.25%) and 405b (Eni’s interest 75%) with ongoing development activities; (vi) Block 212 (Eni’s interest 22.38%) with discoveries already made; and (vii) Blocks 316b, 319a and 321a (Eni operator with a 49% interest) in the Kerzaz area with ongoing exploration activities. In April 2011, Eni signed a cooperation agreement with Sonatrach to explore for and develop unconventional hydrocarbons, particularly shale gas plays in Algeria.

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

Production in Block 403a/d and Rom North comes mainly from the HBN and Rom and satellite fields and represented approximately 20% of Eni’s production in Algeria in 2011. A new multiphase pumping system is under finalization in compliance with applicable country law to reduce gas flaring by 2012.

Production in Blocks 401a/402a comes mainly from the ROD/SFNE and satellite fields and accounted for approximately 25% of Eni’s production in Algeria in 2011. Infilling activities are being performed in order to maintain the current production plateau.

The main fields in Block 403 are BRN, BRW and BRSW which accounted for approximately 18% of Eni’s production in Algeria in 2011.

In Block 405b, the development activity relates to the MLE and CAFC integrated project. The final investment decision of the projects was sanctioned (MLE in 2009; CAFC in 2010). The MLE development plan foresees the construction of a natural gas treatment plant with a capacity of 350 mmCF/d and of four export pipelines with linkage to the national grid system. These facilities will also receive gas from the CAFC field. Production start-up is expected in 2012. The CAFC project provides the construction of an oil treatment plant and will also benefit from synergies with MLE production facilities. Gas and oil production start-up of CAFC field are expected in 2012 and 2014, respectively. The overall Block 405b will target a production plateau of approximately 33 KBOE/d net to Eni by 2015.

Block 208 is located South of Bir Rebaa. The El Merk project is progressing with the drilling activities and the construction of treatment facilities. The development program provides for the construction of a gas treatment plant with a capacity of approximately 600 mmCF/d, two oil trains with a capacity of 65 KBBL/d and three export pipelines with linkage to the national system for an overall production of approximately 11 KBBL/d. Start-up is expected in 2013.

The Algerian hydrocarbon Law No. 5 of 2007 introduced a higher tax burden for the national oil company Sonatrach which has claimed to renegotiate the economic terms of certain PSAs in order to restore the initial economic equilibrium. Eni, in this respect, signed an agreement for Block 403, while an agreement has yet to be finalized for Block 401a/402a. In relation to the Block 208, an agreement has been signed and the parties have settled the matter early in March 2012. The settlement was approved by the relevant Algerian authorities.

In the medium-term, management expects to increase Eni’s production in Algeria to approximately 120 KBOE/d, reflecting the ongoing development projects.

46

Egypt. Eni has been present in Egypt since 1954. In 2011, Eni’s share of production in this country amounted to 225 KBOE/d and accounted for 15% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Gulf of Suez, primarily in Belayim field (Eni’s interest 100%) and in the Western Desert mainly Melehia concession (56% interest) and Ras Qattara (75% interest). Gas production mainly comes from the operated or participated concession of North Port Said (Eni’s interest 100%), El Temsah (50% interest), Baltim (50% interest) and Ras el Barr (50% interest, non-operated) and all located in the offshore the Nile Delta. In 2011, production from these main concessions accounted for approximately 91% of Eni’s production in Egypt. Exploration and production activities in Egypt are regulated by Production Sharing Agreements. In July 2011, Eni and the Egyptian Authorities reaffirmed their upstream commitment in the Country, particularly in the Western Desert, the Mediterranean Sea and the Sinai Basins. Agreed plans foresee drilling additional producing wells and the fast track of recent discoveries as well as an exploration plan including the drilling of 12 wells. In 2011, production was started-up at the Denise B field in the El Temsah concession (Eni operator with a 50% interest), the second development phase of the Denise field with the drilling of 3 other subsea wells linked to the production facilities in the area flowing initially at 7 KBOE/d net to Eni. Production peak is expected at 14 KBOE/d in 2012.

Main activities of the year were: (i) the upgrading of the El Gamil plant by adding new compression capacity to support production; (ii) the Seth project (Eni’s interest 50%). The development activity provides the drilling of two wells and the installation of production platform. Start-up is expected in 2012. Through its affiliate Unión Fenosa Gas, Eni has an indirect interest in the Damietta natural gas liquefaction plant with a producing capacity of 5.1 mmtonnes/y of LNG corresponding to approximately 268 BCF/y of feed gas. Eni is currently supplying 35 BCF/y for a 20-year period. Natural gas supplies derived from the Taurt and Denise fields with 17 KBOE/d net to Eni of feed gas. Exploration activities yielded positive results with near field activities in the: (i) Belayim concession with three oil discovery wells (BB-10, BLNE-1 and EBLS-1) that were linked to the existing facilities; (ii) Abu Madi West development lease (Eni’s interest 75%) with Nidoco West and Nidoco East gas discoveries. The linkage to the existing facilities was completed; (iii) Melehia development lease with the Aman SW, Dorra-1X oil and Melehia North-1X wells that were started-up; and (iv) East Kanayis concession (Eni’s interest 100%) with the Qattara Rim-3 and Qattara North-1 oil discoveries. Libya. Eni started operations in Libya in 1959. In 2011, Eni’s oil and gas production averaged 108 KBOE/d. The 2011 activities and production were affected by the Libyan crisis for about eight months. From September all activities and the oil and gas production offshore and onshore have been partially resumed. Gas export via the GreenStream pipeline has been re-opened in October and export gas has subsequently been increased from

47

November when Bahr Essalam field re-started operations. Average daily production at the end of 2011 was in the range of 240 KBOE/d. Full capacity production level in all fields is expected during the second half of 2012. For further information on this matter, see "Item 3 – Risk Factors".

Production activity is carried out in the Mediterranean offshore facing 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%); and (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); and (iv) Area F with Block 118 (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 Blocks NC 41 and NC 169 (onshore) including the Western Libyan Gas Project (Eni’s interest 50%).

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

Tunisia. Eni has been present in Tunisia since 1961. In 2011, Eni’s production amounted to 17 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), MLD (Eni’s interest 50%) and El Borma (Eni’s interest 50%) onshore blocks.

Optimization of production was carried out at the Adam, Djebel Grouz (Eni’s interest 50%), Oued Zar and El Borma fields.

Sub-Saharan Africa

Eni’s operations in Sub-Saharan Africa are conducted mainly in Angola, Congo and Nigeria. In 2011, Sub-Saharan Africa accounted for 23% of Eni’s total worldwide production of oil and natural gas.

Angola. Eni has been present in Angola since 1980. In 2011, Eni’s production averaged 95 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore. The main producing blocks with Eni’s participation are: (i) Block 0 in Cabinda (Eni’s interest 9.8%) North of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni’s interest ranging from 12% to 15%) in the offshore of the Congo Basin; (iii) Development Areas in the former Block 14 (Eni’s interest 20%) in the deep offshore West of Block 0; and (iv) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo Basin. Eni also holds interests in other non producing concessions, in particular in the Lianzi Development Area (Block 14K/A IMI Unit Area - Eni’s interest 10%), in Block 3/05-A (Eni’s interest 12%), in onshore Cabinda North (Eni’s interest 15%) and in the Open Areas of Block 2 awarded to the Gas Project (Eni’s interest 20%). In the exploration and development phase, Eni is operator of Block 15/06 (Eni’s interest 35%), where West Hub is the main sanctioned project underway, with start-up expected in 2014 and peaking production at 80 KBBL/d. Exploration and production activities in Angola are regulated by concessions and PSAs. In 2011, Eni was awarded the right to explore and the operatorship of the deep offshore Block 35, with a 30% interest. The agreement foresees the drilling of 2

48

commitment wells to be carried out in the first 5 years of the exploration phase. This deal was approved by the relevant authorities.

Within the activities for reducing gas flaring in Block 0 (Eni’s interest 9.8%), activity progressed at the Nemba field in Area B. Completion is expected in 2013 reducing flared gas by approximately 85%. Other ongoing projects include: (i) the completion of linkage and treatment facilities at the Malongo plant; and (ii) the installation of a second compression unit at the Nemba platform in Area B.

In the Area A the concept definition phase has been completed for the further development of the Mafumeira field. Project sanctioning is expected in 2012 with start-up in 2015.

Main projects underway in the Development Areas of former Block 15 (Eni’s interest 20%) concerned: (i) the satellites of Kizomba Phase 1, with start-up expected before by mid 2012 and peaking production at 100 KBBL/d (approximately 21 KBBL/d net to Eni) in 2013; and (ii) drilling activity at the Mondo and Saxi/Batuque fields to finalize their development plan. The subsea facility of the Gas Gathering project has been completed and will provide for the collection of all the gas of the Kizomba, Mondo and Saxi/Batuque fields to be delivered to the A-LNG liquefaction plant.

Eni holds a 13.6% interest in the Angola LNG Limited (A-LNG) consortium responsible for the construction of an LNG plant with a processing capacity of approximately 1.1 BCF/d of natural gas and produce 5.2 mmtonnes/y of LNG and over 50 KBBL/d of condensates and LPG. The project has been sanctioned by relevant Angolan Authorities. It envisages the development of 10,594 BCF of gas in 30 years. Exports start-up is expected in the second quarter of 2012. LNG may be delivered to the United States market at the re-gasification plant in Pascagoula (Eni’s capacity amounting to approximately 205 BCF/y) in Mississippi. A joint company has been established to assess further possible marketing opportunities.

In addition, Eni is part of the Gas Project, a second gas consortium with the Angolan national company and other partners that will explore further potential gas discoveries to support the feasibility of a second LNG train or other marketing projects to deliver gas and associated liquids. Eni is technical advisor with a 20% interest.

Exploration activities yielded positive results in: (i) Block 2 (Eni’s interest 20%) with the Garoupa-2 and Garoupa Norte 1 appraisal gas and condensates wells, within the Gas Project; (ii) Block 15/06 with the Lira gas and condensates discovery; and (iii) in the same block with the Mukuvo-1 discovery and Cinguvu-2 and Cabaça South East-3 appraisal wells containing oil.

In the medium-term, management expects to increase Eni’s production to approximately 170 KBBL/d reflecting contributions from ongoing development projects. Congo. Eni has been present in Congo since 1968. In 2011, production averaged 104 KBOE/d net to Eni. Eni’s activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore. Eni’s main operated oil producing interests in Congo are the Zatchi (Eni’s interest 65%) and Loango (Eni’s interest 50%), Ikalou (Eni’s interest 100%), Djambala, Foukanda and Mwafi (Eni’s interest 65%), Kitina (Eni’s interest 35.75%), Awa Paloukou (Eni’s interest 90%), M’Boundi (Eni’s interest 83%), Kouakouala (Eni’s interest 75%), Zingali and Loufika (Eni’s interest 85%) fields. Other relevant producing areas are a 35% interest in the Pointe Noire Grand Fond, PEX and Likouala permits. In the exploration phase, Eni also holds interests in the Mer Très Profonde Sud deep offshore block (Eni’s interest 30%), the Noumbi onshore permit (Eni’s interest 37%) and the Marine XII offshore permit (Eni operator with a 65% interest). Exploration and production activities in Congo are regulated by Production Sharing Agreements.

49

In 2011, production started-up at the Libondo offshore field (Eni’s interest 35%) with production of approximately 3 KBOE/d net to Eni.

Activities on the M’Boundi field moved forward with the application of advanced recovery techniques and a design to monetize associated gas within the activities aimed at zero gas flaring by 2012. In addition starting from 2009, Eni finalized long-term agreements to supply associated gas from the M’Boundi field to feed three facilities in the Pointe Noire area: (i) the under construction potassium plant, owned by Canadian Company MAG Industries; (ii) the existing Djeno power plant (CED - Centrale Electrique du Djeno) with a 50 MW generation capacity; (iii) the recently built CEC Centrale Electrique du Congo power plant (Eni’s interest 20%) with a 300 MW generation capacity. These facilities will also receive in the future gas from the offshore discoveries of the Marine XII permit. In 2011, M’Boundi supply to the CEC and CED power plants was approximately 106 mmCF/d (17 KBOE/d net to Eni).

The RIT project progressed for the rehabilitation of the power grid from Pointe Noire to Brazzaville within the integrated project to monetize gas in Congo.

In the medium-term, management expects to increase Eni’s production in Congo due to the integration and development of recently acquired assets as well as projects underway, targeting a level in excess of 120 KBOE/d by 2018.

Democratic Republic of Congo. Eni has been present in Democratic Republic of Congo since 2010.

Eni holds a 55% interest and operatorship in the Ndunda Block which may lead to future developments after exploration activities. At present no relevant activities are conducted in this country.

Ghana. Eni has been present in Ghana since 2009, following the acquisition of the Offshore Cape Three Points South and Offshore Cape Three Points (Eni operator with a 47.2% interest) exploration permits.

Exploration activities yielded positive results with the Sankofa-2 appraisal well and the Gye Nyame discovery, both containing gas and condensates in the Offshore Cape Three Points license.

Mozambique. Eni has been present in Mozambique since 2006, following the acquisition of the Area 4 block (Eni operator with a 70% interest) located in the offshore Rovuma Basin.

Exploration activities yielded positive results in Area 4 with the Mamba South 1, Mamba North 1 and Mamba North East 1 gas discoveries.

Management believes these fields contain a large amount of gas resources which will eventually be developed in phases.

In the next two years up to 8 additional wells are expected to be drilled in the nearby areas.

Nigeria. Eni has been present in Nigeria since 1962. In 2011, Eni’s oil and gas production averaged 154 KBOE/d located mainly in the onshore and offshore of the Niger Delta.

In 2011, Eni optimized its producing asset portfolio: (i) the purchase from GEC Petroleum Development Co (GDPC) a 49% interest in Block OPL 2009 in addition to the awarding from the Nigerian Government a 50% interest in Block OPL 245 as well as relative license and operatorship; (ii) the divestment of a 5% interest in blocks OML 26 and OML 42; and (iii) the finalization of the divestment of a 40% interest in blocks OML 120 and 121. The transaction is subject to the approval of relevant authorities.

In the development/production phase Eni is operator of onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OML 125 (Eni’s interest 85%), OMLs 120-121 (Eni’s interest 40%), holding interests in OML 118 (Eni’s interest 12.5%) as well as 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 28 onshore blocks and a 12.86% interest in 5 conventional offshore blocks.

In the exploration phase Eni is operator of offshore Oil Prospecting Leases (OPL) 244 (Eni’s interest 60%), OML 134 (former OPL 211 - Eni’s interest 85%) and onshore OPL 282 (Eni’s interest 90%) and OPL 135 (Eni’s interest 48%). Eni also holds a 12.5% interest in OML 135 (former OPL 219).

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 state-owned company.

50

In blocks OMLs 60, 61, 62 and 63 (Eni operator with a 20% interest), activities aimed at guaranteeing production to feed gas to the Bonny liquefaction plant and flaring down progressed. As part of supply to the Bonny liquefaction plant, the compression and gas export capacity at the Obiafu/Obrikom plant was increased to ensure 170 mmCF/d net to Eni of feed gas for 20 years aimed for sixth train. To the same end the development plan progressed at the Tuomo field with early-production start-up in 2012.

In block OML 28 (Eni’s interest 5%) within the integrated oil and natural gas project in the Gbaran-Ubie area, the drilling program progressed. The development plan provides for the construction of a Central Processing Facility (CPF) with treatment capacity of approximately 1 BCF/d of gas and 120 KBBL/d of liquids.

The Forcados/Yokri oil and gas field (Eni’s interest 5%) is under development as part of the integrated associated gas gathering project aimed at supplying gas to the domestic market through Escravos-Lagos pipeline system. First gas is expected in 2013.

Eni holds a 10.4% interest in Nigeria LNG Ltd responsible for the management of the Bonny liquefaction plant, located in the Eastern Niger Delta. The plant has a design treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on six trains. The seventh unit is being engineered as it is in the planning phase. When fully operational, total capacity will amount to approximately 30 mmtonnes/y of LNG, corresponding to a feedstock of approximately 1,624 BCF/y. Natural gas supplies to the plant are provided under gas supply agreements with a 20-year term from the SPDC joint venture (Eni’s interest 5%) and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 blocks with an overall amount at the end of 2011 of 2,797 mmCF/d (267 mmCF/d net to Eni corresponding to approximately 48 KBOE/d). LNG production is sold under long-term contracts and exported to European and American markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co.

Eni holds a 17% interest in Brass LNG Ltd Co for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal, 100 kilometers west of Bonny. This plant is expected to start operating in 2017 with a production capacity of 10 mmtonnes/y of LNG corresponding to 590 BCF/y (approximately 60 net to Eni) of feed gas on two trains for twenty years. Supply to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas reserves in the onshore OMLs 60 and 61. Preliminary long-term contracts were signed to sell the whole LNG production capacity. Eni acquired 1.67 mmtonnes/y of LNG capacity (corresponding to approximately 81 BCF/y). LNG may be delivered to the United States market mainly at the

51

re-gasification plant in Cameron, in Louisiana, U.S. Eni’s capacity amounts to approximately 201 BCF/y. Front end engineering activities progressed. The final investment decision is expected in 2012.

Exploration activities yielded positive results in Block OML 36 (Eni’s interest 5%) with the Opugbene 2 appraisal well containing natural gas and condensates.

In the medium-term, management expects to increase Eni’s production in Nigeria to approximately 200 KBOE/d, reflecting the development of gas reserves.

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 2011, Eni’s operations in Kazakhstan accounted for 7% of its total worldwide production of oil and natural gas.

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 undeveloped 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 will expire at the end of 2041.

The participating interest in the NCSPSA has been redefined, effective as of January 1, 2008, in line with an agreement signed in October 2008 with Kazakh Authorities which proportionally diluted the participating interest of the international companies by transferring a 10% stake in the project to the Kazakh national oil company, KazMunaiGas. In addition to Eni, the partners of the international consortium are the Kazakh national oil company, KazMunaiGas, and the international oil companies Total, Shell and ExxonMobil, each with a participating interest currently of 16.81%, ConocoPhillips with 8.40%, and Inpex with 7.56%.

The exploration and development activities of the Kashagan field and the other discoveries made in the contractual area are executed through an operating model which entails an increased role of the Kazakh partner and defines the international parties’ responsibilities in the execution of the subsequent development phases of the project. The North Caspian Operating Co (NCOC) BV participated by the seven partners of the Consortium has taken over the operatorship of the project. Subsequently development, drilling and production activities have been delegated by NCOC BV to the main partners of the Consortium: Eni has retained the responsibility for the development of Phase 1 of the project (the so-called "Experimental Program") and the onshore part of Phase 2.

The Consortium is currently focused on completing Phase 1 and starting commercial oil production. Management estimates that Phase 1 was 90% completed as of end of December 2011. The Tranches 1 and 2 of the agreed scope of work have reached approximately 98% by the end of the year. The Consortium is currently targeting the achievement of first commercial oil production by end of 2012 or in the early 2013.

The project Phase 1 (“Experimental Program”) as sanctioned by the partners of the venture targets an initial production capacity of 150 KBBL/d. In 2014, the second train of treatment and compression facilities for gas re-injection will be completed and come online enabling to increase the production capacity up to 370 KBBL/d. The partners are planning to further increase available production capacity up to 450 KBBL/d by installing additional gas compression capacity for re-injection in the reservoir. The partners intend to submit the scheme of this additional gas compression activity to the relevant Kazakh Authorities in the course of 2012 in order to obtain approval to start the engineering design. The partners are currently assessing Phase 2 of the development of the Kashagan field with a view of optimizing the development lay-out. The review is expected to be completed by 2012.

Management believes that significant capital expenditures will be required in case the partners of the venture would sanction Phase 2 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. In addition to the expenditures for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets.

As of December 31, 2011 Eni’s proved reserves booked for the Kashagan field amounted to 449 mmBOE, recording a decrease of 120 mmBOE compared to 2010 mainly due to a higher Brent marker price and downward revisions as disclosed under paragraph "Proved Undeveloped Reserves".

As of December 31, 2010, Eni’s proved reserves booked for the Kashagan field amounted to 569 mmBOE, recording a decrease of 19 mmBOE with respect 2009 mainly due to price effect.

52

As of December 31, 2009, Eni’s proved reserves booked for the Kashagan field amounted to 588 mmBOE, recording a decrease of 6 mmBOE with respect to 2008.

As of December 31, 2011, the aggregate costs incurred by Eni for the Kashagan project capitalized in the Consolidated Financial Statements amounted to $6.7 billion (euro 5.2 billion at the EUR/USD exchange rate of December 31, 2011). This capitalized amount included: (i) $5.1 billion relating to expenditure incurred by Eni for the development of the oilfield; and (ii) $1.6 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA Consortium from exiting partners upon exercise of pre-emption rights in previous years.

As of December 31, 2010, the aggregate costs incurred by Eni for the Kashagan project capitalized in the Consolidated Financial Statements amounted to $5.8 billion (euro 4.4 billion at the EUR/USD exchange rate of December 31, 2010). This capitalized amount included: (i) $4.5 billion relating to expenditures incurred by Eni for the development of the oil field; and (ii) $1.3 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years.

Karachaganak. Located in West onshore 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 British Gas are co-operators of the venture with a 32.5% interest each. On December 14, 2011, the Republic of Kazakhstan (RoK) and the contracting companies of Karachaganak Final Production Sharing Agreement (FPSA) reached an agreement to settle all pending claims. The agreement will support the further development of the field. The agreement, effective from June 30, 2012 on satisfaction of conditions precedent, involves Kazakhstan’s KazMunaiGas (KMG) acquiring a 10% interest in the project. This will be done by each of the contracting companies (Eni, BG, Chevron and Lukoil) transferring 10% of their rights and interest in the Karachaganak FPSA to KMG. The contracting companies will receive $1 billion net cash consideration ($325 million being Eni’s share). In addition the agreement provides for the allocation of an extra nominal capacity of 2 million tonnes of oil per annum capacity for the Karachaganak project in the Caspian Pipeline Consortium export pipeline. The effects of the agreement on profit and loss, reserve and production entitlements will be recognized in the 2012 financial statements.

In 2011, production of the Karachaganak field averaged 239 KBBL/d of liquids (64 net to Eni) and 784 mmCF/d of natural gas (211 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir and re-injecting the associated gas in the higher layers. Approximately 85% of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of approximately 240 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 and associated raw gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg.

The fourth liquids stabilization train has been completed and allowed to increase export oil volumes through the Caspian Pipeline Consortium.

Phase 3 of the Karachaganak project is currently under study. The project is aimed at further developing gas and condensates reserves by means of the installation of gas treatment plant and re-injection facilities to increase gas sales and liquids production. The development plan is currently in the phase of technical and marketing discussion to be presented to the relevant Authorities.

As of December 31, 2011, Eni’s proved reserves booked for the Karachaganak field amounted to 500 mmBOE based on a 32.5% working interest, corresponding to the pre-divestment share. The 57 mmBOE decrease derives from the price effect and production of the year in part compensated for upwards revisions.

53

As of December 31, 2010, Eni’s proved reserves booked for the Karachaganak field amounted to 557 mmBOE, recording a decrease of 76 mmBOE with respect to 2009 due to price effect and production of the year.

As of December 31, 2009, Eni’s proved reserves booked for the Karachaganak field amounted to 633 mmBOE, recording a decrease of 107 mmBOE with respect to 2008 in connection to downward revisions due to the impact of higher oil prices and the production of the year.

Rest of Asia

In 2011, Eni’s operations in the rest of Asia accounted for 7% of its total worldwide production of oil and natural gas.

China. Eni has been present in China since 1984 and its activities are located in the South China Sea. In 2011 Eni’s production amounted to 8 KBOE/d.

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

Hydrocarbons are produced from the offshore Blocks 16/08 and 16/19 through eight platforms connected to an FPSO. Natural gas production from the HZ21-1 field is delivered through a sealine to the Zhuhai Terminal and sold to the Chinese National Co CNOOC. Oil is mainly produced from HZ25-4 field (Eni’s interest 49%). Activity is operated by the CACT-Operating Group (Eni’s interest 16.33%). Exploration activity is conducted in Block 28/20 (Eni’s interest 100%).

In January 2011 Eni and PetroChina signed a Memorandum of Understanding to promote joint projects in conventional and non conventional hydrocarbon plays in China and outside China. A similar agreement has been signed on July 2011 with Sinopec.

India. Eni has been present in India since 2005 and its activities are located in the offshore Cauvery Basin near the South-Eastern coast. In 2011, Eni’s production amounted to 4 KBOE/d.

Production mainly comes from the PY-1 gas field which is part of the assets belonging to Hindustan Oil Exploration Co Ltd (Eni’s interest 47.18%) acquired within the Burren acquisition. Gas production is sold to the local national oil company.

Indonesia. Eni has been present in Indonesia since 2001. In 2011, Eni’s production mainly composed of gas, amounted to 14 KBOE/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, the offshore Sumatra, and the offshore and onshore area of West Timor; in total, Eni holds interest in 12 blocks. Exploration and production activities in Indonesia are regulated by PSAs. In 2011, Eni was awarded two operated gas exploration licenses: (i) the Arguni I block with a 100% interest located onshore and offshore in the Bintuni Basin near a liquefaction facility. The agreement foresees seismic data acquisition and the drilling of 2 commitment wells to be carried out in the first three years of exploration phase; and (ii) the North Ganal block, located offshore Indonesia near the relevant Jangkrik discoveries and the Bontang liquefaction terminal, in a consortium with other international oil companies. The commitment activities provides for the seismic data acquisition and the drilling of one well in the first three years. The development plan of the operated Jankrik (Eni’s interest 55%) and Jau (Eni’s interest 85%) gas fields has been approved by relevant authorities. Planned development activities at the Jangkrik offshore field include drilling of production wells, installation of a Floating Production Unit for gas and condensate treatment and construction of a transport facility connecting to the onshore existing network linked to the Bontang liquefaction plant for gas, while condensates will be

54

supplied to the treatment plants in the area. Start-up is expected in 2016. The Jau project provides for the drilling of production wells and the linkage to onshore plants via pipeline. Start-up is expected in 2016.

In 2011, exploration activities related to the coal bed methane project progressed at the Sanga Sanga PSC (Eni’s interest 37.8%). Predevelopment activities are underway exploiting the synergy opportunities provided by the existing production and treatment facilities also including the Bontang LNG plant. Start-up is expected in 2013. In November 2011 Eni signed with the national power company PT Perusahaan Listrik Negara a Memorandum of Understanding to supply approximately 494 KCF/d of CBM gas for at least 5 years (corresponding to approximately 180 mmCF/y) to feed a power plant. The contract is in the process of being finalized.

Exploration activities yielded positive results with Jangkrik North East gas discovery in the Muara Bakau block (Eni operator with a 55% interest), located in the Kutei Basin.

Iran. Eni has been operating in Iran for several years under four Service Contracts (South Pars, Darquain, Dorood and Balal, these latter two projects being operated by another international oil company) entered into with the National Iranian Oil Co (NIOC) between 1999 and 2001, and no other exploration and development contracts have been entered into since then. All above mentioned projects have been completed or substantially completed; the last one, the Darquain project, is being handed over to NIOC. Operatorship has already been transferred to a NIOC affiliate. When the final hand over of operations will be completed, Eni’s involvements will essentially consist of being reimbursed for its past investments. In 2011, Eni’s contractual reimbursements were equivalent to a production of 6 KBOE/d, lower than 1% of the Group’s worldwide production. Eni does not believe that its activities in Iran have a material impact on the Group’s results. See "Item 3 – Risk Factors – Political Consideration – Iran" for a full discussion of risks involved by our presence in Iran.

Iraq. Eni has been present in Iraq since 2009. Eni, leading a consortium of partners including international companies and the national oil company Missan Oil, holds 32.8% interests in Zubair oil field.

Development and production activities in Iraq are regulated by Technical Service Contract. This contractual term establishes an oil entitlement mechanism and associated risk profile similar to those applicable in Production Sharing Contracts.

In 2011, production of the Zubair field averaged 257 KBBL/d (7 KBBL/d net to Eni). Development activities progressed at the Zubair oil field. The project, having a 20-year term with a further 5-year extension, foresees to gradually increase production to a target plateau level of 1.2 mmBBL/d by 2016 and provides for two phases: (i) Rehabilitation Plan approved in 2010 and aimed at improving current operations and reducing production decline as well as appraisal of both producing and undeveloped discovered reservoirs; and (ii) Enhanced Redevelopment Plan designed to attain the scheduled targets. Pakistan. Eni has been present in Pakistan since 2000. In 2011, Eni’s production mainly composed of gas amounted to 56 KBOE/d. Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore). Eni’s main permits in the Country are Bhit (Eni operator with a 40% interest), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.75%), which in 2011 accounted for 81% of Eni’s production in Pakistan. Development activities were aimed at reducing natural decline in: (i) the Bhit field, where the installation of a compression facility was completed. Drilling activities and optimization of current production are underway to extend production plateau; (ii) the Zamzama field, where the first phase of the Front End Compression project has been completed. Two additional wells will be drilled in 2012; and (iii) the Miano Front End Compression (Eni’s interest 15%) and Badhra Field Compression (Eni operator with a 40% interest) projects have been completed in 2011.

55

Exploration activity yielded positive results with: (i) the Kadanwari-27 exploration well, in the homonymous permit (Eni’s interest 18.42%) which yielded up to approximately 50 mmCF/d of gas in test production; (ii) the Lundo discovery and Tajjal 4 appraisal well in the Gambat permit (Eni’s interest 23.7%). The latter start-up is expected in 2012; (iii) the Misri Bhambroo exploration well located in the SW Miano II permit (Eni’s interest 33.3%).

Russia. Eni has been present in Russia since 2007 following the acquisition of Lot 2 in the liquidation procedure of bankrupt Russian company Yukos. Eni acquired a 29.4% interest in the joint venture Severenergia which currently owns important amounts of proved undeveloped gas reserves in the Yamal Peninsula in Siberia. In September 2011, Eni signed a contract whereby Gazprom commits to purchase volumes of gas produced by the joint venture Severenergia through the development of the Samburgskoye field. The agreement secured a final investment decision for the field development. Start-up is expected in 2012. In addition, the Final Investment Decision of the onshore gas and condensate Urengoskoye field was sanctioned. Start-up is expected in 2014. Following the two investment decisions amounts of proved undeveloped reserves were booked in 2011 as reserves held by equity-accounted entities. Turkmenistan. Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused in the Western part of the country. In 2011, Eni’s production averaged 11 KBOE/d. Exploration and production activities in Turkmenistan are regulated by PSAs.

Eni is operator of the Nebit Dag producing block (with a 100% interest). Production derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receives, by means of a swap with the Turkmen Authorities, an equivalent amount of oil at the Okarem field, close to the South coast of the Caspian Sea. Eni’s entitlement is sold FOB. Associated natural gas is used for own consumption and gas lift system. The remaining amount is delivered to Turkmenneft, via national grid.

America

In 2011, Eni’s operations in America area accounted for 8% 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 2011, Eni’s production averaged 7 KBBL/d.

Exploration and production activities in Ecuador are regulated by a service contract, due to expire in 2023.

Production deriving solely from the Villano field is processed by means of a Central Production Facility and transported via a pipeline network to the Pacific Coast.

Trinidad and Tobago. Eni has been present in Trinidad and Tobago since 1970. In 2011, Eni’s production averaged 57 mmCF/d and its activity is concentrated offshore North of Trinidad.

Exploration and production activities in Trinidad and Tobago are regulated by PSAs.

Production is provided by the Chaconia, Ixora, Hibiscus, Ponsettia, Bougainvillea and Heliconia gas fields in the North Coast Marine Area 1 Block (Eni’s interest 17.3%). 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 cost and sold under long-term contracts. LNG production is manly sold in the United States. Additional cargoes are sent to alternative destinations on a spot basis.

United States. Eni has been present in the United States since 1968. Activities are performed in the conventional and deep offshore in the Gulf of Mexico and more recently onshore and offshore in Alaska.

56

In 2011, Eni’s oil and gas production mainly derived from the Gulf of Mexico with an average of 96 KBOE/d.

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

Eni holds interests in 307 exploration and production blocks in the Gulf of Mexico of which 191 are operated by Eni.

The main fields operated by Eni are Allegheny, Appaloosa and Morpeth (Eni’s interest 100%), Longhorn-Leo, Devils Towers and Triton (Eni’s interest 75%) as well as King Kong (Eni’s interest 54%) and Pegasus (Eni’s interest 58%). Eni also holds interests in the Medusa (Eni’s interest 25%), Europa (Eni’s interest 32%), and Thunder Hawk (Eni’s interest 25%) fields.

In 2011, production started at the Appaloosa field with a production of 7 KBBL/d through linkage to the Corral operated platform with a treatment capacity of 33 KBBL/d net to Eni.

Development activity progressed at the Alliance area (Eni’s interest 27.5%), in the Fort Worth Basin in Texas targeting a plateau of 9 KBOE/d in 2012. This area, including gas shale reserves, was acquired in 2009 following a strategic alliance Eni signed with Quicksilver Resources Inc. In 2011 production averaged 8 KBOE/d.

Other main activities included work-over activities at the Goldfinger field (Eni’s interest 100%) and Spiderman field (Eni’s interest 36.7%) as well as the drilling of development wells in the Triton field (Eni’s interest 75%).

In order to achieve the highest security standards of operations in the Gulf of Mexico, Eni entered a consortium led by Helix that worked at the containment of the oil spill at the Macondo well. The Helix Fast Response System (HFRS) 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".

Exploration activities yielded positive results in the offshore block KC919 (Eni’ interest 25%) with Hadrian North appraisal well containing oil and natural gas resources. The discovery allowed approving the development of the Greater Hadrian Area project.

57

Eni holds interests in 135 exploration and development blocks in Alaska, with interests ranging from 10 to 100% and for 59 of these blocks, Eni is the operator.

In 2011, production started at the Nikaitchuq operated field (Eni’s interest 100%), located in the North Slope Basin offshore Alaska. Development plan completion is expected in 2014 with an average production plateau at approximately 21 KBBL/d net to Eni in 2016.

Other main production field is the Oooguruk oil field (Eni’s interest 30%), in the Beaufort Sea with a production of 7 KBBL/d (approximately 2 KBBL/d net to Eni) in 2011.

Venezuela. Eni has been present in Venezuela since 1998. In 2011, Eni’s production averaged 9 KBBL/d.

Activity is concentrated in the Gulf of Venezuela, in the Gulfo de Paria and onshore in the Orinoco Oil Belt.

Exploration and production of oil fields are regulated by the terms of the so-called Empresa Mixta. Under the new legal framework, only a company incorporated under the law of Venezuela is entitled to conduct petroleum operations. A stake of at least 60% in the capital of such company is held by an affiliate of the Venezuela state oil company, PDVSA, preferably Corporación Venezuelana de Petróleo (CVP).

Production and planning activities progressed at the Corocoro oil field (Eni’s interest 26%). In 2012 with the start-up of the Central Production Facility, Eni foresees to exceed current peak production of 42 KBBL/d (approximately 11 KBBL/d net to Eni). The subsequent development phase will allow reaching production of over 51 KBBL/d in 2015.

Planning activities progressed at the Junin 5 field (Eni’s interest 40%), located in the central part of the Orinoco Belt. First oil is expected in 2012 with a production plateau in the first phase of 75 KBBL/d, targeting a long-term production plateau of 240 KBBL/d to be reached in 2018. The project provides the construction of a refinery with a capacity of 350 KBBL/day that will allow also the treatment of intermediate streams from other PDVSA facilities.

In 2011, upstream engineering contracts related to the processing plants were awarded. Start-up of drilling activity is expected in 2012. Eni agreed to finance part of PDVSA’s development costs for the early production phase up to $1.5 billion. In addition, Eni will secure a tranche of the Junin 5 bonus and an additional financing to PDVSA for a total of $500 million to fund the construction of a power station in the Guiria peninsula, confirming its commitment to sustainable development.

Pre-development and appraisal activities were completed at the Perla gas field, located in the Cardon IV block (Eni’s interest 50%) in the Gulf of Venezuela. PDVSA owns a 35% back-in right to be exercised in the development phase, and at that time Eni will hold a 32.5% working interest in the joint operating company.

The Final Investment Decision for the first development phase was sanctioned in the year and a Gas Sale Agreement was signed. EPC contracts for the project are being awarded.

The Early Production phase includes the utilization of the already successfully drilled wells and the installation of production platforms linked by pipelines to the onshore processing plant. The target production of approximately 300 mmCF/d is expected in 2014. The development of Perla is currently planned to continue with two more phases by means of the drilling of additional wells and the upgrading of treatment facilities to reach a plateau production of 1,200 mmCF/d.

Eni is also participating with a 19.5% interest in the Gulfo de Paria Centrale offshore oil exploration block, where the Punta Sur oil discovery is located and with a 40% interest in Punta Pescador and Gulfo de Paria Ovest, the latter coinciding with the Corocoro oil field area.

Australia and Oceania

Eni’s operations in Australia and Oceania area are conducted mainly in Australia. In 2011, the area of Australia and Oceania accounted for 2% of Eni’s total worldwide production of oil and natural gas.

Australia. Eni has been present in Australia since 2000. In 2011, Eni’s production of oil and natural gas averaged 28 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%), WA-25-L (Eni operator with a 65% interest) and JPDA 03-13 (Eni’s interest 10.99%) and JPDA 06-105 (Eni operator with a 40% interest). In the exploration phase Eni holds interests in 10 licenses.

58

In May 2011, Eni signed an agreement with MEO Australia Ltd to farm-in the Heron and Blackwood gas discoveries in permit NT/P-68, located in the Timor Sea. Eni acquired a 50% stake and operatorship in the first gas discovery by financing exploration activities relating to the drilling of two appraisal wells. Eni was granted an option to earn a 50% stake in Blackwood discovery by performing seismic surveys and drilling one well in the area. The agreement also provides an option to acquire an additional 25% in both the discoveries by financing the development plan required to reach a Final Investment Decision (FID).

In November 2011, Eni acquired a 32.5% stake in the Evans Shoal gas discovery in the Timor Sea.

Production started at the Kitan oil field (Eni operator with a 40% interest) located between Timor Leste and Australia. Start-up was achieved by means of the completion of drilling activities in the deep offshore and the linkage to an FPSO plant (Floating Production Storage and Offloading). Peak production of over 40 KBBL/d is expected in 2012.

Capital Expenditures

See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".

Gas & Power

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, managing gas infrastructures for transport, distribution, storage, re-gasification, and LNG supply and marketing. This segment also includes the activities of power generation and electricity sales. In 2011, Eni’s worldwide sales of natural gas amounted to 96.76 BCM, including 2.86 BCM of gas sales made directly by the Eni’s Exploration & Production segment. Sales in Italy amounted to 34.68 BCM, while sales in European markets were 52.98 BCM that included 3.24 BCM of gas sold to certain importers to Italy.

Gas transport, distribution and storage, as well as re-gasification of LNG in Italy are regulated activities as tariffs for the services rendered to gas operators and return on capital employed are set by an independent administrative body. For a further description of those regulated activities see below.

Marketing of natural gas

The competitive scenario in the marketing of natural gas in Europe is particularly challenging as the current economic downturn will weigh on the perspectives of a solid recovery in gas demand. We expect that a combination of weak demand and rising competition fuelled by an oversupply overhang will put on margins pressure and reduce sales opportunities. We expect that this negative outlook in the gas sector in Italy and Europe will remain in place over the next two to three years. The Company is particularly exposed to the commodity risk driven by the circumstance that its supplies are linked to the price of crude oil and certain refined products, whereas its selling prices are benchmarked to spot prices at the continental hubs which have been hit by the current industry downturn.

The Company forecasts that current oversupply conditions in the European gas market will be gradually absorbed over the long-term, targeting a re-coupling between the oil-indexed cost of gas supplies and spot prices at the continental hubs. This forecast is supported by secular growth trends in worldwide gas demand and certain management expectations about gas supplies which are described below.

Considering that current imbalances between demand and supply on the European market are expected to continue for some time, risks still exist that in the next four years the Company may be unable to fulfill its minimum take obligations associated with its long-term gas purchase contracts providing take-or-pay clauses. For a description of these risks see "Item 3 – Risk Factors" and "Item 5 – Management’s Expectation of Operations".

Management has been implementing a number of initiatives to cope with the expected negative outlook in the gas sector targeting to gradually recover profitability over the plan period. First of all, management has committed to renegotiate better economic terms of the Company’s long-term gas purchase contracts, so as to restore the competitiveness of the Company’s cost position in the current difficult market environment. Through renegotiations, management is seeking to achieve better pricing terms, a revision of the contractual flexibility to reflect the current low level of demand, and, possibly, an option to reopen a renegotiation at any moment in the future should market conditions further deteriorate. In the course of 2011, management succeeded in closing certain important negotiations particularly the one with Sonatrach. Other negotiations are ongoing targeting to close new deals by the end of 2012;

59

particularly, in March 2012 the Company signed a preliminary deal with Gazprom. The related economic benefits will be determined considering the whole of 2011 and are expected to be recognized through the profit and loss of 2012.

Furthermore, we intend to strengthen our competitive position in the European gas markets by leveraging on the following initiatives:

(i)	we plan to expand sales volumes and increase our market share leveraging on the multiple presence in a number of markets, the development of a pan-European commercial platform, market knowledge, and aggressive marketing policies aimed at increasing the number of clients in the industrial and residential segments which will benefit from integrating the recently-acquired subsidiaries in France (Altergaz) and Belgium (Nuon);
(ii)	we plan to boost our LNG sales; and
(iii)	we plan to regain market share in the Italian market and to preserve marketing margins leveraging on the strong commercial franchise of the Company, selecting the customer portfolio and implementing differentiated marketing actions to retain clients in each segment with a particular focus on the valuable residential sector where the Company intends to strengthen its market position which boasted at the end of 2011 a customer portfolio of approximately 7.1 million of active contracts thanks to an excellent service, a well-known brand, the commercial growth of the combined offer of gas and electricity and consolidation of new marketing channels.

Finally, the Company intends to capture margins improvements by means of a new risk management strategy by entering derivatives contracts both in the commodity and the financial trading venues in order to capture possible favorable trends in market prices, within limits set by internal policies and guidelines that define the maximum tolerable level of market risk. Furthermore the Company intends to optimize the value of its assets (gas supply contracts, storage sites, transportation rights, customer base, and market position) by effectively managing the flexibilities associated with these assets. This can be achieved by entering arbitrage contracts to leverage price differentials at various points along the gas value chain or through strategies of dynamic forward trading where the underlying items are represented by the Company’s assets. Asset backed trading activities are mitigated by the natural hedge granted by the assets’ availability.

For a description of uncertainties and risks associated with this strategy see "Item 3 – Risk Factors" and "Item 5 – Management’s Expectation of Operations".

The matters regarding future natural gas demand and sales target discussed in this section 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 statements. Such risks and uncertainties relating to future natural gas demand include changes in underlying economic factors, changes in regulation, population growth or shrinkage, changes in the relative mix of demand for natural gas and its principal competing fuels, and unexpected developments in the markets for natural gas and its principal competing fuels.

Demand and supply outlook

In 2011, gas demand in Europe shrank by 10% (down by 6% in Italy) due to the economic downturn, an expansion in the use of renewable sources, a shift to coal in thermoelectric production due to cost advantages, as well as unusual weather conditions. Management expects a recovery in gas demand in the long-term driven by macroeconomic stability and increasing use of gas in the production of electricity, also considering a commitment to reduce CO₂ emissions from EU Member States. Globally, management expects EU demand to increase from around 500 BCM in 2011 to around 565 BCM by 2015, and to close to 600 BCM in 2020, corresponding to an average growth rate of approximately 2% along the period. Gas demand in Italy is expected to grow with an average rate of approximately 2% driven by power generation consumption which is expected to increase from approximately 28 BCM in 2011 to over 40 BCM in 2020.

Those estimates have been revised down from previous management’s planning assumptions to factoring a number of ongoing trends such as:

• uncertainties and volatility in the current macroeconomic cycle;

• growing adoption of consumption patterns and life-styles characterized by wider sensitivity to energy efficiency; and

• EU policies intended to reduce GHG emissions and promoting renewable energy sources, following prescription set by the Climate Change and Renewable Energy package (the so called PEE 20-20-20). The package includes a commitment to reduce greenhouse gas (GHG) emissions by 20% by 2020 compared to emission levels recorded in 1990 (the target being 30% if an international agreement is reached), as well as improved energy efficiency within the EU Member States of 20% by 2020 and a 20% renewable energy target by 2020.

On the plus side, ongoing changes in the energy policies of the Euro-zone as a result of the nuclear accident at the Fukushima plant in Japan could accelerate a recovery in gas consumption. In addition, the fiscal policies of the Member States could affect the composition of the energy mix through the introduction of penalties on the use of the most

60

inefficient and pollutant sources in energy production. Examples of these trends are a proposed European directive to enact a carbon tax to be levied on those sectors which do not participate in the ETS mechanism as well as a proposal to enact certain fiscal adjustments to put a floor at the price of carbon dioxide emissions in the UK.

Gas availability remains abundant as large investments to upgrade import pipelines to Europe have come online from Russia, Algeria and Libya in recent years and large availability of LNG on a worldwide scale has found an outlet at the European continental hubs driving the development of very liquid spot gas markets. The latter was driven by the ramp-up of important upstream projects which added an approximate 65 BCM of liquefaction capacity in the three-year period 2008-2010, coupled with commercial development of non-conventional gas resources in the United States which have reduced the Country’s dependence on LNG imports. Furthermore, in the near future the start-up of new infrastructures in various European entry points is expected and will add approximately 50-60 BCM of new import capacity. These include the Medgaz pipeline connecting Algeria to the Iberian Peninsula, the Nord Stream pipeline connecting Russia to Germany through the Baltic Sea as well as new LNG facilities, particularly a new plant is set to commence operations in the Netherlands with a process capacity of up to 12 BCM. Further 27 BCM of new supplies will be secured by a second line of the Nord Stream later on and new storage capacity will come online. In Italy the gas offered will grow moderately in the next future as a new LNG plant is expected to start operations at Livorno with a 4 BCM treatment capacity and effects are in force of Law Decree No. 130/2010 concerning storage capacity (see below) which is expected to increase by 4 BCM by 2015. In addition the GreenStream pipeline is seen to achieve full operations in 2012 and gas supplies from Libya will be back online. Also counter flow expenditures will favor gas exchanges among European Countries.

As a result of these drivers, we expect that current market imbalances will continue over the next two to three years. Looking beyond, however, we expect the European market to rebalance and then show further improvements driven by some key trends.

First of all, we project that worldwide gas demand will be supported by growing energy needs especially from the Pacific area, where, between now and 2015, we estimate that consumption will increase by 16%, or around 90 BCM, mainly driven by robust rates of economic development, as well as Japan’s shift to gas-fired electricity away from nuclear fuel. This will largely absorb the new LNG production coming on-stream in the region and attract some of the worldwide LNG supplies which are currently being delivered to Europe. Furthermore, South America and the Middle East will see an increase in demand for spot LNG cargoes, which also will absorb some of the oversupply to Europe. Finally, the probable postponement of new projects for the development of gas reserves by upstream operators will also support a better balance in worldwide supplies of LNG as a slowdown in building new liquefaction capacity is projected in the medium-term.

The second one is our belief that albeit domestic production in the United States will continue to grow, nonetheless we expect exports to be limited and subject to regulatory constraints mainly targeting to maintain stable domestic gas prices.

The third trend is that we forecast that import requirements in Europe are projected to increase by almost 80 BCM to 2015 through a combination of growing demand and declining domestic production. Given the expected marginal contribution of European shale gas by that time and the tightening of the LNG market, management expects additional import requirements to be mainly satisfied by pipeline gas under long-term contracts.

Over the next four years we also believe the internal European gas market to become more integrated, thanks to the construction of new interconnection. Easier gas circulation will create additional commercial and trading opportunities for companies, like Eni, with diversified supply contracts and market positions.

Management believes that the above mentioned trends will help European gas operators recover profitability in the medium to long term. Possible risks to these forecasts are the difficulty in estimating the long-term impact of the current European economic slowdown on gas demand, the effectiveness of EU Member States in achieving committed targets in reducing the energy intensity and shifting from gas to renewables in the production of electricity, as well as the actual evolution in the global availability of LNG.

Planned actions in marketing of natural gas

Over the next four years, in order to recover profitability in a difficult market Eni’s strategy focuses on two distinct commercial objectives:

(i)	to consolidate Eni’s position in Europe in the business gas market, where the Company has a well balanced portfolio in terms of geographies, customer segments and contract duration; and
(ii)	to increase our penetration in the European retail segment.

In particular management plans to regain market share in Italy and to expand sales in European target markets by leveraging first of all on the improved competitiveness of the Company’s cost position reflecting the benefit of the

61

renegotiation of its supply contracts, the quality of its offer, including risk management and transport and storage contracts, pricing formulas and commercial options that are designed to suit customers’ needs, and a multi-country approach.

In order to increase exposure to the retail segment, management plans to expand its customer base by almost 30% in the next four years, strengthening its position in this segment in particular in Italy, where the Company added 500 thousand new contracts, through its distinctive dual fuel offer (gas and electricity) and innovative sales channels. The recent acquisitions of Altergaz in France and Nuon in Belgium are expected to contribute to our growth strategy in the retail segment in Europe where Eni can count on a resilient customer base, highly complementary to its operations in the business segment. Looking forward, management intends to continue growing in the European retail segment, using our valuable experience gained in the Italian retail market, our high quality service and customer care, and our multi-channel sales platform.

Supply of natural gas

In 2011, Eni’s consolidated subsidiaries supplied 83.38 BCM of natural gas, representing an increase of 0.89 BCM, or 1.1% from 2010.

Gas volumes supplied outside Italy (76.16 BCM from consolidated companies), imported to Italy or sold outside Italy, represented approximately 90% of total supplies, and showed an increase of 0.96 BCM, or 1.3%, from 2010. Higher volumes were purchased from Russia (up 6.71 BCM), particularly to replace the disruption of Libyan gas supplies (which were down 7.04 BCM) and to supply volumes directed to Turkey (up 2.91 BCM) as a consequence of increased off-takes by Botas.

Supplies in Italy (7.22 BCM) were substantially stable also due to higher domestic production that offset the decline of mature fields.

In 2011, main gas volumes from equity production derived from: (i) Italian gas fields (6.7 BCM); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.4 BCM); (iii) the United States (2.2 BCM); and (iv) other European areas (Croatia with 0.3 BCM). Supplies from equity production fell sharply at the Wafa and Bahr Essalam fields (to 0.6 BCM) in Libya due to the conflict in the country; in 2010 these two fields supplied 2.5 BCM net to Eni.

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 18 BCM representing 18% of total volumes available for sale.

In 2011, withdrawals from storage deposits amounted to 1.79 BCM compared to volumes input to storage deposits of 0.20 BCM in 2010.

62

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

Natural gas supply 2009 2010 2011

(BCM)

Italy	6.86		7.29		7.22
Outside Italy	81.79		75.20		76.16
Russia	22.02		14.29		21.00
Algeria (including LNG)	13.82		16.23		13.94
Libya	9.14		9.36		2.32
the Netherlands	11.73		10.16		11.02
Norway	12.65		11.48		12.30
the United Kingdom	3.06		4.14		3.57
Hungary	0.63		0.66		0.61
Qatar (LNG)	2.91		2.90		2.90
Other supplies of natural gas	4.49		4.42		6.16
Other supplies of LNG	1.34		1.56		2.34
Total supplies of subsidiaries	88.65		82.49		83.38
Withdrawals from (input to) storage	1.25		(0.20	)	1.79
Network losses, measurement differences and other changes	(0.30	)	(0.11	)	(0.21	)
Volumes available for sale of Eni’s subsidiaries	89.60		82.18		84.96
Volumes available for sale of Eni’s affiliates	7.95		9.23		8.94
E&P volumes	6.17		5.65		2.86
Total volumes available for sale	103.72		97.06		96.76

In order to secure long-term access to gas availability, particularly with a view of supplying the Italian gas market, Eni has signed a number of long-term gas supply contracts with key producing countries that supply the European gas markets. These contracts have been ensuring approximately 80 BCM of gas availability from 2010 (including the Distrigas portfolio of supplies and excluding Eni’s other subsidiaries and affiliates) with a residual life of approximately 17 years and a pricing mechanism that indexed to cost of gas to the price of crude oil and its derivatives (gasoil, fuel oil, etc.). These contracts provide take-or-pay clauses whereby the Company is required to collect minimum pre-determined 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, applied to uncollected volumes up to the minimum contractual quantity. The take-or-pay clause entitles the Company to collect pre-paid volumes of gas in later years during the period of contract execution. In the current industry downturn, the Company has failed to off-takes the annual minimum quantities of gas provided by the contractual take-or-pay clause, being forced to pre-pay the underlying gas volumes.

From the beginning of the slump in the gas European market late in 2009, Eni has incurred the take-or-pay clause accumulating deferred costs for an amount of euro 2.22 billion (net of limited amounts of volume make-up) and has paid the associated cash advances amounting to euro 1.76 billion, the difference being the payable towards gas suppliers outstanding as of the balance sheet date.

Considering ongoing market trends and the Company’s outlook for its sales volumes which are anticipated to grow at a modest pace over the next four years, as well as the benefit of contract renegotiations which may temporarily reduce the annual minimum take, management believes that it is likely that in the next two to three years Eni will fail to fulfill its minimum take obligations associated with its supply contracts thus triggering the take-or-pay clause and the obligation to pay cash advances in relation to substantial amounts of gas.

However, based on our long-term expectations about a rebalancing between gas demand and offer in Europe, our projections of sales volumes and unit margins in the next four years and beyond we believe that in the long run the Company will be able to recover the volumes of gas which have been pre-paid up the balance sheet date and the volumes for which we expect to incur the take-or-pay clause in the next four years due to weak market conditions.

This forecast is subject to the risk factors described in Item 3 and in our outlook in Item 5.

Sales of natural gas

In 2011, sales of natural gas were 96.76 BCM, down 0.30 BCM or 0.3%. Sales included Eni’s own consumption, Eni’s share of sales made by equity-accounted entities and E&P sales in Europe and in the Gulf of Mexico.

In Italy, Eni operates in a liberalized market where customers are free to choose their supplier of gas. The Company’s customer portfolio consists of: (i) approximately 3,000 large customers including large industrial clients and

63

power generation utilities, directly linked to the national and the regional natural gas transport networks; and wholesalers, mainly local selling companies which resell natural gas to residential customers through low pressure distribution networks and distributors of natural gas for automotive use; and (ii) residential customers amounting to approximately 7.10 million as of the balance sheet date, which included households (also referred to as the retail market), the tertiary sector (mainly commercial outlets, hospitals, schools and local administrations) and middle-sized enterprises (also referred to as the middle market) located in large metropolitan areas and urban areas.

Despite a 6% decline in natural gas demand, sales volumes on the Italian market were substantially stable, to 34.68 BCM (up 0.39 BCM, or 1.1%) due to the positive effect of market initiatives that led to higher sales to industrial customers (up 0.80 BCM), wholesalers (up 0.32 BCM) and to the power generation segment (up 0.27 BCM). Sales on the Italian exchange for gas and spot markets increased by 0.59 BCM. Lower sales volumes to the residential segment (down 0.72 BCM) reflected the impact of unusual weather conditions on seasonal sales and competitive pressures.

Sales to shippers, who import natural gas to Italy, were down by 5.20 BCM, or 61.6%, due to the disruptions on Libyan supplies in connection to the disruption in the operations of GreenStream gas pipeline.

Sales on target markets in Europe of 49.74 BCM showed a positive trend, increasing by 7.9%, except for Benelux (down 2.92 BCM) where competitive pressure, in particular in the wholesalers segment, reduced Eni’s sale portfolio. The main increases were recorded in Turkey (up 2.91 BCM), due to increased off-takes by Botas, France (up 0.92 BCM) also due to the consolidation of Altergaz, UK/Northern Europe (up 0.88 BCM), Germany-Austria (up 0.80 BCM) and the Iberian Peninsula (up 0.37 BCM).

Sales to markets outside Europe increased by 0.66 BCM, net of changes in consolidation area related to volumes sold in the United States that in 2010 was included in E&P sales in Europe and the Gulf of Mexico, due to higher LNG sales in Argentina and Japan, offset in part by lower sales in Brazil following the divestment of Eni’s interest in Gas Brasiliano Distribuidora, a company distributing and marketing natural gas in Brazil.

E&P sales in Europe and in the United States (2.86 BCM) declined by 2.79 BCM due to the above mentioned reasons.

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

Natural gas sales by entities 2009 2010 2011

(BCM)

Total sales of subsidiaries	89.60	82.00	84.37
Italy (including own consumption)	40.04	34.23	34.60
Rest of Europe	48.65	46.74	45.16
Outside Europe	0.91	1.03	4.61
Total sales of Eni’s affiliates (Eni’s share)	7.95	9.41	9.53
Italy	-	0.06	0.08
Rest of Europe	6.80	7.78	7.82
Outside Europe	1.15	1.57	1.63
Total sales of G&P	97.55	91.41	93.90
E&P in Europe and in the Gulf of Mexico (a)	6.17	5.65	2.86
Worldwide gas sales	103.72	97.06	96.76

(a) E&P sales include volumes marketed by the Exploration & Production segment in Europe (2.57, 2.33 and 2.29 BCM in 2009, 2010 and 2011, respectively) and in the Gulf of Mexico (3.60, 3.32 and 0.57 BCM in 2009, 2010 and 2011, respectively).

64

Natural gas sales by market 2009 2010 2011

(BCM)

ITALY	40.04	34.29	34.68
Wholesalers	5.92	4.84	5.16
Gas release	1.30	0.68
Italian gas exchange and spot markets	2.37	4.65	5.24
Industries	7.58	6.41	7.21
Medium-sized enterprises and services	1.08	1.09	0.88
Power generation	9.68	4.04	4.31
Residential	6.30	6.39	5.67
Own consumption	5.81	6.19	6.21
INTERNATIONAL SALES	63.68	62.77	62.08
Rest of Europe	55.45	54.52	52.98
Importers in Italy	10.48	8.44	3.24
European markets	44.97	46.08	49.74
Iberian Peninsula	6.81	7.11	7.48
Germany-Austria	5.36	5.67	6.47
Benelux	15.72	14.87	11.95
Hungary	2.58	2.36	2.24
UK-Northern Europe	4.31	5.22	6.10
Turkey	4.79	3.95	6.86
France	4.91	6.09	7.01
Other	0.49	0.81	1.63
Extra European markets	2.06	2.60	6.24
E&P in Europe and in the Gulf of Mexico	6.17	5.65	2.86
WORLDWIDE GAS SALES	103.72	97.06	96.76

European Markets

A review of Eni’s presence in the key European markets is presented below.

Benelux. Eni’s holds a leadership position in the Benelux countries (Belgium, the Netherlands and Luxembourg) granted by a direct presence, the integration with Distrigas’ operations and its significant exposure to spot markets in Western Europe. In 2011, sales in Benelux were mainly directed to industrial companies, wholesalers and power generation and amounted to 11.95 BCM (14.87 BCM in 2010), down by 2.92 BCM, or 19.6%, due to rising competitive pressure, in particular in the wholesalers segment. In the next four years, the Company plans to grow sales in Benelux also leveraging on expected synergies deriving from the integration of recently acquired Nuon Belgium NV and Nuon Power Generation Wallon NV, two companies marketing gas and electricity mainly to residential and professional customers in Belgium.

France. Eni sells natural gas to industrial clients, wholesalers and power generation as well as to the retail and middle market segments. Eni is present in the French market through its direct commercial activities and through its subsidiary. Furthermore, Eni holds a 34% interest in Gaz de Bordeaux SAS (with a 17% direct interest and a further 17% held by Altergaz) which is engaged in selling natural gas in the Municipality of Bordeaux. Management plans to expand sales in France over the plan period growing volumes supplied to the business segments and increasing retail customers leveraging on the Altergaz integration. In 2011, sales in France amounted to 7.01 BCM (6.09 BCM in 2010), an increase of 0.92 BCM, or 15.1%, from a year ago.

Germany-Austria. Eni is present in the German natural gas market through its associate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 4.68 BCM in 2011 (2.34 BCM being Eni’s share), and through a direct marketing structure which sold in 2011 approximately 3.23 BCM in Germany and 1.34 BCM in Austria. Management plans to drive growth in direct sales leveraging on the quality of its commercial offer, a projected expansion in its business customer base and the enhancement of direct presence on the market. In 2011, sales in the Germany-Austria market amounted to 6.47 BCM, an increase of 0.80 BCM, or 14.1%, from a year ago.

Iberian Peninsula

Portugal. Eni operates on the Portuguese market through its affiliate Galp Energia (Eni’s interest 33.34%) which sold approximately 5.49 BCM in 2011 (1.83 BCM being Eni’s share).

Spain. Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and Unión Fenosa Gas (UFG) (Eni’s interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2011, UFG gas sales in Europe amounted to 4.88 BCM (2.44 BCM Eni’s

65

share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) re-gasification plants (42.5% and 18.9%, respectively). In 2011, Eni sales in Spain amounted to 5.79 BCM representing a slight increase from a year ago. In 2011, total sales in the Iberian Peninsula amounted to 7.48 BCM, an increase of 0.37 BCM, or 5.2%, from a year ago.

Turkey. Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2011, sales amounted to 6.86 BCM, an increase of 2.91 BCM, or 73.7% from a year ago.

UK-Northern Europe. Eni through its subsidiary North Sea Gas & Power (Eni UK Ltd) markets in the UK the equity gas produced at Eni’s fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF). In 2011, sales amounted to 6.10 BCM, an increase of 16.9% from a year ago.

Deborah Gas Storage Project in the Hewett area, UK. Eni has progressed in developing the Gas Storage Project on the Deborah field within the Hewett area located in the Southern Gas Basin in the North Sea, near the Bacton terminal, UK. The Deborah Gas Storage Project is designed to provide the UK and North Western Europe markets with 4.6 BCM of working gas. Over the last two years significant progress has been made by completing the Front End Engineering Design (“FEED”), obtaining most of the necessary approvals including the agreement with The Crown Estate, the Gas Storage Licence from the Department of Energy and Climate Change (“DECC”) and relevant permits from the North Norfolk District Counsel on the Bacton terminal, securing certain long-term gas storage capacity under the Capacity Allocation Process and having in-depth discussions with potential co-investors. In addition, recently the UK Government expressed a Country strategic need to improve gas storage facilities in order to better manage flex gas as a necessary back up for renewable power generation. Thus, Eni together with other gas storage developers is taking discussions with UK authorities to investigate any capacity mechanism that can facilitate the sanction of gas storage projects. FID on the project will be taken when Eni get a better clarity on ongoing discussion with potential co-investors and the UK governmental authorities.

The LNG Business

Eni is present in all phases of the LNG business: liquefaction, shipping, re-gasification and sale through operated activities or interests in joint ventures and associates. Eni’s presence in the business is tied to the Company’s plans to develop its large gas reserve base in Africa and elsewhere in the world. The LNG business has been deeply impacted by the economic downturn and oversupply affecting the European gas market, as well as by structural modifications in the U.S. market where large availability of gas from unconventional sources have reduced the country’s dependence on gas imports via LNG.

Eni’s main assets and projects in the LNG business are described below.

Qatar. Through its subsidiary Distrigas, Eni increased its development opportunities in the LNG business with access to new supply sources mainly from Qatar, under a 20-year agreement with RasGas (owned by Qatar Petroleum with a 70% interest and ExxonMobil with a 30% interest) and the Zeebrugge LNG terminal on the Western coast of Belgium.

Egypt. Eni, through its interest in Unión Fenosa Gas, owns a 40% interest in the Damietta liquefaction plant with a capacity of approximately 5 mmtonnes/y of LNG which equates to a feedstock of 7.56 BCM/y in natural gas out of which the Gas & Power segment interest is up to 2.2 BCM/y to be marketed in Europe.

Spain. Eni through Unión Fenosa Gas holds a 21.25% interest in the Sagunto re-gasification plant, near Valencia, with a capacity of 8.8 BCM/y and a LNG storage capacity of 450,000 CM which will be increased to 600,000 CM after the ongoing construction of a fourth tank. At present, Eni’s re-gasification capacity entitlement amounts to 1.9 BCM/y of gas.

Eni through Unión Fenosa Gas also holds a 9.45% interest in the El Ferrol re-gasification plant, located in Galicia, with a treatment capacity of approximately 3.6 BCM/y, of which 0.34 BCM/y being Eni’s capacity entitlements. The LNG storage capacity of the plant is 300,000 CM in two tanks.

United States

Cameron. The Cameron LNG terminal is situated 18 miles from the Gulf of Mexico along the Calcasieu Channel in Hackberry, Louisiana. The facility where Eni owns a capacity entitlement to treat LNG commenced operations in the third quarter of 2009. In consideration of a changed demand outlook, on March 1, 2010, Eni renegotiated certain terms of the contract with U.S. company Cameron LNG, relating to the farming out of a share of re-gasification capacity of the Cameron terminal. The new agreement provides that Eni will be entitled to a daily send-out of 572,000 mmbtu (approximately 5.7 BCM/y) and a dedicated storage capacity of 160 KCM, giving Eni more flexibility in managing

66

seasonal swings in gas demand. Furthermore, keeping account of the current oversupply of the U.S. gas market, the Brass project (West Africa) for developing gas reserves to fuel the Cameron plant has been rescheduled with start-up in 2017.

Pascagoula. This project is part of an upstream development project related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes of LNG (approximately 7.3 BCM/y) destined to the North American market in order to monetize part of the Company’s gas reserves. As part of the downstream leg of the project, Eni signed a 20 year contract with Gulf LNG to buy 5.8 BCM/y of the re-gasification capacity of the plant under construction near Pascagoula in Mississippi. The start-up of the re-gasification facility commenced in the fourth quarter of 2011, while the upstream project in Angola has yet to be started up.

At the same time Eni USA Gas Marketing Llc entered a 20-year contract for the purchase of approximately 0.9 BCM/y of re-gasified gas downstream the terminal owned by Angola Supply Services, a company whose partners also own Angola LNG.

LNG sales 2009 2010 2011

(BCM)

G&P sales	9.8	11.2	11.8
Italy	0.1	0.2
Rest of Europe	8.9	9.8	9.8
Extra European markets	0.8	1.2	2.0
E&P sales	3.1	3.8	3.9
Liquefaction plants:
- Bontang (Indonesia)	0.8	0.7	0.6
- Point Fortin (Trinidad and Tobago)	0.5	0.6	0.4
- Bonny (Nigeria)	1.4	2.2	2.5
- Darwin (Australia)	0.4	0.3	0.4
	12.9	15.0	15.7

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, at industrial sites and on the Italian Exchange for electricity. 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 leveraging on the Company’s large gas availability. In addition, with the aim of developing and retaining valuable customers in the residential space and middle to large industrial users, the Company has been developing a commercial offer that provides the combined supply of gas and power.

In 2011, the program for upgrading and improving flexibility of the combined cycle power plants progressed in accordance with the Company’s developing plans.

In 2011, electricity sales (40.28 TWh) increased by 1.9% to due to growth in the client base and higher volumes traded on the Italian power exchange (up 1.54 TWh) despite weak domestic demand, and were directed to the free market (66%), the Italian power exchange (22%), industrial sites (8%) and others (4%).

In the next 12-24 months, management believes that the price of electricity will be just above the price of fuel gas in power generation plus the environmental costs associated with the purchase of green certificates relating to CO₂ emissions. Consequently, the clean spark spread (the spark spread, i.e. the gross margin of gas-fired power plant from selling a unit of electricity, minus the CO₂ emission costs) is expected to be almost zero.

67

Power availability 2009 2010 2011

(TWh)

Power generation sold	24.09	25.63	25.23
Trading of electricity (a)	9.87	13.91	15.05
	33.96	39.54	40.28
Power sales by market
Free market	24.74	27.48	26.87
Italian Exchange for electricity	4.70	7.13	8.67
Industrial plants	2.92	3.21	3.23
Other (a)	1.60	1.72	1.51
	33.96	39.54	40.28

(a) Include positive and negative imbalances.

Power Generation

Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi, Ferrara and in Bolgiano.

In 2011, power production was 25.23 TWh, down 0.40 TWh, or 1.6% from 2010, mainly due to lower production at the Brindisi plant, offset in part by increases at Ravenna and Ferrara plants.

As of December 31, 2011, installed operational capacity was 5.3 GW (5.3 GW in 2010).

Power availability in 2011 was supported by the growth in electricity trading activities (up 1.14 TWh, or 8.2%) due to higher volumes traded on the Italian power exchange benefiting from lower purchase prices.

By 2015, Eni expects to complete its plans for capacity expansion targeting an installed capacity of 5.4 GW. In the medium term, Eni intends to consolidate operations at its power generation plants and to enhance the flexibility of assets in order to better meet market needs. Furthermore Eni intends to develop the production from renewable sources focusing on photovoltaic power plant, and on the Company’s "Green Chemistry" project for the remediation of the Porto Torres site, where it will be also build a bio-mass power plant. Development activities are currently underway at the Taranto (Eni 100%), Ferrara (Eni 51%), and Bolgiano (Eni 100%) plants.

Supplies of natural gas are expected to amount to approximately 6 BCM/y from Eni’s diversified supply portfolio.

New installed generation capacity uses the combined cycle gas fired technology (CCGT), ensuring a high level of efficiency and low environmental impact. Moreover, most of the plants employ Combined Heat and Power (CHP) technologies which contribute to reduce the emission of carbon dioxide by approximately 5 mmtonnes, on an energy production of 26.5 TWh. CHP technology has been acknowledged by the National Law (Legislative Decree No. 79/1999) as a production technology that, being highly efficient and allowing a reduction in primary fuel consumption, is not subject to the current Renewable Energy Sources (“RES”) support scheme (“green certificates”) and entails priority on the national dispatching network and the award of “green certificates” that can be traded against emission allowances. The afore mentioned scheme consists of an obligation on part of power producers to input a certain percentage of energy from renewable sources in proportion to the energy produced or, as an alternate measure, to purchase green certificates which are in turn granted to RES producers in proportion to the “green energy” produced. As of now, CHP production are exempted from the obligation but a stricter interpretation of the legal framework that currently defines CHP (regarding, in particular, the coexistence of a different definition for “high efficiency CHP”) might sharply reduce the amount of energy not subject to the green certificate scheme. However, the recently enacted Legislative Decree No. 28/2011 provides for a phase-out of the green certificates scheme, via a gradual reduction of the share of electricity production currently covered by green certificates, until it is completely cancelled in 2015, and a rebalance of the incentive mechanism in favor of feed-in tariffs for RES while the Ministerial Decree of September 5, 2011 defined a new support scheme for new high-efficiency CHP projects, that will be entitled to receive an amount of Energy Efficiency Titles (“white certificates”). However, a safeguard clause will entitle most of Eni’s plants to receive white certificates in a measure equivalent to 30% of the amount awarded to a new project. In spite of these incentives, we believe that in the next four years our expenses to comply with environmental regulation will trend higher as a result of stricter rules that will apply to the award of emission allowances in the EU emission trading mechanism, causing the Company to increase its purchases of allowance on the free market.

68

The main assets of Eni power generation activities in Italy are provided in the table below.

Site Total installed capacity in 2011⁽¹⁾
(MW) Technology Fuel

Brindisi	1,321	CCGT	gas
Ferrera Erbognone	1,030	CCGT	gas/syngas
Livorno	199	Power station	gas/fuel oil
Mantova	836	CCGT	gas
Ravenna	972	CCGT	gas
Taranto	75	Power station	gas/fuel oil
Ferrara	841	CCGT	gas
Bolgiano	30	Power station	gas
Nettuno	2	Power station	photovoltaic energy
	5,306

(1) Capacity available after completion of dismantling of obsolete plants.

Power Generation 2009 2010 2011

Purchases
Natural gas	(mmCM)	4,790	5,154	5,008
Other fuels	(ktoe)	569	547	528
- of which steam cracking		82	103	99
Production
Electricity	(TWh)	24.09	25.63	25.23
Steam	(ktonnes)	10,048	10,983	14,401
Installed generation capacity	(GW)	5.3	5.3	5.3

Infrastructures

Eni holds transport rights on a large European network of integrated infrastructure for transporting natural gas, which links key consumption basins with the main producing areas (Russia, Algeria, Libya and the North Sea).

In Italy, Eni operates the most of the national transport network, a number of gas underground storage deposits and related facilities, a re-gasification plant in Panigaglia and can rely on an extended system of local distribution networks. Eni is currently implementing plans for expanding and upgrading its national transport and distribution networks and storage capacity.

69

The main assets of Eni transport activities in Italy and outside Italy are described in the table below.

Transport infrastructure

Route	Lines	Length of main line	Diameter	Transport capacity (1)	Pressure min-max	Compression stations
ITALY	(units)	(km)	(inch)	(mmCM/d)	(bar)	(No.)

Mazara del Vallo-Minerbio (under upgrading)	2/3	1,480	48/42 - 48	105.0	75	7
Tarvisio-Sergnano-Minerbio	3	434	42/36, 34 and 48/56	118.8	58/75	3
Passo Gries-Mortara	1/2	177	48/34	64.8	55/75	1

i

i

i

i

i

i

i

i

i

i

i

i

i

Lines

Total length

Diameter

Transport capacity (3)

Transit capacity (4)

Compression stations

OUTSIDE ITALY (2)

(units)

(km)

(inch)

(BCM/y)

(BCM/y)

(No.)

TTPC (Oued Saf Saf-Cap Bon)	2 lines of km 370	740	48	34.0	33.2	5
TMPC (Cap Bon-Mazara del Vallo)	5 lines of km 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)	i	Transport capacity refers to the capacity at the entry point connected to the import pipelines.
(2)	i	In 2011, Eni finalized the divestment of its interests in importing pipelines of natural gas from Northern Europe (TENP and Transitgas) and Russia (TAG) as part of the agreements signed on September 29, 2010 with the European Commission.
(3)	i	Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.
(4)	i	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

Eni owns capacity entitlements in an extensive network of international high pressure pipelines enabling the Company to import natural gas produced in Russia, Algeria, the North Sea, including the Netherlands and Norway, and Libya to Italy. The Company participates to both entities which operate the pipelines and entities which manage transport rights. For financial reporting purposes, such entities are either fully-consolidated or equity-accounted depending on the Company’s interest or agreements with other shareholders.

The structure of the Company’s interests in those entities has significantly changed in 2011 following the divestment of Eni’s interests in pipelines importing natural gas from Northern Europe (TENP and Transitgas) and Russia (TAG) and related carrier companies, as part of the agreements signed on September 29, 2010 with the European Commission to settle an antitrust proceeding related to alleged anti-competitive behavior in the natural gas market.

In light of the strategic importance of the Austrian TAG pipeline to the supply of the Italian system, which transports gas from Russia to Italy, Eni divested its stake to an entity controlled by the Italian State. The divestments will not affect Eni’s contractual gas transport rights.

A description of the main international pipelines currently participated or operated by Eni is provided below.

The TTPC pipeline, 740-kilometer long, made up of two lines that are each 370-kilometer long with a transport capacity of 33.2 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 pipeline was recently upgraded by increasing compression capacity in order to enable transportation of an additional 6.5 BCM/y. The upgrade was finalized in 2008 and became fully-operational during 2009.

The TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 BCM/y. It crosses the underwater 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 Company, started operations in October 2004 for the import of Libyan gas produced at Eni operated fields Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 BCM/y (expandable to 11 BCM/y) and crosses underwater in the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system. From February 22, 2011 to October 2011, in consideration of the crisis in Libya, supplies of natural gas through the GreenStream pipeline have been suspended. Operations restarted late in October 2011.

70

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-kilometer long on two lines and has transport capacity of 16 BCM/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market.</